Grizzly Energy 8K Consolidated Statements of Operations | GRZZP 10 Jun 09

Exhibit 99.1

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index

Below is an index to the items contained in Part II, Item 8, Financial Statements and Supplementary Data.

	Page
Reports of Independent Registered Public Accounting Firms	2
Consolidated Statements of Operations	5
Consolidated Balance Sheets	6
Consolidated Statements of Members’ Equity	7
Consolidated Statements of Cash Flows	8
Consolidated Statements of Other Comprehensive Income (Loss)	9
Notes to Consolidated Financial Statements	10
Supplemental Financial Information
Supplemental Selected Quarterly Financial Information (Unaudited)	25
Supplemental Natural Gas and Oil Operations (Unaudited)	26

All schedules are omitted as the required information is not applicable or the information is presented in the Consolidated Financial Statements and related notes.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Members

Vanguard Natural Resources, LLC

Houston, Texas

We have audited the accompanying consolidated balance sheet of Vanguard Natural Resources, LLC as of December 31, 2008 and the related consolidated statements of operations, comprehensive income (loss), members’ equity and cash flows for the year then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Vanguard Natural Resources, LLC at December 31, 2008, and the results of its operations and its cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Vanguard Natural Resources, LLC's internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated March 10, 2009 (not presented herein) expressed an unqualified opinion thereon.

/s/ BDO Seidman, LLP

Houston, Texas

March 10, 2009, except for Note 13 which is dated

June 10, 2009

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Unitholders of

Vanguard Natural Resources, LLC

and Subsidiaries

We have audited the accompanying consolidated balance sheet of Vanguard Natural Resources, LLC (a Delaware limited liability company) and subsidiaries (the “Company”) as of December 31, 2007, and the related consolidated statements of operations, members’ equity, comprehensive income and cash flows for the year then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Vanguard Natural Resources, LLC and subsidiaries as of December 31, 2007, and the consolidated results of their operations and their cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.

/s/ UHY LLP

Houston, Texas

March 31, 2008

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Members of

Vanguard Natural Gas, LLC

and Subsidiaries

We have audited the accompanying consolidated statements of operations and cash flows of Vanguard Natural Gas, LLC (formerly Nami Holding Company, LLC), and subsidiaries (the “Company”) for the year ended December 31, 2006. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated results of operations and cash flows of Vanguard Natural Gas, LLC and subsidiaries for the year ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

/s/ UHY LLP

Houston, Texas

April 20, 2007

Vanguard Natural Resources, LLC and Subsidiaries

Consolidated Statements of Operations

For the Years Ended December 31,

	Vanguard						Vanguard Predecessor
	2008			2007			2006
Revenues
Natural gas and oil sales	$	68,850,004		$	34,540,500		$	38,849,142
Gain (loss) on commodity cash flow hedges		269,260			(701,675	)		—
Gain on other commodity derivative contracts		32,476,472			—			15,539,915
Total revenues		101,595,736			33,838,825			54,389,057

Costs and expenses
Lease operating expenses		11,111,849			5,066,230			4,896,327
Depreciation, depletion, amortization and accretion		14,910,454			8,981,179			8,633,235
Impairment of natural gas and oil properties		58,886,660			—			—
Selling, general and administrative expenses		6,715,036			3,506,539			5,198,760
Bad debt expense		—			1,007,458			—
Production and other taxes		4,964,987			2,053,604			1,774,215
Total costs and expenses		96,588,986			20,615,010			20,502,537

Income from operations		5,006,750			13,223,815			33,886,520

Other income (expense)
Interest income		17,232			61,621			40,256
Interest expense		(5,490,816	)		(8,134,600	)		(7,371,930	)
Loss on interest rate derivative contracts		(3,284,514	)		—			—
Loss on extinguishment of debt expense		—			(2,501,528	)		—
Total other expense		(8,758,098	)		(10,574,507	)		(7,331,674	)

Net income (loss)	$	(3,751,348	)	$	2,649,308		$	26,554,846

Net income (loss) per unit:
Common and Class B units - basic	$	(0.32	)	$	0.39
Common and Class B units - diluted	$	(0.32	)	$	0.39

Weighted average units outstanding:
Common units – basic & diluted		11,374,473			6,533,411
Class B units – basic & diluted		420,000			278,945

See accompanying notes to consolidated financial statements.

Vanguard Natural Resources, LLC and Subsidiaries

Consolidated Balance Sheets

As of December 31,

	2008			2007
Assets
Current assets
Cash and cash equivalents	$	2,616		$	3,109,563
Trade accounts receivable, net		6,083,479			3,875,078
Derivative assets		22,183,648			4,017,085
Other receivables		2,762,730			497,653
Other currents assets		845,404			453,198
Total current assets		31,877,877			11,952,577

Property and equipment, net of accumulated depreciation		184,224			166,455

Natural gas and oil properties, at cost		284,446,984			135,435,240
Accumulated depletion, amortization and accretion		(102,178,304	)		(28,451,891	)
Natural gas and oil properties evaluated, net – full cost method		182,268,680			106,983,349

Other assets
Derivative assets		15,748,721			1,329,511
Deferred financing costs		881,996			941,833
Non-current deposits		45,963			8,285,883
Other assets		1,554,416			1,519,577
Total assets	$	232,561,877		$	131,179,185

Liabilities and members’ equity

Current liabilities
Accounts payable – trade	$	2,147,664		$	1,056,627
Accounts payable – natural gas and oil		1,327,361			257,073
Payables to affiliates		2,554,624			3,838,328
Derivative liabilities		486,576			—
Accrued expenses		1,247,606			203,159
Total current liabilities		7,763,831			5,355,187

Long-term debt		135,000,000			37,400,000
Derivative liabilities		2,313,335			5,903,384
Asset retirement obligations		2,133,791			189,711
Total liabilities		147,210,957			48,848,282

Commitments and contingencies (Note 9)

Members’ equity
Members’ capital, 12,145,873 and 10,795,000 common units issued and outstanding at December 31, 2008 and 2007, respectively		88,550,178			90,257,856
Class B units, 420,000 issued and outstanding at December 31, 2008 and 2007		4,605,463			2,131,995
Accumulated other comprehensive loss		(7,804,721	)		(10,058,948	)
Total members’ equity		85,350,920			82,330,903

Total liabilities and members’ equity	$	232,561,877		$	131,179,185

See accompanying notes to consolidated financial statements.

Vanguard Natural Resources, LLC and Subsidiaries

Consolidated Statements of Members’ Equity

For the Years Ended December 31, 2008 and 2007

	Common Units	Class B Units	Total Members’ Equity
Balance, January 1, 2007	—	—	$	—
Initial contribution	5,540,000	—	3,289,055
Sale of private placement units	—	—	41,220,000
Distribution to member	—	—	(41,220,000		)
Issuance of common units, net of offering costs of $9,804,085	5,250,000	—	89,945,916
Distribution to members	—	—	(5,626,423		)
Unit-based compensation	5,000	420,000	2,131,995
Net income	—	—	2,649,308
Changes in fair value of cash flow hedges	—	—	(10,058,948		)

Balance, December 31, 2007	10,795,000	420,000	$	82,330,903
Distribution to members ($0.291, $0.445, $0.445 and $0.50 per unit to unit holders of record on February 7, 2008, April 30, 2008, July 31, 2008 and October 31, 2008, respectively)	—	—		(20,128,990	)
Issuance of common units for acquisition of natural gas and oil properties, net of offering costs of $54,191	1,350,873	—		21,305,809
Unit-based compensation	—	—		3,340,319
Settlement of cash flow hedges in other comprehensive income	—	—		2,254,227
Net loss	—	—		(3,751,348	)

Balance, December 31, 2008	12,145,873	420,000	$	85,350,920

See accompanying notes to consolidated financial statements.

