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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 June 30, 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
incorporation or organization) Identification No.)
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 July 31, 2001, the Registrant had 12,682,584 shares of Common Stock,
$0.015 Par Value, outstanding.
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PRIMA ENERGY CORPORATION
INDEX
Page
PART I - FINANCIAL INFORMATION
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............................................. 18
Cautionary Statement for Purposes of the "Safe Harbor" Provisions
of the Private Securities Litigation Reform Act of 1995....... 19
PART II - OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security Holders..... 20
Item 6. Exhibits and Reports on Form 8-K........................ 21
Signatures........................................................ 22
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PART I. FINANCIAL INFORMATION
ITEM I. FINANCIAL STATEMENTS
PRIMA ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, December 31,
2001 2000
------------- -------------
(Unaudited)
CURRENT ASSETS
Cash and cash equivalents .................. $ 19,769,000 $ 20,382,000
Available for sale securities, at market.... 2,426,000 2,311,000
Receivables (net of allowance for doubtful
accounts: 6/30/01, $45,000; 12/31/00,
$44,000).................................. 8,932,000 8,902,000
Derivatives, at fair value ................. 2,144,000 --
Tubular goods inventory .................... 1,721,000 1,409,000
Other ...................................... 716,000 1,042,000
------------- -------------
Total current assets ................. 35,708,000 34,046,000
------------- -------------
OIL AND GAS PROPERTIES, at cost, accounted
for using the full cost method ........... 129,762,000 109,652,000
Less accumulated depreciation,
depletion and amortization ............... (47,555,000) (43,935,000)
------------- -------------
Oil and gas properties - net ......... 82,207,000 65,717,000
------------- -------------
PROPERTY AND EQUIPMENT, at cost
Oilfield service equipment ................. 8,592,000 7,664,000
Office furniture and equipment ............. 805,000 729,000
Field office, shop and land ................ 473,000 473,000
------------- -------------
9,870,000 8,866,000
Less accumulated depreciation .............. (4,442,000) (3,986,000)
------------- -------------
Property and equipment - net ......... 5,428,000 4,880,000
------------- -------------
OTHER ASSETS ............................... 1,257,000 257,000
------------- -------------
$ 124,600,000 $ 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
June 30, December 31,
2001 2000
-------------- --------------
(Unaudited)
CURRENT LIABILITIES
Accounts payable ....................................... $ 2,515,000 $ 3,207,000
Amounts payable to oil and gas property owners ......... 2,524,000 2,501,000
Ad valorem and production taxes payable ................ 3,925,000 1,857,000
Accrued and other liabilities .......................... 537,000 803,000
Deferred tax liability ................................. 626,000 --
-------------- --------------
Total current liabilities ........................ 10,127,000 8,368,000
AD VALOREM TAXES, non-current .......................... 2,056,000 3,213,000
DEFERRED TAX LIABILITY ................................. 19,034,000 13,021,000
-------------- --------------
Total liabilities ................................ 31,217,000 24,602,000
-------------- --------------
STOCKHOLDERS' EQUITY
Preferred stock, $0.001 par value, 2,000,000 shares
authorized; no shares issued or outstanding .......... -- --
Common stock, $0.015 par value, 35,000,000 shares
authorized; 12,815,873 and 12,793,373 shares issued... 192,000 192,000
Additional paid-in capital ............................. 2,236,000 1,760,000
Retained earnings ...................................... 92,819,000 78,472,000
Accumulated other comprehensive income (loss) .......... 1,091,000 (126,000)
Treasury stock, 113,289 and no shares, at cost ......... (2,955,000) --
-------------- --------------
Total stockholders' equity ....................... 93,383,000 80,298,000
-------------- --------------
$ 124,600,000 $ 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 Six Months Ended
June 30, June 30,
---------------------------- ----------------------------
2001 2000 2001 2000
------------ ------------ ------------ ------------
REVENUES
Oil and gas sales ........................... $ 11,909,000 $ 10,235,000 $ 28,266,000 $ 18,962,000
Oilfield services ........................... 2,006,000 1,525,000 3,782,000 3,184,000
Interest, dividends and other ............... 273,000 321,000 610,000 612,000
------------ ------------ ------------ ------------
14,188,000 12,081,000 32,658,000 22,758,000
------------ ------------ ------------ ------------
EXPENSES
Depreciation, depletion and amortization:
Depletion of oil and gas properties ...... 1,852,000 1,492,000 3,620,000 2,943,000
Depreciation of other property ........... 296,000 285,000 578,000 551,000
Lease operating expense ..................... 651,000 619,000 1,450,000 1,255,000
Ad valorem and production taxes ............. 869,000 753,000 2,293,000 1,484,000
Cost of oilfield services ................... 1,379,000 1,338,000 2,513,000 2,618,000
General and administrative .................. 920,000 803,000 2,008,000 1,342,000
------------ ------------ ------------ ------------
5,967,000 5,290,000 12,462,000 10,193,000
------------ ------------ ------------ ------------
Income Before Income Taxes and
Cumulative Effect of Change in
Accounting Principle ..................... 8,221,000 6,791,000 20,196,000 12,565,000
Provision for Income Taxes .................. 2,550,000 1,980,000 6,460,000 3,570,000
------------ ------------ ------------ ------------
Net Income Before Cumulative Effect of
Change in Accounting Principle ........... 5,671,000 4,811,000 13,736,000 8,995,000
