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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 AND EXCHANGE ACT OF 1934
For the quarterly period ended September 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 require to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes [X] No [ ]
As of October 31, 2001, the Registrant had 12,720,709 shares of Common Stock,
$0.015 Par Value, outstanding.
--------------------------------------------------------------------------------
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 .............. 12
Item 3. Quantitative and Qualitative Disclosures About Market Risk ...... 19
Cautionary Statement for Purposes of the "Safe Harbor" Provisions of the
Private Securities Litigation Reform Act of 1995 ....................... 21
PART II - OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K ................................ 21
Signatures .................................................................. 22
2
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
PRIMA ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, December 31,
2001 2000
------------- -------------
(Unaudited)
CURRENT ASSETS
Cash and cash equivalents ....................................... $ 23,347,000 $ 20,382,000
Available for sale securities, at market ........................ 2,400,000 2,311,000
Receivables (net of allowance for doubtful
accounts: $45,000 and $44,000) .............................. 6,127,000 8,902,000
Derivatives, at fair market ..................................... 5,762,000 --
Tubular goods inventory ......................................... 1,161,000 1,409 000
Other ........................................................... 669,000 1,042,000
------------- -------------
Total current assets ........................................ 39,466,000 34,046,000
------------- -------------
OIL AND GAS PROPERTIES, at cost, accounted
for using the full cost method .............................. 135,026,000 108,272,000
Less accumulated depreciation, depletion and amortization ....... (50,334,000) (43,935,000)
------------- -------------
Oil and gas properties - net ................................ 84,692,000 64,337,000
------------- -------------
PROPERTY AND EQUIPMENT, at cost
Oilfield service ................................................ 13,052,000 9,044,000
Office furniture and equipment .................................. 820,000 729,000
Field office, shop and land ..................................... 473,000 473,000
------------- -------------
14,345,000 10,246,000
Less accumulated depreciation ................................... (4,839,000) (3,986,000)
------------- -------------
Property and equipment - net ................................ 9,506,000 6,260,000
------------- -------------
OTHER ASSETS .................................................... 1,257,000 257,000
------------- -------------
$ 134,921,000 $ 104,900,000
============= =============
See accompanying notes to unaudited consolidated financial statements.
3
PRIMA ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS (CONT'D.)
LIABILITIES AND STOCKHOLDERS' EQUITY
September 30, December 31,
2001 2000
------------- -------------
(Unaudited)
CURRENT LIABILITIES
Accounts payable ......................................... $ 3,180,000 $ 3,207,000
Amounts payable to oil and gas property owners ........... 2,193,000 2,501,000
Ad valorem and production taxes payable .................. 3,862,000 1,857,000
Accrued and other liabilities ............................ 621,000 803,000
Deferred tax liability ................................... 1,445,000 --
------------- -------------
Total current liabilities ............................ 11,301,000 8,368,000
AD VALOREM TAXES, non-current ............................ 2,776,000 3,213,000
DEFERRED TAX LIABILITY ................................... 21,030,000 13,021,000
------------- -------------
Total liabilities .................................... 35,107,000 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; 12,860,998 and 12,793,373 shares issued .... 193,000 192,000
Additional paid-in capital ............................... 2,806,000 1,760,000
Retained earnings ........................................ 99,886,000 78,472,000
Accumulated other comprehensive income (loss) ............ 471,000 (126,000)
Treasury stock, 140,289 and no shares, at cost ........... (3,542,000) --
------------- -------------
Total stockholders' equity ........................... 99,814,000 80,298,000
------------- -------------
$ 134,921,000 $ 104,900,000
============= =============
See accompanying notes to unaudited consolidated financial statements.
4
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------------- ----------------------------
2001 2000 2001 2000
----------- ----------- ----------- -----------
REVENUES
Oil and gas sales ................................ $ 9,163,000 $11,428,000 $37,429,000 $30,390,000
Gains on derivative instruments, net ............. 5,552,000 -- 5,552,000 --
Oilfield services ................................ 2,223,000 1,526,000 6,005,000 4,710,000
Interest, dividend and other income .............. 237,000 310,000 847,000 922,000
----------- ----------- ----------- -----------
17,175,000 13,264,000 49,833,000 36,022,000
----------- ----------- ----------- -----------
EXPENSES
Depreciation, depletion and amortization:
Depletion of oil and gas properties ........... 2,779,000 1,443,000 6,399,000 4,386,000
Depreciation of other property ................ 462,000 295,000 1,040,000 846,000
Lease operating expense .......................... 869,000 655,000 2,319,000 1,910,000
Ad valorem and production tax .................... 635,000 950,000 2,928,000 2,434,000
Cost of oilfield services ........................ 1,373,000 1,215,000 3,886,000 3,833,000
General and administrative ....................... 815,000 787,000 2,823,000 2,129,000
----------- ----------- ----------- -----------
6,933,000 5,345,000 19,395,000 15,538,000
----------- ----------- ----------- -----------
Income Before Income Taxes and
Cumulative Effect of Change in
Accounting Principle .......................... 10,242,000 7,919,000 30,438,000 20,484,000
Provision for Income Taxes ....................... 3,175,000 2,350,000 9,635,000 5,920,000
----------- ----------- ----------- -----------
Net Income Before Cumulative
Effect of Change in
Accounting Principle .......................... 7,067,000 5,569,000 20,803,000 14,564,000
Cumulative Effect of Change in
Accounting Principle .......................... -- -- 611,000 --
----------- ----------- ----------- -----------
NET INCOME ....................................... $ 7,067,000 $ 5,569,000 $21,414,000 $14,564,000
=========== =========== =========== ===========
Basic Net Income per Share Before
Cumulative Effect of Change in
Accounting Principle .......................... $ 0.56 $ 0.44 $ 1.63 $ 1.14
Cumulative Effect of Change in
Accounting Principle .......................... -- -- 0.05 --
----------- ----------- ----------- -----------
BASIC NET INCOME PER SHARE ....................... $ 0.56 $ 0.44 $ 1.68 $ 1.14
=========== =========== =========== ===========
Diluted Net Income per Share Before
Cumulative Effect of Change in
Accounting Principle .......................... $ 0.54 $ 0.42 $ 1.57 $ 1.10
Cumulative Effect of Change in
Accounting Principle .......................... -- -- 0.05 --
----------- ----------- ----------- -----------
DILUTED NET INCOME PER SHARE ..................... $ 0.54 $ 0.42 $ 1.62 $ 1.10
=========== =========== =========== ===========
Weighted Average Common Shares
Outstanding ................................... 12,704,951 12,751,284 12,731,488 12,737,148
=========== =========== =========== ===========
Weighted Average Common Shares
Outstanding Assuming Dilution ................. 13,192,611 13,341,946 13,240,255 13,278,912
=========== =========== =========== ===========
See accompanying notes to unaudited consolidated financial statements.
