Pressburg 8K/A Financial Statements and Exhibits | ROAN 16 Oct 06

Exhibit 99.2

BLACKSAND PARTNERS, L.P.

BLACKSAND GP, LLC

BLACKSAND ACQUISITION, LLC

COMBINED FINANCIAL STATEMENTS

As of December 31, 2005 and 2004 and for the years ended December 31, 2005 and 2004

INDEX

		Page

Report of Independent Registered Public Accounting Firm		2
Combined Balance Sheets as of December 31, 2005 and 2004		3
Combined Statements of Operations for the years ended December 31, 2005 and 2004		4
Combined Statements of Comprehensive Loss for the years ended December 31, 2005 and 2004		5
Combined Statements of Changes in Members’ Capital (Deficit) for the years ended December 31, 2005 and 2004		6
Combined Statements of Cash Flows for the periods for the years ended December 31, 2005 and 2004		7
Notes to Combined Financial Statements		8

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners

BlackSand Partners, L.P.

Blacksand GP, LLC

Blacksand Acquisition, LLC

We have audited the accompanying combined balance sheets of BlackSand Partners, L.P., Blacksand GP, LLC and Blacksand Acquisition, LLC, as of December 31, 2005 and 2004, and the related combined statements of income, comprehensive income (loss), changes in partners’ capital, and cash flows for the years ended December 31, 2005 and 2004. 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 audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits 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. 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 audits provided a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the combined financial position of BlackSand Partners, L.P., Blacksand GP, LLC and Blacksand Acquisition, LLC, as of December 31, 2005 and 2004, and the results of their operations and cash flows for the years ended December 31, 2005 and 2004, in conformity with accounting principles generally accepted in the United States of America.

/s/ Hein & Associates, LLP


Denver, Colorado
October 12, 2006

BLACKSAND PARTNERS, L.P.

BLACKSAND GP, LLC

BLACKSAND ACQUISITION, LLC

COMBINED BALANCE SHEETS

	December 31,
	2005			2004
	(in thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	—		$	3,017
Accounts receivable	3,229			2,429
Field inventory	179			76
Prepaid expenses	129			96
Total current assets	3,537			5,618
Oil and Gas Property (successful efforts method):
Proved producing properties	114,061			44,701
Less accumulated depreciation, depletion and amortization	(1,436		)	(2,018		)
Net oil and gas property	112,625			42,683
Property and Equipment:
Field equipment	15,172			14,972
Building	309			305
	15,481			15,277
Less accumulated depreciation, depletion and amortization	(263		)	(908		)
Net property and equipment	15,218			14,369
Other Assets	475			486
Total Assets	$	131,855		$	63,156
LIABILITIES AND PARTNERS’ CAPITAL
Current Liabilities:
Accounts payable	$	214		$	230
Accrued liabilities	1,016			299
Payable to Blacksand Energy, Inc.	—			317
Payable to Hedge Counterparty	—			639
Derivative liability	—			7,652
Total current liabilities	1,230			9,137
Long-Term Liabilities:
Asset retirement obligations	2,293			2,268
Derivative liability	—			19,499
Total long-term liabilities	2,293			21,767
Commitments and Contingencies (Note 5)
Partners’ Capital	128,332			32,252
Total Liabilities and Partners’ Capital	$	131,855		$	63,156

The accompanying notes are an integral part of these financial statements.

BLACKSAND PARTNERS, L.P.

BLACKSAND GP, LLC

BLACKSAND ACQUISITION, LLC

COMBINED STATEMENTS OF OPERATIONS

	Year Ended
	December 31, 2005		December 31, 2004
	(in thousands)
Revenues:
Oil sales	$	27,431	$	18,473
Plant product sales	923		926
Electricity sales	1,122		1,388
Other	389		137
Total revenues	29,865		20,924

Expenses:
Field expense	7,312		6,993
Depreciation, depletion and amortization	2,735		1,623
Administrative costs	1,717		1,461
Interest expense	7		6
Total expenses	11,771		10,083

Net Income (Loss)	$	18,094	$	10,841

The accompanying notes are an integral part of these financial statements.

BLACKSAND PARTNERS, L.P.