Cumulative Effect of Change in
Accounting Principle .................... -- -- 611,000 --
------------ ------------ ------------ ------------
NET INCOME .................................. $ 5,671,000 $ 4,811,000 $ 14,347,000 $ 8,995,000
============ ============ ============ ============
Basic Net Income per Share Before
Cumulative Effect of Change in
Accounting Principle .................... $ 0.45 $ 0.38 $ 1.08 $ 0.71
Cumulative Effect of Change in
Accounting Principle .................... -- -- 0.05 --
------------ ------------ ------------ ------------
BASIC NET INCOME PER SHARE .................. $ 0.45 $ 0.38 $ 1.13 $ 0.71
============ ============ ============ ============
Diluted Net Income per Share Before
Cumulative Effect of Change in
Accounting Principle .................... $ 0.43 $ 0.36 $ 1.03 $ 0.68
Cumulative Effect of Change in
Accounting Principle .................... -- -- 0.05 --
------------ ------------ ------------ ------------
DILUTED NET INCOME PER SHARE ................ $ 0.43 $ 0.36 $ 1.08 $ 0.68
============ ============ ============ ============
Weighted Average Common Shares
Outstanding .............................. 12,732,542 12,715,685 12,744,977 12,730,002
============ ============ ============ ============
Weighted Average Common Shares
Outstanding Assuming Dilution ............ 13,275,321 13,304,367 13,287,674 13,271,578
============ ============ ============ ============
See accompanying notes to unaudited consolidated financial statements.
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PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
---------------------------- ----------------------------
2001 2000 2001 2000
------------ ------------ ------------ ------------
Net income .................................. $ 5,671,000 $4 811,000 $ 14,347,000 $ 8,995,000
------------ ------------ ------------ ------------
Other comprehensive income:
Unrealized gain on derivatives .............. 371,000 -- 1,769,000 --
Deferred income tax expense related to
unrealized gain on derivatives ............ (137,000) -- (654,000) --
Unrealized gain on
available-for-sale securities ............ 65,000 26,000 163,000 51,000
Deferred income tax expense
related to unrealized gain
on available-for-sale securities ......... (26,000) (17,000) (62,000) (26,000)
Reclassification adjustment for losses
included in other income .................. 1,000 18,000 1,000 18,000
------------ ------------ ------------ ------------
274,000 27,000 1,217,000 43,000
------------ ------------ ------------ ------------
COMPREHENSIVE INCOME ........................ $ 5,945,000 $ 4,838,000 $ 15,564,000 $ 9,038,000
============ ============ ============ ============
See accompanying notes to unaudited consolidated financial statements.
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PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Ended
June 30,
------------------------------
2001 2000
------------ ------------
OPERATING ACTIVITIES
Net income ........................................................... $ 14,347,000 $ 8,995,000
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization .......................... 4,198,000 3,494,000
Deferred income taxes ............................................. 6,012,000 2,515,000
Unrealized gains from trading activities .......................... (375,000) --
Other ............................................................. 102,000 173,000
Changes in operating assets and liabilities:
Receivables ..................................................... (29,000) (960,000)
Inventory ....................................................... (312,000) (410,000)
Other current assets ............................................ 235,000 (39,000)
Accounts payable and payables to owners ......................... (669,000) (788,000)
Ad valorem and production taxes payable ......................... 911,000 641,000
Accrued and other liabilities ................................... (266,000) (1,076,000)
------------ ------------
Net cash provided by operating activities ..................... 24,154,000 12,545,000
------------ ------------
INVESTING ACTIVITIES
Additions to oil and gas properties .................................. (21,111,000) (12,632,000)
Purchases of other property .......................................... (1,252,000) (1,314,000)
Purchases of available for sale securities ........................... (61,000) (186,000)
Proceeds from sales of oil and gas and other property ................ 253,000 144,000
------------ ------------
Net cash used in investing activities ......................... (22,171,000) (13,988,000)
------------ ------------
FINANCING ACTIVITIES
Treasury stock purchased ............................................. (2,955,000) (1,778,000)
Proceeds from issuance of common stock ............................... 152,000 199,000
Other ................................................................ 207,000 --
------------ ------------
Net cash used in financing activities ........................ (2,596,000) (1,579,000)
------------ ------------
DECREASE IN CASH AND CASH EQUIVALENTS ................................ (613,000) (3,022,000)
CASH AND CASH EQUIVALENTS, beginning of period ....................... 20,382,000 18,883,000
------------ ------------
CASH AND CASH EQUIVALENTS, end of period ............................. $ 19,769,000 $ 15,861,000
============ ============
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, natural gas and crude oil. 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 unaudited consolidated financial statements have been prepared in
accordance with the instructions to Form 10-Q and, therefore, do not include all
disclosures required for financial statements prepared in conformity with
generally accepted accounting principles. These consolidated financial
statements should be read in conjunction with the Annual Report on Form 10-K of
Prima Energy Corporation for the year ended December 31, 2000, including the
financial statements and notes thereto.