5
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------------- -------------------------------
2001 2000 2001 2000
------------ ------------ ------------ ------------
Net income ................................... $ 7,067,000 $ 5,569,000 $ 21,414,000 $ 14,564,000
------------ ------------ ------------ ------------
Other comprehensive income:
Unrealized gain on hedges .................... 592,000 -- 3,611,000 --
Deferred income tax expense related to
unrealized gain (loss) on hedges .......... 363,000 -- (291,000) --
Reclassification adjustment for (gains)
losses included in net income ............ (1,575,000) -- (2,825,000) --
Unrealized gain(loss) on available-for-
sale securities .......................... 1,000 85,000 164,000 135,000
Deferred income tax expense related to
unrealized gain on available-for-sale
securities ............................... -- (31,000) (62,000) (57,000)
Reclassification adjustment for losses
included in other income ................. (1,000) -- -- 18,000
------------ ------------ ------------ ------------
(620,000) 54,000 597,000 96,000
------------ ------------ ------------ ------------
COMPREHENSIVE INCOME ......................... $ 6,447,000 $ 5,623,000 $ 22,011,000 $ 14,660,000
============ ============ ============ ============
See accompanying notes to unaudited consolidated financial statements.
6
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Nine Months Ended
September 30,
-------------------------------
2001 2000
------------ ------------
OPERATING ACTIVITIES
Net income ................................................. $ 21,414,000 $ 14,564,000
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization ................ 7,439,000 5,232,000
Deferred income taxes ................................... 9,193,000 3,891,000
Unrealized gains from derivative instruments ............ (4,975,000) --
Other ................................................... 452,000 556,000
Changes in operating assets and liabilities:
Receivables .......................................... 2,775,000 (3,119,000)
Inventory ............................................ 248,000 (1,113,000)
Other current assets ................................. 282,000 95,000
Accounts payable and payables to owners .............. (335,000) 623,000
Production taxes payable ............................. 1,568,000 1,623,000
Accrued and other liabilities ........................ (182,000) (735,000)
------------ ------------
Net cash provided by operating activities ........ 37,879,000 21,617,000
------------ ------------
INVESTING ACTIVITIES
Additions to oil and gas properties ........................ (27,811,000) (19,406,000)
Additions to other property ................................ (4,468,000) (2,486,000)
Purchases of available for sale securities ................. (92,000) (216,000)
Proceeds from sales of oil and gas and other property ...... 431,000 170,000
------------ ------------
Net cash used in investing activities ............ (31,940,000) (21,938,000)
------------ ------------
FINANCING ACTIVITIES
Treasury stock purchased ................................... (3,542,000) (1,778,000)
Proceeds from issuance of common stock ..................... 361,000 455,000
Other ...................................................... 207,000 --
------------ ------------
Net cash used in financing activities ............ (2,974,000) (1,323,000)
------------ ------------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS ........... 2,965,000 (1,644,000)
CASH AND CASH EQUIVALENTS, beginning of period ............. 20,382,000 18,883,000
------------ ------------
CASH AND CASH EQUIVALENTS, end of period ................... $ 23,347,000 $ 17,239,000
============ ============
See accompanying notes to unaudited consolidated financial statements.
7
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 nine month report filed on Form 10-Q is
representative of its financial position, its results of operations and its cash
flows for the periods ended September 30, 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 to the classifications at September 30, 2001.
On a quarterly basis, the Company is required to review the carrying
value of its oil and gas properties under the full cost accounting rules of the
Securities and Exchange Commission. Under these rules, capitalized costs of
proved oil and gas properties may not exceed the present value of estimated
future net revenues from proved reserves, discounted at 10%. Application of the
ceiling test generally requires calculating future revenue using unescalated
prices in effect as of the last day of the quarter and requires a write-down for
accounting purposes if the ceiling is exceeded. At September 30, 2001, "spot"
prices applicable to the Company's natural gas sales were temporarily depressed
to a level whereby the Company's capitalized costs exceeded the present value of
future net revenues discounted at 10% by approximately $25 million. This
calculation was based on a spot price for gas delivered into the Colorado
Interstate Gas ("CIG") System of $1.05 per MMBtu. Subsequent to September 30,
2001 and prior to the release of these interim financial statements, the CIG
spot price increased substantially, to levels above $2.00 per MMBtu. As a
result, the calculated present value of the Company's future net revenues,
discounted at 10%, once again exceeded the Company's capitalized costs, and a
write-down as of September 30, 2001 was not necessary.
3. RECENT ACCOUNTING PRONOUNCEMENTS
In July 2001, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standard ("SFAS") No. 141, "Business
Combinations." SFAS No. 141 is intended to improve the transparency of the
accounting and reporting for business combinations by requiring that all
business combinations be accounted for under a single method, the purchase
method. This statement is effective for all business combinations initiated
after June 30, 2001.
