Edgar Filing: PARALLEL PETROLEUM CORP

e10vq

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 March 31, 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

(Registrant’s telephone number, including area code)

Not Applicable

(Former name, former address and former fiscal year,

if changed since last report)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

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

Large accelerated filer 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 May 3, 2007, 37,698,523 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 March 31, 2007 (unaudited) and December 31, 2006		1

- Unaudited Consolidated Statements of Operations for the three months ended March 31, 2007 and 2006		2

- Unaudited Consolidated Statements of Cash Flows for the three months ended March 31, 2007 and 2006		3

- Unaudited Consolidated Statements of Comprehensive Income (Loss) for the three months ended March 31, 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		30

ITEM 4. CONTROLS AND PROCEDURES		33

PART II. — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS		33

ITEM 1A. RISK FACTORS		33

ITEM 6. EXHIBITS		33

SIGNATURES
Certification of Principal Executive Officer Pursuant to Section 302
Certification of Principal Financial Officer Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906

(i)

PART I. – FINANCIAL INFORMATION

Item 1. Financial Statements

PARALLEL PETROLEUM CORPORATION

Consolidated Balance Sheets
(dollars in thousands)


	March 31,			December 31,
	2007			2006
	(unaudited)
Assets

Current assets:
Cash and cash equivalents	$	13,925		$	5,910

Accounts receivable:
Oil and natural gas sales		15,980			18,605
Joint interest owners and other, net of allowance for doubtful account of $80		6,050			7,209
Affiliates and joint ventures		2,585			3,338

		24,615			29,152

Other current assets		1,928			2,863
Deferred tax asset		5,375			4,340

Total current assets		45,843			42,265


Property and equipment, at cost:
Oil and natural gas properties, full cost method (including $66,656 and $50,375 not subject to depletion)		545,724			501,405
Other		2,646			2,614

		548,370			504,019
Less accumulated depreciation, depletion and amortization		(122,222	)		(115,513	)

Net property and equipment		426,148			388,506

Restricted cash		51			325
Investment in pipelines and gathering system ventures		7,808			6,454
Other assets, net of accumulated amortization of $1,289 and $760		4,429			5,268

	$	484,279		$	442,818

Liabilities and Stockholders’ Equity

Current liabilities:
Accounts payable and accrued liabilities	$	37,390		$	36,171
Asset retirement obligations		713			701
Derivative obligations		16,509			14,109

Total current liabilities		54,612			50,981


Revolving credit facility		154,000			115,000
Term loan		50,000			50,000
Asset retirement obligations		4,321			4,362
Derivative obligations		12,273			14,386
Deferred tax liability		25,295			24,307

Total long-term liabilities		245,889			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 37,547,010		375			375
Additional paid-in capital		140,445			140,353
Retained earnings		42,958			43,054

Total stockholders’ equity		183,778			183,782

	$	484,279		$	442,818

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

(1)

PARALLEL PETROLEUM CORPORATION

Consolidated Statements of Operations
For three months ended March 31, 2007 and 2006
(unaudited)
(dollars in thousands, except per share data)


	2007			2006
Oil and natural gas revenues:
Oil and natural gas sales	$	23,116		$	23,276
Loss on hedging		—			(2,733	)

Total revenues		23,116			20,543


Cost and expenses:
Lease operating expense		4,399			3,575
Production taxes		1,054			1,110
General and administrative		2,665			2,129
Depreciation, depletion and amortization		6,709			4,288


Total costs and expenses		14,827			11,102


Operating income		8,289			9,441


Other income (expense), net:
Loss on derivatives not classified as hedges		(4,435	)		(4,714	)
Gain on ineffective portion of hedges		—			143
Interest and other income		52			68
Interest expense		(3,708	)		(2,441	)
Other expense		(36	)		(29	)
Equity in loss of pipelines and gathering system ventures		(305	)		(19	)

Total other income (expense), net		(8,432	)		(6,992	)

Income (loss) before income taxes		(143	)		2,449
Income tax benefit (expense), deferred		47			(838	)

Net income (loss)	$	(96	)	$	1,611


Net income (loss) per common share:
Basic	$	—		$	0.05

Diluted	$	—		$	0.05


Weighted average common share outstanding:
Basic		37,547			34,850

Diluted		37,547			35,547

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

(2)

PARALLEL PETROLEUM CORPORATION

Consolidated Statements of Cash Flows
Three Months Ended March 31, 2007 and 2006
(unaudited)
(dollars in thousands)


	2007			2006
Cash flows from operating activities:
Net income (loss)	$	(96	)	$	1,611
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		6,709			4,288
Accretion of asset retirement obligation		84			31
Deferred income tax		(47	)		838
Loss on derivatives not classified as hedges		4,435			4,714
Gain on ineffective portion of hedges		—			(143	)
Stock option expense		92			388
Equity in loss in pipelines and gathering system ventures		305			19

Changes in assets and liabilities:
Other assets, net		(12	)		311
Restricted cash		274			—
Decrease in accounts receivable		4,537			427
Decrease in other current assets		292			107
Increase in accounts payable and accrued liabilities		1,219			1,671
Federal tax deposit		—			(40	)


Net cash provided by operating activities		17,792			14,222


Cash flows from investing activities:
Additions to oil and natural gas properties		(44,584	)		(55,035	)
Restricted cash		—			2,366
Proceeds from disposition of oil and natural gas properties		152			41
Additions to other property and equipment		(32	)		(1,461	)
Settlements on derivative instruments		(2,479	)		(1,548	)
Investment in pipelines and gathering system ventures		(1,659	)		(2,024	)


Net cash used in investing activities		(48,602	)		(57,661	)


Cash flows from financing activities:
Borrowings from bank line of credit		39,000			41,500
Deferred financing costs		(175	)		—
Proceeds from exercise of stock options		—			416


Net cash provided by financing activities		38,825			41,916


Net increase (decrease) in cash and cash equivalents		8,015			(1,523	)

Cash and cash equivalents at beginning of period		5,910			6,418


Cash and cash equivalents at end of period	$	13,925		$	4,895


Non-cash financing and investing activities:
Oil and natural gas properties asset retirement obligation	$	(113	)	$	1,752
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	$	3,875		$	2,082

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

(3)

PARALLEL PETROLEUM CORPORATION

Consolidated Statements of Comprehensive Income (Loss)
Three Months Ended March 31, 2007 and 2006
(unaudited)
(dollars in thousands)


	2007			2006
Net income (loss)	$	(96	)	$	1,611

Other comprehensive loss:
Unrealized losses on derivatives		—			4,142
Reclassification adjustments for losses on derivatives included in net income (loss)		—			(2,721	)

Change in fair value of derivatives		—			1,421
Income tax benefit (expense)		—			(483	)


Total other comprehensive income		—			938


Total comprehensive income (loss)	$	(96	)	$	2,549

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

(4)

PARALLEL PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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 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.

