Edgar Filing: PARALLEL PETROLEUM CORP

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C. 20549

FORM 10-Q

(Mark One)

/X/

Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended June 30, 2005 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	(I.R.S. Employer Identification
of incorporation or organization)	Number)

1004 N. Big Spring, Suite 400	79701
Midland, Texas	(Zip Code)
(Address of principal executive offices)

(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

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

Yes

At August 1, 2005, 34,025,168 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 June 30, 2005 (unaudited) and December 31, 2004		1

	-	Unaudited Consolidated Statements of Income for the three months and six months
		ended June 30, 2005 and 2004		2

	-	Unaudited Consolidated Statements of Cash Flows for the six months ended June 30,
		2005 and 2004		3

	-	Unaudited Consolidated Statements of Comprehensive Income (Loss) for the three
		months and six months ended June 30, 2005 and 2004		4

	-	Notes to Consolidated Financial Statements		5

ITEM 2.		MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
		CONDITION AND RESULTS OF OPERATIONS		12

ITEM 3.		QUANTITATIVE AND QUALITATIVE DISCLOSURES
		ABOUT MARKET RISK		29

ITEM 4.		CONTROLS AND PROCEDURES		31

		PART II -- OTHER INFORMATION

ITEM 1.		LEGAL PROCEEDINGS		32

ITEM 2.		UNREGISTERED SALES OF EQUITY SECURITIES
		AND USE OF PROCEEDS		32

ITEM 4.		SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS		32

ITEM 6.		EXHIBITS		33

		SIGNATURES

(i)

PARALLEL PETROLEUM CORPORATION
Consolidated Balance Sheets
(dollars in thousands)

		June 30,			December 31,
Assets		2005			2004
		(unaudited)
Current assets:
Cash and cash equivalents	$	3,756		$	4,781
Accounts receivable:
Oil and gas		7,866			6,642
Other, net of allowance for doubtful account of $9		1,256			389
Affiliates		7			7
		9,129			7,038
Other current assets		225			179
Deferred tax asset		4,997			2,531
Total current assets		18,107			14,529
Property and equipment, at cost:
Oil and gas properties, full cost method (including $14,115 and $9,526 not
subject to depletion)		251,913			229,245
Other		2,361			2,062
		254,274			231,307
Less accumulated depreciation, depletion and amortization		(83,837	)		(78,782	)
Net property and equipment		170,437			152,525
Restricted cash		149			2,287
Investment in Westfork Pipeline Company LP		1,572			595
Other assets, net of accumulated amortization of $724 and $581		612			735
	$	190,877		$	170,671
Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable and accrued liabilities	$	7,368		$	5,568
Asset retirement obligations		133			150
Derivative obligations		16,322			7,965
Total current liabilities		23,823			13,683
Revolving credit facility		62,000			79,000
Asset retirement obligations		2,118			1,982
Derivative obligations		27,209			9,525
Deferred tax liability		1,780			6,487
Total long-term liabilities		93,107			96,994
Commitments and contingencies
Stockholders' equity:
Series A preferred stock -- par value $0.10 per share, authorized 50,000 shares		—			—
Preferred stock -- 6% convertible preferred stock -- par value of $0.10 per share
(liquidation preference of $10 per share), authorized 10,000,000 shares,
issued and outstanding 950,000, converted to common stock June, 2005		—			95
Common stock -- par value $0.01 per share, authorized 60,000,000 shares,
issued and outstanding 34,013,572 and 25,439,292		340			254
Additional paid-in capital		76,528			48,328
Retained earnings		22,705			22,073
Accumulated other comprehensive loss		(25,626	)		(10,756	)
Total stockholders' equity		73,947			59,994
	$	190,877		$	170,671

The accompanying notes are an integral part of these Consolidated Financial Statements.

PARALLEL PETROLEUM CORPORATION
Consolidated Statements of Income
(unaudited)
(in thousands, except per share data)


		Three Months Ended June 30,						Six Months Ended June 30,
		2005			2004			2005			2004
Oil and Natural Gas Revenues:
Oil and natural gas sales	$	15,004		$	9,752		$	27,973		$	18,858
Loss on hedging and derivatives		(3,645	)		(1,835	)		(6,857	)		(2,940	)
Total revenues		11,359			7,917			21,116			15,918


Cost and expenses:
Lease operating expense		2,178			2,014			4,736			3,543
Production taxes		701			471			1,281			949
General and administrative		1,466			1,221			3,154			2,443
Depreciation, depletion and amortization		2,773			1,969			5,055			4,046
Total costs and expenses		7,118			5,675			14,226			10,981
Operating income		4,241			2,242			6,890			4,937

Other income (expense), net:
Gain (loss) on ineffective portion of hedges		(1,235	)		17			(3,511	)		7
Interest and other income		22			18			41			158
Interest expense		(796	)		(487	)		(1,934	)		(955	)
Other expense		(1	)		(59	)		(2	)		(85	)
Equity in loss of Westfork Pipeline Company LP		(15	)		—			(94	)		—
Total other expense, net		(2,025	)		(511	)		(5,500	)		(875	)
Income before income taxes		2,216			1,731			1,390			4,062
Income tax expense, deferred		(763	)		(628	)		(487	)		(1,477	)
Net income		1,453			1,103			903			2,585
Cumulative preferred stock dividend		(128	)		(144	)		(271	)		(287	)
Net income available to common stockholders	$	1,325		$	959		$	632		$	2,298

Net income per common share:
Basic	$	0.04		$	0.04		$	0.02		$	0.09
Diluted	$	0.04		$	0.04		$	0.03		$	0.09

Weighted average common share outstanding:
Basic		31,967			25,246			30,341			25,235
Diluted		34,682			28,330			33,355			28,296


The accompanying notes are an integral part of these Consolidated Financial Statements.

PARALLEL PETROLEUM CORPORATION
Consolidated Statements of Cash Flows
Six Months Ended June 30, 2005 and 2004
(unaudited)
(dollars in thousands)

		2005			2004
Cash flows from operating activities:
Net income	$	903		$	2,585

Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization		5,055			4,046
Accretion of asset retirement obligation		54			53
Deferred income tax expense		487			1,477
Loss (gain) on ineffective portion of hedges		3,511			(7	)
Stock option expense		70			84
Equity in loss of Westfork Pipeline Company, LP		94			—
Changes in assets and liabilities:
Increase in accounts receivable		(2,091	)		(507	)
Increase in other current assets		(46	)		(87	)
Other, net		123			(141	)
Restricted cash		(149	)		—
Increase in accounts payable and accrued liabilities		1,800			1,084
Net cash provided by operating activities		9,811			8,587

Cash flows from investing activities:
Additions to oil and gas properties		(25,431	)		(14,590	)
Restricted cash		2,287			—
Proceeds from disposition of oil and gas properties		2,828			25
Additions to other property and equipment		(299	)		(516	)
Investment in Westfork Pipeline Company LP		(1,071	)		—
Net cash used in investing activities		(21,686	)		(15,081	)

Cash flows from financing activities:
Net borrowings (payments) on revolving credit facility		(17,000	)		(5,750	)
Proceeds (net) from common stock issued		27,743			—
Proceeds from exercise of stock options		378			103
Deferred stock offering costs		—			(7	)
Payment of preferred stock dividend		(271	)		(287	)
Net cash provided by (used in) financing activities		10,850			(5,941	)

Net decrease in cash and cash equivalents		(1,025	)		(12,435	)

Cash and cash equivalents at beginning of period		4,781			17,378

Cash and cash equivalents at end of period	$	3,756		$	4,943

Non-cash financing and investing activities:
Oil and gas properties asset retirement obligations, net	$	65		$	189
Conversion of preferred stock	$	95		$	—
Other Transactions:
Interest paid	$	2,403		$	933

The accompany notes are an integral part of these Consolidated Financial Statements.

PARALLEL PETROLEUM CORPORATION
Consolidated Statements of Comprehensive Income (Loss)
(unaudited)
(dollars in thousands)
	Three Months Ended June 30,						Six Months Ended June 30,
		2005			2004			2005			2004

Net income	$	1,453		$	1,103		$	903		$	2,585

Other comprehensive loss:
Unrealized losses on derivatives		(6,038	)		(3,782	)		(29,518	)		(8,125	)
Reclassification adjustments for losses
on derivatives included in net income		3,676			1,952			6,988			3,171
Change in fair value of derivatives		(2,362	)		(1,830	)		(22,530	)		(4,954	)
Income tax benefit		803			624			7,660			1,685

Total other comprehensive loss		(1,559	)		(1,206	)		(14,870	)		(3,269	)

Total comprehensive loss	$	(106	)	$	(103	)	$	(13,967	)	$	(684	)

PARALLEL PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. DESCRIPTION OF BUSINESS – NATURE OF OPERATIONS AND BASIS OFPRESENTATION

Parallel Petroleum Corporation was incorporated in Texas on November 26, 1979, and reincorporated in the State of Delaware on December 18, 1984.

We are engaged in the acquisition, development and exploitation of long life oil and natural gas reserves and, to a lesser extent, the exploration for new oil and natural gas reserves. Our activities are focused in the Permian Basin of west Texas and New Mexico, Liberty County in east Texas and the onshore Gulf Coast area of south Texas. We are actively evaluating, leasing and drilling new projects located in New Mexico, the Fort Worth Basin of Texas, the Cotton Valley Reef trend of east Texas and the Uinta Basin of Utah.

The financial information included herein is unaudited, except the balance sheet as of December 31, 2004 which has been derived from our audited Consolidated Financial Statements as of December 31, 2004. 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, accounting policies and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted in this Form 10-Q Report pursuant to certain rules and regulations of the Securities and Exchange Commission. These financial statements should be read in conjunction with the audited consolidated financial statements and notes included in our Annual Report on Form 10-K for the year ended December 31, 2004.

