Parallel Petroleum 10Q 2006 Q2 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended June 30, 2006 or


o		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
Midland, Texas		79701
(Address of principal executive offices)		(Zip Code)

(432) 684-3727
(Registrant’s telephone number, including area code)

Not Applicable
(Former name, former address and former fiscal year,
if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yesþ Noo

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filerþ Accelerated filero Non-accelerated filero

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12-b-2 of the Exchange Act). Yeso Noþ

At August 3, 2006, 34,964,992 shares of the Registrant’s Common Stock, $0.01 par value, were outstanding.

INDEX


			Page No.
PART I. — FINANCIAL INFORMATION

ITEM 1.		FINANCIAL STATEMENTS

		Reference is made to the succeeding pages for the following consolidated financial statements:

	-	Consolidated Balance Sheets as of June 30, 2006 (unaudited) and December 31, 2005		1

	-	Unaudited Consolidated Statements of Operations for the three months and six months ended June 30, 2006 and 2005		2

	-	Unaudited Consolidated Statements of Cash Flows for the six months ended June 30, 2006 and 2005		3

	-	Unaudited Consolidated Statements of Comprehensive Income (Loss) for the three months and six months ended June 30, 2006 and 2005		4

	-	Notes to Consolidated Financial Statements		5

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS				15

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK				30

ITEM 4. CONTROLS AND PROCEDURES				33

PART II. — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS				33

ITEM 1A. RISK FACTORS				34

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS				34

ITEM 6. EXHIBITS				34

SIGNATURES
Certification Pursuant to Section 302
Certification Pursuant to Section 302
Certification Pursuant to Section 906
Certification Pursuant to Section 906

(ii)

Part I. — Financial Information

Item I. Financial Statements

PARALLEL PETROLEUM CORPORATION

Consolidated Balance Sheets

(dollars in thousands, except per share amounts)


	June 30,			December 31,
	2006			2005
	(unaudited)
Assets
Current assets:
Cash and cash equivalents	$	6,333		$	6,418
Accounts receivable:
Oil and natural gas		13,048			13,183
Other, net of allowance for doubtful account of $9		3,684			877
Affiliates		36			12

		16,768			14,072

Other current assets		4,278			2,364
Deferred tax asset		6,393			5,241

Total current assets		33,772			28,095

Property and equipment, at cost:
Oil and natural gas properties, full cost method (including $36,273 and $19,869 not subject to depletion)		412,762			303,819
Other		3,188			2,404

		415,950			306,223
Less accumulated depreciation, depletion and amortization		(101,254	)		(90,826	)

Net property and equipment		314,696			215,397
Restricted cash		274			2,640
Investment in pipelines and gathering system ventures		9,506			3,326
Other assets, net of accumulated amortization of $1,107 and $901		3,482			3,550

	$	361,730		$	253,008


Liabilities and Stockholders’ Equity

Current liabilities:
Accounts payable and accrued liabilities	$	26,349		$	10,841
Asset retirement obligations		355			214
Derivative obligations		21,258			16,607

Total current liabilities		47,962			27,662


Revolving credit facility		123,500			50,000
Term Loan		50,000			50,000
Asset retirement obligations		4,065			2,281
Derivative obligations		26,721			25,527
Deferred tax liability		12,491			8,036

Total long-term liabilities		216,777			135,844

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,		—			—
Common stock — par value $0.01 per share, authorized 60,000,000 shares, issued and outstanding 34,960,295 and 34,748,916		350			347
Additional paid-in capital		79,755			78,699
Retained earnings		20,974			16,899
Accumulated other comprehensive loss		(4,088	)		(6,443	)

Total stockholders’ equity		96,991			89,502

	$	361,730		$	253,008

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

(1)

PARALLEL PETROLEUM CORPORATION

Consolidated Statements of Operations

(unaudited)

(in thousands, except per share data)


	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2005			2006			2005
Oil and natural gas revenues:
Oil and natural gas sales	$	29,594		$	15,004		$	52,870		$	27,973
Loss on hedging		(3,252	)		(2,741	)		(5,985	)		(5,296	)

Total revenues		26,342			12,263			46,885			22,677

Cost and expenses:
Lease operating expense		3,741			2,178			7,316			4,736
Production taxes		1,468			701			2,578			1,281
General and administrative		2,613			1,408			4,742			3,036
Depreciation, depletion and amortization		6,140			2,773			10,428			5,055

Total costs and expenses		13,962			7,060			25,064			14,108

Operating income		12,380			5,203			21,821			8,569


Other income (expense), net:
Change in fair market value of derivative instruments		(5,493	)		(6,063	)		(10,207	)		(23,696	)
Gain (loss) on ineffective portion of hedges		52			(150	)		195			(860	)
Interest and other income		25			20			93			39
Interest expense		(3,158	)		(868	)		(5,599	)		(2,041	)
Other expense		(39	)		(1	)		(68	)		(2	)
Equity in loss of pipelines and gathering system ventures		(10	)		(15	)		(29	)		(94	)

Total other income (expense), net		(8,623	)		(7,077	)		(15,615	)		(26,654	)

Income (loss) before income taxes		3,757			(1,874	)		6,206			(18,085	)
Income tax benefit (expense), deferred		(1,293	)		628			(2,131	)		6,135

Net income (loss)		2,464			(1,246	)		4,075			(11,950	)
Cumulative preferred stock dividend		—			(128	)		—			(271	)

Net income (loss) available to common stockholders	$	2,464		$	(1,374	)	$	4,075		$	(12,221	)


Net income (loss) per common share:
Basic	$	0.07		$	(0.04	)	$	0.12		$	(0.40	)

Diluted	$	0.07		$	(0.04	)	$	0.11		$	(0.40	)


Weighted average common share outstanding:
Basic		34,940			31,967			34,896			30,341

Diluted		35,638			31,967			35,572			30,341

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

(2)

PARALLEL PETROLEUM CORPORATION

Consolidated Statements of Cash Flows

Six Months Ended June 30, 2006 and 2005

(unaudited)

(dollars in thousands)


	2006			2005
Cash flows from operating activities:
Net income (loss)	$	4,075		$	(11,950	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		10,428			5,055
Accretion of asset retirement obligation		101			54
Deferred income tax		2,131			(6,135	)
Change in fair value of derivatives instruments		10,207			23,696
(Gain) loss on ineffective portion of hedges		(195	)		860
Stock option expense		292			70
Equity in loss of pipelines and gathering system ventures		29			94

Changes in assets and liabilities:
Other assets, net		718			123
Restricted cash		—			(149	)
Increase in accounts receivable		(2,696	)		(2,091	)
Increase in other current assets		(457	)		(11	)
Increase in accounts payable and accrued liabilities		15,508			1,800
Federal tax deposit		(40	)		—

Net cash provided by operating activities		40,101			11,416


Cash flows from investing activities:
Additions to oil and natural gas properties		(107,159	)		(25,431	)
Use of restricted cash for acquisition of oil and natural gas properties		2,366			2,287
Proceeds from disposition of oil and natural gas properties		41			2,828
Additions to other property and equipment		(784	)		(299	)
Settlements on derivative instruments		(2,651	)		(1,570	)
Purchase of derivative instruments		—			(35	)
Investment in pipelines and gathering system ventures		(6,209	)		(1,071	)

Net cash used in investing activities		(114,396	)		(23,291	)


Cash flows from financing activities:
Net borrowings (payments) on revolving line of credit		73,500			(17,000	)
Deferred financing cost		(56	)		—
Proceeds (net) from common stock issued		—			27,743
Proceeds from exercise of stock options		766			378
Payment of preferred stock dividend		—			(271	)

Net cash provided by financing activities		74,210			10,850


Net decrease in cash and cash equivalents		(85	)		(1,025	)

Cash and cash equivalents at beginning of period		6,418			4,781


Cash and cash equivalents at end of period	$	6,333		$	3,756


Non-cash financing and investing activities:
Oil and natural gas properties asset retirement obligations	$	1,825		$	65
Conversion of preferred stock	$	—		$	95
Other transactions:
Interest paid	$	5,026		$	2,290

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

(3)

PARALLEL PETROLEUM CORPORATION

Consolidated Statements of Comprehensive Income (Loss)

(unaudited)

(dollars in thousands)


	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2005			2006			2005
Net income (loss)	$	2,464		$	(1,246	)	$	4,075		$	(11,950	)


Other comprehensive loss:
Unrealized losses on derivatives		(1,084	)		(1,060	)		(2,384	)		(8,473	)
Reclassification adjustments for losses on derivatives included in net income (loss)		3,230			2,788			5,951			5,418

Change in fair value of derivatives		2,146			1,728			3,567			(3,055	)
Income tax benefit (expense)		(730	)		(588	)		(1,213	)		1,038


Total other comprehensive income (loss)		1,416			1,140			2,354			(2,017	)


Total comprehensive income (loss)	$	3,880		$	(106	)	$	6,429		$	(13,967	)

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

(4)

PARALLEL PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


NOTE 1.		DESCRIPTION OF BUSINESS — NATURE OF OPERATIONS AND BASIS OF PRESENTATION

Parallel 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, the Fort Worth Basin of north Texas and the onshore Gulf Coast area of south Texas. We are actively evaluating, leasing and drilling new projects located in 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, 2005 which has been derived from our audited Consolidated Financial Statements as of December 31, 2005. 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 2005 amounts have been conformed to the 2006 financial statement presentation.

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, 2005.

Unless otherwise indicated or unless the context otherwise requires, all references 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.