8
In July 2001, the FASB issued SFAS No. 142, "Goodwill and Other
Intangible Assets." This statement applies to intangibles and goodwill acquired
after June 30, 2001, as well as goodwill and intangibles previously acquired.
Under this statement, goodwill as well as other intangibles determined to have
an infinite life will no longer be amortized. These assets will be reviewed for
impairment on a periodic basis. This statement is effective for the Company in
the first quarter of 2002. Management does not believe the adoption of this
statement will have a material effect on the Company's financial position or
results of operations.
In August 2001, the FASB issued SFAS No. 143 "Accounting for Asset
Retirement Obligations." SFAS No. 143 provides the accounting requirements for
retirement obligations associated with long-lived assets and requires the fair
value of a liability for an asset retirement obligation be recognized in the
period in which it is incurred if a reasonable estimate of fair value can be
made. The associated asset retirement costs are capitalized as part of the
carrying costs of the asset. 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.
In October 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." SFAS No. 144 requires that
long-lived assets be measured at the lower of carrying amount or fair value less
costs to sell, whether reported in continuing operations or in discontinued
operations. Therefore, discontinued operations will no longer be measured at net
realizable value or include amounts for operating losses that have not yet
occurred. SFAS No. 144 is effective for financial statements issued for fiscal
years beginning after December 15, 2001 and generally is to be applied
prospectively.
4. DERIVATIVE ACTIVITIES
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.
These cash flow hedging derivatives are entered into to mitigate the risk of
fluctuating oil and natural gas prices and fluctuating basis differentials,
which can adversely affect operating results. While such hedges can reduce the
adverse effects of oil and gas price declines, they may also limit the benefits
of price increases. The Company's derivatives transactions have been entered
into with major financial institutions, thereby minimizing credit risk.
Statement of Financial Accounting Standards No. 133 "Accounting for
Derivative Instruments and Hedging Activities" ("SFAS 133"), as amended, was
adopted by the Company effective January 1, 2001. 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. SFAS 133
prescribes requirements for designation and documentation of hedging
relationships, and ongoing assessments of effectiveness, in order to qualify for
hedge accounting. Hedge effectiveness is measured based on the relative changes
over time in the fair values of the derivative and the hedged item. If a cash
flow hedge qualifies for hedge accounting under SFAS 133, and is so designated
by the Company, changes in the fair value of the derivative are recorded
initially in other comprehensive income and then recognized in the income
statement when the hedged item affects earnings. If a cash flow hedge does not
qualify for hedge accounting under SFAS 133, or if the Company so elects,
changes in the fair value of the derivative are immediately recognized in
earnings.
All derivatives within the Company have been evaluated in accordance
with SFAS 133. Pursuant to SFAS 133 requirements, the Company has determined
that swaps, collars, puts or floors that are based on NYMEX oil prices or CIG
gas prices qualify as cash flow hedges, but derivatives based on NYMEX gas
prices do not so qualify unless the Company has entered into corresponding
transactions to hedge basis
9
differentials between NYMEX and CIG indices. In addition, sales of call options
do not qualify for hedge accounting.
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 September 30,
2001 financial statements.
The Company has entered into various cash flow hedges related to its
oil and gas production. Some of these derivatives qualify for hedge accounting,
while others are non-qualifying. The following table summarizes the income
statement effects of these transactions in 2001, through the end of the third
quarter (the Company did not hedge any of its natural gas or oil production
during the first nine months of 2000):
Three Months Ended Nine Months Ended
September 30, 2001 September 30, 2001
------------------ ------------------
Realized gains on derivatives qualifying for
hedge accounting, included in oil and gas sales ..... $ 1,575,000 $ 2,825,000
Realized gains on non-qualifying hedges ............... 577,000 577,000
Unrealized gains on non-qualifying hedges ............. 4,975,000 4,975,000
------------------ ------------------
Aggregate amounts reported on consolidated
statements of income ................................ $ 7,127,000 $ 8,377,000
================== ==================
In addition, as of September 30, 2001, net unrealized gains on
derivatives qualifying for hedge accounting, aggregating $786,000 ($495,000 net
of related income taxes), were included in accumulated other comprehensive
income.
As of September 30, 2001, the Company had recorded a current asset of
$5,762,000, representing the aggregate unrealized mark-to-market gains for its
open derivative positions (both qualifying and non-qualifying), which are
summarized below:
Market Total Volumes Contract Unrealized
Time Period Index (MMBtu or Bbls) Price Gains
----------- ------ --------------- -------- ---------------
Natural gas
October 1 - November 30, 2001 CIG 480,000 3.0415 $ 778,000
October 1 - December 31, 2001 NYMEX 1,320,000 3.6119 1,771,000
January 1 - March 31, 2002 NYMEX 1,900,000 3.6201 1,516,000
April 1 - June 30, 2002 NYMEX 1,400,000 3.3440 796,000
July 1 - September 30, 2002 NYMEX 1,200,000 3.4500 667,000
October 1 - October 31, 2002 NYMEX 400,000 3.4910 226,000
Crude Oil Calls
November 1 - December 31, 2001 NYMEX 15,000 29.00 8,000
---------------
Total Unrealized Gains $ 5,762,000
===============
Oil and gas prices are volatile and the market value of these
derivatives will change as the underlying commodity futures prices change.
Mark-to-market adjustments could result in significant earnings volatility. The
actual gains or losses realized will depend on the applicable futures prices in
effect at the time such positions expire or are closed.
10
5. COMMON STOCK
Pursuant to the provisions of the Prima Energy Corporation 1993 Stock
Incentive Plan and the Non-Employee Directors' Stock Option Plan, during the
second and third quarters of 2001, 67,625 shares of Prima's common stock were
issued upon the exercise of stock options, for total proceeds of $361,000.
