UNITED STATES
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 June 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
incorporation or organization) Identification 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 August 5, 2003, 21,150,406 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 June 30, 2003 (unaudited) 3
- Unaudited Consolidated Statements of Operations for
the three months and six months ended June 30, 2002
and 2003 4
- Unaudited Consolidated Statements of Cash Flows for
the six months ended June 30, 2002 and 2003 5
- Unaudited Consolidated Statements of Comprehensive
Income for the three months and six months ended
June 30, 2002 and 2003 6
- Notes to Consolidated Financial Statements 7
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS 15
ITEM QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK 23
ITEM 4. CONTROLS AND PROCEDURES 23
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS 24
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 24
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K 25
SIGNATURES 29
-2-
ITEM 1. FINANCIAL STATEMENTS
PARALLEL PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
(audited) (unaudited)
December 31, June 30,
ASSETS 2002 2003
------------ ------------
Current assets:
Cash and cash equivalents $ 11,811,704 $ 5,960,401
Accounts receivable:
Oil and gas 3,071,315 4,680,644
Others, net of allowance for doubtful account of $12,681 in 2002 and 2003 236,443 355,485
Affiliate 2,084 1,943
------------ ------------
3,309,842 5,038,072
Income tax receivable 832,590 832,590
Other assets 78,675 189,557
Fair value of derivative instruments 21,884 484
------------ ------------
Total current assets 16,054,695 12,021,104
------------ ------------
Property and equipment, at cost:
Oil and gas properties, full cost method (Note 5) 146,679,503 155,121,203
Other 1,083,282 1,375,378
------------ ------------
147,762,785 156,496,581
Less accumulated depreciation and depletion (62,074,559) (65,735,214)
------------ ------------
Net property and equipment (Note 8) 85,688,226 90,761,367
------------ ------------
Other assets, net of accumulated amortization of $78,520 in 2002 and $88,439 in 2003 608,410 688,552
------------ ------------
$102,351,331 $103,471,023
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities $ 3,033,650 $ 3,219,709
Current maturities of long-term debt (Note 2) 4,145,833 7,837,500
Current maturity of derivative obligations 335,829 1,840,035
------------ ------------
7,515,312 12,897,244
------------ ------------
Long-term debt, excluding current maturities (Note 2) 45,604,167 34,912,500
Long-term asset retirement obligation (Note 8) - 1,777,077
Long-term maturity of derivative obligations (Note 6) 103,745 1,603,562
Deferred tax liability 3,627,963 4,181,501
Stockholders' equity:
Series A preferred stock -- par value $.10 per share (aggregate liquidation
preference of $26)
authorized 50,000 shares - -
Preferred stock -- $.60 cumulative convertible preferred
stock -- par value of $.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 21,150,406 in 2003 211,434 211,504
Additional paid-in capital 34,567,866 34,288,137
Retained earnings 10,623,394 15,546,238
Other comprehensive income (loss) net of tax (Note 6) - (2,044,190)
------------ ------------
Total stockholders' equity 45,500,144 48,099,139
Commitments and contingencies (Note 10)
------------ ------------
$102,351,331 $103,471,023
============ ============
*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.