In December 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 123 (revised 2004),Share-Based Payment(SFAS 123(R)). The standard amends SFAS 123 Accounting for Stock Based Compensation and concludes that services received from employees in exchange for stock-based compensation results is a cost to the employer that must be recognized in the financial statements. The cost of such awards should be measured at fair value at grant date.

Parallel adopted SFAS 123(R) effective January 1, 2006, and is applying the modified prospective method, whereby compensation cost will be recognized for the unvested portion of awards granted during the period of June 2001 to August 2005. No options that were granted prior to June 2001 remain unvested at January 1, 2006. Such costs will be recognized in the financial statements of Parallel over the remaining vesting periods. Under this method, prior periods are not revised for comparative purposes.

(5)

For the six months ended June 30, 2006 and 2005, Parallel recognized compensation expense of approximately $0.35 million and $0.07 million, with a tax benefit of $0.12 million and $0.02 million, respectively, associated with its stock option grants.

During the second quarter of 2006, Parallel determined that during 2003 approximately 30,000 options were awarded which were not available for issue under existing stock option plans. In June 2006, the Board of Directors approved a plan whereby these excess options will be repurchased by Parallel for cash totaling approximately $0.51 million. This amount was charged to expense during the second quarter of 2006.

The following table presents the future stock-based compensation expense expected to be recognized over the vesting period of:


	(in thousands)
Third quarter 2006	$	143
Fourth quarter 2006		96
2007		324
2008 through 2011		338

Total	$	901

Nonvested options were 237,500 at June 30, 2006. During the six months ending June 30, 2006, options to purchase 176,250 shares of common stock were exercised; however, no options were granted, expired or forfeited.

The fair value of each option award is estimated on the date of grant. The fair value of stock options granted prior to and remaining outstanding at January 1, 2006 and that had option shares subject to future vesting at that date was determined using the Black-Scholes option valuation method assumptions noted in the following table. Expected volatilities are based on historical volatility of our common stock. The expected term of the options granted used in the model represent the period of time that options granted are expected to be outstanding.


	2001			2005
Expected volatility		57.95	%		54.20	%
Expected dividends		0.00			0.00
Expected term (in years)		8			7
Risk-free rate		5.050	%		4.200	%

A summary of the option activity as of June 30, 2006 is presented below:


						Wtd Avg.
						Remaining
				Wtd. Avg.		Contractual		Aggregate
	Options			Exercise Price		Term		Intrinsic Value
	(in thousands)					(years)		(in thousands)
Outstanding December 31, 2005		1,405		$	5.22
Granted		—		$	—
Exercised		(176	)	$	4.35
Surrendered		(30	)	$	3.09

Outstanding June 30, 2006		1,199		$	5.40		5.9	$	3,729

Exercisable at June 30, 2006		961		$	3.99		4.5	$	2,185

The total aggregate intrinsic value of options exercised during the six months ended June 30, 2006 and 2005, was $0.442 million and $0.216 million, respectively. There were no stock options granted for the six months ended June 30, 2006 and June 30, 2005.

(6)

The following table illustrates the effect on net income and earnings per share if we had applied the fair value recognition provisions of Statement No 123(R) to options under our stock-based compensation plans in all periods presented.


	Three Months Ended			Six Months Ended
	June 30, 2005			June 30, 2005
	(in thousands, except per share data)
Net income, as reported	$	(1,246	)	$	(11,950	)
Add:
Expense recorded in 2005, net of related tax effects		28			70
Deduct:
Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		(23	)		(71	)

Pro forma net loss	$	(1,241	)	$	(11,951	)


Loss per share:
Basic — as reported	$	(0.04	)	$	(0.40	)

Basic — proforma	$	(0.04	)	$	(0.40	)

Diluted — as reported	$	(0.04	)	$	(0.40	)

Diluted — proforma	$	(0.04	)	$	(0.40	)

We have outstanding stock options granted under three separate plans. Options expire 10 years from the date of grant and become exercisable at a rate of 10% each year under one and at a rate of 20% each year under the other two plans. The exercise price of the options is equal to the fair market value per share of common stock on the date of grant.

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 $28.0 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 the revolving credit facility.

Preferred Stock

On June 6, 2005, outstanding shares of Parallel’s 6% Convertible Preferred Stock, $0.10 par value per share, were converted to common stock. Under terms of the preferred stock, all of the holders of the preferred stock elected to convert their shares into shares of Parallel common stock based on a 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 was no longer outstanding.

NOTE 3. CREDIT FACILITIES

We have two separate credit facilities. Our Third Amended and Restated Credit Agreement or the “Revolving Credit Agreement”, dated as of December 23, 2005, with a group of bank lenders provides a revolving line of credit having a “borrowing base” limitation of $140.0 million at June 30, 2006. The total amount that we can borrow and have outstanding at any one time is limited to the lesser of $350.0 million or the borrowing base established by the lenders. At June 30, 2006, the principal amount outstanding under our revolving credit facility was $123.5 million, excluding $0.49 million reserved for our letters of credit. The second credit facility is a five year term loan facility provided to us under a Second Lien Term Loan Agreement (the “Second Lien Agreement”), dated as of November 15, 2005, with a group of banks and other lenders. At June 30, 2006, our term loan under this facility was fully funded in the principal amount of $50.0 million, which was outstanding on that same date.

(7)

Revolving Credit Facility

The Revolving Credit Agreement provides for a credit facility that allows us to borrow, repay and reborrow amounts available under the revolving credit facility. The amount of the borrowing base is based primarily upon the estimated value of our oil and natural 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 loans exceeds the borrowing base, we must either provide additional collateral to the lenders or repay the outstanding principal of our loans 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 revolving credit facility bear interest at the base rate of Citibank, N.A. or the LIBOR rate, at our election. Generally, Citibank’s base rate is equal to its “prime rate” as announced from time to time by Citibank.

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 2.00% to 2.50%, 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 2.50%. If the principal amount outstanding is equal to or greater than 50%, but less than 75% of the borrowing base, the margin is 2.25%. If the principal amount outstanding is less than 50% of the borrowing base, the margin is 2.00%.

The interest rate we are required to pay on our borrowings, including the applicable margin, may never be less than 5.00%. At June 30, 2006, our weighted average base and LIBOR rates, plus margin, were 7.80% on $123.5 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 revolving 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.

All outstanding principal under the revolving credit facility is due and payable on October 31, 2010. The maturity date of our outstanding loans may be accelerated by the lenders upon the occurrence of an event of default under the Revolving Credit Agreement.

As of June 30, 2006 we were in compliance with our debt covenants.

Second Lien Term Loan Facility

The Second Lien Agreement provides a $50.0 million term loan. Loans made to us under this credit facility bear interest at an alternate base rate or the LIBOR rate, at our election. The alternate base rate is the greater of (a) the prime rate in effect on such day and (b) the “Federal Funds Effective Rate” in effect on such day plus¹/2 of 1%, plus a margin of 3.50% per annum.

The LIBOR rate is generally equal to the sum of a (a) the rate designated as “British Bankers Association Interest Settlement Rates” and offered on one, two, three or six month interest periods for deposits of $1.0 million and (b) an applicable margin rate per annum equal to 4.50%.

At June 30, 2006, our Libor interest rate, plus the applicable margin, was 9.9375% on $50.0 million.

In the case of alternate base rate loans, interest is payable the last day of each March, June, September and December. In the case of LIBOR loans, interest is payable the last day of the tranche period not to exceed a three month period.

(8)

All outstanding principal under the Second Lien Agreement is due and payable on November 15, 2010. The maturity date may be accelerated by the lenders upon the occurrence of an event of default under the Second Lien Agreement.

Prepayments in whole or in part if made prior to the first anniversary date will bear a premium of 1% of the amount prepaid. There is no premium after the first anniversary date.

As of June 30, 2006 we were in compliance with our debt covenants.

Interest expense for the six months ending June 30, 2006, for both facilities, was approximately $5.6 million not including approximately $0.3 million for interest capitalized associated with drilling projects.

NOTE 4. ACQUISITIONS

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.

In November 2005 and January 2006, we purchased properties in the Harris San Andres located in Andrews and Gaines County, Texas. The combined net purchase price was approximately $44.2 million.

In March 2006, we purchased additional interests in our Barnett Shale Gas Project located in Tarrant County, Texas. The additional interests were acquired from five unaffiliated parties for a total cash purchase price of approximately $5.5 million. In April 2006, we acquired an additional interest in the Barnett Shale Gas Project located in Tarrant County, Texas from one other unaffiliated third party for approximately $0.57 million.

The table below reflects our consolidated pro forma results of operations for the three and six months ended June 30, 2006, compared to the actual consolidated results of operations for the same period ended June 30, 2005, assuming the 2006 acquisitions were consummated on January 1, 2005.


	Three Months Ended					Six Months Ended
	June 30,					June 30,
	Pro Forma		Pro Forma			Pro Forma		Pro Forma
	2006		2005			2006		2005
	(in thousands, except per share data)
Oil and natural gas sales, net of hedge losses	$	26,342	$	13,968		$	47,441	$	26,120
Operating income	$	12,380	$	6,412		$	22,141	$	10,991
Net income (loss) available to common stockholder	$	2,464	$	(1,238	)	$	4,211	$	(11,938	)

Net income (loss) per common share:
Basic	$	0.07	$	(0.04	)	$	0.12	$	(0.39	)
Diluted	$	0.07	$	(0.04	)	$	0.12	$	(0.39	)

NOTE 5. PREFERRED STOCK

At March 31, 2005, we had outstanding 950,000 shares of 6% Convertible Preferred Stock, $0.10 par value per share. Cumulative annual dividends of $0.60 per share are payable semi-annually on June 15 and December 15 of each year. Each share of preferred stock was entitled to be converted, at the option of the holder, into 2.8571 shares of common stock at an initial conversion price of $3.50 per share, subject to adjustment in certain events. The preferred stock has a liquidation preference of $10 per share and had no voting rights, except as required by law.

