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 September 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                     

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 (Address of principal executive offices)		79701 (Zip Code)

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

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

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

Yes þ      No o

     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 filer o      Accelerated filer þ      Non-accelerated filer o

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

Yes o       No þ

     At November 6, 2006, 37,464,991 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 September 30, 2006 (unaudited) and December 31, 2005			1
- Unaudited Consolidated Statements of Operations for the three months and nine months ended September 30, 2006 and 2005			2
- Unaudited Consolidated Statements of Cash Flows for the nine months ended September 30, 2006 and 2005			3
- Unaudited Consolidated Statements of Comprehensive Income (Loss) for the three months and nine months ended September 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			31
ITEM 4. CONTROLS AND PROCEDURES			34
PART II. — OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS			34
ITEM 1A. RISK FACTORS			34
ITEM 6. EXHIBITS			35
SIGNATURES
Certification Pursuant to Section 302
Certification Pursuant to Section 302
Certification Pursuant to Section 906
Certification Pursuant to Section 906

Part I. – Financial Information

Item I. Financial Statements

PARALLEL PETROLEUM CORPORATION

		September 30,				December 31,
		2006				2005
		(unaudited)
Assets
Current assets:
Cash and cash equivalents		$	312			$	6,418
Accounts receivable:
Oil and natural gas			16,625				13,183
Other, net of allowance for doubtful account of $80 and $9			9,524				877
Affiliates			7				12
			26,156				14,072
Other current assets			3,026				2,364
Deferred tax asset			4,762				5,241
Total current assets			34,256				28,095
Property and equipment, at cost:
Oil and natural gas properties, full cost method (including $42,036 and $19,869 not subject to depletion)			452,704				303,819
Other			3,204				2,404
			455,908				306,223
Less accumulated depreciation, depletion and amortization			(108,674	)			(90,826	)
Net property and equipment			347,234				215,397
Restricted cash			324				2,640
Investment in pipelines and gathering system ventures			12,946				3,326
Other assets, net of accumulated amortization of $1,236 and $901			3,785				3,550
		$	398,545			$	253,008
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities		$	25,721			$	10,841
Asset retirement obligations			384				214
Derivative obligations			15,514				16,607
Total current liabilities			41,619				27,662
Revolving credit facility			97,000				50,000
Term loan			50,000				50,000
Asset retirement obligations			4,241				2,281
Derivative obligations			16,702				25,527
Deferred tax liability			17,883				8,036
Total long-term liabilities			185,826				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 37,464,991 and 34,748,916			374				347
Additional paid-in capital			140,288				78,699
Retained earnings			31,970				16,899
Accumulated other comprehensive loss			(1,532	)			(6,443	)
Total stockholders’ equity			171,100				89,502
		$	398,545			$	253,008

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

PARALLEL PETROLEUM CORPORATION

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2006				2005				2006				2005
Oil and natural gas revenues:
Oil and natural gas sales		$	29,490			$	25,501			$	82,360			$	53,474
Loss on hedging			(3,279	)			(3,664	)			(9,264	)			(8,960	)
Total revenues			26,211				21,837				73,096				44,514
Cost and expenses:
Lease operating expense			5,323				2,663				12,639				7,399
Production taxes			1,538				1,334				4,116				2,615
General and administrative			2,405				1,735				7,147				4,771
Depreciation, depletion and amortization			7,420				3,104				17,848				8,159
Total costs and expenses			16,686				8,836				41,750				22,944
Operating income			9,525				13,001				31,346				21,570
Other income (expense), net:
Change in fair market value of derivative instruments			10,323				(9,388	)			116				(33,086	)
Gain (loss) on ineffective portion of hedges			305				404				500				(456	)
Interest and other income			29				83				122				124
Interest expense			(3,345	)			(1,060	)			(8,944	)			(3,101	)
Other expense			(96	)			(75	)			(164	)			(77	)
Equity in gain (loss) of pipelines and gathering system ventures			(39	)			22				(68	)			(72	)
Total other income (expense), net			7,177				(10,014	)			(8,438	)			(36,668	)
Income (loss) before income taxes			16,702				2,987				22,908				(15,098	)
Income tax benefit (expense), deferred			(5,706	)			(998	)			(7,837	)			5,137
Net income (loss)			10,996				1,989				15,071				(9,961	)
Cumulative preferred stock dividend			—				—				—				(271	)
Net income (loss) available to common stockholders		$	10,996			$	1,989			$	15,071			$	(10,232	)
Net income (loss) per common share:
Basic		$	0.30			$	0.06			$	0.43			$	(0.32	)
Diluted		$	0.30			$	0.06			$	0.42			$	(0.32	)
Weighted average common share outstanding:
Basic			36,215				34,033				35,340				31,585
Diluted			36,919				34,951				36,027				31,585

