UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C. 20549

FORM 10-Q

(Mark One)

þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2007

or

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Transition period from                      to                     

Commission File Number 000-13305

PARALLEL PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

Delaware		75-1971716
(State of other jurisdiction of		(I.R.S. Employer Identification 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
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 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 August 3, 2007, 37,897,923 shares of the Registrant’s Common Stock, $0.01 par value, were outstanding.

 

 

INDEX

		Page No.
PART I. — FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Reference is made to the succeeding pages for the following consolidated financial statements:
- Consolidated Balance Sheets as of June 30, 2007 (unaudited) and December 31, 2006			1
- Unaudited Consolidated Statements of Operations for the three months and six months ended June 30, 2007 and 2006			2
- Unaudited Consolidated Statements of Cash Flows for the six months ended June 30, 2007 and 2006			3
- Unaudited Consolidated Statements of Comprehensive Income for the three months and six months ended June 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.			16
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			35
ITEM 4. CONTROLS AND PROCEDURES			37
PART II — OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS			38
ITEM 1A. RISK FACTORS			38
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS			43
ITEM 6. EXHIBITS			44
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

		June 30,				December 31,
		2007				2006
		(unaudited)
Assets
Current assets:
Cash and cash equivalents		$	5,515			$	5,910
Accounts receivable:
Oil and natural gas sales			17,628				18,605
Joint interest owners and other, net of allowance for doubtful account of $50			4,127				7,209
Affiliates and joint ventures			1,538				3,338
			23,293				29,152
Other current assets			2,298				2,863
Deferred tax asset			5,423				4,340
Total current assets			36,529				42,265
Property and equipment, at cost:
Oil and natural gas properties, full cost method (including $69,203 and $50,375 not subject to depletion)			572,809				501,405
Other			2,771				2,614
			575,580				504,019
Less accumulated depreciation, depletion and amortization			(129,315	)			(115,513	)
Net property and equipment			446,265				388,506
Restricted cash			52				325
Investment in pipelines and gathering system ventures			8,708				6,454
Other assets, net of accumulated amortization of $1,401 and $760			2,724				5,268
		$	494,278			$	442,818
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities		$	38,002			$	36,171
Asset retirement obligations			686				701
Derivative obligations			17,022				14,109
Total current liabilities			55,710				50,981
Revolving credit facility			159,500				115,000
Term loan			50,000				50,000
Asset retirement obligations			4,156				4,362
Derivative obligations			9,137				14,386
Deferred tax liability			27,248				24,307
Total long-term liabilities			250,041				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 37,893,523 and 37,547,010			378				375
Additional paid-in capital			141,727				140,353
Retained earnings			46,422				43,054
Total stockholders’ equity			188,527				183,782
		$	494,278			$	442,818

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

PARALLEL PETROLEUM CORPORATION

		Three Months Ended June 30,								Six Months Ended June 30,
		2007				2006				2007				2006
Oil and natural gas revenues:
Oil and natural gas sales		$	27,354			$	29,594			$	50,470			$	52,870
Loss on hedging			—				(3,252	)			—				(5,985	)
Total revenues			27,354				26,342				50,470				46,885
Cost and expenses:
Lease operating expense			5,576				3,741				9,975				7,316
Production taxes			1,194				1,468				2,248				2,578
Production tax refund			(1,209	)			—				(1,209	)			—
General and administrative			2,580				2,613				5,245				4,742
Depreciation, depletion and amortization			7,150				6,140				13,859				10,428
Total costs and expenses			15,291				13,962				30,118				25,064
Operating income			12,063				12,380				20,352				21,821
Other income (expense), net:
Loss on derivatives not classified as hedges			(2,170	)			(5,493	)			(6,605	)			(10,207	)
Gain on ineffective portion of hedges			—				52				—				195
Interest and other income			56				25				108				93
Interest expense			(4,312	)			(3,158	)			(8,020	)			(5,599	)
Other expense			21				(39	)			(15	)			(68	)
Equity in loss of pipelines and gathering system ventures			(289	)			(10	)			(594	)			(29	)
Total other income (expense), net			(6,694	)			(8,623	)			(15,126	)			(15,615	)
Income before income taxes			5,369				3,757				5,226				6,206
Income tax expense, deferred			(1,905	)			(1,293	)			(1,858	)			(2,131	)
Net income		$	3,464			$	2,464			$	3,368			$	4,075
Net income per common share:
Basic		$	0.09			$	0.07			$	0.09			$	0.12
Diluted		$	0.09			$	0.07			$	0.09			$	0.11
Weighted average common shares outstanding:
Basic			37,786				34,940				37,667				34,896
Diluted			38,769				35,638				38,763				35,572