BLACKSAND GP, LLC

BLACKSAND ACQUISITION, LLC

STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

	Year Ended
	December 31, 2005		December 31, 2004
	(in thousands)

Net Income (Loss)	$	18,094	$	10,841

Unrealized Loss on Oil Hedging Contract	—		(18,930		)

Other Comprehensive Income (Loss)	$	18,094	$	(8,089	)

The accompanying notes are an integral part of these financial statements.

BLACKSAND PARTNERS, L.P.

BLACKSAND GP, LLC

BLACKSAND ACQUISITION, LLC

COMBINED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

	General Partner			Limited Partner			Total
	(in thousands)

Balance, January 1, 2004	$	2,575		$	48,805		$	51,380

Contributions	48			971			1,019
Distributions	(602		)	(11,455		)	(12,057		)
Comprehensive loss	(404		)	(7,685		)	(8,089		)

Balance, December 31, 2004	$	1,617		$	30,636		$	32,253

Contributions	1,357			120,857			122,214
Distributions	(1,515		)	(42,714		)	(44,229		)
Comprehensive income	447			17,647			18,094

Balance, December 31, 2005	$	1,906		$	126,426		$	128,332

The accompanying notes are an integral part of these financial statements.

BLACKSAND PARTNERS, L.P.

BLACKSAND GP, LLC

BLACKSAND ACQUISITION, LLC

COMBINED STATEMENTS OF CASH FLOWS

	Year Ended
	December 31, 2005			December 31, 2004
	(in thousands)

Cash Flows from Operating Activities:
Net Income (Loss)	$	18,094		$	10,841
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization	2,735			1,623
Non-cash expense	33			57
Changes in current assets and liabilities:
Receivables	(800		)	(542		)
Prepaid expenses	(46		)	20
Field inventory	(103		)	59
Derivative liability	21,103			—
Payables	63			768
Net cash provided by operating activities	19,976			12,826

Cash Flows from Investing Activities:
Payment for purchase of Blacksand Acquisition	(86,451		)	—
Property additions:
Proved oil and gas properties	(84		)	(350		)
Field equipment	(16		)	(577		)
Net cash used in investing activities	(86,551		)	(927		)

Cash Flows from Financing Activities:
Capital contributions	95,065			1,019
Distributions	(31,507		)	(12,057		)
Net cash provided by (used in) financing activities	63,558			(11,038		)

Net Increase in Cash and Cash Equivalents	(3,017		)	861

Cash and Equivalents, at beginning of period	3,017			2,156

Cash and Equivalents, at end of period	$	—		$	3,017

Non-Cash Transaction:
Additions to asset retirement obligations	$	—		$	522
Transfer of hedges to Blacksand Energy LLC	$	48,254		$	—

BLACKSAND PARTNERS, L.P.

BLACKSAND GP, LLC

BLACKSAND ACQUISITION, LLC

NOTES TO COMBINED FINANCIAL STATEMENTS

1. Organization and Operations:

The combined financial statements and notes thereto presented refer to the combined financial position and results of operations of BlackSand Partners, L.P., Blacksand GP, LLC and Blacksand Acquisition, LLC (collectively referred to as the “Combined Company” or the “Company”).

BlackSand Partners, L.P. (the “Partnership”) was formed on February 28, 2003, to participate in the operation of the Brea Olinda Field in Orange County, California. The Partnership’s operations consist of the acquisition, development, and operation of oil and gas properties.

Blacksand Acquisition, LLC (“Acquisition LLC”) was formed on May 27, 2005, and Blacksand GP, LLC was formed on July 12, 2005.

Until July 21, 2005, the Partnership interests were owned by TIFD III – X LLC (“TIFD III – X”), a wholly owned subsidiary of General Electric Corporation and BlackSand Energy, Inc. (“Energy”). TIDF III – X was the limited partner in the Partnership and Energy was the general partner in the Partnership. Revenues, expenses, and cash flows were allocated in accordance with the ownership interests.

