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, 2007

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 of		(I.R.S. Employer Identification No.)
incorporation or organization)
1004 N. Big Spring, Suite 400,
Midland, Texas		79701
(Address of Principal Executive Offices)		(Zip Code)

(432) 684-3727

Not Applicable

     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 þ      Accelerated filer o      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 1, 2007, 38,252,644 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, 2007 (unaudited) and December 31, 2006			1
- Unaudited Consolidated Statements of Operations for the three months and nine months ended September 30, 2007 and 2006			2
- Unaudited Consolidated Statements of Cash Flows for the nine months ended September 30, 2007 and 2006			3
- Unaudited Consolidated Statements of Comprehensive Income for the three months and nine months ended September 30, 2007 and 2006			4
- Notes to Consolidated Financial Statements			5
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.			17
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			38
ITEM 4. CONTROLS AND PROCEDURES			41
PART II. — OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS			41
ITEM 1A. RISK FACTORS			41
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			46
ITEM 6. EXHIBITS			47
SIGNATURES
Certification of Principal Executive Officer - Section 302
Certification of Principal Financial Officer - Section 302
Certification of Chief Executive Officer - Section 906
Certification of Chief Financial Officer - Section 906

PART I. — FINANCIAL INFORMATION

ITEM I. Financial Statements

PARALLEL PETROLEUM CORPORATION

Consolidated Balance Sheets

		September 30,				December 31,
		2007				2006
		(unaudited)
Assets
Current assets:
Cash and cash equivalents		$	5,318			$	5,910
Accounts receivable:
Oil and natural gas sales			18,902				18,605
Joint interest owners and other, net of allowance for doubtful account of $50 and $80			3,507				7,209
Affiliates and joint ventures			3,335				3,338
			25,744				29,152
Other current assets			1,515				2,863
Deferred tax asset			6,514				4,340
Total current assets			39,091				42,265
Property and equipment, at cost:
Oil and natural gas properties, full cost method (including $72,435 and $50,375 not subject to depletion)			609,216				501,405
Other			2,839				2,614
			612,055				504,019
Less accumulated depreciation, depletion and amortization			(137,064	)			(115,513	)
Net property and equipment			474,991				388,506
Restricted cash			53				325
Investment in pipelines and gathering system ventures			8,621				6,454
Other assets, net of accumulated amortization of $1,386 and $760			2,820				5,268
		$	525,576			$	442,818
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities		$	42,556			$	36,171
Asset retirement obligations			583				701
Derivative obligations			19,867				14,109
Total current liabilities			63,006				50,981
Revolving credit facility			89,000				115,000
Term loan			—				50,000
Senior notes (principal amount $150,000)			145,300				—
Asset retirement obligations			4,219				4,362
Derivative obligations			5,471				14,386
Deferred tax liability			28,493				24,307
Total long-term liabilities			272,483				208,055
Commitments and contingencies
Stockholders’ equity:
Series A preferred stock — par value $0.10 per share, authorized 50,000 shares			—				—
Common stock — par value $0.01 per share, authorized 60,000,000 shares, issued and outstanding 38,231,144 and 37,547,010			382				375
Additional paid-in capital			142,991				140,353
Retained earnings			46,714				43,054
Total stockholders’ equity			190,087				183,782
		$	525,576			$	442,818

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

PARALLEL PETROLEUM CORPORATION

Consolidated Statements of Operations

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2007				2006				2007				2006
Oil and natural gas revenues:
Oil and natural gas sales		$	29,487			$	29,490			$	79,957			$	82,360
Loss on hedging			—				(3,279	)			—				(9,264	)
Total revenues			29,487				26,211				79,957				73,096
Cost and expenses:
Lease operating expense			6,445				5,323				16,420				12,639
Production taxes			1,448				1,538				3,696				4,116
Production tax refund			—				—				(1,209	)			—
General and administrative			2,492				2,405				7,737				7,147
Depreciation, depletion and amortization			7,821				7,420				21,680				17,848
Total costs and expenses			18,206				16,686				48,324				41,750
Operating income			11,281				9,525				31,633				31,346
Other income (expense), net:
Gain (loss) on derivatives not classified as hedges			(4,556	)			10,323				(11,161	)			116
Gain on ineffective portion of hedges			—				305				—				500
Interest and other income			55				29				163				122
Interest expense			(5,429	)			(3,345	)			(13,449	)			(8,944	)
Cost of debt retirement			(760	)			—				(760	)			—
Other expense			(76	)			(96	)			(91	)			(164	)
Equity in loss of pipelines and gathering system ventures			(69	)			(39	)			(663	)			(68	)
Total other income (expense), net			(10,835	)			7,177				(25,961	)			(8,438	)
Income before income taxes			446				16,702				5,672				22,908
Income tax expense, deferred			(153	)			(5,706	)			(2,011	)			(7,837	)
Net income		$	293			$	10,996			$	3,661			$	15,071
Net income per common share:
Basic		$	0.01			$	0.30			$	0.10			$	0.43
Diluted		$	0.01			$	0.30			$	0.09			$	0.42
Weighted average common shares outstanding:
Basic			38,033				36,215				37,791				35,340
Diluted			38,767				36,919				38,806				36,027