During the nine months ended September 30, 2001, the Company
repurchased 140,289 shares of its common stock as treasury stock for $3,542,000
pursuant to a stock repurchase program. The Board of Directors has authorized
the repurchase of up to 5% of the Company's common stock, depending upon market
conditions, the Company's financial condition, anticipated capital requirements
and liquidity, among other factors. At September 30, 2001, the Company had
repurchased approximately 1.1% of the shares that were outstanding when the
authorization was approved.
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 September 30, 2001:
Basic Net Income per Share ..... $ 7,067,000 12,704,951 $ 0.56
===========
Effect of Stock Options ........ -- 487,660
----------- -----------
Diluted Net Income per Share ... $ 7,067,000 13,192,611 $ 0.54
=========== =========== ===========
Quarter Ended September 30, 2000:
Basic Net Income per Share ..... $ 5,569,000 12,751,284 $ 0.44
===========
Effect of Stock Options ........ -- 590,662
----------- -----------
Diluted Net Income per Share ... $ 5,569,000 13,341,946 $ 0.42
=========== =========== ===========
Nine Months Ended September 30, 2001:
Basic Net Income per Share ..... $21,414,000 12,731,488 $ 1.68
===========
Effect of Stock Options ........ -- 508,767
----------- -----------
Diluted Net Income per Share ... $21,414,000 13,240,255 $ 1.62
=========== =========== ===========
Nine Months Ended September 30, 2000:
Basic Net Income per Share ..... $14,564,000 12,737,148 $ 1.14
===========
Effect of Stock Options ........ -- 541,764
----------- -----------
Diluted Net Income per Share ... $14,564,000 13,278,912 $ 1.10
=========== =========== ===========
11
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 nine months ended September 30, 2001
was $37,879,000 compared to $21,617,000 for the same nine-month period of 2000,
representing a 75% increase. Net working capital at September 30, 2001 was
$28,165,000 compared to $25,678,000 at December 31, 2000. Prima's cash
equivalents and short-term investments totaled $25,747,000 at September 30,
2001, compared to $22,693,000 at the end of 2000. The Company was free of
long-term debt at both dates. Prima expects to fund its exploration,
development, and exploitation operations, expansion of its service companies,
and stock re-purchases using cash provided by operating activities, working
capital, various cost-sharing arrangements, or other financing alternatives. The
Company also regularly reviews opportunities for acquisition of assets or
companies related to the oil and gas industry that could expand or enhance its
existing business. If a sufficiently large transaction is consummated, it could
involve the incurrance of debt or issuance of equity securities.
The Company's revenues and cash flows are substantially derived from
oil and gas sales, which are dependent on oil and gas production volumes and
sales prices. Prima's aggregate net production volumes have increased from
2,765,000 Mcfe in the first quarter of 2001, to 2,892,000 Mcfe in the second
quarter, and 3,088,000 Mcfe in the most recent quarter, but gas prices have
declined more significantly during the same period. As a consequence, the
Company's oil and gas sales revenue, including derivatives qualifying for hedge
accounting, declined from $16,357,000 in the first quarter, to $11,909,000 in
the following quarter, and $9,163,000 in the latest quarter. Prima's future
revenues will continue to be significantly affected by volatility in oil and gas
prices.
During the first nine months of 2001, the Company invested $32,279,000
in property and equipment, compared to $21,892,000 invested in the nine months
ended September 30, 2000. The Company expended $25,850,000 during the 2001
period for its proportionate share of the costs of drilling, completing,
equipping and refracturing wells, $1,884,000 for undeveloped acreage, $77,000
for developed properties and $4,468,000 for gathering and compression facilities
and other property and equipment. These expenditures compare to $17,550,000 for
well costs, $1,651,000 for undeveloped acreage, $205,000 for developed
properties and $2,486,000 for other equipment in the 2000 period. The Company
also expended $3,542,000 for the purchase of 140,289 shares of treasury stock
during the first nine months of 2001 and $1,778,000 for 103,317 treasury shares
purchased during the 2000 period.
The Board of Directors of Prima approved a $45 million capital
expenditures budget for 2001 earlier in the year. However, the Company has
recently decided to defer certain investments to obtain the benefit of
anticipated improvements in service costs or gas prices (as reflected in recent
futures markets quotations), and to re-schedule some operations in the Powder
River Basin coal bed methane ("CBM") play to occur closer to expected in-service
dates of related infrastructure projects. Prima's investments in property and
equipment in 2001 are now expected to total approximately $38 million.
Significant investment activities and related operations are updated
below.
Denver Basin Operations
During the first nine months of 2001, the Company participated in the
drilling of 19 gross (18.8 net) wells and the refracturing or recompleting of 59
gross (55.1 net) wells in the Denver Basin. All of these operations have been
successfully completed and all but one of the wells have already been placed on
or returned to production. New wells and recompletion operations in the Denver
Basin are characterized by flush production at relatively high rates for a few
months, after which lower production levels are established at relatively
shallow decline rates. The Company generally accelerates these operations when
12
oil and gas prices are high and defers them when prices are low, to enhance the
impact on investment returns from the flush production. Because of oil and gas
price declines, and high line pressure attributable to limited processing
capacity in the area, Prima elected to postpone certain drilling and
recompletion operations that had been scheduled for the third and fourth
quarters of 2001. Following a recent recovery in gas prices, and in anticipation
of scheduled expansion of third-party owned plant capacity by the end of this
year, the Company has resumed recompletion operations, but is still deferring
new wells until costs decline or prices increase further. Current plans are to
refrac or recomplete approximately seven wells in the Denver Basin during the
current quarter.
Powder River Basin Coal Bed Methane Operations
Prima owns leaseholds covering 150,000 gross, 140,000 net, acres in the
Powder River Basin CBM play, most of which are still undeveloped. At the end of
2000, Prima's independent engineering consultants identified over 2000 well
locations with estimated proved or probable gas reserves on the Company's lands.