On May 4, 2005, we notified the holders of the preferred stock that all 950,000 outstanding shares of our 6% preferred stock would be redeemed on June 6, 2005. All of the holders of the preferred stock elected to convert their shares of preferred stock into shares of Parallel common stock based on a conversion rate of $10 divided by $3.50. The holders of the preferred stock received approximately 2.8571 shares of common stock of Parallel for

(9)

each share of preferred stock. Dividends on the preferred stock ceased to accrue, and as of June 6, 2005 the preferred stock was no longer outstanding.

NOTE 6. FULL COST CEILING TEST

We use the full cost method to account for our oil and natural gas producing activities. Under the full cost method of accounting, the net book value of oil and natural 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 natural 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 natural 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, 2006, we had a cushion (i.e. the excess of the ceiling over our capitalized cost) in excess of $243.0 million. As a result, we were not required to record a reduction of our oil and natural 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, 2006 and 2005, overhead costs capitalized were approximately $0.83 million and $0.6 million, respectively.

NOTE 7. DERIVATIVE INSTRUMENTS

General

We enter into derivative contracts to provide a measure of stability in the cash flows associated with our oil and natural gas production 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 natural gas prices and to limit variability in our cash interest payments. Our line of credit agreement as of June 30, 2006, required us to maintain derivative financial instruments which limit our exposure to fluctuating commodity prices covering at least 50% of our estimated monthly production of oil and natural gas extending 24 months into the future.

We designated all of our interest rate swaps, collars, puts and commodity swaps entered into in 2002 through June 30, 2004 as cash flow hedges (“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 income (loss) and then transferred to oil and natural gas revenues when the production is sold and interest expense as the interest accrues. Ineffective portions of hedges (changes in fair value resulting from changes in realized prices that do not match the changes in the hedge or reference price) are recognized in gain (loss) on ineffective portion of hedges as they occur.

As of June 30, 2006, we have recorded unrealized losses of $6.2 million ($4.1 million, net of tax) related to our derivative instruments designated as hedges, which represented the estimated aggregate fair values of our open hedge contracts as of that date. These unrealized losses are presented in stockholders’ equity in the Consolidated Balance Sheet as accumulated other comprehensive loss.

Derivative contracts not designated as hedges are “marked-to-market” at each period end and the increases or decreases in fair values recorded to earnings. No derivative instruments entered into subsequent to June 30, 2004 have been designated as cash flow hedges.

(10)

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

Interest Rate Sensitivity

We entered into fixed interest rate swap contracts with BNP Paribas, based on the 90-day LIBOR rates at the time of the contracts. These interest rate swaps are treated as cash flow hedges as defined by Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended (“SFAS 133”), and are on $10.0 million of our variable rate debt for all of 2006. We will continue to pay the variable interest rates for this portion of our borrowing under the Credit Agreement, but due to the interest rate swaps, we have fixed the rate at 4.05%. As of June 30, 2006, the fair market value of these interest rate swaps was $0.07 million.

As of June 30, 2006, we had also employed additional fixed interest rate swap contracts with BNP Paribas and Citibank, N.A. based on the 90-day LIBOR rates at the time of the contracts. However, these contracts are accounted for by “mark-to-market” accounting as prescribed in SFAS 133. Nonetheless, we view these contracts as additional protection against future interest rate volatility.

The table below recaps the nature of these interest rate swaps and the fair market value of these contracts as of June 30, 2006.


	Notional					Fair
Period of Time	Amounts		Fixed Interest Rates			Market Value
	($ in millions)					($ in thousands)
July 1, 2006 thru December 31, 2006⁽¹⁾	$	10		4.05	%	$	70
July 1, 2006 thru December 31, 2006	$	90		4.41	%		486
January 1, 2007 thru December 31, 2007	$	100		4.62	%		850
January 1, 2008 thru December 31, 2008	$	100		4.86	%		572
January 1, 2009 thru December 31, 2009	$	50		5.06	%		195
January 1, 2010 thru October 31, 2010	$	50		5.15	%		141

Total Fair Market Value						$	2,314


(1)		Designated as cash flow hedge.

Commodity Price Sensitivity

Except for the one commodity swap noted in the table below under Commodity Swaps that is designated as a hedge, all of our commodity derivatives are accounted for using “mark-to-market” accounting as prescribed in SFAS 133.

Put Options. In 2005 we purchased put options or “floors” on volumes of 3,000 MMBtu per day for a total of 642,000 MMBtu during the seven month period from April 1, 2006 through October 31, 2006 at an average floor price of $7.17 per MMBtu for a total consideration of approximately $0.23 million. The remaining put options volumes of 369,000 MMBtu have a fair market value of $0.6 million as of June 30, 2006.

Collars. Collars are contracts which combine both a put option or “floor” and a call option or “ceiling”. These contracts may or may not involve payment or receipt of cash at inception, depending on the “ceiling” and “floor” pricing.

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A summary of our collar positions at June 30, 2006 is as follows:


									Houston Ship
			NyMex Oil Prices						Channel Gas Prices				WAHA Gas Prices
	Barrels of						MM Btu of										Fair Market
Period of Time	Oil		Floor		Cap		Natural Gas		Floor		Cap		Floor		Cap		Value
																	($ in thousands)
July 1, 2006 thru December 31, 2006		145,000	$	48.32	$	76.07		—	$	—	$	—	$	—	$	—	$	(1,186	)
July 1, 2006 thru October 31, 2006		—	$	—	$	—		246,000	$	7.50	$	13.90	$	—	$	—		464
July 1, 2006 thru October 31, 2006		—	$	—	$	—		123,000	$	—	$	—	$	9.00	$	14.55		425
January 1, 2007 thru December 31, 2007		219,000	$	52.50	$	83.00		—	$	—	$	—	$	—	$	—		(785	)
April 1, 2007 thru October 31, 2007		—	$	—	$	—		214,000	$	6.00	$	11.05	$	—	$	—		(48	)
January 1, 2008 thru December 31, 2008		109,800	$	55.00	$	76.50		—	$	—	$	—	$	—	$	—		(510	)
January 1, 2009 thru December 31, 2009		91,250	$	55.00	$	73.00		—	$	—	$	—	$	—	$	—		(436	)
January 1, 2010 thru October 31, 2010		76,000	$	55.00	$	71.00		—	$	—	$	—	$	—	$	—		(338	)

Total Fair Market Value																	$	(2,414	)

Commodity Swaps. Generally, swaps are an agreement to buy or sell a specified commodity for delivery in the future, at an agreed fixed price. Swap transactions convert a floating or market price into a fixed price. For any particular swap transaction, the counterparty is required to make a payment to the Company if the reference price for any settlement period is less than the swap or fixed price for such contract, and the Company is required to make a payment to the counterparty if the reference price for any settlement period is greater than the swap or fixed price for such contract.

A recap for the period of time, number of barrels and swap prices are as follows:


			Nymex Oil		Fair Market
Period of Time	Barrels of Oil		Swap Price		Value
					($ in thousands)
July 1, 2006 thru December 20, 2006⁽¹⁾		129,750	$	23.04	$	(6,694	)
July 1, 2006 thru December 31, 2006		92,000	$	36.35		(3,544	)
January 1, 2007 thru December 31, 2007		474,500	$	34.36		(18,620	)
January 1, 2008 thru December 31, 2008		439,200	$	33.37		(15,829	)

Total fair market value					$	(44,687	)


(1)		Designated as a cash flow hedge.

NOTE 8. NET INCOME (LOSS) 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.

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The following table provides the computation of basic and diluted earnings per share for the three and six months ended June 30, 2006 and 2005:


	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2006		2005			2006		2005
	(dollars in thousands, except per share data)
Basic EPS Computation:
Numerator-
Income (loss)	$	2,464	$	(1,246	)	$	4,075	$	(11,950	)
Preferred stock dividend		—		(128	)		—		(271	)


Income (loss) available to common stockholders	$	2,464	$	(1,374	)	$	4,075	$	(12,221	)


Denominator-
Weighted average common shares outstanding		34,940		31,967			34,896		30,341


Basic EPS:
Income (loss) per share	$	0.07	$	(0.04	)	$	0.12	$	(0.40	)


Diluted EPS Computation:
Numerator-
Income (loss)	$	2,464	$	(1,246	)	$	4,075	$	(11,950	)
Preferred stock dividend		—		(128	)		—		(271	)

Income (loss) available to common stockholders	$	2,464	$	(1,374	)	$	4,075	$	(12,221	)


Denominator -
Weighted average common shares outstanding		34,940		31,967			34,896		30,341
Employee stock options		591		—			571		—
Warrants		107		—			105		—
Preferred stock		—		—			—		—

Weighted average common shares for diluted earnings per share assuming conversion		35,638		31,967			35,572		30,341


Diluted EPS:
Income (loss) per share	$	0.07	$	(0.04	)	$	0.11	$	(0.40	)

Some stock options and the convertible preferred stock outstanding were not included in the computation of diluted net income (loss) per share for the three and six months ended June 30, 2005 because Parallel had a net loss from continuing operations and, therefore, the effect would be antidilutive.

