Nabors Industries 10K 2011 Annual report | NBR Filing

Exhibit 99.5

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


Report of Independent Registered Public Accounting Firm			2

Audited Consolidated Financial Statements

Consolidated Balance Sheets			3

Consolidated Statement of Operations			4

Consolidated Statement of Member’s Capital			5

Consolidated Statement of Cash Flows			6

Notes to Consolidated Financial Statements			7-28

Supplemental Oil and Gas Disclosures (Unaudited)			29-33

Report of Independent Registered Public Accounting Firm

The Member of NFR Energy LLC

In our opinion, the accompanying consolidated balance sheets and the related consolidated statement of operations, of member’s capital, and of cash flows present fairly, in all material respects, the financial position of NFR Energy LLC and its subsidiaries (the “Company” and “Member”) at December 31, 2011 and December 31, 2010 and the results of their operations and their cash flows for each of the three years then ended in conformity with accounting principles generally accepted in the United States of America. 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 of these statements 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, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 2 to the consolidated financial statements, at December 31, 2009, the Company changed the manner in which its oil and natural gas reserves are estimated as well as the manner in which prices are determined to calculate the ceiling limit on capitalized oil and natural gas costs.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 23, 2012

Consolidated Financial Statements

NFR Energy LLC

Consolidated Balance Sheets

As of December 31, 2011 and 2010


	December 31, 2011			December 31, 2010
	December 31, 2011			December 31, 2010
	(in thousands)
Assets

Current assets:
Cash and cash equivalents	$	4,306		$	4,437
Accounts receivable, net		24,872			16,016
Prepaid expenses and other current assets		5,649			11,010
Derivative instruments		90,838			40,749

Total current assets		125,665			72,212

Property, plant and equipment:
Oil and gas properties (full cost method)
Proved		2,292,875			1,506,565
Unproved		208,230			218,172
Gas gathering and processing equipment		39,763			40,195
Office furniture and fixtures		8,963			6,325

		2,549,831			1,771,257
Accumulated depletion, depreciation and amortization		(1,041,969	)		(934,682	)

Total property, plant and equipment, net		1,507,862			836,575

Other assets:
Derivative instruments		36,920			68,272
Deferred financing costs		14,669			13,024

Total other assets		51,589			81,296

Total assets	$	1,685,116		$	990,083

Liabilities and member’s capital

Current liabilities:
Accounts payable—trade	$	5,221		$	4,160
Accounts payable—related party		12,126			16,058
Royalties payable		8,820			4,904
Accrued interest payable		13,908			13,078
Accrued exploration and development		39,772			48,112
Accrued operating expenses and other		26,647			17,776
Derivative instruments		56			—

Total current liabilities		106,550			104,088

Long term liabilities:
Revolving credit facility		418,000			94,000
Senior notes		346,782			346,153
Asset retirement obligation		15,348			9,213
Derivative instruments		17,409			—
Other long term obligations		854			891

Total long term liabilities		798,393			450,257

Commitments and contingencies
Member’s capital:
Member’s capital		1,267,698			1,065,183
Amounts receivable from member		(41	)		(150	)
Accumulated deficit		(620,585	)		(738,052	)
Accumulated other comprehensive income		130,837			105,722

Total controlling interests member’s capital		777,909			432,703

Noncontrolling interests		2,264			3,035

Total member’s capital		780,173			435,738

Total liabilities and member’s capital	$	1,685,116		$	990,083

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

Consolidated Financial Statements

NFR Energy LLC

Consolidated Statements of Operations

For the Years Ended December 31, 2011, 2010 and 2009


	For the Year Ended December 31,
	2011			2010			2009
	(in thousands)
Revenues
Oil, natural gas and natural gas liquids sales	$	204,989		$	132,062		$	81,937
Gain on derivative instruments		72,517			51,104			60,686
Other revenue		131			1,390			957