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

PARALLEL PETROLEUM CORPORATION

Consolidated Statements of Cash Flows

Nine Months Ended September 30, 2007 and 2006

		2007				2006
Cash flows from operating activities:
Net income		$	3,661			$	15,071
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization			21,680				17,848
Gain on sale of automobiles			(25	)			—
Accretion of asset retirement obligation			243				172
Accretion of senior notes discount			114				—
Deferred income tax			2,011				7,837
(Gain) loss on derivatives not classified as hedges			11,161				(116	)
Gain on ineffective portion of hedges			—				(500	)
Cost of debt retirement			760				—
Common stock issued in lieu of cash for directors fees			96				100
Stock option expense			161				435
Equity in loss of pipelines and gathering system ventures			663				68
Bad debt expense			(30	)			—
Changes in assets and liabilities:
Other assets, net			226				1,140
Restricted cash			272				(50	)
Decrease (increase) in accounts receivable			3,438				(12,084	)
Decrease (increase) in other current assets			713				(151	)
Increase in accounts payable and accrued liabilities			6,385				14,880
Federal tax deposit			—				(40	)
Net cash provided by operating activities			51,529				44,610
Cash flows from investing activities:
Additions to oil and natural gas properties			(110,015	)			(147,058	)
Use of restricted cash for acquisition of oil and natural gas properties			—				2,366
Proceeds from disposition of oil and natural gas properties and other property and equipment			1,711				130
Additions to other property and equipment			(340	)			(800	)
Settlements on derivative instruments			(9,875	)			(3,568	)
Investment in pipelines and gathering system ventures			(2,830	)			(9,688	)
Net cash used in investing activities			(121,349	)			(158,618	)
Cash flows from financing activities:
Borrowings from bank line of credit			68,500				90,000
Payments on bank line of credit			(94,500	)			(43,000	)
Payment on term loan			(50,000	)			—
Senior notes (principal amount $150,000)			145,186				—
Deferred financing cost			(2,346	)			(179	)
Proceeds (net) from common stock issued			—				60,315
Proceeds from exercise of stock options			2,388				766
Net cash provided by financing activities			69,228				107,902
Net decrease in cash and cash equivalents			(592	)			(6,106	)
Cash and cash equivalents at beginning of period			5,910				6,418
Cash and cash equivalents at end of period		$	5,318			$	312
Non-cash financing and investing activities:
Oil and natural gas properties asset retirement obligations		$	(505	)		$	1,957
Non-cash exchange of oil and natural gas properties
Properties received in exchange		$	6,463			$	—
Properties delivered in exchange		$	(5,495	)		$	—
Other transactions:
Interest paid		$	10,451			$	9,065

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

PARALLEL PETROLEUM CORPORATION

Consolidated Statements of Comprehensive Income

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2007				2006				2007				2006
Net income		$	293			$	10,996			$	3,661			$	15,071
Other comprehensive loss:
Unrealized gain (loss) on derivatives			—				634				—				(1,750	)
Reclassification adjustments for losses on derivatives included in net income			—				3,240				—				9,191
Change in fair value of derivatives			—				3,874				—				7,441
Income tax expense			—				(1,317	)			—				(2,530	)
Total other comprehensive income			—				2,557				—				4,911
Total comprehensive income		$	293			$	13,553			$	3,661			$	19,982

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

     Parallel is 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. The majority of our current producing properties are in the:

	•		Permian Basin of west Texas and New Mexico;
	•		Fort Worth Basin of north Texas; and
	•		the onshore gulf coast area of south Texas.

     The financial information included herein is unaudited. The balance sheet as of December 31, 2006 has been derived from our audited Consolidated Financial Statements as of December 31, 2006. The unaudited financial 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 2006 amounts have been conformed to the 2007 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 Quarterly Report on Form 10-Q pursuant to certain rules and regulations of the Securities and Exchange Commission. These financial statements should be read in conjunction with the audited Consolidated Financial Statements and notes included in our Annual Report on Form 10-K/A for the year ended December 31, 2006.

     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.

     On July 12, 2007, our subsidiaries, Parallel L.P. and Parallel L.L.C., were merged with and into Parallel Petroleum Corporation.

NOTE 2. STOCKHOLDERS’ EQUITY

     Options

     We account for stock based compensation in accordance with the Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards No. 123 (revised 2004), Share-Based Payment (SFAS 123(R)).

     For the nine months ended September 30, 2007 and 2006, we recognized compensation expense of approximately $161,000 and $493,000, respectively, with a tax benefit of approximately $55,000 and

$168,000, respectively, associated with our stock option grants. During the second quarter of 2007, we revised our estimate of expected forfeitures of stock options granted to directors due to the resignation of a director and the subsequent forfeiture of 40,000 stock options held by him. As a result, we revised our estimate of the grant date fair value of shares expected to ultimately vest under our stock option plan by approximately $283,000. As a consequence, general and administrative expenses during the three months ended June 30, 2007 were reduced by approximately $154,000 which included a cumulative adjustment for amounts previously expensed associated with options estimated to be forfeited or surrendered.

     During the second quarter of 2006, we determined that stock options to purchase 30,000 shares of common stock, which were granted in 2003, were not available for grant under our existing stock option plans. In June 2006, these “excess” options were cancelled in exchange for our payment to four employees of cash totaling approximately $511,000. This amount was charged to expense during the second quarter of 2006.

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

		(in thousands)
Fourth quarter 2007			86
2008			228
2009 through 2011			122
Total		$	436

     Options to purchase a total of 137,500 shares of common stock were outstanding and unvested as of September 30, 2007. During the nine months ended September 30, 2007, options to purchase 17,500 shares of common stock were granted to one individual, options to purchase 597,000 shares of common stock were exercised and options to purchase 40,000 shares were forfeited and no options expired.

     The fair value of each option award is estimated on the date of grant. The fair values of stock options granted prior to and remaining outstanding at September 30, 2007 and that had option shares subject to future vesting at that date were determined using the Black-Scholes option valuation method and the assumptions noted in the following table. Expected volatilities are based on historical volatility of the 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.

