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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
----------------------------
(Mark One)
/X/ Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934
For the quarterly period ended September 30, 2003 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 0-13305
--------------------------
PARALLEL PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
DELAWARE 75-1971716
(State of other jurisdiction of (I.R.S. Employer Identification
incorporation or organization) Number)
1004 N. Big Spring, Suite 400,
Midland, Texas 79701
(Address of principal executive offices) (Zip Code)
(432) 684-3727
(Registrant's telephone number, including area code)
Not Applicable
(Former name, former address and former fiscal year,
if changed since 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
Indicate by check mark whether the registrant is an accelerated filer
(as defined in Rule 12b-2 of the Exchange Act).
Yes No `X'
At October 23, 2003, 21,216,863 shares of the Registrant's Common
Stock, $0.01 par value, were outstanding.
INDEX
PART I. - FINANCIAL INFORMATION
Page
No.
----
ITEM 1. FINANCIAL STATEMENTS
Reference is made to the succeeding pages for the following
consolidated financial statements:
- Consolidated Balance Sheets as of December 31, 2002 and
September 30, 2003 (unaudited) 2
- Unaudited Consolidated Statements of Operations for the
three months and nine months ended September 30, 2002 and 2003 3
- Unaudited Consolidated Statements of Cash Flows for the
nine months ended September 30, 2002 and 2003 4
- Unaudited Consolidated Statements of Comprehensive Income for
the three months and nine months ended September 30,
2002 and 2003 5
- Notes to Consolidated Financial Statements 6
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS 14
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK 25
ITEM 4. CONTROLS AND PROCEDURES 26
PART II. - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS 27
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K 27
SIGNATURES
-1-
PARALLEL PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
(audited) (unaudited)
December 31, September 30,
2002 2003
------------------ ------------------
ASSETS
Current assets:
Cash and cash equivalents $ 11,811,704 $ 5,255,221
Accounts receivable:
Oil and gas 3,071,315 4,254,737
Others, net of allowance for doubtful account of $12,681 in 2002 and $9,239 in 2003 236,443 590,718
Affiliate 2,084 4,818
------------ ------------
3,309,842 4,850,273
Income tax receivable 832,590 832,590
Other assets 78,675 98,077
Fair value of derivative instruments 21,884 84
------------ ------------
Total current assets 16,054,695 11,036,245
------------ ------------
Property and equipment, at cost:
Oil and gas properties, full cost method (Note 6) 146,679,503 158,249,928
Other 1,083,282 1,393,447
------------ ------------
147,762,785 159,643,375
Less accumulated depreciation and depletion (62,074,559) (67,924,397)
------------ ------------
Net property and equipment (Note 10) 85,688,226 91,718,978
------------ ------------
Other assets, net of accumulated amortization of $78,520 in 2002 and $134,967 in 2003 608,410 663,586
------------ ------------
$102,351,331 $103,418,809
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities $ 3,033,650 $ 3,300,177
Current maturities of long-term debt (Note 3) 4,145,833 -
Current maturity of derivative obligations 335,829 1,348,469
------------ ------------
7,515,312 4,648,646
------------ ------------
Long-term debt, excluding current maturities (Note 3) 45,604,167 39,750,000
Long-term asset retirement obligation (Note 10) - 1,827,066
Long-term maturity of derivative obligations (Note 7) 103,745 1,730,325
Deferred tax liability 3,627,963 5,531,300
Stockholders' equity:
Series A preferred stock -- par value $.10 per share (aggregate liquidation preference of $26)
authorized 50,000 shares - -
Preferred stock -- 6% convertible preferred stock -- par value $.10 per share
(aggregate liquidation preference of $10) authorized 10,000,000 shares, issued
and outstanding 974,500 in 2002 and 2003 97,450 97,450
Common stock -- par value $.01 per share, authorized 60,000,000
shares, issued and outstanding 21,143,406 in 2002 and 21,174,006 in 2003 211,434 211,740
Additional paid-in capital 34,567,866 34,240,897
Retained earnings 10,623,394 17,241,434
Other comprehensive loss, net of tax (Note 7) - (1,860,049)
------------ ------------
Total stockholders' equity 45,500,144 49,931,472
Commitments and contingencies (Note 12)
------------ ------------
$102,351,331 $103,418,809
============ ============
*The balance sheet as of December 31, 2002 has been derived from Parallel's
audited financial statements. The accompanying notes are an integral part of
these financials.
-2-
PARALLEL PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------- -------------------------
2002 2003 2002 2003
----------- ----------- ------------ ------------
Oil and gas revenues $ 2,709,985 $ 8,731,573 $ 7,489,983 $ 25,756,339
----------- ----------- ------------ ------------
Cost and expenses:
Lease operating expense (Note 10) 648,001 2,078,640 1,918,991 5,719,496
General and administrative, includes $1,471,000
for incentive awards in 2002 347,827 1,061,307 2,672,277 2,831,229
Depreciation, depletion and amortization 1,323,107 2,189,183 4,010,903 6,244,068
----------- ----------- ------------ ------------
Total costs and expenses 2,318,935 5,329,130 8,602,171 14,794,793
----------- ----------- ------------ ------------
Operating income (loss) 391,050 3,402,443 (1,112,188) 10,961,546
----------- ----------- ------------ ------------
Other income (expense), net:
Equity in income (loss) of First Permian, L.P., includes a
$31,082,041 gain on sale of substantially all net assets (99,928) - 30,665,820 -
Derivative instruments gain (loss) (Note 7) (62,589) 85,401 (457,421) 157,235
Interest and other income 33,538 33,630 70,979 79,622
Dividend income 143,494 - 306,872 -
Interest expense (178,417) (539,585) (489,681) (1,547,940)
Other expense (27,360) (31,755) (307,008) (77,765)
Loss on sale of marketable securities (928,540) - (928,540) -
----------- ----------- ------------ ------------
Total other income (expense), net (1,119,802) (452,309) 28,861,021 (1,388,848)
----------- ----------- ------------ ------------
Income (loss) before income taxes (728,752) 2,950,134 27,748,833 9,572,698
Income tax benefit (expense), net 330,836 (1,254,938) (9,253,997) (2,893,202)
----------- ----------- ------------ ------------
Net income (loss) before cumulative effect of change in accounting principle (397,916) 1,695,196 18,494,836 6,679,496
Cumulative effect on prior years of a change in accounting principle, less
applicable income taxes of $31,659 (Note 10) - - - (61,456)
----------- ----------- ------------ ------------
Net income (loss) (397,916) 1,695,196 18,494,836 6,618,040
Cumulative preferred stock dividend (146,175) (146,175) (438,525) (438,525)
----------- ----------- ------------ ------------
Net income (loss) available to common stockholders $ (544,091) $ 1,549,021 $ 18,056,311 $ 6,179,515
=========== =========== ============ ============
Net income (loss) per common share:
Basic - before cumulative effect of a change in accounting principle $ (0.03) $ 0.07 $ 0.87 $ 0.29
Cumulative effect of a change in accounting principle, net of tax - - - -
----------- ----------- ------------ ------------
Basic - after cumulative effect of a change in accounting principle $ (0.03) $ 0.07 $ 0.87 $ 0.29
=========== =========== ============ ============
Diluted - before cumulative effect of a change in accounting principle $ (0.03) $ 0.07 $ 0.79 $ 0.27
Cumulative effect of a change in accounting principle, net of tax - - - -
----------- ----------- ------------ ------------
Diluted - after cumulative effect of a change in accounting principle $ (0.03) $ 0.07 $ 0.79 $ 0.27
=========== =========== ============ ============
Weighted average common share outstanding:
Basic 20,663,861 21,158,619 20,663,861 21,148,933
=========== =========== ============ ============
Diluted 20,663,861 24,162,124 23,536,079 24,082,445
=========== =========== ============ ============
The accompanying notes are an integral part of these financials.
-3-
PARALLEL PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended September 30,
-------------------------------------
2002 2003
----------------- ------------------
Cash flows from operating activities:
Net income $ 18,494,836 $ 6,618,040
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and depletion 4,010,903 6,244,068
Accretion expense - 103,210
Equity in income of First Permian, L.P. net of
cash distributions of $5,501,703 (25,164,117) -
Loss on sale of marketable securities 928,540 -
Change in fair value of derivative instruments 457,421 (157,235)
Stock option expense - 56,384
Deferred income taxes 9,253,997 2,893,202
Cumulative effect on prior years of a change in accounting principle, net of tax - 61,456
Changes in assets and liabilities:
Other, net (44,233) (55,176)
Increase in accounts receivables (135,109) (1,540,431)
Increase in prepaid expenses and other assets (631,391) (19,402)
(Decrease) Increase in accounts payable and accrued liabilities (1,427,123) 120,352
Accrued bonus payable 130,043 -
Purchase of derivative instruments (530,605) -
------------ ------------
Net cash provided by operating activities 5,343,162 14,324,468
------------ ------------
Cash flows from investing activities:
Additions to property and equipment (10,558,989) (10,664,479)
Proceeds from disposition of Energen Stock 12,563,220 -
Proceeds from disposition of property and equipment 692,450 20,400
------------ ------------
Net cash (used) provided in investing activities 2,696,681 (10,644,079)
------------ ------------
Cash flows from financing activities:
Borrowings from bank line of credit 2,865,589 3,173,625
Payments on bank line of credit (11,905,589) (13,173,625)
Proceeds from exercise of stock options - 55,478
Payment of preferred stock dividend (292,350) (292,350)
------------ ------------
Net cash used in financing activities (9,332,350) (10,236,872)
------------ ------------
Net decrease in cash and cash equivalents (1,292,507) (6,556,483)
Beginning cash and cash equivalents 3,351,044 11,811,704
------------ ------------
Ending cash and cash equivalents $ 2,058,537 $ 5,255,221
============ ============
Non-cash financing and investing activities:
Non-cash proceeds from sale of investment $(25,580,339) $ -
Unrealized gain on investment in securities $ 922,085 $ -
Accrued asset retirement obligation related to oil and gas properties $ - $ 1,236,511
Accrued preferred stock dividend $ 170,537 $ 170,537
The accompany notes are an integral part of these financials.
-4-
PARALLEL PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(unaudited)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------------- ----------------------------
2002 2003 2002 2003
-------------- -------------- ------------ ------------
Net income $ (397,916) $ 1,695,196 $ 18,494,836 $ 6,618,040
------------- ----------- ------------ -----------
Other comprehensive income (loss):
Change in derivative fair value - 783,632 - (671,529)
Reclassification adjustments - contract (gain)
loss settlements(1) - (504,630) - (2,146,726)
------------- ----------- ------------ -----------
- 279,002 - (2,818,255)
Income tax (expense) benefit - (94,861) - 958,206
------------- ----------- ------------ -----------
Total other comprehensive income (loss) - 184,141 - (1,860,049)
------------- ----------- ------------ -----------
Total comprehensive income $ (397,916) $ 1,879,337 $ 18,494,836 $ 4,757,991
============= =========== ============ ===========
______________________
(1) For contract gain settlements, the reduction to comprehensive income
offsets contract proceeds recorded as oil and gas revenue or interest
expense. For contract loss settlements, the increase in comprehensive
income offsets contract payments recorded as reductions to oil and gas
revenue or interest expense.
The accompanying notes are an integral part of these financials.
-5-
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
The financial information included herein, except the balance sheet as
of December 31, 2002, is unaudited. However, such information includes all
adjustments (consisting solely of normal recurring adjustments), which are, in
the opinion of management, necessary for a fair statement of the results of
operations for the interim periods. The results of operations for the interim
period are not necessarily indicative of the results to be expected for an
entire year.
Certain information and footnote disclosures normally included in
financial statements prepared in accordance with generally accepted accounting
principles have been condensed or omitted in this Form 10-Q pursuant to certain
rules and regulations of the Securities and Exchange Commission. These financial
statements should be read in conjunction with the financial statements and notes
included in our 2002 Form 10-K.
NOTE 2. STOCKHOLDERS' EQUITY
Options
In September 2003, Parallel adopted Statement of Financial Accounting
Standards No. 123, Accounting for Stock-Based Compensation ("SFAS No. 123") and
related interpretations in accounting for its employee and director stock
options and will apply the fair value based method of accounting to such
options. Under Statement of Financial Accounting Standards No. 148, Accounting
for Stock-Based Compensation - Transition and Disclosure, an amendment to SFAS
No. 123, certain transitional alternatives are available for a voluntary change
to the fair value based method of accounting for stock-based employee
compensation if adopted in a fiscal year beginning before December 16, 2003.
Parallel used the prospective method which applies prospectively the fair value
recognition method to all employee and director awards granted, modified or
settled after the beginning of the fiscal year in which the fair value based
method of accounting for stock-based compensation is adopted.
For the three and nine months ended September 30, 2003, Parallel
recognized compensation expense of $56,384 associated with its stock option
grants. The total number of options granted during the nine months ended
September 30, 2003 was 180,000.
At September 30, 2003, Parallel accounted for stock-based compensation
utilizing the intrinsic value method prescribed by Accounting Principles Board
Opinion No. 25 "Accounting for Stock Issued to Employees" ("APB 25") and related
interpretations. No stock-based employee compensation cost is reflected in the
net income (loss) for the three and nine months ended September 30, 2002, as all
options or warrants granted had an exercise price equal to or greater than the
market value of the underlying common stock on the date of grant. As previously
stated, in September 2003, Parallel adopted the fair value recognition
provisions of SFAS No. 123 prospectively for all employee awards granted,
modified or settled after January 1, 2003. Therefore, the cost related to
stock-based compensation included in the determination of income for the three
and nine month periods ended September 30, 2003 and 2002 is less than that which
would have been recognized if the fair value method had been applied to all
awards since the original effective date of SFAS No. 123. Awards vest over
periods ranging from one to three years. The following table illustrates the
effect on net income and earnings per share as if the fair value based method
had been applied to all outstanding and unvested awards in each period. The fair
value of each grant is estimated on the date of grant using the Black-Scholes
option-pricing model.
