UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C. 20549

FORM 10-Q/A

(Mark One)

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

For the quarterly period ended June 30, 2005 or

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

For the Transition period from                      to                     

PARALLEL PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

DELAWARE (State of other jurisdiction of incorporation or organization)		75-1971716 (I.R.S. Employer Identification Number)
1004 N. Big Spring, Suite 400 Midland, Texas (Address of principal executive offices)		79701 (Zip Code)

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

Yes þ No o

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

                         Large accelerated filer  o            Accelerated filer  þ            Non-accelerated filer o

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o  No þ

     At August 1, 2005, 34,025,168 shares of the Registrant’s Common Stock, $0.01 par value, were outstanding.

 

 

Explanatory Note

This Amendment No. 1 to the Quarterly Report on Form 10-Q of Parallel Petroleum Corporation (“Parallel”, the “Company”, “we”, “our” or “us”) for the quarterly period ended June 30, 2005, which was originally filed on August 3, 2005 (the “Form 10-Q”), is being filed to restate the financial statements and other disclosure included therein. As part of the preparation of our financial statements for the year ended December 31, 2005, we undertook a review of our accounting for oil and gas and interest rate derivatives. We use derivative instruments as a means of reducing financial exposure to fluctuating oil and gas prices and interest rates. We included changes from period to period in the fair value of derivatives classified as cash flow hedges (“Hedges”) as increases or decreases to Accumulated Other Comprehensive Income (“AOCI”) as allowed by Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“FAS 133”). This Hedge accounting treatment is allowed for certain derivatives, including the types of derivatives used by us to reduce exposure to changes in oil and gas prices associated with the sale of oil and gas production and fluctuations in interest rates. In order to qualify for Hedge accounting treatment, specific standards and documentation requirements must be met. We believed that we met those requirements and that our derivative accounting treatment was permitted under FAS 133. However, after a review of FAS 133 and our accounting policies and procedures related to our derivative instruments, we determined that certain of our derivative instruments did not qualify for Hedge accounting treatment under FAS 133. Specifically, we determined that documentation of the relationship of hedged items and the derivative instruments being employed and designated as Hedges was insufficient for derivative instruments entered into during periods subsequent to June 30, 2004; and that accounting for derivative instruments entered into during periods subsequent to June 30, 2004 as cash flow Hedges was, therefore, inappropriate. Accordingly, we have restated our Consolidated Balance Sheets as of June 30, 2005 and December 31, 2004; our Consolidated Statements of Operations for the three months and six months ended June 30, 2005; our Consolidated Statement of Cash Flows for the six months ended June 20, 2005; and our Consolidated Statements of Comprehensive Income (Loss) for the three and six months ended June 30, 2005 in the Form 10-Q to reflect these revisions (see Note 11 to our consolidated financial statements for a reconciliation of our restated results to previously reported results). We have also restated applicable disclosures in ITEM 1. “Notes to Consolidated Financial Statements” and ITEM 2. “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS”. Management has concluded, based on the circumstances involving the restatement of the aforementioned financial statements that as of December 31, 2005, a material weakness in internal control over financial reporting existed with respect to the design of our controls over the proper recording and disclosure of derivative instruments in accordance with FAS 133. See ITEM 4. “CONTROLS AND PROCEDURES.”

This Amendment No. 1 amends and restates the Form 10-Q in its entirety. This Amendment No. 1 does not reflect events occurring after the original filing of the Form 10-Q, and does not modify or update the disclosures therein in any way other than as required to reflect the amendments as previously described and set forth hereinafter. In addition, the filing of this amendment to the Form 10-Q shall not be deemed an admission that the original filing, when made, included any untrue statement of material fact or omitted to state a material fact necessary to make a statement made therein not misleading. This Form 10-Q/A (Amendment No. 1) should be read in conjunction with our filings made with the SEC subsequent to the filing of the original Form 10-Q, including any amendments to those filings.

INDEX

PART I. — FINANCIAL INFORMATION

		Page No.
ITEM 1. FINANCIAL STATEMENTS
Reference is made to the succeeding pages for the following consolidated financial statements:
- Consolidated Balance Sheets as of June 30, 2005 (unaudited) and December 31, 2004			1
- Unaudited Consolidated Statements of Operations for the three months and six months Ended June 30, 2005 and 2004			2
- Unaudited Consolidated Statements of Cash Flows for the six months ended June 30, 2005 and 2004			3
- Unaudited Consolidated Statements of Comprehensive Loss for the three months and six months ended June 30, 2005 and 2004			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			32
ITEM 4. CONTROLS AND PROCEDURES			34
PART II. — OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS			35
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			35
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS			36
ITEM 6. EXHIBITS			37
SIGNATURES
Non-Employee Directors Stock Option Plan
Certification of Principal Executive Officer Pursuant to Section 302
Certification of Principal Financial Officer Pursuant to Section 302
Certification of Chief Executive Officer Pursuant to Section 906
Certification of Chief Financial Officer Pursuant to Section 906

PARALLEL PETROLEUM CORPORATION

Consolidated Balance Sheets
(dollars in thousands)