NOTE 9. ASSET RETIREMENT OBLIGATIONS

On January 1, 2003, we adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations “SFAS 143”. SFAS 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 natural gas properties.

(13)

The following table summarizes our asset retirement obligation transactions:


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
	(in thousands)
Beginning asset retirement obligation	$	4,279		$	2,112		$	2,495		$	2,132

Additions related to new properties		83			109			191			128

Revisions in estimated cash flows		(1	)		4			1,663			2

Deletions related to property disposals		(10	)		(2	)		(30	)		(65	)

Accretion expense		69			28			101			54


Ending asset retirement obligation	$	4,420		$	2,251		$	4,420		$	2,251

NOTE 10. INVESTMENT IN GAS GATHERING SYSTEM

Parallel has invested $2.9 million in an unincorporated joint venture which is constructing and will operate a gas gathering system in Chavez County, New Mexico. Parallel owns approximately 76.5% of the joint venture interest. Under the joint venture agreement, the joint venture is controlled by a management committee made up of Parallel and the two remaining investors in the joint venture. All significant actions of the joint venture must be approved by a vote representing a majority of the joint venture ownership interest plus one other management committee member. Therefore, either Parallel or the remaining two joint venturers acting in concert have the power to veto any matter. As a result of this voting arrangement, Parallel does not have effective voting control and, therefore, Parallel’s investment in the joint venture is accounted for by the equity method.

NOTE 11. COMMITMENTS AND CONTINGENCIES

On December 30, 2005, Parallel was named as a defendant in a lawsuit filed in the 352nd Judicial District Court of Tarrant County, Texas, Cause No. 352-215616-05, AFE Oil and Gas, L.L.C. (aka AFE Oil and Gas, LLC) v. Premium Resources II, L.P., Premium Resources, Inc., Danay Covert, Nick Morris, William D. Middleton, Dale Resources, L.L.C., and Parallel Petroleum, Inc.

In this suit, the plaintiff alleges breach of fiduciary duty, fraud and conspiracy to defraud, breach of contract, constructive trust, suit to remove cloud from title, declaratory judgment, alter ego, and statutory fraud and seeks recovery of an unspecified amount of actual damages, special damages, consequential damages, exemplary damages, attorneys’ fees, pre-judgment and post-judgment interest and costs. Generally, the plaintiff alleges that it owns a 5.5% overriding royalty interest in certain oil and gas properties known as the “Square Top LP” and the “West Fork LP” leases located in Tarrant County, Texas. The plaintiff alleges that the defendants (other than Dale Resources and Parallel) wrongfully and intentionally allowed these original oil and gas leases to terminate; causing the termination of plaintiff’s overriding royalty interest in each lease. The plaintiff further alleges that the defendants (other than Dale Resources and Parallel) failed to drill wells necessary to maintain the original leases in force and that after the original leases were allowed to terminate, the defendants (other than Dale Resources and Parallel) then acquired new oil and gas leases covering these same oil and gas properties, which were subsequently assigned to Dale Resources. Thereafter, Dale Resources allegedly assigned a portion of these new leases to Parallel.

In addition to seeking unspecified monetary damages, the plaintiff also seeks to impose a constructive trust for its benefit on the new oil and natural gas leases and seeks a judicial declaration that either (1) the plaintiff is the owner of an overriding royalty interest in the new leases or that (2) the original leases and plaintiff’s interest in the original leases are still in effect. The plaintiff also claims that the new leases constitute a cloud on plaintiff’s title and seeks to have that cloud removed. Based on Parallel’s present understanding of this case, Parallel believes that it has substantial defenses to the plaintiff’s claims and intends to vigorously assert these defenses. However, if the plaintiff is awarded an interest in the new leases, then Parallel could potentially become liable for the payment to plaintiff of the portion of production proceeds attributable to plaintiff’s interest received by Parallel. On the other hand, if the plaintiff prevails on its claim that the original leases are still in effect, Parallel’s interest in the new leases could

(14)

become subject to forfeiture. Based on the information known to date, Parallel has not established a reserve for this matter.

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, 2006 and 2005 Parallel had made contributions to the 401(k) Plan and Trust of approximately $0.11 million and $0.08 million, respectively.

NOTE 12. SUBSEQUENT EVENTS

We announced on July 12, 2006 that we had entered into collars covering approximately 1.17 million barrels of oil associated with our estimated proved developed producing reserves. BNP Paribas and Citibank, NA are the counterparties for these derivatives, which are West Texas Intermediate (WTI) costless collars with $65.00 floors and caps ranging from $92.00 to $79.60 for the period October 2006 thru October 2010. These collars have not been designated as hedges.


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 management’s discussion and analysis contained in our 2005 Annual Report on Form 10-K, as well as the unaudited consolidated financial statements and notes thereto included in this quarterly report on Form 10-Q.

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.

(15)

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.

(16)

For the three months ended June 30, 2006 the sale price we received for our crude oil production (excluding hedges) averaged $63.17 per barrel compared with $46.97 per barrel for the three months ended June 30, 2005. The average sales price we received for natural gas for the three months ended June 30, 2006 (excluding hedges), was $6.25 per Mcf compared with $6.78 per Mcf for the three months ended June 30, 2005. For information regarding prices received including our hedges, refer to the selected operating data table in the Results of Operations on page 18. Hedge costs for oil and natural gas were $3.3 million and $2.7 million for the three months ended June 30, 2006 and June 30, 2005, respectively. The hedge gain (loss) associated with the ineffective portion of our hedges increased $0.2 million to a gain of approximately $0.05 million in the three months ended June 30, 2006 compared to a loss of approximately ($0.2 million) for the three months ended June, 2005. The reduction in ineffectiveness is caused by a reduction of the differential price of West Texas Intermediate Light and current designated sales of West Texas Sour barrels. 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, 2006, the sale price we received for our crude oil production (excluding hedges) averaged $60.56 per barrel compared with $46.15 per barrel for the six months ended June 30, 2005. The average sales price we received for natural gas for the six months ended June 30, 2006 and June 30, 2005 (excluding hedges), was $6.42. For information regarding prices received including our hedges, refer to the selected operating data table in the Results of Operations on page 18. Hedge costs for oil and natural gas were $6.0 million and $5.3 million for the six months ended June 30, 2006 and June 30, 2005, respectively. The hedge gain (loss) associated with the ineffective portion of our hedges increased $1.1 million to a gain of approximately $0.2 million in the six months ended June 30, 2006 compared to a loss of approximately ($0.86 million) for the six months ended June 30, 2005. The reduction in ineffectiveness is caused by a reduction of the differential price of West Texas Intermediate Light and current designated sales of West Texas Sour barrels. 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 natural gas properties being depleted. Depletion per BOE at June 30, 2006 and 2005 was $9.74 and $7.51 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); and

	•		the prices we receive for our oil and natural gas production.

(17)

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, 2006 and June 30, 2005.


	Three Months Ended						Six Months Ended
	6/30/2006			6/30/2005			6/30/2006			6/30/2005
	(in thousands, except per unit data)
Production Volumes:
Oil (Bbls)		298			218			566			425
Natural gas (Mcf)		1,726			700			2,893			1,302
BOE⁽¹⁾		586			335			1,048			642
BOE per day		6.4			3.7			5.8			3.5

Sales Prices:
Oil (per Bbl)⁽²⁾	$	63.17		$	46.97		$	60.56		$	46.15
Natural gas (per Mcf)⁽²⁾	$	6.25		$	6.78		$	6.42		$	6.42
BOE price⁽²⁾	$	50.56		$	44.77		$	50.43		$	43.57
BOE price⁽³⁾	$	45.01		$	36.60		$	44.72		$	35.32

Operating Revenues
Oil	$	18,802		$	10,259		$	34,284		$	19,618
Oil hedge		(3,252	)		(2,741	)		(5,985	)		(5,095	)
Natural gas		10,792			4,745			18,586			8,355
Natural gas hedge		—			—			—			(201	)

	$	26,342		$	12,263		$	46,885		$	22,677


Operating Expenses:
Lease operating expense	$	3,741		$	2,178		$	7,316		$	4,736
Production taxes		1,468			701			2,578			1,281
General and administrative:
General and administrative		1,523			859			2,657			1,828
Public reporting		1,090			549			2,085			1,208
Depreciation, depletion and amortization		6,140			2,773			10,428			5,055

	$	13,962		$	7,060		$	25,064		$	14,108


Operating income	$	12,380		$	5,203		$	21,821		$	8,569


(1)		A BOE means one barrel of oil equivalent using the ratio of six Mcf of gas to one barrel of oil.

(2)		Unhedged price is the actual price received at the wellhead for our oil and natural gas.

(3)		Hedged price is the actual price received at the wellhead for our oil and natural gas plus or minus the settlements on our derivatives.

(18)

RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED JUNE 30, 2006 AND 2005:

Our oil and natural gas revenues and production product mix are displayed in the following table for the three months ended June 30, 2006 and June 30, 2005.