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 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, 2001 and 2000.
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, 2001.
3. RECENT ACCOUNTING PRONOUNCEMENTS
The Financial Accounting Standards Board has issued Statement of
Financial Accounting Standards ("SFAS") No. 143 "Accounting for Asset Retirement
Obligations."
SFAS No. 143 provides the accounting requirements for retirement
obligations associated with long-lived assets. SFAS No. 143 is effective for
fiscal years beginning after June 15, 2002, and early adoption is permitted. The
Company is currently assessing, but has not yet determined, the impact of SFAS
No. 143 on its consolidated results of operations, cash flows or financial
position.
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4. 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 32% of the
Company's natural gas production and 9% of its oil production was hedged during
the six months ended June 30, 2001, with hedging gains of $1,250,000 included in
oil and gas revenues at the time the hedged volumes were sold. The Company did
not hedge any of its natural gas or oil production during the first six months
of 2000. At June 30, 2001, the Company had open derivative positions as follows:
Monthly Contract
Volume Fixed or Strike Unrealized
MMBtu) or Price per Gains
Type of Derivative (Barrels) Term MMBtu/Bbl (Losses)
----------------------- --------- ------------------- --------------- ----------
Natural gas futures 200,000 July-September 2001 $ 5.5500 $1,398,000
Natural gas basis swaps 240,000 July-November 2001 0.4325 717,000
Natural gas basis swaps (60,000) July-September 2001 1.0775 (24,000)
Crude oil futures 10,000 July-August 2001 29.1950 40,000
Crude oil calls 10,000 July-August 2001 31.5000 13,000
----------
$2,144,000
==========
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.
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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 June 30, 2001
financial statements. As of June 30, 2001, the Company recorded a current asset
of $2,144,000, a net of tax increase in other comprehensive income of
$1,115,000, and hedging gains of $1,250,000 which are included in oil and gas
revenues for the six month ended June 30, 2001.
5. COMMON STOCK
Pursuant to the provisions of the Prima Energy Corporation 1993 Stock
Incentive Plan, during the second quarter of 2001, 22,500 shares of Prima's
common stock were issued upon the exercise of stock options, for total proceeds
of $152,000.
During the six months ended June 30, 2001, the Company repurchased
113,289 shares of its common stock as treasury stock for $2,955,000 pursuant to
a stock repurchase program. The Board of Directors has authorized the repurchase
of up to 5% of the Company's common stock, depending upon market conditions, the
Company's financial condition, anticipated capital requirements and liquidity,
among other factors. At June 30, 2001, the Company had repurchased approximately
1.0% of the shares outstanding when the authorization was approved. During the
month of July 2001, the Company acquired an additional 20,000 shares of its
common stock for $420,000.
During 2001, the shareholders of Prima approved an increase in the
number of authorized shares of common stock from 18,000,000 shares to 35,000,000
shares.
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 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.
Income Shares Per Share
(Numerator) (Denominator) Amount
----------- ------------- ----------
Quarter Ended June 30, 2001:
Basic Net Income per Share ............. $5,671,000 12,732,542 $ 0.45
==========
Effect of Stock Options ................ -- 542,779
---------- ----------
Diluted Net Income per Share ........... $5,671,000 13,275,321 $ 0.43
========== ========== ==========
Quarter Ended June 30, 2000:
Basic Net Income per Share ............. $4,811,000 12,715,685 $ 0.38
Effect of Stock Options ................ -- 588,682 ==========
---------- ----------
Diluted Net Income per Share ........... $4,811,000 13,304,367 $ 0.36
========== ========== ==========
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Income Shares Per Share
(Numerator) (Denominator) Amount
----------- ------------- ----------
Six Months Ended June 30, 2001:
Basic Net Income per Share ............. $14,347,000 12,744,977 $ 1.13
-- 542,697 ==========
Effect of Stock Options ................ ----------- ----------
Diluted Net Income per Share ........... $14,347,000 13,287,674 $ 1.08
=========== ========== ==========
Six Months Ended June 30, 2000:
Basic Net Income per Share ............. $8,995,000 12,730,002 $ 0.71
Effect of Stock Options ................ -- 541,576 ==========
----------- ----------
Diluted Net Income per Share ........... $8,995,000 13,271,578 $ 0.68
=========== ========== ==========
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Liquidity and Capital Resources
The Company's principal internal sources of liquidity are cash flows
generated from operating activities and existing net working capital. Net cash
provided by operating activities for the six months ended June 30, 2001 was
$24,154,000 compared to $12,545,000 for the same six month period of 2000. Net
working capital at June 30, 2001 was $25,581,000 compared to $25,678,000 at
December 31, 2000.
The Company invested $22,363,000 in property and equipment during the
six months ended June 30, 2001, compared to $13,946,000 for the first six months
of 2000. The Company expended $19,731,000 during the 2001 period for its
proportionate share of the costs of drilling, completing, equipping and
refracturing wells and installing gathering and compression facilities,
$1,313,000 for undeveloped acreage, $67,000 for developed properties and
$1,252,000 for other property and equipment. These expenditures compare to
$11,632,000 for well costs, $860,000 for undeveloped acreage, $140,000 for
developed properties and $1,314,000 for other equipment in the 2000 period. The
Company also expended $2,955,000 for the purchase of 113,289 shares of treasury
stock during the first six months of 2001 and $1,778,000 for 103,317 treasury
shares during the 2000 period.