		June 30,				December 31,
		2005				2004
		(unaudited)
		(restated)				(restated)
Assets
Current assets:
Cash and cash equivalents		$	3,756			$	4,781
Accounts receivable:
Oil and gas			7,866				6,642
Other, net of allowance for doubtful account of $9			1,256				389
Affiliates			7				7
			9,129				7,038
Other current assets			190				179
Deferred income tax asset			4,997				2,531
Total current assets			18,072				14,529
Property and equipment, at cost:
Oil and gas properties, full cost method (including $14,115 and $9,526 not subject to depletion)			251,913				229,245
Other			2,361				2,062
			254,274				231,307
Less accumulated depreciation, depletion and amortization			(83,837	)			(78,782	)
Net property and equipment			170,437				152,525
Restricted cash			149				2,287
Investment in Westfork Pipeline Company LP			1,572				595
Other assets, net of accumulated amortization of $724 and $581			774				735
		$	191,004			$	170,671
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities		$	7,368			$	5,568
Asset retirement obligations			133				150
Derivative obligations			16,449				7,965
Total current liabilities			23,950				13,683
Revolving credit facility			62,000				79,000
Asset retirement obligations			2,118				1,982
Derivative obligations			27,209				9,525
Deferred income tax liability			1,780				6,487
Total long-term liabilities			93,107				96,994
Commitments and contingencies
Stockholders’ equity:
Series A preferred stock — par value $0.10 per share, authorized 50,000 shares			—				—
Preferred stock — 6% convertible preferred stock — par value of $0.10 per share (liquidation preference of $10 per share), authorized 10,000,000 shares, issued and outstanding 950,000, converted to common stock June, 2005			—				95
Common stock — par value $0.01 per share, authorized 60,000,000 shares, issued and outstanding 34,013,572 and 25,439,292			340				254
Additional paid-in capital			76,528				48,328
Retained earnings			6,538				18,759
Accumulated other comprehensive loss			(9,459	)			(7,442	)
Total stockholders’ equity			73,947				59,994
		$	191,004			$	170,671

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

PARALLEL PETROLEUM CORPORATION

Consolidated Statements of Operations
(unaudited)
(in thousands, except per share data)

		Three Months Ended June 30,								Six Months Ended June 30,
		2005				2004				2005				2004
		(restated)								(restated)
Oil and natural gas revenues:
Oil and natural gas sales		$	15,004			$	9,752			$	27,973			$	18,858
Loss on hedging and derivatives			(2,741	)			(1,835	)			(5,296	)			(2,940	)
Total revenues			12,263				7,917				22,677				15,918
Cost and expenses:
Lease operating expense			2,178				2,014				4,736				3,543
Production taxes			701				471				1,281				949
General and administrative			1,408				1,221				3,036				2,443
Depreciation, depletion and amortization			2,773				1,969				5,055				4,046
Total costs and expenses			7,060				5,675				14,108				10,981
Operating income			5,203				2,242				8,569				4,937
Other income (expense), net:
Change in fair market value of derivative instruments			(6,065	)			—				(23,698	)			—
Gain (loss) on ineffective portion of hedges			(150	)			17				(860	)			7
Interest and other income			22				18				41				158
Interest expense			(868	)			(487	)			(2,041	)			(955	)
Other expense			(1	)			(59	)			(2	)			(85	)
Equity in loss of Westfork Pipeline Company LP			(15	)			—				(94	)			—
Total other expense, net			(7,077	)			(511	)			(26,654	)			(875	)
Income (loss) before income taxes			(1,874	)			1,731				(18,085	)			4,062
Income tax benefit (expense), deferred			628				(628	)			6,135				(1,477	)
Net income (loss)			(1,246	)			1,103				(11,950	)			2,585
Cumulative preferred stock dividend			(128	)			(144	)			(271	)			(287	)
Net income (loss) available to common stockholders		$	(1,374	)		$	959			$	(12,221	)		$	2,298
Net income (loss) per common share:
Basic		$	(0.04	)		$	0.04			$	(0.40	)		$	0.09
Diluted		$	(0.04	)		$	0.04			$	(0.40	)		$	0.09
Weighted average common share outstanding:
Basic			31,967				25,246				30,341				25,235
Diluted			31,967				28,330				30,341				28,296

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

PARALLEL PETROLEUM CORPORATION

Consolidated Statements of Cash Flows
Six Months Ended June 30, 2005 and 2004
(unaudited)
(dollars in thousands)

		2005				2004
		(restated)
Cash flows from operating activities:
Net income (loss)		$	(11,950	)		$	2,585
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization			5,055				4,046
Accretion of asset retirement obligation			54				53
Deferred income tax			(6,135	)			1,477
Change in fair value of derivatives instruments			23,696				—
Gain (loss) on ineffective portion of hedges			860				(7	)
Stock option expense			70				84
Equity in loss of Westfork Pipeline Company, LP			94				—
Changes in assets and liabilities:
Other assets, net			123				(141	)
Restricted cash			(149	)			—
Increase in accounts receivable			(2,091	)			(507	)
Increase in other current assets			(11	)			(87	)
Increase in accounts payable and accrued liabilities			1,800				1,084
Net cash provided by operating activities			11,416				8,587
Cash flows from investing activities:
Additions to oil and gas properties			(25,431	)			(14,590	)
Use of restricted cash for acquisition of oil and gas properties			2,287				—
Proceeds from disposition of oil and gas properties			2,828				25
Additions to other property and equipment			(299	)			(516	)
Settlements on derivatives			(1,570	)			—
Purchase of derivative instruments			(35	)			—
Investment in Westfork Pipeline Company LP			(1,071	)			—
Net cash used in investing activities			(23,291	)			(15,081	)
Cash flows from financing activities:
Net borrowings (payments) on revolving credit facility			(17,000	)			(5,750	)
Proceeds (net) from common stock issued			27,743				—
Proceeds from exercise of stock options			378				103
Deferred stock offering costs			—				(7	)
Payment of preferred stock dividend			(271	)			(287	)
Net cash provided by (used in) financing activities			10,850				(5,941	)
Net decrease in cash and cash equivalents			(1,025	)			(12,435	)
Cash and cash equivalents at beginning of period			4,781				17,378
Cash and cash equivalents at end of period		$	3,756			$	4,943
Non-cash financing and investing activities:
Oil and gas properties asset retirement obligations, net		$	65			$	189
Conversion of preferred stock		$	95			$	—
Other Transactions:
Interest paid		$	2,403			$	933