-6-
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------- ----------------------------
2002 2003 2002 2003
----------- ----------- ------------ -----------
Net income (loss), as reported $ (397,916) $ 1,695,196 $ 18,494,836 $ 6,618,040
Add: Stock-based employee compensation expense
included in net income (loss), net of tax - 56,384 - 56,384
Deduct: Stock-based employee compensation expense
determined under fair value based method (SFAS 123),
net of tax (321,000) (89,946) (1,037,267) (199,358)
---------- ----------- ------------ -----------
Net income (loss), pro forma $ (718,916) $ 1,661,634 $ 17,457,569 $ 6,475,066
========== =========== ============ ===========
Basic:
Net income (loss) per common share, as reported $ (0.03) $ 0.07 $ 0.87 $ 0.29
========== =========== ============ ===========
Net income (loss) per common share, pro forma $ (0.03) $ 0.07 $ 0.84 $ 0.29
========== =========== ============ ===========
Diluted:
Net income (loss) per common share, as reported $ (0.03) $ 0.07 $ 0.79 $ 0.27
========== =========== ============ ===========
Net income (loss) per common share, pro forma $ (0.03) $ 0.07 $ 0.74 $ 0.27
========== =========== ============ ===========
NOTE 3. LONG TERM DEBT
Long-term debt consists of the following at September 30, 2003:
Revolving Facility note payable to banks, at the agent bank's
base lending rate (with a minimum rate of 4.5%
at September 30, 2003)
$39,750,000
Less: current maturities -
-----------
$39,750,000
===========
Revolving Credit Facility. Under our revolving credit facility, as
amended, we may borrow the lesser of $100,000,000 or the "borrowing base" then
in effect. The borrowing base at September 30, 2003 was $50,000,000, which is
secured by substantially all of our oil and gas reserves. The total outstanding
principal amount of our bank indebtedness at September 30, 2003 was $39,750,000,
excluding $250,000 reserved for our letters of credit, leaving an availability
of $10,000,000 on our borrowing base. The borrowing base is subject to
redetermination semi-annually, on or about April 1 and October 1 of each year.
The banks may also require a redetermination of the borrowing base at any other
time, and from time to time, at the discretion of the banks. All indebtedness
matures December 20, 2006.
The unpaid principal balance of our outstanding borrowings bears
interest at our election at a rate equal to (i) the bank's base lending rate, or
(ii) the libor rate plus a libor margin of
2.75% per annum whenever the borrowing base usage is equal to or
greater than 75%;
2.50% per annum whenever the borrowing base usage is equal to
or greater than 50% but less than 75%;
2.25% per annum whenever the borrowing base usage is less
than 50%.
However, the interest rate may never be less than 4.50%. Interest on
borrowings bearing interest at the libor rate is due and payable on the day on
which the related libor interest period ends or if the interest period is longer
than three months, at three month intervals. Interest on borrowings bearing
interest at the base rate is due and payable on the last day of each month.
-7-
We are required to pay a commitment fee of one-quarter of one percent
times the daily average of the unadvanced amount of the commitment. The
commitment fee is payable quarterly in arrears on the last day of each calendar
quarter.
In addition to customary affirmative covenants, the loan agreement
contains various restrictive covenants and compliance requirements, including:
. maintaining certain financial requirements;
. limitation on additional indebtedness;
. prohibiting the payment of dividends on our common stock;
. limitations on the disposition of assets;
. prohibiting liens (other than in favor of the bank) to exist on
any of our properties;
. limitations on investments, mergers, forming subsidiaries,
affiliate transactions, changes in accounting methods, rental and
lease payments and derivative transactions
. limitations on the purchase, redemption or retirement of stock;
and
. limitations on hedging activities.
NOTE 4. PREFERRED STOCK
We have outstanding 974,500 shares of 6% Convertible Preferred Stock,
$0.10 par value per share. Cumulative annual dividends of $0.60 per share are
payable semi-annually on June 15 and December 15 of each year. Each share of
Convertible Preferred Stock may be converted, at the option of the holder, into
2.8571 shares of common stock at an initial conversion price of $3.50 per share,
subject to adjustment in certain events. The Convertible Preferred Stock has a
liquidation preference of $10 per share and has no voting rights, except as
required by law. We may redeem the preferred stock, in whole or part, for $10
per share plus accrued and unpaid dividends.
NOTE 5. INCOME TAX LIABILITY
For the nine months ended September 30, 2003, we recorded income tax
expense of $2,893,202 resulting in a net deferred tax liability of $5,331,300.
Our income tax expense was largely due to generating taxable income in the
current period. Our effective tax rate for the nine months ended September 30,
2003 was 30%, which is less than the expected rate of 37% due to the recognition
of state income tax, net operating loss carryover and certain federal income tax
credits not previously recognized.
NOTE 6. FULL COST CEILING TEST
We use the full cost method to account for our oil and gas producing
activities. Under the full cost method of accounting, the net book value of oil
and gas properties, less related deferred income taxes, may not exceed a
calculated "ceiling". The ceiling limitation is the discounted estimated
after-tax future net cash flows from proved oil and gas properties. In
calculating future net cash flows, current prices and costs are generally held
constant indefinitely as adjusted for qualifying cash flow hedges under
Statement 133. The net book value of oil and gas properties, less related
deferred income taxes over the ceiling, is compared to the ceiling on a
quarterly and annual basis. Any excess of the net book value, less related
deferred income taxes, is generally written off as an expense. Under rules and
regulations of the SEC, the excess above the ceiling is not written off if,
subsequent to the end of the quarter or year but prior to the release of the
financial results, prices have increased sufficiently that such excess above the
ceiling would not have existed if the increased prices were used in the
calculations.
At September 30, 2003 the net book value of our oil and gas properties,
less related deferred income taxes, was below the calculated ceiling. As a
result, we were not required to record a reduction of our oil and gas properties
under the full cost method of accounting at that time.
Under the full cost method of accounting, all costs incurred in the
acquisition, exploration and development of oil and natural gas properties,
including a portion of our overhead, are capitalized. In the nine month period
ended September 30, 2003 overhead costs capitalized were $678,975.
-8-
NOTE 7. DERIVATIVE INSTRUMENTS
General
For the year ended December 31, 2002, we applied mark-to-market
accounting for our hedge contracts. As of January 1, 2003 we adopted hedge
accounting for the costless collars, oil and gas swaps, and interest rate swaps
described below. We continued market-to-market accounting for our put positions
described below. The purpose of our hedges is to provide a measure of stability
in our oil and gas prices and interest rate payments and to manage exposure to
commodity price and interest rate risk. Our objective is to lock in a range of
oil and gas prices and a fixed interest rate for certain notional amounts.
During the terms of a hedge, the quarterly change in the fair value of
the derivatives is recorded in stockholders' equity as other comprehensive
income (loss) and then transferred to earnings when the production is sold.
Ineffective portions of hedges (changes in realized prices that do not match the
changes in the hedge price) are recognized in earnings as they occur. While the
hedge contract is open, the ineffective gain or loss may increase or decrease
until settlement of the contract. For the nine months ended September 30, 2003,
there was no ineffective portion of our natural gas and interest rate hedges.
For the nine months ended September 30, 2003, we recorded a cumulative charge of
$114,732 to other income (expense) for the ineffective portion of the crude oil
hedges.
For the nine months ended September 30, 2003, $555,601 was transferred
from comprehensive income (loss) and charged to earnings along with the
expiration of the associated hedge contracts. During the twelve month period
ending September 30, 2004, we expect approximately $771,197 to be transferred
out of other comprehensive income (loss) and charged to earnings.
We are exposed to credit risk in the event of nonperformance by BNP
Paribas in its derivative instruments. However, we periodically assess its
credit worthiness to mitigate this credit risk.
Interest Rate Sensitivity
In January, 2003, we entered into a 45-month libor fixed interest rate
swap contract with BNP Paribas. We will receive a fixed interest rate, as noted
in the table below, for the 45-month period beginning March 31, 2003 through
December 20, 2006.
Under our revolving credit facility, we may elect an interest rate
based upon the agent lender's base lending rate, or the libor rate, plus a
margin ranging from 2.25% to 2.75% per annum, depending on our borrowing base
usage. The interest rate we are required to pay, including the applicable
margin, may never be less than 4.50%.
A recap for the period of time, notional amounts, libor fixed interest
rates, expected margin rates and expected fixed interest rates for the contract
are as follows:
Libor Expected Expected
Notional Fixed Margin Fixed
Period of Time Amounts (1) Interest Rates (2) Rates (3) Interest Rates (4)
- ----------------------------------------------- ----------------- ------------------- ----------- ------------------
March 31, 2003 thru December 31, 2003 $ 35,000,000 1.675% 2.750% 4.425%
December 31, 2003 thru December 31, 2004 $ 30,000,000 2.660% 2.500% 5.160%
December 31, 2004 thru December 31, 2005 $ 20,000,000 4.050% 2.250% 6.300%
December 31, 2005 thru December 20, 2006 $ 10,000,000 4.050% 2.250% 6.300%
- -------------------------------
(1) Based on the anticipated principal reductions under our credit facility.
(2) Our swap contract with BNP Paribas.
(3) Based on the anticipated borrowing base usage under our credit facility.
(4)Total of the libor fixed interest rate plus the expected margin
rate under our credit facility. Our credit agreement requires
the interest rate to not be below 4.50%.
-9-
Commodity Price Sensitivity
Puts. On May 24, 2002 we purchased put floors on volumes of 100,000 Mcf
per month for a total of 700,000 Mcf during the seven month period from April,
2003 through October, 2003 at a floor price of $3.00 per Mcf for a total
consideration of approximately $139,500. These derivatives are not held for
trading purposes.
A decrease in fair value of the put floors of $21,800 was
recognized for the nine months ended September 30, 2003 in the Consolidated
Statements of Operations.
The following table illustrates our put options.
Fair Value
Floor at
Period Commodity Mcf Volume Price Cost of Floor September 30, 2003
- ------------------------------- ------------ ------------- ------- --------------- ---------------------
April 2003 thru October 2003 natural gas 700,000 $ 3.00 $ 139,500 $ 84
Costless Collars. Collars are created by purchasing puts to establish a
floor price and then selling a call which establishes a maximum amount the
producer will receive for the oil or gas hedged. Calls are sold to offset or
reduce the premium paid for buying the put. In 2003, we entered into several
costless, seven-month Houston ship channel gas collars. A majority of our
natural gas production is sold based on Houston ship channel prices. A recap for
the period of time, number of MMBtu's and average gas prices is as follows:
Houston Ship Channel
Gas Prices
---------------------------
MMBtu of
Period of Time Natural Gas Floor Cap
- ------------------------------------------- -------------- ------------ -------------
April 1, 2003 thru October 31, 2003 642,000 $ 4.25 $ 5.30
November 1, 2003 thru March 31, 2004 453,000 $ 5.43 $ 6.58
Subsequent to September 30, 2003 we added additional Houston Ship
Channel costless collars for April 1, 2004 through October 31, 2004 on 214,000
MMbtu of gas with a floor of $4.40 and a cap of $5.50.
Swaps. Generally, swaps are an agreement to buy or sell a specified
commodity for delivery in the future, but at an agreed fixed price. Swap
transactions convert a floating price into a fixed price. For any particular
swap transaction, the counterparty is required to make a payment to the hedge
party if the reference price for any settlement period is less than the swap
price for such hedge, and the hedge party is required to make a payment to the
counterparty if the reference price for any settlement period is greater than
the swap price for such hedge.
-10-
In 2003, we entered into additional oil and gas swap contracts with BNP
Paribas. A recap for the period of time, number of MMBtu's, number of barrels,
and swap prices are as follows:
Houston Ship
Barrels of Nymex Oil MMBtu of Channel
Period of Time Oil Swap Prices Natural Gas Gas Swap Price
- -------------------------------------------- ------------ --------------- ------------- -----------------
April 1, 2003 thru October 31, 2003 - $ - 214,000 $ 4.87
April 1, 2003 thru October 31, 2003 - $ - 428,000 $ 4.83
April 1,2003 thru December 31, 2003 293,400 $ 24.94 - $ -
January 1,2004 thru December 31, 2004 347,600 $ 23.47 - $ -
January 1,2005 thru December 31, 2005 292,000 $ 22.77 - $ -
January 1, 2006 thru December 20, 2006 265,500 $ 23.04 - $ -
NOTE 8. INVESTMENT IN FIRST PERMIAN, L.P.
For the nine months ended September 30, 2002, First Permian, L.P. had
net income of $97,050,344, which includes a gain of $107,662,000 on the sale of
its entire oil and gas properties. Our 30.675% share of the net income and
distributions for the nine months ended September 30, 2002, was $30,665,820.
Using the equity method of accounting, our investment is increased or decreased
by our proportionate share of First Permian's net income or loss.
On March 7, 2002, First Permian entered into an Agreement of Sale and
Purchase with Energen Resources Corporation, a wholly owned subsidiary of
Energen Corporation (Energen), to sell all of First Permian's oil and gas
properties for $120 million in cash and 3,043,479 shares in Energen stock
approximating $70 million in value. Energen is a publicly traded company listed
on the NYSE. The transaction closed on April 8, 2002. As a 30.675% interest
owner in First Permian, Parallel received its prorata share of the net proceeds,
$5.5 million in cash and 933,589 shares of Energen common stock.
-11-
NOTE 9. NET INCOME PER COMMON SHARE
Basic income per share is computed by dividing income available to
common stockholders by the weighted average number of common shares outstanding
for the period. Diluted income per share reflects the assumed conversion of all
potentially dilutive securities.
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------------- -------------------------------
2002 2003 2002 2003
--------------- --------------- --------------- ---------------
Basic EPS Computation:
Numerator-
Net income (loss) before cumulative effect of a change
in accounting principle $ (397,916) $ 1,695,196 $18,494,836 $ 6,679,496
Cumulative effect of a change in accounting principle,
net of tax - - - (61,456)
---------- ----------- ----------- -----------
(397,916) 1,695,196 18,494,836 6,618,040
Preferred stock dividend (146,175) (146,175) (438,525) (438,525)
---------- ----------- ----------- -----------
Net income (loss) available to common stockholders $ (544,091) $ 1,549,021 $18,056,311 $ 6,179,515
=========== =========== =========== ===========
Denominator-
Weighted average common shares outstanding 20,663,861 21,158,619 20,663,861 21,148,933
=========== =========== =========== ===========
Basic EPS:
Net income before cumulative effect of a change
in accounting principle $ (0.03) $ 0.07 $ 0.87 $ 0.29
Cumulative effect of a change in accounting principle,
net of tax - - - -
----------- ----------- ----------- -----------
Basic net earnings (loss) per share $ (0.03) $ 0.07 $ 0.87 $ 0.29
=========== =========== =========== ===========
Diluted EPS Computation:
Numerator-
Net income (loss) before cumulative effect of a change
in accounting principle $ (397,916) $ 1,695,196 $18,494,836 $ 6,679,496
Cumulative effect of a change in accounting principle,
net of tax - - - (61,456)
----------- ----------- ----------- -----------
(397,916) 1,695,196 18,494,836 6,618,040
Preferred stock dividend (146,175) - - -
----------- ----------- ----------- -----------
Net income (loss) available to common stockholders $ (544,091) $ 1,695,196 $18,494,836 $ 6,618,040
=========== =========== =========== ===========
Weighted average common shares outstanding 20,663,861 21,158,619 20,663,861 21,148,933
Employee stock options - 219,261 87,974 149,268
Preferred stock - 2,784,244 2,784,244 2,784,244
----------- ----------- ----------- -----------
Weighted average common shares for diluted earnings
per share assuming conversion 20,663,861 24,162,124 23,536,079 24,082,445
=========== =========== =========== ===========
Diluted EPS:
Net income (loss) before cumulative effect of a change
in accounting principle $ (0.03) $ 0.07 $ 0.79 $ 0.27
Cumulative effect of a change in accounting principle,
net of tax - - - -
----------- ----------- ----------- -----------
Diluted net earnings (loss) per share $ (0.03) $ 0.07 $ 0.79 $ 0.27
=========== =========== =========== ===========
-12-
Convertible preferred stock equivalent shares for the three-month
period ended September 30, 2002 that could potentially dilute basic earnings per
share in the future were included in the computation of diluted earnings per
share because to do so would have been anti-dilutive.