Unless otherwise indicated or unless the context otherwise requires, all references in this Quarterly Report on Form 10-Q to “Parallel”, “we”, “us”, and “our” are to Parallel Petroleum Corporation and its consolidated subsidiaries, Parallel L.P. and Parallel, L.L.C.

NOTE 2.

STOCKHOLDERS’ EQUITY

Options

In September, 2003, Parallel adopted the provisions of Statement of Financial Accounting Standards No. 148, Accounting for Stock-Based Compensation – Transition and Disclosure, an amendment to SFAS No. 123, whereby certain transitional alternatives are available for a voluntary change to the fair value based method of accounting for stock-based employee compensation. Parallel used the prospective method which applied 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 was adopted. The potential impact of using the fair value method for all options, on a pro forma basis, is presented in the table that follows.

For the three and six months ended June 30, 2005 and 2004, Parallel recognized compensation expense of approximately $0.028 million and $0.07 million respectively associated with its stock option grants. No options were granted during the quarter ended June 30, 2005 or the quarter ended June 30, 2004.

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.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
		(dollars in thousands, except per share data)

Net income, as reported	$	1,453		$	1,103		$	903		$	2,585
Add:
Expense recorded in 2005 and 2004		28			42			70			84
Deduct:
Total stock-based employee compensation
expense determined under fair value based method
for all awards, net of tax effects		(23	)		(48	)		(71	)		(95	)
Pro forma net income	$	1,458		$	1,097		$	902		$	2,574

Earnings per share:
Basic - as reported	$	0.04		$	0.04		$	0.02		$	0.09
Basic - pro forma	$	0.04		$	0.04		$	0.02		$	0.09

Diluted - as reported	$	0.04		$	0.04		$	0.03		$	0.09
Diluted - pro forma	$	0.04		$	0.04		$	0.03		$	0.09

Sale of Equity Securities

On February 9, 2005, we sold 5,750,000 shares of our common stock, $.01 par value per share, pursuant to a public offering at a price of $5.27 per share. Gross cash proceeds were $30.3 million, and net proceeds were approximately $27.7 million. The common shares were issued under Parallel’s $100.0 million Universal Shelf Registration Statement on Form S-3 which became effective in November 2004. The proceeds were used to reduce our bank debt under our revolving credit facility described in Note 3 below.

Preferred Stock

Under terms of the Preferred Stock, all of the holders of the Preferred Stock elected to convert their shares of Preferred Stock into shares of Parallel common stock based on the conversion rate of $10.00 divided by $3.50. The holders of the Preferred Stock received approximately 2.8571 shares of common stock of Parallel for each share of Preferred Stock. Dividends on the Preferred Stock ceased to accrue, and as of June 6, 2005 the Preferred Stock is no longer outstanding.

NOTE 3.

REVOLVING CREDIT FACILITY

We are a party to a Second Amended and Restated Credit Agreement, as amended (the “Credit Agreement”), with Citibank Texas, N.A., BNP Paribas, Citibank, F.S.B. and Western National Bank. The Credit Agreement provides for a revolving credit facility which means that we can borrow, repay and reborrow funds drawn under the credit facility. The total amount that we can borrow and have outstanding at any one time is limited to the lesser of $200.0 million or the "borrowing base" established by our lenders. Our current borrowing base is $90.0 million. The principal amount outstanding under the credit facility at June 30, 2005 was $62.0 million, excluding $0.49 million reserved for our letters of credit. The amount of the borrowing base is based primarily upon the estimated value of our oil and gas reserves. The borrowing base amount is redetermined by the lenders semi-annually on or about April 1 and October 1 of each year or at other times required by the lenders or at our request. If, as a result of the lenders' redetermination of the borrowing base, the outstanding principal amount of our loan exceeds the borrowing base, we must either provide additional collateral to the lenders or repay 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.

Loans made to us under this credit facility bear interest at Citibank’s base rate or the LIBOR rate, at our election. Generally, Citibank’s base rate is equal to the “prime rate” published in the Wall Street Journal. At June 30, 2005, Parallel had $4.0 million in base rate loans outstanding under the credit facility.

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, six or twelve month interest periods for deposits of $1.0 million, and (b) a margin ranging from 2.25% to 2.75%, depending upon the outstanding principal amount of the loans. If the principal amount outstanding is equal to or greater than 75% of the borrowing base, 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%.

The interest rate we are required to pay on our borrowings, including the applicable margin, may never be less than 4.50%. At June 30, 2005, our Libor interest rate was 5.62% on $31.0 million and 5.78% on $27.0 million.

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 credit facility are less than the borrowing base, an unused commitment fee is required to be paid to the 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.

If the borrowing base is increased, we are required to pay a fee of .375% on the amount of any increase in the borrowing base.

Parallel, L.L.C., a subsidiary of Parallel Petroleum Corporation, guaranteed payment of the loans.

Parallel’s obligations to the lenders are secured by substantially all of its oil and gas properties.

All outstanding principal under the revolving credit facility is due and payable on December 20, 2008. The maturity date of our outstanding loans may be accelerated by the lenders upon the occurrence of an event of default under the Credit Agreement.

The Credit Agreement contains various restrictive covenants and compliance requirements as follows:

•	at the end of each quarter, a current ratio (as defined in the credit agreement) of at least 1.1 to 1.0;

•	for each period (as calculated in the Credit Agreement) ending on December 31, March 31, June 30 and September 30, a funded debt ratio (as defined in the Credit Agreement) of not more than 3.70, 3.60 and 3.50, respectively, for December 31, 2005, 2006 and 2007; and
•	at all times, adjusted consolidated net worth (as defined in the Credit Agreement) of at least (a) $50.0 million, plus (b) seventy-five percent (75%) of the net proceeds from any equity securities issued by Parallel, plus (c) fifty percent (50%) of consolidated net income for each fiscal quarter, if positive, and zero percent (0%) if negative.

As of June 30, 2005 we were in compliance with all covenants.

The Credit Agreement also contains restrictions on all retained earnings and net income for payment of dividends on common stock.

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 seismic survey data;
•	lease acquisitions and drilling activities;
•	acquisitions of producing properties or companies owning producing properties; and,
•	general corporate purposes.

Interest expense for the six months ending June 30, 2005 was approximately $1.9 million not including approximately $0.050 million for interest capitalized associated with drilling projects.

NOTE 4.

ACQUISITIONS

In September and October 2004, with two separate transactions, we purchased additional non-operated working interest in the Fullerton Field properties. The net purchase price for these transactions was approximately $20.9 million.

In October and December 2004, we purchased properties in the Carm-Ann San Andres and North Means Queen Unit located in Andrews and Gaines counties, Texas. The combined net purchase price was approximately $16.5 million. In the first quarter of 2005, we acquired additional interest in these properties for a net purchase price of approximately $2.3 million.

The unaudited pro forma results summarized below reflects our consolidated pro forma results of operations for the three and six months ended June 30, 2004, assuming these acquisitions were consummated on January 1, 2004.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
			Pro Forma				Pro Forma
	2005		2004		2005		2004
		(in thousands, except per share data)

Oil and gas revenue, net of hedge losses	$	11,359	$	10,135	$	21,116	$	20,098
Operating income	$	4,241	$	3,347	$	6,890	$	6,504
Net income available to common shareholders	$	1,325	$	1,395	$	632	$	2,746

Net income per common share:
Basic	$	0.04	$	0.06	$	0.02	$	0.11
Diluted	$	0.04	$	0.06	$	0.03	$	0.11

NOTE 5.

FULL COST CEILING TEST

We use the full cost method to account for our oil and gas producing activities. Under the full cost method of accounting, the net book value of oil and gas properties, less related deferred income taxes and asset retirement obligations, 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. The net book value of oil and gas properties, less related deferred income taxes over the ceiling, is compared to the ceiling on a quarterly and annual basis. Any excess of the net book value, less related deferred income taxes, is generally written off as an expense. Under rules and regulations of the SEC, the excess above the ceiling is not written off if, subsequent to the end of the quarter or year but prior to the release of the financial results, prices have increased sufficiently that such excess above the ceiling would not have existed if the increased prices were used in the calculations.

At June 30, 2005, we had a cushion (i.e. the excess of the ceiling over our capitalized cost) of $131.1 million. 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 six month periods ended June 30, 2005 and 2004, overhead costs capitalized were approximately $0.597 million and $0.522 million respectively.

NOTE 6.

DERIVATIVE INSTRUMENTS

General

We enter into derivative contracts to provide a measure of stability in our oil and gas revenues 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 fixed interest rate. Our line of credit agreement as of June 30, 2005, required at least 50% of our estimated monthly crude oil produced from proved producing oil and gas properties during the 2005 calendar year and thereafter until the maturity date to be hedged. We designate our interest rate swaps, costless collars and commodity swaps as cash flow hedges. The effective portion of the unrealized gain or loss on cash flow hedges is recorded in other comprehensive income (loss) until the forecasted transaction occurs. During the term of a cash flow hedge, the effective portion of the quarterly change in the fair value of the derivatives is recorded in stockholders’ equity as other comprehensive loss and then transferred to oil and gas revenues when the production is sold and interest expense as the interest accrues. Ineffective portions of hedges (changes in realized prices that do not match the changes in the hedge price) are recognized in other expense as they occur. While the hedge contract is open, the ineffective gain or loss may increase or decrease until settlement of the contract.

As of June 30, 2005, we have recorded unrealized losses of $38.8 million ($25.6 million, net of tax) related to our derivative instruments, which represented the estimated aggregate fair values of our open derivative contracts, as of that date. These unrealized losses are presented on the Consolidated Balance Sheet as a current liability of $16.3 million and long-term liabilities of $27.2 million. During the twelve month period ending June 30, 2006, we expect approximately $9.7 million, net of tax, to be transferred out of other comprehensive loss and charged to earnings.