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

PARALLEL PETROLEUM CORPORATION

		2006				2005
Cash flows from operating activities:
Net income (loss)		$	15,071			$	(9,961	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization			17,848				8,159
Accretion of asset retirement obligation			172				82
Deferred income tax			7,837				(5,137	)
Change in fair value of derivative instruments			(116	)			33,086
(Gain) loss on ineffective portion of hedges			(500	)			456
Common stock issued in lieu of cash for directors fees			100				99
Stock option expense			435				119
Equity in loss of pipelines and gathering system ventures			68				72
Changes in assets and liabilities:
Other assets, net			1,140				186
Restricted cash			(50	)			(149	)
Increase in accounts receivable			(12,084	)			(7,927	)
(Increase) decrease in other current assets			(151	)			61
Increase in accounts payable and accrued liabilities			14,880				3,988
Federal tax deposit			(40	)			—
Net cash provided by operating activities			44,610				23,134
Cash flows from investing activities:
Additions to oil and natural gas properties			(147,058	)			(37,888	)
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			130				3,028
Additions to other property and equipment			(800	)			(421	)
Settlements on derivative instruments			(3,568	)			(3,424	)
Purchase of derivative instruments			—				(598	)
Investment in pipelines and gathering system ventures			(9,688	)			(1,686	)
Net cash used in investing activities			(158,618	)			(38,702	)
Cash flows from financing activities:
Net borrowings (payments) on revolving line of credit			47,000				(11,000	)
Deferred financing cost			(179	)			—
Proceeds (net) from common stock issued			60,315				27,743
Proceeds from exercise of stock options			766				450
Payment of preferred stock dividend			—				(271	)
Net cash provided by financing activities			107,902				16,922
Net increase (decrease) in cash and cash equivalents			(6,106	)			1,354
Cash and cash equivalents at beginning of period			6,418				4,781
Cash and cash equivalents at end of period		$	312			$	6,135
Non-cash financing and investing activities:
Oil and natural gas properties asset retirement obligations		$	1,957			$	73
Conversion of preferred stock		$	—			$	95
Other transactions:
Interest paid		$	9,065			$	3,319

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

PARALLEL PETROLEUM CORPORATION

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2006				2005				2006				2005
Net income (loss)		$	10,996			$	1,989			$	15,071			$	(9,961	)
Other comprehensive income (loss):
Unrealized gain (loss) on derivatives			634				(3,702	)			(1,750	)			(12,175	)
Reclassification adjustments for losses on derivatives included in net income (loss)			3,240				3,694				9,191				9,112
Change in fair value of derivatives			3,874				(8	)			7,441				(3,063	)
Income tax benefit (expense)			(1,317	)			3				(2,530	)			1,041
Total other comprehensive income (loss)			2,557				(5	)			4,911				(2,022	)
Total comprehensive income (loss)		$	13,553			$	1,984			$	19,982			$	(11,983	)

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

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.

     For the nine months ended September 30, 2006 and 2005, Parallel recognized compensation expense of approximately $0.49 million and $0.12 million, with a tax benefit of $0.17 million and $0.04 million, respectively,

associated with its stock option grants.