NOTE 10: ASSET RETIREMENT OBLIGATIONS
On January 1, 2003 we adopted Statement of Financial Accounting
Standards No. 143, Accounting for Asset Retirement Obligations "SFAS 143".
Adoption of SFAS 143 is required for all companies with fiscal years beginning
after June 15, 2002. The new standard requires us to recognize a liability for
the present value of all legal obligations associated with the retirement of
tangible long-lived assets and to capitalize an equal amount as a cost of the
asset, depreciating the additional cost through the unit-of-production method on
the life of the asset. Through September 30, 2003 we recorded additional oil and
gas property costs, net of disposals, of $1,236,511, a reduction in accumulated
depletion of $394,230, a non-current liability of $1,708,716 and an after tax
charge of $61,456 for the cumulative effect on prior years for depreciation and
accretion expense on the liability related to expected abandonment costs of our
oil and natural gas properties. The accretion expense for the current quarter is
$34,849 and recorded as a charge to lease operating expense with a corresponding
additional long-term liability.
The following table summarizes our asset retirement obligation
transactions during the three months and nine months ended September 30, 2003.
Three Months Ended Nine Months Ended
September 30, 2003 September 30, 2003
------------------------- -------------------------
Beginning asset retirement obligation $ 1,777,077 $ 1,693,330
Additions related to new properties 49,757 65,831
Deletions related to property disposals (34,617) (35,305)
Accretion expense 34,849 103,210
----------- -----------
Ending asset retirement obligation $ 1,827,066 $ 1,827,066
=========== ===========
Prior years pro forma were not shown since the change was not
significant.
NOTE 11: RECENTLY ANNOUNCED ACCOUNTING PRONOUNCEMENTS
SFAS No. 148, Accounting for Stock-Based Compensation-Transition and
Disclosure, which amends SFAS No. 123, Accounting for Stock-Based Compensation.
SFAS No. 148 provides alternative methods of transition for a voluntary change
to the fair value based method of accounting for stock-based employee
compensation. As of September 30, 2003, we adopted the Prospective method which
applies prospectively the fair value recognition method to all employee and
director awards granted, modified or settled after the beginning of the fiscal
year in which the fair value based method of accounting for stock-based
compensation is adopted. (See Note 2) SFAS 148 also amends the disclosure
requirements of SFAS No. 123 to require prominent disclosures in both annual and
interim financial statements about the method of accounting for stock-based
employee compensation and the effect of the method used on reported results. The
statement is required to be adopted for fiscal years ending after December 15,
2002.
On April 22, 2003, the FASB announced its decision to require all
companies to expense the value of employee stock options. Companies will be
required to measure the cost according to the fair value of the options. The new
guidelines have not been released to measure the cost according to the fair
value of the options. Although the new guidelines have not been released, it is
expected that they will be finalized and become effective in 2004. When final
rules are announced, we will assess the impact to our consolidated financial
statements.
-13-
FIN No. 45, Guarantor's Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of Others, FIN No. 45
requires that a liability be recorded in the guarantor's balance sheet upon
issuance of certain guarantees. Initial recognition and measurement of the
liability will be applied on a prospective basis to guarantees issued or
modified after December 31, 2002. FIN No. 45 also requires disclosures about
guarantees in financial statements for interim or annual periods ending after
December 15, 2002. We do not expect the adoption of FIN No. 45 to have a
material impact on our consolidated financial statements.
FIN No. 46, Consolidation of Variable Interest Entities, an
Interpretation of Accounting Research Bulletin No. 51. FIN No. 46 requires
certain variable interest entities to be consolidated by the primary beneficiary
of the entity if the equity investors in the entity do not have the
characteristics of a controlling financial interest or do not have sufficient
equity at risk for the entity to finance its activities without financial
support from other parties. We do not expect the adoption of FIN No. 46 to have
a material impact on our consolidated financial statements.
In April 2003, the Financial Accounting Standards Board issued SFAS No.
149, Amendment of Statement 133 on Derivative Instruments and Hedging
Activities, which clarifies financial accounting and reporting for derivative
instruments, including certain derivative instruments embedded in other
contracts and for hedging activities under SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities. The Statement is effective for
contracts entered into or modified after June 20, 2003. We do not anticipate
SFAS No. 149 will have a material effect on future earnings.
In May 2003, the FASB issued Statement No. 150 "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity." This
statement establishes standards for how an issuer classifies and measures
certain financial instruments with characteristics of both liabilities and
equity. This statement is effective for financial instruments entered into or
modified after May 31, 2003, and otherwise is effective at the beginning of the
first interim period beginning after June 15, 2003. The adoption of FAS 150 did
not have a material impact on our consolidated financial statements.
NOTE 12. COMMITMENTS AND CONTINGENCIES
At September 30, 2003, we were involved in two lawsuits incidental to
our business. We accrue for such items when a liability is both probable and the
amount can be reasonably estimated. We do not believe the ultimate outcome of
these lawsuits will have a material adverse effect on our financial position or
results of operations. We are not aware of any threatened litigation. We have
not been a party to any bankruptcy, receivership, reorganization, adjustment or
similar proceeding.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
The following discussion and analysis should be read in conjunction
with our Consolidated Financial Statements and the related notes.
OVERVIEW
Strategy
Our primary objective is to increase the per share net asset value of
our common stock through increasing reserves, production, cash flow and
earnings. We are shifting the balance of our investments from properties having
high rates of production in early years to properties with more consistent
production over a longer term. We attempt to reduce our financial risks by
dedicating a smaller portion of our capital to high risk projects, while
reserving the majority of our available capital for exploitation and development
drilling opportunities. Obtaining positions in long-lived oil and gas reserves
will be given priority over properties that might provide more cash flow in the
early years of production, but which have shorter reserve lives. We also attempt
to further reduce risk by emphasizing acquisition possibilities over high risk
exploration projects.
During the latter part of 2002, we reduced our emphasis on high risk
exploration efforts and started focusing on established geologic trends where we
can utilize the engineering, operational, financial and technical expertise of
our entire staff. Although we anticipate participating in exploratory drilling
activities in the future, reducing financial, reservoir, drilling and geological
risks and diversifying our property portfolio are important criteria in the
execution of our business plan. In summary, our business plan:
-14-
. focuses on projects having less geological risk;
. entails less exploratory activity in the down dip Wilcox trend of
our south Texas properties;
. emphasizes exploitation and enhancement activities;
. focuses on acquiring producing properties; and
. expands the scope of our operations by diversifying our
exploratory and development efforts, both in and outside of our
current areas of operation.
Although the direction of our exploration and development activities
has shifted from high risk exploratory activities to lower risk development
opportunities, we will continue our efforts, as we have in the past, to maintain
low general and administrative expenses relative to the size of our overall
operations, utilize advanced technologies, serve as operator in appropriate
circumstances, and reduce operating costs.
The extent to which we are able to implement and follow through with
our business plan will be influenced by:
. the prices we receive for the oil and gas we produce;
. the results of reprocessing and reinterpreting our 3-D seismic
data;
. the results of our drilling activities;
. the costs of obtaining high quality field services;
. our ability to find and consummate acquisition opportunities; and
. our ability to negotiate and enter into work to earn
arrangements, joint venture or other similar agreements on terms
acceptable to us.
Significant changes in the prices we receive for our oil and gas,
drilling results, or the occurrence of unanticipated events beyond our control
may cause us to defer or deviate from our business plan, including the amounts
we have budgeted for our activities.
Operating Performance. Our operating performance is influenced by
several factors, the most significant of which are the prices we receive for our
oil and gas and production volumes. The world price for oil has overall
influence on the prices we receive for our oil production. The prices received
for different grades of oil are based upon the world price for oil, which is
then adjusted based upon the particular grade. Typically, light oil is sold at a
premium, while heavy grades of crude are discounted. Gas prices we receive are
primarily influenced by:
. seasonal demand;
. weather, and hurricane conditions in the Gulf of Mexico;
. availability of pipeline transportation to end users and
proximity of our wells to major transportation pipeline
infrastructures; and
. to a lesser extent, world oil prices.
Additional factors influencing our operating performance include
production expenses, overhead requirements, and cost of capital.
Our oil and gas exploration, development and acquisition activities
require substantial and continuing capital expenditures. Historically, the
sources of financing to fund our capital expenditures have included:
. cash flow from operations,
. sales of our equity securities,
. bank borrowings, and
. industry joint ventures
-15-
For the three months ended September 30, 2003, the sales price we
received for our crude oil production (excluding hedges) averaged $31.00 per
barrel compared with $28.01 per barrel for the three months ended September 30,
2002. The average sales price we received for natural gas for the three months
ended September 30, 2003 (excluding hedges), was $4.78 per mcf compared with
$3.10 per mcf for the three months ended September 30, 2002. Our hedged sales
price that we received for the three months ended September 30, 2003, averaged
$27.68 per barrel for crude oil and $4.86 per mcf for natural gas.
Our oil and gas producing activities are accounted for using the full
cost method of accounting. Under this method, we capitalize all costs incurred
in connection with the acquisition of oil and gas properties and the exploration
for and development of oil and gas reserves. See Note 6 to Financial Statements.
These costs include lease acquisition costs, geological and geophysical
expenditures, costs of drilling both productive and non-productive wells, and
overhead expenses directly related to land and property acquisition and
exploration and development activities. Proceeds from the disposition of oil and
gas properties are accounted for as a reduction in capitalized costs, with no
gain or loss recognized unless the disposition involves a material change in
reserves, in which case the gain or loss is recognized.
Depletion of the capitalized costs of oil and gas properties, including
estimated future development costs, is provided using the equivalent
unit-of-production method based upon estimates of proved oil and gas reserves
and production, which are converted to a common unit of measure based upon their
relative energy content. Unproved oil and gas properties are not amortized, but
are individually assessed for impairment. The cost of any impaired property is
transferred to the balance of oil and gas properties being depleted.
RESULTS OF OPERATIONS
Our business activities are characterized by frequent, and sometimes
significant, changes in our:
. sources of production;
. product mix (oil vs. gas volumes); and
. the prices we receive for our oil and gas production.
Year-to-year or other periodic comparisons of the results of our
operations can be difficult and may not accurately describe our condition. The
table below shows our sale volumes and the prices we received for our production
for the periods presented.
Three Months Ended Nine Months Ended
----------------------------- ---------------------------
9/30/2002 9/30/2003 9/30/2002 9/30/2003
-------------- -------------- ------------ --------------
Sales Volume:
Oil (Bbls) 28,452 158,335 91,739 471,652
Natural gas (Mcf) 616,447 895,216 1,816,909 2,482,104
Equivalent barrels of oil (BOE) (1) 131,193 307,538 394,557 885,336
Equivalent barrels of oil (BOE) per day 1,458 3,417 1,461 3,279
Prices:
Bbls (unhedged) (2) $ 28.01 $ 31.00 $ 23.71 $ 29.86
Bbls (hedged) (3) $ 27.68 $ - $ 27.78
Mcf (unhedged) (2) $ 3.10 $ 4.78 $ 2.93 $ 5.53
Mcf (hedged) (3) $ 4.86 $ - $ 5.10
BOE (unhedged) (2) $ 20.66 $ 29.87 $ 18.98 $ 31.42
BOE (hedged) (3) $ 28.39 $ - $ 29.09
________________
(1) A BOE means one barrel of oil equivalent using the ratio of six Mcf of
gas to one barrel of oil.
(2) Unhedged price is the actual price received at the wellhead for our oil
and natural gas
(3) Hedged price is the actual price received at the wellhead for our oil and
natural gas plus the settlements on our derivatives.
-16-
CRITICAL ACCOUNTING POLICIES AND PRACTICES
Revenue Recognition. We follow the sales method of accounting for oil
and natural gas revenues. Under this method, revenues are recognized based on
actual volumes of oil and natural gas sold to purchasers. No receivables,
payables or unearned revenues are recorded unless a working interest owner's
aggregate sales from the property exceed its share of the total
reserves-in-place.
Full Cost. We account for our oil and natural gas exploration and
development activities using the full cost method of accounting. Under this
method, all costs incurred in the acquisition, exploration and development of
oil and natural gas properties are capitalized. Costs of nonproducing
properties, wells in process of being drilled and significant development
projects are excluded from depletion until such time as the related project is
developed and proved reserves are established or impairment is determined. At
the end of each quarter, the net capitalized costs of our oil and natural gas
properties is limited to the lower of unamortized cost or a ceiling.
Depletion. Provision for depletion of oil and gas properties, under the
full cost method, is calculated using the unit of production method based upon
estimates of proved oil and gas reserves with oil and gas production being
converted to a common unit of measure based upon relative energy content.
Investments in unproved properties and major development projects are not
amortized until proved reserves associated with the projects can be determined
or until impairment occurs. The cost of any impaired property is transferred to
the balance of oil and gas properties being depleted.
Impairment of Assets. Under the full cost accounting rules, the
capitalized costs of oil and gas properties may not exceed a "ceiling limit",
which is based on the present value of estimated future net revenues, net of
income tax effects, from proved reserves, discounted at 10%, plus the lower of
cost or fair market value of unproved properties. If the net capitalized costs
of our oil and natural gas properties exceed the ceiling, we are subject to a
ceiling test write-down to the extent of such excess. A ceiling test write-down
is a non-cash charge to earnings. It reduces earnings and impacts stockholders'
equity in the period of occurrence and results in lower depreciation, depletion
and amortization expense in future periods.