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 three months ended March 31, 2007 and 2006, Parallel recognized compensation expense of approximately $92,000 and $388,000, respectively, with a tax benefit of approximately $31,500 and $132,000, respectively, associated with our stock option grants.

(5)

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


	($ in thousands)
Second quarter 2007	$	137
Third quarter 2007		120
Fourth quarter 2007		99
2008		274
2009 through 2011		156

Total	$	786

Non-vested options outstanding were 207,500 as of March 31, 2007. During the three months ended March 31, 2007, options to purchase 17,500 shares of common stock were granted to one individual. No options were exercised, expired or forfeited.

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 March 31, 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 for the three months ended March 31, 2007 is presented below.


					Weighted
					Average
			Weighted		Remaining
			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		—	$	—
Surrendered		—	$	—
Outstanding March 31, 2007		1,216	$	5.65		4.6	$	21,036
Exercisable at March 31, 2007		1,008	$	4.32		3.6	$	18,787

(6)


	(in thousands)
Intrinsic Value of Options Exercised Three Months Ended March 31, 2007	$	—
Intrinsic Value of Options Exercised Three Months Ended March 31, 2006	$	1,552

Fair Market Value of Options Granted Three Months Ended March 31, 2007	$	218
Fair Market Value of Options Granted Three Months Ended March 31, 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

We have two separate credit facilities. Our Third Amended and Restated Credit Agreement, or “Revolving Credit Agreement”, with a group of bank lenders provides us with a revolving line of credit having a “borrowing base” limitation of $190.0 million at March 31, 2007. 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 March 31, 2007, the principal amount outstanding under our revolving credit facility was $154.0 million, excluding $445,000 reserved for our letters of credit. Our second credit facility is 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 March 31, 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.

Revolving Credit Facility

The 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 March 31, 2007, our weighted average base rate and LIBOR rate, plus the applicable margin, was 7.9% on $154.0 million, the outstanding principal amount of our revolving loan on that same date.

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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. We have also pledged our equity ownership interests in our subsidiaries, Parallel, L.P. and Parallel, L.L.C.

As of March 31, 2007 we were in compliance with all of the covenants in our Revolving Credit Agreement.

Second Lien Term Loan Facility

We also have 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, loans made to us under this credit facility bear interest, at our election, at an alternate base rate or a rate designated in the Agreement as the “LIBO” rate. The alternate base rate is 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 is 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 are also pledged to secure payment of our indebtedness under this facility, but the liens granted to the lender under the Second Lien Agreement are second and junior to the rights of the first lienholders under the Revolving Credit Agreement.

At March 31, 2007, our LIBO interest rate, plus the applicable margin, was 9.85% 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 is payable the last day of each March, June, September and December. In the case of LIBO loans, interest is 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 contains various restriction 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 is due and

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

As of March 31, 2007 we were in compliance with all of the covenants in our Second Lien Agreement.

Interest accrued for the three months ended March 31, 2007, for both of our credit facilities, was approximately $3.9 million. Of this amount, approximately $189,000 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. EQUITY INVESTMENT AND PROPERTY ACQUISITIONS

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

In March 2006, we purchased additional interests in our Barnett Shale gas project located in Tarrant County, Texas. The additional interests were acquired from five unaffiliated parties for a total cash purchase price of approximately $5.5 million.

In a subsequent closing in April 2006, we acquired an additional interest in the Barnett Shale gas project located in Tarrant County, Texas from one other unaffiliated third party for approximately $573,000.

The table below reflects our actual consolidated results of operations for the three months ended March 31, 2007, compared to the consolidated pro forma results of operations for the three months ended March 31, 2006, assuming the 2006 acquisitions were consummated on January 1, 2006.


	Three Months Ended
	March 31,
	Actual			Pro Forma
	2007			2006
	($ in thousands, except per share data
Oil and natural gas sales, net of hedge losses	$	23,116		$	21,056
Operating income	$	8,289		$	9,764
Net income (loss)	$	(96	)	$	1,743

Net income (loss) per common share:
Basic	$	—		$	0.05
Diluted	$	—		$	0.05

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NOTE 6. FULL COST CEILING TEST

We use the full cost method to account for our oil and natural gas producing activities. Under the full cost method of accounting, the net book value of oil and natural gas properties, less related deferred income taxes, may not exceed a calculated “ceiling”. The ceiling limitation is the discounted estimated after-tax future net cash flows from proved oil and natural gas properties. 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 three month periods ended March 31, 2007 and 2006, overhead costs capitalized were approximately $318,000 and $440,000, respectively.

NOTE 7. DERIVATIVE INSTRUMENTS

General

We enter into derivative contracts to provide a measure of stability in the cash flows associated with our oil and natural gas production and interest rate payments and to manage exposure to commodity price and interest rate risk. Our objective is to lock in a range of oil and natural gas prices and to limit variability in our cash interest payments. Our line of credit agreement as of March 31, 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.

We designated all of our interest rate swaps and commodity swaps entered into in 2002 through June 30, 2004 as cash flow hedges (“hedges”). The effective portion of the unrealized gain or loss on cash flow hedges was recorded in other comprehensive income (loss) when the forecasted transaction occurred. During the term of the cash flow hedge, the effective portion of the quarterly change in the fair value of the derivatives was recorded in stockholders’ equity as other comprehensive income (loss) and was transferred to oil and natural gas revenues when the production was sold and interest expense when the interest accrued. Ineffective portions of hedges (changes in fair value resulting from changes in realized prices that do not match the changes in the hedge or reference price) were recognized in gain (loss) on ineffective portion of hedges as they occurred.

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.

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Interest Rate Sensitivity

We completed a fixed interest rate swap contracts with BNP Paribas, based on the 90-day LIBOR rates at the time of the contracts. 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 March 31, 2007, the fair market value of these interest rate swaps was approximately $83,000.

The table below recaps the nature of these interest rate swaps and the fair market value of these contracts as of March 31, 2007.