Total revenues		277,637			184,556			143,580

Operating expenses
Lease operating expenses		27,113			18,637			18,253
Workover expenses		2,903			848			482
Marketing, gathering, transportation and other		19,717			13,730			6,031
Production and ad valorem taxes		7,775			5,483			4,228
General and administrative expenses		23,543			20,605			17,662
Depletion, depreciation and amortization		82,178			52,490			44,813
Gain on bargain purchase		(99,548	)		(372	)		—
Accretion expense		628			493			407
Bad debt expense		3			18			93
Impairments		29,921			1,711			407,294

Total operating expenses		94,233			113,643			499,263

Other income (expenses)
Interest expense		(39,632	)		(33,468	)		(9,392	)
Gain (loss) on derivative instruments		(25,799	)		2,547			3,793
Other loss		(389	)		(963	)		(8,478	)

Total other expenses		(65,820	)		(31,884	)		(14,077	)


Net income (loss) including noncontrolling interests		117,584			39,029			(369,760	)

Less: Net income applicable to noncontrolling interests		(117	)		(260	)		(516	)

Net income (loss) applicable to controlling interests	$	117,467		$	38,769		$	(370,276	)

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

Consolidated Financial Statements

NFR Energy LLC

Consolidated Statement of Member’s Capital

For the Years ended December 31, 2011, 2010 and 2009

(in thousands)


	Comprehensive			Member’s Capital					Amounts Receivable from			Accumulated			Accumulated Other Comprehensive		Noncontrolling			Total Member’s
	Income			Units		Value			Member			Deficit			Income		Interests			Capital

Balance as of December 31, 2008					855	$	854,144		$	(272	)	$	(406,545	)	$	40,919	$	2,734		$	490,980


Member’s contributions					152		151,838			—			—			—		—			151,838
Amounts receivable from members					—		—			(86	)		—			—		—			(86	)
Distributions—noncontrolling interests					—		—			—			—			—		(475	)		(475	)
Distributions to members for state tax withholding					—		(375	)		—			—			—		—			(375	)
Comprehensive loss
Net loss applicable to controlling interests	$	(370,276	)		—		—			—			(370,276	)		—		—			(370,276	)
Unrealized gain on derivative instruments		14,480			—		—			—			—			14,480		—			14,480

Comprehensive loss applicable to controlling interests		(355,796	)
Net income applicable to noncontrolling interests		516			—		—			—			—			—		516			516

Comprehensive loss including noncontrolling interests	$	(355,280	)

Balance as of December 31, 2009					1,007	$	1,005,607		$	(358	)	$	(776,821	)	$	55,399	$	2,775		$	286,602


Member’s contributions					60		60,000			—			—			—		—			60,000
Amounts receivable from member					—		—			208			—			—		—			208
Distributions to member for state tax withholding					—		(424	)		—			—			—		—			(424	)
Comprehensive income
Net income applicable to controlling interests	$	38,769			—		—			—			38,769			—		—			38,769
Unrealized gain on derivative instruments		50,323			—		—			—			—			50,323		—			50,323

Comprehensive income applicable to controlling interests		89,092
Net income applicable to noncontrolling interests		260			—		—			—			—			—		260			260

Comprehensive income including noncontrolling interests	$	89,352

Balance as of December 31, 2010					1,067	$	1,065,183		$	(150	)	$	(738,052	)	$	105,722	$	3,035		$	435,738


Member’s contributions					203		203,000			—			—			—		—			203,000
Amounts receivable from member					—		—			109			—			—		—			109
Distributions—noncontrolling interests					—		—			—			—			—		(888	)		(888	)
Distributions to member for state tax withholding					—		(485	)		—			—			—		—			(485	)
Comprehensive income
Net income applicable to controlling interests	$	117,467			—		—			—			117,467			—		—			117,467
Unrealized gain on derivative instruments		25,115			—		—			—			—			25,115		—			25,115
Comprehensive income applicable to controlling interests		142,582
Net income applicable to noncontrolling interests		117			—		—			—			—			—		117			117
Comprehensive income including noncontrolling interests	$	142,699

Balance as of December 31, 2011					1,270	$	1,267,698		$	(41	)	$	(620,585	)	$	130,837	$	2,264		$	780,173