The risk that we will be required to write down the carrying value of
oil and gas properties increases when oil and gas prices decline. If commodity
prices deteriorate, it is possible that we could incur impairment in 2003.
Proved Reserve Estimates. Our discounted present value of proved oil
and natural gas reserves is a major component of the ceiling calculation, and
represents the component that requires the most subjective judgments. Estimates
of reserves are forecasts based on engineering data, projected future rates of
production and the timing of future expenditures. The process of estimating oil
and natural gas reserves requires substantial judgment, resulting in imprecise
determinations, particularly for new discoveries. Different reserve engineers
may make different estimates of reserve quantities based on the same data. Our
reserve estimates are prepared by outside consultants.
The passage of time provides more qualitative information regarding
estimates of reserves, and revisions are made to prior estimates to reflect
updated information. However, there can be no assurance that more significant
revisions will not be necessary in the future. If future significant revisions
are necessary that reduce previously estimated reserve quantities, it could
result in a full cost property write-down. In addition to the impact of these
estimates of proved reserves on calculation of the ceiling, estimates of proved
reserves are also a significant component of the calculation of depreciation,
depletion and amortization.
While the quantities of proved reserves require substantial judgment,
the associated prices of oil and natural gas reserves that are included in the
discounted present value of the reserves do not require judgment. The ceiling
calculation dictates that prices and costs in effect as of the last day of the
period are held constant indefinitely. Because the ceiling calculation dictates
that we use prices in effect as of the last day of the applicable quarter, the
resulting value is not indicative of the true fair value of the reserves. Oil
and natural gas prices have historically been cyclical and, on any particular
day at the end of a quarter, can be either substantially higher or lower than
prices we actually receive in the long-term, which are a barometer for true fair
value.
-17-
Use of Estimates. The preparation of financial statements in accordance
with generally accepted accounting principles in the United States of America
requires management to make estimates and assumptions that affect reported
assets, liabilities, revenues, expenses, and some narrative disclosures.
Hydrocarbon reserves, future development costs, certain hydrocarbon production
expense and revenue are the most critical estimates to our financial statements.
Derivatives. SFAS No. 133 and SFAS No. 138 require that all derivative
instruments be recorded on the balance sheet at their respective values. SFAS
No. 133 and SFAS No. 138 are effective for all fiscal quarters of all fiscal
years beginning after June 30, 2000. We adopted SFAS No. 133 and SFAS No. 138 on
January 1, 2001. For the year ended December 31, 2002, we used fair value
accounting for our hedge contracts. As of January 1, 2003 we adopted hedge
accounting for the costless collars, oil and gas swaps, and interest rate swaps.
We continued fair value accounting for our put positions. The purpose of our
hedges is to provide a measure of stability in our oil and gas prices and
interest rate payments and to manage exposure to commodity price and interest
rate risk under existing sales contracts.
Off Balance Sheet Arrangements. We do not currently have any off
balance sheet arrangements or other such unrecorded obligations and we have not
guaranteed the debt of any third party. Parallel, L.L.C., a subsidiary, has
guaranteed the indebtness of Parallel Petroleum Corporation and Parallel, L.P.
RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2003 AND 2002:
Oil and Gas Revenues. Oil and gas revenues increased $6,021,588 or
222%, to $8,731,573 for the three months ended September 30, 2003, from
$2,709,985 for the same period of 2002. The increase was primarily the result of
a 134% or 176,345 BOE increase in oil and gas production due to the Fullerton
acquisition on December 20, 2002 and increased production at Cook Mountain and a
37% increase in the average sales price per BOE including hedges.
Lease Operating Costs. Lease operating costs increased $1,430,639, or
221%, to $2,078,640 during the three months ended September 30, 2003, compared
with $648,001 for the same period of 2002. The increase was primarily
attributable to higher lease operating costs associated with the Fullerton
acquisition and Diamond M operations, and outside operated properties acquired
at year-end.
General and Administrative Expenses. General and administrative
expenses increased by $713,480, or 205%, to $1,061,307 for the three months
ended September 30, 2003 from $347,827 for the same period of 2002. The increase
was primarily due to costs associated with additional personnel hired and
associated costs in the implementation of our new business plan.
Depreciation, Depletion and Amortization Expense. Depreciation,
depletion and amortization expense increased by $866,076, or 65%, to $2,189,183
for the three months ended September 30, 2003 compared with $1,323,107 for the
same period of 2002 primarily because of a 134% increase in production volumes.
Equity in Income (loss) of First Permian, L.P. As previously discussed
in Note 8, First Permian, L.P. of which Parallel is a 30.675% interest owner
sold all of their oil and gas properties in a transaction closing on April 8,
2002. Our equity share of the net loss for ongoing general and administrative
and wind down cost in First Permian for the third quarter was $99,928.
Change in Fair Market Value of Derivatives. The change in fair market
value of derivatives increased $147,990 due to the increase in value during the
three months ended September 30, 2003.
Interest and Other Income. Interest and other income increased were
virtually flat for the three month period ended September 30, 2003 compared to
the same period of 2002.
Dividend Income. The $143,494 dividend income in the third quarter of
2002 was related to the Energen stock that was held for sale.
Interest Expense. Interest expense increased $361,168, or 202%, to
$539,585 for the three months ended September 30, 2003 compared with $178,417
for the same period of 2002 due principally to increased bank borrowings of
$30,600,000 associated with our acquisitions, partially offset by a decrease in
the minimum interest rate under our revolving credit facility. The minimum
interest rate decreased from 4.75% to 4.50% in December 2002.
Loss on Sale of Marketable Securities. The loss of $928,540 recognized
in marketable securities is for the sale of 492,400 shares of Energen stock
during the three months ended September 30, 2002. This is the difference in the
April 8, 2002 stock price of $27.40 at the time of the sale of First Permian and
the realized net price of approximately $25.51 received during the third
quarter.
-18-
Income Tax Benefit (Expense). For the three months ended September 30,
2003, we recorded a tax expense of $1,254,938 because of increased earnings
compared to an income tax benefit of $330,836 in 2002.
Net Income. We reported net income of $1,695,196 for the three months
ended September 30, 2003 compared with a net loss of $397,916 for the three
months ended September 30, 2002. The increase of $2,093,112 or 526% is a result
of increased operating income associated with increased volumes and prices in
2003 and the loss on the sale of Energen stock recorded in 2002.
RESULTS OF OPERATIONS FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2003 AND 2002:
Oil and Gas Revenues. Oil and gas revenues increased $18,266,356, or
244%, to $25,756,339 for the nine months ended September 30, 2003, from
$7,489,983 for the same period of 2002. The increase was primarily the result of
a 124% increase in oil and gas production due to the Fullerton acquisition on
December 20, 2002, increased production at Cook Mountain and a 53% increase in
the average sales price per BOE including hedges.
Lease Operating Costs. Lease operating costs increased $3,800,505 or
198%, to $5,719,496 during the first nine months of 2003, compared with
$1,918,991 for the same period of 2002. The increase was primarily attributable
to higher lease operating costs associated with the Fullerton acquisition and
Diamond M operations and outside operated properties acquired at year end.
General and Administrative Expenses. General and administrative
expenses (excluding the incentive award payments paid and accrued during the
nine months ended September 30, 2002 of approximately $1,471,000 related to the
First Permian, L.P. divestiture) increased by $1,629,952 or 136%, to $2,831,229
for the nine months ended September 30, 2003 from $1,201,277 for the same period
of 2002. The increase was primarily due to costs associated with additional
personnel hired and associated costs in the implementation of the business plan.
In the nine month period ended September 30, 2003 overhead costs capitalized
were $678,975.
Depreciation, Depletion and Amortization Expense. Depreciation,
depletion and amortization expense increased by $2,233,165, or 56%, to
$6,244,068 for the first nine months of 2003 compared with $4,010,903 for the
same period of 2002, primarily because of a 124% increase in production volumes.
Equity in Income of First Permian, L.P. As previously discussed in Note
8 to Financial Statements, First Permian, L.P. of which Parallel is a 30.675%
interest owner sold all of their oil and gas properties in a transaction closing
on April 8, 2002. Parallel received its prorata share of net proceeds, $5.5
million in cash and 933,589 shares of Energen Stock. Our share of the net income
and distributions for the first nine months 2002 was $30,665,820.
Change in Fair Market Value of Derivatives. The change in fair market
value of derivatives increased $614,656 due to the increase in value in 2003.
Interest and Other Income. Interest and other income increased $8,643,
or 12% to $79,622 for the nine month period ended September 30, 2003 compared to
$70,979 for the same period of 2002 due to increased cash balances associated
with increased cash flow.
Dividend Income. Dividend income in 2002 was $306,872 associated with
the investment in Energen stock held for sale.
Interest Expense. Interest expense increased $1,058,259 or 216%, to
$1,547,940 for the nine months ended September 30, 2003 compared with $489,681
for the same period of 2002; due principally to increased bank borrowings
associated with our acquisitions, partially offset by a decrease in the minimum
interest rate under our revolving credit facility. The minimum interest rate
decreased from 4.75% to 4.50% in December 2002.
Loss on Sale of Marketable Securities. The loss of $928,540 recognized
in marketable securities is for the sale of 492,400 shares of Energen stock
during the nine months ended September 30, 2002. This is the difference in the
April 8, 2002 stock price of $27.40 at the time of the sale of First Permian and
the realized net price of approximately $25.51 received during the third quarter
2002.
Income Tax Expense. For the nine months ended September 30, 2003 we
recorded a tax expense of $2,893,202. Our effective tax rate for the nine months
ended September 30, 2003 was 30%, which is less than the
-19-
expected rate of 37% due to the recognition of state income tax, net operating
loss carryover and certain federal income tax credits not previously recognized.
For further discussion see Note 5.
Net Income. We reported net income of $6,618,040 for the nine months
ended September 30, 2003 compared to $18,494,836 for the nine months ended June
30, 2002. The decrease of $11,876,796 or 64% resulted from the gain on sale of
First Permian, L.P. less related tax expense, and dividend income from the
Energen stock in 2002. This was partially offset by operating income increasing
$9,849,358 in 2003 due to increased volumes and higher product prices.
Cash flow from operations for the nine months ended September 30, 2003
increased $8,981,306 or 168% to $14,324,468 compared with a net cash flow from
operations of $5,343,162 for the nine months ended September 30, 2002 resulting
from increased operating income.
LIQUIDITY AND CAPITAL RESOURCES
Our capital resources consist primarily of cash flows from our oil and
gas properties and bank borrowings supported by our oil and gas reserves. Our
level of earnings and cash flows depends on many factors, including the prices
we receive for oil and natural gas we produce.
Working capital decreased $2,151,784 as of September 30, 2003 compared
with December 31, 2002. Current assets exceeded current liabilities by
$6,387,599 at September 30, 2003. The working capital decrease was primarily due
to the payments on our revolving debt facility and increased current maturity of
derivative obligations. This was partially offset by the elimination of current
maturities under our revolving credit facility, as amended on September 12,
2003.
We incurred net property costs of $10,644,079 for the nine months ended
September 30, 2003, primarily for our oil and gas property leasehold
acquisition, development, and enhancement activities. Also added to our property
basis were asset retirement costs of $1,236,511 for the adoption of SFAS 143
(see Note 10). The property leasehold acquisition, development and enhancement
activities were financed by the utilization of cash flows provided by
operations.
Based on our projected oil and gas revenues and related expenses and
available bank borrowings, we believe that we will have sufficient capital
resources to fund normal operations and capital requirements, interest expense
and principal reduction payments on bank debt, if required, and preferred stock
dividends. We continually review and consider alternative methods of financing.
Bank Borrowings
On December 20, 2002, Parallel and its subsidiary, Parallel, L.P.,
entered into a First Amended and Restated Credit Agreement with First American
Bank, SSB, Western National Bank and BNP Paribas. The credit facility provides
for revolving loans. This means that we can borrow, repay and reborrow funds
drawn under the credit facility. However, the aggregate amount that we can
borrow and have outstanding at any one time is subject to a borrowing base.
Generally, we can borrow only up to the borrowing base in effect from time to
time. The borrowing base amount is redetermined by the banks on or about April 1
and October 1 of each year or at other times required by the banks or at our
request. If, as a result of the banks' redetermination of the borrowing base,
the outstanding principal amount of our loan exceeds the borrowing base, we must
either provide additional collateral to the banks or prepay the principal of the
note in an amount equal to the excess. Except for the principal payments that
may be required because of our outstanding loans being in excess of the
borrowing base, interest only is payable monthly.
The credit agreement was amended in September 2003. The amendment
included:
. the deletion of the monthly commitment reduction, a provision
that would have required us to begin amortizing our loan
beginning August 31, 2003;
. the modification of certain financial ratio tests;
. an increase in our borrowing base to $50 million;
. changes in certain reporting requirements to the banks; and
. the revision of covenants in the credit agreement governing our
hedging activities.
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The principal amount outstanding under the revolving credit facility
bears interest at First American Bank's base rate or the libor rate, at our
election. Generally, First American Bank's base rate is equal to the prime rate
published in the Wall Street Journal, but not less than 4.50%. The libor rate is
generally equal to the sum of (a) the rate designated as "British Bankers
Association Interest Settlement Rates" and offered on one, two, three or six
month interest periods for deposits of $1,000,000, and (b) a margin ranging from
2.25% to 2.75%, depending upon the outstanding principal amount of the loans.
The interest rate we are required to pay, including the applicable margin, may
never be less than 4.50%. If the principal amount outstanding is equal to or
greater than 75% of the borrowing base established by the banks, the margin is
2.75%. If the principal amount outstanding is equal to or greater than 50%, but
less than 75% of the borrowing base, the margin is 2.50%. If the principal
amount outstanding is less than 50% of the borrowing base, the margin is 2.25%.
In the case of base rate loans, interest is payable on the last day of
each month. In the case of libor loans, interest is payable on the last day of
each applicable interest period.
If the total outstanding borrowings under the facility are less than
the borrowing base, an unused commitment fee is required to be paid to the bank
lenders. The amount of the fee is .25% of the daily average of the unadvanced
amount of the borrowing base. The fee is payable quarterly.
All outstanding principal under the revolving credit facility is due
and payable on December 20, 2006. The loan is secured by substantially all of
our oil and gas properties, including the properties of Parallel, L.P. Parallel,
L.L.C., a subsidiary of Parallel Petroleum Corporation, guaranteed payment of
the loans.
