SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q ---------------------------- (Mark One) /X/ Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the quarterly period ended September 30, 2003 or / / Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the Transition period from to -------------------------- COMMISSION FILE NUMBER 0-13305 -------------------------- PARALLEL PETROLEUM CORPORATION (Exact name of registrant as specified in its charter) DELAWARE 75-1971716 (State of other jurisdiction of (I.R.S. Employer Identification incorporation or organization) Number) 1004 N. Big Spring, Suite 400, Midland, Texas 79701 (Address of principal executive offices) (Zip Code) (432) 684-3727 (Registrant's telephone number, including area code) Not Applicable (Former name, former address and former fiscal year, if changed since last report) Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes `X' No Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes No `X' At October 23, 2003, 21,216,863 shares of the Registrant's Common Stock, $0.01 par value, were outstanding. INDEX PART I. - FINANCIAL INFORMATION Page No. ---- ITEM 1. FINANCIAL STATEMENTS Reference is made to the succeeding pages for the following consolidated financial statements: - Consolidated Balance Sheets as of December 31, 2002 and September 30, 2003 (unaudited) 2 - Unaudited Consolidated Statements of Operations for the three months and nine months ended September 30, 2002 and 2003 3 - Unaudited Consolidated Statements of Cash Flows for the nine months ended September 30, 2002 and 2003 4 - Unaudited Consolidated Statements of Comprehensive Income for the three months and nine months ended September 30, 2002 and 2003 5 - Notes to Consolidated Financial Statements 6 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 14 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 25 ITEM 4. CONTROLS AND PROCEDURES 26 PART II. - OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS 27 ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K 27 SIGNATURES -1- PARALLEL PETROLEUM CORPORATION CONSOLIDATED BALANCE SHEETS <table> (audited) (unaudited) December 31, September 30, 2002 2003 ------------------ ------------------ <s> <c> <c> ASSETS Current assets: Cash and cash equivalents $ 11,811,704 $ 5,255,221 Accounts receivable: Oil and gas 3,071,315 4,254,737 Others, net of allowance for doubtful account of $12,681 in 2002 and $9,239 in 2003 236,443 590,718 Affiliate 2,084 4,818 ------------ ------------ 3,309,842 4,850,273 Income tax receivable 832,590 832,590 Other assets 78,675 98,077 Fair value of derivative instruments 21,884 84 ------------ ------------ Total current assets 16,054,695 11,036,245 ------------ ------------ Property and equipment, at cost: Oil and gas properties, full cost method (Note 6) 146,679,503 158,249,928 Other 1,083,282 1,393,447 ------------ ------------ 147,762,785 159,643,375 Less accumulated depreciation and depletion (62,074,559) (67,924,397) ------------ ------------ Net property and equipment (Note 10) 85,688,226 91,718,978 ------------ ------------ Other assets, net of accumulated amortization of $78,520 in 2002 and $134,967 in 2003 608,410 663,586 ------------ ------------ $102,351,331 $103,418,809 ============ ============ LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable and accrued liabilities $ 3,033,650 $ 3,300,177 Current maturities of long-term debt (Note 3) 4,145,833 - Current maturity of derivative obligations 335,829 1,348,469 ------------ ------------ 7,515,312 4,648,646 ------------ ------------ Long-term debt, excluding current maturities (Note 3) 45,604,167 39,750,000 Long-term asset retirement obligation (Note 10) - 1,827,066 Long-term maturity of derivative obligations (Note 7) 103,745 1,730,325 Deferred tax liability 3,627,963 5,531,300 Stockholders' equity: Series A preferred stock -- par value $.10 per share (aggregate liquidation preference of $26) authorized 50,000 shares - - Preferred stock -- 6% convertible preferred stock -- par value $.10 per share (aggregate liquidation preference of $10) authorized 10,000,000 shares, issued and outstanding 974,500 in 2002 and 2003 97,450 97,450 Common stock -- par value $.01 per share, authorized 60,000,000 shares, issued and outstanding 21,143,406 in 2002 and 21,174,006 in 2003 211,434 211,740 Additional paid-in capital 34,567,866 34,240,897 Retained earnings 10,623,394 17,241,434 Other comprehensive loss, net of tax (Note 7) - (1,860,049) ------------ ------------ Total stockholders' equity 45,500,144 49,931,472 Commitments and contingencies (Note 12) ------------ ------------ $102,351,331 $103,418,809 ============ ============ </table> *The balance sheet as of December 31, 2002 has been derived from Parallel's audited financial statements. The accompanying notes are an integral part of these financials. -2- <page> PARALLEL PETROLEUM CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) <table> Three Months Ended Nine Months Ended September 30, September 30, -------------------------- ------------------------- 2002 2003 2002 2003 ----------- ----------- ------------ ------------ <s> <c> <c> <c> <c> Oil and gas revenues $ 2,709,985 $ 8,731,573 $ 7,489,983 $ 25,756,339 ----------- ----------- ------------ ------------ Cost and expenses: Lease operating expense (Note 10) 648,001 2,078,640 1,918,991 5,719,496 General and administrative, includes $1,471,000 for incentive awards in 2002 347,827 1,061,307 2,672,277 2,831,229 Depreciation, depletion and amortization 1,323,107 2,189,183 4,010,903 6,244,068 ----------- ----------- ------------ ------------ Total costs and expenses 2,318,935 5,329,130 8,602,171 14,794,793 ----------- ----------- ------------ ------------ Operating income (loss) 391,050 3,402,443 (1,112,188) 10,961,546 ----------- ----------- ------------ ------------ Other income (expense), net: Equity in income (loss) of First Permian, L.P., includes a $31,082,041 gain on sale of substantially all net assets (99,928) - 30,665,820 - Derivative instruments gain (loss) (Note 7) (62,589) 85,401 (457,421) 157,235 Interest and other income 33,538 33,630 70,979 79,622 Dividend income 143,494 - 306,872 - Interest expense (178,417) (539,585) (489,681) (1,547,940) Other expense (27,360) (31,755) (307,008) (77,765) Loss on sale of marketable securities (928,540) - (928,540) - ----------- ----------- ------------ ------------ Total other income (expense), net (1,119,802) (452,309) 28,861,021 (1,388,848) ----------- ----------- ------------ ------------ Income (loss) before income taxes (728,752) 2,950,134 27,748,833 9,572,698 Income tax benefit (expense), net 330,836 (1,254,938) (9,253,997) (2,893,202) ----------- ----------- ------------ ------------ Net income (loss) before cumulative effect of change in accounting principle (397,916) 1,695,196 18,494,836 6,679,496 Cumulative effect on prior years of a change in accounting principle, less applicable income taxes of $31,659 (Note 10) - - - (61,456) ----------- ----------- ------------ ------------ Net income (loss) (397,916) 1,695,196 18,494,836 6,618,040 Cumulative preferred stock dividend (146,175) (146,175) (438,525) (438,525) ----------- ----------- ------------ ------------ Net income (loss) available to common stockholders $ (544,091) $ 1,549,021 $ 18,056,311 $ 6,179,515 =========== =========== ============ ============ Net income (loss) per common share: Basic - before cumulative effect of a change in accounting principle $ (0.03) $ 0.07 $ 0.87 $ 0.29 Cumulative effect of a change in accounting principle, net of tax - - - - ----------- ----------- ------------ ------------ Basic - after cumulative effect of a change in accounting principle $ (0.03) $ 0.07 $ 0.87 $ 0.29 =========== =========== ============ ============ Diluted - before cumulative effect of a change in accounting principle $ (0.03) $ 0.07 $ 0.79 $ 0.27 Cumulative effect of a change in accounting principle, net of tax - - - - ----------- ----------- ------------ ------------ Diluted - after cumulative effect of a change in accounting principle $ (0.03) $ 0.07 $ 0.79 $ 0.27 =========== =========== ============ ============ Weighted average common share outstanding: Basic 20,663,861 21,158,619 20,663,861 21,148,933 =========== =========== ============ ============ Diluted 20,663,861 24,162,124 23,536,079 24,082,445 =========== =========== ============ ============ </table> The accompanying notes are an integral part of these financials. -3- <page> PARALLEL PETROLEUM CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) <table> Nine Months Ended September 30, ------------------------------------- 2002 2003 ----------------- ------------------ <s> <c> <c> Cash flows from operating activities: Net income $ 18,494,836 $ 6,618,040 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and depletion 4,010,903 6,244,068 Accretion expense - 103,210 Equity in income of First Permian, L.P. net of cash distributions of $5,501,703 (25,164,117) - Loss on sale of marketable securities 928,540 - Change in fair value of derivative instruments 457,421 (157,235) Stock option expense - 56,384 Deferred income taxes 9,253,997 2,893,202 Cumulative effect on prior years of a change in accounting principle, net of tax - 61,456 Changes in assets and liabilities: Other, net (44,233) (55,176) Increase in accounts receivables (135,109) (1,540,431) Increase in prepaid expenses and other assets (631,391) (19,402) (Decrease) Increase in accounts payable and accrued liabilities (1,427,123) 120,352 Accrued bonus payable 130,043 - Purchase of derivative instruments (530,605) - ------------ ------------ Net cash provided by operating activities 5,343,162 14,324,468 ------------ ------------ Cash flows from investing activities: Additions to property and equipment (10,558,989) (10,664,479) Proceeds from disposition of Energen Stock 12,563,220 - Proceeds from disposition of property and equipment 692,450 20,400 ------------ ------------ Net cash (used) provided in investing activities 2,696,681 (10,644,079) ------------ ------------ Cash flows from financing activities: Borrowings from bank line of credit 2,865,589 3,173,625 Payments on bank line of credit (11,905,589) (13,173,625) Proceeds from exercise of stock options - 55,478 Payment of preferred stock dividend (292,350) (292,350) ------------ ------------ Net cash used in financing activities (9,332,350) (10,236,872) ------------ ------------ Net decrease in cash and cash equivalents (1,292,507) (6,556,483) Beginning cash and cash equivalents 3,351,044 11,811,704 ------------ ------------ Ending cash and cash equivalents $ 2,058,537 $ 5,255,221 ============ ============ Non-cash financing and investing activities: Non-cash proceeds from sale of investment $(25,580,339) $ - Unrealized gain on investment in securities $ 922,085 $ - Accrued asset retirement obligation related to oil and gas properties $ - $ 1,236,511 Accrued preferred stock dividend $ 170,537 $ 170,537 </table> The accompany notes are an integral part of these financials. -4- <page> PARALLEL PETROLEUM CORPORATION CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited) <table> THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------------------- ---------------------------- 2002 2003 2002 2003 -------------- -------------- ------------ ------------ <s> <c> <c> <c> <c> Net income $ (397,916) $ 1,695,196 $ 18,494,836 $ 6,618,040 ------------- ----------- ------------ ----------- Other comprehensive income (loss): Change in derivative fair value - 783,632 - (671,529) Reclassification adjustments - contract (gain) loss settlements(1) - (504,630) - (2,146,726) ------------- ----------- ------------ ----------- - 279,002 - (2,818,255) Income tax (expense) benefit - (94,861) - 958,206 ------------- ----------- ------------ ----------- Total other comprehensive income (loss) - 184,141 - (1,860,049) ------------- ----------- ------------ ----------- Total comprehensive income $ (397,916) $ 1,879,337 $ 18,494,836 $ 4,757,991 ============= =========== ============ =========== </table> ______________________ (1) For contract gain settlements, the reduction to comprehensive income offsets contract proceeds recorded as oil and gas revenue or interest expense. For contract loss settlements, the increase in comprehensive income offsets contract payments recorded as reductions to oil and gas revenue or interest expense. The accompanying notes are an integral part of these financials. -5- <page> PARALLEL PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Basis of Presentation The financial information included herein, except the balance sheet as of December 31, 2002, is unaudited. However, such information includes all adjustments (consisting solely of normal recurring adjustments), which are, in the opinion of management, necessary for a fair statement of the results of operations for the interim periods. The results of operations for the interim period are not necessarily indicative of the results to be expected for an entire year. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted in this Form 10-Q pursuant to certain rules and regulations of the Securities and Exchange Commission. These financial statements should be read in conjunction with the financial statements and notes included in our 2002 Form 10-K. NOTE 2. STOCKHOLDERS' EQUITY Options In September 2003, Parallel adopted Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation ("SFAS No. 123") and related interpretations in accounting for its employee and director stock options and will apply the fair value based method of accounting to such options. Under Statement of Financial Accounting Standards No. 148, Accounting for Stock-Based Compensation - Transition and Disclosure, an amendment to SFAS No. 123, certain transitional alternatives are available for a voluntary change to the fair value based method of accounting for stock-based employee compensation if adopted in a fiscal year beginning before December 16, 2003. Parallel used the prospective method which applies prospectively the fair value recognition method to all employee and director awards granted, modified or settled after the beginning of the fiscal year in which the fair value based method of accounting for stock-based compensation is adopted. For the three and nine months ended September 30, 2003, Parallel recognized compensation expense of $56,384 associated with its stock option grants. The total number of options granted during the nine months ended September 30, 2003 was 180,000. At September 30, 2003, Parallel accounted for stock-based compensation utilizing the intrinsic value method prescribed by Accounting Principles Board Opinion No. 25 "Accounting for Stock Issued to Employees" ("APB 25") and related interpretations. No stock-based employee compensation cost is reflected in the net income (loss) for the three and nine months ended September 30, 2002, as all options or warrants granted had an exercise price equal to or greater than the market value of the underlying common stock on the date of grant. As previously stated, in September 2003, Parallel adopted the fair value recognition provisions of SFAS No. 123 prospectively for all employee awards granted, modified or settled after January 1, 2003. Therefore, the cost related to stock-based compensation included in the determination of income for the three and nine month periods ended September 30, 2003 and 2002 is less than that which would have been recognized if the fair value method had been applied to all awards since the original effective date of SFAS No. 123. Awards vest over periods ranging from one to three years. The following table illustrates the effect on net income and earnings per share as if the fair value based method had been applied to all outstanding and unvested awards in each period. The fair value of each grant is estimated on the date of grant using the Black-Scholes option-pricing model. -6- <table> Three Months Ended Nine Months Ended September 30, September 30, ------------------------- ---------------------------- 2002 2003 2002 2003 ----------- ----------- ------------ ----------- <s> <c> <c> <c> <c> Net income (loss), as reported $ (397,916) $ 1,695,196 $ 18,494,836 $ 6,618,040 Add: Stock-based employee compensation expense included in net income (loss), net of tax - 56,384 - 56,384 Deduct: Stock-based employee compensation expense determined under fair value based method (SFAS 123), net of tax (321,000) (89,946) (1,037,267) (199,358) ---------- ----------- ------------ ----------- Net income (loss), pro forma $ (718,916) $ 1,661,634 $ 17,457,569 $ 6,475,066 ========== =========== ============ =========== Basic: Net income (loss) per common share, as reported $ (0.03) $ 0.07 $ 0.87 $ 0.29 ========== =========== ============ =========== Net income (loss) per common share, pro forma $ (0.03) $ 0.07 $ 0.84 $ 0.29 ========== =========== ============ =========== Diluted: Net income (loss) per common share, as reported $ (0.03) $ 0.07 $ 0.79 $ 0.27 ========== =========== ============ =========== Net income (loss) per common share, pro forma $ (0.03) $ 0.07 $ 0.74 $ 0.27 ========== =========== ============ =========== </table> NOTE 3. LONG TERM DEBT Long-term debt consists of the following at September 30, 2003: Revolving Facility note payable to banks, at the agent bank's base lending rate (with a minimum rate of 4.5% at September 30, 2003) $39,750,000 Less: current maturities - ----------- $39,750,000 =========== Revolving Credit Facility. Under our revolving credit facility, as amended, we may borrow the lesser of $100,000,000 or the "borrowing base" then in effect. The borrowing base at September 30, 2003 was $50,000,000, which is secured by substantially all of our oil and gas reserves. The total outstanding principal amount of our bank indebtedness at September 30, 2003 was $39,750,000, excluding $250,000 reserved for our letters of credit, leaving an availability of $10,000,000 on our borrowing base. The borrowing base is subject to redetermination semi-annually, on or about April 1 and October 1 of each year. The banks may also require a redetermination of the borrowing base at any other time, and from time to time, at the discretion of the banks. All indebtedness matures December 20, 2006. The unpaid principal balance of our outstanding borrowings bears interest at our election at a rate equal to (i) the bank's base lending rate, or (ii) the libor rate plus a libor margin of 2.75% per annum whenever the borrowing base usage is equal to or greater than 75%; 2.50% per annum whenever the borrowing base usage is equal to or greater than 50% but less than 75%; 2.25% per annum whenever the borrowing base usage is less than 50%. However, the interest rate may never be less than 4.50%. Interest on borrowings bearing interest at the libor rate is due and payable on the day on which the related libor interest period ends or if the interest period is longer than three months, at three month intervals. Interest on borrowings bearing interest at the base rate is due and payable on the last day of each month. -7- We are required to pay a commitment fee of one-quarter of one percent times the daily average of the unadvanced amount of the commitment. The commitment fee is payable quarterly in arrears on the last day of each calendar quarter. In addition to customary affirmative covenants, the loan agreement contains various restrictive covenants and compliance requirements, including: . maintaining certain financial requirements; . limitation on additional indebtedness; . prohibiting the payment of dividends on our common stock; . limitations on the disposition of assets; . prohibiting liens (other than in favor of the bank) to exist on any of our properties; . limitations on investments, mergers, forming subsidiaries, affiliate transactions, changes in accounting methods, rental and lease payments and derivative transactions . limitations on the purchase, redemption or retirement of stock; and . limitations on hedging activities. NOTE 4. PREFERRED STOCK We have outstanding 974,500 shares of 6% Convertible Preferred Stock, $0.10 par value per share. Cumulative annual dividends of $0.60 per share are payable semi-annually on June 15 and December 15 of each year. Each share of Convertible Preferred Stock may be converted, at the option of the holder, into 2.8571 shares of common stock at an initial conversion price of $3.50 per share, subject to adjustment in certain events. The Convertible Preferred Stock has a liquidation preference of $10 per share and has no voting rights, except as required by law. We may redeem the preferred stock, in whole or part, for $10 per share plus accrued and unpaid dividends. NOTE 5. INCOME TAX LIABILITY For the nine months ended September 30, 2003, we recorded income tax expense of $2,893,202 resulting in a net deferred tax liability of $5,331,300. Our income tax expense was largely due to generating taxable income in the current period. Our effective tax rate for the nine months ended September 30, 2003 was 30%, which is less than the expected rate of 37% due to the recognition of state income tax, net operating loss carryover and certain federal income tax credits not previously recognized. NOTE 6. FULL COST CEILING TEST We use the full cost method to account for our oil and gas producing activities. Under the full cost method of accounting, the net book value of oil and gas properties, less related deferred income taxes, may not exceed a calculated "ceiling". The ceiling limitation is the discounted estimated after-tax future net cash flows from proved oil and gas properties. In calculating future net cash flows, current prices and costs are generally held constant indefinitely as adjusted for qualifying cash flow hedges under Statement 133. The net book value of oil and gas properties, less related deferred income taxes over the ceiling, is compared to the ceiling on a quarterly and annual basis. Any excess of the net book value, less related deferred income taxes, is generally written off as an expense. Under rules and regulations of the SEC, the excess above the ceiling is not written off if, subsequent to the end of the quarter or year but prior to the release of the financial results, prices have increased sufficiently that such excess above the ceiling would not have existed if the increased prices were used in the calculations. At September 30, 2003 the net book value of our oil and gas properties, less related deferred income taxes, was below the calculated ceiling. As a result, we were not required to record a reduction of our oil and gas properties under the full cost method of accounting at that time. Under the full cost method of accounting, all costs incurred in the acquisition, exploration and development of oil and natural gas properties, including a portion of our overhead, are capitalized. In the nine month period ended September 30, 2003 overhead costs capitalized were $678,975. -8- <page> NOTE 7. DERIVATIVE INSTRUMENTS General For the year ended December 31, 2002, we applied mark-to-market accounting for our hedge contracts. As of January 1, 2003 we adopted hedge accounting for the costless collars, oil and gas swaps, and interest rate swaps described below. We continued market-to-market accounting for our put positions described below. The purpose of our hedges is to provide a measure of stability in our oil and gas prices and interest rate payments and to manage exposure to commodity price and interest rate risk. Our objective is to lock in a range of oil and gas prices and a fixed interest rate for certain notional amounts. During the terms of a hedge, the quarterly change in the fair value of the derivatives is recorded in stockholders' equity as other comprehensive income (loss) and then transferred to earnings when the production is sold. Ineffective portions of hedges (changes in realized prices that do not match the changes in the hedge price) are recognized in earnings as they occur. While the hedge contract is open, the ineffective gain or loss may increase or decrease until settlement of the contract. For the nine months ended September 30, 2003, there was no ineffective portion of our natural gas and interest rate hedges. For the nine months ended September 30, 2003, we recorded a cumulative charge of $114,732 to other income (expense) for the ineffective portion of the crude oil hedges. For the nine months ended September 30, 2003, $555,601 was transferred from comprehensive income (loss) and charged to earnings along with the expiration of the associated hedge contracts. During the twelve month period ending September 30, 2004, we expect approximately $771,197 to be transferred out of other comprehensive income (loss) and charged to earnings. We are exposed to credit risk in the event of nonperformance by BNP Paribas in its derivative instruments. However, we periodically assess its credit worthiness to mitigate this credit risk. Interest Rate Sensitivity In January, 2003, we entered into a 45-month libor fixed interest rate swap contract with BNP Paribas. We will receive a fixed interest rate, as noted in the table below, for the 45-month period beginning March 31, 2003 through December 20, 2006. Under our revolving credit facility, we may elect an interest rate based upon the agent lender's base lending rate, or the libor rate, plus a margin ranging from 2.25% to 2.75% per annum, depending on our borrowing base usage. The interest rate we are required to pay, including the applicable margin, may never be less than 4.50%. A recap for the period of time, notional amounts, libor fixed interest rates, expected margin rates and expected fixed interest rates for the contract are as follows: <table> Libor Expected Expected Notional Fixed Margin Fixed Period of Time Amounts (1) Interest Rates (2) Rates (3) Interest Rates (4) - ----------------------------------------------- ----------------- ------------------- ----------- ------------------ <s> <c> <c> <c> <c> 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% </table> - ------------------------------- (1) Based on the anticipated principal reductions under our credit facility. (2) Our swap contract with BNP Paribas. (3) Based on the anticipated borrowing base usage under our credit facility. (4)Total of the libor fixed interest rate plus the expected margin rate under our credit facility. Our credit agreement requires the interest rate to not be below 4.50%. -9- <page> Commodity Price Sensitivity Puts. On May 24, 2002 we purchased put floors on volumes of 100,000 Mcf per month for a total of 700,000 Mcf during the seven month period from April, 2003 through October, 2003 at a floor price of $3.00 per Mcf for a total consideration of approximately $139,500. These derivatives are not held for trading purposes. A decrease in fair value of the put floors of $21,800 was recognized for the nine months ended September 30, 2003 in the Consolidated Statements of Operations. The following table illustrates our put options. <table> Fair Value Floor at Period Commodity Mcf Volume Price Cost of Floor September 30, 2003 - ------------------------------- ------------ ------------- ------- --------------- --------------------- <s> <c> <c> <c> <c> <c> April 2003 thru October 2003 natural gas 700,000 $ 3.00 $ 139,500 $ 84 </table> Costless Collars. Collars are created by purchasing puts to establish a floor price and then selling a call which establishes a maximum amount the producer will receive for the oil or gas hedged. Calls are sold to offset or reduce the premium paid for buying the put. In 2003, we entered into several costless, seven-month Houston ship channel gas collars. A majority of our natural gas production is sold based on Houston ship channel prices. A recap for the period of time, number of MMBtu's and average gas prices is as follows: <table> Houston Ship Channel Gas Prices --------------------------- MMBtu of Period of Time Natural Gas Floor Cap - ------------------------------------------- -------------- ------------ ------------- <s> <c> <c> <c> April 1, 2003 thru October 31, 2003 642,000 $ 4.25 $ 5.30 November 1, 2003 thru March 31, 2004 453,000 $ 5.43 $ 6.58 </table> Subsequent to September 30, 2003 we added additional Houston Ship Channel costless collars for April 1, 2004 through October 31, 2004 on 214,000 MMbtu of gas with a floor of $4.40 and a cap of $5.50. Swaps. Generally, swaps are an agreement to buy or sell a specified commodity for delivery in the future, but at an agreed fixed price. Swap transactions convert a floating price into a fixed price. For any particular swap transaction, the counterparty is required to make a payment to the hedge party if the reference price for any settlement period is less than the swap price for such hedge, and the hedge party is required to make a payment to the counterparty if the reference price for any settlement period is greater than the swap price for such hedge. -10- In 2003, we entered into additional oil and gas swap contracts with BNP Paribas. A recap for the period of time, number of MMBtu's, number of barrels, and swap prices are as follows: <table> Houston Ship Barrels of Nymex Oil MMBtu of Channel Period of Time Oil Swap Prices Natural Gas Gas Swap Price - -------------------------------------------- ------------ --------------- ------------- ----------------- <s> <c> <c> <c> <c> April 1, 2003 thru October 31, 2003 - $ - 214,000 $ 4.87 April 1, 2003 thru October 31, 2003 - $ - 428,000 $ 4.83 April 1,2003 thru December 31, 2003 293,400 $ 24.94 - $ - January 1,2004 thru December 31, 2004 347,600 $ 23.47 - $ - January 1,2005 thru December 31, 2005 292,000 $ 22.77 - $ - January 1, 2006 thru December 20, 2006 265,500 $ 23.04 - $ - </table> NOTE 8. INVESTMENT IN FIRST PERMIAN, L.P. For the nine months ended September 30, 2002, First Permian, L.P. had net income of $97,050,344, which includes a gain of $107,662,000 on the sale of its entire oil and gas properties. Our 30.675% share of the net income and distributions for the nine months ended September 30, 2002, was $30,665,820. Using the equity method of accounting, our investment is increased or decreased by our proportionate share of First Permian's net income or loss. On March 7, 2002, First Permian entered into an Agreement of Sale and Purchase with Energen Resources Corporation, a wholly owned subsidiary of Energen Corporation (Energen), to sell all of First Permian's oil and gas properties for $120 million in cash and 3,043,479 shares in Energen stock approximating $70 million in value. Energen is a publicly traded company listed on the NYSE. The transaction closed on April 8, 2002. As a 30.675% interest owner in First Permian, Parallel received its prorata share of the net proceeds, $5.5 million in cash and 933,589 shares of Energen common stock. -11- NOTE 9. NET INCOME PER COMMON SHARE Basic income per share is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding for the period. Diluted income per share reflects the assumed conversion of all potentially dilutive securities. <table> Three Months Ended Nine Months Ended September 30, September 30, ------------------------------- ------------------------------- 2002 2003 2002 2003 --------------- --------------- --------------- --------------- <s> <c> <c> <c> <c> Basic EPS Computation: Numerator- Net income (loss) before cumulative effect of a change in accounting principle $ (397,916) $ 1,695,196 $18,494,836 $ 6,679,496 Cumulative effect of a change in accounting principle, net of tax - - - (61,456) ---------- ----------- ----------- ----------- (397,916) 1,695,196 18,494,836 6,618,040 Preferred stock dividend (146,175) (146,175) (438,525) (438,525) ---------- ----------- ----------- ----------- Net income (loss) available to common stockholders $ (544,091) $ 1,549,021 $18,056,311 $ 6,179,515 =========== =========== =========== =========== Denominator- Weighted average common shares outstanding 20,663,861 21,158,619 20,663,861 21,148,933 =========== =========== =========== =========== Basic EPS: Net income before cumulative effect of a change in accounting principle $ (0.03) $ 0.07 $ 0.87 $ 0.29 Cumulative effect of a change in accounting principle, net of tax - - - - ----------- ----------- ----------- ----------- Basic net earnings (loss) per share $ (0.03) $ 0.07 $ 0.87 $ 0.29 =========== =========== =========== =========== Diluted EPS Computation: Numerator- Net income (loss) before cumulative effect of a change in accounting principle $ (397,916) $ 1,695,196 $18,494,836 $ 6,679,496 Cumulative effect of a change in accounting principle, net of tax - - - (61,456) ----------- ----------- ----------- ----------- (397,916) 1,695,196 18,494,836 6,618,040 Preferred stock dividend (146,175) - - - ----------- ----------- ----------- ----------- Net income (loss) available to common stockholders $ (544,091) $ 1,695,196 $18,494,836 $ 6,618,040 =========== =========== =========== =========== Weighted average common shares outstanding 20,663,861 21,158,619 20,663,861 21,148,933 Employee stock options - 219,261 87,974 149,268 Preferred stock - 2,784,244 2,784,244 2,784,244 ----------- ----------- ----------- ----------- Weighted average common shares for diluted earnings per share assuming conversion 20,663,861 24,162,124 23,536,079 24,082,445 =========== =========== =========== =========== Diluted EPS: Net income (loss) before cumulative effect of a change in accounting principle $ (0.03) $ 0.07 $ 0.79 $ 0.27 Cumulative effect of a change in accounting principle, net of tax - - - - ----------- ----------- ----------- ----------- Diluted net earnings (loss) per share $ (0.03) $ 0.07 $ 0.79 $ 0.27 =========== =========== =========== =========== </table> -12- Convertible preferred stock equivalent shares for the three-month period ended September 30, 2002 that could potentially dilute basic earnings per share in the future were included in the computation of diluted earnings per share because to do so would have been anti-dilutive. NOTE 10: ASSET RETIREMENT OBLIGATIONS On January 1, 2003 we adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations "SFAS 143". Adoption of SFAS 143 is required for all companies with fiscal years beginning after June 15, 2002. The new standard requires us to recognize a liability for the present value of all legal obligations associated with the retirement of tangible long-lived assets and to capitalize an equal amount as a cost of the asset, depreciating the additional cost through the unit-of-production method on the life of the asset. Through September 30, 2003 we recorded additional oil and gas property costs, net of disposals, of $1,236,511, a reduction in accumulated depletion of $394,230, a non-current liability of $1,708,716 and an after tax charge of $61,456 for the cumulative effect on prior years for depreciation and accretion expense on the liability related to expected abandonment costs of our oil and natural gas properties. The accretion expense for the current quarter is $34,849 and recorded as a charge to lease operating expense with a corresponding additional long-term liability. The following table summarizes our asset retirement obligation transactions during the three months and nine months ended September 30, 2003. <table> Three Months Ended Nine Months Ended September 30, 2003 September 30, 2003 ------------------------- ------------------------- <s> <c> <c> Beginning asset retirement obligation $ 1,777,077 $ 1,693,330 Additions related to new properties 49,757 65,831 Deletions related to property disposals (34,617) (35,305) Accretion expense 34,849 103,210 ----------- ----------- Ending asset retirement obligation $ 1,827,066 $ 1,827,066 =========== =========== </table> Prior years pro forma were not shown since the change was not significant. NOTE 11: RECENTLY ANNOUNCED ACCOUNTING PRONOUNCEMENTS SFAS No. 148, Accounting for Stock-Based Compensation-Transition and Disclosure, which amends SFAS No. 123, Accounting for Stock-Based Compensation. SFAS No. 148 provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. As of September 30, 2003, we adopted the Prospective method which applies prospectively the fair value recognition method to all employee and director awards granted, modified or settled after the beginning of the fiscal year in which the fair value based method of accounting for stock-based compensation is adopted. (See Note 2) SFAS 148 also amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The statement is required to be adopted for fiscal years ending after December 15, 2002. On April 22, 2003, the FASB announced its decision to require all companies to expense the value of employee stock options. Companies will be required to measure the cost according to the fair value of the options. The new guidelines have not been released to measure the cost according to the fair value of the options. Although the new guidelines have not been released, it is expected that they will be finalized and become effective in 2004. When final rules are announced, we will assess the impact to our consolidated financial statements. -13- FIN No. 45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others, FIN No. 45 requires that a liability be recorded in the guarantor's balance sheet upon issuance of certain guarantees. Initial recognition and measurement of the liability will be applied on a prospective basis to guarantees issued or modified after December 31, 2002. FIN No. 45 also requires disclosures about guarantees in financial statements for interim or annual periods ending after December 15, 2002. We do not expect the adoption of FIN No. 45 to have a material impact on our consolidated financial statements. FIN No. 46, Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51. FIN No. 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without financial support from other parties. We do not expect the adoption of FIN No. 46 to have a material impact on our consolidated financial statements. In April 2003, the Financial Accounting Standards Board issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, which clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. The Statement is effective for contracts entered into or modified after June 20, 2003. We do not anticipate SFAS No. 149 will have a material effect on future earnings. In May 2003, the FASB issued Statement No. 150 "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity." This statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. This statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The adoption of FAS 150 did not have a material impact on our consolidated financial statements. NOTE 12. COMMITMENTS AND CONTINGENCIES At September 30, 2003, we were involved in two lawsuits incidental to our business. We accrue for such items when a liability is both probable and the amount can be reasonably estimated. We do not believe the ultimate outcome of these lawsuits will have a material adverse effect on our financial position or results of operations. We are not aware of any threatened litigation. We have not been a party to any bankruptcy, receivership, reorganization, adjustment or similar proceeding. ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. The following discussion and analysis should be read in conjunction with our Consolidated Financial Statements and the related notes. OVERVIEW Strategy Our primary objective is to increase the per share net asset value of our common stock through increasing reserves, production, cash flow and earnings. We are shifting the balance of our investments from properties having high rates of production in early years to properties with more consistent production over a longer term. We attempt to reduce our financial risks by dedicating a smaller portion of our capital to high risk projects, while reserving the majority of our available capital for exploitation and development drilling opportunities. Obtaining positions in long-lived oil and gas reserves will be given priority over properties that might provide more cash flow in the early years of production, but which have shorter reserve lives. We also attempt to further reduce risk by emphasizing acquisition possibilities over high risk exploration projects. During the latter part of 2002, we reduced our emphasis on high risk exploration efforts and started focusing on established geologic trends where we can utilize the engineering, operational, financial and technical expertise of our entire staff. Although we anticipate participating in exploratory drilling activities in the future, reducing financial, reservoir, drilling and geological risks and diversifying our property portfolio are important criteria in the execution of our business plan. In summary, our business plan: -14- <page> . focuses on projects having less geological risk; . entails less exploratory activity in the down dip Wilcox trend of our south Texas properties; . emphasizes exploitation and enhancement activities; . focuses on acquiring producing properties; and . expands the scope of our operations by diversifying our exploratory and development efforts, both in and outside of our current areas of operation. Although the direction of our exploration and development activities has shifted from high risk exploratory activities to lower risk development opportunities, we will continue our efforts, as we have in the past, to maintain low general and administrative expenses relative to the size of our overall operations, utilize advanced technologies, serve as operator in appropriate circumstances, and reduce operating costs. The extent to which we are able to implement and follow through with our business plan will be influenced by: . the prices we receive for the oil and gas we produce; . the results of reprocessing and reinterpreting our 3-D seismic data; . the results of our drilling activities; . the costs of obtaining high quality field services; . our ability to find and consummate acquisition opportunities; and . our ability to negotiate and enter into work to earn arrangements, joint venture or other similar agreements on terms acceptable to us. Significant changes in the prices we receive for our oil and gas, drilling results, or the occurrence of unanticipated events beyond our control may cause us to defer or deviate from our business plan, including the amounts we have budgeted for our activities. Operating Performance. Our operating performance is influenced by several factors, the most significant of which are the prices we receive for our oil and gas and production volumes. The world price for oil has overall influence on the prices we receive for our oil production. The prices received for different grades of oil are based upon the world price for oil, which is then adjusted based upon the particular grade. Typically, light oil is sold at a premium, while heavy grades of crude are discounted. Gas prices we receive are primarily influenced by: . seasonal demand; . weather, and hurricane conditions in the Gulf of Mexico; . availability of pipeline transportation to end users and proximity of our wells to major transportation pipeline infrastructures; and . to a lesser extent, world oil prices. Additional factors influencing our operating performance include production expenses, overhead requirements, and cost of capital. Our oil and gas exploration, development and acquisition activities require substantial and continuing capital expenditures. Historically, the sources of financing to fund our capital expenditures have included: . cash flow from operations, . sales of our equity securities, . bank borrowings, and . industry joint ventures -15- <page> For the three months ended September 30, 2003, the sales price we received for our crude oil production (excluding hedges) averaged $31.00 per barrel compared with $28.01 per barrel for the three months ended September 30, 2002. The average sales price we received for natural gas for the three months ended September 