	Notional		Weighted Average			Estimated
Period of Time	Amounts		Fixed Interest Rates			Fair Market Value
	($ in millions)					($ in thousands)
April 1, 2007 thru December 31, 2007	$	100		4.62	%	$	487
January 1, 2008 thru December 31, 2008	$	100		4.86	%		(137	)
January 1, 2009 thru December 31, 2009	$	50		5.06	%		(162	)
January 1, 2010 thru October 31, 2010	$	50		5.15	%		(105	)

Total Fair Market Value						$	83

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.

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A summary of our collar positions at March 31, 2007 is as follows:


									Houston Ship				WAHA Gas
	Barrels of		NyMex Oil Prices				MMBtu of		Channel Gas Prices				Prices				Fair Market
Period of Time	Oil		Floor		Cap		Natural Gas		Floor		Cap		Floor		Cap		Value
																	($ in
																	thousands)
April 1, 2007 thru December 31, 2007		220,000	$	55.63	$	84.88		—	$	—	$	—	$	—	$	—		45
April 1, 2007 thru October 31, 2007		—	$	—	$	—		214,000	$	6.00	$	11.05	$	—	$	—		(7	)
April 1, 2007 thru October 31, 2007		—	$	—	$	—		642,000	$	—	$	—	$	6.25	$	8.90		(57	)
April 1, 2007 thru March 31, 2008		—	$	—	$	—		2,196,000	$	—	$	—	$	6.50	$	9.50		(440	)
January 1, 2008 thru December 31, 2008		237,900	$	60.38	$	81.08		—	$	—	$	—	$	—	$	—		89
January 1, 2009 thru December 31, 2009		620,500	$	63.53	$	80.21		—	$	—	$	—	$	—	$	—		1,092
January 1, 2010 thru October 31, 2010		486,400	$	63.44	$	78.26		—	$	—	$	—	$	—	$	—		987

Total Fair Market Value																	$	1,709

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)
April 1, 2007 thru December 31, 2007		357,500	$	34.36	$	(12,020	)
January 1, 2008 thru December 31, 2008		439,200	$	33.37		(15,034	)

Total fair market value					$	(27,054	)

NOTE 8. NET INCOME (LOSS) PER COMMON SHARE

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

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The following table provides the computation of basic and diluted earnings per share for the three months ended March 31, 2007 and 2006:


	Three Months Ended March 31,
	2007			2006
	($ in thousands, except per
	share data)
Basic EPS Computation:
Numerator-
Net income (loss)	$	(96	)	$	1,611


Denominator-
Weighted average common shares outstanding		37,547			34,850


Basic EPS:
Net income (loss) per share	$	—		$	0.05


Diluted EPS Computation:
Numerator-
Net income (loss)	$	(96	)	$	1,611


Denominator -
Weighted average common shares outstanding		37,547			34,850
Employee stock options		—			594
Warrants		—			103

Weighted average common shares for diluted earnings per share assuming conversion		37,547			35,547

Diluted EPS:
Net income (loss) per share	$	—		$	0.05

Stock options to purchase approximately 1.2 million shares of common stock and warrants to purchase approximately 400,000 shares of common stock, which were outstanding as of March 31, 2007, were not included in the computation of diluted income (loss) per share because we had a net loss from continuing operations and therefore, the effect would be antidilutive.

NOTE 9. ASSET RETIREMENT OBLIGATIONS

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

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The following table summarizes our asset retirement obligation transactions:


	Three Months Ended March 31,
	2007			2006
	($ in thousands)
Beginning asset retirement obligation	$	5,063		$	2,495
Additions related to new properties		18			107
Revisions in estimated cash flows		(112	)		1,665
Deletions related to property disposals		(19	)		(20	)
Accretion expense		84			32

Ending asset retirement obligation	$	5,034		$	4,279

NOTE 10. 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 March 31, 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.

NOTE 11. INVESTMENT IN GAS GATHERING SYSTEM

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 have been recorded as equity investments in the accompanying consolidated balance sheet. In the fourth quarter 2006, substantially all of the assets of West Fork Pipeline I and West Fork Pipeline V were sold. As of March 31, 2007, we had invested $290,000 in West Fork Pipeline II.

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West Fork Pipeline II is currently acquiring the necessary easements and permits to begin transmission of natural gas.

As of March 31, 2007, we had invested $7.5 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:


	March 31,		December 31,
	2007		2006
	($ in thousands)
West Fork Pipeline Company II, L.P.		290		280
Hagerman Gas Gathering System		7,518		6,174

	$	7,808	$	6,454

Our loss from equity investments were as follows:


	Three Months Ended March 31,
	2007			2006
	($ in thousands)
West Fork Pipeline Company I, L.P.	$	—		$	(2	)
West Fork Pipeline Company II, L.P.		3			(5	)
West Fork Pipeline Company V, L.P.		—			(12	)
Hagerman Gas Gathering System		(308	)		—

	$	(305	)	$	(19	)

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


	March 31,		December 31,
	2007		2006
	($ in thousands)
Balance Sheet

Current assets	$	400	$	1,408
Non-current assets		10,010		8,361
Current liabilities		349		1,338
Owners’ equity		10,061		8,431


	Three Months Ended March 31,
	2007			2006
	($ in thousands)
Income Statement

Revenues	$	41		$	401
Costs and expenses		(430	)		(372	)

Net income (loss)	$	(389	)	$	29

NOTE 12. 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 March 31, 2007 and 2006, Parallel had made contributions to the 401(k) Plan and Trust of approximately $67,000 and $56,000, respectively.

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

The following discussion and analysis should be read in conjunction with management’s discussion and analysis contained in our 2006 Annual Report on Form 10-K, as well as the unaudited consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.

OVERVIEW

Strategy

Our primary objective is to increase shareholder value of our common stock through increasing reserves, production, cash flow and earnings. We have shifted the balance of our investments from properties having high rates of production in early years to properties expected to produce more

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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.

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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 March 31, 2007, the sale price we received for our crude oil production (excluding hedges) averaged $51.93 per barrel compared with $53.93 per barrel for the three months ended December 31, 2006 and $57.66 per barrel for the three months ended March 31, 2006. The average sales price we received for natural gas for the three months ended March 31, 2007, was $5.86 per Mcf compared with $6.43 per Mcf for the three months ended December 31, 2006 and $6.68 per Mcf for the three months ended March 31, 2006. For information regarding prices received including our hedges, refer to the selected operating data table under the caption “Results of Operations” on page 20. Hedge costs for oil were $2.2 million and $2.7 million for the three months ended December 31, 2006 and March

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31, 2006, respectively. The ineffective portion of our hedges showed a gain of approximately $143,000 for the three months ended March 31, 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 March 31, 2007 and 2006 was $12.57 and $9.02 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 months ended March 31, 2007, December 31, 2006, and March 31, 2006.