		2007				2005				2001
Expected volatility			52.52	%			54.20	%			57.95	%
Expected dividends			0.00				0.00				0.00
Expected term (in years)			6				7				8
Risk-free rate			4.89	%			4.20	%			5.05	%

     A summary of the option activity as of September 30, 2007 is presented below:

										Weighted
										Average
										Remaining
						Weighted Average				Contractual				Aggregate
		Options				Exercise Price				Term				Intrinsic Value
		(in thousands)								(years)				(in thousands)
Outstanding December 31, 2006			1,199			$	5.40
Granted			17			$	22.89
Exercised			(597	)		$	4.00
Forfeited			(40	)		$	12.27
Outstanding September 30, 2007			579			$	6.90				6.1			$	5,844
Exercisable at September 30, 2007			442			$	5.30				5.2			$	5,163

		(in thousands)
Intrinsic Value of Options Exercised Nine Months Ended September 30, 2007		$	9,705
Intrinsic Value of Options Exercised Nine Months Ended September 30, 2006		$	2,855
Fair Market Value of Options Granted Nine Months Ended September 30, 2007		$	218
Fair Market Value of Options Granted Nine Months Ended September 30, 2006		$	—

     We have outstanding stock options granted under five separate plans. Generally, options expire 10 years from the date of grant and become exercisable at rates ranging from 10% each year up to 50% each year. The exercise price cannot be less than the fair market value per share of common stock on the date of grant.

NOTE 3. CREDIT ARRANGEMENTS

     In the past, we have maintained two separate credit facilities. One of these credit facilities is our Third Amended and Restated Credit Agreement, as amended, or “Revolving Credit Agreement”, with a group of bank lenders which, at September 30, 2007, provided us with a revolving line of credit having a “borrowing base” limitation of $150.0 million. 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, 2007, the principal amount outstanding under our revolving credit facility was $89.0 million, excluding $445,000 reserved for our letters of credit. Our second credit facility was a five year term loan facility provided to us under a Second Lien Term Loan Agreement, or the “Second Lien Agreement”, with a group of banks and other lenders. The Second Lien Term Loan Agreement was paid off and terminated on July 31, 2007 with our payment to the lenders of $50.2 million, including interest. This payment was made with proceeds from our sale of unsecured senior notes, or “senior notes”, in the principal amount of $150.0 million that we completed on July 31, 2007.

     Revolving Credit Facility

     Our Revolving Credit Agreement 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 in 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 our 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, 2007, our weighted average base rate and LIBOR rate, plus the applicable margin, was 7.64% on $89.0 million, the outstanding principal amount of our revolving loan on that same date.

     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, we are required to pay an unused commitment fee to the lenders in an amount equal to .25% of the daily average of the unadvanced portion of the borrowing base. The fee is payable quarterly.

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

     All outstanding principal and accrued and unpaid interest 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.

     The Revolving Credit Agreement contains various restrictive covenants, including (i) maintenance of a minimum current ratio, (ii) maintenance of a maximum ratio of funded indebtedness to earnings before interest, income taxes, depreciation, depletion and amortization, (iii) maintenance of a minimum net worth, (iv) prohibition of payment of dividends and (v) restrictions on incurrence of additional debt. We have pledged substantially all of our producing oil and natural gas properties to secure the repayment of our indebtedness under the Revolving Credit Agreement.

     As of September 30, 2007 we were in compliance with all of the covenants in our Revolving Credit Agreement.

     Second Lien Term Loan Facility

     Until July 31, 2007, we also had a $50.0 million term loan made available to us under our Second Lien Agreement. Similar to our Revolving Credit Agreement, interest on loans made to us under this credit facility accrued, at our election, either at an alternate base rate or a rate designated in the Second Lien Agreement as the “LIBO” rate. The alternate base rate was the greater of (a) the prime rate in effect on any 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 LIBO rate was generally equal to the sum of (a) a rate appearing in the Dow Jones Market

Service for the applicable interest periods offered in one, two, three or six month periods and (b) an applicable margin rate per annum equal to 4.50%.

     Our producing oil and natural gas properties were also pledged to secure payment of our indebtedness under this facility, but the liens granted to the lender under the Second Lien Agreement were second and junior to the rights of the first lienholders under the Revolving Credit Agreement.

     In the case of alternate base rate loans, interest was payable the last day of each March, September, September and December. In the case of LIBO loans, interest was payable on the last day of the interest period applicable to each tranche, but not to exceed intervals of three months.

     Upon completion of our senior notes offering, we paid off and terminated this facility on July 31, 2007 with $50.2 million of the net proceeds from the offering. As a result we charged to earnings $760,000 of previously capitalized debt issuance cost.

     Senior Notes

     On July 31, 2007, we completed a private offering of unsecured senior notes (the “senior notes”) in the principal amount of $150.0 million. The senior notes were recorded at the principal amount net of underwriters discount and related expenses of $4.8 million. The senior notes mature on August 1, 2014 and bear interest at 10.25% which is payable semi-annually beginning on February 1, 2008. Considering the discount on the senior notes, the effective interest rate is 10.92%. Prior to August 1, 2010, we may redeem up to 35% of the senior notes for a price equal to 110.250% of the original principal amount of the senior notes with the proceeds of certain equity offerings. On or after August 1, 2011 we may redeem all or some of the senior notes at a redemption price that will decrease from 105.125% of the principal amount of the senior notes to 100% of the principal amount on August 1, 2013. In addition, prior to August 1, 2011, we may redeem some or all of the senior notes at a redemption price equal to 100% of the principal amount of the senior notes to be redeemed, plus a make-whole premium, plus any accrued and unpaid interest. Generally, the “make-whole” premium is an amount equal to the greater of (a) 1% of the principal amount of the senior notes being redeemed and (b) the excess of the present value of the redemption price of such notes as of August 1, 2011 plus all required interest payments due through August 1, 2011 (computed at a discount rate equal to a specified U.S. “Treasury Rate” plus 50 basis points), over the principal amount of the senior notes being redeemed.