-3-
PARALLEL PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended June 30, Six Months Ended June 30,
------------------------------ ----------------------------
2002 2003 2002 2003
------------ ------------ ----------- ------------
Oil and gas revenues $ 2,808,807 $ 8,531,974 $ 4,779,998 $ 17,024,766
------------ ------------ ------------ ------------
Cost and expenses:
Lease operating expense (Note 8) 721,614 2,185,196 1,270,990 3,640,856
General and administrative, includes $1,471,000
for incentive awards in 2002 1,974,686 968,154 2,324,450 1,769,922
Depreciation, depletion and amortization 1,333,166 1,989,194 2,687,796 4,054,885
------------ ------------ ------------ ------------
Total costs and expenses 4,029,466 5,142,544 6,283,236 9,465,663
------------ ------------ ------------ ------------
Operating income (loss) (1,220,659) 3,389,430 (1,503,238) 7,559,103
------------ ------------ ------------ ------------
Other income (expense), net:
Equity in income of First Permian, L.P., includes a
$31,082,041 gain on sale of substantially all net assets 31,082,041 - 30,765,748 -
Change in fair market value of derivatives (Note 6) (54,974) 274,291 (394,832) 71,834
Interest and other income 21,066 1,336 37,441 45,992
Dividend income 163,378 - 163,378 -
Interest expense (158,207) (521,891) (311,264) (1,008,355)
Other expense (107,582) (25,466) (279,648) (46,010)
------------ ------------ ------------ ------------
Total other income (expense), net 30,945,722 (271,730) 29,980,823 (936,539)
------------ ------------ ------------ ------------
Income before income taxes 29,725,063 3,117,700 28,477,585 6,622,564
Income tax (expense), net (10,063,560) (446,610) (9,584,833) (1,638,264)
------------ ------------ ------------ ------------
Net income before cumulative effect of change in accounting principle 19,661,503 2,671,090 18,892,752 4,984,300
Cumulative effect on prior years of a change in accounting principle,
lessapplicable income taxes of $31,659 (Note 8) - - - (61,456)
------------ ------------ ------------ ------------
Net income 19,661,503 2,671,090 18,892,752 4,922,844
Cumulative preferred stock dividend (146,175) (146,175) (292,350) (292,350)
------------ ------------ ------------ ------------
Net income available to common stockholders $ 19,515,328 $ 2,524,915 $ 18,600,402 $ 4,630,494
============ ============ ============ ============
Net income per common share:
Basic - before cumulative effect of a change in accounting principal $ 0.94 $ 0.12 $ 0.90 $ 0.22
Cumulative effect of a change in accounting principle, net of tax - - - -
------------ ------------ ------------ ------------
Basic - after cumulative effect of a change in acocounting principle $ 0.94 $ 0.12 $ 0.90 $ 0.22
============ ============ ============ ============
Diluted - before cumulative effect of a change in accounting principle $ 0.84 $ 0.11 $ 0.80 $ 0.20
Cumulative effect of a change in accounting principle, net of tax - - - -
------------ ------------ ------------ ------------
Diluted - after cumulative effect of a change in accounting principle $ 0.84 $ 0.11 $ 0.80 $ 0.20
============ ============ ============ ============
Weighted average common share outstanding:
Basic 20,663,861 21,144,650 20,663,861 21,144,028
============ ============ ============ ============
Diluted 23,541,120 24,078,413 23,571,736 24,051,398
============ ============ ============ ============
The accompanying notes are an integral part of these financials.
-4-
PARALLEL PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended June 30,
-----------------------------------
2002 2003
---------------- -----------------
Cash flows from operating activities:
Net income $ 18,892,752 $ 4,922,844
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and depletion 2,687,796 4,054,885
Accretion expense - 68,361
Equity in income of First Permian, L.P. net of
cash distributions of $5,501,703 (25,264,046) -
Change in fair value of derivative instruments 394,832 (71,834)
Deferred income taxes 9,584,833 1,638,264
Cumulative effect on prior years of a change in accounting principle, net of tax - 61,456
Changes in assets and liabilities:
Other, net 24,424 (80,142)
Increase in accounts receivables (155,393) (1,728,230)
Increase in prepaid expenses and other assets (662,252) (110,882)
(Decrease) Increase in accounts payable and accrued liabilities (840,703) 186,059
Accrued bonus payable 1,201,172 -
Purchase of derivative instruments (530,605) -
------------ ------------
Net cash provided by operating activities 5,332,810 8,940,781
------------ ------------
Cash flows from investing activities:
Additions to property and equipment (6,781,897) (7,532,825)
Proceeds from disposition of property and equipment 572,799 20,400
------------ ------------
Net cash used in investing activities (6,209,098) (7,512,425)
------------ ------------
Cash flows from financing activities:
Borrowings from bank line of credit 865,589 3,173,625
Payments on bank line of credit (715,589) (10,173,625)
Proceeds from exercise of stock options - 12,691
Payment of preferred stock dividend (292,350) (292,350)
------------ ------------
Net cash used in financing activities (142,350) (7,279,659)
------------ ------------
Net decrease in cash and cash equivalents (1,018,638) (5,851,303)
Beginning cash and cash equivalents 3,351,044 11,811,704
------------ ------------
Ending cash and cash equivalents $ 2,332,406 $ 5,960,401
============ ============
Non-cash financing and investing activities:
Non-cash proceeds from sale of investment $ (25,580,339) $ -
Unrealized gain on investment in securities $ (93,359) $ -
Accrued asset retirement obligation related to oil and gas properties $ - $ 1,221,371
Accrued preferred stock dividend $ 24,363 $ 24,363
The accompany notes are an integral part of these financials.