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

PARALLEL PETROLEUM CORPORATION

Consolidated Statements of Comprehensive Loss
(unaudited)
(dollars in thousands)

		Three Months Ended June 30,								Six Months Ended June 30,
		2005				2004				2005				2004
		(restated)								(restated)
Net income (loss)		$	(1,246	)		$	1,103			$	(11,950	)		$	2,585
Other comprehensive loss:
Unrealized losses on derivatives			(1,060	)			(3,782	)			(8,473	)			(8,125	)
Reclassification adjustments for losses on derivatives included in net income (loss)			2,788				1,952				5,418				3,171
Change in fair value of derivatives			1,728				(1,830	)			(3,055	)			(4,954	)
Income tax benefit (expense)			(588	)			624				1,038				1,685
Total other comprehensive income (loss)			1,140				(1,206	)			(2,017	)			(3,269	)
Total comprehensive loss		$	(106	)		$	(103	)		$	(13,967	)		$	(684	)

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

PARALLEL PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

     We are engaged in the acquisition, development and exploitation of long life oil and natural gas reserves and, to a lesser extent, the exploration for new oil and natural gas reserves. Our activities are focused in the Permian Basin of west Texas and New Mexico, Liberty County in east Texas and the onshore Gulf Coast area of south Texas. We are actively evaluating, leasing and drilling new projects located in New Mexico, the Fort Worth Basin of Texas, the Cotton Valley Reef trend of east Texas and the Uinta Basin of Utah.

     The financial information included herein is unaudited, except the balance sheet as of December 31, 2004 which has been derived from our audited Consolidated Financial Statements as of December 31, 2004, as restated (see Note 11). However, such information includes all adjustments (consisting solely of normal recurring adjustments), which are, in the opinion of management, necessary for a fair statement of the results of operations for the interim periods. The results of operations for the interim period are not necessarily indicative of the results to be expected for an entire year.

     Certain information, accounting policies and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted in this Form 10-Q Report pursuant to certain rules and regulations of the Securities and Exchange Commission. These financial statements should be read in conjunction with the audited consolidated financial statements and notes included in our Annual Report on Form 10-K for the year ended December 31, 2004.

     Unless otherwise indicated or unless the context otherwise requires, all references to “Parallel”, “we”, “us”, and “our” are to Parallel Petroleum Corporation and its consolidated subsidiaries, Parallel L.P. and Parallel, L.L.C.

NOTE 2. STOCKHOLDERS’ EQUITY

Options

     In September, 2003, Parallel adopted the provisions of Statement of Financial Accounting Standards No. 148, Accounting for Stock-Based Compensation — Transition and Disclosure, an amendment to SFAS No. 123, whereby certain transitional alternatives are available for a voluntary change to the fair value based method of accounting for stock-based employee compensation. Parallel used the prospective method which applied prospectively the fair value recognition method to all employee and director awards granted, modified or settled after the beginning of the fiscal year in which the fair value based method of accounting for stock-based compensation was adopted. The potential impact of using the fair value method for all options, on a pro forma basis, is presented in the table that follows.

     For the three and six months ended June 30, 2005 and 2004, Parallel recognized compensation expense of approximately $0.028 million and $0.07 million respectively associated with its stock option grants. No options were granted during the quarter ended June 30, 2005 or the quarter ended June 30, 2004.

     The following table illustrates the effect on net income and earnings per share as if the fair value based method had been applied to all outstanding and unvested awards in each period. The fair value of each grant is estimated on the date of grant using the Black-Scholes option-pricing model.

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2005				2004				2005				2004
		(dollars in thousands, except per share data)
		(restated)								(restated)
Net income, as reported		$	(1,246	)		$	1,103			$	(11,950	)		$	2,585
Add:
Expense recorded in 2005 and 2004			28				42				70				84
Deduct:
Total stock-based employee compensation expense determined under fair value based method for all awards, net of tax effects			(23	)			(48	)			(71	)			(95	)
Pro forma net income (loss)		$	(1,241	)		$	1,097			$	(11,951	)		$	2,574
Earnings (loss) per share:
Basic — as reported		$	(0.04	)		$	0.04			$	(0.40	)		$	0.09
Basic — pro forma		$	(0.04	)		$	0.04			$	(0.40	)		$	0.09
Diluted — as reported		$	(0.04	)		$	0.04			$	(0.40	)		$	0.09
Diluted — pro forma		$	(0.04	)		$	0.04			$	(0.40	)		$	0.09

Sale of Equity Securities

     On February 9, 2005, we sold 5,750,000 shares of our common stock, $.01 par value per share, pursuant to a public offering at a price of $5.27 per share. Gross cash proceeds were $30.3 million, and net proceeds were approximately $27.7 million. The common shares were issued under Parallel’s $100.0 million Universal Shelf Registration Statement on Form S-3 which became effective in November 2004. The proceeds were used to reduce our bank debt under our revolving credit facility described in Note 3 below.