We are highly dependent on bank borrowings to fund our exploration and
drilling activities. Our borrowing base is generally equivalent to the loan
value of our producing oil and gas properties as determined by the banks in
their sole discretion. If our borrowing base declines significantly, our
liquidity would be suddenly and materially limited.
If the borrowing base is increased, we are required to pay a fee of
..25% on the amount of any increase in the borrowing base.
Our obligations to the banks are secured by substantially all of our
oil and gas properties. Our bank borrowings have been incurred to finance our
property acquisition, 3-D seismic surveys, enhancement and drilling activities.
In addition to customary affirmative covenants, the credit agreement
contains various restrictive covenants and compliance requirements, including:
. maintaining certain financial ratios;
. limitations on incurring additional indebtedness;
. prohibiting the payment of dividends on our common stock;
. limitations on the disposition of assets; and
. prohibiting liens (other than in favor of the banks) to exist on
any of our properties.
If we have borrowing capacity under our credit agreement, we intend to
borrow, repay and reborrow under the revolving credit facility from time to time
as necessary, subject to borrowing base limitations, to fund:
. interpretation and processing of 3-D seismic survey data;
. lease acquisitions and drilling activities;
. acquisitions of producing properties or companies owning
producing properties; and
. general corporate purposes.
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Preferred Stock
At September 30, 2003 we had 974,500 shares of 6% convertible preferred
stock outstanding. The preferred stock:
. requires us to pay dividends of $.60 per annum, semi-annually on
June 15 and December 15 of each year.
. is convertible into common stock at any time, at the option of
the holder, into 2.8751 shares of common stock at an initial
conversion price of $3.50 per shares, subject to adjustment in
certain events.
. is redeemable at our option, in whole or in part, for $10 per
share, plus accrued dividends.
. has no voting rights, except as required by applicable law, and,
except that as long as any shares of preferred stock remain
outstanding, the holders of a majority of the outstanding shares
of the preferred stock may vote on any proposal to change any
provision of the preferred stock which materially and adversely
affects the rights, preferences or privileges of the preferred
stock.
. is senior to the common stock with respect to dividends and on
liquidation, dissolution or winding up of Parallel.
. has a liquidation value of $10 per share, plus accrued and unpaid
dividends.
Commodity Price Risk Management Transactions
Certain of our commodity price risk management arrangements have
required us to deliver cash collateral or other assurances of performance to the
counterparties in the event that our payment obligations with respect to our
commodity price risk management transactions exceed certain levels.
With the primary objective of achieving more predictable revenues and
cash flows and reducing the exposure to fluctuations in oil and natural gas
prices, we have entered into price risk management transactions of various kinds
with respect to both oil and natural gas. While the use of certain of these
price risk management arrangements limits the downside risk of adverse price
movements, it may also limit future revenues from favorable price movements. We
engage in transactions such as swaps and collars which are marked-to-market at
the end of the relevant accounting period. Since the futures market historically
has been highly volatile, these fluctuations may cause significant impact on the
results of any given accounting period. We have entered into price risk
management transactions with respect to a substantial portion of our estimated
production for the remainder of 2003 through 2006. We continue to evaluate
whether to enter into additional price risk management transactions for 2003 and
future years. In addition, we may determine from time to time to unwind our then
existing price management positions as part of our price risk management
strategy.
Future Capital Requirements
Our capital expenditure budget is highly dependent on future oil and gas prices
and the availability of funding. Our estimated capital budget for 2003 is
anticipated to be approximately $14.0 million, of which approximately $10.6
million had been expended as of September 30, 2003. Additional capital
expenditures in the estimated amount of $3.4 million are expected to be incurred
during the remainder of 2003. These expenditures will be governed by the
following factors:
. internally generated cash flows;
. availability of borrowing under our revolving credit facility;
. additional sources of financing; and
. future drilling successes.
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In 2003, we have focused on drilling lower risk natural gas prospects
that could have a meaningful effect on our reserve base and cash flows. In
selected cases, we may elect to reduce our interest in higher risk, higher
impact projects. We may also sell certain non-core producing properties to raise
funds for capital expenditures.
The following table is a summary of significant contractual cash
obligations:
Obligation Due in Period
----------------------------------------------------------
Contractual Cash Obligations 2003 2004 2005 2006 Total
- ------------------------------------------------ ----------- ---------- ----------- ----------- ----------
(in 000's)
Revolving Credit Facility (Secured) $ - $ - $ - $ 39,750 $ 39,750
Office Lease (Dinero Plaza) $ 102 $ 102 $ 102 $ 68 $ 374
Preferred Stock Dividends $ 585 $ 585 $ 585 $ 585 $ 2,340
Outlook
The oil and gas industry is capital intensive. We make, and anticipate
that we will continue to make, substantial capital expenditures in the
exploration for, development and acquisition of oil and gas reserves.
Historically, our capital expenditures have been financed primarily with:
. internally generated cash from operations;
. proceeds from bank borrowings; and
. proceeds from sales of equity securities.
The continued availability of these capital sources depends upon a
number of variables, including:
. our proved reserves;
. the volumes of oil and gas we produce from existing wells;
. the prices at which we sell oil and gas; and
. our ability to acquire, locate and produce new reserves.
Each of these variables materially affects our borrowing capacity. We
may from time to time seek additional financing in the form of:
. increased bank borrowings;
. sales of Parallel's securities;
. sales of non-core properties; or
. other forms of financing.
We do not have agreements for any future financing and there can be no
assurance as to the availability or terms of any such financing.
Inflation
Inflation has not had a significant impact on our financial condition
or results of operations. We do not believe that inflation poses a material risk
to our business.
Recent Accounting Pronouncements
SFAS No. 148, Accounting for Stock-Based Compensation-Transition and
Disclosure, which amends SFAS No. 123, Accounting for Stock-Based Compensation.
SFAS No. 148 provides alternative methods of transition for a
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voluntary change to the fair value based method of accounting for stock-based
employee compensation. As of September 30, 2003, we adopted the Prospective
method which applies prospectively the fair value recognition method to all
employee and director awards granted, modified or settled after the beginning of
the fiscal year in which the fair value based method of accounting for
stock-based compensation is adopted. (See Note 2) SFAS 148 also amends the
disclosure requirements of SFAS No. 123 to require prominent disclosures in both
annual and interim financial statements about the method of accounting for
stock-based employee compensation and the effect of the method used on reported
results. The statement is required to be adopted for fiscal years ending after
December 15, 2002.
On April 22, 2003, the FASB announced its decision to require all
companies to expense the value of employee stock options. Companies will be
required to measure the cost according to the fair value of the options. The new
guidelines have not been released to measure the cost according to the fair
value of the options. Although the new guidelines have not been released, it is
expected that they will be finalized and become effective in 2004. When final
rules are announced, we will assess the impact to our consolidated financial
statements.
FIN No. 45, Guarantor's Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of Others, FIN No. 45
requires that a liability be recorded in the guarantor's balance sheet upon
issuance of certain guarantees. Initial recognition and measurement of the
liability will be applied on a prospective basis to guarantees issued or
modified after December 31, 2002. FIN No. 45 also requires disclosures about
guarantees in financial statements for interim or annual periods ending after
December 15, 2002. We do not expect the adoption of FIN No. 45 to have a
material impact on our consolidated financial statements.
FIN No. 46, Consolidation of Variable Interest Entities, an
Interpretation of Accounting Research Bulletin No. 51. FIN No. 46 requires
certain variable interest entities to be consolidated by the primary beneficiary
of the entity if the equity investors in the entity do not have the
characteristics of a controlling financial interest or do not have sufficient
equity at risk for the entity to finance its activities without financial
support from other parties. We do not expect the adoption of FIN No. 46 to have
a material impact on our consolidated financial statements.
In April 2003, the Financial Accounting Standards Board issued SFAS No.
149, Amendment of Statement 133 on Derivative Instruments and Hedging
Activities, which clarifies financial accounting and reporting for derivative
instruments, including certain derivative instruments embedded in other
contracts and for hedging activities under SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities. The Statement is effective for
contracts entered into or modified after June 20, 2003. We do not anticipate
SFAS No. 149 will have a material effect on future earnings.
In May 2003, the FASB issued Statement No. 150 "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity." This
statement establishes standards for how an issuer classifies and measures
certain financial instruments with characteristics of both liabilities and
equity. This statement is effective for financial instruments entered into or
modified after May 31, 2003, and otherwise is effective at the beginning of the
first interim period beginning after June 15, 2003. The adoption of FAS 150 did
not have a material impact on our consolidated financial statements.
Effects of Derivative Instruments
For the year ended December 31, 2002, we used mark-to-market accounting
for our hedge contracts. As of January 1, 2003 we adopted hedge accounting for
the costless collars, oil and gas swaps, and interest rate swaps. We continued
fair value accounting for our put positions described below. The purpose of our
hedges is to provide a measure of stability in our oil and gas prices and
interest rate payments and to manage exposure to commodity price and interest
rate risk. Our objective is to lock in a range of oil and gas prices and a fixed
interest rate for certain notional amounts.
During the terms of a hedge, the quarterly change in the fair value of
the derivatives is recorded in stockholders' equity as other comprehensive
income (loss) and then transferred to earnings when the production is sold.
Ineffective portions of hedges (changes in realized prices that do not match the
changes in the hedge price) are recognized in earnings as they occur. While the
hedge contract is open, the ineffective gain or loss may increase or decrease
until settlement of the contract.
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We are exposed to credit risk in the event of nonperformance by the
counterparty in its derivative instruments. However, we periodically assess the
creditworthiness of the counterparty to mitigate this credit risk. See Note 7 to
Consolidated Financial Statements.
TRENDS AND PRICES
Changes in oil and gas prices significantly affect our revenues, cash
flows and borrowing capacity. Markets for oil and gas have historically been,
and will continue to be, volatile. Prices for oil and gas typically fluctuate in
response to relatively minor changes in supply and demand, market uncertainty,
seasonal, political and other factors beyond our control. We are unable to
accurately predict domestic or worldwide political events or the effects of
other such factors on the prices we receive for our oil and gas. Please refer to
Note 7 Derivative Instruments.
Our capital expenditure budgets are highly dependent on future oil and
gas prices and will be consistent with internally generated cash flows.
During fiscal year 2002 the average realized sales price for our oil
and natural gas was $21.03 per BOE. For the nine months ended September 30,
2003, our average realized price was $29.09 per BOE.
FORWARD-LOOKING STATEMENTS
In addition to historical information contained herein, this Form 10-Q
Report contains forward-looking statements subject to various risks and
uncertainties that could cause our actual results to differ materially from
those in the forward-looking statements. Forward-looking statements can be
identified by the use of forward-looking terminology such as "may", "will",
"expect," "intend," "anticipate, "estimate," "continue," "present value,"
"future," "reserves" or other variations thereof or comparable terminology.
Factors that could cause or contribute to such differences include, but are not
limited to:
. those relating to the results of exploratory drilling activity,
. changes in oil and natural gas prices,
. operating risks,
. availability of drilling equipment,
. outstanding indebtedness,
. changes in interest rates,
. dependence on weather conditions,
. seasonality,
. expansion and other activities of competitors,
. changes in federal or state environmental laws and the
administration of such laws,
. the general condition of the economy and its effect on the
securities markets.
While we believe our forward-looking statements are based upon
reasonable assumptions, these are factors that are difficult to predict and that
are influenced by economic and other conditions beyond our control. Investors
are urged to consider such risks and other uncertainties discussed in documents
filed by us with the SEC.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Interest Rate Risk
Our only financial instrument sensitive to changes in interest rates is
our bank debt. Our annual interest costs in 2003 could fluctuate based on
short-term interest rates. As the interest rate is variable and reflects current
market conditions, the carrying value approximates the fair value. The table
below shows principal cash flows and related weighted average interest rates by
expected maturity dates. Weighted average interest rates were determined using
weighted average interest paid and accrued in June 2003.
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December December December December
2003 2004 2005 2006 Total
------------- ------------ ------------ ------------ -------------
(In 000's, except interest rates)
Variable rate debt:
Revolving facility (secured) $ - $ - $ - $ 39,750 $ 39,750
Average interest rate (unhedged) 4.50% 4.50% 4.50% 4.50% -
Average interest rate (hedged)(1) 4.425% 5.16% 6.30% 6.30% -
- ---------------------
(1) Total of the libor fixed interest rate plus the expected margin rate under
our revolving credit facility. Our credit agreement requires the interest
rate to not be below 4.50%.
At September 30, 2003, we had bank loans in the amount of $39,750,000
outstanding at an average interest rate of 4.50%. Borrowings under our revolving
credit facility bear interest, at our election, at (i) the bank's base rate or
(ii) the Eurodollar rate, plus 2.75%, but in no event less than 4.50%. As a
result, our annual interest costs in 2003 could fluctuate based on short-term
interest rates. Assuming no change in the amount outstanding during 2003, the
impact on interest expense of a one-half of one percent change in the average
interest rate above the 4.50% floor would be approximately $50,096 for the
remainder of the year. As the interest rate is variable and is reflective of
current market conditions, the carrying value approximates the fair value.
We periodically hedge a portion of our interest rates to manage
exposure to interest rate movements. In January 2003 we entered into several
libor fixed rate swap contracts extending throughout our loan period. See Note
7.
Commodity Price Risk
Our major market risk exposure is in the pricing applicable to our oil
and natural gas production. Market risk refers to the risk of loss from adverse
changes in oil and natural gas prices. Realized pricing is primarily driven by
the prevailing domestic price for crude oil and spot prices applicable to the
region in which we produce natural gas. Historically, prices received for oil
and gas production have been volatile and unpredictable. Pricing volatility is
expected to continue. Oil prices ranged from a low of $22.93 per barrel to a
high of $27.07 per barrel during 2002. Natural gas prices we received during
2002 ranged from a low of $1.35 per Mcf to a high of $4.18 per Mcf. During 2003
oil prices ranged from a low of $22.78 to a high of $35.95. Natural gas prices
we received during 2003 ranged from a low of $1.98 per Mcf to a high of $10.28
per Mcf. A significant decline in the prices of natural gas or oil could have a
material adverse effect on our financial condition and results of operations.