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

PARALLEL PETROLEUM CORPORATION

Six Months Ended June 30, 2007 and 2006
(unaudited)
(dollars in thousands)

		2007				2006
Cash flows from operating activities:
Net income		$	3,368			$	4,075
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization			13,859				10,428
Accretion of asset retirement obligation			164				101
Deferred income tax			1,858				2,131
Loss on derivatives not classified as hedges			6,605				10,207
Gain on ineffective portion of hedges			—				(195	)
Stock option expense			59				292
Equity in loss of pipelines and gathering system ventures			594				29
Bad debt expense			(30	)			—
Changes in assets and liabilities:
Other assets, net			(88	)			718
Restricted cash			273				—
Decrease (increase) in accounts receivable			5,889				(2,696	)
Decrease (increase) in other current assets			293				(457	)
Increase in accounts payable and accrued liabilities			1,831				15,508
Federal tax deposit			—				(40	)
Net cash provided by operating activities			34,675				40,101
Cash flows from investing activities:
Additions to oil and natural gas properties			(73,553	)			(107,159	)
Use of restricted cash for acquisition of oil and natural gas properties			—				2,366
Proceeds from disposition of oil and natural gas properties			1,764				41
Additions to other property and equipment			(214	)			(784	)
Settlements on derivative instruments			(5,862	)			(2,651	)
Investment in pipelines and gathering system ventures			(2,848	)			(6,209	)
Net cash used in investing activities			(80,713	)			(114,396	)
Cash flows from financing activities:
Borrowings from bank line of credit			46,000				73,500
Payments on bank line of credit			(1,500	)			—
Deferred financing cost			(175	)			(56	)
Proceeds from exercise of stock options			1,318				766
Net cash provided by financing activities			45,643				74,210
Net decrease in cash and cash equivalents			(395	)			(85	)
Cash and cash equivalents at beginning of period			5,910				6,418
Cash and cash equivalents at end of period		$	5,515			$	6,333
Non-cash financing and investing activities:
Oil and natural gas properties asset retirement obligations		$	(385	)		$	1,825
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		$	8,474			$	5,026

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

PARALLEL PETROLEUM CORPORATION

		Three Months Ended June 30,								Six Months Ended June 30,
		2007				2006				2007				2006
Net income		$	3,464			$	2,464			$	3,368			$	4,075
Other comprehensive loss:
Unrealized losses on derivatives			—				(1,084	)			—				(2,384	)
Reclassification adjustments for losses on derivatives included in net income			—				3,230				—				5,951
Change in fair value of derivatives			—				2,146				—				3,567
Income tax expense			—				(730	)			—				(1,213	)
Total other comprehensive income			—				1,416				—				2,354
Total comprehensive income		$	3,464			$	3,880			$	3,368			$	6,429

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.

     Parallel Petroleum Corporation, or “Parallel”, and its subsidiaries 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. 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

     Parallel accounts 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 six months ended June 30, 2007 and 2006, Parallel recognized compensation expense of approximately $59,000 and $292,000, respectively, with a tax benefit of approximately $20,000 and $99,000, 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 includes a cumulative adjustment for amounts previously expensed associated with options estimated to be forfeited or surrendered.