Approximately 80% of this acreage is comprised of federal leases that are
currently subject to stringent limitations on drilling, pending completion of an
ongoing environmental impact statement ("EIS") for CBM drilling in the Powder
River Basin. This EIS is currently expected to be finalized in the summer of
2002.
Prima has drilled 114 gross (111.5 net) wells in the CBM development
area year to-date, including 103 (101.5 net) wells drilled during the first nine
months of the year. Since initiating its CBM activities in 1998, the Company has
drilled a total of 280 gross (277.6 net) wells in the play, and plans to drill
approximately ten additional CBM wells during the balance of 2001. Approximately
140 CBM wells have been tied-in to sales lines and are in various stages of
production or de-watering. This number is expected to increase to approximately
156 by year-end.
The Company has organized its CBM acreage into 28 defined project
areas. Of the 280 CBM wells drilled by Prima to-date, 272 are located within six
of these project areas, each of which is briefly described below. Concentration
of Prima's development activities to-date within these project areas, and on the
specific coals targeted so far, reflect a number of considerations other than
estimated recoverable reserves and projected production rates. The Company's CBM
activities have been limited to fee lands, state lands, and certain coals
underlying federal lands for which drilling permits have been attainable. These
activities have largely been focused on relatively shallow coals, near
development activities of other operators. Generally, the higher-potential coals
identified on the Company's lands have not yet been developed. These deeper,
thicker coal sequences are also not yet proven through development by other
operators, and once developed, are expected to take longer to de-water than
coals that have already been under development and production in the region for
a period of time. The Company recently reduced the pace of its development
activities in the CBM play due to lower gas prices, regulatory constraints, and
delays in infrastructure development required to tie-in new wells. The Company
plans to aggressively develop its CBM acreage as infrastructure development
proceeds and regulatory constraints are addressed. Current plans call for
focusing near-term activities within the project areas discussed below where
existing infrastructure and available drilling permits facilitate cost-effective
development, and on commencing limited pilot projects to begin to test some of
the deeper, higher-potential coals underlying Prima's acreage. The following is
a brief update on activities in the six project areas where most of Prima's CBM
operations have been conducted to-date.
Stones Throw - The 9,900-acre Stones Throw project area was the first
selected by the Company for CBM development, due primarily to its proximity to
an existing CBM field and related infrastructure. Prima has now drilled 153
wells at Stones Throw, of which 114 are currently de-watering or producing. Each
well drilled has targeted either the Canyon, Cook, or Wall coal, at depths
between approximately 500 and 850 feet. Prima has installed compression at
Stones Throw with current capacity to produce up to 10 million cubic feet of gas
per day, and gross production from the field has recently been averaging
approximately 8 million cubic feet of gas per day. Current plans call for
connecting most of the remaining wells drilled in this field into a sales line
by the first quarter of next year, but deferring further drilling pending
additional production history or improved gas markets. Production results
to-date have been less than expected from 29 wells drilled in the southeast
portion of the project area (Section 16) and from 20
13
other wells completed in the Wall coal, which is thinner and shallower in this
area than in some other portions of the CBM play. However, Cook and Canyon coal
results outside of Section 16 have been more encouraging and production has been
continuing to incline.
Kingsbury - Prima has drilled 28 wells in the 8,900-acre Kingsbury
project area, of which 26 are producing or de-watering after having been tied
into third-party gathering and compression facilities. All but two wells drilled
at Kingsbury to-date have been completed in the Lower Anderson coal, but several
developable coals are present in this project area. Production has continued to
incline as de-watering progresses, and gross production at Kingsbury has
recently been averaging approximately 950 Mcf of gas per day. The Company plans
to submit applications for permits to drill additional wells on both private and
federal lands in this area., but permits for locations on federal lands may be
subject to delays due to the on-going EIS. Current plans are to drill and test
approximately ten wells in the Kingsbury area during the current quarter, and to
formulate 2002 drilling plans for the project after additional monitoring of
production performance.
North Shell Draw - Prima has drilled 35 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 until spring 2002.
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. Encouraging
results were obtained from production testing of seven North Shell Draw wells
during the third quarter. These data will be used to design facilities,
structure gas gathering arrangements and plan 2002 drilling activities for this
area.
Porcupine-Tuit - The Company has drilled 23 Wyodak-coal wells in this
5,500-acre project area, which exhibits favorable coal quality and thickness at
relatively shallow depths. Other operators in the area have already reported
encouraging results from completions in the same coal. After an air quality
permit to operate compression facilities is obtained, Prima plans to install or
arrange for installation of gathering and compression facilities. Initial
production is expected to be established by spring 2002. Drilling in the area
will likely resume at that time, but is expected to initially be limited by
availability of drilling permits on federal lands. Prima's acreage position in
the Porcupine-Tuit area was recently enhanced by an acquisition closed in the
current quarter that added approximately 1,800 gross (800 net) undeveloped
acres.
Hensley - Prima has drilled and completed 18 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 three that were drilled to the Upper Anderson
coal. The Company is finalizing a gathering agreement with a third party for
this project area, and 16 of the existing wells at Hensley could be placed
on-line by year-end if compression facilities can be installed within that time
frame. The Company plans to apply for additional drilling permits on federal
lands within the Hensley project area over the next several months, but issuance
of such permits may be delayed due to the pending EIS.
Cedar Draw - The Company recently drilled 15 wells, including nine unit
obligation wells, on the 3,800-acre Echeta federal unit within the 6,000-acre
Cedar Draw project area. Three different coals were targeted by these 15 wells,
which will provide test data useful for formulating further development plans.
Cedar Draw is in close proximity to the North Shell Draw area, and the Company
anticipates coordinating development of the two projects, including
infrastructure installation and the scheduling of additional drilling during
2002.