Effective July 21, 2005, Blacksand Energy, LLC (the “LLC”) was formed to finance the purchase of the limited and general partnership interests in the Partnership. In July 2005, the LLC made a capital contribution to Acquisition LLC of approximately $95.1 million. Effective July 21, 2005, Acquisition LLC purchased 100% of the limited and general partnership interests in the Partnership for approximately $86.5 million. As a result of the change of control and as required by SEC Staff Accounting Bulletin No. 54, the purchase by Acquisition LLC was “pushed down”, meaning the post-transaction financial statements of the acquired entity, i.e., the Partnership, reflect the purchase price as the new increased basis of accounting. The purchase price paid was allocated to the assets acquired, primarily the oil and gas properties, at the fair market value at the date of acquisition, as determined using a variety of valuation methods, including third party appraisals. The increase in cost basis is reflected on the balance sheet of the Combined Company at December 31, 2005.

The Company’s revenues are predominantly derived from the sale of oil and related by-products. In addition to its producing oil and gas properties, the Partnership owns a natural gas processing plant and turbines which convert the Partnership’s and third party’s gas production into electricity. The electricity is either sold or used by the Partnership as an energy source for its oil and gas operations.

Management estimates that the value of the Company’s properties is derived from oil and gas reserves and the related production. While the gas plant and turbines have residual values, such values are insignificant when compared to the value of oil and gas reserves.

On August 1, 2006, the Combined Company was acquired by Linn Energy, LLC (“Linn”). See Note 9.

2. Summary of Significant Accounting Policies:

Cash Equivalents –The Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents.

Concentration of Credit Risk – The Company’s cash equivalents and short-term investments are exposed to concentrations of credit risk. The Company manages and controls this risk by investing these funds with major financial institutions.

The Company’s receivables are comprised of amounts due it from the sale of its oil production and sundry products. The amounts are due from a limited number of entities and collectability is dependent upon the financial wherewithal of each individual company as well as the general

economic conditions of the industry. The receivables are not collateralized. However, to date the Company has had no bad debts.

Inventory – Inventory consists of pipe and tubular goods intended to be used in the Company’s oil and gas operations, and is stated at the lower of cost or market using the average cost valuation method.

Oil and Gas Producing Activities – The Company follows the “successful efforts” method of accounting for its oil and gas properties. Under this method of accounting, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well has not found proved reserves, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive. Exploratory expenses, including geological and geophysical expenses and annual delay rentals for oil and gas leases, are charged to expense as incurred.

Capitalized costs are evaluated in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 144, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of.” In applying this statement, the expected undiscounted future net cash flows are compared to the capitalized costs on a field-by-field basis at the end of the period. If impairment is indicated, the asset is written down to its estimated fair value based on expected future discounted cash flows. As of December 31, 2005 and 2004, the Company had no impairment on its oil and gas properties.

Depreciation and depletion of capitalized costs for developed oil and gas properties is provided using the units-of-production method based upon proved reserves for each field. Depletion expense for oil and gas producing properties was $2.0 million and $1.1 million for the years ended December 31, 2005 and 2004, respectively.

Gains and losses are generally recognized upon the sale of interests in proved oil and gas properties based on the portion of the property sold. For sales of partial interests in unproved properties, the Company treats the proceeds as a recovery of costs with no gain recognized until all costs have been recovered.

Other Property and Equipment – Other property and equipment such as office furniture, tank farms, turbines, computers and buildings is recorded at cost. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repairs are expensed when incurred. Depreciation is provided using the straight-line method over the estimated useful lives of the assets, from three to 30 years. Gains and losses on dispositions of other property and equipment are included in the results of operations. Depreciation expense on other property and equipment was $0.6 million and $0.5 million for the years ended December 31, 2005 and 2004, respectively.

Accounting Estimates – The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in these financial statements and the accompanying notes. The Company’s estimates include its estimated useful lives of assets and future asset retirement obligation. The actual results could differ from those estimates.

The Company’s provisions for depreciation, depletion, and impairment of the capitalized costs of developed oil and gas properties are determined based upon the estimated quantities of proved oil and gas reserves. Management emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties.

Accordingly, it is reasonably possible these estimates will materially change in the near term as additional information becomes available.

Income Taxes – The entities that are included in the Combined Company are limited liability companies. Accordingly, no provision for income taxes has been recorded as the income, deductions, expenses and credits of the Combined Company are reported on the individual tax returns of the partners of the Combined Company.

Revenue Recognition – Revenue is recorded on the accrual basis as sales are made and deliveries occur. Oil and gas revenues included realized gains and losses on derivatives.