     We have agreed, pursuant to a Registration Rights Agreement with the initial purchasers of the senior notes to use our commercially reasonable efforts to prepare and file with the Securities and Exchange Commission, within 180 days after July 31, 2007, a registration statement with respect to a registered offer to exchange freely tradable notes having substantially identical terms as the senior notes and to use our reasonable best efforts to cause the registration statement to be declared effective within 210 days after July 31, 2007. If we fail to meet these obligations under the Registration Rights Agreement we may be required to pay additional interest to holders of the senior notes. The rate of additional interest will be .25% per year for the first 90-day period immediately following a determination that the provisions of the Registration Rights Agreement have not been fulfilled, with the rate increasing by an additional .25% for each subsequent 90 day period up to a maximum additional interest rate of 1.0% per year. Under this agreement, the maximum additional interest that we could be required to pay over the life of the senior

notes is approximately $9.4 million. No amounts of additional interest have been accrued as a liability as we have no belief that we will not be able to fulfill the requirements of the Registration Rights Agreement.

     The indenture governing the senior notes restricts our ability to: (i) borrow money; (ii) issue redeemable and preferred stock; (iii) pay distributions or dividends; (iv) make investments; (v) create liens without securing the senior notes; (vi) enter into agreements that restrict dividends from subsidiaries; (vii) sell certain assets or merge with or into other companies; (viii) enter into transactions with affiliates; (ix) guarantee indebtedness; and (x) enter into new lines of business.

     The net proceeds, after payment of typical transaction expenses, of approximately $143.5 million were used first to retire our second lien term loan with the remainder being applied to our revolving credit facility.

     Interest Accrued

     For the nine months ended September 30, 2007, the aggregate interest accrued under our Revolving Credit Agreement, Second Lien Agreement and our senior notes was approximately $13.5 million. Of this amount, approximately $393,000 was capitalized.

NOTE 4. PROPERTY EXCHANGE

     On February 23, 2007, we entered into a property exchange agreement with an unrelated third party. As a result of the exchange, we acquired an additional 9,233 net undeveloped acres in our New Mexico Wolfcamp project area with an estimated fair value of approximately $6.5 million. We will be the operator of wells drilled on this undeveloped acreage. Under the terms of the exchange agreement, we assigned to the third party interests in 37 non-operated wells and 3,250 net undeveloped non-operated acres in the New Mexico Wolfcamp project area, along with cash of approximately $969,000. In accordance with the full cost method of accounting, no gain or loss was recorded on the transaction.

NOTE 5. 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. 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 over the ceiling, 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.

     Under the full cost method of accounting, all costs incurred in the acquisition, exploration and development of oil and natural gas properties, including a portion of our overhead, are capitalized. In the nine month periods ended September 30, 2007 and 2006, overhead costs capitalized were approximately $1.1 million and $1.3 million, respectively.

NOTE 6. 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 Revolving Credit Agreement requires us to maintain derivative financial instruments covering at least 50% of our estimated monthly production of oil and natural gas extending 24 months into the future.

     Derivative contracts not designated as cash flow 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 completed a fixed interest rate swap contract with BNP Paribas, based on the 90-day LIBOR rates at the time we entered into the contract in January 2003. This interest rate swap was treated as a cash flow hedge as defined by Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended (“SFAS 133”), and covered $10.0 million of our variable rate debt for all of 2006. As of December 31, 2006 this interest rate swap had expired.

     We have employed 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. These contracts are accounted for by “mark to market” accounting as prescribed in SFAS 133. We view these contracts as protection against future interest rate volatility. As of September 30, 2007, the fair market value of these interest rate swaps was a liability of approximately $591,000.

     The table below recaps the nature of these interest rate swaps and the fair market value of these contracts as of September 30, 2007.

										Estimated
		Notional				Fixed				Fair
Period of Time		Amounts				Interest Rates				Market Value
		($ in millions)								($ in thousands)
October 1, 2007 thru December 31, 2007		$	100				4.62	%		$	161
January 1, 2008 thru December 31, 2008		$	100				4.86	%			(323	)
January 1, 2009 thru December 31, 2009		$	50				5.06	%			(283	)
January 1, 2010 thru October 31, 2010		$	50				5.15	%			(146	)
Total Fair Market Value										$	(591	)

Commodity Price Sensitivity

     All of our commodity derivatives are accounted for using “mark-to-market” accounting as prescribed in SFAS 133.

     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, 2007 is as follows:

														Estimated
		Barrles of				NyMex Oil Prices								Fair Market
Period of Time		Oil				Floor				Cap				Value
														($ in thousands)
October 1, 2007 thru December 31, 2007			73,600			$	55.63			$	84.88			$	(108	)
January 1, 2008 thru December 31, 2008			237,900			$	60.38			$	81.08				(553	)
January 1, 2009 thru December 31, 2009			620,500			$	63.53			$	80.21				(473	)
January 1, 2010 thru October 31, 2010			486,400			$	63.44			$	78.26				(80	)

						Houston Ship
		M M Btu of				Channel Gas Prices
		Natural Gas				Floor				Cap
October 1, 2007 thru October 31, 2007			31,000			$	6.00			$	11.05				—

		M M Btu of				WAHA Gas Prices
		Natural Gas				Floor				Cap
October 1, 2007 thru October 31, 2007			93,000			$	6.25			$	8.90				75
October 1, 2007 thru March 31, 2008			1,098,000			$	6.50			$	9.50				472
Total Fair Market Value														$	(667	)

     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 us if the reference price for any settlement period is less than the swap or fixed price for such contract, and we are 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.