     During the second quarter of 2006, Parallel determined that during 2003 approximately 30,000 options were awarded which were not available for issue under existing stock option plans. In June 2006, the Board of Directors approved a plan whereby these excess options were repurchased by Parallel for 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)
Third quarter 2007		$	101
Fourth quarter 2007			86
2008			228
2009 through 2011			122
Total		$	537

     Non-vested options outstanding were 167,500 as of June 30, 2007. During the six months ended June 30, 2007, options to purchase 17,500 shares of common stock were granted to one individual, options to purchase 305,000 shares of common stock were exercised and 40,000 options were forfeited; however, 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 June 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 June 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			(305	)		$	4.32
Forfeited			(40	)		$	12.27
Outstanding June 30, 2007			871			$	5.81				5.3			$	14,012
Exercisable at June 30, 2007			704			$	4.32				4.4			$	12,366

		(in thousands)
Intrinsic Value of Options Exercised Six Months Ended June 30, 2007		$	5,637
Intrinsic Value of Options Exercised Six Months Ended June 30, 2006		$	2,855
Fair Market Value of Options Granted Six Months Ended June 30, 2007		$	218
Fair Market Value of Options Granted Six Months Ended June 30, 2006		$	—

     We have outstanding stock options granted under five separate plans. 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 FACILITIES

     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 June 30, 2007, provided us with a revolving line of credit having a “borrowing base” limitation of $190.0 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 June 30, 2007, the principal amount outstanding under our revolving credit facility was $159.5 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. At June 30, 2007, our term loan under this facility was fully funded in the principal amount of $50.0 million, which was outstanding on that same date.

     As described below, in connection with our recent senior notes offering we entered into a Third Amendment to our Revolving Credit Agreement and paid off and terminated our Second Lien Agreement.

     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 June 30, 2007, our weighted average base rate and LIBOR rate, plus the applicable margin, was 8.11% on $159.5 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 June 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 Term Loan Agreement, or the “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 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.

     Upon completion of our senior notes offering, we paid off and terminated this facility, including interest payable, with $50.2 million of the net proceeds from the offering.

     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.

     At June 30, 2007, our LIBO interest rate, plus the applicable margin, was 9.875% on $50.0 million, the outstanding principal amount of our term loan on that same date.

     In the case of alternate base rate loans, interest was payable the last day of each March, June, 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.

     The Second Lien Agreement contained various restrictive covenants, including (i) maintenance of a maximum ratio of debt to earnings before interest, income taxes, depreciation, depletion and amortization, (ii) maintenance of a minimum ratio of oil and natural gas reserve value to debt, (iii) prohibition of payment of dividends, and (iv) restrictions on incurrence of additional debt. All outstanding principal and accrued and unpaid interest under the Second Lien Agreement was due and payable on November 15, 2010. The maturity date could be accelerated by the lenders upon the occurrence of an event of default under the Second Lien Agreement.

     As of June 30, 2007 we were in compliance with all of the covenants in our Second Lien Agreement.

     Interest accrued for the six months ended June 30, 2007, for both of our credit facilities, was approximately $8.4 million. Of this amount, approximately $345,000 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 over the ceiling, is compared to the ceiling on a quarterly and annual basis. Any excess of the net book value, less related deferred income taxes, is generally written off as an expense. Under rules and regulations of the SEC, the excess above the ceiling is not written off if, subsequent to the end of the quarter or year but prior to the release of the financial results, prices have increased sufficiently that such excess above the ceiling would not have existed if the increased prices were used in the calculations.

     Under the full cost method of accounting, all costs incurred in the acquisition, exploration and development of oil and natural gas properties, including a portion of our overhead, are capitalized. In the six month periods ended June 30, 2007 and 2006, overhead costs capitalized were approximately $725,000 and $854,000, 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 line of credit agreement as of June 30, 2007, 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.

     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 completed a fixed interest rate swap contract with BNP Paribas, based on the 90-day LIBOR rates at the time of the contract. 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 was on $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 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. These contracts are accounted for by “mark to market” accounting as prescribed in SFAS 133. We view these contracts as additional protection against future interest rate volatility. As of June 30, 2007, the fair market value of these interest rate swaps was approximately $939,000.