During the first six months of 2001, the Company participated in the
drilling of 15 gross (14.8 net) wells and the refracturing or recompleting of 47
gross (44.0 net) wells in the Denver Basin. All of these operations have been
successfully completed and the wells placed on or restored to production.
Current plans are to drill an additional five to ten wells and to refrac or
recomplete approximately 25 wells in this area during the remainder of 2001.
During July 2001, three wells were refractured and one was recompleted.
Prima drilled 65 gross (63.5 net) CBM wells during the first half of
2001 and five gross and net wells in the current quarter to-date. Since
initiating its CBM activities in 1998, Prima has drilled a total of 240 gross
(237.6 net) wells in the play, and the Company plans to drill approximately 80
additional CBM wells during the balance of 2001, subject to completing certain
surface use agreements and obtaining winter access to various drill-sites. This
activity would increase Prima's total CBM wells drilled to approximately 320 at
year-end. The Company remains on schedule to have approximately 140 CBM wells
tied-in to sales lines and in various stages of production and de-watering by
the end of
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August 2001, and to have a total of 200 wells tied-in by year end. Prima owns
leaseholds covering 150,000 gross, 140,000 net, acres in the Powder River Basin
CBM play, most of which are still undeveloped. Approximately 80% of this acreage
represents federal leases that are currently subject to stringent limitations on
drilling, pending completion of an ongoing environmental impact study ("EIS")
for CBM drilling in the Powder River Basin, which is currently expected to be
finalized in the summer of 2002.
The Company has organized its CBM acreage into 28 defined project
areas. The following summary describes activities to-date for those project
areas where significant operations have been conducted or where near-term
activities are planned. Of the 240 CBM wells drilled by Prima to-date, 225 are
located within the project areas described. The other 15 wells were drilled in
various parts of the CBM play to obtain data useful for evaluation and planning,
and are expected to be incorporated in future development activities. The five
project areas described below on which the Company has conducted drilling
operations account for approximately one quarter of Prima's total acreage in the
Powder River Basin CBM play.
Stones Throw - The Company's 9,900-acre Stones Throw project area was the first
selected for development, due primarily to its proximity to an existing CBM
field and related infrastructure. Prima has now drilled 122 wells at Stones
Throw, of which 50 have been completed in the Canyon coal, 52 have been
completed in the Cook coal, and 20 have been completed in the Wall coal.
Ninety-nine of these wells have been hooked up to the Company's gathering system
and are now de-watering or producing. Prima has installed four screw
compressors, and two reciprocating compressors at Stones Throw, establishing
capacity to produce up to 10 million cubic feet of gas per day. Gross production
from this field has recently been averaging approximately 6,500 Mcf of gas per
day. The Company has obtained permits to drill 100 additional wells at Stones
Throw, including 90 special drainage permits recently issued by the Bureau of
Land Management ("BLM") for federal lands. Current plans call for drilling
approximately 40 wells in the Stones Throw area during the balance of 2001.
Kingsbury - The Company has drilled 27 wells in the 8,900-acre Kingsbury project
area, all of which are either producing or de-watering after having been tied
into third-party gathering and compression facilities. Gross production has
recently been averaging approximately 600 Mcf of gas per day. All wells drilled
at Kingsbury to-date have been completed in the Lower Anderson coal, but several
developable coals are present in this project area. The Company plans to submit
permit applications for 117 additional well locations in this area over the next
several months, including 50 on private lands and 67 on federal lands. The
permits for locations on federal lands may be subject to delays due to the
on-going EIS. Current plans call for the drilling of approximately 20 wells in
the Kingsbury project area during the second half of the year.
North Shell Draw - Prima has drilled 36 wells targeting the Lower Anderson coal
in this 7,400-acre project area. Other developable coals are also present.
Access to this area for drilling and pipeline construction is limited during
winter months, and no additional drilling is planned for this area in 2001. The
Company plans to install, or arrange for a third party to install, a gathering
system and compression at North Shell Draw by mid-2002. Seven wells are
currently being prepared for production testing, to obtain data that will be
utilized to configure the facilities and structure gas gathering arrangements
for this area.
Porcupine-Tuit - The Company has drilled 23 Wyodak-coal wells in this 4,900-acre
project area and current plans call for drilling four additional wells before
year-end. The timing of drilling wells at Porcupine-Tuit has been largely
dictated by lease obligations. Gathering and compression facilities
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still need to be installed in order to produce these wells, and Prima plans to
install, or arrange for a third party to install, such facilities by mid-2002.
Drilling in the area will likely resume at that time.
Hensley - Prima has drilled and completed 17 wells in the 4,800-acre Hensley
area, including eight that targeted the Lower Canyon coal, seven that were
drilled to the Wall coal, and two that were drilled to the Upper Canyon coal.
The Company anticipates entering into a gathering agreement with a third party
for this project area by the end of the current quarter. The existing wells
could be placed on line before the end of the year if an air-quality permit can
be obtained to operate a gas-fired compressor. The Company also plans to apply
for approximately 100 additional drilling permits on federal lands within the
Hensley project area over the next several months. Issuance of such permits may
be delayed due to the pending EIS.