     We have entered into oil swap contracts with BNP Paribas. A summary of our commodity swaps at September 30, 2007 is as follows:

										Estimated
		Number of				NyMex Oil				Fair Market
Period of Time		Barrels of Oil				Swap Price				Value
										($ in thousands)
October 1, 2007 thru December 31, 2007			119,600			$	34.36			$	(5,411	)
January 1, 2008 thru December 31, 2008			439,200			$	33.37				(17,923	)
Total fair market value										$	(23,334	)

NOTE 7. NET INCOME PER COMMON SHARE

     Basic earnings per share (“EPS”) exclude any dilutive effects of options, 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, 2007 and 2006:

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2007				2006				2007				2006
		(dollars in thousands, except per share data)
Basic EPS Computation:
Numerator-
Income		$	293			$	10,996			$	3,661			$	15,071
Denominator-
Weighted average common shares outstanding			38,033				36,215				37,791				35,340
Basic EPS:
Income per share		$	0.01			$	0.30			$	0.10			$	0.43
Diluted EPS Computation:
Numerator-
Income		$	293			$	10,996			$	3,661			$	15,071
Denominator -
Weighted average common shares outstanding			38,033				36,215				37,791				35,340
Employee stock options			521				596				749				581
Warrants			213				108				266				106
Weighted average common shares for diluted earnings per share assuming conversion			38,767				36,919				38,806				36,027
Diluted EPS:
Income per share		$	0.01			$	0.30			$	0.09			$	0.42

NOTE 8. ASSET RETIREMENT OBLIGATIONS

     The following table summarizes our asset retirement obligation transactions:

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2007				2006				2007				2006
						(in thousands)
Beginning asset retirement obligation		$	4,842			$	4,420			$	5,063			$	2,495
Additions related to new properties			85				123				151				314
Revisions in estimated cash flows			(130	)			11				(297	)			1,674
Deletions related to property disposals			(74	)			—				(358	)			(30	)
Accretion expense			79				71				243				172
Ending asset retirement obligation		$	4,802			$	4,625			$	4,802			$	4,625

NOTE 9. RECENTLY ANNOUNCED ACCOUNTING PRONOUNCEMENTS

     We adopted the provisions of Financial Accounting Standards Board (“FASB”) Interpretation No. 48, “Accounting for Uncertainty in Income Taxes-an interpretation of FASB Statement No. 109” (“FIN 48”), on January 1, 2007. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement 109, “Accounting for Income Taxes”, and prescribes a recognition threshold and measurement process for financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.

     Based on our evaluation, we have concluded that there are no significant uncertain tax positions requiring recognition in our financial statements. Our evaluation was performed for the tax years ended December 31, 2003, 2004, 2005 and 2006, the tax years which remain subject to examination by major tax jurisdictions as of September 30, 2007.

     We may from time to time be assessed interest or penalties by major tax jurisdictions, although any such assessments historically have been minimal and immaterial to our financial results.

     In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“FAS 157”). FAS 157 defines fair value as used in numerous accounting pronouncements, establishes a framework for measuring fair value in accordance with generally accepted accounting principles and expands disclosure requirements related to the use of fair value measures in financial statements. FAS 157 will be effective for our financial statements for the fiscal year beginning January 1, 2008; however, earlier application is encouraged. We are currently evaluating the timing of adoption and the impact that adoption might have on our financial position or results of operations.

     In February 2007, the FASB issued SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities, Including an Amendment of FASB Statement No. 115,” (FAS 159) which will become effective on January 1, 2008. FAS 159 permits entities to measure eligible financial assets, financial liabilities and firm commitments at fair value, on an instrument-by-instrument basis, that are otherwise not permitted to be accounted for at fair value under other generally accepted accounting principles. The

fair value measurement election is irrevocable and subsequent changes in fair value must be recorded in earnings. We will adopt this statement in the first quarter of 2008 and we do not expect to elect the fair value option for any eligible financial instruments and other items.

NOTE 10. INVESTMENT IN GAS GATHERING SYSTEMS

     We have invested in three separate partnerships that own and construct pipeline systems for gathering natural gas, primarily on our leaseholds in the Barnett Shale area. These partnerships include West Fork Pipeline Company I, L.P., West Fork Pipeline Company II, L.P. and West Fork Pipeline Company V, L.P. These investments were recorded as equity investments in the accompanying consolidated balance sheet. During the fourth quarter 2006, substantially all of the assets of West Fork Pipeline I and West Fork Pipeline V were sold. As of September 30, 2007, we had invested $306,000 in West Fork Pipeline II. West Fork Pipeline II is currently acquiring the necessary easements and permits to begin transmission of natural gas.

     As of September 30, 2007, we also invested $8.3 million in a joint venture known as the Hagerman Gas Gathering System (“Hagerman”) to construct pipelines on certain of our leaseholds in New Mexico. The Hagerman gathering system is currently being extended to additional productive areas.

     Our current investment percentage in the two remaining ventures is as follows:

West Fork Pipeline Company II, L.P.			35.8750	%
Hagerman Gas Gathering System			76.5000	%

     Our investment in Hagerman is accounted for by the equity method since we do not have voting control. All significant actions taken by Hagerman must be approved by Parallel, plus one of the two other equity owners. Consequently, the remaining equity owners can prevent voting control by Parallel.