We are exposed to credit risk in the event of nonperformance by the counterparty to these contracts, BNP Paribas. However, we periodically assess the creditworthiness of the counterparty to mitigate this credit risk.

Interest Rate Sensitivity

We entered into fixed rate swap contracts with BNP Paribas based on the 90-day LIBOR rates at the time of the contract. The effect of the swap is that we converted our variable rate debt into fixed rate debt. We will receive variable interest rates (see Note 3) and pay fixed rates as shown in the table below.


Period of Time	Notional Amounts		Fixed Interest Rates
	($ in millions)
July 1, 2005 thru December 31, 2005	$	50	3.36	%

January 1, 2006 thru December 31, 2006	$	50	3.82	%

January 1, 2007 thru December 31, 2007	$	50	4.30	%

January 1, 2008 thru December 30, 2008	$	50	4.74	%

Commodity Price Sensitivity

Puts. On April 7, 2005, we purchased put floors on volumes of 1,000 Mcf per day for a total of 214,000 Mcf during the seven month period from April 1, 2006 through October 31, 2006, at a floor price of $5.50 per Mcf for a total consideration of approximately $0.035 million. These derivatives were not held for trading purposes and are not designated as cash flow hedges.

Costless Collars. Collars are created by purchasing puts to establish a floor price and then selling a call which establishes a maximum amount we will receive for the oil or gas hedged. Calls are sold to offset the premium paid for buying the put. We have entered into several costless gas collars and light sweet crude oil collars.

A recap for the period of time, number of MMBtu’s, number of barrels, and oil and gas prices is as follows:

							Houston
		NyMex					Ship Channel
		Oil Prices					Gas Prices
Period of Time	Barrels of Oil	Floor		Cap		MMBtu of Natural Gas	Floor		Cap

July 1, 2005 thru October 31, 2005	—	$	—	$	—	246,000	$	5.00	$	7.26

July 1, 2005 thru December 31, 2005	36,800	$	36.00	$	49.60	—	$	—	$	—

January 1, 2006 thru December 31, 2006	70,800	$	35.00	$	44.00	—	$	—	$	—

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.

We have entered into 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:

	Barrels of	Nymex Oil
Period of Time	Oil	Swap Price


July 1, 2005 thru December 31, 2005	312,800	$	30.18

January 1, 2006 thru December 20, 2006	448,000	$	28.46

January 1, 2007 thru December 31, 2007	474,500	$	34.36

January 1, 2008 thru December 31, 2008	439,200	$	33.37

NOTE 7.

NET INCOME PER COMMON SHARE

Basic earnings per share (“EPS”) exclude any dilutive effects of option, warrants and convertible securities and is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding for the period. Diluted earnings per share are computed similar to basic earnings per share. However, diluted earnings per share reflect the assumed conversion of all potentially dilutive securities.

The following table provides the computation of basic and diluted earnings per share for the three and six months ended June 30, 2005 and 2004:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
		(dollars in thousands, except per share data)
Basic EPS Computation:
Numerator-
Income	$	1,453		$	1,103		$	903		$	2,585
Preferred stock dividend		(128	)		(144	)		(271	)		(287	)

Income available to common stockholders	$	1,325		$	959		$	632		$	2,298

Denominator-
Weighted average common shares outstanding		31,967			25,246			30,341			25,235

Basic EPS:
Income per share	$	0.04		$	0.04		$	0.02		$	0.09

Diluted EPS Computation:
Numerator-
Income	$	1,453		$	1,103		$	903		$	2,585
Preferred stock dividend		—			—			—			—

Income available to common stockholders	$	1,453		$	1,103		$	903		$	2,585

Denominator -
Weighted average common shares outstanding		33,935			25,246			32,680			25,235
Employee stock options		606			285			544			268
Warrants		141			65			131			59
Preferred stock		—			2,734			—			2,734
Weighted average common shares for diluted
earnings per share assuming conversion		34,682			28,330			33,355			28,296

Diluted EPS:
Income	$	0.04		$	0.04		$	0.03		$	0.09

NOTE 8:

ASSET RETIREMENT OBLIGATIONS

On January 1, 2003, we adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations “SFAS No. 143”. SFAS No. 143 requires us to recognize a liability for the present value of all obligations associated with the retirement of tangible long-lived assets and to capitalize an equal amount as a cost of the related oil and gas properties.

The following table summarizes our asset retirement obligation activity:

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2005			2004		2005			2004
		(in thousands)

Beginning asset retirement obligation	$	2,112		$	1,864	$	2,132		$	1,701

Additions related to new properties		113			59		130			231

Deletions related to property disposals		(2	)		—		(65	)		(42	)

Accretion expense		28			20		54			53

Ending asset retirement obligation	$	2,251		$	1,943	$	2,251		$	1,943

NOTE 9.

RECENTLY ANNOUNCED ACCOUNTING PRONOUNCEMENTS

In December 2004, the Financial Accounting Standards Board (“FASB”) issued “Statement of Financial Accounting Standards No. 123 (revised 2004)”, “Share-Based Payment” (SFAS No. 123(R)). SFAS No. 123(R) requires an entity to recognize the grant-date fair value of stock options and other equity-based compensation issued to employees in the income statement. SFAS No. 123(R) initially was to be effective for the Company beginning July 1, 2005. On April 14, 2005, the Securities and Exchange Commission announced a delay in the implementation of SFAS No. 123(R) until the beginning of the fiscal year after June 15, 2005. The Company does not expect SFAS No. 123(R) to have a material impact on its results of operations.

NOTE 10.

COMMITMENTS AND CONTINGENCIES

From time to time, we are a party to ordinary routine litigation incidental to our business. We are currently a defendant in one lawsuit incidental to our business. We do not believe the ultimate outcome of this lawsuit will have a material adverse effect on our financial condition or results of operations. We are not aware of any other threatened litigation and we have not been a party to any bankruptcy, receivership, reorganization, adjustment or similar proceeding.

Effective January 1, 2005, we established a 401(k) Plan and Trust for eligible employees. Employees may not participate in the former SEP plan with the establishment of the 401(k) Plan and Trust. As of the six months ending June 30, 2005 Parallel had made contributions to the 401(k) Plan and Trust of approximately $0.077 million.

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 shareholder value of our common stock through increasing reserves, production, cash flow and earnings. We have shifted the balance of our investments from properties having high rates of production in early years to properties expected to produce more consistently 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 natural gas reserves are 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.

Since the latter part of 2002, we have reduced our emphasis on high risk exploration efforts and focused on established geologic trends where we 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 current business plan:

•	focuses on projects having less geological risk;
•	emphasizes exploitation and enhancement activities;
•	focuses on acquiring producing properties; and

•	expands the scope of 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 natural 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 the oil and natural gas, 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 natural gas and our production volumes. The world price for oil has overall influence on the prices that 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. Natural gas prices we receive are influenced by:

•	seasonal demand;
•	weather;
•	hurricane conditions in the Gulf of Mexico;

•	availability of pipeline transportation to end users;
•	proximity of our wells to major transportation pipeline infrastructures; and
•	to a lesser extent, world oil prices.

Additional factors influencing our overall operating performance include:

•	production expenses;
•	overhead requirements; and
•	costs of capital.

Our oil and natural 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.

For the three months ended June 30, 2005, the sale price we received for our crude oil production (excluding hedges) averaged $46.97 per barrel compared with $35.70 per barrel for the three months ended June 30, 2004. The average sales price we received for natural gas for the three months ended June 30, 2005 (excluding hedges), was $6.78 per Mcf compared with $5.94 per Mcf for the three months ended June 30, 2004. For information regarding prices received including our hedges, refer to the selected operating data table in the Results of Operations on page 16. Hedge costs for oil and natural gas was $3.6 million and $1.8 million for the three months ended June 30, 2005 and June 30, 2004 respectively. The hedge loss associated with the ineffective portion of our hedges was $1.2 million for the second quarter ended June 30, 2005. The ineffectiveness is caused by a widening of the differential price of West Texas Intermediate Light and current designated sales of West Texas Sour barrels. U. S. refineries are currently paying a premium for West Texas Intermediate, which is the NyMex benchmark. The majority of our oil is West Texas Sour. Actual gains or losses may increase or decrease until settlement of these contracts.

For the six months ended June 30, 2005, the sale price we received for our crude oil production (excluding hedges) averaged $46.15 per barrel compared with $34.31 per barrel for the six months ended June 30, 2004. The average sales price we received for natural gas for the six months ended June 30, 2005 (excluding hedges), was $6.42 per Mcf compared with $5.55 per Mcf for the six months ended June 30, 2004. For information regarding prices received including our hedges, refer to the selected operating data table in the Results of Operations on page 16. Hedge costs for oil and natural gas was $6.8 million and $2.9 million for the six months ended June 30, 2005 and June 30, 2004 respectively. The hedge loss associated with the ineffective portion of our hedges was $3.5 million for the six months ended June 30, 2005. The ineffectiveness is caused by a widening of the differential price of West Texas Intermediate Light and current designated sales of West Texas Sour barrels. U. S. refineries are currently paying a premium for West Texas Intermediate, which is the NyMex benchmark. The majority of our oil is West Texas Sour. Actual gains or losses may increase or decrease until settlement of these contracts.

Our oil and natural gas producing activities are accounted for using the full cost method of accounting. Under this accounting method, we capitalize all costs incurred in connection with the acquisition of oil and natural gas properties and the exploration for and development of oil and natural gas reserves. These costs include lease acquisition costs, geological and geophysical expenditures, costs of drilling 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 natural gas properties are accounted for as a reduction in capitalized costs, with no gain or loss recognized unless a disposition involves a material change in reserves, in which case the gain or loss is recognized.