Echeta and Wild Turkey Federal Units - The Company expects to begin drilling on
the 3,800-acre Echeta federal unit within the next 60 days. Initial plans call
for drilling between nine and 15 wells this year, targeting two different coals.
Due to conditions imposed by the BLM relating to winter access, the Company does
not expect to begin drilling on the 6,000-acre Wild Turkey federal unit until
the second quarter of 2002. Previously, drilling was expected to commence at
Wild Turkey in late 2001.
As noted above, all CBM wells hooked-up by Prima to-date are at Stones
Throw or Kingsbury. The following table shows year-to-date well status and
production for Prima's CBM operations through July 2001. Production volumes for
the latest month shown are estimates. The term "hooked-up" means the well is
completed and connected to a gas sales line and water handling facilities as of
the end of the month. The number of producing wells shown represents all wells
that produced any gas for at least one day during the month. The columns labeled
"top quartile production" show the gross production of the top-producing quarter
of the producing well count. The increasing trend of production rate per well
reflects the early stage in the production profile of a typical CBM well.
Individual well production rates during the reported period varied from less
than one Mcf per day to over 250 Mcf per day. Top quartile production rates
provide an indication of the variability in production rates within the total
group of producing wells.
Gross Production (Mcf)
------------------------------------------------------
All Producing Wells Top Quartile Wells
Total Wells Total Wells -------------------------- -------------------------
Hooked-up Producing Total Avg/Well/Day Total Avg/Well/Day
----------- ----------- ---------- ------------ --------- ------------
January 2001 ....... 49 40 30,600 25 25,500 82
February 2001 ...... 64 38 37,200 35 21,700 78
March 2001 ......... 72 55 58,900 35 36,100 83
April 2001 ......... 86 69 78,600 38 51,300 95
May 2001 ........... 103 73 89,700 40 61,100 104
June 2001 .......... 123 81 109,500 45 63,600 101
July 2001 .......... 124 110 181,600 53 118,500 136
Other
Prima controls approximately 77,000 gross, 73,000 net, undeveloped
acres in east-central Utah, on the Wasatch Plateau. The Company's Coyote Flats
prospect is located 15 to 25 miles northwest of Price, Utah. Significant
hydrocarbon production exists in the area, which is characterized by
considerable structural complexity. Immediately south of Coyote Flats, at Clear
Creek Field, in excess of 136 Bcf of natural gas has been produced from a Ferron
sandstone structural trap. To the east of the prospect area, development is
underway on the
13
14
Blackhawk coalbeds at Castlegate Field. To the southeast, Drunkards Wash Field
has produced 210 Bcf of natural gas from the Ferron coalbeds. Prima's objective
at Coyote Flats is to test the hydrocarbon potential of sandstone and coalbed
reservoirs in the Blackhawk, Emory, Ferron and Dakota members of the middle to
lower Cretaceous section. The Company has designed a drilling program to take
multiple cores and drill stem tests, and data related to gas content, reservoir
quality, and reservoir pressures will be gathered and evaluated. These data will
be utilized to determine the future potential of the Coyote Flats prospect. The
Company intends to drill the initial test well on the prospect during the second
half of 2001 and anticipates either drilling an additional well or re-entering
an existing well within the prospect area later this year. The timing is
dependent on surface-owner approvals, rig availability and government permits.
The Coyote Flats prospect is a higher-risk exploration project with no assurance
that commercial production will ever be established.
Prima owns approximately 15,700 gross, 5,400 net, undeveloped acres in
its Hells Half Acre prospect located in Natrona County, Wyoming. This prospect
is a seismically-defined structure located approximately 10 miles southeast of
the Cave Gulch Field, five miles east of the Cooper Reservoir Field, and five
miles southeast of Waltman Field. The Company plans to participate in the #11-9
Miller Ranch well to be drilled on the prospect during the second half of 2001.
The 12,700-foot test is designed to test the Lance-Mesaverde section, which
produces at the Cave Gulch and Cooper Reservoir Fields. The Company expects to
have a small working interest in the initial test well on this higher-risk
project, but will have more significant exposure on surrounding lands.
This fall, Prima plans to participate in the #11-13 Echeta Road federal
well, a 9,750 foot Muddy-sandstone exploratory test, located in Campbell County,
Wyoming. The Company will have a 25% working interest in the initial test well.
This well is located two miles southeast of Prima's Cedar Draw Field that
produces from the Muddy sandstones at approximately 9,500 feet. Cedar Draw has
produced 3.8 Bcf of natural gas and 94,000 barrels of oil since it was
discovered in November 1997.
Prima owns approximately 72,000 gross, 28,000 net, undeveloped acres on
its Merna prospect located in Sublette County, Wyoming. The Company has entered
into an agreement with a third party to support that party's effort to re-enter
and complete one well and drill a second well on offsetting acreage. In exchange
for information obtained from these operations, Prima has agreed to allow the
third party to participate in the drilling of a test well on Prima's acreage
within the next six months. Operations are currently being conducted on the
initial well re-entry to test the over-pressured Lance interval.