30, 2003 (excluding hedges), was $4.78 per mcf compared with $3.10 per mcf for the three months ended September 30, 2002. Our hedged sales price that we received for the three months ended September 30, 2003, averaged $27.68 per barrel for crude oil and $4.86 per mcf for natural gas. Our oil and gas producing activities are accounted for using the full cost method of accounting. Under this method, we capitalize all costs incurred in connection with the acquisition of oil and gas properties and the exploration for and development of oil and gas reserves. See Note 6 to Financial Statements. These costs include lease acquisition costs, geological and geophysical expenditures, costs of drilling both productive and non-productive wells, and overhead expenses directly related to land and property acquisition and exploration and development activities. Proceeds from the disposition of oil and gas properties are accounted for as a reduction in capitalized costs, with no gain or loss recognized unless the disposition involves a material change in reserves, in which case the gain or loss is recognized. Depletion of the capitalized costs of oil and gas properties, including estimated future development costs, is provided using the equivalent unit-of-production method based upon estimates of proved oil and gas reserves and production, which are converted to a common unit of measure based upon their relative energy content. Unproved oil and gas properties are not amortized, but are individually assessed for impairment. The cost of any impaired property is transferred to the balance of oil and gas properties being depleted. RESULTS OF OPERATIONS Our business activities are characterized by frequent, and sometimes significant, changes in our: . sources of production; . product mix (oil vs. gas volumes); and . the prices we receive for our oil and gas production. Year-to-year or other periodic comparisons of the results of our operations can be difficult and may not accurately describe our condition. The table below shows our sale volumes and the prices we received for our production for the periods presented. <table> Three Months Ended Nine Months Ended ----------------------------- --------------------------- 9/30/2002 9/30/2003 9/30/2002 9/30/2003 -------------- -------------- ------------ -------------- <s> <c> <c> <c> <c> Sales Volume: Oil (Bbls) 28,452 158,335 91,739 471,652 Natural gas (Mcf) 616,447 895,216 1,816,909 2,482,104 Equivalent barrels of oil (BOE) (1) 131,193 307,538 394,557 885,336 Equivalent barrels of oil (BOE) per day 1,458 3,417 1,461 3,279 Prices: Bbls (unhedged) (2) $ 28.01 $ 31.00 $ 23.71 $ 29.86 Bbls (hedged) (3) $ 27.68 $ - $ 27.78 Mcf (unhedged) (2) $ 3.10 $ 4.78 $ 2.93 $ 5.53 Mcf (hedged) (3) $ 4.86 $ - $ 5.10 BOE (unhedged) (2) $ 20.66 $ 29.87 $ 18.98 $ 31.42 BOE (hedged) (3) $ 28.39 $ - $ 29.09 </table> ________________ (1) A BOE means one barrel of oil equivalent using the ratio of six Mcf of gas to one barrel of oil. (2) Unhedged price is the actual price received at the wellhead for our oil and natural gas (3) Hedged price is the actual price received at the wellhead for our oil and natural gas plus the settlements on our derivatives. -16- CRITICAL ACCOUNTING POLICIES AND PRACTICES Revenue Recognition. We follow the sales method of accounting for oil and natural gas revenues. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers. No receivables, payables or unearned revenues are recorded unless a working interest owner's aggregate sales from the property exceed its share of the total reserves-in-place. Full Cost. We account for our oil and natural gas exploration and development activities using the full cost method of accounting. Under this method, all costs incurred in the acquisition, exploration and development of oil and natural gas properties are capitalized. Costs of nonproducing properties, wells in process of being drilled and significant development projects are excluded from depletion until such time as the related project is developed and proved reserves are established or impairment is determined. At the end of each quarter, the net capitalized costs of our oil and natural gas properties is limited to the lower of unamortized cost or a ceiling. Depletion. Provision for depletion of oil and gas properties, under the full cost method, is calculated using the unit of production method based upon estimates of proved oil and gas reserves with oil and gas production being converted to a common unit of measure based upon relative energy content. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. The cost of any impaired property is transferred to the balance of oil and gas properties being depleted. Impairment of Assets. Under the full cost accounting rules, the capitalized costs of oil and gas properties may not exceed a "ceiling limit", which is based on the present value of estimated future net revenues, net of income tax effects, from proved reserves, discounted at 10%, plus the lower of cost or fair market value of unproved properties. If the net capitalized costs of our oil and natural gas properties exceed the ceiling, we are subject to a ceiling test write-down to the extent of such excess. A ceiling test write-down is a non-cash charge to earnings. It reduces earnings and impacts stockholders' equity in the period of occurrence and results in lower depreciation, depletion and amortization expense in future periods. The risk that we will be required to write down the carrying value of oil and gas properties increases when oil and gas prices decline. If commodity prices deteriorate, it is possible that we could incur impairment in 2003. Proved Reserve Estimates. Our discounted present value of proved oil and natural gas reserves is a major component of the ceiling calculation, and represents the component that requires the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. The process of estimating oil and natural gas reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data. Our reserve estimates are prepared by outside consultants. The passage of time provides more qualitative information regarding estimates of reserves, and revisions are made to prior estimates to reflect updated information. However, there can be no assurance that more significant revisions will not be necessary in the future. If future significant revisions are necessary that reduce previously estimated reserve quantities, it could result in a full cost property write-down. In addition to the impact of these estimates of proved reserves on calculation of the ceiling, estimates of proved reserves are also a significant component of the calculation of depreciation, depletion and amortization. While the quantities of proved reserves require substantial judgment, the associated prices of oil and natural gas reserves that are included in the discounted present value of the reserves do not require judgment. The ceiling calculation dictates that prices and costs in effect as of the last day of the period are held constant indefinitely. Because the ceiling calculation dictates that we use prices in effect as of the last day of the applicable quarter, the resulting value is not indicative of the true fair value of the reserves. Oil and natural gas prices have historically been cyclical and, on any particular day at the end of a quarter, can be either substantially higher or lower than prices we actually receive in the long-term, which are a barometer for true fair value. -17- Use of Estimates. The preparation of financial statements in accordance with generally accepted accounting principles in the United States of America requires management to make estimates and assumptions that affect reported assets, liabilities, revenues, expenses, and some narrative disclosures. Hydrocarbon reserves, future development costs, certain hydrocarbon production expense and revenue are the most critical estimates to our financial statements. Derivatives. SFAS No. 133 and SFAS No. 138 require that all derivative instruments be recorded on the balance sheet at their respective values. SFAS No. 133 and SFAS No. 138 are effective for all fiscal quarters of all fiscal years beginning after June 30, 2000. We adopted SFAS No. 133 and SFAS No. 138 on January 1, 2001. For the year ended December 31, 2002, we used fair value accounting for our hedge contracts. As of January 1, 2003 we adopted hedge accounting for the costless collars, oil and gas swaps, and interest rate swaps. We continued fair value accounting for our put positions. The purpose of our hedges is to provide a measure of stability in our oil and gas prices and interest rate payments and to manage exposure to commodity price and interest rate risk under existing sales contracts. Off Balance Sheet Arrangements. We do not currently have any off balance sheet arrangements or other such unrecorded obligations and we have not guaranteed the debt of any third party. Parallel, L.L.C., a subsidiary, has guaranteed the indebtness of Parallel Petroleum Corporation and Parallel, L.P. RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2003 AND 2002: Oil and Gas Revenues. Oil and gas revenues increased $6,021,588 or 222%, to $8,731,573 for the three months ended September 30, 2003, from $2,709,985 for the same period of 2002. The increase was primarily the result of a 134% or 176,345 BOE increase in oil and gas production due to the Fullerton acquisition on December 20, 2002 and increased production at Cook Mountain and a 37% increase in the average sales price per BOE including hedges. Lease Operating Costs. Lease operating costs increased $1,430,639, or 221%, to $2,078,640 during the three months ended September 30, 2003, compared with $648,001 for the same period of 2002. The increase was primarily attributable to higher lease operating costs associated with the Fullerton acquisition and Diamond M operations, and outside operated properties acquired at year-end. General and Administrative Expenses. General and administrative expenses increased by $713,480, or 205%, to $1,061,307 for the three months ended September 30, 2003 from $347,827 for the same period of 2002. The increase was primarily due to costs associated with additional personnel hired and associated costs in the implementation of our new business plan. Depreciation, Depletion and Amortization Expense. Depreciation, depletion and amortization expense increased by $866,076, or 65%, to $2,189,183 for the three months ended September 30, 2003 compared with $1,323,107 for the same period of 2002 primarily because of a 134% increase in production volumes. Equity in Income (loss) of First Permian, L.P. As previously discussed in Note 8, First Permian, L.P. of which Parallel is a 30.675% interest owner sold all of their oil and gas properties in a transaction closing on April 8, 2002. Our equity share of the net loss for ongoing general and administrative and wind down cost in First Permian for the third quarter was $99,928. Change in Fair Market Value of Derivatives. The change in fair market value of derivatives increased $147,990 due to the increase in value during the three months ended September 30, 2003. Interest and Other Income. Interest and other income increased were virtually flat for the three month period ended September 30, 2003 compared to the same period of 2002. Dividend Income. The $143,494 dividend income in the third quarter of 2002 was related to the Energen stock that was held for sale. Interest Expense. Interest expense increased $361,168, or 202%, to $539,585 for the three months ended September 30, 2003 compared with $178,417 for the same period of 2002 due principally to increased bank borrowings of $30,600,000 associated with our acquisitions, partially offset by a decrease in the minimum interest rate under our revolving credit facility. The minimum interest rate decreased from 4.75% to 4.50% in December 2002. Loss on Sale of Marketable Securities. The loss of $928,540 recognized in marketable securities is for the sale of 492,400 shares of Energen stock during the three months ended September 30, 2002. This is the difference in the April 8, 2002 stock price of $27.40 at the time of the sale of First Permian and the realized net price of approximately $25.51 received during the third quarter. -18- <page> Income Tax Benefit (Expense). For the three months ended September 30, 2003, we recorded a tax expense of $1,254,938 because of increased earnings compared to an income tax benefit of $330,836 in 2002. Net Income. We reported net income of $1,695,196 for the three months ended September 30, 2003 compared with a net loss of $397,916 for the three months ended September 30, 2002. The increase of $2,093,112 or 526% is a result of increased operating income associated with increased volumes and prices in 2003 and the loss on the sale of Energen stock recorded in 2002. RESULTS OF OPERATIONS FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2003 AND 2002: Oil and Gas Revenues. Oil and gas revenues increased $18,266,356, or 244%, to $25,756,339 for the nine months ended September 30, 2003, from $7,489,983 for the same period of 2002. The increase was primarily the result of a 124% increase in oil and gas production due to the Fullerton acquisition on December 20, 2002, increased production at Cook Mountain and a 53% increase in the average sales price per BOE including hedges. Lease Operating Costs. Lease operating costs increased $3,800,505 or 198%, to $5,719,496 during the first nine months of 2003, compared with $1,918,991 for the same period of 2002. The increase was primarily attributable to higher lease operating costs associated with the Fullerton acquisition and Diamond M operations and outside operated properties acquired at year end. General and Administrative Expenses. General and administrative expenses (excluding the incentive award payments paid and accrued during the nine months ended September 30, 2002 of approximately $1,471,000 related to the First Permian, L.P. divestiture) increased by $1,629,952 or 136%, to $2,831,229 for the nine months ended September 30, 2003 from $1,201,277 for the same period of 2002. The increase was primarily due to costs associated with additional personnel hired and associated costs in the implementation of the business plan. In the nine month period ended September 30, 2003 overhead costs capitalized were $678,975. Depreciation, Depletion and Amortization Expense. Depreciation, depletion and amortization expense increased by $2,233,165, or 56%, to $6,244,068 for the first nine months of 2003 compared with $4,010,903 for the same period of 2002, primarily because of a 124% increase