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	Three Months Ended
	3/31/2007		12/31/2006			3/31/2006
	(in thousands, except per unit data)
Production Volumes:
Oil (Bbls)		273		289			268
Natural gas (Mcf)		1,521		1,645			1,167
BOE⁽¹⁾		527		563			463
BOE per day		5.9		6.1			5.1

Sales Prices:
Oil (per Bbl)⁽²⁾	$	51.93	$	53.93		$	57.66
Natural gas (per Mcf)⁽²⁾	$	5.86	$	6.43		$	6.68
BOE price⁽²⁾	$	43.85	$	46.46		$	50.27
BOE price⁽³⁾	$	43.85	$	42.47		$	44.37

Operating Revenues:
Oil	$	14,211	$	15,598		$	15,482
Oil hedge		—		(2,248	)		(2,733	)
Natural gas		8,905		10,579			7,794

	$	23,116	$	23,929		$	20,543


Operating Expenses:
Lease operating expense	$	4,399	$	4,180		$	3,575
Production taxes		1,054		1,461			1,110
General and administrative:
General and administrative		1,644		1,649			1,134
Public reporting		1,021		727			995
Depreciation, depletion and amortization		6,709		6,839			4,288

	$	14,827	$	14,856		$	11,102


Operating income	$	8,289	$	9,073		$	9,441

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

(2) Excludes hedge transactions.

(3) Includes hedge transactions.

RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED MARCH 31, 2007 AND 2006:

Our oil and natural gas revenues and production product mix are displayed in the following table for the three months ended March 31, 2007 and March 31, 2006.

Oil and Gas Revenues


	Revenues						Production
	2007			2006			2007			2006
Oil (Bbls)		61	%		62	%		52	%		58	%
Natural gas (Mcf)		39	%		38	%		48	%		42	%

Total		100	%		100	%		100	%		100	%

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


	Three Months Ended March 31,					Increase			% Increase
	2007		2006			(Decrease)			(Decrease)
	(in thousands except per unit data)
Production Volumes
Oil (Bbls)		273		268			5			2	%
Natural gas (Mcf)		1,521		1,167			354			30	%
BOE		527		463			64			14	%

Sales Price
Oil (per Bbl)⁽¹⁾	$	51.93	$	57.66		$	(5.73	)		(10	)%
Natural gas (per Mcf)⁽¹⁾	$	5.86	$	6.68		$	(0.82	)		(12	)%
BOE price⁽¹⁾	$	43.85	$	50.27		$	(6.42	)		(13	)%
BOE price⁽²⁾	$	43.85	$	44.37		$	(0.52	)		(1	)%

Operating Revenues
Oil	$	14,211	$	15,482		$	(1,271	)		(8	)%
Oil hedges		—		(2,733	)		2,733			100	%
Natural gas		8,905		7,794			1,111			14	%

Total	$	23,116	$	20,543		$	2,573			13	%


⁽¹⁾		Excludes hedge transactions.

⁽²⁾		Includes hedge transactions.

Oil revenues, excluding hedges, decreased $1.3 million or 8% for the three months ended March 31, 2007 compared to the same period of 2006. The oil production increase was primarily attributable to new wells in the Harris and New Mexico areas increasing volumes approximately 23,000 Bbls and 4,000 Bbls, respectively, offset partially by reduced production of approximately 10,000 Bbls, 6,000 Bbls and 4,000 Bbls in the Diamond M, Wilcox and Fullerton areas, respectively, when comparing the first quarter 2007 to first quarter 2006. The increase in oil production increased revenue approximately $290,000 for 2007. Wellhead average realized crude oil prices decreased $5.73 per Bbl or 10% to $51.93 per Bbl for 2007 compared to 2006. The decrease in oil price decreased revenue approximately $1.6 million for 2007.

Natural gas revenues increased $1.1 million or 14% for the three months ended March 31, 2007 compared to the same period of 2006. The natural gas production increase was attributable to new wells drilled in the New Mexico and Barnett Shale areas with an increase of approximately 468,000 Mcf and 279,000 Mcf, respectively, offset by a decline of approximately 393,000 Mcf in our south Texas wells when comparing first quarter 2007 to first quarter 2006. The increase in natural gas volumes increased revenue approximately $2.4 million for 2007. Average realized wellhead natural gas prices decreased 12% or $0.82 per Mcf to $5.86 per Mcf. The decrease in natural gas prices had a negative effect on revenues of approximately $1.2 million for the three months ending March 31, 2007.

We settled all remaining derivatives classified as cash flow hedges in December 2006. Therefore, oil hedge losses were $0 in 2007 compared to a loss of $2.7 million in 2006. On a BOE basis, hedges accounted for a realized loss of $5.90 per BOE in 2006.

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Cost and Expenses


	Three months ended March 31,				Increase			% Increase
	2007		2006		(Decrease)			(Decrease)
			($ in thousands)
Lease operating expense	$	4,399	$	3,575	$	824			23	%
Production taxes		1,054		1,110		(56	)		(5	)%
General and administrative:
General and administrative		1,644		1,134		510			45	%
Public reporting		1,021		995		26			3	%

Total general and administrative		2,665		2,129		536			25	%

Depreciation, depletion and amortization		6,709		4,288		2,421			56	%

Total	$	14,827	$	11,102	$	3,725			34	%

Lease operating costs increased approximately $824,000, or 23%, to $4.4 million during the three months ended March 31, 2007 compared with $3.6 million for the same period of 2006. The increase in lease operating expense is due to mechanical, ad valorem and utility costs which increased our related lifting costs (excluding production taxes) to $8.34 per BOE in 2007, as compared to $7.72 per BOE in 2006, an 8% increase in our per BOE lifting costs.

General and administrative expenses increased 25% or $536,000 in 2007 compared to 2006. Included in our total general and administrative expenses is public reporting cost which increased 3% or $26,000 for 2007. The increase in general and administrative costs is due to compensation costs and consultation fees. General and administrative expenses capitalized to the full cost pool were approximately $318,000 for 2007 and approximately $440,000 for 2006. On a BOE basis, general and administrative costs were $3.12 per BOE in 2007 compared to $2.45 per BOE in 2006, while public reporting costs were $1.94 per BOE and $2.15 per BOE for the same periods.