-5-
PARALLEL PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(unaudited)
THREE MONTHS ENDED JUNE 30, SIX MONTHS ENDED JUNE 30,
--------------------------------- -----------------------------
2002 2003 2002 2003
------------- ------------- -------------- -------------
Net income $ 19,661,503 $ 2,671,090 $ 18,892,752 $ 4,922,844
Oil, natural gas and interest rate derivatives
adjustments, net of tax - (821,997) - (2,044,190)
------------ ----------- ------------ -----------
Comprehensive income, net of tax $ 19,661,503 $ 1,849,093 $ 18,892,752 $ 2,878,654
============ =========== ============ ===========
The accompanying notes are an integral part of these financials.
-6-
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.
We account 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. The following
pro forma information, as required by Statement of Financial Accounting
Standards No. 123 "Accounting for Stock-Based Compensation" (SFAS 123") as
amended by Statement of Financial Accounting Standards No. 148 ("SFAS 148"),
presents net income and earnings per share information as if the stock options
issued since May 2, 2002 were accounted for using the fair value method. The
fair value of stock options issued for each year was estimated at the date of
grant using the Black-Scholes option pricing model. A total of 180,000 options
were granted during quarter ending June 30, 2003.
The SFAS 123 pro forma information for the three months and six months
ended June 30, 2002 and 2003 is as follows:
Three Months Ended Six Months Ended
June 30, June 30,
------------------------------- --------------------------------
2002 2003 2002 2003
---------------- -------------- ---------------- ---------------
Net income (loss), as reported $ 19,661,503 $ 2,671,090 $ 18,892,752 $ 4,922,844
Add: Stock-based employee compensation expense
included in net income (loss), net of tax - - - -
Deduct: Stock-based employee compensation expense
determined under fair value based method (SFAS 123),
net of tax (339,567) (61,754) (716,267) (109,412)
------------ ------------ ------------ ------------
Net income (loss), pro forma $ 19,321,936 $ 2,609,336 $ 18,176,485 $ 4,813,432
============ ============ ============ ============
Basic:
Net income (loss) per common share, as reported $ 0.94 $ 0.12 $ 0.90 $ 0.22
============ ============ ============ ============
Net income (loss) per common share, pro forma $ 0.92 $ 0.11 $ 0.86 $ 0.21
============ ============ ============ ============
Diluted:
Net income (loss) per common share, as reported $ 0.84 $ 0.11 $ 0.80 $ 0.20
============ ============ ============ ============
Net income (loss) per common share, pro forma $ 0.82 $ 0.10 $ 0.77 $ 0.20
============ ============ ============ ============
-7-
NOTE 2. LONG TERM DEBT
Long-term debt consists of the following at June 30, 2003:
Revolving Facility note payable to bank, at bank's base lending rate
(4.5% at June 30, 2003)
$42,750,000
Less: current maturities 7,837,500
-----------
$34,912,500
===========
Scheduled maturities of long-term debt at June 30, 2003 are as follows:
2003 $ 3,562,500
2004 8,550,000
2005 8,550,000
2006 8,550,000
2007 8,550,000
2008 4,987,500
-----------
$42,750,000
===========
Revolving Credit Facility. Under our revolving credit facility, we may
borrow the lesser of $100,000,000 or the "borrowing base" then in effect. The
borrowing base at June 30, 2003, was $45,000,000, which is secured by
substantially all of our oil and gas reserves. The total outstanding principal
amount of our bank indebtedness at June 30, 2003 was $42,750,000, excluding
$250,000 reserved for our letters of credit, leaving an availability of
$2,000,000 on our borrowing base. The borrowing base is subject to
redetermination semi-annually, on or about May 1 and November 1 of each year.