Depletion of the capitalized costs of oil and natural gas properties, including estimated future development costs, is provided using the equivalent unit-of-production method based upon estimates of proved oil and natural gas reserves and production, which are converted to a common unit of measure based upon their relative energy content. Unproved oil and natural 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. Depletion per BOE at June, 2005 and 2004 was $7.94 and $6.92 respectively.

Results of Operations

Our business activities are characterized by frequent, and sometimes significant, changes in our:

•	reserve base;
•	sources of production;
•	product mix (gas versus oil volumes);
•	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 fully and accurately describe our condition. The following table shows selected operating data for each of the three and six months ended June 30, 2005 and June 30, 2004.


	Three Months Ended						Six Months Ended
	6/30/2005			6/30/2004			6/30/2005			6/30/2004
		(in thousands, except per unit data)

Production Volumes:
Oil (Bbls)		218			166			425			327
Natural gas (Mcf)		700			644			1,302			1,376
BOE⁽¹⁾		335			273			642			556
BOE per day		3.7			3.0			3.5			3.1

Sales Prices:
Oil (per Bbl)⁽²⁾	$	46.97		$	35.70		$	46.15		$	34.31
Natural gas (per Mcf)⁽²⁾	$	6.78		$	5.94		$	6.42		$	5.55
BOE price ⁽²⁾	$	44.77		$	35.72		$	43.57		$	33.92
BOE price⁽³⁾	$	33.90		$	29.00		$	32.89		$	28.63

Operating Revenues:
Oil	$	10,259		$	5,928		$	19,618		$	11,218
Oil hedge		(3,645	)		(1,522	)		(6,656	)		(2,646	)
Natural gas		4,745			3,824			8,355			7,640
Natural gas hedge		—			(313	)		(201	)		(294	)
	$	11,359		$	7,917		$	21,116		$	15,918

Operating Expenses:
Lease operating expense	$	2,178		$	2,014		$	4,736		$	3,543
Production taxes		701			471			1,281			949
General and administrative:
General and administrative		917			806			1,946			1,540
Public reporting		549			415			1,208			903
Depreciation, depletion and amortization		2,773			1,969			5,055			4,046
	$	7,118		$	5,675		$	14,226		$	10,981
Operating income	$	4,241		$	2,242		$	6,890		$	4,937
________________
(1) A BOE means one barrel of oil equivalent using the ratio of six Mcf of gas to one barrel of oil.
(2) Excludes hedge transactions.
(3) Includes hedge transactions

RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED JUNE 30, 2005 AND 2004:

Our oil and natural gas revenues and production product mix are displayed in the following table for the three months ended June 30, 2005 and June 30, 2004.

Oil and Gas Revenues:
	Revenues⁽¹⁾				Production
	2005		2004		2005		2004

Oil (Bbls)	58	%	56	%	65	%	61	%
Natural gas (Mcf)	42	%	44	%	35	%	39	%
Total	100	%	100	%	100	%	100	%
__________
(1) Includes hedge transactions

The following table outlines the detail of our operating revenues for the following periods.

	Three Months Ended June 30,						Increase		% Increase
	2005			2004			(Decrease)		(Decrease)

		(in thousands except per unit data)

Production Volumes:
Oil (Bbls)		218			166			52	31	%
Natural gas (Mcf)		700			644			56	9	%
BOE		335			273			62	23	%
BOE/Day		3.7			3.0			0.7	23	%

Sales Price:
Oil (per Bbl)⁽¹⁾	$	46.97		$	35.70		$	11.27	32	%
Natural gas (per Mcf)⁽¹⁾	$	6.78		$	5.94		$	0.84	14	%
BOE price⁽¹⁾	$	44.77		$	35.72		$	9.05	25	%
BOE price⁽²⁾	$	33.90		$	29.00		$	4.90	17	%

Operating Revenues:
Oil	$	10,259		$	5,928		$	4,331	73	%
Oil hedges	$	(3,645	)	$	(1,522	)	$	2,123	139	%
Natural gas	$	4,745		$	3,824		$	921	24	%
Natural gas hedges	$	—		$	(313	)	$	313	100	%
Total	$	11,359		$	7,917		$	3,442	43	%
______________
(1) Excludes hedge transactions.
(2) Includes hedge transactions.

Oil revenues, excluding hedges, increased $4.3 million or 73% for the three months ended June 30, 2005 compared to the same period of 2004. Oil production volumes increased 31% attributable to acquisitions and re-stimulations in the Fullerton San Andres Field, acquisitions in the Carm-Ann San Andres Field/N. Means Queen Unit and the drilling of producing and injection wells on our Diamond M Property. The increase in oil production increased revenue approximately $1.8 million for 2005. Wellhead average realized crude oil prices increased

$11.27 per Bbl or 32% to $46.97 per Bbl for 2005 compared to 2004. The increase in oil price increased revenue approximately $2.5 million for 2005.

Natural gas revenues, excluding hedges, increased $0.9 million or 24% for the three months ended June 30, 2005 compared to the same period of 2004. Natural gas production volumes increased 9% due to a Wilcox natural gas discovery in south Texas. The increase in natural gas volumes increased revenue approximately $0.3 million for 2005. Average realized wellhead natural gas prices increased 14% or $0.84 per Mcf to $6.78 per Mcf. The increase in natural gas prices had a positive effect on revenues of approximately $0.6 million for the three months ending June 30, 2005.

Losses on oil hedges increased $2.1 million or 139% for 2005 compared to 2004 due to the increase in oil prices. Natural gas hedge losses were $0.3 million in 2004. On a BOE basis, hedges accounted for a realized loss of $10.87 per BOE in 2005 compared to $6.72 per BOE in 2004. We have hedged certain oil and natural gas volumes to try and mitigate price changes in our oil and natural gas movements and to meet the requirements under our loan facility. BOE per day increased 676 BOE or 22% for 2005 compared to the same period in 2004.

With our recently announced results in the Diamond M Canyon Reef Unit, the New Mexico Gas Project, our onshore Gulf Coast Wilcox well and the Barnett Shale project, we expect increased production volumes over the second quarter 2005 if initial rates are maintained.

Cost and Expenses:
	Three months ended June 30,				Increase		% Increase
	2005		2004		(Decrease)		(Decrease)
		(dollars in thousands)

Lease operating expense	$	2,178	$	2,014	$	164	8	%
Production taxes		701		471		230	49	%
General and administrative:
General and administrative		917		806		111	14	%
Public reporting		549		415		134	32	%
Total general and administrative		1,466		1,221		245	20	%
Depreciation, depletion and amortization		2,773		1,969		804	41	%
Total	$	7,118	$	5,675	$	1,443	25	%

Lease operating costs increased approximately $0.2 million, or 8%, to $2.2 million during the three months ended June 30, 2005 compared with $2.0 million for the same period of 2004. The increase in lease operating expense is primarily due to our acquisitions in the Fullerton San Andres Field and the Carm-Ann San Andres Field/N. Means Queen Unit, increased ad valorem taxes and increased utility costs on our oil properties. Lifting costs were $6.50 per BOE in 2005 compared to $7.38 per BOE in 2004 on a BOE basis. As we continue to exploit and develop our long-life Permian Basin oil properties (Fullerton, Carm-Ann and Diamond M), we expect that lifting costs will continue around the same level or decline due to increased efficiencies on oil properties and increased development of gas properties which have lower lifting costs. The lifting costs per BOE are also expected to be reduced by the development of natural gas properties in south Texas, Barnett Shale and New Mexico.

Production taxes increased 49% or $0.2 million in 2005, associated with a wellhead increase in revenues of $5.3 million. Production taxes in future periods will be a function of product mix, production volumes and product prices.

General and administrative expenses in total increased 20% or $0.2 million in 2005 compared to 2004. Included in our total general and administrative expenses is public reporting cost which increased 32% or $0.1 million for 2005. The SOX 404 costs continue to be a significant portion of the increase in our public reporting

costs and we expect SOX 404 costs to continue through 2005. The remainder of the increase in general and administrative costs is due to computer tech support and legal expense. General and administrative expenses capitalized to the full cost pool were $0.3 million for 2005 compared to $0.2 million in 2004. On a BOE basis, general and administrative costs were $2.74 per BOE in 2005 compared to $2.95 per BOE in 2004, while public reporting costs were $1.64 per BOE and $1.52 per BOE for the same period. General and administrative expenses will increase in 2005 in association with reporting requirements and operational support.

Depreciation, depletion and amortization expense increased 41% or $0.8 million for 2005 compared to 2004. Depletion per BOE was $8.28 for 2005 and $7.21 for 2004. This increase is attributable to increased drilling costs and producing property purchases. Depletion costs are highly correlated with production volumes and capital expenditures. Fiscal year 2005 depletion costs will increase with increased production volumes and capital expenditures.

Other income (expense):
	Three months ended June 30,						Increase			% Increase
	2005			2004			(Decrease)			(Decrease)
		(dollars in thousands)

Gain (loss) on ineffective portion of hedges	$	(1,235	)	$	17		$	(1,252	)	(7,365	)%
Interest and other income		22			18			4		22	%
Interest expense, net		(796	)		(487	)		309		63	%
Other expense		(1	)		(59	)		(58	)	(98	)%
Equity loss in Westfork Pipeline Company LP		(15	)		—			15		—
Total	$	(2,025	)	$	(511	)	$	1,514		296	%

The loss associated with the ineffective portion of our hedges increased $1.3 million for 2005 compared to 2004. Commodity prices continued to increase into the second quarter of 2005. The spread between sweet and sour crude was wider for the second quarter of 2005 as compared to the same period of 2004 resulting in an increased ineffectiveness of our derivative contracts. The actual gain or loss may increase or decrease until settlement of these contracts. Interest expense increased with the increase of debt from approximately $34.0 million at June 30, 2004 to $62.0 million at June 30, 2005 along with an increase of our loan interest rate for 2005. Capitalized interest on work in progress decreased interest expense by approximately $0.050 million. Our equity investment in the construction phase of the Westfork Pipeline Company LP resulted in a loss for the second quarter of 2005.