Vanguard Natural Resources, LLC and Subsidiaries

Consolidated Statements of Cash Flows

For the Years Ended December 31,

	Vanguard						Vanguard Predecessor
	2008			2007			2006
Operating activities
Net income (loss)	$	(3,751,348	)	$	2,649,308		$	26,554,846
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		14,910,454			8,981,179			8,633,235
Impairment of natural gas and oil properties		58,886,660			—			—
Amortization of deferred financing costs		362,400			296,115			—
Bad debt expense		—			1,007,458			—
Unit-based compensation		3,576,558			2,131,995			—
Amortization of premiums paid and non-cash settlements on derivative contracts		5,226,465			4,274,120			—
Unrealized gains on other commodity and interest rate derivative contracts		(35,851,133	)		—			(17,747,817	)
Changes in operating assets and liabilities:
Trade accounts receivable		(2,208,401	)		(504,683	)		1,634,402
Payables to affiliates		(1,850,094	)		(530,809	)		(3,448,823	)
Price risk management activities, net		(342,778	)		(15,798,359	)		—
Other receivables		(2,265,077	)		—			1,004,464
Inventory		—			—			(54,988	)
Other current assets		(344,940	)		(340,060	)		40,803
Accounts payable		2,161,325			1,243,817			373,381
Accrued expenses		1,044,447			(2,037,794	)		(902,185	)
Net cash provided by operating activities		39,554,538			1,372,287			16,087,318

Investing activities
Additions to property and equipment		(74,053	)		(132,371	)		(8,486,055	)
Additions to natural gas and oil properties		(18,174,285	)		(12,821,192	)		(28,896,671	)
Acquisitions of natural gas and oil properties		(100,742,893	)		(3,649,702	)		—
Deposits and prepayments of natural gas and oil properties		(548,271	)		(9,805,460	)		—
Net cash used in investing activities		(119,539,502	)		(26,408,725	)		(37,382,726	)

Financing activities
Proceeds from borrowings		340,300,000			126,200,000			21,360,000
Repayment of debt		(242,700,000	)		(182,867,500	)		—
Proceeds from sale of initial public offering units, net		(54,191	)		89,946,916			—
Proceeds from private placement units		—			41,220,000			—
Distributions to members		(20,128,990	)		(46,846,423	)		(1,375,104	)
Financing costs		(302,563	)		(1,237,948	)		—
Purchase of units for issuance as unit-based compensation		(236,239	)		—			—
Net cash provided by financing activities		76,878,017			26,415,045			19,984,896
Net increase (decrease) in cash and cash equivalents		(3,106,947	)		1,378,607			(1,310,512	)
Cash and cash equivalents, beginning of year		3,109,563			1,730,956			3,041,468
Cash and cash equivalents, end of year	$	2,616		$	3,109,563		$	1,730,956
Supplemental cash flow information:
Cash paid for interest	$	5,039,665		$	8,839,169		$	7,233,549
Non-cash financing and investing activities:
Asset retirement obligations	$	1,882,397		$	177,153		$	187,638
Derivative assets assumed in acquisition of natural gas and oil properties	$	2,467,573		$	—		$	—
Initial contribution of assets	$	—		$	3,289,055		$	—
Issuance of common units for acquisition of natural gas and oil properties	$	21,360,000		$	—		$	—
Transfer of deposit for acquisition of natural gas and oil properties	$	7,830,000		$	—		$	—

See accompanying notes to consolidated financial statements.

Vanguard Natural Resources, LLC and Subsidiaries

Consolidated Statements of Other Comprehensive Income (Loss)

For the Years Ended December 31,

	Vanguard						Vanguard Predecessor
	2008			2007			2006

Net income (loss)	$	(3,751,348	)	$	2,649,308		$	26,554,846

Net income (losses) from derivative contracts:
Unrealized mark-to-market gains (losses) arising during the period		2,747,150			(9,644,224	)		—
Reclassification adjustments for settlements		(492,923	)		(414,724	)		—
Other comprehensive income (loss)		2,254,227			(10,058,948	)		—

Comprehensive income (loss)	$	(1,497,121	)	$	(7,409,640	)	$	26,554,846

See accompanying notes to consolidated financial statements.

Vanguard Natural Resources, LLC and Subsidiaries

Notes to Consolidated Financial Statements

December 31, 2008

Description of the Business:

Vanguard Natural Resources, LLC is a publicly traded limited liability company focused on the acquisition and development of mature, long-lived natural gas and oil properties in the United States. Through our operating subsidiaries, we own properties in the southern portion of the Appalachian Basin, primarily in southeast Kentucky and northeast Tennessee, in the Permian Basin, primarily in west Texas and southeastern New Mexico, and in south Texas.

References in this report to (1) “us,” “we,” “our,” “the Company,” “Vanguard” or “VNR” are to Vanguard Natural Resources, LLC and its subsidiaries, including Vanguard Natural Gas, LLC (“VNG”), Trust Energy Company, LLC (“TEC”), VNR Holdings, Inc. (“VNRH”), and Ariana Energy, LLC (“Ariana Energy”) and Vanguard Permian, LLC (“Vanguard Permian”) and (2) “Vanguard Predecessor,” “Predecessor,” “our operating subsidiary” or “VNG” are to Vanguard Natural Gas, LLC.

We were formed in October 2006 and effective January 5, 2007, Vanguard Natural Gas, LLC (formerly Nami Holding Company, LLC) was separated into our operating subsidiary and Vinland Energy Eastern, LLC (“Vinland”). As part of the separation, we retained all of our Predecessor’s proved producing wells and associated reserves. We also retained 40% of our Predecessor’s working interest in the known producing horizons in approximately 95,000 gross undeveloped acres and a contract right to receive approximately 99% of the net proceeds from the sale of production from certain producing gas and oil wells. In the separation, Vinland was conveyed the remaining 60% of our Predecessor’s working interest in the known producing horizons in this acreage, and 100% of our Predecessor’s working interest in depths above and 100 feet below our known producing horizons. Vinland operates all of our existing wells in Appalachia and all of the wells that we drilled in Appalachia. We refer to these events as the “Restructuring.”

In October 2007, we completed our initial public offering (“IPO”) of 5.25 million units representing limited liability interests in VNR at $19.00 per unit for net proceeds of $92.8 million after deducting underwriting discounts and fees of $7.0 million. In addition, we incurred offering costs of $2.8 million in connection with the IPO. The proceeds were used to reduce indebtedness under our Credit Facility by $80.0 million and the balance was used for the payment of accrued distributions to pre-IPO unitholders and the payment of a deferred swap obligation.

1. Summary of Significant Accounting Policies

(a)	Basis of Presentation and Principles of Consolidation:

The consolidated financial statements as of and for the years ended December 31, 2008 and 2007 include the accounts of VNR and its wholly owned subsidiaries. In conjunction with the Restructuring, Nami Resources Company, LLC conveyed its assets to Vinland or TEC as appropriate and as of January 5, 2007 is not a wholly-owned subsidiary of VNG and therefore is not consolidated in these consolidated financial statements. The consolidated financial statements as of and for the year ended December 31, 2006 are based on the annual audited financial statements of VNG prior to the Restructuring. As such, these periods are labeled Vanguard Predecessor and are separated from VNR financial data by a bold black line.

Our consolidated financial statements are prepared in accordance with U.S. generally accepted accounting principles and include the accounts of all subsidiaries after the elimination of all significant intercompany accounts and transactions. Additionally, our financial statements for prior periods include reclassifications that were made to conform to the current period presentation. Those reclassifications did not impact our reported net income or member’s equity.

(b)	Recently Adopted Accounting Pronouncements:

In September 2006, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 157 “Fair Value Measurements” (“SFAS 157”). SFAS 157 introduces a framework for measuring fair value and expands required disclosure about fair value measurements of assets and liabilities. On February 6, 2008, the FASB issued a final FASB Staff Position (“FSP”) No. FAS 157-b, “Effective Date of FASB Statement No. 157.” This FSP delays the effective date of SFAS 157 for all non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis. In addition, the FSP removes certain leasing transactions from the scope of SFAS 157. The effective date of SFAS 157 for non-financial assets and non-financial liabilities has been delayed by one year to fiscal years beginning after November 15, 2008 and interim periods within those fiscal years. SFAS 157 for financial assets and liabilities is effective for fiscal years beginning after November 15, 2007, and the Company prospectively adopted the standard for those assets and liabilities as of January 1, 2008. In adopting SFAS 157, the Company determined that the impact of these additional assumptions on fair value measurements did not have a material effect on financial position or results of operations. The Company is still assessing the potential impact of implementation in 2009 of those portions of the guidance for which the effective date has been deferred by the FASB.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115” (“SFAS 159”), which permits companies to choose, at specified dates, to measure certain eligible financial instruments at fair value. The objective of SFAS 159 is to reduce volatility in preparer reporting that may be caused as a result of measuring related financial assets and liabilities differently and to expand the use of fair value measurements. The provisions of SFAS 159 apply only to entities that elect to use the fair value option. Additional disclosures are also required for instruments for which the fair value option is elected. SFAS 159 is effective for fiscal years beginning after November 15, 2007. No retrospective application is allowed, except for companies that choose to adopt early. At the effective date, companies may elect the fair value option for eligible items that exist at that date, and the effect of the first remeasurement to fair value must be reported as a cumulative-effect adjustment to the opening balance of retained earnings. Effective January 1, 2008, the Company adopted SFAS 159. Because the Company did not elect to apply the provisions of SFAS 159 to any eligible financial instrument, the adoption did not affect the consolidated financial statements.

(c)	New Pronouncements Issued But Not Yet Adopted:

In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS 141(R)”), which replaces FASB Statement No. 141. SFAS 141(R) establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired. The Statement also establishes disclosure requirements that will enable users to evaluate the nature and financial effects of the business combination. SFAS 141(R) is effective for acquisitions that occur in an entity’s fiscal year that begins after December 15, 2008, which will be our fiscal year 2009. The impact, if any, on the consolidated financial statements will depend on the nature and size of business combinations that we consummate after the effective date.