in production volumes. Equity in Income of First Permian, L.P. As previously discussed in Note 8 to Financial Statements, First Permian, L.P. of which Parallel is a 30.675% interest owner sold all of their oil and gas properties in a transaction closing on April 8, 2002. Parallel received its prorata share of net proceeds, $5.5 million in cash and 933,589 shares of Energen Stock. Our share of the net income and distributions for the first nine months 2002 was $30,665,820. Change in Fair Market Value of Derivatives. The change in fair market value of derivatives increased $614,656 due to the increase in value in 2003. Interest and Other Income. Interest and other income increased $8,643, or 12% to $79,622 for the nine month period ended September 30, 2003 compared to $70,979 for the same period of 2002 due to increased cash balances associated with increased cash flow. Dividend Income. Dividend income in 2002 was $306,872 associated with the investment in Energen stock held for sale. Interest Expense. Interest expense increased $1,058,259 or 216%, to $1,547,940 for the nine months ended September 30, 2003 compared with $489,681 for the same period of 2002; due principally to increased bank borrowings associated with our acquisitions, partially offset by a decrease in the minimum interest rate under our revolving credit facility. The minimum interest rate decreased from 4.75% to 4.50% in December 2002. Loss on Sale of Marketable Securities. The loss of $928,540 recognized in marketable securities is for the sale of 492,400 shares of Energen stock during the nine months ended September 30, 2002. This is the difference in the April 8, 2002 stock price of $27.40 at the time of the sale of First Permian and the realized net price of approximately $25.51 received during the third quarter 2002. Income Tax Expense. For the nine months ended September 30, 2003 we recorded a tax expense of $2,893,202. Our effective tax rate for the nine months ended September 30, 2003 was 30%, which is less than the -19- <page> expected rate of 37% due to the recognition of state income tax, net operating loss carryover and certain federal income tax credits not previously recognized. For further discussion see Note 5. Net Income. We reported net income of $6,618,040 for the nine months ended September 30, 2003 compared to $18,494,836 for the nine months ended June 30, 2002. The decrease of $11,876,796 or 64% resulted from the gain on sale of First Permian, L.P. less related tax expense, and dividend income from the Energen stock in 2002. This was partially offset by operating income increasing $9,849,358 in 2003 due to increased volumes and higher product prices. Cash flow from operations for the nine months ended September 30, 2003 increased $8,981,306 or 168% to $14,324,468 compared with a net cash flow from operations of $5,343,162 for the nine months ended September 30, 2002 resulting from increased operating income. LIQUIDITY AND CAPITAL RESOURCES Our capital resources consist primarily of cash flows from our oil and gas properties and bank borrowings supported by our oil and gas reserves. Our level of earnings and cash flows depends on many factors, including the prices we receive for oil and natural gas we produce. Working capital decreased $2,151,784 as of September 30, 2003 compared with December 31, 2002. Current assets exceeded current liabilities by $6,387,599 at September 30, 2003. The working capital decrease was primarily due to the payments on our revolving debt facility and increased current maturity of derivative obligations. This was partially offset by the elimination of current maturities under our revolving credit facility, as amended on September 12, 2003. We incurred net property costs of $10,644,079 for the nine months ended September 30, 2003, primarily for our oil and gas property leasehold acquisition, development, and enhancement activities. Also added to our property basis were asset retirement costs of $1,236,511 for the adoption of SFAS 143 (see Note 10). The property leasehold acquisition, development and enhancement activities were financed by the utilization of cash flows provided by operations. Based on our projected oil and gas revenues and related expenses and available bank borrowings, we believe that we will have sufficient capital resources to fund normal operations and capital requirements, interest expense and principal reduction payments on bank debt, if required, and preferred stock dividends. We continually review and consider alternative methods of financing. Bank Borrowings On December 20, 2002, Parallel and its subsidiary, Parallel, L.P., entered into a First Amended and Restated Credit Agreement with First American Bank, SSB, Western National Bank and BNP Paribas. The credit facility provides for revolving loans. This means that we can borrow, repay and reborrow funds drawn under the credit facility. However, the aggregate amount that we can borrow and have outstanding at any one time is subject to a borrowing base. Generally, we can borrow only up to the borrowing base in effect from time to time. The borrowing base amount is redetermined by the banks on or about April 1 and October 1 of each year or at other times required by the banks or at our request. If, as a result of the banks' redetermination of the borrowing base, the outstanding principal amount of our loan exceeds the borrowing base, we must either provide additional collateral to the banks or prepay the principal of the note in an amount equal to the excess. Except for the principal payments that may be required because of our outstanding loans being in excess of the borrowing base, interest only is payable monthly. The credit agreement was amended in September 2003. The amendment included: . the deletion of the monthly commitment reduction, a provision that would have required us to begin amortizing our loan beginning August 31, 2003; . the modification of certain financial ratio tests; . an increase in our borrowing base to $50 million; . changes in certain reporting requirements to the banks; and . the revision of covenants in the credit agreement governing our hedging activities. -20- <page> The principal amount outstanding under the revolving credit facility bears interest at First American Bank's base rate or the libor rate, at our election. Generally, First American Bank's base rate is equal to the prime rate published in the Wall Street Journal, but not less than 4.50%. The libor rate is generally equal to the sum of (a) the rate designated as "British Bankers Association Interest Settlement Rates" and offered on one, two, three or six month interest periods for deposits of $1,000,000, and (b) a margin ranging from 2.25% to 2.75%, depending upon the outstanding principal amount of the loans. The interest rate we are required to pay, including the applicable margin, may never be less than 4.50%. If the principal amount outstanding is equal to or greater than 75% of the borrowing base established by the banks, the margin is 2.75%. If the principal amount outstanding is equal to or greater than 50%, but less than 75% of the borrowing base, the margin is 2.50%. If the principal amount outstanding is less than 50% of the borrowing base, the margin is 2.25%. In the case of base rate loans, interest is payable on the last day of each month. In the case of libor loans, interest is payable on the last day of each applicable interest period. If the total outstanding borrowings under the facility are less than the borrowing base, an unused commitment fee is required to be paid to the bank lenders. The amount of the fee is .25% of the daily average of the unadvanced amount of the borrowing base. The fee is payable quarterly. All outstanding principal under the revolving credit facility is due and payable on December 20, 2006. The loan is secured by substantially all of our oil and gas properties, including the properties of Parallel, L.P. Parallel, L.L.C., a subsidiary of Parallel Petroleum Corporation, guaranteed payment of the loans. We are highly dependent on bank borrowings to fund our exploration and drilling activities. Our borrowing base is generally equivalent to the loan value of our producing oil and gas properties as determined by the banks in their sole discretion. If our borrowing base declines significantly, our liquidity would be suddenly and materially limited. If the borrowing base is increased, we are required to pay a fee of ..25% on the amount of any increase in the borrowing base. Our obligations to the banks are secured by substantially all of our oil and gas properties. Our bank borrowings have been incurred to finance our property acquisition, 3-D seismic surveys, enhancement and drilling activities. In addition to customary affirmative covenants, the credit agreement contains various restrictive covenants and compliance requirements, including: . maintaining certain financial ratios; . limitations on incurring additional indebtedness; . prohibiting the payment of dividends on our common stock; . limitations on the disposition of assets; and . prohibiting liens (other than in favor of the banks) to exist on any of our properties. If we have borrowing capacity under our credit agreement, we intend to borrow, repay and reborrow under the revolving credit facility from time to time as necessary, subject to borrowing base limitations, to fund: . interpretation and processing of 3-D seismic survey data; . lease acquisitions and drilling activities; . acquisitions of producing properties or companies owning producing properties; and . general corporate purposes. -21- Preferred Stock At September 30, 2003 we had 974,500 shares of 6% convertible preferred stock outstanding. The preferred stock: . requires us to pay dividends of $.60 per annum, semi-annually on June 15 and December 15 of each year. . is convertible into common stock at any time, at the option of the holder, into 2.8751 shares of common stock at an initial conversion price of $3.50 per shares, subject to adjustment in certain events. . is redeemable at our option, in whole or in part, for $10 per share, plus accrued dividends. . has no voting rights, except as required by applicable law, and, except that as long as any shares of preferred stock remain outstanding, the holders of a majority of the outstanding shares of the preferred stock may vote on any proposal to change any provision of the preferred stock which materially and adversely affects the rights, preferences or privileges of the preferred stock. . is senior to the common stock with respect to dividends and on liquidation, dissolution or winding up of Parallel. . has a liquidation value of $10 per share, plus accrued and unpaid dividends. Commodity Price Risk Management Transactions Certain of our commodity price risk management arrangements have required us to deliver cash collateral or other assurances of performance to the counterparties in the event that our payment obligations with respect to our commodity price risk management transactions exceed certain levels. With the primary objective of achieving more predictable revenues and cash flows and reducing the exposure to fluctuations in oil and natural gas prices, we have entered into price risk management transactions of various kinds with respect to both oil and natural gas. While the use of certain of these price risk management arrangements limits the downside risk of adverse price movements, it may also limit future revenues from favorable price movements. We engage in transactions such as swaps and collars which are marked-to-market at the end of the relevant accounting period. Since the futures market historically has been highly volatile, these fluctuations may cause significant impact on the results of any given accounting period. We have entered into price risk management transactions with respect to a substantial portion of our estimated production for the remainder of 2003 through 2006. We continue to evaluate whether to enter into additional price risk management transactions for 2003 and future years. In addition, we may determine from time to time to unwind our then existing price management positions as part of our price risk management strategy. Future Capital Requirements Our capital expenditure budget is highly dependent on future oil and gas prices and the availability of funding. Our estimated capital budget for 2003 is anticipated to be approximately $14.0 million, of which approximately $10.6 million had been expended as of September 30, 2003. Additional capital expenditures in the estimated amount of $3.4 million are expected to be incurred during the remainder of 2003. These expenditures will be governed by the following factors: . internally generated cash flows; . availability of borrowing under our revolving credit facility; . additional sources of financing; and . future drilling successes. -22- <page> In 2003, we have focused on drilling lower risk natural gas prospects that could have a meaningful effect on our reserve base and cash flows. In selected cases, we may elect to reduce our interest in higher risk, higher impact projects. We may also sell certain non-core producing properties to raise funds for capital expenditures. The following table is a summary of significant contractual cash obligations: <table> Obligation Due in Period ---------------------------------------------------------- Contractual Cash Obligations 2003 2004 2005 2006 Total - ------------------------------------------------ ----------- ---------- ----------- ----------- ---------- (in 000's) <s> <c> <c> <c> <c> <c> Revolving Credit Facility (Secured) $ - $ - $ - $ 39,750 $ 39,750 Office Lease (Dinero Plaza) $ 102 $ 102 $ 102 $ 68 $ 374 Preferred Stock Dividends $ 585 $ 585 $ 585 $ 585 $ 2,340 </table> Outlook The oil and gas industry is capital intensive. We make, and anticipate that we will continue to make, substantial capital expenditures in the exploration for, development and acquisition of oil and gas reserves. Historically, our capital expenditures have been financed primarily with: . internally generated cash from operations; . proceeds from bank borrowings; and . proceeds from sales of equity securities. The continued availability of these capital sources depends upon a number of variables, including: . our proved reserves; . the volumes of oil and gas we produce from existing wells; . the prices at which we sell oil and gas; and . our ability to acquire, locate and produce new reserves. Each of these variables materially affects our borrowing capacity. We may from time to time seek additional financing in the form of: . increased bank