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 October 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 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
14
varied from less than one Mcf per day to over 350 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 Top Quartile
Total Wells Total Wells Wells 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 124 110 179,200 53 117.000 135
August 2001 138 129 214,100 54 144,500 141
September 2001 140 138 243,800 59 153,100 146
October 2001 140 138 273,000 64 164,700 152
Other Operations
Prima has continued to expand its acreage position in east-central
Utah, on the Wasatch Plateau, to approximately 95,000 gross (90,000 net)
undeveloped acres, covering several different prospects. Approximately 75,000
gross (71,000 net) acres are included in the Company's Coyote Flats prospect.
The 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. Prima's objective at Coyote Flats is to test
the hydrocarbon potential of sandstone and coal bed reservoirs in the Blackhawk,
Emery, Ferron and Dakota members of the middle to lower Cretaceous section. The
Company has elected to postpone drilling the initial test well on Coyote Flats
until the summer of 2002, when test wells on two other prospects in the area are
also planned. These are higher-risk exploration projects with no assurance that
commercial production will ever be established.
Prima owns approximately 17,500 gross (5,300 net) undeveloped acres in
the 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 is participating in the #11-9
Miller Ranch well, which is currently drilling. This 12,700-foot test is
designed to evaluate the Lance-Mesaverde section, which produces at the Cave
Gulch and Cooper Reservoir Fields. The Company has approximately a 7% working
interest in this well, but retains more significant exposure in surrounding
lands. Hells Half Acre is also prospective at depths ranging to approximately
20,000 feet for large-potential reserve accumulations. Prima anticipates that
the operator will propose a test well to evaluate deeper horizons sometime
during the first half of 2002.
Prima owns approximately 72,000 gross (28,000 net) undeveloped acres on
its Merna prospect, which is located in Sublette County, Wyoming, 10 to 30 miles
north of the Pinedale Anticline. 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 agreed to allow the third party to
participate in the drilling of a test well on Prima's acreage within the next
nine months. Operations are currently being conducted on the initial well
re-entry to test the over-pressured Lance interval.
15
Results of Operations
The Company's primary source of revenues is the sale of oil and natural
gas production. Because of fluctuations in oil and natural gas prices and
production volumes, the Company's operating results for any period are not
necessarily indicative of future operating results.
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. Prima's revenues, cash flows, earnings and
operations are adversely affected when oil and gas prices decline. Gas prices
have declined significantly since reaching record high levels early in 2001, and
oil prices have also declined in 2001, albeit more modestly. These price
declines have unfavorably impacted the Company's operating results, as more
fully described below. The Company cannot accurately predict future oil and
natural gas prices, but, historically, oil and gas supply and demand have
responded to changes in price levels to correct from short-lived extreme levels
of high or low prices.
Quarters Ended September 30, 2001 and 2000
For the quarter ended September 30, 2001, the Company earned net income
of $7,067,000, or $0.54 per diluted share, on revenues of $17,175,000. These
results compare to net income of $5,569,000, or $0.42 per diluted share, on
revenues of $13,264,000 for the comparable quarter of 2000. Expenses totaled
$6,933,000 in the 2001 third quarter, compared to $5,345,000 for the 2000 third
quarter. Revenues increased $3,911,000, or 29%, expenses increased $1,588,000,
or 30%, and net income increased $1,498,000, or 27%.
Revenues for the 2001 period included $7,127,000 of gains related to
oil and gas derivatives (see Note 4). This total was comprised of hedging gains,
which are discussed below, plus realized and unrealized gains on derivative
instruments that did not qualify for hedge accounting, in the amounts of
$577,000 and $4,975,000, respectively. No comparable amounts were reported in
2000.
Excluding gains from derivative instruments, oil and gas sales reported
for the quarter ended September 30, 2001 were $7,588,000, compared to
$11,428,000 for the same quarter of 2000, a decrease of $3,840,000 or 34%. The
decrease was attributable to lower natural gas and oil prices, partially offset
by increased production volumes.
The following information is provided excluding effects of derivatives.
The average sales price received by the Company for natural gas production was
$1.96 per Mcf for the 2001 quarter, compared to $3.73 per Mcf for the 2000
quarter, a decrease of $1.77 per Mcf, or 47%. The average price received for oil
in the third quarter of 2001 was $26.39 per barrel compared to $30.80 per barrel
for the second quarter of 2000, a decrease of $4.41 per barrel or 14%. On an Mcf
equivalent basis, the average price received was $2.46 per Mcfe for the quarter
ended September 30, 2001 compared to $4.06 per Mcfe for the quarter ended
September 30, 2000, representing an overall 39% decline in average prices. The
Company's oil and gas revenues were 63% derived from natural gas sales during
the 2001 quarter compared to 71% in the 2000 quarter.
Hedging gains of $1,575,000 are included in oil and gas revenues for
the third quarter of 2001. Such gains had the effect of increasing average price
realizations by $0.63 per Mcf of natural gas, $0.59 per barrel of oil, and $0.51
per Mcfe. Cumulative gains realized on derivatives relating to production months
in the third quarter of 2001 aggregated $2,515,000, including gains from
derivatives that qualify for hedge accounting and gains from non-qualifying
derivatives, and including both gains reported in the current period and gains
previously reported. The Company did not hedge any of its production during the
third quarter of 2000.
16
The Company's net natural gas production totaled 2,456,000 Mcf and
2,165,000 Mcf for the third quarters of 2001 and 2000, respectively, an increase
of 291,000 Mcf, or 13%, in the current year. Prima's net oil production totaled
105,000 barrels and 109,000 barrels in the third quarters of 2001 and 2000,
respectively, a decrease of 4,000 barrels, or 4%. On an equivalent unit basis,
the Company's production increased approximately 10%, to 3,088,000 Mcfe in the
recent quarter from 2,817,000 Mcfe last year. Total production was 80% natural
gas and 20% oil in the third quarter of 2001, compared to 77% gas and 23% oil in
the same period last year. Net production from the Company's CBM operations,
which totaled 518,000 Mcf in the recent quarter, compared to none last year,
more than offset net decreases from the Company's other producing properties
attributable to natural declines and limited new activity.