In December 2007, the FASB issued SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements—an amendment of ARB No. 51” (“SFAS 160”). SFAS 160 requires that accounting and reporting for minority interests will be recharacterized as non-controlling interests and classified as a component of equity. SFAS 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners. SFAS 160 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding non-controlling interest in one or more subsidiaries or that deconsolidate a subsidiary. This statement is effective as of the beginning of an entity’s first fiscal year beginning after December 15, 2008, which will be our fiscal year 2009. Based upon the December 31, 2008 balance sheet, SFAS 160 would have no impact on the consolidated financial statements.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities” (“SFAS 161”). SFAS 161 is intended to improve financial reporting about derivative instruments and hedging activities by requiring enhanced disclosures to enable investors to better understand their effects on an entity’s financial position, financial performance, and cash flows. SFAS 161 achieves these improvements by requiring disclosure of the fair values of derivative instruments and their gains and losses in a tabular format. It also provides more information about an entity’s liquidity by requiring disclosure of derivative features that are credit risk-related. Finally, it requires cross-referencing within footnotes to enable financial statement users to locate important information about derivative instruments. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. We are currently evaluating the impact of adopting SFAS161on our consolidated financial statements.

In December 2008, the Securities and Exchange Commission or “SEC” published a Final Rule, “Modernization of Oil and Gas Reporting.” The new rule permits the use of new technologies to determine proved reserves if those technologies have been demonstrated to lead to reliable conclusions about reserves volumes. The new requirements also will allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (a) report the independence and qualifications of its reserves preparer or auditor; (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit; and (c) report oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices. The use of average prices will affect future impairment and depletion calculations. The new disclosure requirements are effective for annual reports on Forms 10-K for fiscal years ending on or after December 31, 2009. A company may not apply the new rules to disclosures in quarterly reports prior to the first annual report in which the revised disclosures are required. The Company has not yet determined the impact of this Final Rule, which will vary depending on changes in commodity prices, on its disclosures, financial position or results of operations.

(d)	Cash Equivalents:

The Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents.

(e)	Accounts Receivable and Allowance for Doubtful Accounts:

Accounts receivable are customer obligations due under normal trade terms and are presented on the consolidated balance sheets net of allowances for doubtful accounts. We establish provisions for losses on accounts receivable if we determine that we will not collect all or part of the outstanding balance. We regularly review collectibility and establish or adjust our allowance as necessary using the specific identification method.

(f)	Inventory:

Materials, supplies and commodity inventories are valued at the lower of cost or market. The cost is determined using the first-in, first-out method. Inventories are included in other current assets in the accompanying consolidated balance sheets.

(g)	Property and Equipment:

Property and equipment is recorded at cost. Major property additions, replacements and betterments are capitalized, while maintenance and repairs that do not extend the useful life of an asset are expensed as incurred. Depreciation is recorded using the straight-line method over the respective estimated useful lives of our assets.

The estimated useful lives of our property and equipment are as follows:

	Lives (Years)
Furniture and fixtures		3-5
Machinery and equipment		7

Depreciation expense for the years ended December 31, 2008 and 2007 was $56,283 and $36,539, respectively. Our Predecessor’s consolidated statement of operations included depreciation expense in the amount of $693,266 for the year ended December 31, 2006.

(h)	Natural Gas and Oil Properties:

The full cost method of accounting is used to account for natural gas and oil properties. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of natural gas and oil reserves are capitalized. These capitalized amounts include the costs of unproved properties, internal costs directly related to acquisitions, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, both dry hole costs and geological and geophysical costs are capitalized into the full cost pool, which is subject to amortization and subject to ceiling test limitations as discussed below.

Capitalized costs associated with proved reserves are amortized over the life of the reserves using the unit of production method. Conversely, capitalized costs associated with unproved properties are excluded from the amortizable base until these properties are evaluated, which occurs on a quarterly basis. Specifically, costs are transferred to the amortizable base when properties are determined to have proved reserves. In addition, we transfer unproved property costs to the amortizable base when unproved properties are evaluated as being impaired and as exploratory wells are determined to be unsuccessful. Additionally, the amortizable base includes estimated future development costs, dismantlement, restoration and abandonment costs net of estimated salvage values, and geological and geophysical costs incurred that cannot be associated with unevaluated properties or prospects in which we own a direct interest.

Capitalized costs are limited to a ceiling based on the present value of future net revenues using end of period spot prices discounted at 10%, plus the lower of cost or fair market value of unproved properties. If the ceiling is not greater than or equal to the total capitalized costs, we are required to write down capitalized costs to the ceiling. We perform this ceiling test calculation each quarter. Any required write downs are included in the consolidated statements of operations as an impairment charge. Ceiling test calculations include the effects of the portion of natural gas and oil derivative contracts that have been recorded in other comprehensive income. We recorded a non-cash ceiling test impairment of natural gas and oil properties for the year ended December 31, 2008 of $58.9 million as a result of a decline in natural gas and oil prices at the measurement date. This impairment was calculated based on prices of $5.71 per MMBtu for natural gas and $41.00 per barrel of crude oil. No ceiling test impairment was required during 2007 or 2006.

When we sell or convey interests in natural gas and oil properties, they reduce natural gas and oil reserves for the amount attributable to the sold or conveyed interest. We do not recognize a gain or loss on sales of natural gas and oil properties, unless those sales would significantly alter the relationship between capitalized costs and proved reserves. Sales proceeds on insignificant sales are treated as an adjustment to the cost of the properties.

(i)	Asset Retirement Obligations:

Under SFAS No. 143, “Accounting for Asset Retirement Obligations,” we record a liability for asset retirement obligations at fair value in the period in which the liability is incurred if a reasonable estimate of fair value can be made. The associated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method over the assets useful life. Our recognized asset retirement obligation exclusively relates to the plugging and abandonment of natural gas and oil wells. Management periodically reviews the estimate of the timing of well abandonments as well as the estimated plugging and abandonment costs, which are discounted at the credit adjusted risk free rate. These retirement costs are recorded as a long-term liability on the consolidated balance sheet with an offsetting increase in natural gas and oil properties. An ongoing accretion expense is recognized for changes in the value of the liability as a result of the passage of time, which we record in depreciation, depletion, amortization and accretion expense in the consolidated statements of operations.

(j)	Impairment of Long-Lived Assets:

We evaluate the carrying value of long-lived assets, other than investments in natural gas and oil properties, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. For property and equipment used in operations, the determination of impairment is based upon expectations of undiscounted future cash flows, before interest, of the related asset. If the carrying value of the asset exceeds the undiscounted future cash flows, the impairment would be computed as the difference between the carrying value of the asset and the fair value.

(k)	Revenue Recognition and Gas Imbalances:

We apply the sales method of accounting for natural gas and oil revenue. Under this method, revenues are recognized based on the actual volume of natural gas and oil sold to customers, net of any royalty interests owed on the sold product. In the movement of natural gas, it is common for differences to arise between the volume of gas contracted or nominated, and the volume of gas actually received or delivered. These variances or imbalances, are the result of certain attributes of the natural gas commodity and the industry itself. Consequently, the credit given by a pipeline for volumes received from producers may be different than volumes actually delivered by a pipeline. When all necessary information, such as the final pipeline statement for receipts and deliveries are available, the imbalances are resolved and adjustments to the trade accounts receivable or trade accounts payable is recorded as appropriate. The amounts of imbalances were not material at December 31, 2008 and 2007.

(l)	Concentration of Credit Risk:

Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash and cash equivalents, accounts receivable and derivative contracts. We control our exposure to credit risk associated with these instruments by (i) placing our assets and other financial interests with credit-worthy financial institutions, (ii) maintaining policies over credit extension that include the evaluation of customers’ financial condition and monitoring payment history, although we do not have collateral requirements and (iii) netting derivative assets and liabilities for counterparties where we have a legal right of offset.

At December 31, 2008 and 2007, the cash and cash equivalents are concentrated in three financial institutions. We periodically assess the financial condition of these institutions and believe that any possible credit risk is minimal.

The following purchasers accounted for 10% or more of the Company’s natural gas and oil sales for the years ended December 31:

	2008			2007			2006
Seminole Energy Services		52	%		—			—
North American Energy Corporation		—			41	%		32	%
Osram Sylvania, Inc.		15	%		16	%		13	%
BP Energy Company		10	%		11	%		10	%
Dominion Field Services, Inc.		—			13	%		13	%
Eagle Energy Partners, LLC		—			11	%		7	%

This concentration of customers may impact the overall exposure to credit risk in that the customers are in the energy industry and they may be similarly affected by changes in economic or other conditions.