Preferred Stock

     On May 4, 2005, notice was mailed that all 950,000 outstanding shares of our 6% Preferred Stock would be redeemed on June 6, 2005. All of the holders of the Preferred Stock elected to convert their shares of Preferred Stock into shares of Parallel common stock based on the conversion rate of $10.00 divided by $3.50. The holders of the Preferred Stock received approximately 2.8571 shares of common stock of Parallel for each share of Preferred Stock. Dividends on the Preferred Stock ceased to accrue, and as of June 6, 2005 the Preferred Stock is no longer outstanding.

NOTE 3. REVOLVING CREDIT FACILITY

     We are a party to a Second Amended and Restated Credit Agreement, as amended (the “Credit Agreement”), with Citibank Texas, N.A., BNP Paribas, Citibank, F.S.B. and Western National Bank. The Credit Agreement provides for a revolving credit facility which means that we can borrow, repay and reborrow funds drawn under the credit facility. The total amount that we can borrow and have outstanding at any one time is limited to the lesser of $200.0 million or the “borrowing base” established by our lenders. Our current borrowing base is $90.0 million. The principal amount outstanding under the credit facility at June 30, 2005 was $62.0 million, excluding $0.49 million reserved for our letters of credit. The amount of the borrowing base is based primarily upon the estimated value of our oil and 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 loan exceeds the borrowing base, we must either provide additional collateral to the lenders or repay the principal of the note 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 credit facility bear interest at Citibank’s base rate or the LIBOR rate, at our election. Generally, Citibank’s base rate is equal to the “prime rate” published in the Wall Street Journal. At June 30, 2005, Parallel had $4.0 million in base rate loans outstanding under the credit facility.

     The LIBOR rate is generally equal to the sum of (a) the rate designated as “British Bankers Association Interest Settlement Rates” and offered on one, two, three, six or twelve month interest periods for deposits of $1.0 million, and (b) a margin ranging from 2.25% to 2.75%, depending upon the outstanding principal amount of the loans. If the principal amount outstanding is equal to or greater than 75% of the borrowing base, the margin is 2.75%. If the principal amount outstanding is equal to or greater than 50%, but less than 75% of the borrowing base, the margin is 2.50%. If the principal amount outstanding is less than 50% of the borrowing base, the margin is 2.25%.

     The interest rate we are required to pay on our borrowings, including the applicable margin, may never be less than 4.50%. At June 30, 2005, our Libor interest rate was 5.62% on $31.0 million and 5.78% on $27.0 million.

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

     If the total outstanding borrowings under the credit facility are less than the borrowing base, an unused commitment fee is required to be paid to the lenders. The amount of the fee is .25% of the daily average of the unadvanced amount of the borrowing base. The fee is payable quarterly.

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

     Parallel, L.L.C., a subsidiary of Parallel Petroleum Corporation, guaranteed payment of the loans.

     Parallel’s obligations to the lenders are secured by substantially all of its oil and gas properties.

     All outstanding principal under the revolving credit facility is due and payable on December 20, 2008. The maturity date of our outstanding loans may be accelerated by the lenders upon the occurrence of an event of default under the Credit Agreement.

     The Credit Agreement contains various restrictive covenants and compliance requirements as follows:

	•		at the end of each quarter, a current ratio (as defined in the credit agreement) of at least 1.1 to 1.0;
	•		for each period (as calculated in the Credit Agreement) ending on December 31, March 31, June 30 and September 30, a funded debt ratio (as defined in the Credit Agreement) of not more than 3.70, 3.60 and 3.50, respectively, for December 31, 2005, 2006 and 2007; and
	•		at all times, adjusted consolidated net worth (as defined in the Credit Agreement) of at least (a) $50.0 million, plus (b) seventy-five percent (75%) of the net proceeds from any equity securities issued by Parallel, plus (c) fifty percent (50%) of consolidated net income for each fiscal quarter, if positive, and zero percent (0%) if negative.

     As a result of the restatement of the financial statements concerning our accounting for certain oil and natural gas and interest rate derivative instruments (see Note 11), we were not in compliance with certain covenants in the Credit Agreement concerning financial reporting requirements. We have obtained waivers of our non-compliance with these covenants from our lenders.

     The Credit Agreement also contains restrictions on all retained earnings and net income for payment of dividends on common stock.

     If we have borrowing capacity under our Credit Agreement, we intend to borrow, repay and reborrow under the revolving credit facility from time to time as necessary, subject to borrowing base limitations, to fund:

	•		interpretation and processing seismic survey data;
	•		lease acquisitions and drilling activities;
	•		acquisitions of producing properties or companies owning producing properties; and,

•

general corporate purposes.

     Interest expense for the six months ending June 30, 2005 was approximately $1.9 million not including approximately $0.050 million for interest capitalized associated with drilling projects.

NOTE 4. ACQUISITIONS

     In September and October 2004, with two separate transactions, we purchased additional non-operated working interest in the Fullerton Field properties. The net purchase price for these transactions was approximately $20.9 million.

     In October and December 2004, we purchased properties in the Carm-Ann San Andres and North Means Queen Unit located in Andrews and Gaines counties, Texas. The combined net purchase price was approximately $16.5 million. In the first quarter of 2005, we acquired additional interest in these properties for a net purchase price of approximately $2.3 million.

     The table below reflects our actual consolidated restated results of operations for the three and six months ended June 30, 2005, compared to the consolidated pro forma results of operations for the six months ended June 30, 2004, assuming these acquisitions were consummated on January 1, 2004.