Major Customers – During the years ended December 31, 2005 and 2004, the Company sold all of its oil to a single customer. Oil sales represent approximately 92% and 95% of total revenue during years ended December 31, 2005 and 2004, respectively. The Company does not consider this a risk as there is a readily available supply of purchasers in the area.

Oil Hedge Contracts – In connection with the initial capitalization of the Partnership, the Partnership was required to enter into long-term oil hedge contracts to manage its exposure to oil price volatility. Due to significant changes in the price of oil since the inception of the partnership, these contracts have resulted in significant realized and unrealized losses. The Partnership utilized oil hedges that compare a fixed oil price with a monthly average NYMEX oil price and the difference was settled in cash each month. The Partnership accounted for these contracts as cash flow hedges under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activity.” The resulting realized gains or losses were recognized in the statement of operations. The Partnership recorded realized losses on hedging of $6.7 million and $6.2 million for the years ended December 31, 2005 and 2004, respectively, which have been recorded as a reduction to oil revenue on the statement of operations. The Partnership accounted for the unrealized changes in fair value of designated hedges, to the extent that the hedge is effective, as a component of Other Comprehensive Income in the Members’ Capital (Deficit) section of the balance sheet.

As noted above, effective July 21, 2005, the LLC was formed to fund Acquisition LLC’s purchase of 100% of the limited and general partnership interests in the Partnership. At July 21, 2005, the LLC assumed all hedge liabilities previously held by the Partnership and entered into a transaction to buy-up the fixed price on those hedges at the approximate market rate of $15.5 million, which represented a realized loss of LLC. Subsequently, in August 2006, in connection with the acquisition of the Combined Company by Linn, the LLC liquidated its hedge positions. See Note 9.

3. Asset Retirement Obligations:

The Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” The estimated fair value of the future costs associated with dismantlement, abandonment and restoration of oil and gas properties and associated equipment is recorded when incurred. The net estimated costs are discounted to present values using a risk-adjusted rate over the estimated economic life of the oil and gas properties and capitalized as part of the related asset. The capitalized retirement costs are depreciated/depleted together with the cost of the asset to which they relate. The associated liability is classified in other long-term liabilities in the accompanying balance sheets. The liability is periodically adjusted to reflect (1) new liabilities incurred, (2) liabilities settled during the period, (3) accretion expense, and (4) revisions to estimated future cash flow requirements. The accretion expense is recorded as a component of depreciation, depletion and amortization expense in the accompanying statements of income.

A reconciliation of the Company’s asset retirement obligations is as follows:

	Year Ended
	December 31, 2005			December 31, 2004
	(in thousands)

Beginning of period	$	2,268		$	1,648
Accretion expense	815			98
Revisions to estimate	(790		)	522
End of period	$	2,293		$	2,268

4. Commitments and Contingencies:

Environmental – The Company is subject to extensive federal, state, and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. The Company is not aware of any significant environmental liabilities.

5. Related Party Transactions:

The Combined Company was managed under service agreements with Energy. Through July 20, 2005, Energy was paid a management fee of 8% of net revenues per month. Beginning July 21, 2005, Energy was paid a management fee of $5,000 per month and reimbursed for all expenses incurred on behalf of the Combined Company (primarily payroll cost). Management fee expense is included in ‘Administrative Costs’ on the statement of operations. The total amount of expense reimbursement paid under these agreements during the years ended December 31, 2005 and 2004 was approximately $2.6 million and $1.7 million, respectively. The Company had outstanding payables due to Energy of approximately $48,000 and $0.3 million at December 31, 2005 and 2004, respectively.

Energy owns vehicles that are used for the Company’s operations. The depreciation expense (of

$3,000 per month) incurred by Energy is allocated to the Company monthly, and is charged to lease operating expense. $36,000 was recognized as expense for each of the years ended December 31, 2005 and 2004.

The Combined Company was responsible for reimbursing Energy for certain costs. Although not a party to the lease for office space, the Company reimbursed Energy for the yearly allocation of approximately $72,000.

Under the provisions of the Senior Credit Facility, hedging transactions entered into by the LLC were guaranteed by the oil and gas production of the Partnership. At December 31, 2005, the LLC had derivative liabilities recorded of approximately $47.2 million. Effective August 1, 2006, the LLC liquidated all of its hedge positions. See Note 9.