The Board of Directors of Prima approved a $45 million capital
expenditures budget for 2001. The Company expects that its operations, including
drilling, completion and recompletion well costs, expansion of its service
companies, undeveloped leasehold acquisitions and stock re-purchases will be
financed by funds provided by operations, working capital, various cost-sharing
arrangements, or from other financing alternatives. The Company also regularly
reviews opportunities for acquisition of assets or companies related to the oil
and gas industry which could expand or enhance its existing business. If a
sufficiently large transaction is consummated, it could involve the incurrence
of debt or issuance of equity securities.
14
15
Results of Operations
Quarters Ended June 30, 2001 and 2000
For the quarter ended June 30, 2001, the Company earned net income of
$5,671,000, or $.43 per diluted share, on revenues of $14,188,000, compared to
net income of $4,811,000, or $.36 per diluted share, on revenues of $12,081,000
for the comparable quarter of 2000. Expenses were $5,967,000 for the 2001 second
quarter compared to $5,290,000 for the 2000 second quarter. Revenues increased
$2,107,000, or 17%, expenses increased $677,000, or 13%, and net income
increased $860,000, or 18%.
Oil and gas sales for the quarter ended June 30, 2001 were $11,909,000
compared to $10,235,000 for the same quarter of 2000, an increase of $1,674,000
or 16%. The increase is primarily attributable to higher natural gas prices. The
average price received for natural gas production was $3.97 per Mcf for the 2001
quarter compared to $3.19 per Mcf for the 2000 quarter, an increase of $0.78 per
Mcf or 24%. The average price received for oil in the second quarter of 2001 was
$27.55 per barrel compared to $27.50 per barrel for the second quarter of 2000,
an increase of $0.05 per barrel or less than 1%. On an Mcf equivalent basis, the
average price received for the Company's production was $4.12 per Mcfe for the
quarter ended June 30, 2001 compared to $3.51 per Mcfe for the quarter ended
June 30, 2000. The Company's oil and gas revenues were 74% derived from the
sales of natural gas during the 2001 quarter compared to 70% in the 2000
quarter. During the second quarter of 2001, the Company hedged approximately 27%
of its natural gas production and 18% of its oil production. Hedging gains of
$828,000 are included in oil and gas revenues for this period, which increased
the average price received per Mcf of natural gas by $0.37 and per barrel of oil
by $0.12. The Company did not hedge any of its production during the second
quarter of 2000.
The Company's net natural gas production was 2,220,000 Mcf and
2,244,000 Mcf for the second quarters of 2001 and 2000, respectively, a decrease
of 24,000 Mcf or 1%. Its net oil production was 112,000 barrels for both
quarters. On an Mcf equivalent basis, the Company's second quarter production
was 77% natural gas and 23% oil for both quarters. Production levels has
decreased in the Powder River Basin conventional wells and the Wind River Basin
wells due to natural declines and limited new activity. These declines were
partially offset by slight production increases in the Denver Basin and by new
production in the Powder River Basin Coalbed Methane play.
The Company's depletion expense for oil and gas properties was
$1,852,000, or $0.64 per Mcfe, on 2,892,000 equivalent Mcf produced during the
second quarter of 2001, compared to $1,492,000, or $0.51 per Mcfe, on 2,915,000
equivalent Mcf produced during the second quarter of 2000. The higher depletion
rate reflects higher drilling and operating costs experienced during the fourth
quarter of 2000. Depreciation of other fixed assets, which includes service
equipment, furniture, office equipment and buildings, was $296,000 and $285,000
for the quarters ended June 30, 2001 and 2000, respectively.
Lease operating expenses ("LOE") were $651,000 for the quarter ended
June 30, 2001 compared to $619,000 for the quarter ended June 30, 2000. Ad
valorem and production taxes were $869,000 and $753,000 for the same periods.
Production taxes increased with higher product prices. Total lifting costs (LOE
plus ad valorem and production taxes) were 13% of oil and gas revenues and $0.53
per Mcfe for the 2001 quarter compared to 13% and $0.47 per Mcfe for the 2000
quarter.
15
16
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 completion and
swab rigs, trucking, water hauling and rental equipment, and other related
activities. Revenues were $2,006,000 for the quarter ended June 30, 2001
compared to $1,525,000 for the comparable quarter of 2000, an increase of
$481,000, or 32%. Costs of oilfield services were $1,379,000 for the quarter
ended June 30, 2001 compared to $1,338,000 for the same period of 2000, an
increase of $41,000 or 3%. For the quarter ended June 30, 2001, 39% of the fees
billed by the service companies were for Company owned wells compared to 34% for
the quarter ended June 30, 2000. Intercompany billings are eliminated in
consolidation.
General and administrative expenses ("G&A"), net of third party
reimbursements and amounts capitalized, were $920,000 for the quarter ended June
30, 2001 compared to $803,000 for the quarter ended June 30, 2000, an increase
of $117,000 or 15%. Third party reimbursement of management and operator fees
were $98,000 and $102,000 during the quarter ended June 30, 2001 and 2000,
respectively. The Company's G&A costs have otherwise increased due to expansion
of the Company's activities and operations.