Income tax expense was $0.8 million in 2005 compared to an expense of $0.6 million in 2004. Income tax expense for 2005 will be dependent on our earnings and is expected to be approximately 35% of income before income taxes.

We had basic net income per share of $.04 and diluted net income per share of $.04 for 2005 and 2004. Basic weighted average common shares outstanding increased from 25.2 million shares in 2004 to 32.0 million shares in 2005. The increase in common shares is due to the sale of 5,750,000 shares of common stock in a public offering in February of 2005 and the redeemed preferred shares to common shares in June of 2005.

RESULTS OF OPERATIONS FOR THE SIX MONTHS ENDED JUNE 30, 2005 AND 2004:

Our oil and natural gas revenues and production product mix are displayed in the following table for the six months ended June 30, 2005 and June 30, 2004.

Oil and Gas Revenues:
	Revenues⁽¹⁾				Production
	2005		2004		2005		2004

Oil (Bbls)	61	%	54	%	66	%	59	%
Natural gas (Mcf)	39	%	46	%	34	%	41	%
Total	100	%	100	%	100	%	100	%
__________
(1) Includes hedge transactions

The following table outlines the detail of our operating revenues for the following periods.

	Six Months Ended June 30,						Increase			% Increase
	2005			2004			(Decrease)			(Decrease)
		(in thousands except per unit data)

Production Volumes:
Oil (Bbls)		425			327			98		30	%
Natural gas (Mcf)		1,302			1,376			(74	)	(5	)%
BOE		642			556			86		15	%
BOE/Day		4			3			0		13	%

Sales Price:
Oil (per Bbl)⁽¹⁾	$	46.15		$	34.31		$	11.84		35	%
Natural gas (per Mcf)⁽¹⁾	$	6.42		$	5.55		$	0.87		16	%
BOE price⁽¹⁾	$	43.57		$	33.92		$	9.65		28	%
BOE price⁽²⁾	$	32.89		$	28.63		$	4.26		15	%

Operating Revenues:
Oil	$	19,618		$	11,218			8,400		75	%
Oil hedges	$	(6,656	)	$	(2,646	)		4,010		152	%
Natural gas	$	8,355		$	7,640			715		9	%
Natural gas hedges	$	(201	)	$	(294	)		(93	)	(32	)%
Total	$	21,116		$	15,918			5,198		33	%
______________
(1) Excludes hedge transactions.
(2) Includes hedge transactions.

Oil revenues, excluding hedges, increased $8.4 million or 75% for the six months ended June 30, 2005 compared to the same period of 2004. Oil production volumes increased 30% attributable to acquisitions and re-stimulations in the Fullerton San Andres Field, acquisitions in the Carm-Ann San Andres Field/N. Means Queen Unit and the drilling of producing and injection wells on our Diamond M Property. The increase in oil production

increased revenue approximately $3.4 million for 2005. Wellhead average realized crude oil prices increased $11.84 per Bbl or 35% to $46.15 per Bbl for 2005 compared to 2004. The increase in oil price increased revenue approximately $5.0 million for 2005.

Natural gas revenues, excluding hedges, increased $0.7 million or 9% for the six months ended June 30, 2005 compared to the same period of 2004. Natural gas production volumes decreased 5% primarily due to natural production declines in our south Texas Yegua/Frio and Cook Mountain projects. The decline in natural gas volumes decreased revenue approximately $0.4 million for 2005. Average realized wellhead natural gas prices increased 16% or $0.87 per Mcf to $6.42 per Mcf. The increase in natural gas prices had a positive effect on revenues of approximately $1.1 million for the six months ending June 30, 2005.

Losses on oil hedges increased $4.0 million or 152% for 2005 compared to 2004 due to the increase in oil prices. Natural gas hedge losses were $0.2 million in 2005 compared to a loss of $0.3 million in 2004. On a BOE basis, hedges accounted for a realized loss of $10.68 per BOE in 2005 compared to $5.29 per BOE in 2004. We have hedged certain oil and natural gas volumes to try and mitigate price changes in our oil and natural gas movements and to meet the requirements under our loan facility.

Cost and Expenses:
	Six months ended June 30,				Increase		% Increase
	2005		2004		(Decrease)		(Decrease)
		(dollars in thousands)

Lease operating expense	$	4,736	$	3,543	$	1,193	34	%
Production taxes		1,281		949		332	35	%
General and administrative:
General and administrative		1,946		1,540		406	26	%
Public reporting		1,208		903		305	34	%
Total general and administrative		3,154		2,443		711	29	%
Depreciation, depletion and amortization		5,055		4,046		1,009	25	%
Total	$	14,226	$	10,981	$	3,245	30	%

Lease operating costs increased approximately $1.2 million, or 34%, to $4.7 million during the six months ended June 30, 2005 compared with $3.5 million for the same period of 2004. The increase in lease operating expense is primarily due to our acquisitions in the Fullerton San Andres Field and the Carm-Ann San Andres Field/N. Means Queen Unit, increased ad valorem taxes and increased utility costs on our oil properties. Lifting costs were $7.38 per BOE in 2005 compared to $6.37 per BOE in 2004 on a BOE bases. As we continue to exploit and develop our long-life Permian Basin oil properties (Fullerton, Carm-Ann and Diamond M), we expect that lifting costs will continue around the same level or decline due to increased efficiencies on oil properties and increased development of gas properties which have lower lifting costs. The lifting costs are also expected to be reduced by the development of natural gas properties in south Texas, Barnett Shale and New Mexico.

Production taxes increased 35% or $0.3 million in 2005, associated with a wellhead increase in revenues of $9.1 million. Production taxes in future periods will be a function of product mix, production volumes and product prices.

General and administrative expenses in total increased 29% or $0.7 million in 2005 compared to 2004. Included in our total general and administrative expenses is public reporting cost which increased 34% or $0.3 million for 2005. The SOX 404 costs continue to be a significant portion of the increase in our public reporting costs and we expect SOX 404 costs to continue through 2005. The remainder of the increase in general and

administrative costs is due to salary increases, computer tech support and rent for increased building space. General and administrative expenses capitalized to the full cost pool were $0.6 million for 2005 compared to $0.5 million in 2004. On a BOE basis, general and administrative costs were $3.03 per BOE in 2005 compared to $2.77 per BOE in 2004, while public reporting costs were $1.88 per BOE and $1.62 per BOE for the same period. General and administrative expenses will increase in 2005 in association with reporting requirements and operational support.

Depreciation, depletion and amortization expense increased 25% or $1.0 million for 2005 compared to 2004. Depletion per BOE was $7.87 for 2005 and $7.28 for 2004. This increase is attributable to increased drilling costs and producing property purchases. Depletion costs are highly correlated with production volumes and capital expenditures. Fiscal year 2005 depletion costs will increase with increased production volumes and capital expenditures.

Other income (expense):
	Six months ended June 30,						Increase			% Increase
	2005			2004			(Decrease)			(Decrease)
		(dollars in thousands)

Gain (loss) on ineffective portion of hedges	$	(3,511	)	$	7		$	(3,518	)	(50,257	)%
Interest and other income		41			158			(117	)	(74	)%
Interest expense, net		(1,934	)		(955	)		979		103	%
Other expense		(2	)		(85	)		(83	)	(98	)%
Equity loss in Westfork Pipeline Company LP		(94	)		—			94		—
Total	$	(5,500	)	$	(875	)	$	4,625		529	%

The loss associated with the ineffective portion of our hedges increased $3.5 million for 2005 compared to 2004. Commodity prices continued to increase into the second quarter of 2005. The spread between sweet and sour crude was wider for 2005 as compared to the same period of 2004 resulting in an increased ineffectiveness of our derivative contracts. The actual gain or loss may increase or decrease until settlement of these contracts. Interest expense increased with the increase of debt from approximately $34.0 million at June 30, 2004 to $62.0 million at June 30, 2005 along with an increase of our loan interest rate for 2005. Capitalized interest on work in progress decreased interest expense by approximately $0.050 million. Our equity investment in the construction phase of the Westfork Pipeline Company LP resulted in a loss for 2005.

Income tax expense was $0.5 million in 2005 compared to an expense of $1.5 million in 2004. Income tax expense for 2005 will be dependent on our earnings and is expected to be approximately 35% of income before income taxes.

We had basic net income per share of $.02 and $.09 and diluted net income per share of $.03 and $.09 for 2005 and 2004, respectively. Basic weighted average common shares outstanding increased from approximately 25.0 million shares in 2004 to approximately 30.0 million shares in 2005. The increase in common shares is due to the sale of 5,750,000 shares of common stock in a public offering in February of 2005 and the redeemed preferred shares to common shares in June, 2005.

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 gas we produce.

Working capital decreased 776% or approximately $6.6 million as of June 30, 2005 compared with

December 31, 2004. Current liabilities exceeded current assets by $5.7 million at June 30, 2005. The working capital decrease was primarily due to the increased current maturity of derivative obligations of approximately $8.3 million.

We incurred net property costs of $21.7 million for the six months ended June 30, 2005 compared to $15.1 million for the same period in 2004. Our property expenditures were $23.1 million for the first six months of 2005, which was partially offset by restricted cash utilized for property purchases and proceeds from non-strategic property dispositions. Included in our property basis for the first six months of 2005 and 2004 were net asset retirement costs of approximately $0.065 million and $0.189 million respectively (see Note 8 to Consolidated Financial Statements). Our property leasehold acquisition, development and enhancement activities were financed by our revolving credit facility, the utilization of cash flows provided by operations, cash on hand and proceeds from non strategic property sales and bank borrowings.