     During the second quarter of 2006, Parallel determined that stock options to purchase an aggregate of 30,000 shares of common stock that had been granted under Parallel’s 1998 Stock Option Plan to four non-officer employees during 2003 were not available for grant under the 1998 Stock Option Plan. In June 2006, the Board of Directors approved a Settlement Agreement and Release whereby these “excess” options were cancelled in exchange for Parallel’s payment to each employee of cash in an amount equal to the difference between the fair market value of the stock ($20.11) and the exercise price of the options ($3.09), multiplied by the number of “excess” options held by the employees. The total amount paid by Parallel was 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)
Fourth quarter 2006			96
2007			324
2008 through 2011			338
Total		$	758

     Nonvested options were 197,500 at September 30, 2006. During the nine months ended September 30, 2006, 176,250 options 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 for the nine months ended September 30, 2006 is presented below:

										Weighted
										Average
						Weighted				Remaining
						Average				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 September 30, 2006			1,199			$	5.40				5.6			$	17,571
Exercisable at September 30, 2006			1,001			$	4.32				4.6			$	15,759

		(in thousands)
Intrinsic Value of Options Exercised Nine Months Ending September 30, 2006		$	2,855
Intrinsic Value of Options Exercised Nine Months Ending September 30, 2005		$	897
Fair Market Value of Options Granted Nine Months Ending September 30, 2006		$	—
Fair Market Value of Options Granted Nine Months Ending September 30, 2005		$	1,423

     There were no stock options granted for the quarter ended September 30, 2006. For the quarter ended September 30, 2005 there were 200,000 options granted with a fair market value of $1.42 million.

     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				Nine Months Ended
		September 30, 2005				September 30, 2005
		(in thousands, except per share data)
Net income (loss), as reported		$	1,989			$	(9,961	)
Add:
Expense recorded in 2005, net of related tax effects			49				119
Deduct:
Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects			(35	)			(106	)
Pro forma net income (loss)		$	2,003			$	(9,948	)
Income (loss) per share:
Basic — as reported		$	0.06			$	(0.32	)
Basic — pro forma		$	0.06			$	(0.32	)
Diluted — as reported		$	0.06			$	(0.32	)
Diluted — pro forma		$	0.06			$	(0.32	)

     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.

     On August 16, 2006, we sold 2,500,000 shares of our common stock, $.01 par value per share, pursuant to a public offering at a price of $25.25 per share. Gross cash proceeds were $63.1 million, and net proceeds were approximately $60.3 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 for general corporate purposes, including debt repayment and the acceleration of our drilling and completion operations in certain core areas such as the Barnett Shale gas, New Mexico Wolfcamp gas and Permian Basin west Texas oil properties

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 $156.0 million at October 1, 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 September 30, 2006, the principal amount outstanding under our revolving credit facility was $97.0 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 September 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

     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 September 30, 2006, our weighted average base and LIBOR rates, plus margin, were 7.64% on $97.0 million.

     In the case of base rate loans, interest is payable on the last day of each month. In the case of LIBOR loans, interest is payable on the last day of each applicable interest period.

     If the total outstanding borrowings under the 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 September 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 plus ¹/2 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 September 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.

     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 September 30, 2006 we were in compliance with our debt covenants.

     Interest expense for the nine months ending September 30, 2006, for both facilities, was approximately $9.2 million not including approximately $0.55 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 assuming the 2006 acquisitions were consummated on January 1, 2005 and January 1, 2006, and assuming the 2005 acquisition occurred January 1, 2005.

		Three Months Ended								Nine Months Ended
		September 30,								September 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		$	26,211			$	24,640			$	73,652			$	50,760
Operating income		$	9,525			$	15,021			$	31,666			$	26,012
Net income (loss) available to common stockholder		$	10,996			$	2,661			$	15,207			$	(9,277	)
Net income (loss) per common share:
Basic		$	0.30			$	0.08			$	0.43			$	(0.29	)
Diluted		$	0.30			$	0.08			$	0.42			$	(0.29	)

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 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, 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 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 may not be written off if, subsequent to the end of the quarter or year but prior to the release of the financial results, prices have increased sufficiently that such excess above the ceiling would not have existed if the increased prices were used in the calculations.

     At September 30, 2006, we had a cushion (i.e. the excess of the ceiling over our capitalized cost) in excess of $120.0 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 and interest expense, are capitalized. In the nine month periods ended September 30, 2006 and 2005, overhead costs capitalized were approximately $1.31 million and $0.92 million, respectively and capitalized interest expense was $0.55 million and $0.10 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 September 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 September 30, 2006, we have recorded unrealized losses of $2.3 million ($1.5 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.

     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 September 30, 2006, the fair market value of these interest rate swaps was $0.03 million.