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

										Estimated
		Notional				Fixed				Fair
Period of Time		Amounts				Interest Rates				Market Value
		($ in millions)								($ in thousands)
July 1, 2007 thru December 31, 2007		$	100				4.62	%		$	415
January 1, 2008 thru December 31, 2008		$	100				4.86	%			331
January 1, 2009 thru December 31, 2009		$	50				5.06	%			100
January 1, 2010 thru October 31, 2010		$	50				5.15	%			93
Total Fair Market Value										$	939

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 June 30, 2007 is as follows:

														Estimated
		Barrles of				NyMex Oil Prices								Fair Market
Period of Time		Oil				Floor				Cap				Value
														($ in thousands)
July 1, 2007 thru December 31, 2007			147,200			$	55.63			$	84.88			$	(25	)
January 1, 2008 thru December 31, 2008			237,900			$	60.38			$	81.08				(161	)
January 1, 2009 thru December 31, 2009			620,500			$	63.53			$	80.21				(38	)
January 1, 2010 thru October 31, 2010			486,400			$	63.44			$	78.26				(251	)
						Houston Ship
		MMBtu of				Channel Gas Prices
		Natural Gas				Floor				Cap
July 1, 2007 thru October 31, 2007			123,000			$	6.00			$	11.05				24
		MMBtu of				WAHA Gas Prices
		Natural Gas				Floor				Cap
July 1, 2007 thru October 31, 2007			369,000			$	6.25			$	8.90				104
July 1, 2007 thru March 31, 2008			1,650,000			$	6.50			$	9.50				218
Total Fair Market Value														$	(129	)

     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.

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

						Nymex Oil				Fair Market
Period of Time		Barrels of Oil				Swap Price				Value
										($ in thousands)
July 1, 2007 thru December 31, 2007			239,200			$	34.36			$	(8,674	)
January 1, 2008 thru December 31, 2008			439,200			$	33.37				(16,185	)
Total fair market value										$	(24,859	)

NOTE 7. NET INCOME PER COMMON SHARE

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

     The following table provides the computation of basic and diluted earnings per share for the three and six months ended June 30, 2007 and 2006:

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2007				2006				2007				2006
		(dollars in thousands, except per share data)
Basic EPS Computation:
Numerator-
Income		$	3,464			$	2,464			$	3,368			$	4,075
Denominator-
Weighted average common shares outstanding			37,786				34,940				37,667				34,896
Basic EPS:
Income per share		$	0.09			$	0.07			$	0.09			$	0.12
Diluted EPS Computation:
Numerator-
Income		$	3,464			$	2,464			$	3,368			$	4,075
Denominator -
Weighted average common shares outstanding			37,786				34,940				37,667				34,896
Employee stock options			714				591				812				571
Warrants			269				107				284				105
Weighted average common shares for diluted earnings per share assuming conversion			38,769				35,638				38,763				35,572
Diluted EPS:
Income per share		$	0.09			$	0.07			$	0.09			$	0.11

NOTE 8. 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								Six Months Ended
		June 30,								June 30,
		2007				2006				2007				2006
		(in thousands)
Beginning asset retirement obligation		$	5,034			$	4,279			$	5,063			$	2,495
Additions related to new properties			48				83				66				191
Revisions in estimated cash flows			(55	)			(1	)			(167	)			1,663
Deletions related to property disposals			(265	)			(10	)			(284	)			(30	)
Accretion expense			80				69				164				101
Ending asset retirement obligation		$	4,842			$	4,420			$	4,842			$	4,420

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 June 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 are currently evaluating if we will elect the fair value option for any eligible financial instruments and other items.

NOTE 10. INVESTMENT IN GAS GATHERING SYSTEMS

     We had investments in three separate partnerships that construct pipeline systems for gathering natural gas, primarily on our leaseholds in the Barnett Shale area. These partnerships are 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 June 30, 2007, we had invested $299,000 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 June 30, 2007, we had invested $8.4 million in 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. We anticipate additional investments in Hagerman during 2007.