(m)	Use of Estimates:

The preparation of financial statements in conformity with accounting principles generally accepted in the Unites States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved natural gas and oil reserves and related cash flow estimates used in impairment tests of natural gas and oil properties, the fair value of derivative contracts and asset retirement obligations, accrued natural gas and oil revenues and expenses, as well as estimates of expenses related to depreciation, depletion, amortization and accretion. Actual results could differ from those estimates.

(n)	Price Risk Management Activities:

We have entered into derivative contracts with counterparties that are lenders under our reserve-based credit facility, Citibank N.A., BNP Paribas, The Bank of Nova Scotia and Wachovia Bank, N.A., to hedge price risk associated with a portion of our natural gas and oil production. While it is never management’s intention to hold or issue derivative instruments for speculative trading purposes, conditions sometimes arise where actual production is less than estimated which has, and could, result in overhedged volumes. Under fixed-priced commodity swap agreements, the Company receives a fixed price on a notional quantity in exchange for paying a variable price based on a market index, such as the Columbia Gas Appalachian Index (‘TECO Index”), Henry Hub or Houston Ship Channel for natural gas production and the West Texas Intermediate Light Sweet for oil production. Under put option agreements, we pay the counterparty an option premium, equal to the fair value of the option at the purchase date. At settlement date we receive the excess, if any, of the fixed floor over floating rate. Under collar contracts, we pay the counterparty if the market price is above the ceiling price and the counterparty pays us if the market price is below the floor price on a notional quantity. The collars and put options for natural gas are settled based on the NYMEX price for natural gas at Henry Hub or Houston Ship Channel.

Under Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities,” (“SFAS 133”), all derivative instruments are recorded on the consolidated balance sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date. We net derivative assets and liabilities for counterparties where we have a legal right of offset. Changes in the derivatives’ fair value are recognized currently in earnings unless specific hedge accounting criteria are met. For qualifying cash flow hedges, the unrealized gain or loss on the derivative is deferred in accumulated other comprehensive income (loss) in the equity section of the consolidated balance sheets to the extent the hedge is effective. Gains and losses on cash flow hedges included in accumulated other comprehensive income (loss) are reclassified to gains (losses) on commodity cash flow hedges in the period that the related production is delivered. The unrealized gains (losses) on derivative contracts that do not qualify for hedge accounting treatment are recorded as gains (losses) on other commodity derivative contracts in the Consolidated Statements of Operations.

In connection with preparing our quarterly report for third quarter 2008 and discussion with BDO Seidman, LLP, the Company’s new independent registered public accounting firm, management of the Company and the Audit Committee of its Board of Directors concluded that the contemporaneous formal documentation it had prepared to support its initial hedge designations and subsequent assessments for ineffectiveness in connection with the Company’s natural gas and oil hedging program in 2008 did not meet the technical requirements to qualify for cash flow hedge accounting treatment in accordance with SFAS 133. The primary reasons for this determination were that the formal hedge documentation lacked specificity of the hedged cash flow and the quantitative subsequent assessments for ineffectiveness were insufficient. Therefore, the cash flow designations failed to meet hedge documentation requirements for cash flow hedge accounting treatment. In addition, the natural gas derivative swap contracts entered into in 2007 were de-designated as cash flow hedges in the first quarter of 2008 due to an overhedged position in natural gas which made them ineffective. As a result, the Company now recognizes changes in its derivatives’ fair values in current earnings under gains (losses) on other commodity derivative contracts. In addition, the net derivative loss at December 31, 2007 related to the de-designated natural gas derivate swap contracts entered into in 2007 is reported in accumulated other comprehensive income until the month in which the transactions settle, at which time it is recognized as gains (losses) on commodity cash flow hedges.

(o)	Income Taxes:

The Company is treated as a partnership for federal and state income tax purposes. As such, it is not a taxable entity and does not directly pay federal and state income tax. Its taxable income or loss, which may vary substantially from the net income or net loss reported in the consolidated statements of operations, is included in the federal and state income tax returns of each unitholder. Accordingly, no recognition has been given to federal and state income taxes for the operations of the Company. The aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as the Company does not have access to information about each unitholders’ tax attributes in the Company. However with respect to the Company, the Company’s book basis in its net assets exceeded the Company’s net tax basis by $54.7 million at December 31, 2008.

Legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax, including previously non-taxable entities such as limited partnerships and limited liability partnerships. The tax is assessed on Texas sourced taxable margin which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits. Although the Revised Texas Franchise Tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses. The Company recorded a current tax liability of $0.1 million and a deferred tax liability of $0.2 million during the year ended December 31, 2008, respectively. The charges of $0.1 million and $0.2 million are included on our consolidated statements of operations for the year ended December 31, 2008, respectively, as a component of production and other taxes. The Company had no Texas sourced margin tax prior to 2008.

2. Acquisitions

On December 21, 2007, we entered into a Purchase and Sale Agreement with the Apache Corporation for the purchase of certain oil and natural gas properties located in ten separate fields in the Permian Basin of west Texas and southeastern New Mexico. The purchase price for said assets was $78.3 million with an effective date of October 1, 2007. We completed this acquisition on January 31, 2008 for an adjusted purchase price of $73.4 million, subject to customary post closing adjustments. The post closing adjustments reduced the final purchase price to $71.5 million and included a purchase price adjustment of $6.8 million for the cash flow from the acquired properties for the period between the effective date, October 1, 2007, and the final settlement date. The purchase price included a payment of $7.8 million paid by us to the seller in December 2007 and this amount is reported in non-current deposits in our consolidated balance sheet at December 31, 2007. As part of this acquisition, we assumed fixed-price oil swaps covering approximately 90% of the estimated proved developed producing oil reserves through 2011 at a weighted average price of $87.29. The fair value of these fixed-price oil swaps was a liability of $1.1million at January 31, 2008. This acquisition was funded with borrowings under our existing reserve-based credit facility.

On July 18, 2008, we entered into a Purchase and Sale Agreement with Segundo Navarro Drilling, Ltd., a wholly owned subsidiary of the Lewis Energy Group, for the acquisition of certain natural gas and oil properties located in the Dos Hermanos Field in Webb County, Texas. The purchase price for said assets was $53.4 million with an effective date of June 1, 2008. We completed this acquisition on July 28, 2008 for an adjusted purchase price of $51.4 million, subject to customary post-closing adjustments to be determined. This acquisition was funded with $30.0 million of borrowings under our reserve-based credit facility and through the issuance of 1,350,873 common units of the Company valued at $21.4 million. Upon closing this transaction, we assumed natural gas swaps and collars based on Houston Ship Channel pricing for approximately 85% of the estimated gas production from existing producing wells for the period beginning July 2008 through December 2011 which had a fair value of $3.6 million on July 28, 2008.

The following unaudited pro forma results for the years ended December 31, 2008 and 2007 show the effect on the Company’s consolidated results of operations as if the January 2008 acquisition and July 2008 acquisition had occurred on January 1, 2008 and 2007. The pro forma results for the 2008 and 2007 periods presented are the results of combining the statement of operations for the Company with the revenues and direct operating expenses of the oil and gas properties acquired adjusted for (1) assumption of asset retirement obligations and accretion expense for the properties acquired, (2) depletion expense applied to the adjusted basis of the properties acquired using the purchase method of accounting, (3) impairment of natural gas and oil properties, (4)interest expense on added borrowings necessary to finance the acquisition, and (5) the impact of common units issued to partially finance the July 2008 acquisition. The pro forma information is based upon numerous assumptions, and is not necessarily indicative of future results of operations:

	Year Ended December 31,
	2008 Pro forma		2007 Pro forma
	(in thousands, except per unit amounts)
	(unaudited)
Total revenues	$	109,919	$	60,774
Net income	$	1,893	$	6,321
Net income per unit:
Common & Class B units – basic	$	0.15	$	0.77
Common & Class B units – diluted	$	0.15	$	0.77

3. Accounts Receivable and Allowance for Doubtful Accounts

We established an approximate $1.0 million provision for a loss on the entire amount due from a customer which filed for protection under Chapter 11 of the Bankruptcy Code in May 2007. The account receivable was due from oil sales through December 2006 at which time we ceased selling oil to the customer. As the amount of any potential recovery is uncertain, we elected to reserve the entire balance and it is reflected as bad debt expense on our consolidated statement of operations for the year ended December 31, 2007. We began selling our oil production to a new customer beginning in March 2007.