The bank may also require a redetermination of the borrowing base and monthly
commitment reduction at any time in its sole discretion. Monthly commitment
reductions begin August 31, 2003 in an amount equal to the amount of the
borrowing base on the day immediately preceeding the date of each such monthly
commitment reduction divided by the number of months then remaining prior to
July 31, 2008. All indebtedness under the revolving facility 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.
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:
-8-
o maintaining certain financial requirements;
o limitation on additional indebtedness;
o prohibiting the payment of dividends on our common stock;
o limitations on the disposition of assets;
o prohibiting liens (other than in favor of the bank) to exist on
any of our properties;
o limitations on investments, mergers, forming subsidiaries,
affiliate transactions, changes in accounting methods, rental and
lease payments and derivative transactions
o limitations on the purchase, redemption or retirement of stock;
and
o limitations on hedging activities.
NOTE 3. 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 4. INCOME TAX LIABILITY
For the six months ended June 30, 2003, we recorded income tax expense
of $1,638,264 resulting in a net deferred tax liability of $4,181,501. Our
income tax expense was largely due to generating taxable income in the current
period. Our effective tax rate for the six months ended June 30, 2003 was 25%,
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 5. 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. 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 June 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.
-9-
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 six month period
ended June 30, 2003 overhead costs capitalized were $430,780.
NOTE 6. DERIVATIVE INSTRUMENTS
General
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 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 six months ended June 30, 2003, there
was no ineffective portion of our natural gas and interest rate hedges. For the
six months ended June 30, 2003, we recorded a cumulative charge of $103,473 to
other income (expense) for the ineffective portion of the crude oil hedges.
For the six months ended June 30, 2003, $251,017 was transferred from
comprehensive income (loss) and charged to earnings along with the expiration of
the associated hedge contracts. During the twelve month period ended June 30,
2004, we expect approximately $1,023,647 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 June 30, 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%.
10
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%.
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 $21,400 was recognized for
the six months ended June 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 June 30, 2003
------------------------------- ------------ --------------- --------- --------------- ---------------
April 2003 thru October 2003 natural gas 700,000 $ 3.00 $ 139,500 $ 484
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 January and June, 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 302,000 $ 5.70 $ 6.80
11
Subsequent to June 30, 2003, we added additional Houston Ship Channel
costless collars for November 1, 2003 through March 31, 2004 on 151,000 MMbtu
of gas with a floor of $4.90 and a cap of $6.15.
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.
In January and February, 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 275,000 $ 24.58 - $ -
January 1,2004 thru December 31, 2004 329,400 $ 23.19 - $ -
January 1,2005 thru December 31, 2005 292,000 $ 22.77 - $ -
January 1, 2006 thru December 20, 2006 265,500 $ 23.04 - $ -
Subsequent to June 30, 2003, we added additional Nymex oil swaps for
October 1, 2003 through December 31, 2003 on 18,400 Bbls for $30.27 per Bbl and
for January 1, 2004 through March 31, 2004 on 18,200 Bbls for $28.51 per Bbl.