		Three Months Ended								Six Months Ended
		June 30,								June 30,
						Pro Forma								Pro Forma
		2005				2004				2005				2004
		(in thousands, except per share data)
		(restated)								(restated)
Oil and gas revenue, net of hedge losses		$	12,263			$	10,135			$	22,677			$	20,098
Operating income		$	5,203			$	3,347			$	8,569			$	6,504
Net income (loss) available to common stockholders		$	(1,374	)		$	1,395			$	(12,221	)		$	2,746
Net income (loss) per common share:
Basic		$	(0.04	)		$	0.06			$	(0.40	)		$	0.11
Diluted		$	(0.04	)		$	0.06			$	(0.40	)		$	0.11

NOTE 5. FULL COST CEILING TEST

     We use the full cost method to account for our oil and gas producing activities. Under the full cost method of accounting, the net book value of oil and gas properties, less related deferred income taxes and asset retirement obligations, may not exceed a calculated “ceiling”. The ceiling limitation is the discounted estimated after-tax future net cash flows from proved oil and gas properties. In calculating future net cash flows, current prices and costs are generally held constant indefinitely as adjusted for qualifying cash flow hedges. The net book value of oil and gas properties, less related deferred income taxes over the ceiling, is compared to the ceiling on a quarterly and annual basis. Any excess of the net book value, less related deferred income taxes, is generally written off as an expense. Under rules and regulations of the SEC, the excess above the ceiling is not written off if, subsequent to the end of the quarter or year but prior to the release of the financial results, prices have increased sufficiently that such excess above the ceiling would not have existed if the increased prices were used in the calculations.

     At June 30, 2005, we had a cushion (i.e. the excess of the ceiling over our capitalized cost) in excess of $140.0 million. As a result, we were not required to record a reduction of our oil and gas properties under the full cost method of accounting at that time.

     Under the full cost method of accounting, all costs incurred in the acquisition, exploration and development of oil and natural gas properties, including a portion of our overhead, are capitalized. In the six month periods ended June 30, 2005 and 2004, overhead costs capitalized were approximately $0.597 million and $0.522 million respectively.

NOTE 6. DERIVATIVE INSTRUMENTS

General

     We enter into derivative contracts to provide a measure of stability in the cash flows associated with our oil and 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 gas prices and to limit variability in our cash interest payments. Our line of credit agreement as of June 30, 2005, 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, commodity collars and commodity swaps entered into in 2002 through June 30, 2004 as cash flow hedges (“hedges”). The effective portion of the unrealized gain or loss on cash flow hedges is recorded in other comprehensive income (loss) until the forecasted transaction occurs. During the term of a cash flow hedge, the effective portion of the quarterly change in the fair value of the derivatives is recorded in stockholders’ equity as other comprehensive loss and then transferred to oil and gas revenues when the production is sold and interest expense as the interest accrues. Ineffective portions of hedges (changes in fair value resulting from changes in realized prices that do not match the changes in the hedge or reference price) are recognized in other expense as they occur.

     As of June 30, 2005, we have recorded unrealized losses of $14.3 million ($9.5 million, net of tax) related to our derivative instruments designated as hedges, which represented the estimated aggregate fair values of our open hedge contracts, as of that date. These unrealized losses are presented in stockholders’ equity in the Consolidated Balance Sheet as accumulated other comprehensive loss. During the twelve month period ending June 30, 2006, we expect approximately $6.8 million, net of tax, in accumulated other comprehensive loss to be charged to earnings.

     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. However, we periodically assess the creditworthiness of the counterparty to mitigate this credit risk.

Interest Rate Sensitivity

     We entered into fixed interest rate swap contracts with BNP Paribas based on the 90-day LIBOR rates at the time of the contracts. These interest rate swaps are treated as cash flow hedges as defined by Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended (“SFAS 133”), and are on $20.0 million of our variable rate debt for all of 2005 and on $10.0 million of our variable rate debt for all of 2006. We will continue to pay the variable interest rates for this portion of our borrowing under the Credit Agreement, but due to the interest rate swaps, we have fixed the rate at 4.05%. As of June 30, 2005, the fair market value of these interest rate swaps was an unrealized loss of $27,000.

     As of June 30, 2005, we had also employed additional fixed interest rate swap contracts with BNP Paribas based on the 90-day LIBOR rates at the time of the contracts. However, these contracts are accounted for by “mark-to-market” accounting as prescribed in SFAS 133. Nonetheless, we view these contracts as additional protection against future interest rate volatility.

     The table below recaps the nature of these interest rate swaps and the fair market value of these contracts as of June 30, 2005.

		Notional								Fair
Period of Time		Amounts				Fixed Interest Rates				Market Value
		($ in millions)								($ in thousands)
July 1, 2005 thru December 31, 2005(1)		$	20				4.05	%		$	(33	)
July 1, 2005 thru December 31, 2005		$	30				2.89	%		$	124
January 1, 2006 thru December 31, 2006(1)		$	10				4.05	%		$	6
January 1, 2006 thru December 31, 2006		$	40				3.76	%		$	136
January 1, 2007 thru December 31, 2007		$	50				4.30	%		$	(83	)
January 1, 2008 thru December 30, 2008		$	50				4.74	%		$	(246	)
Total Fair Market Value										$	(96	)

Commodity Price Sensitivity

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

     Put Options. On April 7, 2005, we purchased put options or “floors” on volumes of 1,000 Mcf per day for a total of 214,000 Mcf during the seven month period from April 1, 2006 through October 31, 2006, at an average floor price of $5.50 per Mcf for a total consideration of approximately $35,000.