On February 9, 2005, we had gross cash proceeds of $30.3 million and net proceeds of approximately $27.7 million from the sale of common stock (see Note 2 to Consolidated Financial Statements). These proceeds and cash available were used to reduce our borrowings on the revolving line of credit by approximately $29.0 million.

Stockholders’ equity is $73.9 million for June 30, 2005 compared to $60.0 million at December 31, 2004, an increase of 23%. The increase is attributable to the net proceeds of approximately $27.7 received from the sale of equity securities of 5,750,000 shares of our common stock offset by the increase in accumulated comprehensive income (loss) of $14.8 million related to our derivative instruments (see Note 6 to Consolidated Financial Statements) and net income of $0.903 million.

Based on our projected oil and gas revenues and related expenses, available bank borrowings and expected cash derived from non-strategic asset divestitures, we believe that we will have sufficient capital resources to fund normal operations and capital requirements, including interest expense and principal reduction payments on bank debt, if required. We continually review and consider alternative methods of financing.

Bank Borrowings

We are a party to a Second Amended and Restated Credit Agreement, as amended (the “Credit Agreement”), with Citibank Texas, N.A. BNP Paribas, Citibank, F.S.B. and Western National Bank. The Credit Agreement provides for a revolving credit facility which means that we can borrow, repay and reborrow funds drawn under the credit facility. The total amount that we can borrow and have outstanding at any one time is limited to the lesser of $200.0 million or the "borrowing base" established by our lenders. Our current borrowing base is $90.0 million. The principal amount outstanding under the credit facility at June 30, 2005 was $62.0 million, excluding $0.49 million reserved for our letters of credit. The amount of the borrowing base is based primarily upon the estimated value of our oil and gas reserves. The borrowing base amount is redetermined by the lenders semi-annually on or about April 1 and October 1 of each year or at other times required by the lenders or at our request. If, as a result of the lenders' redetermination of the borrowing base, the outstanding principal amount of our loan exceeds the borrowing base, we must either provide additional collateral to the lenders or repay 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.

Loans made to us under this credit facility bears interest at Citibank’s base rate or the LIBOR rate, at our election. Generally, Citibank’s base rate is equal to the sum the “prime rate” published in the Wall Street Journal. At June 30, 2005, Parallel had $4.0 million in base rate loans outstanding under the credit facility.

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 borrowing base is increased, we are required to pay a fee of .375% on the amount of any increase in the borrowing base.

Parallel, L.L.C., a subsidiary of Parallel Petroleum Corporation, guaranteed payment of the loans.

Parallel’s obligations to the lenders are secured by substantially all of its oil and gas properties.

The Credit Agreement contains various restrictive covenants and compliance requirements as follows:

•	at the end of each quarter, a current ratio (as defined in the credit agreement) of at least 1.1 to 1.0;

•	for each period (as calculated in the Credit Agreement) ending on December 31, March 31, June 30 and September 30, a funded debt ratio (as defined in the Credit Agreement) of not more than 3.70, 3.60 and 3.50, respectively, for December 31, 2005, 2006 and 2007; and
•	at all times, adjusted consolidated net worth (as defined in the Credit Agreement) of at least (a) $50.0 million, plus (b) seventy-five percent (75%) of the net proceeds from any equity securities issued by Parallel, plus (c) fifty percent (50%) of consolidated net income for each fiscal quarter, if positive, and zero percent (0%) if negative.

As of June 30, 2005 we were in compliance with all covenants.

The Credit Agreement also contains restrictions on all retained earnings and net income for payment of dividends on common stock.

•	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.

Interest expense for the six months ending June 30, 2005 was approximately $1.9 million not including approximately $0.050 million for interest capitalized associated with drilling projects.

Sale of Equity Securities

Preferred Stock

Under terms of the Preferred Stock, all of the holders of the Preferred Stock elected to convert their shares of Preferred Stock into shares of Parallel common stock based on the conversion rate of $10.00 divided by $3.50. The holders of the Preferred Stock will receive approximately 2.8571 shares of common stock of Parallel for each share of Preferred Stock. Dividends on the Preferred Stock ceased to accrue, and as of June 6, 2005 the Preferred Stock is no longer outstanding.

Commodity Price Risk Management Transactions

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.

Under cash flow hedge accounting, the quarterly change in the fair value of the commodity derivatives is recorded in stockholders’ equity as other comprehensive loss and then transferred to revenue when the production is sold. Ineffective portions of cash flow hedges (changes in realized prices that do not match the changes in the hedge price) are recognized in other expense as they occur. While the cash flow hedge contract is open, the ineffective gain or loss many increase or decrease until settlement of the contract.

Under cash flow hedge accounting for interest rate swaps, the quarterly change in the fair value of the derivatives is recorded in stockholders’ equity as other comprehensive loss and then transferred to interest expense when the contract settles. Ineffective portions of cash flow hedges are recognized in other expense as they occur.

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.

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.

Contractual Obligations, Commitments and Off-Balance Sheet Arrangements

We have contractual obligations and commitments that may affect our financial position. However, based on our assessment of the provisions and circumstances of our contractual obligation and commitments, we do not feel there would be an adverse effect on our consolidated results of operations, financial condition or liquidity.

The following table is a summary of significant contractual obligations as of June 30, 2005:

	Obligation Due in Period
	Six months ending December 31,		Year ended December 31,
Contractual Cash Obligations	2005		2006		2007		2008		2009		After 5 years		Total
		(in thousands)
Revolving Credit Facility (secured)	$	—	$	—	$	—	$	62,000	$	—	$	—	$	62,000
Office Lease (Dinero Plaza)		78		105		—		—		—		—		183
Andrews and Snyder Field Offices⁽¹⁾		12		23		23		14		14		—		86
Asset retirement obligations⁽²⁾		105		38		229		19		150		1,710		2,251
Derivative Obligations		9,053		14,111		10,593		9,774		—		—		43,531
Drilling contract		292		964		613		—		—		—		1,869
Total	$	9,540	$	15,241	$	11,458	$	71,807	$	164	$	1,710	$	109,920
_________________

(1) The Snyder field office lease remains in effect until the termination of our trade agreement with a third party working interest owner in the Diamond “M” project. The Andrews field office lease expires in December 2007. The lease cost for these two office facilities are billed to nonaffiliated third party working interest owners under our joint operating agreements with these third parties.
(2) Assets retirement obligations of oil and natural gas assets, excluding salvage value and accretion.

Outlook

The oil and natural 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 natural 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 natural 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.

Except for the revolving credit facility we have with our bank lenders, 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

Our drilling costs have escalated due to increased demand for drilling services in the industry and we would expect this trend to continue, but our commodity prices have also increased at the same time.

Critical Accounting Policies

This discussion should be read in conjunction with the financial statements and the accompanying notes and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our Annual Report or Form 10-K for the year ended December 31, 2004, filed with the Securities and Exchange Commission on March 15, 2005.

In December 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123(R)). SFAS No. 123(R) requires an entity to recognize the grant-date fair value of stock options and other equity-based compensation issued to employees in the income statement. SFAS No. 123(R) initially was effective for Parallel beginning July 1, 2005. On April 14, 2005, the Securities and Exchange Commission announced a delay in the implementation of SFAS No. 123(R) until the beginning of the fiscal year after June 15, 2005. We do not expect SFAS No. 123(R) to have a material impact on its results of operations.

Effects of Derivative Instruments

As of January 1, 2003 we designated our costless collars, oil and gas swaps and interest rate swaps as cash flow hedges under the provisions of SFAS 133, as amended. The adoption of cash flow hedge accounting allows us to record changes in fair value of contracts designated as cash flow hedges through other income (loss) until realized. When realized, we reflect the gain or loss on commodity derivatives designated as cash flow hedges in revenue and on interest rate derivatives designated as cash flow hedges in interest expense. We utilize mark-to-market accounting for our put positions. The purpose of our hedges is to provide a measure of stability in our oil and gas prices and interest rate payments and to manage exposure to commodity price and interest rate risk. Our objective is to lock in a range of oil and gas prices and a fixed interest rate for certain notional amounts.

Under cash flow hedge accounting, the quarterly change in the fair value of the derivatives is recorded in stockholders’ equity as other comprehensive loss and then transferred to earnings when the production is sold. Ineffective portions of cash flow hedges (changes in realized prices that do not match the changes in the hedge price) are recognized in other expense as they occur. While the cash flow hedge contract is open, the ineffective gain or loss many increase or decrease until settlement of the contract.

TRENDS AND PRICES

Changes in oil and gas prices significantly affect our revenues, cash flows and borrowing capacity. Markets for oil and natural gas have historically been, and will continue to be, volatile. Prices for oil and natural 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 natural gas.

Our capital expenditure budgets are highly dependent on future oil and natural gas prices and will be consistent with internally generated cash flows.

During fiscal year 2004 the average realized sales price for our oil and natural gas was $37.55 (unhedged) per BOE. For the six months ended June 30, 2005, our average realized price was $43.57 (unhedged) per BOE.

FORWARD-LOOKING STATEMENTS

Cautionary Statement Regarding Forward-Looking Statements

Some statements contained in this Quarterly Report on Form 10-Q are "forward-looking statements". These forward looking statements relate to, among others, the following:

•	our future financial and operating performance and results;
•	our business strategy;
•	changes in prices and demand for oil and natural gas;
•	sources of funds necessary to conduct operations and complete acquisitions;
•	development costs;
•	number and location of planned wells;
•	our future commodity price risk management activities; and
•	our plans and forecasts.

We have based these forward-looking statements on our current assumptions, expectations and projections about future events.