     We have 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 September 30, 2006.

		Notional								Fair
Period of Time		Amounts				Fixed Interest Rates				Market Value
		($ in millions)								($ in thousands)
October 1, 2006 thru December 31, 2006 (1)		$	10				4.05	%		$	30
October 1, 2006 thru December 31, 2006		$	50				4.41	%			307
January 1, 2007 thru December 31, 2007		$	100				4.62	%			469
January 1, 2008 thru December 31, 2008		$	100				4.86	%			(119	)
January 1, 2009 thru December 31, 2009		$	50				5.06	%			(82	)
January 1, 2010 thru October 31, 2010		$	50				5.15	%			(59	)
Total Fair Market Value										$	546

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 93,000 MMBtu have a fair market value of $0.30 million as of September 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.

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

														M M Btu				Houston Ship																Fair
		Barrels of				NyMex Oil Prices								of Natural				Channel Gas Prices								WAHA Gas Prices								Market
Period of Time		Oil				Floor				Cap				Gas				Floor				Cap				Floor				Cap				Value
																																		($ in
																																		thousands)
October 1, 2006 thru December 31, 2006			99,000			$	53.12			$	80.87				—			$	—			$	—			$	—			$	—			$	(246	)
October 1, 2006 thru October 31, 2006			—			$	—			$	—				62,000			$	7.50			$	13.90			$	—			$	—				217
October 1, 2006 thru October 31, 2006			—			$	—			$	—				31,000			$	—			$	—			$	9.00			$	14.55				164
January 1, 2007 thru December 31, 2007			292,000			$	55.63			$	84.88				—			$	—			$	—			$	—			$	—				146
April 1, 2007 thru October 31, 2007			—			$	—			$	—				214,000			$	6.00			$	11.05			$	—			$	—				51
January 1, 2008 thru December 31, 2008			237,900			$	60.38			$	81.08				—			$	—			$	—			$	—			$	—				236
January 1, 2009 thru December 31, 2009			620,500			$	63.53			$	80.21				—			$	—			$	—			$	—			$	—				1,583
January 1, 2010 thru October 31, 2010			486,400			$	63.44			$	78.26				—			$	—			$	—			$	—			$	—				1,492
Total Fair Market Value																																		$	3,643

     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)
October 1, 2006 thru December 20, 2006 (1)			60,750			$	23.04			$	(2,476	)
October 1, 2006 thru December 31, 2006			46,000			$	36.35				(1,275	)
January 1, 2007 thru December 31, 2007			474,500			$	34.36				(15,315	)
January 1, 2008 thru December 31, 2008			439,200			$	33.37				(14,195	)
Total fair market value										$	(33,261	)

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.

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

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2006				2005				2006				2005
		(dollars in thousands, except per share data)
Basic EPS Computation:
Numerator-
Income (loss)		$	10,996			$	1,989			$	15,071			$	(9,961	)
Preferred stock dividend			—				—				—				(271	)
Income (loss) available to common stockholders		$	10,996			$	1,989			$	15,071			$	(10,232	)
Denominator-
Weighted average common shares outstanding			36,215				34,033				35,340				31,585
Basic EPS:
Income (loss) per share		$	0.30			$	0.06			$	0.43			$	(0.32	)
Diluted EPS Computation:
Numerator-
Income (loss)		$	10,996			$	1,989			$	15,071			$	(9,961	)
Preferred stock dividend			—				—				—				(271	)
Income (loss) available to common stockholders		$	10,996			$	1,989			$	15,071			$	(10,232	)
Denominator -
Weighted average common shares outstanding			36,215				34,033				35,340				31,585
Employee stock options			596				774				581				—
Warrants			108				144				106				—
Preferred stock			—				—				—				—
Weighted average common shares for diluted earnings per share assuming conversion			36,919				34,951				36,027				31,585
Diluted EPS:
Income (loss) per share		$	0.30			$	0.06			$	0.42			$	(0.32	)

     Some stock options and the convertible preferred stock outstanding were not included in the computation of diluted net income (loss) per share for the nine months ended September 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.