The provision for income taxes was $2,550,000 for the quarter ended
June 30, 2001 compared to $1,980,000 for the quarter ended June 30, 2000, an
increase of $570,000 or 29%. The Company's effective tax rate increased to 31.0%
from 29.2%. 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
increased $1,430,000 or 21% for 2001, while the permanent differences did not
increase proportionately.
Six Months Ended June 30, 2001 and 2000
For the six months ended June 30, 2001, the Company earned net income
of $14,347,000, or $1.08 per diluted share, on revenues of $32,658,000, compared
to net income of $8,995,000, or $.68 per diluted share, on revenues of
$22,758,000 for the six months ended June 30, 2000. Expenses were $12,462,000
for the 2001 six month period compared to $10,193,000 for the 2000 six month
period. Revenues increased $9,900,000, or 44%, expenses increased $2,269,000, or
22%, and net income increased $5,352,000, or 59%.
Oil and gas sales for the six months ended June 30, 2001 were
$28,266,000 compared to $18,962,000 for the six months ended June 30, 2000, an
increase of $9,304,000 or 49%. The average price received for natural gas
production was $5.10 per Mcf for the six months ended June 30, 2001, compared to
$2.91 per Mcf for the six months ended June 30, 2000, an increase of $2.19 per
Mcf or 75%. The average price received for oil for the first six months of 2001
was $28.03 per barrel compared to $27.40 per barrel for the same period of 2000,
an increase of $0.63 per barrel or 2%. On an Mcf equivalent basis, the average
price received for the Company's production was $5.00 per Mcfe for the six
months ended June 30, 2001 compared to $3.30 per Mcfe for the six months ended
June 30, 2000. The Company's oil and gas revenues were 78% derived from the
sales of natural gas during the first six months of 2001 compared to 68% during
the first six months of 2000. During the six months ended June 30, 2001, the
Company hedged approximately 32% of its natural gas production and 9% of its oil
production. Net hedging gains of $1,250,000 increased the average price received
per Mcf of natural gas by $0.29 and per barrel of oil by $0.06. The Company did
not hedge any of its production during the six months ended June 30, 2000.
16
17
The Company's net natural gas production was 4,319,000 Mcf and
4,410,000 Mcf for the first six months of 2001 and 2000, respectively, a
decrease of 91,000 Mcf or 2%. Its net oil production was 223,000 barrels
compared to 224,000 barrels for the same six month periods, a decrease of 1,000
barrels or less than 1%. On an Mcf equivalent basis, the Company's production
for the six months ended June 30, 2001 was 76% natural gas and 24% oil, compared
to 77% natural gas and 23% oil for the same period of 2000.
The Company's depletion expense for oil and gas properties was
$3,620,000, or $0.64 per Mcfe, on 5,657,000 equivalent Mcf produced during the
first six months of 2001, compared to $2,943,000, or $0.51 per Mcfe, on
5,754,000 equivalent Mcf produced during the first six months of 2000.
Depreciation of other fixed assets was $578,000 and $551,000 for the six months
ended June 30, 2001 and 2000, respectively, an increase of $27,000, or 5%.
LOE was $1,450,000 for the six months ended June 30, 2001 compared to
$1,255,000 for the six months ended June 30, 2000. Ad valorem and production
taxes were $2,293,000 and $1,484,000 for the same periods. Total lifting costs
were 13% of oil and gas revenues and $0.66 per Mcfe for the 2001 quarter
compared to 14% and $0.48 per Mcfe for 2000.
Oilfield services revenues were $3,782,000 for the six months ended
June 30, 2001 compared to $3,184,000 for the comparable six month period of
2000, an increase of $598,000 or 19%. Costs of oilfield services were $2,513,000
for the six months ended June 30, 2001 compared to $2,618,000 for the same
period of 2000, a decrease of $105,000 or 4%. For the six months ended June 30,
2001, 39% of the fees billed by the service companies were for Company owned
wells compared to 33% for the six months ended June 30, 2000.
G&A was $2,008,000 for the six months ended June 30, 2001 compared to
$1,342,000 for the six months ended June 30, 2000, an increase of $666,000 or
50%. Third party reimbursements were $213,000 and $240,000 during the six months
ended June 30, 2001 and 2000, respectively. Management fees received from third
parties have decreased as the Company has acquired additional working interests
in operated wells and sold interests in properties it previously operated.
The provision for income taxes, including the tax effect of a change in
accounting principle, was $6,725,000 for the six months ended June 30, 2001
compared to $3,570,000 for the same six month period of 2000. Income before
income taxes increased $7,631,000 for the 2001 six month period and the
effective tax rate increased to 32.0% from 28.4%. The Company's provision for
income taxes was 89% deferred in 2001 compared to 70% in 2000.
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 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.
17
18
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company's primary market risks relate to changes in the prices
received from sales of oil and natural gas. The Company 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 between NYMEX and Rocky Mountain prices on the
hedged portion of its production, by enabling it to effectively receive a fixed
price for the hedged oil and gas production volumes. Such instruments also
generally limit the benefits realized by the Company from increases in oil and
natural gas prices on the hedged portion of its production. 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. The
Company's derivatives either qualify as cash flow hedges or fair value hedges,
and are accounted for accordingly.