     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:

		June 30,				December 31,
		2007				2006
		($ in thousands)
West Fork Pipeline Company II, L.P.		$	299			$	280
Hagerman Gas Gathering System			8,409				6,174
		$	8,708			$	6,454

     Our loss from equity investments were as follows:

		Three Months Ended June 30,								Six Months Ended June 30,
		2007				2006				2007				2006
		($ in thousands)								($ in thousands)
West Fork Pipeline Company I, L.P.		$	—			$	28			$	—			$	26
West Fork Pipeline Company II, L.P.			2				(16	)			5				(21	)
West Fork Pipeline Company V, L.P.			—				(22	)			—				(34	)
Hagerman Gas Gathering System			(291	)			—				(599	)			—
		$	(289	)		$	(10	)		$	(594	)		$	(29	)

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

		June 30,				December 31,
		2007				2006
		($ in thousands)
Balance Sheet
Current assets		$	621			$	1,408
Non-current assets			11,155				8,361
Current liabilities			561				1,338
Owners’ equity			11,215				8,431

		Three Months Ended June 30,								Six Months Ended June 30,
		2007				2006				2007				2006
		($ in thousands)								($ in thousands)
Income Statement
Revenues		$	124			$	706			$	165			$	1,107
Costs and expenses			(378	)			(636	)			(808	)			(1,008	)
Net income (loss)		$	(254	)		$	70			$	(643	)		$	99

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 June 30, 2007 and 2006, Parallel had made contributions to the 401(k) Plan and Trust of approximately $134,000 and $113,000, 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. 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.

NOTE 12. SUBSEQUENT EVENTS

     Offering of 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 mature on August 1, 2014 and bear interest at 10.25% which is payable semi-annually beginning on February 1, 2008. 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. We have agreed to use our reasonable best efforts to exchange the senior notes for registered, freely tradable notes which otherwise have substantially identical terms to the senior notes within 210 days of July 31, 2007.

     The indenture governing the senior notes restricts our and our restricted subsidiaries, if any, 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 estimated net proceeds, after payment of typical transaction expenses, of approximately $143.0 million were used first to retire our second lien term loan with the remainder being applied to our revolving credit facility.

     Amendment to Revolving Credit Agreement

     On July 31, 2007, we entered into a Third Amendment to the Revolving Credit Agreement upon completing our senior notes offering. This Third Amendment amended the Revolving Credit Agreement by, among other things:

	•		reducing the borrowing base from $190.0 million to $150.0 million;
	•		providing that our ratio of Consolidated Funded Debt to Consolidated EBITDA (as defined in the Revolving Credit Agreement) shall not exceed (i) 4.25 to 1.00 during the year 2007; (ii) 4.00 to 1.00 during the year 2008, or (iii) 3.50 to 1.00 during the year 2009 and thereafter during the term hereof, in each case calculated at the end of each fiscal quarter using the results of the twelve-month period immediately preceding the end of each such fiscal quarter;
	•		allowing for the issuance and sale of the senior notes; and
	•		providing that an event of default under the senior notes will also constitute an event of default under the Revolving Credit Agreement.

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

     Our primary objective is to increase the 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 now emphasize reducing drilling risks by dedicating a smaller portion of our capital to high risk projects, while reserving the majority of our available capital for acquisition, exploitation, enhancement 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 we now focus primarily on established geologic trends where we can better utilize the engineering, operational, financial and technical expertise of our entire staff. Although we expect to continue participating in exploratory drilling activities in the future, reducing financial, reservoir, drilling and geological risks and diversifying our property portfolio are the principal criteria in the execution of our business plan. In summary, our current business plan:

•

focuses on projects having less geological risk;

	•		emphasizes acquisition, exploitation, development and enhancement activities;
	•		includes the utilization of horizontal and fracture stimulation technologies on certain types of reservoirs;
	•		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 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; and
	•		costs of capital.