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

     A summary of our collar positions at June 30, 2005 is as follows:

																		Houston
						NyMex												Ship Channel
		Barrels				Oil Prices								M M Btu of				Gas Prices
Period of Time		of Oil				Floor				Cap				Natural Gas				Floor				Cap				Fair Market Value
																										($ in thousands)
July 1, 2005 thru October 31, 2005			—			$	—			$	—				246,000			$	5.00			$	7.26			$	(52	)
July 1, 2005 thru December 31, 2005			36,800			$	36.00			$	49.60				—			$	—			$	—				(322	)
January 1, 2006 thru December 31, 2006			70,800			$	35.00			$	44.00				—			$	—			$	—				(1,023	)
Total Fair Market Value																										$	(1,397	)

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

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

						Nymex Oil				Fair Market
Period of Time		Barrles of Oil				Swap Price				Value
										($ in thousands)
July 1, 2005 thru December 31, 2005(1)			184,000			$	23.31			$	(6,410	)
July 1, 2005 thru December 31, 2005			128,800			$	39.96			$	(2,360	)
January 1, 2006 thru December 20, 2006(1)			265,500			$	23.04				(9,241	)
January 1, 2006 thru December 20, 2006			182,500			$	36.36				(3,988	)
January 1, 2007 thru December 31, 2007			474,500			$	34.36				(10,511	)
January 1, 2008 thru December 31, 2008			439,200			$	33.37				(9,528	)
Total fair market value										$	(42,038	)

NOTE 7. NET INCOME PER COMMON SHARE

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

     The following table provides the computation of basic and diluted earnings per share for the three and six months ended June 30, 2005 and 2004:

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2005				2004				2005				2004
		(dollars in thousands, except per share data)
		(restated)								(restated)
Basic EPS Computation:
Numerator-
Income (loss)		$	(1,246	)		$	1,103			$	(11,950	)		$	2,585
Preferred stock dividend			(128	)			(144	)			(271	)			(287	)
Income (loss) available to common stockholders		$	(1,374	)		$	959			$	(12,221	)		$	2,298
Denominator-
Weighted average common shares outstanding			31,967				25,246				30,341				25,235
Basic EPS:
Income (loss) per share		$	(0.04	)		$	0.04			$	(0.40	)		$	0.09
Diluted EPS Computation:
Numerator-
Income (loss)		$	(1,246	)		$	1,103			$	(11,950	)		$	2,585
Preferred stock dividend			(128	)			—				(271	)			—
Income (loss) available to common stockholders		$	(1,374	)		$	1,103			$	(12,221	)		$	2,585
Denominator -
Weighted average common shares outstanding			31,967				25,246				30,341				25,235
Employee stock options			—				285				—				268
Warrants			—				65				—				59
Preferred stock			—				2,734				—				2,734
Weighted average common shares for diluted earnings per share assuming conversion			31,967				28,330				30,341				28,296
Diluted EPS:
Income (loss)		$	(0.04	)		$	0.04			$	(0.40	)		$	0.09

NOTE 8: ASSET RETIREMENT OBLIGATIONS

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

     The following table summarizes our asset retirement obligation activity:

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2005				2004				2005				2004
						(in thousands)
Beginning asset retirement obligation		$	2,112			$	1,864			$	2,132			$	1,701
Additions related to new properties			113				59				130				231
Deletions related to property disposals			(2	)			—				(65	)			(42	)
Accretion expense			28				20				54				53
Ending asset retirement obligation		$	2,251			$	1,943			$	2,251			$	1,943

NOTE 9. RECENTLY ANNOUNCED ACCOUNTING PRONOUNCEMENTS

     In December 2004, the Financial Accounting Standards Board (“FASB”) issued “Statement of Financial Accounting Standards No. 123 (revised 2004)”, “Share-Based Payment” (“SFAS No. 123(R)”). SFAS No. 123(R) requires an entity to recognize the grant-date fair value of stock options and other equity-based compensation issued to employees in the income statement. SFAS No. 123(R) initially was to be effective for the Company beginning July 1, 2005. On April 14, 2005, the Securities and Exchange Commission announced a delay in the implementation of SFAS No. 123(R) until the beginning of the fiscal year after June 15, 2005. The Company does not expect SFAS No. 123(R) to have a material impact on its results of operations.

NOTE 10. COMMITMENTS AND CONTINGENCIES

     From time to time, we are a party to ordinary routine litigation incidental to our business. We are currently a defendant in one lawsuit incidental to our business. We do not believe the ultimate outcome of this lawsuit will have a material adverse effect on our financial condition or results of operations. We are not aware of any other threatened litigation and we have not been a party to any bankruptcy, receivership, reorganization, adjustment or similar proceeding.

     Effective January 1, 2005, we established a 401(k) Plan and Trust for eligible employees. Employees may not participate in the former SEP plan with the establishment of the 401(k) Plan and Trust. As of the six months ending June 30, 2005 Parallel had made contributions to the 401(k) Plan and Trust of approximately $0.077 million.

NOTE 11. RESTATEMENT

     This amended quarterly report on Form 10-Q for the quarter ended June 30, 2005 includes detailed disclosures relative to the restatement of the consolidated financial statements for the three and six months ended June 30, 2005, and the consolidated balance sheet as of December 31, 2004.