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

Consolidated Financial Statements

NFR Energy LLC

Consolidated Statement of Cash Flows

For the Years ended December 31, 2011, 2010 and 2009


	For the Year Ended December 31,
	2011			2010			2009
	(in thousands)
Cash flows from operating activities:
Net income (loss), including noncontrolling interests	$	117,584		$	39,029		$	(369,760	)

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization		82,178			52,490			44,813
Impairments		29,921			1,711			407,294
Loss on sale of asset		600			1,138			8,569
Bad debt expense		3			18			93
Accretion expense		628			493			407
Accrued interest expense		1,458			11,953			(142	)
Rent expense and amortization of deferred rent		(38	)		(321	)		120
Amortization of deferred financing costs		2,817			4,325			1,083
(Gain) loss on derivative instruments		23,844			(1,672	)		(3,793	)
Amortization of option premium		—			3,239			3,918
Amortization of prepaid expenses		2,482			1,762			2,374
Gain on bargain purchase		(99,548	)		(372	)		—
Non cash distributions to member		(485	)		(424	)		(375	)
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable		(8,858	)		3,610			275
Increase in other assets		(6,713	)		(5,393	)		(10,895	)
(Decrease) increase in accounts and royalties payable and accrued liabilities		13,159			(5,871	)		(1,277	)

Net cash provided by operating activities		159,032			105,715			82,704


Cash flows from investing activities:
Oil and gas property additions		(292,648	)		(270,548	)		(311,689	)
Oil and gas property acquisitions		(385,218	)		(64,525	)		—
Cash received from insurance proceeds		—			2,343			—
Gas processing equipment additions		(3,810	)		(246	)		(366	)
Other asset additions		(2,952	)		(425	)		(1,511	)
Cash received from sale of assets		3,706			8,012			5,584

Net cash used in investing activities		(680,922	)		(325,389	)		(307,982	)


Cash flows from financing activities:
Borrowings from revolving credit facility		584,500			176,500			243,500
Proceeds from issuance of senior notes		—			345,597			—
Debt repayments		(260,500	)		(347,000	)		(167,500	)
Deferred financing costs		(4,462	)		(13,683	)		(3,633	)
Capital contributions		203,109			60,208			151,752
Distribution—noncontrolling interests		(888	)		—			(475	)

Net cash provided by financing activities		521,759			221,622			223,644


Net increase (decrease) in cash and cash equivalents		(131	)		1,948			(1,634	)
Cash and cash equivalents, beginning of period		4,437			2,489			4,123

Cash and cash equivalents, end of period	$	4,306		$	4,437		$	2,489

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

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

1. Organization

NFR Energy LLC (NFR or the Company) was established as a Delaware limited liability company in July 2006. Ramshorn Investments, Inc. (Ramshorn), a wholly owned subsidiary of Nabors Industries Ltd. (Nabors), and First Reserve Corporation (First Reserve) have formed NFR as a joint venture to invest in oil and natural gas exploration opportunities within the onshore U.S. market. Ramshorn and First Reserve each committed $500 million in equity. Operations of the Company commenced in 2007. Nabors is one of the largest land drilling contractors in the world, conducting drilling operations and providing well and other services in the U.S. and internationally. First Reserve was founded in 1983 and is the oldest and largest private equity firm specializing in the energy industry. Additional equity commitments were made by certain members of NFR management and the Company’s board of representatives (the Members).

On November 5, 2010, the Company formed NFR Holdings LLC as a Delaware limited liability company (NFR Holdings), at which time NFR Holdings formed NFR Holdings II, LLC as a Delaware limited liability company (NFR Holdings II), and NFR Holdings II formed NFR Merger Sub LLC, as a Delaware limited liability company (Merger Sub). Effective November 5, 2010, Merger Sub merged into the Company, with the Company being the surviving entity (the Merge”) and all of the membership interests of the Company were converted into membership interests in NFR Holdings. In addition to membership interests, all incentive units are maintained and held by NFR Holdings. As a consequence of the Merger, NFR Holdings II LLC is now the single member owner of NFR Energy LLC. The change in legal structure had no direct impact on the financial statements of the Company.