Depreciation depletion and amortization expense increased 56% or $2.4 million for 2007 compared to 2006. Depletion per BOE was $12.57 for 2007 and $9.02 for 2006. This increase is attributable to an overall increase in actual and anticipated drilling 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 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 due to the nature of the wellbores. 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.

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Other income (expense)


	Three months ended March 31,						Increase			% Increase
	2007			2006			(Decrease)			(Decrease)
				($ in thousands)
Loss on derivatives not classified as hedges	$	(4,435	)	$	(4,714	)	$	279			6	%
Gain on ineffective portion of hedges		—			143			(143	)		(100	)%
Interest and other income		52			68			(16	)		(24	)%
Interest expense		(3,708	)		(2,441	)		(1,267	)		52	%
Other expense		(36	)		(29	)		(7	)		24	%
Equity in loss of pipelines and gathering system ventures		(305	)		(19	)		(286	)		1505	%

Total	$	(8,432	)	$	(6,992	)	$	(1,440	)		21	%

We recorded a loss of $4.4 million in 2007 for derivatives not classified as hedges, as compared to a loss of $4.7 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.

The ineffective portion of our hedges was a gain of approximately $143,000 in 2006. As of December 31, 2006, all remaining cash flow hedge contracts, as defined by SFAS 133, had been settled.

Interest expense increased with the increase in our bank debt from $141.5 million as of March 31, 2006 to $204.0 million as of March 31, 2007, along with an increase of our 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 March 31, 2007, the loss from the investment was approximately $308,000. 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 benefit was $47,000 in 2007 compared to an expense of $838,000 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 (loss) per share of $0.00 and $0.05 for 2007 and 2006, respectively. Basic weighted average common shares outstanding were approximately 37.5 million shares for 2007 and approximately 34.9 million 2006. The outstanding stock options and warrants to purchase approximately 1.2 million and 400,000 shares of common stock, respectively, were not included in the computation of diluted income (loss) per share for the first quarter 2007 because we had a net loss and the effect would be antidilutive.

LIQUIDITY AND CAPITAL RESOURCES

Our capital resources consist primarily of cash flows from our oil and natural gas properties and bank borrowings supported by our oil and natural gas reserves. Our level of earnings and cash flows depends on many factors, including the prices we receive for oil and natural gas we produce.

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Working capital decreased approximately $53,000 as of March 31, 2007 compared with December 31, 2006. Current liabilities exceeded current assets by $8.8 million at March 31, 2007. The working capital decrease was due to the increase in cash and cash equivalents of $8.0 million, offset by a decrease in accounts receivable of approximately $4.5 million, an increase in accounts payable of approximately $1.2 million and an increase in current derivative obligations of $2.4 million.

We incurred net property costs of $46.1 million for the three months ended March 31, 2007 compared to $56.1 million for the same period in 2006. Included in our increased property basis for the first quarter of 2007 and 2006 were net asset retirement costs of approximately $(113,000) and $1.7 million, respectively (see Note 9 to Consolidated Financial Statements). Our property leasehold acquisition, development and enhancement activities were financed by our revolving credit facility, the utilization of cash flows provided by operations, cash on hand and bank borrowings.

Stockholders’ equity at March 31, 2007 was $183.7 million, as compared to $183.8 million at December 31, 2006. The decrease is primarily attributable to our net loss of approximately $96,000.

Our capital investment budget will be funded from our estimated operating cash flows and our bank borrowings. If our cash flows and bank borrowings are not sufficient to fund all of our estimated capital expenditures, we may fund any shortfall with proceeds from the sale of our debt or equity securities, reduce our capital budget or effect a combination of these alternatives. The amount and timing of our expenditures are subject to change based upon market conditions, results of expenditures, new opportunities and other factors.

Bank Borrowings

Revolving Credit Facility

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

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

As of March 31, 2007 we were in compliance with all of the covenants in our Revolving Credit Agreement.

Second Lien Term Loan Facility

We also have 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, loans made to us under this credit facility bear interest, at our election, at an alternate base rate or a rate designated in the Second Lien Agreement as the “LIBO” rate. The alternate base rate is 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.

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

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At March 31, 2007, our LIBO interest rate, plus the applicable margin, was 9.85% on $50.0 million, the outstanding principal amount of our term loan on that same date.

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

As of March 31, 2007 we were in compliance with all of the covenants in our Second Lien Agreement.

Interest accrued for the three months ended March 31, 2007, for both of our credit facilities, was approximately $3.9 million. Of this amount, approximately $189,000 was capitalized.

Commodity Price Risk Management Transactions and Effects of Derivative Instruments

The purpose of our derivative transactions is to provide a measure of stability in our cash flows. The derivative trade arrangements we have employed include collars, costless collars, floors or purchased puts, and oil, natural gas and interest rate swaps. In 2003, we designated our derivative trades as cash flow hedges under the provisions of SFAS 133, as amended. Although our purpose for entering into derivative trades has remained the same, contracts entered into after June 30, 2004 have not been designated as cash flow hedges.

At December 31, 2006, we had no derivatives in place that were designated as cash flow hedges. All commodity derivative contracts at December 31, 2006 were accounted for by “mark-to-market” accounting whereby changes in fair value were charged to earnings. Changes in the fair values of derivatives are recorded in our Consolidated Statements of Operations as these changes occur in “Other income (expense), net”. To the extent these trades relate to production in 2007 and beyond, and oil prices increase, we will report a loss currently, but if there are no further changes in prices, our revenue will be correspondingly higher (than if there had been no price increase) when the production is sold.

All interest rate swaps that we have entered into for 2007 and beyond are accounted for by “mark-to-market” accounting as prescribed in SFAS 133.

We are exposed to credit risk in the event of nonperformance by the counterparties to our derivative trade instruments. However, we periodically assess the creditworthiness of the counterparties to mitigate this credit risk.

Certain of our commodity price risk management arrangements have required us to deliver cash collateral or other assurances of performance to the counterparties in the event that our payment obligations with respect to our commodity price risk management transactions exceed certain levels.

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Contractual Obligations, Commitments and Off-Balance Sheet Arrangements

We have contractual obligations and commitments that may affect our financial position. However, based on our assessment of the provisions and circumstances of our contractual obligations and commitments, we do not believe that these obligations and commitments will materially adversely affect our consolidated results of operations, financial condition or liquidity.