We periodically hedge a portion of our oil and natural gas to manage
exposure to commodity price risk under existing sales contracts. Our objective
is to lock in a range of oil and gas prices. We try to meet this objective by
entering into costless collars and swap hedge contracts. As of September 30,
2003, outstanding gas swap agreements and collars had a net fair value gain of
$215,137. The aggregate effect of a hypothetical 10% change in gas prices would
result in a change of approximately $194,059 in fair value of these swap
agreements and collars at September 30, 2003. As of September 30, 2003,
outstanding oil differential swaps had a net fair value loss of $2,693,474. The
aggregate effect of a hypothetical 10% change in oil prices would result in a
change of approximately $2,485,491 in the fair value of these oil differential
swaps and collars at September 30, 2003.
Because most of our swap agreements and collars are designated hedge
derivatives, and to the extent the hedges are effective, changes in their fair
value generally are reported as a component of accumulated other comprehensive
income (loss) until the related sale of production occurs. At that time, the
realized hedge derivative gain or loss is transferred to revenues in the
consolidated income statement
For the remainder of fiscal 2003 hedged oil and natural gas volumes
represent approximately 69% and 44% respectively of expected production from
October thru December 2003. Please read Note 7 to our Financial Statements for
additional information about market risks.
ITEM 4. CONTROLS AND PROCEDURES
As of the end of the period covered by this Quarterly Report on Form
10-Q, the effectiveness of our disclosure controls and procedures was evaluated
by our management, with the participation of our chief executive officer, Thomas
R. Cambridge (principal executive officer), and our chief financial officer,
Steven D. Foster (principal financial officer). Our disclosure controls and
procedures are designed to help ensure that information we are required to
disclose in reports that we file with the SEC is accumulated and communicated to
our management and recorded,
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processed, summarized and reported within the time periods prescribed by the
SEC. Mr. Cambridge and Mr. Foster have concluded that our disclosure controls
and procedures are effective for their intended purposes. There were no changes
in internal control over financial reporting that occurred during the last
fiscal quarter that have materially affected, or are reasonably likely to
materially affect, our internal control over financial reporting.
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
At September 30, 2003, we were involved in two lawsuits incidental to
our business. We accrue for such items when a liability is both probable and the
amount can be reasonably estimated. We do not believe the ultimate outcome of
these lawsuits will have a material adverse effect on our financial position or
results of operations. We are not aware of any threatened litigation. We have
not been a party to any bankruptcy, receivership, reorganization, adjustment or
similar proceeding.
ITEM 6. EXHIBIT AND REPORTS ON FORM 8-K
(a) Exhibits
No. Description of Exhibit
---- -----------------------
3.1 Certificate of Incorporation of Registrant (incorporated by
reference to Exhibit 3.1 to Form 10-K of the Registrant for
the fiscal year ended December 31, 1998.)
3.2 Bylaws of Registrant (Incorporated by reference to Exhibit 3
to the Registrant's Form 8-K, dated October 9, 2000, as filed
with the Securities and Exchange Commission on October 10,
2000.)
4.1 Certificate of Designations, Preferences and Rights of Serial
Preferred Stock - 6% Convertible Preferred Stock (Incorporated
by reference to Exhibit 4.1 to Form 10-Q of the Registrant for
the fiscal quarter ended September 30, 1998.)
4.2 Certificate of Designation, Preferences and Rights of Series A
Preferred Stock. (Incorporated by reference to Exhibit 4.2 of
Form 10-K for the fiscal year ended December 31, 2000.)
4.3 Rights Agreement, dated as of October 5, 2000, between the
Registrant and Computershare Trust Company, Inc., as Rights
Agent. (Incorporated by reference to Exhibit 4.3 of Form 10-K
for the fiscal year ended December 31, 2000.)
Executive Compensation Plans and Arrangements (Exhibit No.'s
------------------------------------------------------------
10.1 through 10.9):
------------------
10.1 1983 Incentive Stock Option Plan (Incorporated by reference to
Exhibit 10.2 to Form S-l of the Registrant (File No. 2-92397)
as filed with the Securities and Exchange Commission on July
26, 1984, as amended by Amendments No. 1 and 2 on October 5,
1984, and October 25, 1984, respectively.)
10.2 1992 Stock Option Plan (Incorporated by reference to Exhibit
28.1 to Form S-8 of the Registrant (File No. 33-57348) as
filed with the Securities and Exchange Commission on January
25, 1993.)
10.3 Stock Option Agreement between the Registrant and Thomas R.
Cambridge dated December 11, 1991 (Incorporated by reference
to Exhibit 10.4 of Form 10-K of the Registrant for the fiscal
year ended December 31, 1992.)
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10.4 Stock Option Agreement between the Registrant and Thomas R.
Cambridge dated October 18, 1993 (Incorporated by reference to
Exhibit 10.4(e) of Form 10-K of the Registrant for the fiscal
year ended December 31, 1993.)
10.5 Merrill Lynch, Pierce, Fenner & Smith Incorporated Prototype
Simplified Employee Pension Plan (Incorporated by reference to
Exhibit 10.6 of the Registrant's Form 10-K for the fiscal year
ended December 31, 1995.)
10.6 Non-Employee Directors Stock Option Plan (Incorporated by
reference to Exhibit 10.6 of the Registrant's Form 10-K Report
for the fiscal year ended December 31, 1997).
10.7 1998 Stock Option Plan (Incorporated by reference to Exhibit
10.7 of Form 10-K of the Registrant for the fiscal year ended
December 31, 1998.)
10.8 Form of Incentive Award Agreements, dated December 12, 2001,
between the Registrant and Thomas R. Cambridge, Larry C.
Oldham, Eric A. Bayley and John S. Rutherford granting 2,394
Unit Equivalent Rights to Mr. Cambridge; 9,564 Unit Equivalent
Rights to Mr. Oldham; 2,869 Unit Equivalent Rights to Mr.
Bayley; and 7,173 Unit Equivalent Rights to Mr. Rutherford.
(Incorporated by reference to Exhibit 10.8 of the Registrant's
Form 10-K Report for the fiscal year ended December 31, 2001).
10.9 Form of Change of Control Agreements, dated June 1, 2001,
between the Registrant and Thomas R. Cambridge, Larry C.
Oldham, Eric A. Bayley and John S. Rutherford. (Incorporated
by reference to Exhibit 10.9 of the Registrant's Form 10-K
Report for the fiscal year ended December 31, 2001).
10.10 Restated Loan Agreement, dated December 27, 1999, between the
Registrant and Bank One, Texas, N.A. (Incorporated by
reference to Exhibit 10.8 of Form 10-K of the Registrant for
the fiscal year ended December 31, 1999).
10.11 Loan Agreement dated December 18, 2000, between the Registrant
and Bank One, Texas, N.A. (Incorporated by reference to
Exhibit 10.8 of Form 10-K of the Registrant for the fiscal
year ended December 31, 2000.)
10.12 Letter agreement, dated March 24, 1999, between the Registrant
and Bank One, Texas, N.A. (Incorporated by reference to
Exhibit 10.9 of Form 10-K of the Registrant for the fiscal
year ended December 31, 1998.)
10.13 Certificate of Formation of First Permian, L.L.C.
(Incorporated by reference to Exhibit 10.1 of the Registrant's
Form 8-K report dated June 30, 1999.)
10.14 Limited Liability Company Agreement of First Permian, L.L.C.
(Incorporated by reference to Exhibit 10.2 of the Registrant's
Form 8-K report dated June 30, 1999.)
10.15 Merger Agreement dated June 25, 1999. (Incorporated by
reference to Exhibit 10.3 of the Registrant's Form 8-K report
dated June 30, 1999.)
10.16 Agreement and Plan of Merger of First Permian, L.L.C. and Nash
Oil Company, L.L.C. (Incorporated by reference to Exhibit 10.4
of the Registrant's Form 8-K report dated June 30, 1999.)
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10.17 Certificate of Merger of First Permian, L.L.C. and Nash Oil
Company, L.L.C (Incorporated by reference to Exhibit 10.5 of
the Registrant's Form 8-K Report dated June 30, 1999.)
10.18 Amended and Restated Limited Liability Company Agreement of
First Permian, L.L.C. dated as of May 31, 2000. (Incorporated
by reference to Exhibit 10.16 of Form 10-K for the fiscal year
ended December 31, 2000.)
10.19 Credit Agreement dated June 30, 1999, by and among First
Permian, L.L.C., Parallel Petroleum Corporation, Baytech,
Inc., and Bank One, Texas, N.A. (Incorporated by reference to
Exhibit 10.6 of the Registrant's Form 8-K report dated June
30, 1999.)
10.20 Limited Guaranty, dated June 30, 1999, by and among First
Permian, L.L.C., Parallel Petroleum Corporation, and Bank One,
Texas, N.A. (Incorporated by reference to Exhibit 10.7 of the
Registrant's Form 8-K report dated June 30, 1999.)
10.21 Intercreditor Agreement, dated as of June 30, 1999, by and
among First Permian, L.L.C., Bank One, Texas, N.A., Tejon
Exploration Company, and Mansefeldt Investment Corporation
(Incorporated by reference to Exhibit 10.8 of the Registrant's
Form 8-K report dated June 30, 1999.)
10.22 Subordinated Promissory Note, dated June 30, 1999, in the
original principal amount of $8.0 million made by First
Permian, L.L.C. payable to the order of Tejon Exploration
Company (Incorporated by reference to Exhibit 10.9 of the
Registrant's Form 8-K report dated June 30, 1999.)
10.23 Subordinated Promissory Note, dated June 30, 1999, in the
original principal amount of $8.0 million made by First
Permian, L.L.C. payable to the order of Mansefeldt Investment
Corporation (Incorporated by reference to Exhibit 10.10 of the
Registrant's Form 8-K report dated June 30, 1999.)
10.24 Second Restated Credit Agreement, dated October 25, 2000,
among First Permian, L.L.C., Bank One, Texas, N.A., and Bank
One Capital Markets, Inc. (Incorporated by reference to
Exhibit 10.22 of Form 10-K for the fiscal year ended December
31, 2000.)
10.25 Loan Agreement, dated January 25, 2002, between the Registrant
and First American Bank, SSB (Incorporated by reference to
Exhibit 10.25 of Form 10-K for the fiscal year ended December
31, 2001.)
10.26 Purchase and Sale Agreement, dated as of November 27, 2002,
among JMC Exploration, Inc., Arkoma Star L.L.C., Parallel,
L.P. and Texland Petroleum, Inc. (Incorporated by reference to
Exhibit 10.1 of Form 8-K of the Registrant, dated December 20,
2002)
10.27 First Amended and Restated Credit Agreement, dated December
20, 2002, by and among Parallel Petroleum Corporation,
Parallel, L.P. Parallel, L.L.C., First American Bank, SSB,
Western National Bank and BNP Paribas (Incorporated by
reference to Exhibit 10.2 of Form 8-K of the Registrant, dated
December 20, 2002)
10.28 Guaranty dated December 20, 2002, between Parallel, L.L.C. and
First American Bank, SSB, as Agent (Incorporated by reference
to Exhibit 10.3 of Form 8-K of the Registrant, dated December
20, 2002)
*10.29 First Amendment to First Amended and Restated Credit
Agreement, dated as of September 12, 2003, by and among
Parallel Petroleum Corporation, Parallel, L.P., Parallel,
L.L.C., First American, SSB, Western National Bank, and BNP
Paribas
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21 Subsidiaries (Incorporated by reference to Exhibit 21 of Form
10-K of the Registrant for the fiscal year ended December 31,
2002)
*31.1 Certification of Principal Executive Officer pursuant to 18
U.S.C. Section 1350, as adopted pursuant to Section 302 of the
Sarbanes - Oxley Act of 2002.
*31.2 Certification of Principal Financial Officer pursuant to 18
U.S.C. Section 1350, as adopted pursuant to Section 302 of the
Sarbanes - Oxley Act of 2002.
*32.1 Certification of Chief Executive Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the
Sarbanes - Oxley Act of 2002.
*32.2 Certification of Chief Financial Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the
Sarbanes - Oxley Act of 2002.
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* Filed herewith.
(b) Reports on Form 8-K
During the fiscal quarter ended September 30, 2003, we filed one report
on Form 8-K.
On August 14, 2003, we filed Form 8-K, dated August 14, 2003, reporting
matters furnished under Item 9 - Regulation FD Disclosure, and Item 12 -
Disclosure of Results of Operations and Financial Condition. This report
included our August 14, 2003 press release announcing our results of operations
and financial condition for the second quarter ended June 30, 2003.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
PARALLEL PETROLEUM CORPORATION
BY: /s/ Thomas R. Cambridge
Date: October 30, 2003 ---------------------------------------
Thomas R. Cambridge
Chairman of the Board of Directors
and Chief Executive Officer
Date: October 30, 2003 BY: /s/ Steven D. Foster
---------------------------------------
Steven D. Foster,
Chief Financial Officer
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INDEX TO EXHIBITS
(a) Exhibits
No. Description of Exhibit
---- ----------------------
3.1 Certificate of Incorporation of Registrant (incorporated by
reference to Exhibit 3.1 to Form 10-K of the Registrant for
the fiscal year ended December 31, 1998.)
3.2 Bylaws of Registrant (Incorporated by reference to Exhibit 3
to the Registrant's Form 8-K, dated October 9, 2000, as filed
with the Securities and Exchange Commission on October 10,
2000.)
4.1 Certificate of Designations, Preferences and Rights of Serial
Preferred Stock - 6% Convertible Preferred Stock (Incorporated
by reference to Exhibit 4.1 to Form 10-Q of the Registrant for
the fiscal quarter ended September 30, 1998.)
4.2 Certificate of Designation, Preferences and Rights of Series A
Preferred Stock. (Incorporated by reference to Exhibit 4.2 of
Form 10-K for the fiscal year ended December 31, 2000.)
4.3 Rights Agreement, dated as of October 5, 2000, between the
Registrant and Computershare Trust Company, Inc., as Rights
Agent. (Incorporated by reference to Exhibit 4.3 of Form 10-K
for the fiscal year ended December 31, 2000.)
Executive Compensation Plans and Arrangements (Exhibit No.'s
------------------------------------------------------------
10.1 through 10.9):
-------------------
10.1 1983 Incentive Stock Option Plan (Incorporated by reference to
Exhibit 10.2 to Form S-l of the Registrant (File No. 2-92397)
as filed with the Securities and Exchange Commission on July
26, 1984, as amended by Amendments No. 1 and 2 on October 5,
1984, and October 25, 1984, respectively.)
10.2 1992 Stock Option Plan (Incorporated by reference to Exhibit
28.1 to Form S-8 of the Registrant (File No. 33-57348) as
filed with the Securities and Exchange Commission on January
25, 1993.)