4. Credit Facilities and Long-Term Debt

Our credit facilities and long-term debt consisted of the following at December 31,:

Description	Interest Rate	Maturity Date	2008		2007
Senior secured reserve-based credit facility	Variable	March 31, 2011	$	135,000,000	$	37,400,000
Total			$	135,000,000	$	37,400,000

Senior Secured Reserve-Based Credit Facility

In January 2007, the Company entered into a four-year revolving reserve-based credit facility (“reserve-based credit facility”) with Citibank, N.A. and BNP Paribas. All of our Predecessor’s outstanding debt was repaid with borrowings under this reserve-based credit facility, including an early prepayment penalty of $2.5 million. The available credit line (“borrowing base”) is subject to adjustment from time to time but not less than on a semi-annual basis based on the projected discounted present value (as determined by independent petroleum engineers) of estimated future net cash flows from certain proved natural gas and oil reserves of the Company. The initial borrowing base was set at $115.5 million and is secured by a first lien security interest in all of the Company’s natural gas and oil properties. However, the borrowing base was subject to $1.0 million reductions per month starting on July 1, 2007 through November 1, 2007, which resulted in a borrowing base of $110.5 million as reaffirmed in November 2007 pursuant to the semi-annual borrowing base redetermination. We applied $80.0 million of the net proceeds from our IPO in October 2007 to reduce our indebtedness under the reserve-based credit facility. In February 2008, our reserve-based credit facility was amended and restated to extend the maturity from January 3, 2011 to March 31, 2011, increase the maximum facility amount from $200.0 million to $400.0 million, increase our borrowing base from $110.5 million to $150.0 million and add two additional financial institutions as lenders, Wachovia Bank, N.A. and The Bank of Nova Scotia. Additional borrowings were made in January 2008 pursuant to the acquisition of natural gas and oil properties in the Permian Basin and in July 2008 an additional $30.0 million was borrowed to fund a portion of the cash consideration paid in the south Texas acquisition. In May 2008, our reserve-based credit facility was amended in response to a potential acquisition that ultimately did not occur. As a result, none of the provisions included in this amendment went into effect. In October 2008, we amended our reserve-based credit facility, which set our borrowing base under the facility at $175.0 million pursuant to our semi-annual redetermination and added a new lender, Compass Bank. As a result, indebtedness under the reserve-based credit facility totaled $135.0 million at December 31, 2008. In February 2009 our reserve-based credit facility was amended. See Note 12. Subsequent Events for further discussion.

Interest rates under the reserve-based credit facility are based on Euro-Dollars (LIBOR) or ABR (Prime) indications, plus a margin. Pursuant to the October 2008 reserve-based credit facility amendment our borrowing base utilization grid is as follows:

Borrowing Base Utilization Grid

Borrowing Base Utilization Percentage	<33%			>33% <66%			>66% <85%			>85%
Eurodollar Loans		1.500	%		1.750	%		2.000	%		2.125	%
ABR Loans		0.000	%		0.250	%		0.500	%		0.750	%
Commitment Fee Rate		0.250	%		0.300	%		0.375	%		0.375	%
Letter of Credit Fee		1.000	%		1.250	%		1.500	%		1.750	%

Our reserve-based credit facility contains a number of customary covenants that require us to maintain certain financial ratios, limit our ability to incur additional debt, sell assets, create liens, or make certain distributions. Additionally, our reserve-based credit facility stipulates that a change of control is not permitted, which includes (1) an acquisition of ownership, directly or indirectly, beneficially or of record, by any person or group (within the meaning of the Securities Exchange Act of 1934 and the rules of the SEC) of equity interests representing more than 25% of the aggregate ordinary voting power represented by our issued and outstanding equity interests other than by Majeed S. Nami or his affiliates, or (2) the replacement of a majority of our directors by persons not approved by our board of directors. At December 31, 2008, we were in compliance with our debt covenants.

Our reserve-based credit facility required us to enter into a commodity price hedge position establishing certain minimum fixed prices for anticipated future production equal to approximately 84% of the projected production from proved developed producing reserves from the second half of 2007 through 2011. Also, our reserve-based credit facility required that certain production put option contracts for the years 2007, 2008 and 2009 be put in place to create a price floor for anticipated production from new wells drilled. See Note 5. Price Risk Management Activities for further discussion.

5. Price Risk Management Activities

Under SFAS 133, all derivative instruments are recorded on the consolidated balance sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date. We net derivative assets and liabilities for counterparties where we have a legal right of offset. Changes in the derivatives’ fair value are recognized currently in earnings unless specific hedge accounting criteria are met. For qualifying cash flow hedges, the unrealized gain or loss on the derivative is deferred in accumulated other comprehensive income (loss) in the equity section of the consolidated balance sheets to the extent the hedge is effective. Gains and losses on cash flow hedges included in accumulated other comprehensive income (loss) are reclassified to gains (losses) on commodity cash flow hedges in the period that the related production is delivered. The unrealized gains (losses) on derivative contracts that do not qualify for hedge accounting treatment are recorded as gains (losses) on other commodity derivative contracts in the Consolidated Statements of Operations.

On January 3, 2007, our Predecessor’s natural gas price swaps were terminated, which resulted in the Company incurring swap termination fees of $2.8 million and an additional loss on derivative contracts of approximately $0.8 million included in our consolidated statement of operations for the year ended December 31, 2007. New natural gas derivative contracts were put in place in conjunction with entering into the reserve-based credit facility as described in Note 4. Credit Facility and Long-Term Debt. The Company paid $6.5 million for the put option contracts and payments for the put option contracts and the swap termination fee were funded with borrowings under the reserve-based credit facility. At our election, also in January 2007, we entered into a NYMEX natural gas collar contract. In May 2007, we reset our 2007, 2008 and 2009 natural gas swaps at higher prices and incurred a $7.3 million deferred swap payment obligation with the derivative counterparty which accrued interest daily at 7.36% and was payable at the earlier of five days after the closing of an equity issuance or November 1, 2007. The deferred swap obligation was paid in October 2007 using proceeds from our IPO.

In February 2008, as part of the Permian Basin acquisition, we assumed fixed-price oil swaps covering approximately 90% of the estimated proved developed producing oil production through 2011 at a weighted average price of $87.29. Also, in February 2008, we sold calls (or set a ceiling price) which effectively collared 2,000,000 MMBtu of gas production in 2008 through 2009 which was previously only subject to a put (or price floor), we reset the price on 2,387,640 MMBtu of natural gas swaps settling in 2010 from $7.53 to $8.76 per MMBtu and we entered into a 2012 fixed-price oil swap at $80.00 for 87% of our estimated proved developed production. In April 2008, we reset the price on 800,000 MMBtu of natural gas puts settling from May 1, 2008 to December 31, 2008 from $7.50 to $9.00 per MMBtu at a cost to the Company of $0.3 million which was funded with cash on hand. In July 2008, in connection with the south Texas acquisition, we assumed natural gas swaps and collars based on Houston Ship Channel pricing for approximately 85% of the estimated gas production from existing producing wells for the period beginning July 2008 through December 2011.

In November 2008, in connection with preparing our quarterly report for third quarter 2008 and discussion with BDO Seidman, LLP, the Company’s new independent registered public accounting firm, management of the Company and the Audit Committee of its Board of Directors concluded that the contemporaneous formal documentation it had prepared to support its initial hedge designations and subsequent assessments for ineffectiveness in connection with the Company’s natural gas and oil hedging program in 2008 did not meet the technical requirements to qualify for cash flow hedge accounting treatment in accordance with SFAS 133. The primary reasons for this determination were that the formal hedge documentation lacked specificity of the hedged cash flow and the quantitative subsequent assessments for ineffectiveness were insufficient. Therefore, the cash flow designations failed to meet hedge documentation requirements for cash flow hedge accounting treatment. In addition, the natural gas derivative swap contracts entered into in 2007 were de-designated as cash flow hedges in the first quarter of 2008 due to an overhedged position in natural gas which made them ineffective. As a result, the Company now recognizes changes in its derivatives’ fair values in current earnings under gains (losses) on other commodity derivative contracts. In addition, the net derivative loss at December 31, 2007 related to the de-designated natural gas derivate swap contracts entered into in 2007 is reported in accumulated other comprehensive income until the month in which the transactions settle, at which time it is recognized as gains (losses) on commodity cash flow hedges.

At December 31, 2008, the Company had open commodity derivative contracts covering our anticipated future production as follows:

Swap Agreements

	Gas			Oil
Contract Period	MMBtu	Weighted Average Fixed Price		Bbls	WTI Price
2009	3,629,946	$	9.42	181,500	$	87.23
2010	3,236,040	$	9.10	164,250	$	85.65
2011	2,962,312	$	7.82	151,250	$	85.50
2012	—	$	—	144,000	$	80.00

Put Option Contracts

Contract Period	Volume in MMBtu		Purchased NYMEX Price Floor
2009	840,143		$	7.50

Collars

	Gas								Oil
	MMBtu		Floor			Ceiling			Bbls		Floor			Ceiling
Production Period:
2009		1,000,000		$	7.50		$	9.00		36,500		$	100.00		$	127.00
2010		730,000		$	8.00		$	9.30		—		$	—		$	—

In February 2009, we liquidated our 2012 oil swap and entered into new natural gas derivative contracts. See Note 12. Subsequent Events for further discussion.

Interest Rate Swaps

We enter into interest rate swap agreements, which require exchanges of cash flows that serve to synthetically convert a portion of our variable interest rate exposures to fixed interest rates.