Oil and Gas Revenues


	Revenues⁽¹⁾						Production
	2006			2005			2006			2005
Oil (Bbls)		59	%		61	%		51	%		65	%
Natural gas (Mcf)		41	%		39	%		49	%		35	%

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
	2006			2005			(Decrease)			(Decrease)
				(in thousands except per unit data)
Production Volumes
Oil (Bbls)		298			218			80			37	%
Natural gas (Mcf)		1,726			700			1,026			147	%
BOE		586			335			251			75	%
BOE/Day		6.4			3.7			2.7			74	%

Sales Price
Oil (per Bbl)⁽¹⁾	$	63.17		$	46.97		$	16.20			34	%
Natural gas (per Mcf)⁽¹⁾	$	6.25		$	6.78		$	(0.53	)		(8	)%
BOE price⁽¹⁾	$	50.56		$	44.77		$	5.79			13	%
BOE price⁽²⁾	$	45.01		$	36.60		$	8.41			23	%

Operating Revenues
Oil	$	18,802		$	10,259		$	8,543			83	%
Oil hedges	$	(3,252	)	$	(2,741	)	$	511			19	%
Natural gas	$	10,792		$	4,745		$	6,047			127	%

Total	$	26,342		$	12,263		$	14,079			115	%


(1)		Excludes hedge transactions.

(2)		Includes hedge transactions.

Oil revenues, excluding hedges, increased $8.5 million or 83% for the three months ended June 30, 2006 compared to the same period of 2005. Oil production volumes increased 37% which was primarily due to the Harris Field acquisition and drilling programs in the Carm-Ann San Andres Field/N. Means Queen Unit and the Diamond M Property. The increase in oil production increased revenue approximately $3.7 million for 2006. Wellhead average realized crude oil prices increased $16.20 per Bbl or 34% to $63.17 per Bbl for 2006 compared to 2005. The increase in oil price increased revenue approximately $4.8 million for 2006.

Natural gas revenues, excluding hedges, increased $6.1 million or 127% for the three months ended June 30, 2006 compared to the same period of 2005. Natural gas production volumes increased 147% primarily due to the drilling program in the Barnett Shale in north Texas, New Mexico area and the Wilcox natural gas discovery in south Texas. The increase in natural gas volumes increased revenue approximately $7.0 million for 2006. Average

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realized wellhead natural gas prices decreased 8% or $0.53 per Mcf to $6.25 per Mcf. The decrease in natural gas prices had a negative effect on revenues of approximately $0.9 million for the three months ending June 30, 2006.

Losses on oil hedges increased $0.5 million or 19% for 2006 compared to 2005 due to the increase in oil prices. On a BOE basis, hedges accounted for a realized loss of $5.55 per BOE in 2006 compared to $8.17 per BOE in 2005. We have hedged certain oil volumes to try and mitigate price changes in our oil movements and to meet the requirements under our loan facility. BOE production increased 251 BOE or 75% for 2006 compared to the same period in 2005.

Cost and Expenses


	Three months ended June 30,				Increase		% Increase
	2006		2005		(Decrease)		(Decrease)
	(dollars in thousands)
Lease operating expense	$	3,741	$	2,178	$	1,563		72	%
Production taxes		1,468		701		767		109	%
General and administrative:
General and administrative		1,523		859		664		77	%
Public reporting		1,090		549		541		99	%

Total general and administrative		2,613		1,408		1,205		86	%

Depreciation, depletion and amortization		6,140		2,773		3,367		121	%

Total	$	13,962	$	7,060	$	6,902		98	%

Lease operating costs increased approximately $1.6 million, or 72%, to $3.7 million during the three months ended June 30, 2006 compared with $2.2 million for the same period of 2005. The increase in lease operating expense is primarily due to increased well count due to our drilling program in the Diamond M Deep, Cam-Ann San Andres Field/ N. Means Queen Unit and Barnett Shale Fields as well as the acquisition of the Harris Field, and increased ad valorem taxes. Lifting costs were $6.38 per BOE in 2006 compared to $6.50 per BOE in 2005. As we continue to exploit and develop our long-life Permian Basin oil properties (Fullerton, Carm-Ann, Harris 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 the Barnett Shale and New Mexico.

Production taxes increased 109% or $0.8 million in 2006, associated with an increase in revenues of $14.6 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 86% or $1.2 million in 2006 compared to 2005. Included in our total general and administrative expenses is public reporting cost which increased 99% or $0.5 million. Public reporting increased due to increases in investor relation presentations including road shows and the annual stockholder meeting. In addition public reporting also experienced increases in director stock option expenses as well as employee compensation related expenditures. The remainder of the increase in general and administrative costs is due to employee compensation and related benefit costs. During the second quarter of 2006, we determined that during 2003 approximately 30,000 options were awarded which were not available for issue under existing stock option plans. In June 2006, the Board of Directors approved a plan whereby these excess options would be repurchased for cash totaling approximately $0.5 million. This amount was charged to expense during the second quarter of 2006. General and administrative expenses capitalized to the full cost pool were $0.4 million for 2006 compared to $0.3 million in 2005. On a BOE basis, general and administrative costs were $2.60 per BOE in 2006 compared to $2.56 per BOE in 2005, while public reporting costs were $1.86 per BOE and $1.64 per BOE for the same period. General and administrative expenses will increase in 2006 in association with the reporting requirements and operational support.

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Depreciation, depletion and amortization expense increased 121% or $3.4 million for 2006 compared to 2005. Depreciation, depletion and amortization per BOE was $10.49 for 2006 and $8.28 for 2005. 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 2006 depletion will increase with increased production volumes and capital expenditures.

Other income (expense)


	Three months ended June 30,						Increase			% Increase
	2006			2005			(Decrease)			(Decrease)
	(dollars in thousands)
Change in fair market value of derivatives	$	(5,493	)	$	(6,063	)	$	(570	)		(9	)%
Gain (loss) on ineffective portion of hedges		52			(150	)		202			135	%
Interest and other income		25			20			5			25	%
Interest expense, net		(3,158	)		(868	)		2,290			264	%
Other expense		(39	)		(1	)		38			3,800	%
Equity in loss of pipelines and gathering system ventures		(10	)		(15	)		(5	)		(33	)%

Total	$	(8,623	)	$	(7,077	)	$	1,546			22	%

The loss associated with the change in fair market value of derivatives decreased by $0.6 million in 2006 compared to 2005. While the gain associated with the ineffective portion of our hedges increased $0.2 million for 2006 compared to 2005. Crude oil prices continued to increase into the second quarter of 2006. Meanwhile natural gas prices went in the opposite direction and continued their decrease in the second quarter of 2006. Our total volumes designated as cash flow hedges decreased in 2006 compared to 2005. This resulted in a gain in the ineffectiveness for the 2006 although the spread between sweet and sour crude was wider. The actual gain or loss may increase or decrease until settlement of these contracts.

Interest expense increased with the increase of debt from approximately $62.0 million at June 30, 2005 to $173.5 million at June 30, 2006 along with an increase of our loan interest rate for 2006. Capitalized interest on work in progress decreased interest expense by $0.3 million in 2006, an increase of $0.25 million compared to 2005.

Income tax expense was $1.3 million in 2006 compared to a benefit of $0.6 million in 2005. Income tax expense for 2006 will be dependent on our earnings and is expected to be approximately 35% of income before income taxes.

We had basic net earnings per share of $.07 and net loss of $.04 and diluted net earnings per share of $.07 and net loss of $.04 for 2006 and 2005, respectively. Basic weighted average common shares outstanding increased from 32.0 million shares in 2005 to 34.9 million shares in 2006. The increase in common shares is due to the redemption of preferred shares to common shares in June of 2005. The stock options and the convertible preferred stock outstanding were not included in the computation of diluted net earnings (loss) per share for the second quarter 2005 because we had a net loss and the effect would be antidilutive.

RESULTS OF OPERATIONS FOR THE SIX MONTHS ENDED JUNE 30, 2006 AND 2005:

Our oil and natural gas revenues and production product mix are displayed in the following table for the six months ended June 30, 2006 and June 30, 2005.

Oil and Gas Revenues


	Revenues⁽¹⁾						Production
	2006			2005			2006			2005
Oil (Bbls)		60	%		64	%		54	%		66	%
Natural gas (Mcf)		40	%		36	%		46	%		34	%

Total		100	%		100	%		100	%		100	%


(1)		Includes hedge transactions

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


	Six Months Ended June 30,						Increase			% Increase
	2006			2005			(Decrease)			(Decrease)
	(in thousands except per unit data)
Production Volumes
Oil (Bbls)		566			425			141			33	%
Natural gas (Mcf)		2,893			1,302			1,591			122	%
BOE		1,048			642			406			63	%
BOE/Day		5.8			3.5			2.3			65	%

Sales Price
Oil (per Bbl)⁽¹⁾	$	60.56		$	46.15		$	14.41			31	%
Natural gas (per Mcf)⁽¹⁾	$	6.42		$	6.42		$	—			0	%
BOE price⁽¹⁾	$	50.43		$	43.57		$	6.86			16	%
BOE price⁽²⁾	$	44.72		$	35.32		$	9.40			27	%

Operating Revenues
Oil	$	34,284		$	19,618			14,666			75	%
Oil hedges	$	(5,985	)	$	(5,095	)		890			17	%
Natural gas	$	18,586		$	8,355			10,231			122	%
Natural gas hedges	$	—		$	(201	)		(201	)		100	%

Total	$	46,885		$	22,677			24,208			107	%


(1)		Excludes hedge transactions.

(2)		Includes hedge transactions.

Oil revenues, excluding hedges, increased $14.7 million or 75% for the six months ended June 30, 2006 compared to the same period of 2005. Oil production volumes increased 33% primarily due to the acquisition of the Harris Field and the drilling programs in the Cam-Ann San Andres Field/N. Means Queen Unit and the Diamond M properties. The increase in oil production increased revenue approximately $6.5 million for 2006. Wellhead average realized crude oil prices increased $14.41 per Bbl or 31% to $60.56 per Bbl for 2006 compared to 2005. The increase in oil price increased revenue approximately $8.2 million for 2006.