10.3 Stock Option Agreement between the Registrant and Thomas R.
Cambridge dated December 11, 1991 (Incorporated by reference
to Exhibit 10.4 of Form 10-K of the Registrant for the fiscal
year ended December 31, 1992.)
10.4 Stock Option Agreement between the Registrant and Thomas R.
Cambridge dated October 18, 1993 (Incorporated by reference to
Exhibit 10.4(e) of Form 10-K of the Registrant for the fiscal
year ended December 31, 1993.)
10.5 Merrill Lynch, Pierce, Fenner & Smith Incorporated Prototype
Simplified Employee Pension Plan (Incorporated by reference to
Exhibit 10.6 of the Registrant's Form 10-K for the fiscal year
ended December 31, 1995.)
10.6 Non-Employee Directors Stock Option Plan (Incorporated by
reference to Exhibit 10.6 of the Registrant's Form 10-K Report
for the fiscal year ended December 31, 1997).
10.7 1998 Stock Option Plan (Incorporated by reference to Exhibit
10.7 of Form 10-K of the Registrant for the fiscal year ended
December 31, 1998.)
10.8 Form of Incentive Award Agreements, dated December 12, 2001,
between the Registrant and Thomas R. Cambridge, Larry C.
Oldham, Eric A. Bayley and John S. Rutherford granting 2,394
Unit Equivalent Rights to Mr. Cambridge; 9,564 Unit Equivalent
Rights to Mr. Oldham; 2,869 Unit Equivalent Rights to Mr.
Bayley; and 7,173 Unit Equivalent Rights to Mr. Rutherford.
(Incorporated by reference to Exhibit 10.8 of the Registrant's
Form 10-K Report for the fiscal year ended December 31, 2001).
10.9 Form of Change of Control Agreements, dated June 1, 2001,
between the Registrant and Thomas R. Cambridge, Larry C.
Oldham, Eric A. Bayley and John S. Rutherford. (Incorporated
by reference to Exhibit 10.9 of the Registrant's Form 10-K
Report for the fiscal year ended December 31, 2001).
10.10 Restated Loan Agreement, dated December 27, 1999, between the
Registrant and Bank One, Texas, N.A. (Incorporated by
reference to Exhibit 10.8 of Form 10-K of the Registrant for
the fiscal year ended December 31, 1999).
10.11 Loan Agreement dated December 18, 2000, between the Registrant
and Bank One, Texas, N.A. (Incorporated by reference to
Exhibit 10.8 of Form 10-K of the Registrant for the fiscal
year ended December 31, 2000.)
10.12 Letter agreement, dated March 24, 1999, between the Registrant
and Bank One, Texas, N.A. (Incorporated by reference to
Exhibit 10.9 of Form 10-K of the Registrant for the fiscal
year ended December 31, 1998.)
10.13 Certificate of Formation of First Permian, L.L.C.
(Incorporated by reference to Exhibit 10.1 of the Registrant's
Form 8-K report dated June 30, 1999.)
10.14 Limited Liability Company Agreement of First Permian, L.L.C.
(Incorporated by reference to Exhibit 10.2 of the Registrant's
Form 8-K report dated June 30, 1999.)
10.15 Merger Agreement dated June 25, 1999. (Incorporated by
reference to Exhibit 10.3 of the Registrant's Form 8-K report
dated June 30, 1999.)
10.16 Agreement and Plan of Merger of First Permian, L.L.C. and Nash
Oil Company, L.L.C. (Incorporated by reference to Exhibit 10.4
of the Registrant's Form 8-K report dated June 30, 1999.)
10.17 Certificate of Merger of First Permian, L.L.C. and Nash Oil
Company, L.L.C (Incorporated by reference to Exhibit 10.5 of
the Registrant's Form 8-K Report dated June 30, 1999.)
10.18 Amended and Restated Limited Liability Company Agreement of
First Permian, L.L.C. dated as of May 31, 2000. (Incorporated
by reference to Exhibit 10.16 of Form 10-K for the fiscal year
ended December 31, 2000.)
10.19 Credit Agreement dated June 30, 1999, by and among First
Permian, L.L.C., Parallel Petroleum Corporation, Baytech,
Inc., and Bank One, Texas, N.A. (Incorporated by reference to
Exhibit 10.6 of the Registrant's Form 8-K report dated June
30, 1999.)
10.20 Limited Guaranty, dated June 30, 1999, by and among First
Permian, L.L.C., Parallel Petroleum Corporation, and Bank One,
Texas, N.A. (Incorporated by reference to Exhibit 10.7 of the
Registrant's Form 8-K report dated June 30, 1999.)
10.21 Intercreditor Agreement, dated as of June 30, 1999, by and
among First Permian, L.L.C., Bank One, Texas, N.A., Tejon
Exploration Company, and Mansefeldt Investment Corporation
(Incorporated by reference to Exhibit 10.8 of the Registrant's
Form 8-K report dated June 30, 1999.)
10.22 Subordinated Promissory Note, dated June 30, 1999, in the
original principal amount of $8.0 million made by First
Permian, L.L.C. payable to the order of Tejon Exploration
Company (Incorporated by reference to Exhibit 10.9 of the
Registrant's Form 8-K report dated June 30, 1999.)
10.23 Subordinated Promissory Note, dated June 30, 1999, in the
original principal amount of $8.0 million made by First
Permian, L.L.C. payable to the order of Mansefeldt Investment
Corporation (Incorporated by reference to Exhibit 10.10 of the
Registrant's Form 8-K report dated June 30, 1999.)
10.24 Second Restated Credit Agreement, dated October 25, 2000,
among First Permian, L.L.C., Bank One, Texas, N.A., and Bank
One Capital Markets, Inc. (Incorporated by reference to
Exhibit 10.22 of Form 10-K for the fiscal year ended December
31, 2000.)
10.25 Loan Agreement, dated January 25, 2002, between the Registrant
and First American Bank, SSB (Incorporated by reference to
Exhibit 10.25 of Form 10-K for the fiscal year ended December
31, 2001.)
10.26 Purchase and Sale Agreement, dated as of November 27, 2002,
among JMC Exploration, Inc., Arkoma Star L.L.C., Parallel,
L.P. and Texland Petroleum, Inc. (Incorporated by reference to
Exhibit 10.1 of Form 8-K of the Registrant, dated December 20,
2002)
10.27 First Amended and Restated Credit Agreement, dated December
20, 2002, by and among Parallel Petroleum Corporation,
Parallel, L.P. Parallel, L.L.C., First American Bank, SSB,
Western National Bank and BNP Paribas (Incorporated by
reference to Exhibit 10.2 of Form 8-K of the Registrant, dated
December 20, 2002)
10.28 Guaranty dated December 20, 2002, between Parallel, L.L.C. and
First American Bank, SSB, as Agent (Incorporated by reference
to Exhibit 10.3 of Form 8-K of the Registrant, dated December
20, 2002)
*10.29 First Amendment to First Amended and Restated Credit
Agreement, dated as of September 12, 2003, by and among
Parallel Petroleum Corporation, Parallel, L.P., Parallel,
L.L.C., First American, SSB, Western National Bank, and BNP
Paribas
21 Subsidiaries (Incorporated by reference to Exhibit 21 of Form
10-K of the Registrant for the fiscal year ended December 31,
2002)
*31.1 Certification of Principal Executive Officer pursuant to 18
U.S.C. Section 1350, as adopted pursuant to Section 302 of the
Sarbanes - Oxley Act of 2002.
*31.2 Certification of Principal Financial Officer pursuant to 18
U.S.C. Section 1350, as adopted pursuant to Section 302 of the
Sarbanes - Oxley Act of 2002.
*32.1 Certification of Chief Executive Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the
Sarbanes - Oxley Act of 2002.
*32.2 Certification of Chief Financial Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the
Sarbanes - Oxley Act of 2002.
- ---------------
*File herewith.
Exhibit 10.29
FIRST AMENDMENT TO FIRST AMENDED
AND RESTATED CREDIT AGREEMENT
This First Amendment to First Amended and Restated Credit Agreement
(this "First Amendment") dated as of September 12, 2003, is by and among
PARALLEL PETROLEUM CORPORATION, a Delaware corporation, and PARALLEL, L.P., a
Texas limited partnership (collectively, the "Borrowers"), and PARALLEL, L.L.C.,
a Delaware limited liability company ("Guarantor"), and FIRST AMERICAN BANK,
SSB, BNP PARIBAS AND WESTERN NATIONAL BANK (collectively, "Lenders"), and FIRST
AMERICAN BANK, SSB, as Joint Lead Arranger and as Administrative Agent ("Agent")
and BNP PARIBAS, as Joint Lead Arranger and as Syndication Agent.
RECITALS:
WHERAS, Borrowers, Guarantor and Lenders in the capacities stated
above, entered into that First Amended and Restated Credit Agreement dated as of
December 20, 2002 (the "Credit Agreement"); and
WHEREAS, Borrowers, Guarantor and Lenders desire to amend the Credit
Agreement in certain respects.
NOW, THEREFORE, in consideration of the mutual covenants and agreements
contained herein and other good and valuable consideration, the receipt and
sufficiency of which are hereby acknowledged and confessed, the parties hereto
agree as follows:
Agreement
Section 1. Definitions.
Except as otherwise expressly provided herein, all terms defined in the
Credit Agreement shall have the same meanings herein.
Section 2. Deletion of Monthly Commitment Reductions. The parties to the
Credit Agreement have agreed to delete the Monthly Commitment Reduction
requirement set forth in the Credit Agreement, and in connection therewith (a)
Section 2(g)(ii) of the Credit Agreement is hereby deleted in its entirety, (b)
all references in the Credit Agreement to the "Monthly Commitment Reduction" or
the "Monthly Commitment Reductions" are hereby deleted, and (c) all text in the
Credit Agreement associated with use of the terms "Monthly Commitment Reduction"
and "Monthly Commitment Reductions" is hereby deleted to the extent and only to
the extent such text relates solely to the Monthly Commitment Reductions.
Section 3. Additional Definitions. Section 1 of the Credit Agreement is
hereby amended to add the following definitions in alphabetical order:
Consolidated EBITDA means for any period, PPC's consolidated
earnings during such period from continuing operations, before
provision for interest expenses, income taxes, depreciation, depletion,
amortization, gains and losses on asset sales and other non-cash
charges.
Consolidated Funded Debt means as of any date, PPC's total
outstanding liabilities for borrowed money and other interest-bearing
liabilities on such date, determined in each case on a consolidated
basis in accordance with GAAP.
Section 4. Deletion of Certain Definitions. The defined terms
"Consolidated Cash Flow", "Consolidated Net Income", "Debt Service Coverage
Ratio" and "Monthly Commitment Reduction" in Section 1 of the Credit Agreement
are hereby deleted in their entirety.
-1-
Section 5. Amendment to Semi-Annual Determination Dates. The first
sentence of Section 7(b)(i) of the Credit Agreement is hereby amended in its
entirety to read as follows:
Subsequent determinations of the Borrowing Base shall be made by Lenders
semi-annually on or about April 1 and October 1 of each year beginning
April 1, 2004, or as Unscheduled Redeterminations.
Section 6. Amendment to Borrowing Base Evaluation Factors. Section
7(e)(i) of the Credit Agreement is hereby amended in its entirety to read as
follows:
(i) Oil and Gas Properties. No later than March 1 and
September 1 of each year, beginning March 1, 2004, Borrowers shall, at
their own expense, furnish to Lenders an engineering report covering
the Oil and Gas Properties in form and substance satisfactory to Agent
and dated effective not more than sixty (60) days prior to the delivery
of the same to Lenders. Each such report shall be prepared by an
independent petroleum engineering firm acceptable to Agent, utilizing
economic pricing parameters used by .Agent as established from time to
time, together with such other information, reports and data concerning
the value of the Oil and Gas Properties as Agent shall deem reasonably
necessary to determine the value of such Oil and Gas Properties. Each
Lender shall determine the amount of the Borrowing Base attributable to
the Oil and Gas Properties based upon the loan collateral value which
such Lender in its discretion (using such methodology, assumptions and
discount rates as such Lender customarily uses in assigning collateral
value to oil and gas properties, oil and gas gathering systems, gas
processing and plant operations) assigns to such Oil and Gas Properties
at the time in question and based upon such other credit factors
consistently applied (including, without limitation, the assets,
liabilities, cash flows, business, properties, prospects, management
and ownership of Borrowers and their Affiliates) as such Lender
customarily considers in evaluating similar oil and gas credits.
Section 7. Amendment to Reporting Requirements. Sections 12(a)(i), (ii)
and (iii) of the Credit Agreement are hereby amended in their entirety to read
as follows:
(i) Annual Audited Financial Statements. As soon*as available,
and in any event within ninety (90) days after the end of each fiscal
year of PPC (x) the annual audited consolidated Financial Statements of
PPC, prepared in accordance with GAAP accompanied by an unqualified
opinion on such Financial Statements rendered by KPMG LLP or another
independent accounting firm reasonably acceptable to the Agent, and (y)
the annual unaudited consolidating Financial Statements of PPC prepared
in accordance with GAAP;
(ii) Quarterly Financial Statements. As soon as available, and
in any event within forty-five (45) days after the end of each fiscal
quarter of PPC, the quarterly unaudited consolidated and consolidating
Financial Statements of PPC prepared in accordance with GAAP;
(iii) Report on Properties. As soon as available and in any
event on or before March 1, 2004, and thereafter on or before March 1
and September 1 of each calendar year, and at such other times as any
Lender, in accordance with Section 7 hereof, may request, the
engineering reports required to be furnished to the Agent under such
Section 7 on the Oil and Gas Properties;
Section 8. Amendment to Crude Oil Hedging Covenant. Section 12(w) of
the Credit Agreement is hereby amended by adding at the end thereof the
following sentence:
(w) Crude Oil Hedging. Each of the foregoing hedging
requirements shall be based upon the then most current reserve
evaluation delivered by Borrowers to Agent pursuant to Section
12(a)(iii) above, and Borrowers shall be in compliance with the
required volumes to be
-2-
hedged within ninety (90) days after the effective date of each such
most current reserve evaluation.
Section 9. Deletion of Debt Service Coverage Ratio and Addition of new
Funded Debt Ratio. Section 13(c) of the Credit Agreement is hereby amended in
its entirety to read as follows:
(c) Funded Debt Ratio. PPC will not allow its ratio of
Consolidated Funded Debt to Consolidated EBITDA to exceed 3.00 to 1.00.
This ratio shall be calculated at the end of each fiscal quarter of PPC
beginning on September 30, 2003, using the results of the twelve-month
period immediately preceding the end of each such fiscal quarter.