We use the words "may," "will," "expect," "anticipate," "estimate," "believe," "continue," "intend, " "plan," "budget," "present value," "future" or "reserves" or other similar words to identify forward-looking statements. These statements also involve risks and uncertainties that could cause our actual results or financial condition to materially differ for our expectations. We believe the assumptions and expectations reflected in these forward-looking statements are reasonable. However, we cannot give any assurance that our expectations will prove to be correct or that we will be able to take any actions that are presently planned. All of these statements involve assumptions of future events and risks and uncertainties. Risks and uncertainties associated with forward-looking statements include, but are not limited to:

•	fluctuations in prices of oil and natural gas;
•	demand for oil and natural gas;
•	losses due to potential or future litigation;
•	future capital requirements and availability of financing;
•	geological concentration of our reserves;
•	risks associated with drilling and operating wells;
•	competition;
•	general economic conditions;
•	governmental regulations;

•	receipt of amounts owed to us by purchasers of our production and counterparties to our hedging contracts;

•	hedging decisions, including whether or not to hedge;
•	events similar to 911;
•	actions of third party co-owners of interests in properties in which we also own an interest; and

•	fluctuations in interest rates and availability of capital.

For these and other reasons, actual results may differ materially from those projected or implied. We believe it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict, or over which we have no control. We caution you against putting undue reliance on forward-looking statements or projecting any future results based on such statements.

Before you invest in our common stock, you should be aware that there are various risks associated with an investment. We have described some of these risks under “Risks Related to Our Business” beginning on page 20 of our Form 10-K for year ended December 31, 2004.

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The following quantitative and qualitative information is provided about market risks and derivative instruments to which Parallel was a party at June 30, 2005, and from which Parallel may incur future earnings, gains or losses from changes in market interest rates and oil and natural gas prices.

Interest Rate Sensitivity as of June 30, 2005

Our only financial instrument sensitive to changes in interest rates is our bank debt. 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, 2005. You should read Note 3 to the Consolidated Financial Statements for further discussion of our debt that is sensitive to interest rates.

		2005		2006			2007			2008			2009		Total
		($ in thousands)
Variable rate debt:
Revolving facility (secured)	$	—		$	—		$	—		$	62,000		$	—	$	62,000
Weighted average interest rate		5.73	%		5.73	%		5.73	%		5.73	%		—

At June 30, 2005, we had bank loans in the amount of approximately $62.0 million outstanding on our revolving credit facility at an average interest rate of 5.88%. Borrowings under our credit facility bear interest, at our election, at (i) the bank’s base rate or (ii) the LIBOR rate, plus LIBOR margin, but in no event less than 4.50%. As a result, our annual interest cost in 2005 will fluctuate based on short-term interest rates. As the interest rate is variable and is reflective of current market conditions, the carrying value approximates the fair value.

Under our 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%. At June 30, 2005, the weighted average interest rate for our LIBOR rate loans was 5.69%

We entered into LIBOR fixed interest rate swap contracts with BNP Paribas. We will pay a fixed interest rate, as noted in the table below, for the period beginning July 1, 2005 through December 30, 2008.

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:

		Notional	Fixed			Fair
Period of Time		Amounts	Interest Rates			Market Value
		($ in millions)				($ in millions)
July 1, 2005 thru December 31, 2005	$	50	3.36	%	$	0.091

January 1, 2006 thru December 31, 2006	$	50	3.82	%		0.141

January 1, 2007 thru December 31, 2007	$	50	4.30	%		(0.082	)

January 1, 2008 thru December 30, 2008	$	50	4.74	%		(0.247	)

Total Fair Market Value					$	(0.097	)

Commodity Price Sensitivity as of June 30, 2005

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. We expect pricing volatility to continue. Oil prices ranged from a low of $26.76 per barrel to a high of $52.82 per barrel during 2004. Natural gas prices we received during 2004 ranged from a low of $2.31 per Mcf to a high of $8.79 per Mcf. During 2005, oil prices ranged from a low of $36.43 to a high of $55.27. Natural gas prices we received during 2005, ranged from a low of $2.22 per Mcf to a high of $9.95 per Mcf. A significant decline in the prices of oil or natural gas could have a material adverse effect on our financial condition and results of operations.

Puts. On April 7, 2005, we purchased put floors on volumes of 1,000 Mcf per day for a total of 214,000 Mcf during the seven month period from April 1, 2006 through October 31, 2006, at a floor price of $5.50 per Mcf for a total consideration of approximately $0.035 million. These derivatives were not held for trading purposes.

Costless Collar. 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 gas prices is as follows:



		NyMex Oil Prices					Houston Ship Channel Gas Prices
Period of Time	Barrels of Oil	Floor		Cap		MMBtu of Natural Gas	Floor		Cap			Fair Market Value
												($ in thousands)

July 1, 2005 thru October 31, 2005	—	$	—	$	—	246,000	$	5.00	$	7.26	$	(52	)

July 1, 2005 thru December 31, 2005	36,800	$	36.00	$	49.60	—	$	—	$	—		(322	)

January 1, 2006 thru December 31, 2006	70,800	$	35.00	$	44.00	—	$	—	$	—		(1,023	)

Total Fair Market Value											$	(1,397	)

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.

We have entered into oil swap contracts with BNP Paribas. A recap for the period of time, number of barrels and swap prices are as follows:

	Barrels			Fair
	of	Nymex Oil		Market
Period of Time	Oil	Swap Price		Value
				($ in thousands)

July 1, 2005 thru December 31, 2005	312,800	$	30.18	$	(8,770	)

January 1, 2006 thru December 20, 2006	448,000	$	28.46		(13,230	)

January 1, 2007 thru December 31, 2007	474,500	$	34.36		(10,510	)

January 1, 2008 thru December 31, 2008	439,200	$	33.37		(9,527	)

Total fair market value				$	(42,037	)

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, Larry C. Oldham (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, processed, summarized and reported within the time periods prescribed by the SEC. Mr. Oldham 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

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Sale of Unregistered Securities

At Parallel's annual meeting of stockholders held on June 22, 2004, the stockholders approved the Parallel Petroleum Corporation 2004 Non-Employee Director Stock Grant Plan. Upon approval of the plan by the stockholders, we began paying an annual retainer fee to each non-employee Director in the form of common stock having a value of $25,000. Only Directors of Parallel who are not employees of Parallel or any of its subsidiaries are eligible to participate in the Plan. Under the plan, each non-employee Director is entitled to receive an annual retainer fee consisting of shares of common stock that will be automatically granted on the first day of July in each year. The actual number of shares received is determined by dividing $25,000 by the average daily closing price of the common stock on the Nasdaq Stock Market for the ten consecutive trading days commencing fifteen trading days before the first day of July of each year ($8.622). Effective on July 1, 2005, in accordance with the terms of the plan, a total of 11,596 shares of common stock were granted to four non-employee Directors as follows: Jeffrey G. Shrader – 2,899 shares; Dewayne E. Chitwood – 2,899 shares; Martin B. Oring – 2,899 shares; and Ray M. Poage – 2,899 shares. The shares of common stock were issued without registration under the Securities Act of 1933, as amended, in reliance on the exemption provided by Section 4(2) of the Securities Act. Generally, shares issued under this plan are not transferable as long as the non-employee Director holding the shares remains a Director of the Company. Certificates evidencing the shares bear restrictive legends.

Repurchase of Equity Securities

Neither we nor any "affiliated purchaser" repurchased any of our equity securities during the second quarter ended June 30, 2005. However, as described under Note 2 on page 6 of this report, the holders of our 6% convertible preferred stock exercised their right to convert all 950,000 outstanding shares of preferred stock into a total of 2,714,280 shares of our common stock following our announcement on May 3, 2005 that we would redeem all of the preferred stock on June 6, 2005 at a price of $10.00 for each share of preferred stock. The holders of preferred stock received approximately 2.8571 shares of common stock for each share of preferred stock, together with accumulated and unpaid dividends up to June 6, 2005, the redemption date.

ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

Our annual meeting of stockholders was held on June 21, 2005. At the meeting, the following six persons were elected to serve as directors of Parallel for a term of one year expiring in 2006 and until their respective successors are duly qualified and elected: (1) Thomas R. Cambridge, (2) Dewayne E. Chitwood,

(3) Larry C. Oldham, (4) Martin B. Oring, (5) Ray M. Poage, and (6) Jeffrey G. Shrader. Set forth below is a tabulation of votes with respect to each nominee for director.

			BROKER
NAME	VOTES CAST FOR	VOTES WITHHELD	NON—VOTES

Thomas R. Cambridge	27,880,052	771,543	—
Dewayne E. Chitwood	28,399,953	251,642	—
Larry C. Oldham	28,403,085	248,510	—
Martin B. Oring	28,498,133	153,462	—
Ray M. Poage	28,499,963	151,632	—
Jeffrey G. Shrader	27,976,600	674,995	—

Also, the stockholders voted upon and ratified the appointment of BDO Seidman, LLP to serve as our independent public accountants for 2005. Set forth below is a tabulation of votes with respect to the proposal to ratify the appointment of our independent public accountants:

VOTES FOR	VOTES AGAINST	ABSTENTIONS

28,607,389	18,188	26,018

ITEM 6.		EXHIBITS
(a)	Exhibits

The following exhibits are filed herewith or incorporated by reference, as indicated:

No.	Description of Exhibit

3.1	Certificate of Incorporation of Registrant (Incorporated by reference to Exhibit 3.1 to Form 10-Q of the Registrant for the fiscal quarter ended June 30, 2004)

3.2	Bylaws of Registrant (Incorporated by reference to Exhibit 3 of the Registrant’s Form 8-K, dated October 9, 2000, as filed with the Securities and Exchange Commission on October 10, 2000)

3.3	Certificate of Formation of Parallel, L.L.C. (Incorporated by reference to Exhibit No. 3.3 of the Registrant’s Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004)