12
NOTE 7. 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 Six Months Ended
June 30, June 30,
------------------------------- -----------------------------
2002 2003 2002 2003
--------------- --------------- ------------- ---------------
Basic EPS Computation:
Numerator-
Net income before cumulative effect of a change
in accounting principle $19,661,503 $ 2,671,090 $18,892,752 $ 4,984,300
Cumulative effect of a change in accounting principle,
net of tax - - - (61,456)
----------- ----------- ----------- -----------
19,661,503 2,671,090 18,892,752 4,922,844
Preferred stock dividend (146,175) (146,175) (292,350) (292,350)
----------- ----------- ----------- -----------
Net income available to common stockholders $19,515,328 $ 2,524,915 $18,600,402 $ 4,630,494
=========== =========== =========== ===========
Denominator-
Weighted average common shares outstanding 20,663,861 21,144,650 20,663,861 21,144,028
=========== =========== =========== ===========
Basic EPS:
Net income before cumulative effect of a change $ 0.94 $ 0.12 $ 0.90 $ 0.22
in accounting principle
Cumulative effect of a change in accounting principle,
net of tax - - - -
----------- ----------- ----------- -----------
Net income $ 0.94 $ 0.12 $ 0.90 $ 0.22
=========== =========== =========== ===========
iluted EPS Computation:
Numerator-
Net income before cumulative effect of a change $19,661,503 $ 2,671,090 $18,892,752 $ 4,984,300
in accounting principle
Cumulative effect of a change in accounting principle,
net of tax - - - (61,456)
----------- ----------- ----------- -----------
19,661,503 2,671,090 18,892,752 4,922,844
Preferred stock dividend - - - -
----------- ----------- ----------- -----------
Net income available to common stockholders $19,661,503 $ 2,671,090 $18,892,752 $ 4,922,844
=========== =========== =========== ===========
Weighted average common shares outstanding 20,663,861 21,144,650 20,663,861 21,144,028
Employee stock options 93,015 149,519 123,631 123,126
Preferred stock 2,784,244 2,784,244 2,784,244 2,784,244
----------- ----------- ----------- -----------
Weighted average common shares for diluted earnings
per share assuming conversion 23,541,120 24,078,413 23,571,736 24,051,398
=========== =========== =========== ===========
Diluted EPS:
Net income before cumulative effect of a change $ 0.84 $ 0.11 $ 0.79 $ 0.20
in accounting principle
Cumulative effect of a change in accounting principle,
net of tax - - - -
----------- ----------- ----------- -----------
Net income $ 0.84 $ 0.11 $ 0.79 $ 0.20
=========== =========== =========== ===========
13
NOTE 8: 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 June 30, 2003 we recorded additional oil and gas
property costs, net of disposals, of $1,221,371, 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
$34,526 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 six months ended June 30, 2003.
Three Months Ended Six Months Ended
June 30, 2003 June 30, 2003
------------------------- -------------------------
Beginning asset retirement obligation $ 1,727,165 $ 1,693,330
Additions related to new properties 16,074 16,074
Deletions related to property disposals (688) (688)
Accretion expense 34,526 68,361
------------------------- -------------------------
Ending asset retirement obligation $ 1,777,077 $ 1,777,077
========================= =========================
Prior years pro forma were not shown since the change was not
significant.
NOTE 9: 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. The statement 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.
We currently account for stock-based compensation in accordance with APB
Opinion No. 25 which requires us to recognize compensation expense only to the
extent that the fair market value is greater than the option price at the date
of grant.
14
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 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. We do not expect the
adoption of FAS 150 to have a material impact on our consolidated financial
statements.
NOTE 10.COMMITMENTS AND CONTINGENCIES
At June 30, 2003, we were involved in one lawsuit incidental to our
business. In the opinion of management, the ultimate outcome of this lawsuit
will not 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.
15
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:
o focuses on projects having less geological risk;
o entails less exploratory activity in the down dip Wilcox trend
of our south Texas properties;
o emphasizes exploitation and enhancement activities;
o focuses on acquiring producing properties; and
o 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:
o the prices we receive for the oil and gas we produce;
o the results of reprocessing and reinterpreting our 3-D seismic
data;
o the results of our drilling activities;
o the costs of obtaining high quality field services;
o our ability to find and consummate acquisition opportunities;
and
o 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, hurricane conditions in the
Gulf of Mexico, and availability of pipeline transportation to end users and
proximity of our wells to major transportation pipeline infrastructure 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
16
included:
o cash flow from operations,
o sales of our equity securities,
o bank borrowings, and
o industry joint ventures
For the three months ended June 30, 2003, the sales price we received
for our crude oil production (excluding hedges) averaged $26.09 per barrel
compared with $22.29 per barrel for the three months ended June 30, 2002. The
average sales price we received for natural gas for the three months ended June
30, 2003 (excluding hedges), was $6.10 per mcf compared with $3.39 per mcf for
the three months ended June 30, 2002. Our hedged sales price that we received
for the three months ended June 30, 2003, averaged $24.00 per barrel for crude
oil and $5.84 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 5 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:
o sources of production;
o product mix (oil vs. gas volumes); and
o the prices we receive for our oil and gas production.