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

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

     For the three months ended June 30, 2007 the sale price we received for our crude oil production (excluding hedges) averaged $59.24 per barrel compared with $63.17 per barrel for the three months ended June 30, 2006. The average sales price we received for natural gas for the three months ended June 30, 2007, was $6.79 per Mcf compared with $6.25 per Mcf for the three months ended June 30, 2006. For information regarding prices received including our hedges, refer to the selected operating data table in the Results of Operations on page 20. Hedge costs for oil were $3.3 million for the three months ended June 30, 2006. The ineffective portion showed a gain of approximately $52,000 for the three months ended June 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 the six months ended June 30, 2007, the sale price we received for our crude oil production (excluding hedges) averaged $55.56 per barrel compared with $60.56 per barrel for the six months ended

June 30, 2006. The average sales price we received for natural gas for the six months ended June 30, 2007, was $6.34 per Mcf compared with $6.42 per Mcf for the six months ended June 30, 2006. For information regarding prices received including our hedges, refer to the selected operating data table in the Results of Operations on page 20. Hedge costs for oil and natural gas was $6.0 million for the six months ended June 30, 2006. The ineffective portion showed a gain approximately $195,000 for the six months ended June 30, 2006. We settled all remaining derivatives classified as cash flow hedges in December 2006. Therefore, no ineffectiveness on hedges was identified in 2007.

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

     Depletion of the capitalized costs of oil and natural gas properties, including estimated future development costs, is provided using the equivalent unit-of-production method based upon estimates of proved oil and natural gas reserves and production, which are converted to a common unit of measure based upon their relative energy content. Unproved oil and natural gas properties are not amortized, but are individually assessed for impairment. The cost of any impaired property is transferred to the balance of oil and natural gas properties being depleted. Depletion per BOE at June 30, 2007 and 2006 was $12.73 and $9.74 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 six months ended June 30, 2007 and June 30, 2006.

		Three Months Ended								Six Months Ended
		6/30/2007				6/30/2006				6/30/2007				6/30/2006
		(in thousands, except per unit data)
Production Volumes:
Oil (Bbls)			270				298				543				566
Natural gas (Mcf)			1,679				1,726				3,200				2,893
BOE (1)			550				586				1,076				1,048
BOE per day			6.0				6.4				5.9				5.8
Sales Prices:
Oil (per Bbl) (2)		$	59.24			$	63.17			$	55.56			$	60.56
Natural gas (per Mcf) (2)		$	6.79			$	6.25			$	6.34			$	6.42
BOE price (2)		$	49.81			$	50.56			$	46.89			$	50.43
BOE price (3)		$	49.81			$	45.01			$	46.89			$	44.72
Operating Revenues
Oil		$	15,956			$	18,802			$	30,167			$	34,284
Oil hedge			—				(3,252	)			—				(5,985	)
Natural gas			11,398				10,792				20,303				18,586
		$	27,354			$	26,342			$	50,470			$	46,885
Operating Expenses:
Lease operating expense		$	5,576			$	3,741			$	9,975			$	7,316
Production taxes			1,194				1,468				2,248				2,578
Production tax refund			(1,209	)			—				(1,209	)			—
General and administrative:
General and administrative			1,768				1,523				3,412				2,657
Public reporting			812				1,090				1,833				2,085
Depreciation, depletion and amortization			7,150				6,140				13,859				10,428
		$	15,291			$	13,962			$	30,118			$	25,064
Operating income		$	12,063			$	12,380			$	20,352			$	21,821

RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED JUNE 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 June 30, 2007 and June 30, 2006.

Oil and Gas Revenues

		Revenues(1)								Production
		2007				2006				2007				2006
Oil (Bbls)			58	%			59	%			49	%			51	%
Natural gas (Mcf)			42	%			41	%			51	%			49	%
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 June 30,								Increase				% Increase
		2007				2006				(Decrease)				(Decrease)
		(in thousands except per unit data)
Production Volumes
Oil (Bbls)			270				298				(28	)			(9	)%
Natural gas (Mcf)			1,679				1,726				(47	)			(3	)%
BOE			550				586				(36	)			(6	)%
BOE/Day			6.0				6.4				(0.4	)			(6	)%
Sales Price
Oil (per Bbl)(1)		$	59.24			$	63.17			$	(3.93	)			(6	)%
Natural gas (per Mcf)(1)		$	6.79			$	6.25			$	0.54				9	%
BOE price(1)		$	49.81			$	50.56			$	(0.75	)			(1	)%
BOE price(2)		$	49.81			$	45.01			$	4.80				11	%
Operating Revenues
Oil		$	15,956			$	18,802			$	(2,846	)			(15	)%
Oil hedges			—				(3,252	)			3,252				100	%
Natural gas			11,398				10,792				606				6	%
Total		$	27,354			$	26,342			$	1,012				4	%