     Our equity investments consisted of the following as of the dates indicated:

		September 30,				December 31,
		2007				2006
		($ in thousands)
West Fork Pipeline Company II, L.P.		$	306			$	280
Hagerman Gas Gathering System			8,315				6,174
		$	8,621			$	6,454

     Our losses from equity investments were as follows:

		Three Months Ended September 30,								Nine Months Ended September 30,
		2007				2006				2007				2006
		($ in thousands)								($ in thousands)
West Fork Pipeline Company I, L.P.		$	—			$	169			$	—			$	195
West Fork Pipeline Company II, L.P.			—				(15	)			5				(35	)
West Fork Pipeline Company V, L.P.			—				(22	)			—				(57	)
Hagerman Gas Gathering System			(69	)			(171	)			(668	)			(171	)
		$	(69	)		$	(39	)		$	(663	)		$	(68	)

     Summarized combined financial information for our equity investments (listed above) is reported below. Amounts represent 100% of the investees’ financial information:

		September 30,				December 31,
		2007				2006
		($ in thousands)
Balance Sheet
Current assets		$	601			$	1,408
Non-current assets			11,032				8,351
Current liabilities			541				1,329
Owners’ equity			11,092				8,430

		Three Months Ended September 30,								Nine Months Ended September 30,
		2007				2006				2007				2006
		($ in thousands)								($ in thousands)
Income Statement
Revenues		$	181			$	1,276			$	346			$	2,383
Costs and expenses			(426	)			(963	)			(1,234	)			(1,971	)
Net income (loss)		$	(245	)		$	313			$	(888	)		$	412

NOTE 11. COMMITMENTS AND CONTINGENCIES

     From time to time, we are party to ordinary routine litigation incidental to our business. We are not presently a defendant in any judicial or other proceedings, nor are we aware of any 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 fiscal quarters ended September 30, 2007 and 2006, Parallel had made contributions to the 401(k) Plan and Trust of approximately $201,000 and $170,000, respectively.

     On May 21, 2007, we received a Notice of Proposed Adjustment, or the “Notice”, from the Internal Revenue Service, or the “Service”, advising us of proposed adjustments to our calculations of federal income tax resulting in a proposed alternative minimum tax liability in the aggregate amount of approximately $2.0 million for the years 2004 and 2005. After advising the Service that we intended to appeal the Notice, we received correspondence from the Service on July 10, 2007 stating that the issue remains in development pending receipt of additional documents requested and any proposed tax adjustment would not be made until after reviewing the documents requested. On November 5, 2007, we received an examination report related to this matter which reduces the amount of proposed adjustment to approximately $1.1 million, which includes interest. We intend to vigorously contest the adjustment proposed by the Service and believe that we will ultimately prevail in our position. We would expect the recording of any adjustment, if later determined to be required, to entail a reclassification from our deferred tax liability accounts to a current liability for federal income taxes payable. Such an adjustment would generally not result in a charge to earnings except for amounts which might be assessed for penalties or interest on underpayment

of current tax for our fiscal years ending December 31, 2004 and 2005. If a liability for penalties or interest were determined to be probable, the amounts of such penalties and/or interest would be charged to earnings. We believe that the effects of this matter would not have a material adverse effect on our financial position or results of operations for any fiscal year, but could have a material adverse effect on our results of operations for the fiscal quarter in which we actually incur or establish a reserve account for penalties or interest.

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 2006 Annual Report on Form 10-K/A, as well as the unaudited consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.

OVERVIEW

Strategy

     Conduct Exploitation Activities on Our Existing Assets. We seek to maximize economic return on our existing assets by maximizing production rates and ultimate recovery, while managing operational efficiency to minimize direct lifting costs. Development and production growth activities include infill and extension drilling of new wells, re-completion, pay adds and re-stimulation of existing wells and implementation and management of enhanced oil recovery projects such as waterflood operations. Operational efficiencies and cost reduction measures include optimization of surface facilities, such as fluid handling systems, gas compression or artificial lift installations. Efficiencies are also increased through aggressive monitoring and management of electrical power consumption, injection water quality programs, chemical and corrosion prevention programs and the use of production surveillance equipment and software. In all instances, a proactive approach is taken to achieve the desired result while ensuring minimal environmental impact.

     Accelerate Horizontal Drilling and Fracture Stimulation Activities in Gas Resource Plays. We believe the use of horizontal drilling and fracture stimulations has enabled us to develop reserves economically, such as our Barnett Shale and Wolfcamp Carbonate gas projects.

     Use Advanced Technologies and Production Techniques. We believe that 3-D seismic surveys, horizontal drilling, fracture stimulation and other advanced technologies and production techniques are useful tools that help improve normal drilling operations and enhance our production and returns. We believe that our use of these technologies and production techniques in exploring for, developing and exploiting oil and natural gas properties can: reduce drilling risks, lower finding costs, provide for more efficient production of oil and natural gas from our properties and increase the probability of locating and producing reserves that might not otherwise be discovered.

     Acquire Long-Lived Properties with Enhancement Opportunities. Our acquisition strategy is focused on leveraging our geographical expertise in our core areas of operation and seeking assets located in and around these areas. We selectively evaluate acquisition opportunities and expect that they will continue to play a role in increasing our reserve base and future drilling inventory. When identifying target assets, we focus primarily on reserve quality and assets in nascent plays with upside potential. Through this approach, we have traditionally targeted smaller asset acquisitions which allow us to absorb, enhance and exploit properties without taking on significant integration risk.

     Conduct Exploratory Activities. Although we do not emphasize exploratory drilling, we will selectively undertake exploratory projects that have known geological and reservoir characteristics, are in close proximity to existing wells so data from the existing wells can be correlated with seismic data on or near the prospect being evaluated, and that could have a potentially meaningful impact on our reserves.

     The extent to which we are able to implement and follow through with our business strategy 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 we produce, 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;
	•		costs of capital; and
	•		effects of derivative contracts.

     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 and debt securities;
	•		bank borrowings; and
	•		industry joint ventures.