17
Year-to-year or other periodic comparisons of the results of our
operations can be difficult and may not accurately describe our condition. A BOE
means one barrel of oil equivalent using the ratio of six Mcf of gas to one
barrel of oil.
Three Months Ended Six Months Ended
----------------------------- ---------------------------
6/30/2002 6/30/2003 6/30/2002 6/30/2003
-------------- -------------- ------------ --------------
Sales Volume:
Oil (Bbls) 33,126 159,739 63,287 313,317
Natural gas (Mcf) 609,812 805,137 1,200,462 1,586,888
Equivalent barrels of oil (BOE) 134,761 293,929 263,364 577,798
Equivalent barrels of oil (BOE) per day 1,497 3,266 1,463 3,210
Prices:
Bbls (unhedged) $ 22.29 $ 26.09 $ 21.77 $ 29.28
Bbls (hedged) $ 24.00 $ - $ 27.82
Mcf (unhedged) $ 3.39 $ 6.10 $ 2.83 $ 5.96
Mcf (hedged) $ 5.84 $ - $ 5.24
BOE (unhedged) $ 20.84 $ 30.89 $ 18.15 $ 32.25
BOE (hedged) $ 29.03 $ - $ 29.46
CRITICAL ACCOUNTING POLICIES AND PRACTICES
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
18
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.
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 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 market-to-market 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.
RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED JUNE 30, 2003 AND 2002:
Oil and Gas Revenues. Oil and gas revenues increased $5,723,167 or 204%,
to $8,531,974 for the three months ended June 30, 2003, from $2,808,807 for the
same period of 2002. The increase was primarily the result of a 118% increase in
oil and gas production due to the Fullerton acquisition on December 20, 2002 and
increased production at Cook Mountain and a 39% increase in the average sales
price per BOE including hedges.
Lease Operating Costs. Lease operating costs increased $1,463,582, or
203%, to $2,185,196 during the three months ended June 30, 2003, compared with
$721,614 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 three months
ended June 30, 2002 of approximately $1,471,000 related to the First Permian,
L.P. divestiture) increased by $464,468, or 92%, to $968,154 for the three
months ended June 30, 2003 from $503,686 for the same period of 2002. The
increase was primarily due to costs associated with additional personnel hired
to implement our new business plan.
Depreciation, Depletion and Amortization Expense. Depreciation,
depletion and amortization expense increased by $656,028, or 49%, to $1,989,194
for the three months ended June 30, 2003 compared with $1,333,166 for the same
period of 2002 primarily because of a 118% increase in production volumes.
19
Interest Expense. Interest expense increased $363,684, or 230%, to
$521,891 for the three months ended June 30, 2003 compared with $158,207 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.
Interest and Other Income. Interest and other income decreased $19,730,
or 94% to $1,336 for the three month period ended June 30, 2003 compared to
$21,066 for the same period of 2002 due to decreased other miscellaneous income.
Income Tax Expense. For the three months ended June 30, 2003, we
recorded a tax expense of $446,610. During the second quarter we recognized
state income tax, net operating loss carryover and certain federal income tax
credits not previously recognized. For further discussion see Note 4.
Net Income. We reported net income of $2,671,090 for the three months
ended June 30, 2003 compared with net income of $19,661,503 for the three months
ended June 30, 2002. The decrease of $16,990,413 or 86% resulted from the gain
on sale of First Permian, L.P. and dividend income from the Energen stock,
partially offset by accrued incentive award payments to employees reported
during the three months ended June 30, 2002 and increased oil and gas revenues
for the three months ended June 30, 2003.