Natural gas revenues, excluding hedges, increased $10.2 million or 122% for the six months ended June 30, 2006 compared to the same period of 2005. Natural gas production volumes increased 122% primarily due to added production from new wells in New Mexico, Barnett Shale of north Texas and the Wilcox discovery in south Texas. The increase in natural gas volumes increased revenue approximately $10.2 million for 2006. Average realized wellhead natural gas prices per Mcf of $6.42 remained flat.

Losses on oil hedges increased $0.9 million or 17% for 2006 compared to 2005 due to the increase in oil prices. Natural gas hedge losses were $0.2 million in 2005. On a BOE basis, hedges accounted for a realized loss of $5.71 per BOE in 2006 compared to $8.25 per BOE in 2005. 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.

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Cost and Expenses


	Six months ended June 30,				Increase		% Increase
	2006		2005		(Decrease)		(Decrease)
	(dollars in thousands)
Lease operating expense	$	7,316	$	4,736	$	2,580		54	%
Production taxes		2,578		1,281		1,297		101	%
General and administrative:
General and administrative		2,657		1,828		829		45	%
Public reporting		2,085		1,208		877		73	%

Total general and administrative		4,742		3,036		1,706		56	%

Depreciation, depletion and amortization		10,428		5,055		5,373		106	%

Total	$	25,064	$	14,108	$	10,956		78	%

Lease operating costs increased approximately $2.6 million, or 54%, to $7.3 million during the six months ended June 30, 2006 compared with $4.7 million for the same period of 2005. The increase in lease operating expense is primarily due to increased well count due to our drilling program in the Diamond M, Carm-Ann San Andres Field/N. Means Queen Unit and Barnett Shale Field as well as the acquisition of the Harris Field, and increased ad valorem taxes. Lifting costs were $6.98 per BOE in 2006 compared to $7.38 per BOE in 2005. As we continue to exploit and develop our long-life Permian Basin oil properties (Fullerton, Carm-Ann, Harris 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 the Barnett Shale and New Mexico.

Production taxes increased 101% or $1.3 million in 2006, associated with an increase in revenues of $24.9 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 56% or $1.7 million in 2006 compared to 2005. Included in our total general and administrative expenses is public reporting cost which increased 73% or $0.9 million. Public reporting increased due to increases in investor relation presentations including road shows and the stockholder meeting. In addition public reporting also experienced increases in director stock option expenses as well as employee compensation related expenditures. The remainder of the increase in general and administrative costs is due to employee compensation and related benefit costs. During the second quarter of 2006, we determined that during 2003 approximately 30,000 options were awarded which were not available for issue under existing stock option plans. In June 2006, the Board of Directors approved a plan whereby these excess options would be repurchased for cash totaling approximately $0.5 million. This amount was charged to expense during the second quarter of 2006. General and administrative expenses capitalized to the full cost pool were $0.8 million for 2006 compared to $0.6 million in 2005. On a BOE basis, general and administrative costs were $2.53 per BOE in 2006 compared to $2.85 per BOE in 2005, while public reporting costs were $1.99 per BOE and $1.88 per BOE for the same period. General and administrative expenses will increase in 2006 in association with the reporting requirements and operational support.

Depreciation, depletion and amortization expense increased 106% or $5.4 million for 2006 compared to 2005. Depreciation, depletion and amortization per BOE was $9.95 for 2006 and $7.87 for 2005. 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 2006 depletion will increase with increased production volumes and capital expenditures.

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Other income (expense)


	Six months ended June 30,						Increase			% Increase
	2006			2005			(Decrease)			(Decrease)
	(dollars in thousands)
Change in fair market value of derivatives	$	(10,207	)	$	(23,696	)	$	(13,489	)		(57	)%
Gain (loss) on ineffective portion of hedges		195			(860	)		1,055			123	%
Interest and other income		93			39			54			138	%
Interest expense, net		(5,599	)		(2,041	)		3,558			174	%
Other expense		(68	)		(2	)		66			3,300	%
Equity in loss of pipelines and gathering system ventures		(29	)		(94	)		(65	)		(69	)%

Total	$	(15,615	)	$	(26,654	)	$	(11,039	)		41	%

The loss associated with the change in fair market value of derivatives decreased by $13.5 million in 2006 compared to 2005. While the gain associated with the ineffective portion of our hedges increased $1.1 million for 2006 compared to 2005. Crude oil prices continued to increase in 2006. Meanwhile natural gas prices went in the opposite direction and continued their decrease in 2006. Our total volumes designated as cash flow hedges decreased in 2006 compared to 2005. This resulted in a gain in the ineffectiveness for the 2006 although the spread between sweet and sour crude was wider. The actual gain or loss may increase or decrease until settlement of these contracts.

Income tax expense was $2.1 million in 2006 compared to a benefit of $6.1 million in 2005. Income tax expense for 2006 will be dependent on our earnings and is expected to be approximately 35% of income before income taxes.

We had basic net earnings per share of $.12 and net loss of $.40 and diluted net earnings per share of $.11 and net loss of $.40 for 2006 and 2005, respectively. Basic weighted average common shares outstanding increased from approximately 30.0 million shares in 2005 to approximately 34.9 million shares in 2006. The increase in common shares is due to the conversion of preferred shares into common shares in June, 2005 and our sale of common stock in February 2005.

LIQUIDITY AND CAPITAL RESOURCES

Working capital decreased approximately $14.6 million as of June 30, 2006 compared with December 31, 2005. Current liabilities exceeded current assets by $14.2 million at June 30, 2006. The working capital decrease was due to the increased current maturity of derivative obligations and increases in payables associated with our accelerated drilling program for 2006.

We incurred net property costs of $111.7 million for the six months ended June 30, 2006 compared to $21.7 million for the same period in 2005. The increase is primarily related to our accelerated budget and the Harris and Barnett Shale acquisitions. Our property expenditures were $104.8 million for the first six months of 2006 partially offset by restricted cash utilized for property purchases. Included in our increased property basis for the six months of 2006 and 2005 were net asset retirement costs of approximately $1.8 million and $0.07 million, respectively (see Note 9 to Consolidated Financial Statements). Our property leasehold acquisition, development and enhancement activities were financed by our bank borrowings, the utilization of cash flows provided by operations and cash on hand.

Stockholders’ equity is $97.0 million for June 30, 2006 compared to $89.5 million at December 31, 2005 an increase of 8%. The increase is primarily attributable to a reduction in accumulated comprehensive loss of $2.4 million related to our derivative instruments (see Note 7 to Consolidated Financial Statements) and net income of $4.1 million.

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Historically, we have funded our operations, capital requirements and interest expense requirements with cash flows from our oil and natural gas properties, bank borrowings and proceeds from sales of our equity securities. Although we expect these same capital resources to support our future activities, we continually review and consider alternative methods of financing.

Bank Borrowings

We have two separate credit facilities. Our Third Amended and Restated Credit Agreement (or the “Revolving Credit Agreement”), dated as of December 23, 2005, with a group of bank lenders provides a revolving line of credit having a “borrowing base” limitation of $140.0 million at June 30, 2006. The total amount that we can borrow and have outstanding at any one time is limited to the lesser of $350.0 million or the borrowing base established by the lenders. At June 30, 2006, the principal amount outstanding under our revolving credit facility was $123.5 million, excluding $0.49 million reserved for our letters of credit. The second credit facility is a five year term loan facility provided to us under a Second Lien Term Loan Agreement (the “Second Lien Agreement”), dated as of November 15, 2005, with a group of banks and other lenders. At June 30, 2006, our term loan under this facility was fully funded in the principal amount of $50.0 million, which was outstanding on that same date.

Revolving 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.

As of June 30, 2006, we were in compliance with our debt covenants.

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Second Lien Term Loan Facility

At June 30, 2006, our Libor interest rate, plus the applicable margin, was 9.9375% on $50.0 million.

Prepayments in whole or in part if made prior to the first anniversary date will bear a premium of 1% of the amount prepaid. There is no premium after the first anniversary date.

As of June 30, 2006 we were in compliance with our debt covenants.

Preferred Stock

Sale of Equity Securities

Commodity Price Risk Management Transactions and Effects of Derivative Instruments

The purpose of all of our derivative trades is to provide a measure of stability in cash flow as a result of our daily activities associated with the selling of oil and natural gas production and expenditures associated with the borrowings that we have secured through our Bank Borrowings. The derivative trade arrangements we have employed include collars, costless collars, floors or purchased puts, oil and natural gas swaps and interest rate swaps. In 2003, we designated our derivative trades as cash flow hedges under the provisions of SFAS 133, as

amended. Although our purpose for entering into derivative trades has remained the same, contracts entered into after June 30, 2004 were not designated as cash flow hedges.

Under cash flow hedge accounting for oil and natural gas production, the quarterly effective portion of the change in fair value of the commodity derivatives is recorded in stockholders’ equity as other comprehensive income (loss) and then transferred to revenue in the period the related oil and natural gas production is sold.