6. Guarantee of Debt:

Effective July 21, 2005, in order to fund Acquisition LLC’s purchase of 100% of the limited and general partnership interests in the Partnership, the LLC entered into a senior secured four-year bank credit agreement (the “Senior Credit Facility”) with a banking syndicate and a subordinated secured four and one-half year credit facility (the “Subordinated Credit Facility”). In August 2006, the LLC repaid all the debt under both of these facilities. See Note 9.

The Senior Credit Facility and the Subordinated Credit Facility were guaranteed by the Partnership. If the LLC were to have defaulted under the agreements, the Partnership would have been required to remit the outstanding principal and interest at the time of default. The Partnership had no recourse to recover from third parties any of the amounts paid under the guarantee. Upon the occurrence of a triggering event or condition under the guarantee, the Partnership could have liquidated its oil and gas properties to recover all or a portion of the amounts paid under the guarantee. The significant provisions of the facilities and the outstanding balances as of December 31, 2005 are discussed below.

The Senior Credit Facility was a revolving credit facility for up to $200.0 million. The initial borrowing base was established at $80.0 million and the LLC borrowed $72.0 million upon closing. The maximum amount available under Senior Credit Facility was subject to semi-annual re-determinations of the borrowing base in accordance with the lenders’ customary procedures and practices. Interest on amounts borrowed was computed at LIBOR plus a margin of 1.50% to 2.25%, or the higher of the lead bank’s prime rate or the Federal Funds Rate plus 0.50%, plus a margin of 0.50% to 1.25% at the LLC’s option, with margins on the various rate options based on the ratio of credit outstanding to the borrowing base. At December 31, 2005, the LLC had $66.0 million outstanding under the Senior Credit Facility.

The Subordinated Credit Facility was a non-amortizing, second lien credit facility for up to $50.0 million. The initial commitment was $15.0 million and the LLC borrowed the full amount at closing. Interest on amounts borrowed was charged at LIBOR plus 6.00% or the prime rate plus 3.00%. At December 31, 2005, the LLC had $15.0 million outstanding under the Subordinated Credit Facility.

8. Purchase and Sale of Oil and Gas Interests:

On January 17, 2006, the Company sold a 12.5% royalty interest in all of its oil production for $39.8 million. The royalty interest is burdened by production and ad valorem taxes.

On May 17, 2006, effective January 1, 2006, the Company sold a 2.5% royalty interest in all of its oil production for approximately $10.0 million.

On May 4, 2006, the LLC completed no acquisition of oil and gas properties located in California for approximately $17.3 million and created new subsidiary, Brea. The results of Brea are included in the combined financial statements of the Combined Company from the date of acquisition.

In order to facilitate a like-kind exchange of the Company’s royalty sales under Section 1031 of the Internal Revenue Code, the proceeds from the sales have been deposited with a qualified intermediary, which were partially used with the May 2006 acquisition. The remaining balance became taxable to the partners of the LLC. The Company recognized gains on the sales for financial reporting purposes.

9. Subsequent Events:

On August 1, 2006, the LCC paid approximately $65.1 million to cancel all of its hedge contracts. On August 1, 2006, the LLC also repaid all outstanding debt under its Senior Credit Facility and Subordinated Credit Facility (approximately $62.6 million).

On August 1, 2006, Linn acquired the Combined Company for a preliminary aggregate purchase price of approximately $293.3 million. Results of operations and financial position beginning August 1, 2006 will be reported in the consolidated financial statements of Linn.

10. Recently Issued Accounting Standards:

As of January 1, 2006, the Company adopted SFAS No. 154, “Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and SFAS No. 3” (“SFAS 154”). SFAS 154 requires retrospective application of voluntary changes in accounting principles, unless it is impracticable. The implementation of this standard did not have a material impact on the Company’s results of operations and financial condition.