The Company's depletion expense for oil and gas properties was
$2,779,000, or $0.90 per Mcfe, in the third quarter of 2001, compared to
$1,443,000, or $0.51 per Mcfe, in the third quarter of 2000. The substantial
increase in the depletion rate reflects a number of factors, including:
significant declines in oil and gas prices, which, under the methodology
prescribed, affects estimates of oil and gas reserves that can be economically
recovered through future production; increases in oilfield service costs, which
impacted actual costs incurred during the past year and the assumptions required
to be used in estimating future development costs; and use of more conservative
assumptions for estimating undeveloped CBM reserves, pending additional
performance-related data. The Company's depletion rate will next be re-evaluated
in conjunction with preparation of reserve reports at the end of the year.
Depreciation of other fixed assets, which includes service equipment,
gathering, transportation and compression equipment, office furniture and
equipment, and buildings, was $462,000 and $295,000 for the quarters ended
September 30, 2001 and 2000, respectively. The increase is related to asset
additions, primarily for service and gas transportation related equipment.
Lease operating expenses ("LOE") totaled $869,000 for the quarter ended
September 30, 2001 compared to $655,000 for the quarter ended September 30,
2000. The increase was primarily attributable to new production from CBM wells.
Ad valorem and production taxes were $635,000 and $950,000 for the same periods.
Production taxes decreased with revenues, as the result of lower product prices.
Total lifting costs (LOE plus ad valorem and production taxes) were 16% of oil
and gas revenues and $0.49 per Mcfe for the 2001 quarter, compared to 14% and
$0.57 per Mcfe for the 2000 quarter.
Oilfield services include the operations of Action Oilfield Services,
Inc. (Colorado), Action Energy Services (Wyoming), and Arete Gathering Company,
wholly-owned subsidiaries. Related revenues include well servicing fees from
completion and swab rigs, CBM drilling rigs, trucking, water hauling, equipment
rentals, and gas gathering, compression and transportation fees. Revenues were
$2,223,000 for the quarter ended September 30, 2001 compared to $1,526,000 for
the comparable quarter of 2000, an increase of $697,000, or 46%. Costs of
oilfield services were $1,373,000 for the quarter ended September 30, 2001
compared to $1,215,000 for the same period of 2000, an increase of $158,000 or
13%. Higher revenues were attributable to rate increases, more equipment placed
in service, and an increased portion of services that were provided to third
parties. For the quarter ended September 30, 2001, 34% of the fees billed by the
service companies were for Company-owned wells, compared to 40% for the quarter
ended September 30, 2000. Intercompany billings are eliminated in consolidation.
General and administrative expenses ("G&A"), net of third party
reimbursements and amounts capitalized, were $815,000 for the quarter ended
September 30, 2001 compared to $787,000 for the quarter ended September 30,
2000, an increase of $28,000 or 4%. Third party reimbursement of management and
operator fees were $79,000 and $77,000 during the quarters ended September 30,
2001 and 2000, respectively. The Company's G&A costs have otherwise increased
due to expansion of the Company's activities and operations, offset by increased
amounts capitalized.
The provision for income taxes was $3,175,000 for the quarter ended
September 30, 2001 compared to $2,350,000 for the quarter ended September 30,
2000, an increase of $825,000 or 35%. The Company's effective tax rate increased
to 31.0% from 29.7%. The Company's effective tax rates are less than statutory
rates due to permanent differences between financial and taxable income, which
consist primarily of statutory depletion deductions and Section 29 tax credits.
The Company's effective tax rate
17
increased primarily because income before income taxes increased $2,323,000 or
29% for 2001, while the permanent differences did not increase proportionately.
Nine Months Ended September 30, 2001 and 2000
For the nine months ended September 30, 2001, the Company earned net
income of $21,414,000, or $1.62 per diluted share, on revenues of $49,833,000,
compared to net income of $14,564,000, or $1.10 per diluted share, on revenues
of $36,022,000 for the nine months ended September 30, 2000. Expenses were
$19,395,000 for the 2001 nine-month period compared to $15,538,000 for the 2000
nine-month period. Revenues increased $13,811,000, or 38%, expenses increased
$3,857,000, or 25%, and net income increased $6,850,000, or 47%.
Revenues for the 2001 period included $8,377,000 of gains related to
oil and gas derivatives (see Note 4). This total was comprised of hedging gains,
which are discussed below, plus realized and unrealized gains on derivative
instruments that did not qualify for hedge accounting, in the amounts of
$577,000 and $4,975,000, respectively. No comparable amounts were reported in
2000.
Excluding gains from derivative instruments, oil and gas sales for the
nine months ended September 30, 2001 were $34,604,000 compared to $30,390,000
for the nine months ended September 30, 2000, an increase of $4,214,000 or 14%.
The increase was due to the combined effects of a 12% rise in average price
realizations and a 2% growth in production volumes.
The following information is provided excluding effects of derivatives.
The average price received by the Company for its natural gas production was
$3.78 per Mcf for the nine months ended September 30, 2001, compared to $3.18
per Mcf for the nine months ended September 30, 2000, an increase of $0.60 per
Mcf or 19%. The average price received for oil for the first nine months of 2001
was $27.43 per barrel compared to $28.51 per barrel for the same period of 2000,
a decrease of $1.08 per barrel or 4%. On an Mcf equivalent basis, the average
price received for the Company's production was $3.96 per Mcfe for the nine
months ended September 30, 2001 compared to $3.55 per Mcfe for the nine months
ended September 30, 2000, representing an overall 12% increase in average
prices. The Company's oil and gas revenues were 74% derived from the sales of
natural gas during the first nine months of 2001 compared to 69% during the
first nine months of 2000.