     During the course of our preparation of our December 31, 2005 Form 10-K, we identified errors with respect to our use of hedge accounting for certain transactions under SFAS 133. Specifically, we determined that our documentation of the relationship of hedged items and the derivative instruments being employed and designated as hedges was insufficient when compared to the documentation requirements in SFAS 133 for derivative instruments entered into during periods subsequent to June 30, 2004, and that accounting for derivative instruments entered into during periods subsequent to June 30, 2004 as cash flow hedges was, therefore, inappropriate.

Effects of the Restatement

     The effect of the restatement on the consolidated balance sheet as of June 30, 2005 and as of December 31, 2004 by line item is as follows:

		As of June 30, 2005								As of December 31, 2004
		As previously								As previously
		reported				As restated				reported				As restated
		(in thousands)
		(unaudited)
Condensed Consolidated Balance Sheet data:
Other current assets		$	225			$	190			$	179			$	179
Total current assets			18,107				18,072				14,529				14,529
Other assets, net of accumulated amortization of $724 and $581			612				774				735				735
Total assets			190,877				191,004				170,671				170,671
Derivative obligation — current			16,322				16,449				7,965				7,965
Total current liabilities			23,823				23,950				13,683				13,683
Derivative obligation — long term			27,209				27,209				9,525				9,525
Total long-term liabilities			93,107				93,107				96,994				96,994
Retained earnings			22,705				6,538				22,073				18,759
Accumulated other comprehensive loss			(25,626	)			(9,459	)			(10,756	)			(7,442	)
Total liabilities and stockholders’ equity			190,877				191,004				170,671				170,671

     The effect of the restatement on the consolidated statements of operations for the three and six months ended June 30, 2005 is as follows:

		Three Months Ended								Six Months Ended
		June 30, 2005								June 30, 2005
		As previously								As previously
		reported				As restated				reported				As restated
		(in thousands)								(in thousands)
		(unaudited)								(unaudited)
Consolidated Statement of Operations data:
Loss on hedging and derivatives		$	(3,645	)		$	(2,741	)		$	(6,857	)		$	(5,296	)
Total revenues			11,359				12,263				21,116				22,677
Operating income			4,241				5,203				6,890				8,569
Change in fair market value of derivatives			—				(6,065	)			—				(23,698	)
Loss on ineffective portion of hedges			(1,235	)			(150	)			(3,511	)			(860	)
Interest expense			(796	)			(868	)			(1,934	)			(2,041	)
Total other expense, net			(2,025	)			(7,077	)			(5,500	)			(26,654	)
Net income (loss) before income taxes			2,216				(1,874	)			1,390				(18,085	)
Income tax benefit (expense), deferred			(763	)			628				(487	)			6,135
Net income (loss)			1,453				(1,246	)			903				(11,950	)
Net income (loss) available to common stockholders			1,325				(1,374	)			632				(12,221	)
Net income (loss) per common share:
Basic		$	0.04			$	(0.04	)		$	0.02			$	(0.40	)
Diluted		$	0.04			$	(0.04	)		$	0.03			$	(0.40	)

     The effect of the restatement on the consolidated statement of cash flows for the six months ended June 30, 2005 is as follows:

		Six Months Ended
		June 30, 2005
		As previously
		reported				As restated
		(in thousands)
		(unaudited)
Condensed Consolidated Statement of Cash Flows data:
Net income (loss)		$	903			$	(11,950	)
Deferred income tax expense (benefit)			487				(6,135	)
Change in fair value of derivative instruments			—				23,696
Loss on ineffective portion of hedges			3,511				860
Other assets, net			123				123
Increase in other current assets			(46	)			(11	)
Net cash provided by operating activities			9,811				11,416
Settlements on derivatives			—				(1,570	)
Purchase of derivative instruments			—				(35	)
Net cash used in investing activities			(21,686	)			(23,291	)

     The effect of the restatement on the consolidated statements of comprehensive income (loss) for the three and six months ended June 30, 2005 is as follows:

		Three Months Ended								Six Months Ended
		June 30, 2005								June 30, 2005
		As previously								As previously
		reported				As restated				reported				As restated
		(in thousands)								(in thousands)
		(unaudited)								(unaudited)
Net loss		$	1,453			$	(1,246	)		$	903			$	(11,950	)
Other comprehensive loss:
Unrealized losses on derivatives			(6,038	)			(1,060	)			(29,518	)			(8,473	)
Reclassification adjustments for losses on derivatives included in net income (loss)			3,676				2,788				6,988				5,418
Change in fair value of derivatives			(2,362	)			1,728				(22,530	)			(3,055	)
Income tax benefit (expense)			803				(588	)			7,660				1,038
Total other comprehensive loss			(1,559	)			1,140				(14,870	)			(2,017	)
Total comprehensive loss		$	(106	)		$	(106	)		$	(13,967	)		$	(13,967	)

     The restatement also impacted or made changes to Notes 1, 2, 3, 4, 6 and 7 of these Notes to Consolidated Financial Statements and resulted in adding this Note 11.

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 our Consolidated Financial Statements and the related notes.

OVERVIEW

Strategy

     Our primary objective is to increase shareholder value of our common stock through increasing reserves, production, cash flow and earnings. We have shifted the balance of our investments from properties having high rates of production in early years to properties expected to produce more consistently over a longer term. We attempt to reduce our financial risks by dedicating a smaller portion of our capital to high risk projects, while reserving the majority of our available capital for exploitation and development drilling opportunities. Obtaining positions in long-lived oil and natural gas reserves are given priority over properties that might provide more cash flow in the early years of production, but which have shorter reserve lives. We also attempt to further reduce risk by emphasizing acquisition possibilities over high risk exploration projects.