borrowings; . sales of Parallel's securities; . sales of non-core properties; or . other forms of financing. We do not have agreements for any future financing and there can be no assurance as to the availability or terms of any such financing. Inflation Inflation has not had a significant impact on our financial condition or results of operations. We do not believe that inflation poses a material risk to our business. Recent Accounting Pronouncements SFAS No. 148, Accounting for Stock-Based Compensation-Transition and Disclosure, which amends SFAS No. 123, Accounting for Stock-Based Compensation. SFAS No. 148 provides alternative methods of transition for a -23- <page> voluntary change to the fair value based method of accounting for stock-based employee compensation. As of September 30, 2003, we adopted the Prospective method which applies prospectively the fair value recognition method to all employee and director awards granted, modified or settled after the beginning of the fiscal year in which the fair value based method of accounting for stock-based compensation is adopted. (See Note 2) SFAS 148 also amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The statement is required to be adopted for fiscal years ending after December 15, 2002. On April 22, 2003, the FASB announced its decision to require all companies to expense the value of employee stock options. Companies will be required to measure the cost according to the fair value of the options. The new guidelines have not been released to measure the cost according to the fair value of the options. Although the new guidelines have not been released, it is expected that they will be finalized and become effective in 2004. When final rules are announced, we will assess the impact to our consolidated financial statements. FIN No. 45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others, FIN No. 45 requires that a liability be recorded in the guarantor's balance sheet upon issuance of certain guarantees. Initial recognition and measurement of the liability will be applied on a prospective basis to guarantees issued or modified after December 31, 2002. FIN No. 45 also requires disclosures about guarantees in financial statements for interim or annual periods ending after December 15, 2002. We do not expect the adoption of FIN No. 45 to have a material impact on our consolidated financial statements. FIN No. 46, Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51. FIN No. 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without financial support from other parties. We do not expect the adoption of FIN No. 46 to have a material impact on our consolidated financial statements. In April 2003, the Financial Accounting Standards Board issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, which clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. The Statement is effective for contracts entered into or modified after June 20, 2003. We do not anticipate SFAS No. 149 will have a material effect on future earnings. In May 2003, the FASB issued Statement No. 150 "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity." This statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. This statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The adoption of FAS 150 did not have a material impact on our consolidated financial statements. Effects of Derivative Instruments For the year ended December 31, 2002, we used mark-to-market accounting for our hedge contracts. As of January 1, 2003 we adopted hedge accounting for the costless collars, oil and gas swaps, and interest rate swaps. We continued fair value accounting for our put positions described below. The purpose of our hedges is to provide a measure of stability in our oil and gas prices and interest rate payments and to manage exposure to commodity price and interest rate risk. Our objective is to lock in a range of oil and gas prices and a fixed interest rate for certain notional amounts. During the terms of a hedge, the quarterly change in the fair value of the derivatives is recorded in stockholders' equity as other comprehensive income (loss) and then transferred to earnings when the production is sold. Ineffective portions of hedges (changes in realized prices that do not match the changes in the hedge price) are recognized in earnings as they occur. While the hedge contract is open, the ineffective gain or loss may increase or decrease until settlement of the contract. -24- <page> We are exposed to credit risk in the event of nonperformance by the counterparty in its derivative instruments. However, we periodically assess the creditworthiness of the counterparty to mitigate this credit risk. See Note 7 to Consolidated Financial Statements. TRENDS AND PRICES Changes in oil and gas prices significantly affect our revenues, cash flows and borrowing capacity. Markets for oil and gas have historically been, and will continue to be, volatile. Prices for oil and gas typically fluctuate in response to relatively minor changes in supply and demand, market uncertainty, seasonal, political and other factors beyond our control. We are unable to accurately predict domestic or worldwide political events or the effects of other such factors on the prices we receive for our oil and gas. Please refer to Note 7 Derivative Instruments. Our capital expenditure budgets are highly dependent on future oil and gas prices and will be consistent with internally generated cash flows. During fiscal year 2002 the average realized sales price for our oil and natural gas was $21.03 per BOE. For the nine months ended September 30, 2003, our average realized price was $29.09 per BOE. FORWARD-LOOKING STATEMENTS In addition to historical information contained herein, this Form 10-Q Report contains forward-looking statements subject to various risks and uncertainties that could cause our actual results to differ materially from those in the forward-looking statements. Forward-looking statements can be identified by the use of forward-looking terminology such as "may", "will", "expect," "intend," "anticipate, "estimate," "continue," "present value," "future," "reserves" or other variations thereof or comparable terminology. Factors that could cause or contribute to such differences include, but are not limited to: . those relating to the results of exploratory drilling activity, . changes in oil and natural gas prices, . operating risks, . availability of drilling equipment, . outstanding indebtedness, . changes in interest rates, . dependence on weather conditions, . seasonality, . expansion and other activities of competitors, . changes in federal or state environmental laws and the administration of such laws, . the general condition of the economy and its effect on the securities markets. While we believe our forward-looking statements are based upon reasonable assumptions, these are factors that are difficult to predict and that are influenced by economic and other conditions beyond our control. Investors are urged to consider such risks and other uncertainties discussed in documents filed by us with the SEC. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Interest Rate Risk Our only financial instrument sensitive to changes in interest rates is our bank debt. Our annual interest costs in 2003 could fluctuate based on short-term interest rates. As the interest rate is variable and reflects current market conditions, the carrying value approximates the fair value. The table below shows principal cash flows and related weighted average interest rates by expected maturity dates. Weighted average interest rates were determined using weighted average interest paid and accrued in June 2003. -25- <table> December December December December 2003 2004 2005 2006 Total ------------- ------------ ------------ ------------ ------------- (In 000's, except interest rates) <s> <c> <c> <c> <c> <c> Variable rate debt: Revolving facility (secured) $ - $ - $ - $ 39,750 $ 39,750 Average interest rate (unhedged) 4.50% 4.50% 4.50% 4.50% - Average interest rate (hedged)(1) 4.425% 5.16% 6.30% 6.30% - </table> - --------------------- (1) Total of the libor fixed interest rate plus the expected margin rate under our revolving credit facility. Our credit agreement requires the interest rate to not be below 4.50%. At September 30, 2003, we had bank loans in the amount of $39,750,000 outstanding at an average interest rate of 4.50%. Borrowings under our revolving credit facility bear interest, at our election, at (i) the bank's base rate or (ii) the Eurodollar rate, plus 2.75%, but in no event less than 4.50%. As a result, our annual interest costs in 2003 could fluctuate based on short-term interest rates. Assuming no change in the amount outstanding during 2003, the impact on interest expense of a one-half of one percent change in the average interest rate above the 4.50% floor would be approximately $50,096 for the remainder of the year. As the interest rate is variable and is reflective of current market conditions, the carrying value approximates the fair value. We periodically hedge a portion of our interest rates to manage exposure to interest rate movements. In January 2003 we entered into several libor fixed rate swap contracts extending throughout our loan period. See Note 7. Commodity Price Risk Our major market risk exposure is in the pricing applicable to our oil and natural gas production. Market risk refers to the risk of loss from adverse changes in oil and natural gas prices. Realized pricing is primarily driven by the prevailing domestic price for crude oil and spot prices applicable to the region in which we produce natural gas. Historically, prices received for oil and gas production have been volatile and unpredictable. Pricing volatility is expected to continue. Oil prices ranged from a low of $22.93 per barrel to a high of $27.07 per barrel during 2002. Natural gas prices we received during 2002 ranged from a low of $1.35 per Mcf to a high of $4.18 per Mcf. During 2003 oil prices ranged from a low of $22.78 to a high of $35.95. Natural gas prices we received during 2003 ranged from a low of $1.98 per Mcf to a high of $10.28 per Mcf. A significant decline in the prices of natural gas or oil could have a material adverse effect on our financial condition and results of operations. We periodically hedge a portion of our oil and natural gas to manage exposure to commodity price risk under existing sales contracts. Our objective is to lock in a range of oil and gas prices. We try to meet this objective by entering into costless collars and swap hedge contracts. As of September 30, 2003, outstanding gas swap agreements and collars had a net fair value gain of $215,137. The aggregate effect of a hypothetical 10% change in gas prices would result in a change of approximately $194,059 in fair value of these swap agreements and collars at September 30, 2003. As of September 30, 2003, outstanding oil differential swaps had a net fair value loss of $2,693,474. The aggregate effect of a hypothetical 10% change in oil prices would result in a change of approximately $2,485,491 in the fair value of these oil differential swaps and collars at September 30, 2003. Because most of our swap agreements and collars are designated hedge derivatives, and to the extent the hedges are effective, changes in their fair value generally are reported as a component of accumulated other comprehensive income (loss) until the related sale of production occurs. At that time, the realized hedge derivative gain or loss is transferred to revenues in the consolidated income statement For the remainder of fiscal 2003 hedged oil and natural gas volumes represent approximately 69% and 44% respectively of expected production from October thru December 2003. Please read Note 7 to our Financial Statements for additional information about market risks. ITEM 4. CONTROLS AND PROCEDURES As of the end of the period covered by this Quarterly Report on Form 10-Q, the effectiveness of our disclosure controls and procedures was evaluated by our management, with the participation of our chief executive officer, Thomas R. Cambridge (principal executive officer), and our chief financial officer, Steven D. Foster (principal financial officer). Our disclosure controls and procedures are designed to help ensure that information we are required to disclose in reports that we file with the SEC is accumulated and communicated to our management and recorded, -26- <page> processed, summarized and reported within the time periods prescribed by the SEC. Mr. Cambridge and Mr. Foster have concluded that our disclosure controls and procedures are effective for their intended purposes. There were no changes in internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. PART II - OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS At September 30, 2003, we were involved in two lawsuits incidental to our business. We accrue for such items when a liability is both probable and the amount can be reasonably estimated. We do not believe the ultimate outcome of these lawsuits will have a material adverse effect on our financial position or results of operations. We are not aware of any threatened litigation. We have not been a party to any bankruptcy, receivership, reorganization, adjustment or similar proceeding. ITEM 6. EXHIBIT AND REPORTS ON FORM 8-K (a) Exhibits No. Description of Exhibit ---- ----------------------- 3.1 Certificate of Incorporation of Registrant (incorporated by reference to Exhibit 3.1 to Form 10-K of the Registrant for the fiscal year ended December 31, 1998.) 3.2 Bylaws of Registrant (Incorporated by reference to Exhibit 3 to the Registrant's Form 8-K, dated October 9, 2000, as filed with the Securities and Exchange Commission on October 10, 2000.) 4.1 Certificate of Designations, Preferences and Rights of Serial Preferred Stock - 6% Convertible Preferred Stock (Incorporated by reference to Exhibit 4.1 to Form 10-Q of the Registrant for the fiscal quarter ended September 30, 1998.) 4.2 Certificate of Designation, Preferences and Rights of Series A Preferred Stock. (Incorporated by reference to Exhibit 4.2 of Form 10-K for the fiscal year ended December 31, 2000.) 4.3 Rights Agreement, dated as of October 5, 2000, between the Registrant and Computershare Trust Company, Inc., as Rights Agent. (Incorporated by reference to Exhibit 4.3 of Form 10-K for the fiscal year ended December 31, 2000.) Executive Compensation Plans and Arrangements (Exhibit No.'s ------------------------------------------------------------ 10.1 through 10.9): ------------------ 10.1 1983 Incentive Stock Option Plan (Incorporated by reference to Exhibit 10.2 to Form S-l of the Registrant (File No. 2-92397) as filed with the Securities and Exchange Commission on July 26, 1984, as amended by Amendments No. 1 and 2 on October 5, 1984, and October 25, 1984, respectively.) 