From December 2007 through March 2008, we entered into interest rate swap agreements which effectively fixed the LIBOR rate at 2.66 % to 3.88% on $60.0 million of borrowings. In August 2008, we entered into two interest rate basis swaps which changed the reset option from three month LIBOR to one month LIBOR on the total $60.0 million of outstanding interest rate swaps. By doing so, the company reduced its borrowing cost by 14 basis points on $20.0 million of borrowings for a one year period starting September 10, 2008 and 12 basis points on $40.0 million of borrowings for a one year period starting October 31, 2008. As a result of these two basis swaps, the company chose to de-designate the interest rate swaps as cash flow hedges as the terms of the new contracts no longer matched the terms of the original contracts, thus causing the interest rate hedges to be ineffective. Beginning in the third quarter of 2008, the Company recorded changes in the fair value of its interest rate derivatives in current earnings under gains (losses) on interest rate derivative contracts. The net unrealized gain at June 30, 2008 related to the de-designated cash flow hedges is reported in accumulated other comprehensive income and later reclassified to earnings in the month in which the transactions settle.

At December 31, 2008, the Company had open interest rate derivative contracts as follows:

	Notional Amount		Fixed Libor Rates
Period:
January 1, 2009 to December 10, 2010	$	10,000,000	1.50	%
January 1, 2009 to December 20, 2010	$	10,000,000	1.85	%
January 1, 2009 to January 31, 2011	$	20,000,000	3.00	%
January 1, 2009 to March 31, 2011	$	20,000,000	2.08	%
January 1, 2009 to December 10, 2012	$	20,000,000	3.35	%
January 1, 2009 to January 31, 2013	$	20,000,000	2.38	%
January 1, 2009 to September 10, 2009 (Basis Swap)	$	20,000,000	LIBOR 1M vs. LIBOR 3M
January 1, 2009 to October 31, 2009 (Basis Swap)	$	40,000,000	LIBOR 1M vs. LIBOR 3M

6. Fair Value Measurements

As discussed in Note 1. Summary of Significant Accounting Policies (b), we prospectively adopted SFAS 157 for financial assets and financial liabilities. SFAS 157 does not expand the use of fair value measurements, but rather, provides a framework for consistent measurement of fair value for those assets and liabilities already measured at fair value under other accounting pronouncements. Certain specific fair value measurements, such as those related to share-based compensation, are not included in the scope of SFAS 157. Primarily, SFAS 157 is applicable to assets and liabilities related to financial instruments, to some long-term investments and liabilities, to initial valuations of assets and liabilities acquired in a business combination, and to long-lived assets carried at fair value subsequent to an impairment write down. It does not apply to natural gas and oil properties accounted for under the full cost method, which are subject to impairment based on SEC rules. SFAS 157 applies to assets and liabilities carried at fair value on the consolidated balance sheet, as well as to supplemental fair value information about financial instruments not carried at fair value.

The estimated fair values of the Company’s financial instruments closely approximate the carrying amounts as discussed below:

Cash and cash equivalents, accounts receivable, other current assets, accounts payable, payables to affiliates and accrued expenses. The carrying amounts approximate fair value due to the short maturity of these instruments.

Long-term debt. The carrying amount of our reserve-based credit facility approximates fair value because our current borrowing rate does not materially differ from market rates for similar bank borrowings.

Certain provisions of SFAS 157 have been deferred by the FASB. Accordingly, the Company has not applied the provisions of SFAS 157 to those non-financial assets and liabilities which are not measured at fair value on a non-recurring basis. This includes asset retirement obligations, and any assets other than natural gas and oil properties, for which an impairment write down is recorded during the period. There have been no such asset impairments in the current period.

The Company has applied the provisions of SFAS 157 to assets and liabilities measured at fair value on a recurring basis. This includes natural gas, oil and interest rate derivatives contracts. SFAS 157 provides a definition of fair value and a framework for measuring fair value, as well as expanding disclosures regarding fair value measurements. The framework requires fair value measurement techniques to include all significant assumptions that would be made by willing participants in a market transaction. These assumptions include certain factors not consistently provided for previously by those companies utilizing fair value measurement; examples of such factors would include the company’s own credit standing (when valuing liabilities) and the buyer’s risk premium. In adopting SFAS 157, the Company determined that the impact of these additional assumptions on fair value measurements did not have a material effect on financial position or results of operations. The Company is still assessing the potential impact of implementation in 2009 of those portions of the guidance for which the effective date has been deferred by the FASB.

SFAS 157 defines fair value as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. SFAS 157 provides a hierarchy of fair value measurements, based on the inputs to the fair value estimation process. It requires disclosure of fair values classified according to the “levels” described below. The hierarchy is based on the reliability of the inputs used in estimating fair value and requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The framework for fair value measurement assumes that transparent “observable” (Level 1) inputs generally provide the most reliable evidence of fair value and should be used to measure fair value whenever available. The classification of a fair value measurement is determined based on the lowest level (with Level 3 as lowest) of significant input to the fair value estimation process.

The standard describes three levels of inputs that may be used to measure fair value:


Level 1		Quoted prices for identical instruments in active markets.

Level 2		Quoted market prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs and significant value drivers are observable in active markets.

Level 3		Valuations derived from valuation techniques in which one or more significant inputs or significant value drivers are unobservable. Level 3 assets and liabilities generally include financial instruments whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant management judgment or estimation or for which there is a lack of external corroboration as to the inputs used.

As required by SFAS 157, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. Our commodity derivative instruments consist of swaps and options. We estimate the fair values of the swaps based on published forward commodity price curves for the underlying commodities as of the date of the estimate. We estimate the option value of the contract floors and ceilings using an option pricing model which takes into account market volatility, market prices and contract parameters The discount rate used in the discounted cash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates. In order to estimate the fair value of our interest rate swaps, we use a yield curve based on money market rates and interest rate swaps, extrapolate a forecast of future interest rates, estimate each future cash flow, derive discount factors to value the fixed and floating rate cash flows of each swap, and then discount to present value all known (fixed) and forecasted (floating) swap cash flows. Curve building and discounting techniques used to establish the theoretical market value of interest bearing securities are based on readily available money market rates and interest rate swap market data. To extrapolate future cash flows, discount factors incorporating our counterparties’ and our credit standing are used to discount future cash flows. The Company has classified the fair values of all its derivative contracts as Level 2.

Financial assets and financial liabilities measured at fair value on a recurring basis are summarized below:

	December 31, 2008
	Fair Value Measurements Using							Assets/Liabilities
	Level 1		Level 2			Level 3		at Fair value
Assets:
Commodity derivative contracts	$	—	$	37,932,369		$	—	$	37,932,369
Total derivative instruments	$	—	$	37,932,369		$	—	$	37,932,369

Liabilities:
Interest rate derivative contracts	$	—	$	(2,799,911	)	$	—	$	(2,799,911	)
Total derivative instruments	$	—	$	(2,799,911	)	$	—	$	(2,799,911	)

7. Asset Retirement Obligations

The asset retirement obligations as of December 31 reported on our consolidated balance sheets and the changes in the asset retirement obligations for the year ended December 31, were as follows:

	2008		2007
Asset retirement obligation at January 1,	$	189,711	$	—
Liabilities added during the current period		1,882,397		177,153
Accretion expense		61,683		12,558
Asset retirement obligation at December 31,	$	2,133,791	$	189,711

Accretion expense for the years ended December 31, 2008, 2007 and 2006 was $61,683, $12,558 and $18,307, respectively.

8. Related Party Transactions

In Appalachia, we rely on Vinland to execute our drilling program, operate our wells and gather our natural gas. We reimburse Vinland $60 per well per month (in addition to normal third party operating costs) for operating our current natural gas and oil properties in Appalachia under a Management Services Agreement (“MSA”) which costs are reflected in our lease operating expenses. Also, Vinland receives a $0.25 per mcf transportation fee for producing wells as of January 5, 2007 and $0.55 per mcf transportation fee on any new wells drilled after January 5, 2007 within the area of mutual interest or “AMI.” This transportation fee only encompasses transporting the natural gas to third party pipelines at which point additional transportation fees to natural gas markets apply. These transportation fees are outlined under a Gathering and Compression Agreement (“GCA”) with Vinland and are reflected in our lease operating expenses. For the years ended December 31, 2008 and 2007, costs incurred under the MSA were $0.6 million and $0.5 million, respectively and costs incurred under the GCA were $1.0 million and $1.2 million, respectively. In addition, for the year ended December 31, 2007, Vinland reimbursed us for certain gas sales contracts that were fixed at prices below market in the amount of $1.0 million which is reflected in natural gas and oil sales. A payable of $2.6 million and $3.8 million, respectively, is reflected on our December 31, 2008 and December 31, 2007 consolidated balance sheets in connection with these agreements and direct expenses incurred by Vinland related to the drilling of new wells and operations of all of our existing wells in Appalachia. In September 2008, the Company acquired certain natural gas and oil properties in Appalachia from Vinland for a total purchase price of $4.0 million. The consideration included $3.1 million in cash and $0.9 million reduction in amounts previously due to Vanguard.