     The following table summarizes our asset retirement obligation transactions:

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2006				2005				2006				2005
						(in thousands)
Beginning asset retirement obligation		$	4,420			$	2,251			$	2,495			$	2,132
Additions related to new properties			123				37				314				166
Revisions in estimated cash flows			11				(12	)			1,674				(9	)
Deletions related to property disposals			—				(17	)			(30	)			(84	)
Accretion expense			71				28				172				82
Ending asset retirement obligation		$	4,625			$	2,287			$	4,625			$	2,287

     Accretion expense is recognized as a component of lease operating expense.

NOTE 10. RECENTLY ANNOUNCED ACCOUNTING PRONOUNCEMENTS

     In July 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109” (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes”, and prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. Additionally, FIN 48 provides guidance on subsequent derecognition of tax positions, financial statement classification, recognition of interest and penalties, accounting in interim periods, and disclosure and transition requirements. FIN 48 is effective for the Company’s fiscal year beginning January 1, 2007, with early adoption permitted. The Company is in the process of evaluating FIN 48.

     In September 2006, the Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin No. 108 (“SAB 108”). Due to diversity in practice among registrants, SAB 108 expresses SEC staff views regarding the process by which misstatements in financial statements are evaluated for purposes of determining whether financial statement restatement is necessary, SAB 108 is effective for fiscal years ending after November 15, 2006, and early application is encouraged. Parallel does not believe SAB 108 will have a material impact on our financial position or results from operations.

     In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“FAS 157”). This Statement defines fair value as used in numerous accounting pronouncements, establishes a framework for measuring fair value in generally accepted account principles and expands disclosure related to the use of fair value measures in financial statements. The Statement is to be effective for Parallel’s financial statements issued in 2008; however, earlier application is encouraged. Parallel is currently evaluating the timing of adoption and the impact that adoption might have on our financial position or results of operations.

NOTE 11. INVESTMENT IN GAS GATHERING SYSTEM

     Parallel has invested $5.6 million in an unincorporated joint venture which is constructing and will operate a gas gathering system in Chaves County, New Mexico. Parallel owns approximately 76.5% of the joint venture interest. The joint venture is managed by a three-member management committee consisting of one member appointed by Parallel and two other members appointed by the other two participants 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 12. 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 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 nine months ending September 30, 2006 and 2005 Parallel had made contributions to the 401(k) Plan and Trust of approximately $0.17 million and $0.12 million, respectively.

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.

The extent to which we are able to implement and follow through with our business plan will be influenced by:

	•		the prices we receive for the oil and natural gas we produce;
	•		the results of reprocessing and reinterpreting our 3-D seismic data;
	•		the results of our drilling activities;
	•		the costs of obtaining high quality field services;
	•		our ability to find and consummate acquisition opportunities; and
	•		our ability to negotiate and enter into work to earn arrangements, joint venture or other similar agreements on terms acceptable to us.

     Significant changes in the prices we receive for the oil and natural gas, or the occurrence of unanticipated events beyond our control may cause us to defer or deviate from our business plan, including the amounts we have budgeted for our activities.

Operating Performance

     Our operating performance is influenced by several factors, the most significant of which are the prices we receive for our oil and natural gas and our production volumes. The world price for oil has overall influence on the prices that we receive for our oil production. The prices received for different grades of oil are based upon the world price for oil, which is then adjusted based upon the particular grade. Typically, light oil is sold at a premium, while heavy grades of crude are discounted. Natural gas prices we receive are influenced by:

	•		seasonal demand;
	•		weather;
	•		hurricane conditions in the Gulf of Mexico;
	•		availability of pipeline transportation to end users;
	•		proximity of our wells to major transportation pipeline infrastructures; and
	•		to a lesser extent, world oil prices.

Additional factors influencing our overall operating performance include:

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

     Our oil and natural gas exploration, development and acquisition activities require substantial and continuing capital expenditures. Historically, the sources of financing to fund our capital expenditures have included:

	•		cash flow from operations;
	•		sales of our equity securities;
	•		bank borrowings; and
	•		industry joint ventures.