3.4	Limited Liability Company Agreement of Parallel, L.L.C. (Incorporated by reference to Exhibit No. 3.4 of the Registrant’s Statement on Form S-3, No. 333-119725 filed on October 13, 2004)

3.5	Certificate of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit No. 3.5 of the Registrant’s Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004)

3.6	Agreement of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit No. 3.6 of the Registrant’s Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004)

4.1	Certificate of Designations, Preferences and Rights of Serial Preferred Stock - 6% Convertible Preferred Stock (Incorporated by reference to Exhibit 4.1 of Form 10-Q of the Registrant for the fiscal quarter ended June 30, 2004)

4.2	Certificate of Designation, Preferences and Rights of Series A Preferred Stock (Incorporated by reference to Exhibit 4.2 of Form 10-K of the Registrant 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 of the Registrant for the fiscal year ended December 31, 2000)

4.4	Form of Indenture relating to senior debt securities of the Registrant (Incorporated by reference to Exhibit No. 4.4 of the Registrant’s Statement on Form S-3, No. 333-119725 filed on October 13, 2004)

4.5	Form of Indenture relating to subordinated debt securities of the Registrant (Incorporated by reference to Exhibit No. 4.5 of the Registrant’s Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004)

4.6	Form of common stock certificate of the Registrant (Incorporated by reference to Exhibit No. 4.6 of the Registrant’s Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004)

4.7	Warrant Purchase Agreement, dated November 20, 2001, between the Registrant and Stonington Corporation (Incorporated by reference to Exhibit 4.7 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004)

4.8	Warrant Purchase Agreement, dated December 23, 2003, between the Registrant and Stonington Corporation (Incorporated by reference to Exhibit 4.8 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004)

	Executive Compensation Plans and Arrangements (Exhibit No.'s 10.1 through 10.8):

10.1	1992 Stock Option Plan (Incorporated by reference to Exhibit 10.1 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004)

10.2	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)

*10.3	Non-Employee Directors Stock Option Plan

10.4	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)

10.5	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 Form 10-K of the Registrant for the fiscal year ended December 31, 2001)


10.6	2001 Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.7 of the Registrant's Form 10-Q Report for the first fiscal quarter ended March 31, 2004)

10.7	2004 Non-Employee Director Stock Grant Plan (Incorporated by reference to Exhibit 10.1 of the Registrant's Form 8-K Report dated September 22, 2004)

10.8	Incentive and Retention Plan (Incorporated by reference to Exhibit 10.1 of the Registrant's Form 8-K Report dated September 23, 2004 and filed with the Securities and Exchange Commission on September 29, 2004)

10.9	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)

10.10	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)

10.11	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 of the Registrant for the fiscal year ended December 31, 2000)

10.12	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)

10.13	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)

10.14	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 of the Registrant for the fiscal year ended December 31, 2000)

10.15	Loan Agreement, dated as of January 25, 2002, between the Registrant and First American Bank, SSB (Incorporated by reference to Exhibit 10.25 of Form 10-K of the Registrant for the fiscal year ended December 31, 2001)

10.16	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)

10.17	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)

10.18	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)


10.19	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 Bank, SSB, Western National Bank, and BNP Paribas (Incorporated by reference to Exhibit 10.29 of Form 10-Q of the Registrant for the quarter ended September 30, 2003)

10.20	Second Amended and Restated Credit Agreement, dated September 27, 2004, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB, BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by reference to Exhibit 10.1 of the Registrant's Form 8-K Report dated September 27, 2004 and filed with the Securities and Exchange Commission on October 1, 2004)

10.21	Agreement of Limited Partnership of West Fork Pipeline Company LP (Incorporated by reference to Exhibit 10.21 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004)

10.22	First Amendment to Second Amended and Restated Credit Agreement, dated as of December 27, 2004, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB, BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K Report dated December 30, 2004 and filed with the Securities and Exchange Commission on December 30, 2004)

10.23	Second Amendment to Second Amended and Restated Credit Agreement, dated as of April 1, 2005, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB, BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K Report dated April 4, 2005 and filed with the Securities and Exchange Commission on April 8, 2005)

14	Code of Ethics (Incorporated by reference to Exhibit No. 14 of the Registrant’s Form 10-K Report for the fiscal year ended December 31, 2003 and filed with the Securities and Exchange Commission on March 22, 2004)

21	Subsidiaries (Incorporated by reference to Exhibit No. 21 of the Registrant’s Form 10-K Report for the fiscal year ended December 31, 2003 and filed with the Securities and Exchange Commission on March 22, 2004)

*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.

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


Date: August 3, 2005	BY: /s/ Larry C. Oldham
	Larry C. Oldham
	President and Chief Executive Officer



Date: August 3, 2005	BY: /s/ Steven D. Foster
	Steven D. Foster,
	Chief Financial Officer

INDEX TO EXHIBITS

No.	Description of Exhibit

3.1	Certificate of Incorporation of Registrant (Incorporated by reference to Exhibit 3.1 to Form 10-Q of the Registrant for the fiscal quarter ended June 30, 2004)

3.2	Bylaws of Registrant (Incorporated by reference to Exhibit 3 of the Registrant’s Form 8-K, dated October 9, 2000, as filed with the Securities and Exchange Commission on October 10, 2000)

3.3	Certificate of Formation of Parallel, L.L.C. (Incorporated by reference to Exhibit No. 3.3 of the Registrant’s Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004)

3.4	Limited Liability Company Agreement of Parallel, L.L.C. (Incorporated by reference to Exhibit No. 3.4 of the Registrant’s Statement on Form S-3, No. 333-119725 filed on October 13, 2004)

3.5	Certificate of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit No. 3.5 of the Registrant’s Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004)

3.6	Agreement of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit No. 3.6 of the Registrant’s Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004)

4.1	Certificate of Designations, Preferences and Rights of Serial Preferred Stock - 6% Convertible Preferred Stock (Incorporated by reference to Exhibit 4.1 of Form 10-Q of the Registrant for the fiscal quarter ended June 30, 2004)

4.2	Certificate of Designation, Preferences and Rights of Series A Preferred Stock (Incorporated by reference to Exhibit 4.2 of Form 10-K of the Registrant 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 of the Registrant for the fiscal year ended December 31, 2000)

4.4	Form of Indenture relating to senior debt securities of the Registrant (Incorporated by reference to Exhibit No. 4.4 of the Registrant’s Statement on Form S-3, No. 333-119725 filed on October 13, 2004)

4.5	Form of Indenture relating to subordinated debt securities of the Registrant (Incorporated by reference to Exhibit No. 4.5 of the Registrant’s Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004)

4.6	Form of common stock certificate of the Registrant (Incorporated by reference to Exhibit No. 4.6 of the Registrant’s Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004)

4.7	Warrant Purchase Agreement, dated November 20, 2001, between the Registrant and Stonington Corporation (Incorporated by reference to Exhibit 4.7 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004)


4.8	Warrant Purchase Agreement, dated December 23, 2003, between the Registrant and Stonington Corporation (Incorporated by reference to Exhibit 4.8 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004)

	Executive Compensation Plans and Arrangements (Exhibit No.'s 10.1 through 10.8):

10.1	1992 Stock Option Plan (Incorporated by reference to Exhibit 10.1 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004)

10.2	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)

*10.3	Non-Employee Directors Stock Option Plan

10.4	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)

10.5	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 Form 10-K of the Registrant for the fiscal year ended December 31, 2001)

10.6	2001 Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.7 of the Registrant's Form 10-Q Report for the first fiscal quarter ended March 31, 2004)

10.7	2004 Non-Employee Director Stock Grant Plan (Incorporated by reference to Exhibit 10.1 of the Registrant's Form 8-K Report dated September 22, 2004)

10.8	Incentive and Retention Plan (Incorporated by reference to Exhibit 10.1 of the Registrant's Form 8-K Report dated September 23, 2004 and filed with the Securities and Exchange Commission on September 29, 2004)

10.9	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)

10.10	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)

10.11	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 of the Registrant for the fiscal year ended December 31, 2000)

10.12	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)


10.13	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)

10.14	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 of the Registrant for the fiscal year ended December 31, 2000)

10.15	Loan Agreement, dated as of January 25, 2002, between the Registrant and First American Bank, SSB (Incorporated by reference to Exhibit 10.25 of Form 10-K of the Registrant for the fiscal year ended December 31, 2001)

10.16	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)

10.17	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)

10.18	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)

10.19	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 Bank, SSB, Western National Bank, and BNP Paribas (Incorporated by reference to Exhibit 10.29 of Form 10-Q of the Registrant for the quarter ended September 30, 2003)

10.20	Second Amended and Restated Credit Agreement, dated September 27, 2004, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB, BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by reference to Exhibit 10.1 of the Registrant's Form 8-K Report dated September 27, 2004 and filed with the Securities and Exchange Commission on October 1, 2004)

10.21	Agreement of Limited Partnership of West Fork Pipeline Company LP (Incorporated by reference to Exhibit 10.21 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004)

10.22	First Amendment to Second Amended and Restated Credit Agreement, dated as of December 27, 2004, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB, BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K Report dated December 30, 2004 and filed with the Securities and Exchange Commission on December 30, 2004)

10.23	Second Amendment to Second Amended and Restated Credit Agreement, dated as of April 1, 2005, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB, BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K Report dated April 4, 2005 and filed with the Securities and Exchange Commission on April 8, 2005)


14	Code of Ethics (Incorporated by reference to Exhibit No. 14 of the Registrant’s Form 10-K Report for the fiscal year ended December 31, 2003 and filed with the Securities and Exchange Commission on March 22, 2004)

21	Subsidiaries (Incorporated by reference to Exhibit No. 21 of the Registrant’s Form 10-K Report for the fiscal year ended December 31, 2003 and filed with the Securities and Exchange Commission on March 22, 2004)

*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