Section 10. Amendment to Rate Management Transactions Covenant. Section
13(1) of the Credit Agreement is hereby amended in its entirety to read as
follows:
(1) Neither either Borrower nor Guarantor will, and will not
permit any Subsidiary to, enter into any Rate Management Transactions,
except the foregoing prohibitions shall not apply to (x) transactions
required by this Agreement or consented to in writing by the Majority
Lenders, in each case which are on terms acceptable to the Majority
Lenders, or (y) transactions by Borrowers designed to hedge, provide a
floor price for, or swap crude oil or natural gas, provided that (i)
the same do not cover more than seventy-five percent (75%) of
Borrowers' aggregate estimated production from proved producing
reserves existing as of the date of the execution thereof based upon
the then most current reserve evaluation required pursuant to Section
12(a)(iii) above, (ii) the same do not contain terms or provisions
which would require margin calls, (iii) the counterparty to any such
transaction has a minimum rating of "A-1" by Standard & Poors'
Corporation or "A-3" by Moody's Investors Service, Inc., (iv) the same
are for a term of twenty-four (24) months or less, and (v) the same
include provisions for payment to Borrowers upon the occurrence of
specified price indexes of a price per unit of measurement equal to or
greater than that under the Agent's then current pricing policies; or,
provided that (A) the same do not cover more than ninety percent (90%)
of Borrowers' aggregate estimated production from proved producing
reserves existing as of the date of the execution thereof based upon
the then most current reserve evaluation required pursuant to Section
12(a)(iii) above, (B) the same do not cover more than seventy-five
percent (75%) of Borrowers' aggregate estimated production from all
categories of proved reserves existing as of the date of the execution
thereof based upon the then most current reserve evaluation required
pursuant to Section 12(a)(iii) above, (C) as of the date of the
execution thereof, Borrowers' aggregate actual production from proved
producing reserves exceeds Borrowers' aggregate forecasted production
from proved producing reserves for such date based on the then most
current reserve evaluation required pursuant to Section 12(a)(iii)
above, (D) the same are for a term of twelve (12) months or less, and
(E) the same satisfy the requirements set forth in items (ii), (iii)
and (v) above.
Section 11. Amendment to Exhibit "D". Paragraph (d)(ii) of the
Certificate of Compliance attached to the Credit Agreement as Exhibit "D" is
hereby amended in its entirety to read as follows:
(ii) Funded Debt Ratio; and
Section 12. Redetermination of Borrowing Base. In accordance with Section
7(b) of the Credit Agreement, a semi-annual redetermination of the Borrowing
Base has been made by Lenders. Pursuant to Section 7(b) of the Credit Agreement,
Agent hereby notifies you that the Lenders have redetermined the Borrowing Base
and, effective as of the date of this First Amendment, the redetermined
Borrowing Base is $50,000,000.
Section 13. Global Amendment of Loan Documents. All of the Loan Documents
are hereby modified wherever necessary, and even though not specifically
addressed herein, so as to conform to the amendments to the Credit Agreement as
set forth herein, and the Borrowers and the Guarantor covenant to observe,
comply with and perform each of the terms and provisions of the Loan Documents
to which they are parties, as modified hereby. Each
-3-
Loan Document to which Borrowers or Guarantor is a party is hereby amended so
that any reference in each such Loan Document to the Credit Agreement shall mean
a reference to the Credit Agreement as amended hereby.
Section 14. Representations and Warranties of Borrowers and Guarantor.
Borrowers and Guarantor hereby jointly and severally represent and warrant to
Lenders as follows:
(a) The representations and warranties contained in Section 10
of the Credit Agreement are true and correct on and as of the date
hereof as though made on and as of the date hereof, except for those
representations and warranties which address matters only as of a
particular date (which remain true and correct as of such date).
(b) No Event of Default or Default has occurred and is
continuing under the Credit Agreement.
(c) The execution, delivery and performance by Borrowers and
Guarantor of this First Amendment are within the Borrowers' and
Guarantor's partnership, corporate and limited liability company
powers, have been duly authorized by all necessary action, require no
action by or in respect of, or filing with, any governmental body,
agency or official and do not violate or constitute a default under any
provisions of applicable law or any material agreement binding upon
Borrowers, Guarantor or their respective Subsidiaries or result in the
creation or imposition of any Lien upon any of the assets of Borrowers,
Guarantor or their respective Subsidiaries, except Permitted Liens.
(d) This First Amendment constitutes the valid and binding
obligation of Borrowers and Guarantor enforceable in accordance with
its terms except as (i) the enforceability thereof may be limited by
bankruptcy, insolvency or similar laws affecting creditor's rights
generally, and (ii) the availability of equitable remedies may be
limited by equitable principles of general application.
Section 15. Conditions Precedent. This First Amendment shall be
effective as of the date upon which all of the following conditions have been
satisfied:
(a) the Agent shall have received counterparts of this First
Amendment duly executed by Borrowers, Guarantor and Lenders;
(b) the Agent shall have received from Borrowers for the
ratable benefit of Lenders the fees required by Section 8(b) of the
Credit Agreement;
(c) the Borrowers and Guarantor shall have provided to Agent
(i) a copy of resolutions, in form and substance satisfactory to Agent,
of the Board of Directors of PPC authorizing the execution, delivery
and performance of this First Amendment and any other Loan Documents to
be executed or delivered pursuant hereby, certified by the secretary or
an assistant secretary of PPC, which certificate shall be in form and
substance satisfactory to Agent and Agent's counsel and shall state
that the resolutions thereby certified have not been amended, modified,
revoked or rescinded, (ii) a copy of the resolutions, in form and
substance satisfactory to Agent, duly adopted by the respective
partners of PLP authorizing the execution, delivery and performance of
this First Amendment and any other Loan Documents to be executed or
delivered by PLP pursuant hereto, certified by PLP's general partner,
which certificate shall be in form and substance satisfactory to Agent
and Agent's counsel and shall state that the resolutions thereby
certified have not been amended, modified, revoked or rescinded, and
(iii) resolutions, in form and substance satisfactory to Agent, of the
members of Guarantor authorizing the execution, delivery and
performance of this First Amendment and any other Loan Documents to be
executed or delivered pursuant hereto, certified by its secretary or
assistant secretary, which certificate shall be in form and substance
satisfactory to Agent and Agent's counsel and shall state that the
resolutions thereby certified have not been amended, modified, revoked
or rescinded; and
(d) Agent shall have received any other documents,
certificates and opinions in connection
-4-
with this First Amendment that may be requested by Agent, in form and
substance satisfactory to Agent.
Section 16. Ratification of Credit Agreement and Other Loan Documents.
Except as expressly amended hereby, the Credit Agreement and all of the other
Loan Documents are and shall be unchanged and all of the terms, provisions,
covenants, conditions, schedules and exhibits thereof shall remain and continue
in full force and effect and are hereby ratified and confirmed by Borrowers,
Guarantor and Lenders as of the date of this First Amendment as if the Credit
Agreement and the other Loan Documents were executed by Borrowers, Guarantor and
the other parties thereto as of the date of this First Amendment. The amendments
contemplated hereby shall not limit or impair any Liens securing the Loans, each
of which are hereby ratified, affirmed and extended to secure the Loans as they
may be increased pursuant hereto.
Section 17. No Waiver. Neither the execution by Lenders of this First
Amendment nor anything contained herein shall in anywise be construed or operate
as a waiver by Lenders of any Default of Event of Default (whether now existing
or that may occur hereafter) or of any of Lenders' or Agent's rights under the
Credit Agreement as amended hereby or under any of the other Loan Documents.
Section 18. Miscellaneous.
18.1 Legal Expenses. The Borrowers hereby agree to pay on
demand all reasonable fees and expenses of counsel to the Agent
incurred by the Agent in connection with the preparation, negotiation
and execution of this First Amendment and all related documents.
18.2 Multiple Counterparts. Multiple counterparts of this
First Amendment may be signed by the parties hereto (including by
facsimile transmission), each of which shall be an original but all of
which together shall constitute but one and the same instrument.
18.3 Reference to Agreement. Each of the Loan Documents is
hereby amended so that any reference in the Loan Documents to the
Credit Agreement shall mean a reference to the Credit Agreement as
amended hereby.
18.4 Governing Law. This First Amendment is being executed and
delivered, and is intended to be performed, in Midland, Midland County,
Texas, and the substantive laws of Texas shall govern the validity,
construction, enforcement and interpretation of this First Amendment
and all other documents and instruments referred to herein, unless
otherwise specified therein.
18.5 Plural and Singular Forms. The definitions given to terms
defined hereby shall be equally applicable to both the singular and
plural forms of such terms.
18.6 Final Agreement. THIS FIRST AMENDMENT, THE CREDIT
AGREEMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT
BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR,
CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE
NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.
IN WITNESS THEREOF, Borrowers, Guarantor and Lenders have caused this
First Amendment to be duly executed as of the day and year first above written.
BORROWERS: PARALLEL PETROLEUM CORPORATION,
a Delaware corporation
By: /s/ Larry C. Oldham
-------------------------------
Larry C. Oldham, President
-5-
PARALLEL, L.P., a Texas limited
partnership
By: Parallel Petroleum Corporation,
Its General Partner
By: /s/ Larry C. Oldham
---------------------------
Larry C. Oldham, President
GUARANTOR: PARALLEL, L.L.C., a Delaware
limited liability company
By: /s/ David R. Hancock
---------------------------
David R. Hancock, President
LENDERS: FIRST AMERICAN BANK, SSB, a state
savings bank, as Joint Lead
Arranger and Administrative
Agent and as a Lender
By: /s/ Frank K. Stowers
---------------------------
Frank K. Stowers
Senior Vice President
BNP PARIBAS, as Joint Lead
Arranger and Syndication Agent
and as a Lender
By: /s/ Brian M. Malone
---------------------------
Brian M. Malone
Managing Director
By: /s/ Polly Schott
---------------------------
Polly Schott
Vice President
WESTERN NATIONAL BANK,
as a Lender
By: /s/ Wesley D. Bownds
---------------------------
Wesley D. Bownds
Executive Vice President
-6-
Exhibit 31.1
CERTIFICATION
I, Thomas R. Cambridge, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Parallel Petroleum
Corporation:
2. Based on my knowledge, this report does not contain any untrue statement of
a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this report.
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused
such disclosure controls and procedures to be designed under
our supervision, to ensure that material information relating
to the registrant, including its consolidated subsidiaries, is
made known to us by others within those entities, particularly
during the period in which this report is being prepared;
(b) Evaluated the effectiveness of the registrant's disclosure
controls and procedures and presented in this report our
conclusions about the effectiveness of the disclosure controls
and procedures, as of the end of the period covered by this
report based on such evaluation; and
(c) Disclosed in this report any change in the registrant's
internal control over financial reporting that occurred during
the registrant's most recent fiscal quarter that has
materially affected, or is reasonably likely to materially
affect, the registrant's internal control over financial
reporting; and
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation of internal control over financial reporting, to
the registrant's auditors and the audit committee of the registrant's board
of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the
design or operation of internal control over financial
reporting which are reasonably likely to adversely affect the
registrant's ability to record, process, summarize and report
financial information; and
(b) Any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal control over financial reporting.
Date: October 30, 2003 /s/ Thomas R. Cambridge
-----------------------------
Thomas R. Cambridge
Chief Executive Officer
Exhibit 31.2
CERTIFICATION
I, Steven D. Foster, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Parallel Petroleum
Corporation:
2. Based on my knowledge, this report does not contain any untrue statement of
a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this report.
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused
such disclosure controls and procedures to be designed under
our supervision, to ensure that material information relating
to the registrant, including its consolidated subsidiaries, is
made known to us by others within those entities, particularly
during the period in which this report is being prepared;
(b) Evaluated the effectiveness of the registrant's disclosure
controls and procedures and presented in this report our
conclusions about the effectiveness of the disclosure controls
and procedures, as of the end of the period covered by this
report based on such evaluation; and
(c) Disclosed in this report any change in the registrant's
internal control over financial reporting that occurred during
the registrant's most recent fiscal quarter that has
materially affected, or is reasonably likely to materially
affect, the registrant's internal control over financial
reporting; and
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation of internal control over financial reporting, to
the registrant's auditors and the audit committee of the registrant's board
of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the
design or operation of internal control over financial
reporting which are reasonably likely to adversely affect the
registrant's ability to record, process, summarize and report
financial information; and
(b) Any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal control over financial reporting.
Date: October 30, 2003 /s/ Steven D. Foster
-----------------------------
Steven D. Foster
Chief Financial Officer
Exhibit 32.1
CERTIFICATION
(Not filed pursuant to the Securities Exchange Act of 1934)
Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906
of the Sarbanes - Oxley Act of 2002, the undersigned, Thomas R. Cambridge, the
Chairman of the Board of Directors and Chief Executive Officer of Parallel
Petroleum Corporation ("Parallel"), hereby certifies that the Quarterly Report
on Form 10-Q of Parallel for the quarter ended September 30, 2003 fully complies
with the periodic reporting requirements of the Securities Exchange Act of 1934,
as amended, and the information contained in that Form 10-Q Report fairly
presents, in all material respects, the financial condition and results of
operations of Parallel.
Dated: October 30, 2003
/s/ Thomas R. Cambridge
-------------------------------
Thomas R. Cambridge, Chairman
of the Board of Directors and Chief
Executive Officer
A signed original of this written statement required by Section 906 has been
provided to Parallel Petroleum Corporation and will be retained by Parallel
Petroleum Corporation and furnished to the Securities Exchange Commission or its
staff upon request.
Exhibit 32.2
CERTIFICATION
(Not filed pursuant to the Securities Exchange Act of 1934)
Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906
of the Sarbanes - Oxley Act of 2002, the undersigned, Steven D. Foster, the
Chief Financial Officer of Parallel Petroleum Corporation ("Parallel"), hereby
certifies that the Quarterly Report on Form 10-Q of Parallel for the quarter
ended September 30, 2003 fully complies with the periodic reporting requirements
of the Securities Exchange Act of 1934, as amended, and the information
contained in that Form 10-Q Report fairly presents, in all material respects,
the financial condition and results of operations of Parallel.
Dated: October 30, 2003
/s/ Steven D. Foster
---------------------------------
Steven D. Foster,
Chief Financial Officer
A signed original of this written statement required by Section 906 has been
provided to Parallel Petroleum Corporation and will be retained by Parallel
Petroleum Corporation and furnished to the Securities Exchange Commission or its
staff upon request.