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Ineffective portions of cash flow hedges (changes in the fair value of derivative instruments due to changes in realized prices that do not match the changes in the hedge price) are recognized in gain (loss) on ineffective portion of hedges as they occur. While the cash flow hedge contract is open, the ineffective gain or loss may increase or decrease until settlement of the contract. As of June 30, 2006, we had designated as cash flow hedges of 750 Bbls per day of production from July 1, 2006 through December 20, 2006. All other commodity derivative trades are accounted for by “mark-to-market” accounting whereby changes in fair value are charged to earnings. Changes in the fair value of derivatives are recorded in our Consolidated Statements of Operations as these changes occur in the “Other income (expense), net” section of this statement. To the extent these trades relate to production in 2006 and beyond and oil prices increase, we report a loss currently, but if there is no further change in prices, our net earnings will be correspondingly higher (than if there had been no price increase) when the production is sold.

Under cash flow hedge accounting for interest rates, the quarterly change in the fair value of the derivative is recorded in stockholders’ equity as other comprehensive income (loss). The gain or loss is transferred, on a contract by contract basis, to interest expense as the interest accrues. Ineffective portions of cash flow hedges are recognized in other expense as they occur. As of June 30, 2006, the floating interest rate on $10.0 million of the Bank Borrowings in 2006 was hedged. All other interest rate swaps that have been entered into are accounted for by “mark-to-market” accounting as prescribed by SFAS 133.

We are exposed to credit risk in the event of nonperformance by the counterparty in our derivative trade 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, 2006:


	Obligation Due in Period
	Six months
	ending
	December 31,		Periods ended December 31,								After
Contractual Cash Obligations	2006		2007		2008		2009		2010		5 years		Total
	(in thousands)
Revolving Credit Facility (secured)⁽¹⁾	$	4,856	$	9,633	$	9,659	$	9,633	$	131,523	$	—	$	165,304
Second Lien Term Loan Agreement⁽²⁾		2,505		4,969		4,982		4,969		54,342		—		71,767
Office Lease (Dinero Plaza)		97		204		210		216		36		—		763
Andrews and Snyder Field Offices⁽³⁾		11		23		14		14		14		—		76
Asset retirement obligations⁽⁴⁾		300		82		58		253		567		3,160		4,420
Derivative Obligations		11,424		19,442		16,339		436		338		—		47,979
Drilling Contract		515		764		—		—		—		—		1,279

Total	$	19,708	$	35,117	$	31,262	$	15,521	$	186,820	$	3,160	$	291,588

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(1)		Outstanding principal of $123.5 million due October 31, 2010 and estimated interest obligation calculated using the weighted average rate at June 30, 2006 of 7.8%

(2)		Outstanding principal of $50.0 million due November 15, 2010 and estimated interest obligation calculated using the LIBOR rate at June 30, 2006 of 9.9375%

(3)		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.

(4)		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 natural 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 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, 2005, filed with the Securities and Exchange Commission on March 16, 2006.

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TRENDS AND PRICES

Changes in oil and natural 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 2005 the average realized sales price for our oil and natural gas was $51.57 (unhedged) per BOE. For the six months ended June 30, 2006, our average realized price was $50.43 (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;

	•		the drilling plans and ability to secure drilling rigs to effectuate plans;

	•		production volumes;

	•		our business strategy;

	•		market prices;

	•		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;

	•		dependent on key personnel;

	•		reliance on technological development and technology development programs;

	•		demand for oil and natural gas;

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	•		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 and liability for environmental matters;

	•		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 19 of our Form 10-K for the year ended December 31, 2005.

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, 2006, 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, 2006

Our only financial instruments sensitive to changes in interest rates are our bank debt and interest rate swaps. As the interest rate is variable and reflects current market conditions, the carrying value of our bank debt 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, 2006. You should read Note 3 to the Consolidated Financial Statements for further discussion of our debt that is sensitive to interest rates.


	2006			2007			2008			2009			2010			Total
	(in thousands, except interest rates)
Revolving Facility (secured)	$	—		$	—		$	—		$	—		$	123,500		$	123,500
Average interest rate		7.80	%		7.80	%		7.80	%		7.80	%		7.80	%
Term Loan (Second Lien)	$	—		$	—		$	—		$	—		$	50,000		$	50,000
Average interest rate		9.94	%		9.94	%		9.94	%		9.94	%		9.94	%

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At June 30, 2006, we had bank loans in the amount of approximately $123.5 million outstanding on our revolving credit facility at a weighted average interest rate of 7.8% and approximately $50.0 million outstanding on our term loan at an interest rate of 9.9375%. Under our revolving credit facility, we may elect an interest rate based upon the agent bank’s base lending rate or the LIBOR rate, plus a margin ranging from 2.00% to 2.50% per annum, depending upon the outstanding principal amount of the loans. The interest rate we are required to pay, including the applicable margin, may never be less than 5.00%.

As of June 30, 2006, we employed fixed interest rate swap contracts with BNP Paribas, based on the 90-day LIBOR rates at the time of the contract. These interest rate swaps are treated as a cash flow hedge as defined in SFAS 133, and are on $10.0 million of our variable rate debt for all of 2006. We will continue to pay the variable interest rates for this portion of our Bank Borrowings, but due to the interest rate swaps, we have fixed the rate at 4.05%. Under the terms of these contracts, in periods during which the fixed interest rate stated in the agreement exceeds the variable rate (which is based on the 90-day LIBOR rate), we pay to the counterparty an amount determined by applying this excess fixed rate to the notional amount of the contract. In periods when the variable rate exceeds the fixed rate stated in the respective swap contract, the counterparty pays an amount to us determined by applying the excess of the variable rate over the stated fixed rate. As of June 30, 2006, the fair market value of these interest rate swaps was a gain of $0.07 million.

A recap for the period of time, notional amounts, fixed interest rates, and fair market value of these contracts at June 30, 2006 follows:


	Notional					Fair
Period of Time	Amounts		Fixed Interest Rates			Market Value
	($ in millions)					($ in thousands)
July 1, 2006 thru December 31, 2006⁽¹⁾	$	10		4.05	%	$	70
July 1, 2006 thru December 31, 2006	$	90		4.41	%		486
January 1, 2007 thru December 31, 2007	$	100		4.62	%		850
January 1, 2008 thru December 31, 2008	$	100		4.86	%		572
January 1, 2009 thru December 31, 2009	$	50		5.06	%		195
January 1, 2010 thru October 31, 2010	$	50		5.15	%		141

Total Fair Market Value						$	2,314


(1)		Designated as cash flow hedge.

Commodity Price Sensitivity as of June 30, 2006

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 natural gas production have been volatile and unpredictable. We expect pricing volatility to continue. Oil prices ranged from a low of $36.43 per barrel to a high of $65.63 per barrel during 2005. Natural gas prices we received during 2005 ranged from a low of $2.22 per Mcf to a high of $15.43 per Mcf. During 2006 oil prices ranged from a low of $51.65 to a high of $68.35. Natural gas prices we received during 2006 ranged from a low of $1.09 per Mcf to a high of $15.11 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.

We employ various derivative instruments in order to minimize our exposure to the aforementioned commodity price volatility. As of June 30, 2006, we had employed costless collars, collars, and swaps in order to protect against this price volatility. Although all of the contracts that we have entered into are viewed as protection

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against this price volatility, all but two of these contracts are accounted for by the “mark-to-market” accounting method as prescribed in SFAS 133.

As of June 30, 2006, we had commodity swap contracts designated as cash flow hedges totaling 750 Bbls per day from July 1, 2006 through December 20, 2006 at a NYMEX swap price of $23.04 per Bbl.

A description of our active commodity derivative contracts as of June 30, 2006 follows:

A summary of our collar positions at June 30, 2006 is as follows:


			NyMex Oil Prices						Houston Ship Channel Gas Prices				WAHA Gas Prices
	Barrels of						MM Btu of										Fair Market
Period of Time	Oil		Floor		Cap		Natural Gas		Floor		Cap		Floor		Cap		Value
																	($ in thousands)
July 1, 2006 thru December 31, 2006		145,000	$	48.32	$	76.07		—	$	—	$	—	$	—	$	—	$	(1,186	)
July 1, 2006 thru October 31, 2006		—	$	—	$	—		246,000	$	7.50	$	13.90	$	—	$	—		464
July 1, 2006 thru October 31, 2006		—	$	—	$	—		123,000	$	—	$	—	$	9.00	$	14.55		425
January 1, 2007 thru December 31, 2007		219,000	$	52.50	$	83.00		—	$	—	$	—	$	—	$	—		(785	)
April 1, 2007 thru October 31, 2007		—	$	—	$	—		214,000	$	6.00	$	11.05	$	—	$	—		(48	)
January 1, 2008 thru December 31, 2008		109,800	$	55.00	$	76.50		—	$	—	$	—	$	—	$	—		(510	)
January 1, 2009 thru December 31, 2009		91,250	$	55.00	$	73.00		—	$	—	$	—	$	—	$	—		(436	)
January 1, 2010 thru October 31, 2010		76,000	$	55.00	$	71.00		—	$	—	$	—	$	—	$	—		(338	)

Total Fair Market Value																	$	(2,414	)

Commodity Swaps. Generally, swaps are an agreement to buy or sell a specified commodity for delivery in the future, at an agreed fixed price. Swap transactions convert a floating or market price into a fixed price. For any particular swap transaction, the counterparty is required to make a payment to the Company if the reference price for any settlement period is less than the swap or fixed price for such contract, and the Company is required to make a payment to the counterparty if the reference price for any settlement period is greater than the swap or fixed price for such contract.