     For the three months ended September 30, 2007 the sale price we received for our crude oil production (excluding hedges) averaged $69.45 per barrel compared with $64.53 per barrel for the three months ended September 30, 2006. The average sales price we received for natural gas for the three months ended September 30, 2007, was $5.81 per Mcf compared with $5.64 per Mcf for the three months ended September 30, 2006. Hedge costs for oil were $3.3 million for the three months ended September 30, 2006. The ineffective portion showed a gain of approximately $305,000 for the three months ended September 30, 2006. We settled all remaining derivatives classified as cash flow hedges in December 2006. Therefore, no ineffectiveness on hedges was identified in 2007. For information regarding prices received including our hedges, you should refer to the selected operating data table under “Results of Operations” on page 20.

     For the nine months ended September 30, 2007, the sale price we received for our crude oil production (excluding hedges) averaged $59.98 per barrel compared with $61.88 per barrel for the nine months ended September 30, 2006. The average sales price we received for natural gas for the nine months ended September 30, 2007, was $6.14 per Mcf compared with $6.11 per Mcf for the nine months ended September 30, 2006. Hedge costs for oil and natural gas was $9.3 million for the nine months ended September 30, 2006. The ineffective portion showed a gain approximately $500,000 for the nine months ended September 30, 2006. We settled all remaining derivatives classified as cash flow hedges in December 2006. Therefore, no ineffectiveness on hedges was identified in 2007. For information regarding prices received including our hedges, you should refer to the selected operating data table under “Results of Operations” on page 20.

     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 through September 30, 2007 and 2006 was $12.84 and $10.53 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, 2007 and September 30, 2006.

		Three Months Ended								Nine Months Ended
		9/30/2007				9/30/2006				9/30/2007				9/30/2006
						(in thousands, except per unit data)
Production Volumes:
Oil (Bbls)			254				282				797				848
Natural gas (Mcf)			2,043				2,001				5,243				4,894
BOE (1)			595				616				1,671				1,664
BOE per day			6.5				6.7				6.1				6.1
Sales Prices:
Oil (per Bbl) (2)		$	69.45			$	64.53			$	59.98			$	61.88
Natural gas (per Mcf)		$	5.81			$	5.64			$	6.14			$	6.11
BOE price (2)		$	49.62			$	47.91			$	47.86			$	49.50
BOE price (3)		$	49.62			$	42.58			$	47.86			$	43.93
Operating Revenues
Oil		$	17,619			$	18,194			$	47,786			$	52,478
Oil hedge			—				(3,279	)			—				(9,264	)
Natural gas			11,868				11,296				32,171				29,882
		$	29,487			$	26,211			$	79,957			$	73,096
Operating Expenses:
Lease operating expense		$	6,445			$	5,323			$	16,420			$	12,639
Production taxes			1,448				1,538				3,696				4,116
Production tax refund			—				—				(1,209	)			—
General and administrative			2,492				2,405				7,737				7,147
Depreciation, depletion and amortization			7,821				7,420				21,680				17,848
		$	18,206			$	16,686			$	48,324			$	41,750
Operating income		$	11,281			$	9,525			$	31,633			$	31,346

RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2007 AND 2006:

     Our oil and natural gas revenues and production product mix are displayed in the following table for the three months ended September 30, 2007 and September 30, 2006.

Oil and Gas Revenues

		Revenues(1)								Production
		2007				2006				2007				2006
Oil (Bbls)			60	%			57	%			43	%			46	%
Natural gas (Mcf)			40	%			43	%			57	%			54	%
Total			100	%			100	%			100	%			100	%

     The following table shows our production volumes, product sales prices and operating revenues for the following periods.

		Three Months Ended September 30,								Increase				% Increase
		2007				2006				(Decrease)				(Decrease)
						(in thousands except per unit data)
Production Volumes
Oil (Bbls)			254				282				(28	)			(10	)%
Natural gas (Mcf)			2,043				2,001				42				2	%
BOE			595				616				(22	)			(3	)%
BOE/Day			6.5				6.7				(0.2	)			(3	)%
Sales Price
Oil (per Bbl)(1)		$	69.45			$	64.53			$	4.92				8	%
Natural gas (per Mcf)		$	5.81			$	5.64			$	0.17				3	%
BOE price(1)		$	49.62			$	47.91			$	1.71				4	%
BOE price(2)		$	49.62			$	42.58			$	7.04				17	%
Operating Revenues
Oil		$	17,619			$	18,194			$	(575	)			(3	)%
Oil hedges			—				(3,279	)			3,279				(100	)%
Natural gas			11,868				11,296				572				5	%
Total		$	29,487			$	26,211			$	3,276				12	%

Oil revenues

     Average oil prices, excluding hedges, for the three months ended September 30, 2006 were $64.53, as compared to $69.45 for the three months ended September 30, 2007. Average oil prices were up $4.92 Bbl. When applied to current production, this accounts for an additional $1.2 million in revenue. Oil production decreased 10% or 28,000 Bbls. These decreases occurred primarily in the Carm-Ann of 11,000 Bbls, Diamond M Deep of 11,000 Bbls and the Wilcox area in south Texas of 4,000 Bbls. These decreases were as a result of natural declines and limited developmental activity occurring in 2007 in these areas. The volume decline accounted for a reduction of $1.8 million in revenue.

Natural gas revenues

     Average natural gas prices for three months ended September 30, 2006 was $5.64 compared to the three months ended September 30, 2007 of $5.81. Average natural gas prices received were up $0.17 per Mcf, when applied to current production this accounted for an increase of approximately $347,000 in revenue. Natural gas production increased 2%, primarily due to an increase in the New Mexico Wolfcamp of approximately 412,000 Mcf. This was as of a result of the developmental program in this area. This volume increase was offset with decreases in south Texas of approximately 302,000 Mcf which is as a result of normal decline and Parallel refocusing activity away from this area. In addition there was a decline of approximately 45,000 Mcf in the Permian area where limited developmental drilling activity has occurred during 2007. This volume increase accounted for an increase in revenue of approximately $225,000.