10.2 1992 Stock Option Plan (Incorporated by reference to Exhibit 28.1 to Form S-8 of the Registrant (File No. 33-57348) as filed with the Securities and Exchange Commission on January 25, 1993.) 10.3 Stock Option Agreement between the Registrant and Thomas R. Cambridge dated December 11, 1991 (Incorporated by reference to Exhibit 10.4 of Form 10-K of the Registrant for the fiscal year ended December 31, 1992.) -27- <page> 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.) -28- <page> 10.17 Certificate of Merger of First Permian, L.L.C. and Nash Oil Company, L.L.C (Incorporated by reference to Exhibit 10.5 of the Registrant's Form 8-K Report dated June 30, 1999.) 10.18 Amended and Restated Limited Liability Company Agreement of First Permian, L.L.C. dated as of May 31, 2000. (Incorporated by reference to Exhibit 10.16 of Form 10-K for the fiscal year ended December 31, 2000.) 10.19 Credit Agreement dated June 30, 1999, by and among First Permian, L.L.C., Parallel Petroleum Corporation, Baytech, Inc., and Bank One, Texas, N.A. (Incorporated by reference to Exhibit 10.6 of the Registrant's Form 8-K report dated June 30, 1999.) 10.20 Limited Guaranty, dated June 30, 1999, by and among First Permian, L.L.C., Parallel Petroleum Corporation, and Bank One, Texas, N.A. (Incorporated by reference to Exhibit 10.7 of the Registrant's Form 8-K report dated June 30, 1999.) 10.21 Intercreditor Agreement, dated as of June 30, 1999, by and among First Permian, L.L.C., Bank One, Texas, N.A., Tejon Exploration Company, and Mansefeldt Investment Corporation (Incorporated by reference to Exhibit 10.8 of the Registrant's Form 8-K report dated June 30, 1999.) 10.22 Subordinated Promissory Note, dated June 30, 1999, in the original principal amount of $8.0 million made by First Permian, L.L.C. payable to the order of Tejon Exploration Company (Incorporated by reference to Exhibit 10.9 of the Registrant's Form 8-K report dated June 30, 1999.) 10.23 Subordinated Promissory Note, dated June 30, 1999, in the original principal amount of $8.0 million made by First Permian, L.L.C. payable to the order of Mansefeldt Investment Corporation (Incorporated by reference to Exhibit 10.10 of the Registrant's Form 8-K report dated June 30, 1999.) 10.24 Second Restated Credit Agreement, dated October 25, 2000, among First Permian, L.L.C., Bank One, Texas, N.A., and Bank One Capital Markets, Inc. (Incorporated by reference to Exhibit 10.22 of Form 10-K for the fiscal year ended December 31, 2000.) 10.25 Loan Agreement, dated January 25, 2002, between the Registrant and First American Bank, SSB (Incorporated by reference to Exhibit 10.25 of Form 10-K for the fiscal year ended December 31, 2001.) 10.26 Purchase and Sale Agreement, dated as of November 27, 2002, among JMC Exploration, Inc., Arkoma Star L.L.C., Parallel, L.P. and Texland Petroleum, Inc. (Incorporated by reference to Exhibit 10.1 of Form 8-K of the Registrant, dated December 20, 2002) 10.27 First Amended and Restated Credit Agreement, dated December 20, 2002, by and among Parallel Petroleum Corporation, Parallel, L.P. Parallel, L.L.C., First American Bank, SSB, Western National Bank and BNP Paribas (Incorporated by reference to Exhibit 10.2 of Form 8-K of the Registrant, dated December 20, 2002) 10.28 Guaranty dated December 20, 2002, between Parallel, L.L.C. and First American Bank, SSB, as Agent (Incorporated by reference to Exhibit 10.3 of Form 8-K of the Registrant, dated December 20, 2002) *10.29 First Amendment to First Amended and Restated Credit Agreement, dated as of September 12, 2003, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American, SSB, Western National Bank, and BNP Paribas -29- <page> 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. - ------------------ * Filed herewith. (b) Reports on Form 8-K During the fiscal quarter ended September 30, 2003, we filed one report on Form 8-K. On August 14, 2003, we filed Form 8-K, dated August 14, 2003, reporting matters furnished under Item 9 - Regulation FD Disclosure, and Item 12 - Disclosure of Results of Operations and Financial Condition. This report included our August 14, 2003 press release announcing our results of operations and financial condition for the second quarter ended June 30, 2003. -30- SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. PARALLEL PETROLEUM CORPORATION BY: /s/ Thomas R. Cambridge Date: October 30, 2003 --------------------------------------- Thomas R. Cambridge Chairman of the Board of Directors and Chief Executive Officer Date: October 30, 2003 BY: /s/ Steven D. Foster --------------------------------------- Steven D. Foster, Chief Financial Officer -31- 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.) <page> 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.) <page> 10.21 Intercreditor Agreement, dated as of June 30, 1999, by and among First Permian, L.L.C., Bank One, Texas, N.A., Tejon Exploration Company, and Mansefeldt Investment Corporation (Incorporated by reference to Exhibit 10.8 of the Registrant's Form 8-K report dated June 30, 1999.) 10.22 Subordinated Promissory Note, dated June 30, 1999, in the original principal amount of $8.0 million made by First Permian, L.L.C. payable to the order of Tejon Exploration Company (Incorporated by reference to Exhibit 10.9 of the Registrant's Form 8-K report dated June 30, 1999.) 10.23 Subordinated Promissory Note, dated June 30, 1999, in the original principal amount of $8.0 million made by First Permian, L.L.C. payable to the order of Mansefeldt Investment Corporation (Incorporated by reference to Exhibit 10.10 of the Registrant's Form 8-K report dated June 30, 1999.) 10.24 Second Restated Credit Agreement, dated October 25, 2000, among First Permian, L.L.C., Bank One, Texas, N.A., and Bank One Capital Markets, Inc. (Incorporated by reference to Exhibit 10.22 of Form 10-K for the fiscal year ended December 31, 2000.) 10.25 Loan Agreement, dated January 25, 2002, between the Registrant and First American Bank, SSB (Incorporated by reference to Exhibit 10.25 of Form 10-K for the fiscal year ended December 31, 2001.) 10.26 Purchase and Sale Agreement, dated as of November 27, 2002, among JMC Exploration, Inc., Arkoma Star L.L.C., Parallel, L.P. and Texland Petroleum, Inc. (Incorporated by reference to Exhibit 10.1 of Form 8-K of the Registrant, dated December 20, 2002) 10.27 First Amended and Restated Credit Agreement, dated December 20, 2002, by and among Parallel Petroleum Corporation, Parallel, L.P. Parallel, L.L.C., First American Bank, SSB, Western National Bank and BNP Paribas (Incorporated by reference to Exhibit 10.2 of Form 8-K of the Registrant, dated December 20, 2002) 10.28 Guaranty dated December 20, 2002, between Parallel, L.L.C. and First American Bank, SSB, as Agent (Incorporated by reference to Exhibit 10.3 of Form 8-K of the Registrant, dated December 20, 2002) *10.29 First Amendment to First Amended and Restated Credit Agreement, dated as of September 12, 2003, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American, SSB, Western National Bank, and BNP Paribas 21 Subsidiaries (Incorporated by reference to Exhibit 21 of Form 10-K of the Registrant for the fiscal year ended December 31, 2002) *31.1 Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002. *31.2 Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002. *32.1 Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002. *32.2 Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002. - --------------- *File herewith. Exhibit 10.29 FIRST AMENDMENT TO FIRST AMENDED AND RESTATED CREDIT AGREEMENT This First Amendment to First Amended and Restated Credit Agreement (this "First Amendment") dated as of September 12, 2003, is by and among PARALLEL PETROLEUM CORPORATION, a Delaware corporation, and PARALLEL, L.P., a Texas limited partnership (collectively, the "Borrowers"), and PARALLEL, L.L.C., a Delaware limited liability company ("Guarantor"), and FIRST AMERICAN BANK, SSB, BNP PARIBAS AND WESTERN NATIONAL BANK (collectively, "Lenders"), and FIRST AMERICAN BANK, SSB, as Joint Lead Arranger and as Administrative Agent ("Agent") and BNP PARIBAS, as Joint Lead Arranger and as Syndication Agent. RECITALS: WHERAS, Borrowers, Guarantor and Lenders in the capacities stated above, entered into that First Amended and Restated Credit Agreement dated as of December 20, 2002 (the "Credit Agreement"); and WHEREAS, Borrowers, Guarantor and Lenders desire to amend the Credit Agreement in certain respects. NOW, THEREFORE, in consideration of the mutual covenants and agreements contained herein and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged and confessed, the parties hereto agree as follows: Agreement Section 1. Definitions. Except as otherwise expressly provided herein, all terms defined in the Credit Agreement shall have the same meanings herein. Section 2. Deletion of Monthly Commitment Reductions. The parties to the Credit Agreement have agreed to delete the Monthly Commitment Reduction requirement set forth in the Credit Agreement, and in connection therewith (a) Section 2(g)(ii) of the Credit Agreement is hereby deleted in its entirety, (b) all references in the Credit Agreement to the "Monthly Commitment Reduction" or the "Monthly Commitment Reductions" are hereby deleted, and (c) all text in the Credit Agreement associated with use of the terms "Monthly Commitment Reduction" and "Monthly Commitment Reductions" is hereby deleted to the extent and only to the extent such text relates solely to the Monthly Commitment Reductions. Section 3. Additional Definitions. Section 1 of the Credit Agreement is hereby amended to add the following definitions in alphabetical order: Consolidated EBITDA means for any period, PPC's consolidated earnings during such period from continuing operations, before provision for interest expenses, income taxes, depreciation, depletion, amortization, gains and losses on asset sales and other non-cash charges. Consolidated Funded Debt means as of any date, PPC's total outstanding liabilities for borrowed money and other interest-bearing liabilities on such date, determined in each case on a consolidated basis in accordance with GAAP. Section 4. Deletion of Certain Definitions. The defined terms "Consolidated Cash Flow", "Consolidated Net Income", "Debt Service Coverage Ratio" and "Monthly Commitment Reduction" in Section 1 of the Credit Agreement are hereby deleted in their entirety. -1- <page> Section 5. Amendment to Semi-Annual Determination Dates. The first sentence of Section 7(b)(i) of the Credit Agreement is hereby amended in its entirety to read as follows: Subsequent determinations of the Borrowing Base shall be made by Lenders semi-annually on or about April 1 and October 1 of each year beginning April 1, 2004, or as Unscheduled Redeterminations. Section 6. Amendment to Borrowing Base Evaluation Factors. Section 7(e)(i) of the Credit Agreement is hereby amended in its entirety to read as follows: (i) Oil and Gas Properties. No later than March 1 and September 1 of each year, beginning March 1, 2004, Borrowers shall, at their own expense, furnish to Lenders an engineering report covering the Oil and Gas Properties in form and substance satisfactory to Agent and dated effective not more than sixty (60) days prior to the delivery of the same to Lenders. Each such report shall be prepared by an independent petroleum engineering firm acceptable to Agent, utilizing economic pricing parameters used by .Agent as established from time to time, together with such other information, reports and data concerning the value of the Oil and Gas Properties as Agent shall deem reasonably necessary to determine the value of such Oil and Gas Properties. Each Lender shall determine the amount of the Borrowing Base attributable to the Oil and Gas Properties based upon the loan collateral value which such Lender in its discretion (using such methodology, assumptions and discount rates as such Lender customarily uses in assigning collateral value to oil and gas properties, oil and gas gathering systems, gas processing and plant operations) assigns to such Oil and Gas Properties at the time in question and based upon such other credit factors consistently applied (including, without limitation, the assets, liabilities, cash flows, business, properties, prospects, management and ownership of Borrowers and their Affiliates) as such Lender customarily considers in evaluating similar oil and gas credits. Section 7. Amendment to Reporting Requirements. Sections 12(a)(i), (ii) and (iii) of the Credit Agreement are hereby amended in their entirety to read as follows: (i) Annual Audited Financial Statements. As soon*as available, and in any event within ninety (90) days after the end of each fiscal year of PPC (x) the annual audited consolidated Financial Statements of PPC, prepared in accordance with GAAP accompanied by an unqualified opinion on such Financial Statements rendered by KPMG LLP or another independent accounting firm reasonably acceptable to the Agent, and (y) the annual unaudited consolidating Financial Statements of PPC prepared in accordance with GAAP; (ii) Quarterly Financial Statements. As soon as available, and in any event within forty-five (45) days after the end of each fiscal quarter of PPC, the quarterly unaudited consolidated and consolidating Financial Statements of PPC prepared in accordance with GAAP; (iii) Report on Properties. As soon as available and in any event on or before March 1, 2004, and thereafter on or before March 1 and September 1 of each calendar year, and at such other times as any Lender, in accordance with Section 7 hereof, may request, the engineering reports required to be furnished to the Agent under such Section 7 on the Oil and Gas Properties; Section 8. Amendment to Crude Oil Hedging Covenant. Section 12(w) of the Credit Agreement is hereby amended by adding at the end thereof the following sentence: (w) Crude Oil Hedging. Each of the foregoing hedging requirements shall be based upon the then most current reserve evaluation delivered by Borrowers to Agent pursuant to Section 12(a)(iii) above, and Borrowers shall be in compliance with the required volumes to be -2- <page> hedged within ninety (90) days after the effective date of each such most current reserve evaluation. Section 9. Deletion of Debt Service Coverage Ratio and Addition of new Funded Debt Ratio. Section 13(c) of