     Since the latter part of 2002, we have reduced our emphasis on high risk exploration efforts and focused on established geologic trends where we utilize the engineering, operational, financial and technical expertise of our entire staff. Although we anticipate participating in exploratory drilling activities in the future, reducing financial, reservoir, drilling and geological risks and diversifying our property portfolio are important criteria in the execution of our business plan. In summary, our current business plan:

	•		focuses on projects having less geological risk;
	•		emphasizes exploitation and enhancement activities;
	•		focuses on acquiring producing properties; and
	•		expands the scope of operations by diversifying our exploratory and development efforts, both in and outside of our current areas of operation.

     Although the direction of our exploration and development activities has shifted from high risk exploratory activities to lower risk development opportunities, we will continue our efforts, as we have in the past, to maintain low general and administrative expenses relative to the size of our overall operations, utilize advanced technologies, serve as operator in appropriate circumstances, and reduce operating costs.

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

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

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

Operating Performance

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

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

     Additional factors influencing our overall operating performance include:

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

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

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

     For the three months ended June 30, 2005, the sale price we received for our crude oil production (excluding hedges) averaged $46.97 per barrel compared with $35.70 per barrel for the three months ended June 30, 2004. The average sales price we received for natural gas for the three months ended June 30, 2005 (excluding hedges), was $6.78 per Mcf compared with $5.94 per Mcf for the three months ended June 30, 2004. For information regarding prices received including our hedges, refer to the selected operating data table in the Results of Operations on page 19. Hedge costs for oil and natural gas was $2.7 million and $1.8 million for the three months ended June 30, 2005 and June 30, 2004 respectively. The hedge loss associated with the ineffective portion of our hedges was $150,000 for the second quarter ended June 30, 2005. The ineffectiveness is caused by a widening of the differential price of West Texas Intermediate Light and current designated sales of West Texas Sour barrels. U. S. refineries are currently paying a premium for West Texas Intermediate, which is the NyMex benchmark. The majority of our oil is West Texas Sour. Actual gains or losses may increase or decrease until settlement of these contracts.

     For the six months ended June 30, 2005, the sale price we received for our crude oil production (excluding hedges) averaged $46.15 per barrel compared with $34.31 per barrel for the six months ended June 30, 2004. The average sales price we received for natural gas for the six months ended June 30, 2005 (excluding hedges), was $6.42 per Mcf compared with $5.55 per Mcf for the six months ended June 30, 2004. For information regarding prices received including our hedges, refer to the selected operating data table in the Results of Operations on page 19. Hedge costs for oil and natural gas were $5.3 million and $2.9 million for the six months ended June 30, 2005 and June 30, 2004 respectively. The hedge loss associated with the ineffective portion of our hedges was $860,000 for the six months ended June 30, 2005. The ineffectiveness is caused by a widening of the differential price of

West Texas Intermediate Light and current designated sales of West Texas Sour barrels. U. S. refineries are currently paying a premium for West Texas Intermediate, which is the NyMex benchmark. The majority of our oil is West Texas Sour. Actual gains or losses may increase or decrease until settlement of these contracts.

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

     Depletion of the capitalized costs of oil and natural gas properties, including estimated future development costs, is provided using the equivalent unit-of-production method based upon estimates of proved oil and natural gas reserves and production, which are converted to a common unit of measure based upon their relative energy content. Unproved oil and natural gas properties are not amortized, but are individually assessed for impairment. The cost of any impaired property is transferred to the balance of oil and gas properties being depleted. Depletion per BOE at June, 2005 and 2004 was $7.94 and $6.92 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);
	•		the prices we receive for our oil and gas production;

     Year-to-year or other periodic comparisons of the results of our operations can be difficult and may not fully and accurately describe our condition. The following table shows selected operating data for each of the three and six months ended June 30, 2005 and June 30, 2004.

		Three Months Ended								Six Months Ended
		6/30/2005				6/30/2004				6/30/2005				6/30/2004
		(in thousands, except per unit data)
		(restated)								(restated)
Production Volumes:
Oil (Bbls)			218				166				425				327
Natural gas (Mcf)			700				644				1,302				1,376
BOE(1)			335				273				642				556
BOE per day			3.7				3.0				3.5				3.1
Sales Prices:
Oil (per Bbl)(2)		$	46.97			$	35.70			$	46.15			$	34.31
Natural gas (per Mcf)(2)		$	6.78			$	5.94			$	6.42			$	5.55
BOE price (2)		$	44.77			$	35.72			$	43.57			$	33.92
BOE price(3)		$	36.60			$	29.00			$	35.32			$	28.63
Operating Revenues
Oil		$	10,259			$	5,928			$	19,618			$	11,218
Oil hedge			(2,741	)			(1,522	)			(5,095	)			(2,646	)
Natural gas			4,745				3,824				8,355				7,640
Natural gas hedge			—				(313	)			(201	)			(294	)
		$	12,263			$	7,917			$	22,677			$	15,918
Operating Expenses:
Lease operating expense		$	2,178			$	2,014			$	4,736			$	3,543
Production taxes			701				471				1,281				949
General and administrative:
General and administrative			859				806				1,828				1,540
Public reporting			549				415				1,208				903
Depreciation, depletion and amortization			2,773				1,969				5,055				4,046
		$	7,060			$	5,675			$	14,108			$	10,981
Operating income		$	5,203			$	2,242			$	8,569			$	4,937