     Oil revenues, excluding hedges, decreased $2.8 million or 15% for the three months ended June 30, 2007 compared to the same period of 2006. The oil production decreased 9% attributable to a decline of approximately 17,000 Bbls, 13,000 Bbls, and 5,000 Bbls in the Carm-Ann, Diamond M and Fullerton areas, respectively, offset with an increase of approximately 16,000 Bbls from new wells drilled in the Harris area. The decrease in oil production decreased revenue approximately $1.8 million for 2007. Wellhead average realized crude oil prices decreased $3.93 Bbl or 6% to $59.24 per Bbl for 2007 compared to 2006. The decrease in oil price decreased revenue approximately $1.0 million for 2007.

     Natural gas revenues increased approximately $600,000 or 6% for the three months ended June 30, 2007 compared to the same period of 2006. Natural gas production decreased 3% attributable to a decline of approximately 378,000 Mcf in our south Texas wells and a decline of approximately 16,000

Mcf and 21,000 Mcf in the Carm-Ann and Diamond M Deep areas, respectively, offset by an increase in production attributable to new wells drilled in the New Mexico area with an increase of approximately 373,000 Mcf comparing three months ending June 30, 2007 to three months ending June 30, 2006. The decrease in natural gas volumes decreased revenue approximately $300,000 for 2007. Average realized wellhead natural gas prices increased 9% or $0.54 per Mcf to $6.79 per Mcf. The increase in natural gas prices had a positive effect on revenues of approximately $900,000 for the three months ending June 30, 2007.

     We settled all remaining derivatives classified as cash flow hedges in December 2006. Therefore, oil hedge losses were $0 for three months ending June 30, 2007 compared to a loss of $3.2 million for three months ending June 30, 2006. On a BOE basis, hedges accounted for a realized loss of $5.55 per BOE in 2006.

Cost and Expenses

		Three months ended June 30,								Increase				% Increase
		2007				2006				(Decrease)				(Decrease)
		(dollars in thousands)
Lease operating expense		$	5,576			$	3,741			$	1,835				49	%
Production taxes			1,194				1,468				(274	)			(19	)%
Production tax refund			(1,209	)			—				(1,209	)			N/A
General and administrative:
General and administrative			1,768				1,523				245				16	%
Public reporting			812				1,090				(278	)			(26	)%
Total general and administrative			2,580				2,613				(33	)			(1	)%
Depreciation, depletion and amortization			7,150				6,140				1,010				16	%
Total		$	15,291			$	13,962			$	1,329				10	%

     Lease operating costs increased approximately $1.8 million, or 49%, to $5.5 million during the three months ended June 30, 2007 compared with $3.7 million for the same period of 2006. The increase in lease operating expense is attributable to the increase of approximately $849,000 in the Permian Basin area primarily for lease and well repairs and workover expense; increase of approximately $268,000 primarily for workover expense and water disposal for new wells in the Barnett Shale area; and an increase of approximately $680,000 primarily for lease and well repairs, transportation, marketing and water disposal for new wells in our New Mexico area. Lifting costs (excluding production taxes) were $10.15 per BOE in 2007 compared to $6.38 per BOE in 2006 a 59% increase in our per BOE lifting costs.

     Production tax decreased 19% or $274,000 in 2007, associated with $2.8 million decrease in revenue. Production taxes in the future periods will be a function of product mix, production volumes and product prices.

     A production tax refund was received in June 2007 in the amount of $1.2 million for gas production taxes on non-operated wells in the Wilcox area of south Texas for production periods March 2005 through January 2007. These refunds were received by the operator of these wells only after the operator’s application for tax abatement was approved by state regulatory agencies. The reduction in our production tax expense was recognized only when approval of the application for tax abatement was granted by the state.