     For the three months ended September 30, 2006 the sale price we received for our crude oil production (excluding hedges) averaged $64.53 per barrel compared with $58.95 per barrel for the three months ended September 30, 2005. The average sales price we received for natural gas for the three months ended September 30, 2006 (excluding hedges), was $5.64 per Mcf compared with $9.88 per Mcf for the three months ended September 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 were $3.3 million and $3.7 million for the three months ended September 30, 2006 and September 30, 2005, respectively. The hedge gain associated with the ineffective portion of our hedges decreased $0.1 million to a gain of approximately $0.3 million in the three months ended September 30, 2006 compared to a gain of $0.4 million for the three months ended September, 2005. The gain on ineffectiveness is caused by a narrowing 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 nine months ended September 30, 2006, the sale price we received for our crude oil production (excluding hedges) averaged $61.88 per barrel compared with $50.86 per barrel for the nine months ended September 30, 2005. The average sales price we received for natural gas for the nine months ended September 30, 2006 (excluding hedges), was $6.11 per Mcf compared with $8.01 per Mcf for the nine months ended September 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 $9.3 million and $9.0 million for the nine months ended September 30, 2006 and September 30, 2005, respectively. The hedge gain (loss) associated with the ineffective portion of our hedges increased approximately $1.0 million to a gain of approximately $0.5 million in the nine months ended September 30, 2006 compared to a loss of approximately ($0.5 million) for the nine months ended September 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 September 30, 2006 and

2005 was $10.53 and $7.27 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.

     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 nine months ended September 30, 2006 and September 30, 2005.

		Three Months Ended								Nine Months Ended
		9/30/2006				9/30/2005				9/30/2006				9/30/2005
		(in thousands, except per unit data)
Production Volumes:
Oil (Bbls)			282				247				848				672
Natural gas (Mcf)			2,001				1,109				4,894				2,411
BOE (1)			616				432				1,664				1,074
BOE per day			6.7				4.7				6.1				3.9
Sales Prices:
Oil (per Bbl) (2)		$	64.53			$	58.95			$	61.88			$	50.86
Natural gas (per Mcf) (2)		$	5.64			$	9.88			$	6.11			$	8.01
BOE price (2)		$	47.91			$	59.09			$	49.50			$	49.81
BOE price (3)		$	42.58			$	50.60			$	43.93			$	41.46
Operating Revenues
Oil		$	18,194			$	14,550			$	52,478			$	34,168
Oil hedge			(3,279	)			(3,664	)			(9,264	)			(8,759	)
Natural gas			11,296				10,951				29,882				19,306
Natural gas hedge			—				—				—				(201	)
		$	26,211			$	21,837			$	73,096			$	44,514
Operating Expenses:
Lease operating expense		$	5,323			$	2,663			$	12,639			$	7,399
Production taxes			1,538				1,334				4,116				2,615
General and administrative:
General and administrative			1,579				1,113				4,236				2,941
Public reporting			826				622				2,911				1,830
Depreciation, depletion and amortization			7,420				3,104				17,848				8,159
		$	16,686			$	8,836			$	41,750			$	22,944
Operating income		$	9,525			$	13,001			$	31,346			$	21,570

RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED SEPTEMBER 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 September 30, 2006 and September 30, 2005.

		Revenues (1)								Production
		2006				2005				2006				2005
Oil and Gas Revenues
Oil (Bbls)			57	%			50	%			46	%			57	%
Natural gas (Mcf)			43	%			50	%			54	%			43	%
Total			100	%			100	%			100	%			100	%

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

		Three Months Ended September 30,								Increase				% Increase
		2006				2005				(Decrease)				(Decrease)
		(in thousands except per unit data)
Production Volumes
Oil (Bbls)			282				247				35				14	%
Natural gas (Mcf)			2,001				1,109				892				80	%
BOE			616				432				184				43	%
BOE/Day			6.7				4.7				2.0				43	%
Sales Price
Oil (per Bbl)(1)		$	64.53			$	58.95			$	5.58				9	%
Natural gas (per Mcf) (1)		$	5.64			$	9.88			$	(4.24	)			(43	)%
BOE price (1)		$	47.91			$	59.09			$	(11.18	)			(19	)%
BOE price (2)		$	42.58			$	50.60			$	(8.02	)			(16	)%
Operating Revenues
Oil		$	18,194			$	14,550			$	3,644				25	%
Oil hedges		$	(3,279	)		$	(3,664	)		$	(385	)			(11	)%
Natural gas		$	11,296			$	10,951			$	345				3	%
Total		$	26,211			$	21,837			$	4,374				20	%

     Oil revenues, excluding hedges, increased $3.6 million or 25% for the three months ended September 30, 2006 compared to the same period of 2005. Oil production volumes increased 14% 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 $2.1 million for 2006 (based on 2005 comparable period average prices). Wellhead average realized crude oil prices increased $5.58 per Bbl or 9% to $64.53 per Bbl for 2006 compared to 2005. The increase in oil price increased revenue approximately $1.5 million for 2006 (based on current period production) for the three months ending September 30, 2006.