The following table is a summary of significant contractual obligations as of March 31, 2007:


	Obligation Due in Period
	Periods ended December 31,										After
Contractual Cash Obligations	2007		2008		2009		2010		2011		5 years		Total
	($ in thousands)
Revolving Credit Facility (secured)⁽¹⁾	$	9,141	$	11,182	$	12,133	$	164,105	$	—	$	—	$	196,561
Term Loan Facility (secured)⁽²⁾		3,711		4,925		4,925		54,304		—		—		67,865
Office Lease (Dinero Plaza)		154		210		216		36		—		—		616
Andrews and Snyder Field Offices⁽³⁾		17		14		14		14		14		539		612
Asset retirement obligations⁽⁴⁾		556		201		118		40		54		4,065		5,034
Derivative Obligations		12,170		15,862		432		317		—		—		28,781
Drilling Contract		542		—		—		—		—		—		542

Total	$	26,291	$	32,394	$	17,838	$	218,816	$	68	$	4,604	$	300,011


⁽¹⁾		Outstanding principal of $154.0 million due October 31, 2010 and estimated interest obligation calculated using the weighted average rate at March 31, 2007 of 7.9%

⁽²⁾		Outstanding principal of $50.0 million due November 15, 2010 and estimated interest obligation calculated using the LIBO rate at M arch 31, 2007 of 9.85%

⁽³⁾		The Snyder office lease expires upon the cessation of production from the Diamond “M “ area wells. The Andrews office lease expires in December 2007. The lease cost for these two office facilities are billed to nonaffiliated third party working interest owners under our joint operating agreements with these third parties.

⁽⁴⁾		Asset retirement obligations of oil and natural gas assets, excluding salvage value and accretion.

Outlook

The oil and natural gas industry is capital intensive. We make, and anticipate that we will continue to make, substantial capital expenditures in the exploration for, development and acquisition of oil and natural gas reserves. Historically, our capital expenditures have been financed primarily with:

	•		internally generated cash from operations;

	•		proceeds from bank borrowings; and

	•		proceeds from sales of equity securities.

The continued availability of these capital sources depends upon a number of variables, including:

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	•		our proved reserves;

	•		the volumes of oil and natural gas we produce from existing wells;

	•		the prices at which we sell oil and natural gas; and

	•		our ability to acquire, locate and produce new reserves.

Each of these variables materially affects our borrowing capacity. We may from time to time seek additional financing in the form of:

	•		increased bank borrowings;

	•		sales of our debt or equity securities;

	•		sales of non-core properties; or

	•		other forms of financing.

Except for the revolving credit facility we have with our bank lenders, we do not currently have any agreements for any future financing and there can be no assurance as to the availability or terms of any such future financing.

Inflation

Our drilling and production costs have escalated and we expect this trend to continue.

Critical Accounting Policies

Our critical accounting policies are included and discussed in our Annual Report on Form 10-K for the year ended December 31, 2006, as filed with the Securities and Exchange Commission on February 28, 2007. These critical accounting policies should be read in conjunction with the financial statements and the accompanying notes and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” also included in our Annual Report on Form 10-K for the year ended December 31, 2006.

TRENDS AND PRICES

Changes in oil and natural gas prices significantly affect our revenues, cash flows and borrowing capacity. Markets for oil and natural gas have historically been, and will continue to be, volatile. Prices for oil and natural gas typically fluctuate in response to relatively minor changes in supply and demand, market uncertainty, seasonal, political and other factors beyond our control. We are unable to accurately predict domestic or worldwide political events or the effects of other such factors on the prices we receive for our oil and natural gas.

Our capital expenditure budgets are highly dependent on future oil and natural gas prices.

During fiscal year 2006 the average realized sales price for our oil and natural gas was $48.73 (unhedged) per BOE. For the three months ended March 31, 2007, our average realized price was $43.85 (unhedged) per BOE.

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FORWARD-LOOKING STATEMENTS

Cautionary Statement Regarding Forward-Looking Statements

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

	•		our future financial and operating performance and results;

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

	•		production volumes;

	•		our business strategy;

	•		market prices;

	•		sources of funds necessary to conduct operations and complete acquisitions;

	•		development costs;

	•		number and location of planned wells;

	•		our future commodity price risk management activities; and

	•		our plans and forecasts.

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

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

	•		fluctuations in prices of oil and natural gas;

	•		dependent on key personnel;

	•		reliance on technological development and technology development programs;

	•		demand for oil and natural gas;

	•		losses due to potential or future litigation;

	•		future capital requirements and availability of financing;

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	•		geological concentration of our reserves;

	•		risks associated with drilling and operating wells;

	•		competition;

	•		general economic conditions;

	•		governmental regulations and liability for environmental matters;

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

	•		hedging decisions, including whether or not to hedge;

	•		events similar to 911;

	•		actions of third party co-owners of interests in properties in which we also own an interest; and

	•		fluctuations in interest rates and availability of capital.

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

Before you invest in our common stock, you should be aware that there are various risks associated with an investment. We have described some of these risks under “Risks Related to Our Business” beginning on page 13 of our Form 10-K for the year ended December 31, 2006.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The following quantitative and qualitative information is provided about market risks and derivative instruments to which we were a party at March 31, 2007, and from which we may incur future earnings, gains or losses from changes in market interest rates and oil and natural gas prices.

Interest Rate Sensitivity as of March 31, 2007

Our only financial instruments sensitive to changes in interest rates are our bank debt and interest rate swaps. As the interest rate is variable and reflects current market conditions, the carrying value of our bank debt approximates the fair value. The table below shows principal cash flows and related weighted average interest rates by expected maturity dates. Weighted average interest rates were determined using weighted average interest paid and accrued in March, 2007. You should read Note 3 to the Consolidated Financial Statements for further discussion of our debt that is sensitive to interest rates.