9. Commitments and Contingencies

The Company is a defendant in a legal proceeding arising in the normal course of our business. While the outcome and impact of such legal proceedings on the Company cannot be predicted with certainty, management does not believe that it is probable that the outcome of any action will have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flow.

Nami Resources Company, LLC, a subsidiary of our Predecessor that was retained by our founding unitholder in connection with the Restructuring, has been involved in an ongoing dispute with Asher Land and Mineral Company, Ltd., or Asher, pursuant to which Asher claims, among other things, that Nami Resources Company, LLC did not correctly calculate the royalties paid to it and that it failed to abide by certain terms of the leases relating to the coordination of oil and gas development with coal development activities.

On September 8, 2006, Asher filed a complaint in Kentucky state court initiating an action styled Asher Land and Mineral, Ltd. v. Nami Resources Company, LLC, Bell Circuit Court, Civil Action No. 06-CI-00417. In that action, Asher sought monetary damages and court-ordered rescission of the leases. Before a responsive pleading was filed, Asher voluntarily withdrew its complaint and dismissed the case. On December 15, 2006, Asher filed a new action styled Asher Land and Mineral, Ltd. v. Nami Resources Company, LLC, Bell Circuit Court, Civil Action No. 06-CI-00566. In that action, Asher has made the same allegations as in the prior suit and added a claim for an undetermined amount of punitive damages. The parties have exchanged limited initial discovery requests.

On August 29, 2007, Asher filed a motion to add additional defendants to the action cited above, including Vanguard Natural Resources, LLC, Vanguard Natural Gas, LLC and Trust Energy Company, LLC. The Company has filed several motions to be dismissed from this action but to date is still a named defendant in this case. Since that time, no discovery has been sought from the Company by Asher. We have retained separate counsel to represent us in this case as it progresses and intend to continue to vigorously defend the action.

We received a contract right to receive approximately 99% of the net proceeds from the sale of production from certain producing oil and gas wells located within the Asher lease, which accounted for approximately 2.6% of our estimated proved reserves as of December 31, 2008. We did not receive an assignment of any working interest in the Asher lease. The Asher lease and the litigation related thereto were retained by Nami Resources Company, LLC. If the Asher lease is terminated or if Nami Resources Company, LLC’s rights to production under wells of which we have contract rights to receive proceeds are adversely affected, we could lose our contract rights to receive such proceeds or it could be adversely affected.

Nami Resources Company, LLC and Vinland have agreed to indemnify us for all liabilities, judgments and damages that may arise in connection with the litigation referenced above as well as providing for the defense of any such claims. The indemnities agreed to by Nami Resources Company, LLC and Vinland will remain in place until the resolution of the Asher litigation.

10. Common Units and Net Income (Loss) per Unit

In April 2007, the sole member of VNG contributed all of the issued and outstanding common units in VNG to VNR for six million common units representing all of the issued and outstanding common units of VNR at such time. VNR then completed a private equity offering pursuant to which it sold 2.29 million common units to certain private investors for $41.2 million. The proceeds of this private equity offering were used to make a distribution to Majeed S. Nami, VNR’s largest unitholder. Mr. Nami used a portion of these funds to capitalize Vinland and Vinland paid us $3.9 million to reduce outstanding accounts receivable from Vinland. In October 2007, we successfully completed our IPO of 5.25 million common units.

Basic earnings per unit is computed in accordance with SFAS No. 128, “Earnings Per Share” (“SFAS 128”) by dividing net earnings attributable to unitholders by the weighted average number of units outstanding during the period. Diluted earnings per unit is computed by adjusting the average number of units outstanding for the dilutive effect, if any, of unit equivalents. The Company uses the treasury stock method to determine the dilutive effect. At December 31, 2008, the Company had two classes of units outstanding: (i) units representing limited liability company interests (“common units”) listed on NYSE Arca under the symbol VNR and (ii) Class B units, issued to officers and an employee as discussed in Note 11.Unit-Based Compensation. The Class B units participate in distributions and no forfeiture is expected; therefore, all Class B units were considered in the computation of basic earnings per unit. The 175,000 options and phantom units granted to officers under our long-term incentive plan had no dilutive effect; therefore, they have been excluded from the computation of diluted earnings per unit.

In accordance with SFAS 128, dual presentation of basic and diluted earnings per unit has been presented in the consolidated statements of operations for the years ended December 31, 2008 and 2007 for each class of units issued and outstanding at that date: common units and Class B units. Net income (loss) per unit is allocated to the units and the Class B units on an equal basis. No calculation was made for the Vanguard Predecessor period.

11. Unit-Based Compensation

In April 2007, the sole member reserved 460,000 restricted Class B units in VNR for issuance to employees. Certain members of management were granted 365,000 restricted Class B units in VNR in April 2007, which vest two years from the date of grant. In addition, another 55,000 restricted VNR Class B units were issued in August 2007 to two other employees that were hired in April and May, 2007, which will vest after three years. The remaining 40,000 restricted Class B units are available to be awarded to new employees or members of our board of directors as they are retained. In October 2007 and February 2008, four board members were granted 5,000 common units each which will vest after one year. Additionally, in October 2007, two officers were granted options to purchase an aggregate of 175,000 units under our long-term incentive plan with an exercise price equal to the initial public offering price of $19.00 which vested immediately upon being granted, have a term of five years and had a fair value of $0.1 million on the date of grant.

Furthermore, on March 27, 2008, phantom units were granted to two officers in amounts equal to 1% of our units outstanding at January 1, 2008 and the amount to be paid was equal to the appreciation in value of the units, if any, from the date of the grant until the determination date (December 31, 2008), plus cash distributions paid on the units, less an 8% hurdle rate. As of December 31, 2008, there was no appreciation in the value of these units; therefore, no liability or expense was recognized. These common units, Class B units, options and phantom units were granted as partial consideration for services to be performed under employment contracts and thus are subject to accounting for these grants under SFAS 123(R), Share-Based Payment.

The fair value of restricted units issued is determined based on the fair market value of VNR units on the date of the grant. This value is amortized over the vesting period as referenced above. A summary of the status of the non-vested units as of December 31, 2008 is presented below:

	Number of Non-vested Units	Weighted Average Grant Date Fair Value

Non-vested units at December 31, 2007	425,000	$	18.14
Granted	15,000	16.79
Non-vested units at December 31, 2008	440,000	$	18.10

At December 31, 2008, there was approximately $2.3 million of unrecognized compensation cost related to non-vested restricted units. The cost is expected to be recognized over an average period of approximately 0.8 years. Our consolidated statements of operations reflects non-cash compensation of $3.6 million and $2.1 million in the selling, general and administrative expenses line item for the years ended December 31, 2008 and 2007, respectively.

12. Subsequent Events

Our reserve-based credit facility was amended in February 2009 to amend covenants to allow the Company to repurchase up to $5.0 million of our own units.

In February 2009, we liquidated our 2012 oil swap and entered into new 2010 and 2011 natural gas swap and collar transactions. Specifically, an $8.04 and $7.85 fixed price NYMEX natural gas swap for January through September 2010 and April through September 2011, respectively, was executed for 2,000 MMBtu/day. In addition, a 2,000 MMBtu/day NYMEX natural gas collar with a floor price of $7.50 and a ceiling price of $9.00 for October 2010 through March 2011 and October 2011 through December 2011 was executed. These natural gas derivatives were set at prices above the current market by using the proceeds of the liquidation of the 2012 oil swap.

13. Guarantees of Securities to be Registered

We are contemplating the filing of a registration statement on Form S-3 that will include debt securities. The debt securities will be co-issued by our 100% owned finance subsidiary (the “Subsidiary Issuer”) and will be guaranteed by us and all of our subsidiaries other than the Subsidiary Issuer (the “Subsidiary Guarantors” and, together with the Subsidiary Issuer, the “Subsidiaries”). Such guarantees will be full and unconditional as well as joint and several. As the parent company, we have no independent operating assets or operations. In addition, there will be no restrictions on our ability to obtain funds from our Subsidiaries by dividend or loan, and our Subsidiaries will have no restricted assets.

Supplemental Selected Quarterly Financial Information (Unaudited)

Financial information by quarter is summarized below.