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We have entered into oil swap contracts with BNP Paribas. A recap for the period of time, number of barrels, swap prices and fair market values as of June 30, 2006 for these swaps follows:


			Nymex Oil		Fair Market
Period of Time	Barrels of Oil		Swap Price		Value
					($ in thousands)
July 1, 2006 thru December 20, 2006⁽¹⁾		129,750	$	23.04	$	(6,694	)
July 1, 2006 thru December 31, 2006		92,000	$	36.35		(3,544	)
January 1, 2007 thru December 31, 2007		474,500	$	34.36		(18,620	)
January 1, 2008 thru December 31, 2008		439,200	$	33.37		(15,829	)
Total fair market value					$	(44,687	)


(1)		Designated as a cash flow hedge.

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), in accordance with Rules of the Securities Exchange Act of 1934. Based on that evaluation, Mr. Oldham and Mr. Foster have concluded that our disclosure controls and procedures were effective as of June 30, 2006 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

On December 30, 2005, we were named as a defendant in a lawsuit filed in the 352nd Judicial District Court of Tarrant County, Texas, Cause No. 352-215616-05, AFE Oil and Gas, L.L.C. (aka AFE Oil and Gas, LLC) v. Premium Resources II, L.P., Premium Resources, Inc., Danay Covert, Nick Morris, William D. Middleton, Dale Resources, L.L.C., and Parallel Petroleum, Inc.

In addition to seeking unspecified monetary damages, the plaintiff also seeks to impose a constructive trust for its benefit on the new oil and natural gas leases and seeks a judicial declaration that either (1) the plaintiff is the owner of an overriding royalty interest in the new leases or that (2) the original leases and plaintiff’s interest in the original leases are still in effect. The plaintiff also claims that the new leases constitute a cloud on plaintiff’s title and seeks to have that cloud removed. Based on our present understanding of this case, we believe that we have substantial defenses to the plaintiff’s claims and intend to vigorously assert these defenses. However, if the plaintiff is awarded an interest in the new leases, we could potentially become liable for the payment to plaintiff of the

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portion of production proceeds attributable to plaintiff’s interest received by us. On the other hand, if the plaintiff prevails on its claim that the original leases are still in effect, our interest in the new leases could become subject to forfeiture. Based on the information known to date, we have not established a reserve for this matter.

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.

ITEM 1A. RISK FACTORS

There have been no material changes from the risk factors as previously disclosed in our Form 10-K Report for the fiscal year ended December 31, 2005.

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

Our annual meeting of stockholders was held on June 21, 2006. 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		30,406,819		1,077,002		—
Dewayne E. Chitwood		29,979,815		1,504,006		—
Larry C. Oldham		30,971,637		512,184		—
Martin B. Oring		30,646,633		837,188		—
Ray M. Poage		30,646,808		837,013		—
Jeffrey G. Shrader		30,747,778		736,043		—

Also, the stockholders voted upon and ratified the appointment of BDO Seidman, LLP to serve as our independent public accountants for 2006. 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
	31,000,006		466,125		17,690

ITEM 6. 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)

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No.		Description of Exhibit

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 (Incorporated by reference to Exhibit 10.3 of the Registrant’s Form 10-Q of the Registrant for the fiscal quarter ended June 30, 2005)

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 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)

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No.		Description of Exhibit

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 Amendment 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

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No.		Description of Exhibit

		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)

10.24		Third Amendment to Second Amended and Restated Credit Agreement (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K Report dated October 4, 2005 and filed with the Securities and Exchange Commission on October 20, 2005)

10.25		Purchase and Sale Agreement, dated as of October 14, 1005, among Parallel, L.P., Lynx Production Company, Inc., Elton Resources, Inc., Cascade Energy Corporation, Chelsea Energy, Inc., William P. Sutter, Trustee, William P. Sutter Trust, J. Leroy Bell, E. L. Brahaney, Brent Beck, Cavic Interests, LLC and Stanley Talbott (Incorporated by reference to Exhibit 10.2 of the Registrant’s Form 8-K Report dated October 14, 2005 and filed with the Securities and Exchange Commission on October 20, 2005)

10.26		Ancillary Agreement to Purchase and Sale Agreement, dated October 14, 2005, between Parallel, L.P. and Lynx Production Company, Inc. (Incorporated by reference to Exhibit 10.3 of the Registrant’s Form 8-K Report dated October 14, 2005 and filed with the Securities and Exchange Commission on October 20, 2005)

10.27		Guarantee of Parallel, L.P., dated October 13, 2004 (Incorporated by reference to Exhibit 10.4 of the Registrant’s Form 8-K Report dated October 14, 2005 and filed with the Securities and Exchange Commission on October 20, 2005)

10.28		ISDA Master Agreement, dated as of October 13, 2005, between Parallel, L.P. and Citibank, N.A. (Incorporated by reference to Exhibit 10.5 of the Registrant’s Form 8-K Report dated October 14, 2005 and filed with the Securities and Exchange Commission on October 20, 2005)

10.29		Third Amended and Restated Credit Agreement, dated as of December 23, 2005, among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C. and Citibank Texas, N.A., BNP Paribas, CitiBank F.S.B., Western National Bank, Compass Bank, Comerica Bank, Bank of Scotland and Fortis Capital Corp. (Incorporated by reference to Exhibit No. 10.1 of the Registrant’s Form 8-K Report, dated December 23, 2005, as filed with the Securities and Exchange Commission on December 30, 2005)

10.30		Second Lien Term Loan Agreement, dated November 15, 2005, among Parallel Petroleum Corporation, Parallel, L.P., BNP Paribas and Citibank Texas, N.A. (Incorporated by reference to Exhibit No. 10.4 of the Registrant’s Form 8-K Report, dated November 15, 2005, as filed with the Securities and Exchange Commission on November 21, 2005)

10.31		Intercreditor and Subordination Agreement, dated November 15, 2005, among Citibank Texas, N.A., BNP Paribas, Parallel Petroleum Corporation, Parallel, L.P. and Parallel, L.L.C. (Incorporated by reference to Exhibit No. 10.5 of the Registrant’s Form 8-K Report, dated November 15, 2005, as filed with the Securities and Exchange Commission on November 21, 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.

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No.		Description of Exhibit

*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.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	PARALLEL PETROLEUM CORPORATION
Date: August 8, 2006	BY:	/s/ Larry C. Oldham
	Larry C. Oldham
	President and Chief Executive Officer


Date: August 8, 2006	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)


No.		Description of Exhibit

10.3		Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.3 of the Registrant’s Form 10-Q of the Registrant for the fiscal quarter ended June 30, 2005)

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 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)


No.		Description of Exhibit

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 Amendment 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)

10.24		Third Amendment to Second Amended and Restated Credit Agreement (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K Report dated October 4, 2005 and filed with the Securities and Exchange Commission on October 20, 2005)

10.25		Purchase and Sale Agreement, dated as of October 14, 1005, among Parallel, L.P., Lynx Production Company, Inc., Elton Resources, Inc., Cascade Energy Corporation, Chelsea Energy, Inc., William P. Sutter, Trustee, William P. Sutter Trust, J. Leroy Bell, E. L. Brahaney, Brent Beck, Cavic Interests, LLC and Stanley Talbott (Incorporated by reference to Exhibit 10.2 of the Registrant’s Form 8-K Report dated October 14, 2005 and filed with the Securities and Exchange Commission on October 20, 2005)

10.26		Ancillary Agreement to Purchase and Sale Agreement, dated October 14, 2005, between Parallel, L.P. and Lynx Production Company, Inc. (Incorporated by reference to Exhibit 10.3 of the Registrant’s Form 8-K Report dated October 14, 2005 and filed with the Securities and Exchange Commission on October 20, 2005)

10.27		Guarantee of Parallel, L.P., dated October 13, 2004 (Incorporated by reference to Exhibit 10.4 of the Registrant’s Form 8-K Report dated October 14, 2005 and filed with the Securities and Exchange Commission on October 20, 2005)

10.28		ISDA Master Agreement, dated as of October 13, 2005, between Parallel, L.P. and Citibank, N.A. (Incorporated by reference to Exhibit 10.5 of the Registrant’s Form 8-K Report dated October 14, 2005 and filed with the Securities and Exchange Commission on October 20, 2005)

10.29		Third Amended and Restated Credit Agreement, dated as of December 23, 2005, among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C. and Citibank Texas, N.A., BNP Paribas, CitiBank F.S.B., Western National Bank, Compass Bank, Comerica Bank, Bank of Scotland and Fortis Capital Corp. (Incorporated by reference to Exhibit No. 10.1 of the Registrant’s Form 8-K Report, dated December 23, 2005, as filed with the Securities and Exchange Commission on December 30, 2005)

10.30		Second Lien Term Loan Agreement, dated November 15, 2005, among Parallel Petroleum Corporation, Parallel, L.P., BNP Paribas and Citibank Texas, N.A. (Incorporated by reference to Exhibit No. 10.4 of the


No.		Description of Exhibit

		Registrant’s Form 8-K Report, dated November 15, 2005, as filed with the Securities and Exchange Commission on November 21, 2005)

10.31		Intercreditor and Subordination Agreement, dated November 15, 2005, among Citibank Texas, N.A., BNP Paribas, Parallel Petroleum Corporation, Parallel, L.P. and Parallel, L.L.C. (Incorporated by reference to Exhibit No. 10.5 of the Registrant’s Form 8-K Report, dated November 15, 2005, as filed with the Securities and Exchange Commission on November 21, 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.

Positive
Negative
Uncertain
Constraining
Legalese
Litigious
Readability	8th grade Good

Parallel Petroleum Inactive 10-Q2006 Q2 Quarterly report

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