RESULTS OF OPERATIONS FOR THE SIX MONTHS ENDED JUNE 30, 2003 AND 2002:
Oil and Gas Revenues. Oil and gas revenues increased $12,244,768, or
256%, to $17,024,766 for the six months ended June 30, 2003, from $4,779,998 for
the same period of 2002. The increase was primarily the result of a 119%
increase in oil and gas production due to the Fullerton acquisition on December
20, 2002, increased production at Cook Mountain and a 62% increase in the
average sales price per BOE including hedges.
Lease Operating Costs. Lease operating costs increased $2,369,866 or
186%, to $3,640,856 during the first six months of 2003, compared with
$1,270,990 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 six months
ended June 30, 2002 of approximately $1,471,000 related to the First Permian,
L.P. divestiture) increased by $916,472 or 107%, to $1,769,922 for the six
months ended June 30, 2003 from $853,450 for the same period of 2002. The
increase was primarily due to costs associated with additional personnel hired
to implement the business plan.
Depreciation, Depletion and Amortization Expense. Depreciation,
depletion and amortization expense increased by $1,367,089, or 51%, to
$4,054,885 for the first six months of 2003 compared with $2,687,796 for the
same period of 2002, primarily because of a 119% increase in production volumes.
Interest Expense. Interest expense increased $697,091 or 224%, to
$1,008,355 for the six months ended June 30, 2003 compared with $311,264 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.
Interest and Other Income. Interest and other income increased $8,551,
or 23% to $45,992 for the six month period ended June 30, 2003 compared to
$37,441 for the same period of 2002 due to increased cash balances associated
with increased cash flow.
20
Income Tax Expense. For the six months ended June 30, 2003 we recorded a
tax expense of $1,638,264. Our effective tax rate for the six months ended June
30, 2003 was 25%, 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. For further discussion see
Note 4.
Net Income. We reported net income of $4,922,844 for the six months
ended June 30, 2003 compared to $18,892,752 for the six months ended June 30,
2002. The decrease of $13,969,908 or 74% resulted from the gain on sale of First
Permian, L.P., dividend income from the Energen stock, partially offset by
accrued incentive award payments to employees reported during the three months
ended June 30, 2002.
Cash flow from operations for the six months ended June 30, 2003
increased $3,607,971 or 68% to $8,940,781 compared with a net cash flow from
operations of $5,332,810 for the six months ended June 30, 2002.
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 $9,415,523 as of June 30, 2003 compared with
December 31, 2002. Current liabilities exceeded current assets by $876,140 at
June 30, 2003 compared with current assets exceeding current liabilities by
$8,539,383 at December 31, 2002. Working capital decreased primarily due to the
payment of $7,000,000 on our bank debt requirements, current derivative
obligations, increased receivables and current maturities of long-term debt.
We incurred net property costs of $7,512,425 for the six months ended
June 30, 2003, primarily for our oil and gas property acquisition, development,
and enhancement activities. Also added to our property basis were asset
retirement costs of $1,221,371 for the adoption of SFAS 143 (see Note 8). The
property 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, interest expense and principal reduction
payments on bank debt, if required, and preferred stock dividends. We
continually review and consider alternative methods of financing.
The following table is a summary of significant contractual cash
obligations:
Obligation Due in Period
-------------------------------------------------------------------------
Contractual Cash Obligations 2003 2004 2005 2006 2007 2008 Total
------------------------------------------------ ---------- --------- --------- ---------- --------- --------- ----------
(000)
Revolving Credit Facility (Secured) $ 3,563 $ 8,550 $ 8,550 $ 8,550 $ 8,550 $ 4,987 $ 42,750
Office Lease (Dinero Plaza) $ 102 $ 102 $ 102 $ 68 $ - $ - $ 374
As of May 31, 2003 we found a tenant for our former office space and our
lease agreement was terminated.
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 6 Derivative Instruments.