	Quarters Ended
	March 31			June 30			September 30		December 31			Total
	(in thousands, except per unit amounts)
2008
Natural gas and oil sales	$	14,002		$	20,852		$	20,839	$	13,157		$	68,850
Gain (loss) on commodity cash flow hedges		416			155			45		(347	)		269
Gain (loss) on other commodity derivative contracts		(21,772	)		(58,045	)		63,364		48,930			32,477
Total revenues		(7,354	)		(37,038	)		84,248		61,740			101,596
Impairment of natural gas and oil properties		—			—			—		58,887			58,887
Other costs and expenses (1)		7,452			8,696			10,495		11,059			37,702
Total costs and expenses		7,452			8,696			10,495		69,946			96,589
Net income (loss)	$	(15,932	)	$	(47,020	)	$	71,809	$	(12,608	)	$	(3,751	)

Net income (loss) per unit:
Common & Class B units – basic	$	(1.42	)	$	(4.19	)	$	5.90	$	(1.00	)	$	(0.32	)
Common & Class B units – diluted	$	(1.42	)	$	(4.19	)	$	5.90	$	(1.00	)	$	(0.32	)

2007
Natural gas and oil sales	$	8,962		$	10,107		$	7,641	$	7,831		$	34,541
Gain (loss) on commodity cash flow hedges		(748	)		(918	)		940		24			(702	)
Total revenues		8,214			9,189			8,581		7,855			33,839
Total costs and expenses (1)		5,128			4,767			5,026		5,694			20,615
Net income (loss)	$	(1,626	)	$	2,240		$	1,051	$	984		$	2,649

Net income (loss) per unit:
Common & Class B units – basic	$	(0.29	)	$	0.38		$	0.18	$	0.10		$	0.39
Common & Class B units – diluted	$	(0.29	)	$	0.38		$	0.18	$	0.10		$	0.39

(1)	Includes lease operating expenses, depreciation, depletion, amortization and accretion, selling, general and administration expenses, bad debt expense and production and other taxes.

Vanguard Natural Resources, LLC and Subsidiaries

Notes to Consolidated Financial Statements

December 31, 2008

Supplemental Natural Gas and Oil Information (Unaudited)

We are a publicly-traded limited liability company focused on the acquisition and development of mature, long-lived natural gas and oil properties in the United States.

Capitalized costs related to natural gas and oil producing activities and related accumulated depletion, amortization and accretion were as follows at December 31:

	2008			2007
Aggregate capitalized costs relating to natural gas and oil producing activities	$	284,446,984		$	135,435,240
Aggregate accumulated depletion, amortization and accretion		(102,178,304	)		(28,451,891	)
Net capitalized costs	$	182,268,680		$	106,983,349
SFAS 143 asset retirement obligations	$	2,133,791		$	189,711

Costs incurred in natural gas and oil producing activities, whether capitalized or expensed, were as follows for the years ended December 31:

	Vanguard				Vanguard Predecessor
	2008		2007		2006
Property acquisition costs	$	128,323,699	$	3,670,561	$	—
Development costs		19,097,637		12,859,838		37,467,066
Total cost incurred	$	147,421,336	$	16,530,399	$	37,467,066

The table above includes capitalized internal costs incurred in connection with the development of natural gas and oil reserves of $3,880,000 in 2006. No internal costs were capitalized in 2008 or 2007. Additionally, capitalized interest of $58,960, $75,672 and $117,097 for the years ended December 31, 2008, 2007 and 2006, respectively, are included in the table above.

Net quantities of proved developed and undeveloped reserves of natural gas and oil and changes in these reserves at December 31, 2008, 2007 and 2006 are presented below. Information in these tables is based on reserve reports prepared by our independent petroleum engineers, Netherland, Sewell & Associates, Inc. for 2008, 2007 and 2006.

	Gas (in Mcf)			Oil (in Bbls)
Net proved reserves
January 1, 2006		107,690,281			463,693
Revisions of previous estimates		(17,529,333	)		(106,630	)
Extensions, discoveries and other		8,205,425			18,623
Production		(4,181,708	)		(32,718	)
December 31, 2006		94,184,665			342,968
Revisions of previous estimates		(31,943,375	)		798
Extensions, discoveries and other		4,544,443			16,725
Purchases of reserves in place		2,387,113			6,165
Production		(4,044,380	)		(30,629	)
December 31, 2007		65,128,466			336,027
Revisions of previous estimates		(5,475,099	)		73,480
Extensions, discoveries and other		5,856,100			25,017
Purchases of reserves in place		20,089,537			4,374,410
Production		(4,361,907	)		(261,575	)
December 31, 2008		81,237,097			4,547,359

Proved developed reserves
December 31, 2006		48,166,327			249,329
December 31, 2007		48,897,929			233,507
December 31, 2008		58,315,899			3,766,394

Revisions of previous estimates of reserves are a result of changes in natural gas and oil prices, production costs, well performance and the reservoir engineer’s methodology. Changes in natural gas prices had a significant impact on proved reserves in 2006. From December 31, 2005 to December 31, 2006, the revisions of previous estimates for natural gas reduced proved reserves by 17.5 Bcf largely due to natural gas prices decreasing from $9.89 per MMbtu to $5.63 per MMbtu at the respective year ends. From December 31, 2006 to December 31, 2007, the revisions of previous estimates for natural gas reduced proved reserves by 31.9 Bcf primarily due to the value of the 60% interest in proved undeveloped properties which was conveyed to Vinland in the Restructuring.

There are numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production and projecting the timing of development expenditures, including many factors beyond our control. The reserve data represents only estimates. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretations and judgment. All estimates of proved reserves are determined according to the rules prescribed by the SEC. These rules indicate that the standard of “reasonable certainty” be applied to proved reserve estimates. This concept of reasonable certainty implies that as more technical data becomes available, a positive, or upward, revision is more likely than a negative, or downward, revision. Estimates are subject to revision based upon a number of factors, including reservoir performance, prices, economic conditions and government restrictions. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of that estimate. Reserve estimates are often different from the quantities of natural gas and oil that are ultimately recovered. The meaningfulness of reserve estimates is highly dependent on the accuracy of the assumptions on which they were based. In general, the volume of production from natural gas and oil properties we own declines as reserves are depleted. Except to the extent we conduct successful development activities or acquire additional properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. There have been no major discoveries or other events, favorable or adverse, that may be considered to have caused a significant change in the estimated proved reserves since December 31, 2008.

Results of operations from producing activities were as follows for the years ended December 31:

	Vanguard						Vanguard Predecessor
	2008			2007			2006
Production revenues (1)	$	62,542,789		$	33,838,191		$	35,976,571
Production costs (2)		(15,799,836	)		(7,119,834	)		(6,670,542	)
Depreciation, depletion and amortization		(14,812,305	)		(8,960,524	)		(8,511,390	)
Impairment of natural gas and oil properties		(58,886,660	)		—			—
Results of operations from producing activities	$	(26,956,012	)	$	17,757,833		$	20,794,639

(1) Production revenues include gains and losses on commodity cash flow hedges in 2008 and 2007 and realized losses on other commodity derivative contracts in 2008 and 2006.

(2) Production cost includes lease operating expenses and production related taxes, including ad valorem and severance taxes.

The standardized measure of discounted future net cash flows relating to our proved natural gas and oil reserves at December 31 is as follows (in thousands):

	Vanguard						Vanguard Predecessor
	2008			2007			2006
Future cash inflows	$	739,560		$	587,639		$	663,604
Future production costs		(258,948	)		(173,485	)		(192,520	)
Future development costs		(50,268	)		(36,842	)		(66,906	)
Future net cash flows		430,344			377,312			404,178
10% annual discount for estimated timing of cash flows		(240,271	)		(226,315	)		(255,357	)
Standardized measure of discounted future net cash flows	$	190,073		$	150,997		$	148,821

For the December 31, 2008 calculations in the preceding table, estimated future cash inflows from estimated future production of proved reserves were computed using year-end prices of $5.71 per MMBtu for natural gas, adjusted by field for energy content, and $41.00 per barrel of oil, adjusted for quality, transportation fees and a regional price differential. We may receive amounts different than the standardized measure of discounted cash flow for a number of reasons, including price changes and the effects of our hedging activities.

The following are the principal sources of change in our standardized measure of discounted future net cash flows (in thousands):

	Year Ended December 31, (1)
	Vanguard						Vanguard Predecessor
	2008			2007			2006
Sales and transfers, net of production costs	$	(53,050	)	$	(26,718	)	$	(29,306	)
Net changes in prices and production costs		(20,385	)		52,625			(231,630	)
Extensions discoveries and improved recovery, less related costs		13,036			10,791			21,110
Changes in estimated future development costs		(12,056	)		18,045			(24,336	)
Previously estimated development costs incurred during the period		19,956			16,531			37,467
Revision of previous quantity estimates		(10,149	)		(75,071	)		(31,726	)
Accretion of discount		15,100			14,882			40,043
Purchases of reserves in place		82,454			4,249			—
Change in production rates, timing and other		4,170			(13,158	)		(33,230	)
Net change	$	39,076		$	2,176		$	(251,608	)

(1) This disclosure reflects changes in the standardized measure calculation excluding the effects of hedging activities.

Grizzly Energy (GRZZP) Inactive 8-KConsolidated Statements of Operations