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	2007			2008			2009			2010			2011			Total
	($ in thousands, except interest rates)
Revolving Credit Facility (secured)	$	—		$	—		$	—		$	—		$	154,000		$	154,000
Weighted average interest rate		7.90	%		7.90	%		7.90	%		7.90	%		7.90	%
Second Lien Term Loan Facility (secured)	$	—		$	—		$	—		$	—		$	50,000		$	50,000
Average interest rate		9.85	%		9.85	%		9.85	%		9.85	%		9.85	%

At March 31, 2007, we had outstanding bank loans in the aggregate principal amount of $204.0 million at a weighted average interest rate of 8.4%. Under our revolving credit facility, we may elect an interest rate based upon the agent bank’s base lending rate or the LIBOR rate, plus a margin ranging from 2.25% to 2.75% per annum, depending upon the outstanding principal amount of the loans. The interest rate we are required to pay, including the applicable margin, may never be less than 5.00%. Under our second lien term loan facility, we may elect an interest rate based upon an alternate base rate, or the LIBO rate, plus a margin of 4.50%.

We completed fixed interest rate swap contracts with BNP Paribas, based on the 90-day LIBOR rates at the time of the contracts. 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 March 31, 2007, the fair market value of these interest rate swaps was approximately $83,000.

A recap for the period of time, notional amounts, fixed interest rates, and fair market value of these contracts at March 31, 2007 follows:


	Notional		Weighted Average			Estimated
Period of Time	Amounts		Fixed Interest Rates			Fair Market Value
	($ in millions)					($ in thousands)
April 1, 2007 thru December 31, 2007	$	100		4.62	%	$	487
January 1, 2008 thru December 31, 2008	$	100		4.86	%		(137	)
January 1, 2009 thru December 31, 2009	$	50		5.06	%		(162	)
January 1, 2010 thru October 31, 2010	$	50		5.15	%		(105	)

Total Fair Market Value						$	83

Commodity Price Sensitivity as of March 31, 2007

Our major market risk exposure is the pricing applicable to our oil and natural gas production. Market risk refers to the risk of loss from adverse changes in oil and natural gas prices. Realized pricing is primarily driven by the prevailing domestic price for crude oil and spot prices applicable to the region in which we produce natural gas. Historically, prices received for oil and natural gas production have been volatile and unpredictable. We expect pricing volatility to continue. Oil prices ranged from a low of $51.65 per barrel to a high of $73.03 per barrel during 2006. Natural gas prices we received during 2006 ranged from a low of $1.00 per Mcf to a high of $15.11 per Mcf. During the first quarter ended March

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31, 2007 oil prices ranged from a low of $47.62 to a high of $60.81. Natural gas prices we received during the first quarter ended March 31, 2007 ranged from a low of $1.64 per Mcf to a high of $11.22 per Mcf. A significant decline in the prices of oil or natural gas could have a material adverse effect on our financial condition and results of operations.

We employ various derivative instruments in order to minimize our exposure to the aforementioned commodity price volatility. As of March 31, 2007, we had employed costless collars, collars, and swaps in order to protect against this price volatility. Although all of the contracts that we have entered into are viewed as protection against this price volatility, all contracts are accounted for by the “mark-to-market” accounting method as prescribed in SFAS 133.

A description of our active commodity derivative contracts as of March 31, 2007 follows:

A summary of our collar positions at March 31, 2006 is as follows:


									Houston Ship				WAHA Gas
	Barrels of		NyMex Oil Prices				MMBtu of		Channel Gas Prices				Prices				Fair Market
Period of Time	Oil		Floor		Cap		Natural Gas		Floor		Cap		Floor		Cap		Value
																	($ in
																	thousands)
April 1, 2007 thru December 31, 2007		220,000	$	55.63	$	84.88		—	$	—	$	—	$	—	$	—		45
April 1, 2007 thru October 31, 2007		—	$	—	$	—		214,000	$	6.00	$	11.05	$	—	$	—		(7	)
April 1, 2007 thru October 31, 2007		—	$	—	$	—		642,000	$	—	$	—	$	6.25	$	8.90		(57	)
April 1, 2007 thru March 31, 2008		—	$	—	$	—		2,196,000	$	—	$	—	$	6.50	$	9.50		(440	)
January 1, 2008 thru December 31, 2008		237,900	$	60.38	$	81.08		—	$	—	$	—	$	—	$	—		89
January 1, 2009 thru December 31, 2009		620,500	$	63.53	$	80.21		—	$	—	$	—	$	—	$	—		1,092
January 1, 2010 thru October 31, 2010		486,400	$	63.44	$	78.26		—	$	—	$	—	$	—	$	—		987

Total Fair Market Value																	$	1,709

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We have entered into oil swap contracts with BNP Paribas. A recap for the period of time, number of barrels, swap prices and fair market values as of March 31, 2007 for these swaps follows:


			Nymex Oil		Fair Market
Period of Time	Barrels of Oil		Swap Price		Value
					($ in thousands)
April 1, 2007 thru December 31, 2007		357,500	$	34.36	$	(12,020	)
January 1, 2008 thru December 31, 2008		439,200	$	33.37		(15,034	)

Total fair market value					$	(27,054	)

ITEM 4. CONTROLS AND PROCEDURES

As of the end of the period covered by this Quarterly Report on Form 10-Q, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended) was evaluated by our management, with the participation of our Chief Executive Officer, Larry C. Oldham (principal executive officer), and our Chief Financial Officer, Steven D. Foster (principal financial officer), in accordance with rules under the Securities Exchange Act of 1934, as amended. Based on that evaluation, Mr. Oldham and Mr. Foster have concluded that our disclosure controls and procedures were effective as of March 31, 2007 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934, as amended, is accumulated and communicated to management and recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

There were no changes in our internal control over financial reporting that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

ITEM 1A. RISK FACTORS

There have been no material changes from the risk factors as previously disclosed in our Form 10-K Report for the fiscal year ended December 31, 2006.

ITEM 6. EXHIBITS

(a)		Exhibits

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


No.		Description of Exhibit
3.1		Certificate of Incorporation of Registrant (Incorporated by reference to Exhibit 3.1 to Form 10-Q of the Registrant for the fiscal quarter ended June 30, 2004)

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3.2		Bylaws of Registrant (Incorporated by reference to Exhibit No. 3.2 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)

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

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

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

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

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

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

4.3		Rights Agreement, dated as of October 5, 2000, between the Registrant and Computershare Trust Company, Inc., as Rights Agent (Incorporated by reference to Exhibit 1 of Form 8-A of the Registrant filed with the Securities and Exchange Commission on October 10, 2000)

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

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

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

4.7		Purchase Warrant Agreement, dated as of October 1, 1980, between the Registrant and American Stock Transfer, Inc. (Incorporated by reference to Exhibit No. 4.7 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)