Hedging gains of $2,825,000 are included in oil and gas revenues for
the first nine months of 2001. Such gains had the effect of increasing average
price realizations by $0.41 per Mcf of natural gas, $0.26 per barrel of oil, and
$0.32 per Mcfe. Cumulative gains realized on derivatives relating to production
months in the first three quarters of 2001 aggregated $4,278,000, including
gains from derivatives that qualify for hedge accounting and gains from
non-qualifying derivatives, and including both gains reported for the current
nine-month period and amounts recorded as the cumulative effect of a change in
accounting principle at the beginning of the year. The Company did not hedge any
of its production during the nine months ended September 30, 2000.
The Company's net natural gas production was 6,775,000 Mcf and
6,574,000 Mcf for the first nine months of 2001 and 2000, respectively, an
increase of 201,000 Mcf, or 3%. Net oil production was 328,000 barrels and
333,000 barrels for the same nine-month periods, representing a decrease of
5,000 barrels or 2%. On an equivalent unit basis, the Company's production
increased approximately 2%, to 8,745,000 Mcfe during the first nine months of
2001, from 8,571,000 Mcfe in the same period last year. Total production for the
nine months ended September 30, 2001 was 78% natural gas and 22% oil, compared
to 77% natural gas and 23% oil for the same period of 2000. Net production from
the Company's CBM operations, which totaled 809,000 Mcf in the current year,
compared to none last year, more than offset net decreases from the Company's
other producing properties attributable to natural declines and limited new
activity.
18
The Company's depletion expense for oil and gas properties was
$6,399,000, or $0.73 per Mcfe, during the first nine months of 2001, compared to
$4,386,000, or $0.51 per Mcfe produced during the first nine months of 2000.
Depreciation of other fixed assets was $1,040,000 and $846,000 for the nine
months ended September 30, 2001 and 2000, respectively, an increase of $194,000,
or 23%. The increases were attributable to the same factors as noted above in
the discussion of third quarter results.
LOE was $2,319,000 for the nine months ended September 30, 2001
compared to $1,910,000 for the nine months ended September 30, 2000, primarily
reflecting incremental costs associated with new CBM production. Ad valorem and
production taxes were $2,928,000 and $2,434,000 for the same periods, reflecting
increased revenue. Total lifting costs were 14% of oil and gas revenues and
$0.60 per Mcfe for the first nine months of 2001, compared to 14% and $0.51 per
Mcfe for the same 2000 period.
Reflecting higher rates and increased utilization, oilfield service
revenues grew by 27%, to $6,005,000 in the nine months ended September 30, 2001,
from $4,710,000 during the comparable nine-month period of 2000. Costs of
oilfield services were $3,886,000 for the nine months ended September 30, 2001,
compared to $3,833,000 for the same period of 2000, an increase of $53,000 or
1%. For the nine months ended September 30, 2001, 37% of the fees billed by the
service companies were for Company-owned wells, compared to 35% for the nine
months ended September 30, 2000.
G&A was $2,823,000 for the nine months ended September 30, 2001
compared to $2,129,000 for the nine months ended September 30, 2000, an increase
of $694,000 or 33%. Third-party reimbursements were $292,000 and $318,000 during
the nine months ended September 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. In addition, the Company has increased its staff in the
current year to manage expanded operations.
The provision for income taxes, including the tax effect of a change in
accounting principle, was $9,900,000 for the nine months ended September 30,
2001 compared to $5,920,000 for the same nine-month period of 2000. Income
before income taxes increased $9,954,000 for the 2001 nine-month period and the
effective tax rate increased to 31.7% from 28.9%. The Company's provision for
income taxes was 93% deferred in 2001 compared to 66% in 2000.
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, options 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, and the ineffective portion of
its derivatives instruments.
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 transactions are generally cash flow hedges determined to
be qualifying or non-qualifying for hedge accounting treatment in accordance
with the provisions of SFAS 133. Note 4 to the unaudited consolidated financial
statements provides further information with respect to derivatives and related
accounting policies.
19
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 nine months of 2001, the Company sold 328,000 barrels
of oil. A hypothetical decrease of $2.74 per barrel (10% of average prices for
the period exclusive of hedging transactions) would have decreased the Company's
production revenues by $899,000 for the period. The Company sold 6,775,000 Mcf
of natural gas during the same period. A hypothetical decrease of $ 0.38 per Mcf
(10% of average prices for the period exclusive of hedging transactions) would
have decreased the Company's production revenues by $2,574,000 for the period.
The Company closed certain derivative instruments between September
30, 2001 and November 6, 2001, for net realized gains totaling $1,209,000. As of
November 6, 2001, open oil and gas derivative instruments showed net unrealized
gains of $2,430,000, as follows:
Market Total Volumes Contract Unrealized
Time Period Index (MMBtu or Bbls) Price Gains
----------- ------ --------------- -------- ------------
Natural gas
December 2001 NYMEX 500,000 3.8380 $ 458,000
January - March, 2002 NYMEX 1,900,000 3.6201 1,007,000
April - June, 2002 NYMEX 2,000,000 3.2716 457,000
July - September, 2002 NYMEX 1,800,000 3.3342 380,000
October 2002 NYMEX 600,000 3.3615 123,000
Crude Oil Calls
December 2001 NYMEX 5,000 29.00 5,000
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Total Unrealized Gains $ 2,430,000
============
20
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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 "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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PART II. FINANCIAL INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
None.
(b) Reports on Form 8-K
The Company filed a Report on Form 8-K dated August 14, 2001,
reporting its earnings for the quarter and six months ended June 30, 2001 and
providing an operations update.
21
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
PRIMA ENERGY CORPORATION
(Registrant)
Date: November 13, 2001 By /s/ Richard H. Lewis
-------------------- -------------------------------------
Richard H. Lewis,
President and Chief Executive Officer
Date: November 13, 2001 By /s/ Neil L. Stenbuck
-------------------- -------------------------------------
Neil L. Stenbuck,
Executive Vice President and Chief
Financial Officer
22