     Total general and administrative expenses in total decreased 1% or approximately $33,000 in 2007 compared to 2006. Included in our total general and administrative expenses is public reporting cost which decreased 26% or approximately $278,000. The decrease in total general and administrative costs is due to recognition of a cumulative adjustment for forfeited director stock options offset by an increase in employee compensation and related benefit costs. During the second quarter of 2006, we determined

that during 2003 approximately 30,000 options were awarded which were not available for issue under existing stock option plans. In June 2006, the Board of Directors approved a plan whereby these excess options would be repurchased for cash totaling approximately $511,000. This amount was charged to expense during the second quarter of 2006. General and administrative expenses capitalized to the full cost pool were $407,000 for 2007 compared to $413,000 in 2006. On a BOE basis, general and administrative costs were $3.22 per BOE in 2007 compared to $2.60 per BOE in 2006, while public reporting costs were $1.48 per BOE and $1.86 per BOE for the same period.

     Depreciation, depletion and amortization expense increased 16% or $1.0 million for 2007 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. Our drilling efforts over the past year and our future drilling plans are focused on our natural gas resource projects which have higher associated per BOE drilling and development costs than our drilling projects in the Permian Basin of west Texas and onshore gulf coast of south Texas 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 a significant increase in our depletion rate per BOE.

Other income (expense)

		Three months ended June 30,								Increase				% Increase
		2007				2006				(Decrease)				(Decrease)
		(dollars in thousands)
Loss on derivatives not classified as hedges		$	(2,170	)		$	(5,493	)		$	3,323				60	%
Gain on ineffective portion of hedges			—				52				(52	)			(100	)%
Interest and other income			56				25				31				124	%
Interest expense, net			(4,312	)			(3,158	)			(1,154	)			(37	)%
Other expense			21				(39	)			60				154	%
Equity in loss of pipelines and gathering system ventures			(289	)			(10	)			(279	)			(2,790	)%
Total		$	(6,694	)		$	(8,623	)		$	1,929				22	%

     We recorded a loss of $2.2 million in 2007 for derivatives not classified as hedges, as compared to a loss of $5.5 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 increased with the increase of our bank debt from $173.5 million at June 30, 2006 to $209.5 million at June 30, 2007 along with an increase of our weighted average loan interest rate for 2007. Interest expense will increase in 2007 with increased borrowings for leasehold acquisitions and amounts expended for drilling.

     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 June 30, 2007, the loss from the investment was approximately $290,000. 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 expense was $1.9 million in 2007 compared to $1.3 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.

     We had basic and diluted net income per share of $.09 and $.07 for 2007 and 2006, respectively. Basic weighted average common shares outstanding increased from 34.9 million shares in 2006 to 37.8 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.

RESULTS OF OPERATIONS FOR THE SIX MONTHS ENDED JUNE 30, 2007 AND 2006:

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

Oil and Gas Revenues

		Revenues(1)								Production
		2007				2006				2007				2006
Oil (Bbls)			60	%			60	%			50	%			54	%
Natural gas (Mcf)			40	%			40	%			50	%			46	%
Total			100	%			100	%			100	%			100	%

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

		Six Months Ended June 30,								Increase				% Increase
		2007				2006				(Decrease)				(Decrease)
		(in thousands except per unit data)
Production Volumes
Oil (Bbls)			543				566				(23	)			(4	)%
Natural gas (Mcf)			3,200				2,893				307				11	%
BOE			1,076				1,048				28				3	%
BOE/Day			5.9				5.8				0.1				3	%
Sales Price
Oil (per Bbl)(1)		$	55.56			$	60.56			$	(5.00	)			(8	)%
Natural gas (per Mcf)(1)		$	6.34			$	6.42			$	(0.08	)			(1	)%
BOE price(1)		$	46.89			$	50.43			$	(3.54	)			(7	)%
BOE price(2)		$	46.89			$	44.72			$	2.17				5	%
Operating Revenues
Oil		$	30,167			$	34,284				(4,117	)			(12	)%
Oil hedges			—				(5,985	)			5,985				100	%
Natural gas			20,303				18,586				1,717				9	%
Total		$	50,470			$	46,885			$	3,585				8	%