the Credit Agreement is hereby amended in its entirety to read as follows: (c) Funded Debt Ratio. PPC will not allow its ratio of Consolidated Funded Debt to Consolidated EBITDA to exceed 3.00 to 1.00. This ratio shall be calculated at the end of each fiscal quarter of PPC beginning on September 30, 2003, using the results of the twelve-month period immediately preceding the end of each such fiscal quarter. Section 10. Amendment to Rate Management Transactions Covenant. Section 13(1) of the Credit Agreement is hereby amended in its entirety to read as follows: (1) Neither either Borrower nor Guarantor will, and will not permit any Subsidiary to, enter into any Rate Management Transactions, except the foregoing prohibitions shall not apply to (x) transactions required by this Agreement or consented to in writing by the Majority Lenders, in each case which are on terms acceptable to the Majority Lenders, or (y) transactions by Borrowers designed to hedge, provide a floor price for, or swap crude oil or natural gas, provided that (i) the same do not cover more than seventy-five percent (75%) of Borrowers' aggregate estimated production from proved producing reserves existing as of the date of the execution thereof based upon the then most current reserve evaluation required pursuant to Section 12(a)(iii) above, (ii) the same do not contain terms or provisions which would require margin calls, (iii) the counterparty to any such transaction has a minimum rating of "A-1" by Standard & Poors' Corporation or "A-3" by Moody's Investors Service, Inc., (iv) the same are for a term of twenty-four (24) months or less, and (v) the same include provisions for payment to Borrowers upon the occurrence of specified price indexes of a price per unit of measurement equal to or greater than that under the Agent's then current pricing policies; or, provided that (A) the same do not cover more than ninety percent (90%) of Borrowers' aggregate estimated production from proved producing reserves existing as of the date of the execution thereof based upon the then most current reserve evaluation required pursuant to Section 12(a)(iii) above, (B) the same do not cover more than seventy-five percent (75%) of Borrowers' aggregate estimated production from all categories of proved reserves existing as of the date of the execution thereof based upon the then most current reserve evaluation required pursuant to Section 12(a)(iii) above, (C) as of the date of the execution thereof, Borrowers' aggregate actual production from proved producing reserves exceeds Borrowers' aggregate forecasted production from proved producing reserves for such date based on the then most current reserve evaluation required pursuant to Section 12(a)(iii) above, (D) the same are for a term of twelve (12) months or less, and (E) the same satisfy the requirements set forth in items (ii), (iii) and (v) above. Section 11. Amendment to Exhibit "D". Paragraph (d)(ii) of the Certificate of Compliance attached to the Credit Agreement as Exhibit "D" is hereby amended in its entirety to read as follows: (ii) Funded Debt Ratio; and Section 12. Redetermination of Borrowing Base. In accordance with Section 7(b) of the Credit Agreement, a semi-annual redetermination of the Borrowing Base has been made by Lenders. Pursuant to Section 7(b) of the Credit Agreement, Agent hereby notifies you that the Lenders have redetermined the Borrowing Base and, effective as of the date of this First Amendment, the redetermined Borrowing Base is $50,000,000. Section 13. Global Amendment of Loan Documents. All of the Loan Documents are hereby modified wherever necessary, and even though not specifically addressed herein, so as to conform to the amendments to the Credit Agreement as set forth herein, and the Borrowers and the Guarantor covenant to observe, comply with and perform each of the terms and provisions of the Loan Documents to which they are parties, as modified hereby. Each -3- <page> Loan Document to which Borrowers or Guarantor is a party is hereby amended so that any reference in each such Loan Document to the Credit Agreement shall mean a reference to the Credit Agreement as amended hereby. Section 14. Representations and Warranties of Borrowers and Guarantor. Borrowers and Guarantor hereby jointly and severally represent and warrant to Lenders as follows: (a) The representations and warranties contained in Section 10 of the Credit Agreement are true and correct on and as of the date hereof as though made on and as of the date hereof, except for those representations and warranties which address matters only as of a particular date (which remain true and correct as of such date). (b) No Event of Default or Default has occurred and is continuing under the Credit Agreement. (c) The execution, delivery and performance by Borrowers and Guarantor of this First Amendment are within the Borrowers' and Guarantor's partnership, corporate and limited liability company powers, have been duly authorized by all necessary action, require no action by or in respect of, or filing with, any governmental body, agency or official and do not violate or constitute a default under any provisions of applicable law or any material agreement binding upon Borrowers, Guarantor or their respective Subsidiaries or result in the creation or imposition of any Lien upon any of the assets of Borrowers, Guarantor or their respective Subsidiaries, except Permitted Liens. (d) This First Amendment constitutes the valid and binding obligation of Borrowers and Guarantor enforceable in accordance with its terms except as (i) the enforceability thereof may be limited by bankruptcy, insolvency or similar laws affecting creditor's rights generally, and (ii) the availability of equitable remedies may be limited by equitable principles of general application. Section 15. Conditions Precedent. This First Amendment shall be effective as of the date upon which all of the following conditions have been satisfied: (a) the Agent shall have received counterparts of this First Amendment duly executed by Borrowers, Guarantor and Lenders; (b) the Agent shall have received from Borrowers for the ratable benefit of Lenders the fees required by Section 8(b) of the Credit Agreement; (c) the Borrowers and Guarantor shall have provided to Agent (i) a copy of resolutions, in form and substance satisfactory to Agent, of the Board of Directors of PPC authorizing the execution, delivery and performance of this First Amendment and any other Loan Documents to be executed or delivered pursuant hereby, certified by the secretary or an assistant secretary of PPC, which certificate shall be in form and substance satisfactory to Agent and Agent's counsel and shall state that the resolutions thereby certified have not been amended, modified, revoked or rescinded, (ii) a copy of the resolutions, in form and substance satisfactory to Agent, duly adopted by the respective partners of PLP authorizing the execution, delivery and performance of this First Amendment and any other Loan Documents to be executed or delivered by PLP pursuant hereto, certified by PLP's general partner, which certificate shall be in form and substance satisfactory to Agent and Agent's counsel and shall state that the resolutions thereby certified have not been amended, modified, revoked or rescinded, and (iii) resolutions, in form and substance satisfactory to Agent, of the members of Guarantor authorizing the execution, delivery and performance of this First Amendment and any other Loan Documents to be executed or delivered pursuant hereto, certified by its secretary or assistant secretary, which certificate shall be in form and substance satisfactory to Agent and Agent's counsel and shall state that the resolutions thereby certified have not been amended, modified, revoked or rescinded; and (d) Agent shall have received any other documents, certificates and opinions in connection -4- <page> with this First Amendment that may be requested by Agent, in form and substance satisfactory to Agent. Section 16. Ratification of Credit Agreement and Other Loan Documents. Except as expressly amended hereby, the Credit Agreement and all of the other Loan Documents are and shall be unchanged and all of the terms, provisions, covenants, conditions, schedules and exhibits thereof shall remain and continue in full force and effect and are hereby ratified and confirmed by Borrowers, Guarantor and Lenders as of the date of this First Amendment as if the Credit Agreement and the other Loan Documents were executed by Borrowers, Guarantor and the other parties thereto as of the date of this First Amendment. The amendments contemplated hereby shall not limit or impair any Liens securing the Loans, each of which are hereby ratified, affirmed and extended to secure the Loans as they may be increased pursuant hereto. Section 17. No Waiver. Neither the execution by Lenders of this First Amendment nor anything contained herein shall in anywise be construed or operate as a waiver by Lenders of any Default of Event of Default (whether now existing or that may occur hereafter) or of any of Lenders' or Agent's rights under the Credit Agreement as amended hereby or under any of the other Loan Documents. Section 18. Miscellaneous. 18.1 Legal Expenses. The Borrowers hereby agree to pay on demand all reasonable fees and expenses of counsel to the Agent incurred by the Agent in connection with the preparation, negotiation and execution of this First Amendment and all related documents. 18.2 Multiple Counterparts. Multiple counterparts of this First Amendment may be signed by the parties hereto (including by facsimile transmission), each of which shall be an original but all of which together shall constitute but one and the same instrument. 18.3 Reference to Agreement. Each of the Loan Documents is hereby amended so that any reference in the Loan Documents to the Credit Agreement shall mean a reference to the Credit Agreement as amended hereby. 18.4 Governing Law. This First Amendment is being executed and delivered, and is intended to be performed, in Midland, Midland County, Texas, and the substantive laws of Texas shall govern the validity, construction, enforcement and interpretation of this First Amendment and all other documents and instruments referred to herein, unless otherwise specified therein. 18.5 Plural and Singular Forms. The definitions given to terms defined hereby shall be equally applicable to both the singular and plural forms of such terms. 18.6 Final Agreement. THIS FIRST AMENDMENT, THE CREDIT AGREEMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES. IN WITNESS THEREOF, Borrowers, Guarantor and Lenders have caused this First Amendment to be duly executed as of the day and year first above written. BORROWERS: PARALLEL PETROLEUM CORPORATION, a Delaware corporation By: /s/ Larry C. Oldham ------------------------------- Larry C. Oldham, President -5- <page> PARALLEL, L.P., a Texas limited partnership By: Parallel Petroleum Corporation, Its General Partner By: /s/ Larry C. Oldham --------------------------- Larry C. Oldham, President GUARANTOR: PARALLEL, L.L.C., a Delaware limited liability company By: /s/ David R. Hancock --------------------------- David R. Hancock, President LENDERS: FIRST AMERICAN BANK, SSB, a state savings bank, as Joint Lead Arranger and Administrative Agent and as a Lender By: /s/ Frank K. Stowers --------------------------- Frank K. Stowers Senior Vice President BNP PARIBAS, as Joint Lead Arranger and Syndication Agent and as a Lender By: /s/ Brian M. Malone --------------------------- Brian M. Malone Managing Director By: /s/ Polly Schott --------------------------- Polly Schott Vice President WESTERN NATIONAL BANK, as a Lender By: /s/ Wesley D. Bownds --------------------------- Wesley D. Bownds Executive Vice President -6- Exhibit 31.1 CERTIFICATION I, Thomas R. Cambridge, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Parallel Petroleum Corporation: 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report. 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: October 30, 2003 /s/ Thomas R. Cambridge ----------------------------- Thomas R. Cambridge Chief Executive Officer Exhibit 31.2 CERTIFICATION I, Steven D. Foster, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Parallel Petroleum Corporation: 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report. 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: October 30, 2003 /s/ Steven D. Foster ----------------------------- Steven D. Foster Chief Financial Officer Exhibit 32.1 CERTIFICATION (Not filed pursuant to the Securities Exchange Act of 1934) Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002, the undersigned, Thomas R. Cambridge, the Chairman of the Board of Directors and Chief Executive Officer of Parallel Petroleum Corporation ("Parallel"), hereby certifies that the Quarterly Report on Form 10-Q of Parallel for the quarter ended September 30, 2003 fully complies with the periodic reporting requirements of the Securities Exchange Act of 1934, as amended, and the information contained in that Form 10-Q Report fairly presents, in all material respects, the financial condition and results of operations of Parallel. Dated: October 30, 2003 /s/ Thomas R. Cambridge ------------------------------- Thomas R. Cambridge, Chairman of the Board of Directors and Chief Executive Officer A signed original of this written statement required by Section 906 has been provided to Parallel Petroleum Corporation and will be retained by Parallel Petroleum Corporation and furnished to the Securities Exchange Commission or its staff upon request. Exhibit 32.2 CERTIFICATION (Not filed pursuant to the Securities Exchange Act of 1934) Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002, the undersigned, Steven D. Foster, the Chief Financial Officer of Parallel Petroleum Corporation ("Parallel"), hereby certifies that the Quarterly Report on Form 10-Q of Parallel for the quarter ended September 30, 2003 fully complies with the periodic reporting requirements of the Securities Exchange Act of 1934, as amended, and the information contained in that Form 10-Q Report fairly presents, in all material respects, the financial condition and results of operations of Parallel. Dated: October 30, 2003 /s/ Steven D. Foster --------------------------------- Steven D. Foster, Chief Financial Officer A signed original of this written statement required by Section 906 has been provided to Parallel Petroleum Corporation and will be retained by Parallel Petroleum Corporation and furnished to the Securities Exchange Commission or its staff upon request.