In February 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 155, “Accounting for Certain Hybrid Instruments, (an Amendment of FASB Statements No. 133 and140)” (“SFAS 155”). The standard allows financial instruments that have embedded derivatives to be accounted for as a whole, eliminating the need to bifurcate the derivative from its host, if the holder elects to account for the whole instrument on a fair value basis. SFAS 155 also establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation. The standard is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. The Company is currently evaluating the effect that the implementation of SFAS 155 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In June 2006, the FASB issued Financial Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109” (“FIN 48”). The interpretation sets forth a consistent recognition threshold and measurement attribute, and criteria for subsequently recognizing, derecognizing and measuring uncertain tax positions for financial statement purposes. FIN 48 also requires expanded disclosure with respect to the uncertainty in income taxes. The interpretation is effective for fiscal years beginning after December 31, 2006. The Company is currently evaluating the effect that the adoption of FIN 48 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”), which provides guidance for using fair value to measure assets and liabilities. SFAS 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value and clarifies that for items that are not actively traded, such as certain kinds of derivatives, fair value should reflect the price in a transaction with a market participant, including an adjustment for risk, not just the company’s mark-to-model value. SFAS 157 also requires expanded disclosure of the effect on earnings for items measured using unobservable data. The provisions of SFAS 157 are effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Company is currently evaluating the effect that the

implementation of SFAS 157 will have on its results of operations and financial condition, but does not expect it will have a material impact.

11. Natural Gas and Oil Costs Incurred and Producing Activities (Unaudited):

All costs incurred related to the Partnership’s oil and gas properties are classified as proved properties which have required no significant development costs in 2004 and 2003.

(a) Reserve Quantity Information

Below are the net quantities of net proved developed and undeveloped reserves and proved developed reserves.

	Year Ended
	December 31, 2005				December 31, 2004
	Oil (MBbls)		Gas (MMcf)		Oil (MBbls)		Gas (MMcf)
Proved developed and undeveloped reserves:
Beginning of year	27,587		22,562		25,932		20,967
Net extensions, discoveries, and improved recoveries	2,411		627		689		796
Production	(728	)	(914	)	(738	)	(799	)
Revision of previous estimates	285		(1,063	)	1,704		1,598
End of year	29,555		21,212		27,587		22,562
Proved developed reserves:
Beginning of year	23,404		21,389		21,774		19,797
End of year	25,361		20,069		23,404		21,389

(b) Standardized Measure of Discounted Future Net Cash Flows Relating to Natural Gas and Oil Reserves

The standardized measure of discounted future net cash flows relating to proved natural gas and oil reserves (Standardized Measure) is a disclosure requirement under SFAS No. 69, “Disclosures about Oil and Gas Producing Activities.”

The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the natural gas and oil reserves of the property. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions.

The estimates of future cash flows and future production and development costs are based on period-end sales prices for natural gas and oil, estimated future production of proved reserves and estimated future production and development costs of proved reserves, based on current costs and economic conditions. The estimated future net cash flows are then discounted at a rate of 10%.

The standardized measure of discounted future net cash flows relating to proved natural gas and oil reserves is as follows:

	Year Ended
	December 31, 2005			December 31, 2004
	(in thousands)
Future cash inflows	$	1,430,537		$	971,543
Future production costs	(259,387		)	(218,392		)
Future development and abandonment cost	(11,751		)	(13,148		)
Future net cash flows	$	1,159,399		$	740,003
10% annual discount for estimated timing of cash flows	(879,685		)	(557,878		)
Standardized measure of discounted future net cash flows	$	279,714		$	182,125

Changes in the standardized measure of discounted future net cash flows relating to proved natural gas and oil reserves is as follows:

	Year Ended
	December 31, 2005			December 31, 2004
	(in thousands)
Sales of oil and gas production	$	(21,042	)	$	(12,407	)
Changes in prices and production costs	106,475			42,996
Extensions, discoveries, and improved recoveries	11,038			11,802
Development costs incurred	84			350
Change in estimated development costs	1,313			4,978
Accretion of discount	18,213			12,508
Timing and other	(18,492		)	(3,184		)
Change in standardized measure	$	97,589		$	57,043

Estimates of economically recoverable natural gas and oil reserves and of future net revenues are based upon a number of variable factors and assumptions, all of which are to some degree subjective and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geologic formations and other matters. Actual quantities of natural gas and oil may differ materially from the amounts estimated.

Pressburg (ROAN) Inactive 8-K/AFinancial Statements and Exhibits