21
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 sales price for our oil was
approximately $24.59 per barrel while the average sales prices we received for
natural gas was approximately $3.33 per thousand cubic feet ("Mcf"). For the six
months ended June 30, 2003, the average price for our oil production was
approximately $29.28 (unhedged) per Bbl, while the average price received at
that same date for our natural gas production was approximately $5.96 per Mcf
(unhedged).
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:
o those relating to the results of exploratory drilling activity,
o changes in oil and natural gas prices,
o operating risks,
o availability of drilling equipment,
o outstanding indebtedness,
o changes in interest rates,
o dependence on weather conditions,
o seasonality,
o expansion and other activities of competitors,
o changes in federal or state environmental laws and the administration
of such laws,
o the general condition of the economy and effect on the .
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.
22
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET 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.
July July July July July July
2003 2004 2005 2006 2007 2008 Total
------------- ------------ ------------ ------------ ------------ -------------- -------------
(In 000's, except interest rates)
Variable rate debt:
Revolving facility (secured) $ 3,563 $ 8,550 $ 8,550 $ 8,550 $ 8,550 $ 4,987 $ 42,750
Average interest rate (unhedged) 4.50% 4.50% 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 June 30, 2003, we had bank loans in the amount of $42,750,000
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 $107,753 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 6.
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 $14.26 per barrel to a
high of $29.57 per barrel during 2002. Natural gas prices we received during
2002 ranged from a low of $1.05 per Mcf to a high of $4.94 per Mcf. During 2003
oil prices ranged from a low of $22.78 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. For the remainder of
fiscal 2003 hedged oil and natural gas volumes represent approximately 56% and
54% respectively of expected production from July thru December 2003. See Note
6.
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
23
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, 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 occured 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 June 30, 2003, we were involved in one lawsuit incidental to our
business. In the opinion of management, the ultimate outcome of this lawsuit
will not 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 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
Our annual meeting of stockholders was held on June 19, 2003. At the
meeting, the following persons were elected to serve as directors of Parallel
for a term of one year expiring in 2004 and until their respective successors
are duly qualified and elected: (1) Thomas R. Cambridge, (2) Larry C. Oldham,
(3) Dewayne E. Chitwood, (4) Martin B. Oring, (5) Charles R. Pannill, (6) Ray M.
Poage, and (7) Jeffrey G. Shrader. Set forth below is a tabulation of votes with
respect to each nominee for director.
BROKER
NAME VOTES CAST FOR VOTES WITHHELD NON-VOTES
---------------------------- ------------------------ ----------------------- --------------
Thomas R. Cambridge 18,975,312 333,435 -
Larry C. Oldham 18,998,812 309,935 -
Dewayne E. Chitwood 18,999,517 309,230 -
Martin B. Oring 18,975,017 333,730 -
Charles R. Pannill 18,973,197 335,550 -
Ray M. Poage 18,998,947 309,800 -
Jeffrey G. Shrader 18,975,797 332,950 -
In addition to electing directors, the stockholders also voted
upon and ratified the appointment of KPMG LLP to serve as our independent public
accountants for 2003. Set forth below is a tabulation of votes with respect to
the proposal to ratify the appointment of our independent public accountants:
BROKER
FOR AGAINST ABSTAIN NON-VOTES
---------------------------- ------------------------ ----------------------- --------------
18,912,509 383,249 12,989 -
24
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.)
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).
25
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.)
26
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)
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.
27
*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.
---------------
* Filed herewith.
(b) Reports on Form 8-K
During the fiscal quarter ended June 30, 2003, we filed one report on
Form 8-K.
On May 15, 2003, we filed Form 8-K, dated May 15, 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 May 15, 2003 press release announcing our results of operations and
financial condition for the first quarter ended March 31, 2003.
28
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: August 13, 2003 --------------------------------
Thomas R. Cambridge
Chairman of the Board of Directors
and Chief Executive Officer
Date: August 13, 2003 BY: /s/ Steven D. Foster
---------------------------------
Steven D. Foster,
Chief Financial Officer
29
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)
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.
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 controls 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 controls over financial reporting.
Date: August 13, 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 controls 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 controls over financial reporting.
Date: August 13, 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 June 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: August 13, 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 June 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: August 13, 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.