4.8		First Amendment to Warrant Agreement, dated as of February 22, 2007, among the Registrant, Computershare Shareholder Services, Inc. and Computershare Trust Company, N.A. (Incorporated by reference to Exhibit No. 4.8 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)

		Executive Compensation Plans and Arrangements (Exhibit No.’s 10.1 through 10.7):

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

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10.2		Merrill Lynch, Pierce, Fenner & Smith Incorporated Prototype Simplified Employee Pension Plan (Incorporated by reference to Exhibit 10.6 of the Registrant’s Form 10-K for the fiscal year ended December 31, 1995)

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

10.4		1998 Stock Option Plan (Incorporated by reference to Exhibit No. 10.4 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)

10.5		2001 Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.7 of the Registrant’s Form 10-Q Report for the fiscal quarter ended March 31, 2004)

10.6		2004 Non-Employee Director Stock Grant Plan (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K Report dated September 22, 2004)

10.7		Incentive and Retention Plan (Incorporated by reference to Exhibit No. 10.7 of the Registrant for the fiscal year ended December 31, 2006)

10.8		First Amended and Restated Credit Agreement, dated December 20, 2002, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB, Western National Bank and BNP Paribas (Incorporated by reference to Exhibit 10.2 of Form 8-K of the Registrant, dated December 20, 2002)

10.9		Guaranty dated December 20, 2002, between Parallel, L.L.C. and First American Bank, SSB, as Agent (Incorporated by reference to Exhibit 10.3 of Form 8-K of the Registrant, dated December 20, 2002)

10.10		First Amendment to First Amended and Restated Credit Agreement, dated as of September 12, 2003, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB, Western National Bank, and BNP Paribas (Incorporated by reference to Exhibit 10.29 of Form 10-Q of the Registrant for the quarter ended September 30, 2003)

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

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

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

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

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

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

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

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

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

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

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

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

10.23		Guaranty, dated as of December 23, 2005, made by Parallel, L.L.C. to and in favor of Citibank Texas, N.A. (Incorporated by reference to Exhibit No. 10.23 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)

10.24		Third Amended and Restated Pledge Agreement, dated as of December 23, 2005, between Parallel, L.L.C. and Citibank Texas, N.A. (Incorporated by reference to Exhibit No. 10.24 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)

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10.25		Second Lien Guarantee and Collateral Agreement, dated as of November 15, 2005, made by Parallel Petroleum Corporation and Parallel, L.P. to and in favor of BNP Paribas (Incorporated by reference to Exhibit No. 10.25 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)

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

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

*31.1		Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes – Oxley Act of 2002.

*31.2		Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes – Oxley Act of 2002.

*32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002.

*32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002.


*		Filed herewith.

(37)

SIGNATURES

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


	PARALLEL PETROLEUM CORPORATION
	BY: /s/ Larry C. Oldham
Date: May 9, 2007	Larry C. Oldham
	President and Chief Executive Officer



Date: May 9, 2007	BY: /s/ Steven D. Foster
	Steven D. Foster,
	Chief Financial Officer

INDEX TO EXHIBITS


No.		Description of Exhibit

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

3.2		Bylaws of Registrant (Incorporated by reference to Exhibit No. 3.2 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)

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

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

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

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

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

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

4.3		Rights Agreement, dated as of October 5, 2000, between the Registrant and Computershare Trust Company, Inc., as Rights Agent (Incorporated by reference to Exhibit 1 of Form 8-A of the Registrant filed with the Securities and Exchange Commission on October 10, 2000)

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

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

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

4.7		Purchase Warrant Agreement, dated as of October 1, 1980, between the Registrant and American Stock Transfer, Inc. (Incorporated by reference to Exhibit No. 4.7 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)

4.8		First Amendment to Warrant Agreement, dated as of February 22, 2007, among the Registrant, Computershare Shareholder Services, Inc. and Computershare Trust Company, N.A. (Incorporated by reference to Exhibit No. 4.8 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)

Index to Exhibits


		Executive Compensation Plans and Arrangements (Exhibit No.’s 10.1 through 10.7):

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

10.2		Merrill Lynch, Pierce, Fenner & Smith Incorporated Prototype Simplified Employee Pension Plan (Incorporated by reference to Exhibit 10.6 of the Registrant’s Form 10-K for the fiscal year ended December 31, 1995)

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

10.4		1998 Stock Option Plan (Incorporated by reference to Exhibit No.10.4 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)

10.5		2001 Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.7 of the Registrant’s Form 10-Q Report for the fiscal quarter ended March 31, 2004)

10.6		2004 Non-Employee Director Stock Grant Plan (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K Report dated September 22, 2004)

10.7		Incentive and Retention Plan (Incorporated by reference to Exhibit No. 10.7 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)

10.8		First Amended and Restated Credit Agreement, dated December 20, 2002, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB, Western National Bank and BNP Paribas (Incorporated by reference to Exhibit 10.2 of Form 8-K of the Registrant, dated December 20, 2002)

10.9		Guaranty dated December 20, 2002, between Parallel, L.L.C. and First American Bank, SSB, as Agent (Incorporated by reference to Exhibit 10.3 of Form 8-K of the Registrant, dated December 20, 2002)

10.10		First Amendment to First Amended and Restated Credit Agreement, dated as of September 12, 2003, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB, Western National Bank, and BNP Paribas (Incorporated by reference to Exhibit 10.29 of Form 10-Q of the Registrant for the quarter ended September 30, 2003)

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

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

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

10.14		Second Amendment to Second Amended and Restated Credit Agreement, dated as of April 1, 2005, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First


		American Bank, SSB, BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K Report dated April 4, 2005 and filed with the Securities and Exchange Commission on April 8, 2005)

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

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

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

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

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

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

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

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

10.23		Guaranty, dated as of December 23, 2005, made by Parallel, L.L.C. to and in favor of Citibank Texas, N.A. (Incorporated by reference to Exhibit No. 10.23 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)

10.24		Third Amended and Restated Pledge Agreement, dated as of December 23, 2005, between Parallel, L.L.C. and Citibank Texas, N.A. (Incorporated by reference to Exhibit No. 10.24 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)


10.25		Second Lien Guarantee and Collateral Agreement, dated as of November 15, 2005, made by Parallel Petroleum Corporation and Parallel, L.P. to and in favor of BNP Paribas (Incorporated by reference to Exhibit No. 10.25 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)

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

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

*31.1		Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes – Oxley Act of 2002.

*31.2		Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes – Oxley Act of 2002.

*32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002.

*32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002.


*		Filed herewith.