     Natural gas revenues, excluding hedges, increased $0.3 million or 3% for the three months ended September 30, 2006 compared to the same period of 2005. Natural gas production volumes increased 80% 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 $8.8 million (based on 2005 comparable period average prices) for 2006. Average realized wellhead natural gas prices decreased 43% or $4.24 per Mcf to $5.64 per Mcf. The

decrease in natural gas prices had a negative effect on revenues of approximately $8.5 million (based on current period production) for the three months ending September 30, 2006.

     Losses on oil hedges decreased $0.39 million or 11% for 2006 compared to 2005 due to the decrease in oil prices. On a BOE basis, hedges accounted for a realized loss of $5.33 per BOE in 2006 compared to $8.49 per BOE in 2005. We have hedged certain oil volumes in an attempt to mitigate price volatility and to meet the requirements under our loan facility. BOE production increased 2,000 BOE/day or 43% for 2006 compared to the same period in 2005.

		Three months ended September 30,								Increase				% Increase
		2006				2005				(Decrease)				(Decrease)
						(dollars in thousands)
Cost and Expenses
Lease operating expense		$	5,323			$	2,663			$	2,660				100	%
Production taxes			1,538				1,334				204				15	%
General and administrative:
General and administrative			1,579				1,113				466				42	%
Public reporting			826				622				204				33	%
Total general and administrative			2,405				1,735				670				39	%
Depreciation, depletion and amortization			7,420				3,104				4,316				139	%
Total		$	16,686			$	8,836			$	7,850				89	%

     Lease operating costs increased approximately $2.7 million, or 100%, to $5.3 million during the three months ended September 30, 2006 compared with $2.7 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 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 $8.64 per BOE in 2006 compared to $6.17 per BOE in 2005. The increase in lifting costs is primarily due to general overall increases in operating costs including ad valorem tax, service costs, electricity and chemicals.

     Production taxes increased 15% or $0.2 million in 2006, associated with an increase in revenues of $4.3 million. Production taxes in future periods will be a function of product mix, production volumes and product prices.

     General and administrative expenses in total increased 39% or $0.67 million in 2006 compared to 2005. Included in our total general and administrative expenses is public reporting cost which increased 33% or $0.2 million. Public reporting increased due to increases in investor presentations 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. General and administrative expenses capitalized to the full cost pool were approximately $0.5 million for 2006 compared to $0.3 million in 2005. On a BOE basis, general and administrative costs were $2.56 per BOE in 2006 compared to $2.58 per BOE in 2005, while public reporting costs were $1.34 per BOE and $1.44 per BOE for the same period.

     Depreciation, depletion and amortization expense increased 139% or $4.3 million for 2006 compared to 2005. Depreciation, depletion and amortization per BOE was $12.05 for 2006 and $7.19 for 2005. This increase is attributable to increased drilling costs, producing property purchases and reserve revisions as a result of decreased product prices. Depletion costs are highly correlated with production volumes, capital expenditures and product prices. Fiscal year 2006 depletion will increase with increased production volumes and capital expenditures.

		Three months ended September 30,								Increase				% Increase
		2006				2005				(Decrease)				(Decrease)
		(dollars in thousands)
Other income (expense)
Change in fair market value of derivatives		$	10,323			$	(9,388	)		$	19,711				210	%
Gain on ineffective portion of hedges			305				404				(99	)			(25	)%
Interest and other income			29				83				(54	)			(65	)%
Interest expense, net			(3,345	)			(1,060	)			2,285				216	%
Other expense			(96	)			(75	)			21				28	%
Equity in gain (loss) of pipelines and gathering system ventures			(39	)			22				(61	)			(277	)%
Total		$	7,177			$	(10,014	)		$	17,191				172	%