Oil hedges

     We settled all remaining derivatives classified as cash flow hedges in December 2006. Therefore, oil hedge losses were $0 for three months ended September 30, 2007 compared to a loss of $3.2 million for three months ended September 30, 2006.

Cost and Expenses

		Three months ended September 30,								Increase				% Increase
		2007				2006				(Decrease)				(Decrease)
						(dollars in thousands)
Lease operating expense		$	6,445			$	5,323			$	1,122				21	%
Production taxes			1,448				1,538				(90	)			(6	)%
General and administrative			2,492				2,405				87				4	%
Depreciation, depletion and amortization			7,821				7,420				401				5	%
Total		$	18,206			$	16,686			$	1,520				9	%

Lease operating expense

     Lease operating expenses are up primarily due to workover expenditures incurred in 2007. We are currently performing workovers on several of our older oil properties and this has led to an increase in this category of approximately $610,000. As we begin our drilling program on these oil properties, we expect these costs to go down. In addition we incurred approximately $691,000 in charges on new wells during the third quarter 2007 that had not been drilled in 2006. As we drill additional wells our lease operating expenses will go up. Lifting costs (excluding production taxes) were $10.84 per BOE in 2007 compared to $8.64 per BOE in 2006, a 25% increase in our per BOE lifting costs.

Production taxes

     Production taxes decreased 6% or $90,000 in 2007, associated with an approved reduced tax rate on non-operated wells in the Wilcox area of south Texas. We were notified of these rates in June 2007. Production taxes are a function of product mix, production volumes and product prices.

General and administrative

     General and administrative expenses increased 4%, or approximately $87,000, in 2007 as compared to 2006. This increase was primarily due to increases in legal fees of approximately $150,000. Salary costs were up $86,000 which offset a reduction in contract labor costs of $105,000. On a BOE basis, general and administrative expenses were $4.20 per BOE in 2007 compared to $3.90 per BOE in 2006.

Depreciation, depletion and amortization

     Depreciation, depletion and amortization expense increased 5%, or $401,000, for 2007 as compared to 2006. This increase is attributable to an overall increase in actual and anticipated drilling costs and related oilfield service costs. Increased cost levels affect both the depletable amounts of capitalized costs in 2007 and the depletion attributable to amounts of estimated future development costs on proved undeveloped properties. Throughout 2007, our actual drilling activity and a majority of our newly identified proved undeveloped locations have been in our natural gas resource projects in the Permian Basin of west Texas and the Barnett Shale areas. These areas have higher associated per BOE drilling and development costs due to the use of horizontal drilling and multi-stage stimulation techniques. These factors, when combined with the increase in the absolute level of our capital expenditures during this time period have led to increases in our depletion rate per BOE.

Other income (expense)

		Three months ended September 30,								Increase				% Increase
		2007				2006				(Decrease)				(Decrease)
						(dollars in thousands)
Gain (loss) on derivatives not classified as hedges		$	(4,556	)		$	10,323				(14,879	)			(144	)%
Gain on ineffective portion of hedges			—				305				(305	)			(100	)%
Interest and other income			55				29				26				90	%
Interest expense, net			(5,429	)			(3,345	)			(2,084	)			62	%
Cost of debt retirement			(760	)			—				(760	)			N/A
Other expense			(76	)			(96	)			20				(21	)%
Equity in loss of pipelines and gathering system ventures			(69	)			(39	)			(30	)			77	%
Total		$	(10,835	)		$	7,177			$	(18,012	)			(251	)%

Gain (loss) on derivatives not classified as hedges

     We recorded a loss of $4.6 million in 2007 for derivatives not classified as hedges, as compared to a gain of $10.3 million for 2006. Future gains or losses on derivatives not classified as hedges will be impacted by the volatility of commodity prices and interest rates, as well as by the terms of any new derivative contracts.

Interest expense

     Interest expense increased $2.0 million with the $92 million increase in principal amount of our debt from $147.0 million at September 30, 2006 to $239.0 million at September 30, 2007 along with an increase in our weighted average interest rates for 2007.

Cost of debt retirement

     Cost of debt retirement represent the write off of previously capitalized debt issuance costs associated with our Second Lien Term Loan that was retired with the proceeds of our senior notes offering.

Equity in loss of pipelines and gathering system ventures

     During 2006, we and two other unaffiliated parties formed a joint venture known as the Hagerman Gas Gathering System, which was formed for the purpose of constructing, owning and operating a

gas gathering system in New Mexico. For the quarter ended September 30, 2007, the loss from the investment was approximately $69,000. This loss was offset by an insignificant amount of income from our equity investment in West Fork Pipeline II. We recognize our share of net loss from negative net operating income as an investment loss.

Federal income tax

     Federal income tax expense was approximately $153,000 in 2007 compared to $5.7 million in 2006. Income tax expense for 2007 will be dependent on our earnings and is expected to be approximately 35% of income before income taxes.

Basic and diluted net income

     We had basic and diluted net income per share of $0.01 and $.30 for 2007 and 2006, respectively. Basic weighted average common shares outstanding increased from 36.2 million shares in 2006 to 38.0 million shares in 2007. The increase in common shares was primarily due to our public offering of 2.5 million shares of common stock in August 2006 and the exercise of employee and non-employee stock options.

RESULTS OF OPERATIONS FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2007 AND 2006:

     Our oil and natural gas revenues and production product mix are displayed in the following table for the nine months ended September 30, 2007 and September 30, 2006.

Oil and Gas Revenues

		Revenues(1)								Production
		2007				2006				2007				2006
Oil (Bbls)			60	%			59	%			48	%			51	%
Natural gas (Mcf)			40	%			41	%			52	%			49	%
Total			100	%			100	%			100	%			100	%