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 hedging
transactions are approved by the Chief Executive Officer before they are entered
into and significant transactions are reviewed by the Company's Board of
Directors. The Company uses only conventional derivative instruments and
attempts to manage its credit risk by entering into derivative 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.
During the first six months of 2001, the Company sold 223,000 barrels
of oil. A hypothetical decrease of $2.80 per barrel (10% of average prices for
the period exclusive of hedging transactions) would have decreased the Company's
production revenues by $624,000 for the period. The Company sold 4,319,000 Mcf
of natural gas during the same period. A hypothetical decrease of $0.48 per Mcf
(10% of average prices for the period exclusive of hedging transactions) would
have decreased the Company's production revenues by $2,073,000 for the period.
The Company realized hedging and trading gains of $1,453,000 during
July and August of 2001, which will be reflected in the Company's results for
the third quarter of 2001. As of August 2, 2001, open hedging and trading
positions for production through October 2002 showed net unrealized gains of
$1,624,000, as follows:
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19
Monthly Contract
Volume Price per Unrealized
Type of Derivative (MMBtu) Term MMBtu Gains
---------------------------- --------------- -------------------------------- ----------- ----------
Natural gas basis swaps 240,000 Sept-November 2001 $0.4325 $ 207,000
Natural gas basis swaps (60,000) September 2001 1.0775 13,000
Natural gas futures 600,000 Sept-November 2001 3.6383 798,000
Natural gas futures 400,000 Dec 2001-Feb 2002 3.8697 226,000
Natural gas futures 350,000 March 2002 3.7220 51,000
Natural gas futures 300,000 April-May 2002 3.5365 80,000
Natural gas futures 200,000 June-October 2002 3.7492 249,000
----------
$1,624,000
==========
-----------------------------
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 "anticipate," "expect," "plan," "believe," or "intend" 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 liabilities, delays and associated costs 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; 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.
-----------------------------
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20
PART II OTHER INFORMATION
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
On May 16, 2001, the Company held an annual meeting of stockholders. The
following table sets forth certain information relating to each matter voted
upon at the meeting.
Votes
---------------------------------------------------------
Withheld/ Broker
Matters Voted Upon For Against Abstain Non-Votes
------------------ ----------- ----------- ------------ -----------
Election of James R. Cummings 10,771,404 389,202
as Class I Director.
Election of George L. Seward 10,810,754 349,852
as Class I Director.
Approval of an amendment to the Certificate of 10,888,871 244,079 27,656
Incorporation increasing the number of authorized shares of
common stock to 35,000,000 shares.
Approval of the Prima Energy 6,615,102 2,381,736 35,556 2,128,212
Corporation 2001 Stock Incentive Plan.
Ratification of the selection of 11,122,860 4,755 32,991
Deloitte & Touche LLP as independent auditors for 2001.
20
21
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
The following exhibits are filed herewith pursuant to Rule 601 of Regulation
S-K.
EXHIBIT NO. DOCUMENT
3.1 Certificate of Amendment of the Certificate of Incorporation
of Prima Energy Corporation
4.1 Rights Agreement dated as of May 23, 2001, between Prima
Energy Corporation and Computershare Trust Company, Inc., as
Rights Agent, including the form of Certificate of
Designation, Powers, Preferences and Rights of Series A
Participating Preferred Stock dated May 29, 2001, as Exhibit
A, the Form of Right Certificate, as Exhibit B, and the
Summary of Rights to Purchase Preferred Shares.
(Incorporated by reference to Current Report on Form 8-K for
Prima Energy Corporation dated May 23, 2001 and filed June
6, 2001.)
(b) Reports on Form 8-K
The Company filed a Report on Form 8-K dated May 10, 2001, reporting
its first quarter 2001 earnings and providing an operations update. The Company
filed a Report on Form 8-K dated May 16, 2001, announcing the appointment of
Neil L. Stenbuck to the Board of Directors to fill the vacancy created by the
concurrent resignation of Mr. Robert E. Childress. Mr. Stenbuck was also
appointed to the position of Chief Financial Officer of the Company. A Report on
Form 8-K dated May 23, 2001 announced the approval of a Shareholder Rights Plan
by Prima's Board of Directors.
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22
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 14, 2001 By /s/ Richard H. Lewis
----------------------- ----------------------------------
Richard H. Lewis,
President
Date August 14, 2001 By /s/ Neil L. Stenbuck
----------------------- ----------------------------------
Neil L. Stenbuck,
Executive Vice President - Finance
22
23
INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION
------- -----------
3.1 Certificate of Amendment of the Certificate of Incorporation
of Prima Energy Corporation
4.1 Rights Agreement dated as of May 23, 2001, between Prima
Energy Corporation and Computershare Trust Company, Inc., as
Rights Agent, including the form of Certificate of
Designation, Powers, Preferences and Rights of Series A
Participating Preferred Stock dated May 29, 2001, as Exhibit
A, the Form of Right Certificate, as Exhibit B, and the
Summary of Rights to Purchase Preferred Shares.
(Incorporated by reference to Current Report on Form 8-K for
Prima Energy Corporation dated May 23, 2001 and filed June
6, 2001.)