The Company is operating in one segment and is pursuing development and exploration projects in a variety of forms including operated and non-operated working interests, joint ventures, farm-outs, and acquisitions, including conventional and unconventional resources. NFR is a holding company within which it conducts its operations through, and its operating assets are owned by its subsidiaries.

2. Significant Accounting Policies

Basis of Presentation

The Company presents its consolidated financial statements in accordance with U.S. generally accepted accounting principles (GAAP). The accompanying consolidated financial statements include NFR and its subsidiaries. All significant intercompany transactions have been eliminated.

Certain other reclassifications have been made to prior periods to conform to the current presentation.

Change in Accounting Method

In January 2010 the Financial Accounting Standard Board (FASB) issued Accounting Standards Update 2010-03 (ASU 2010-03), “Extractive Industries – Oil and Gas”, which conforms the authoritative guidance to the requirements of the new Securities Exchange Commission (SEC) rules released in December 2008 “Modernization of Oil and Gas Reporting” and are effective December 31, 2009. The principle revisions under the new FASB and SEC authoritative guidance include changing the manner in which oil and gas reserves are estimated as well as the manner in which prices are determined to calculate the ceiling limit on capitalized oil and gas costs. These changes will result in future amounts of depreciation, depletion and amortization (DD&A) being different from what would have been recorded if the new rules had not been mandated. This change in accounting has been treated in these financial statements as a change in accounting principle that is inseparable from a change in accounting estimate. As noted below, reserves and discounted cash flows prepared using the new rules were used in the calculation of DD&A for the fourth quarter of 2009 and the ceiling test at December 31, 2011, 2010 and 2009.

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

2. Significant Accounting Policies (continued)

Cash and Cash Equivalents

All highly liquid investments purchased with an initial maturity of three months or less are considered to be cash equivalents.

Concentration of Credit Risk

The Company’s receivables are comprised of oil and natural gas revenue receivables. The amounts are due from a limited number of entities; therefore, the collectability is dependent upon the general economic conditions of a few purchasers. The Company regularly reviews collectability and establishes the allowance for doubtful accounts as necessary using the specific identification method. The receivables are not collateralized.

Inventory

Inventory, which is included in prepaid expenses and other, consists principally of tubular goods, spare parts, and equipment, that is used in our drilling operations. The inventory balance, net of impairments, was $4.1 million and $9.3 million as of December 31, 2011 and 2010, respectively. Inventory is stated at the lower of weighted-average cost or market. In 2009, the Company revamped its drilling program and moved to a horizontal program due to improved economics versus a vertical program, leaving it with inventory not properly designed for its horizontal drilling activities, in effect, rendering it obsolete. The total impairments relating to obsolete inventory was $1.4 million, $1.7 million and $21.3 million in 2011, 2010 and 2009, respectively, included in “Impairments” in the consolidated statements of operations.

Oil and Natural Gas Properties and Equipment

The Company uses the fullcost method of accounting for its investment in oil and natural gas properties. Under this method, the Company capitalizes all acquisition, exploration, and development costs incurred for the purpose of finding oil and natural gas reserves, including salaries, benefits, and other internal costs directly attributable to these activities. The Company capitalized $3.5 million, $3.5 million and $3.3 million of internal costs in 2011, 2010 and 2009, respectively. Costs associated with production and general corporate activities, however, are expensed in the period incurred. The Company also includes the present value of its dismantlement, restoration, and abandonment costs within the capitalized oil and natural gas property balance (see “Asset Retirement Obligation” below). Unless a significant portion of the Company’s proved reserve quantities is sold (greater than 25%), proceeds from the sale of oil and natural gas properties are accounted for as a reduction to capitalized costs, and gains and losses are not recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas.

Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and natural gas reserves. The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned. The properties are reviewed on a quarterly basis for impairment, and if impaired, are reclassified to proved property and included in the ceiling test and depletion calculations.

Under the full cost method of accounting, a ceiling test is performed on a quarterly basis. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test determines a limit on the book value of oil and natural gas properties. The capitalized costs of proved oil and natural gas properties, net of accumulated DD&A, may not exceed the estimated future net cash flows from proved oil and natural gas reserves, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheets, using the unweighted average first day of the month pricesfor the prior twelve month period for 2011 and 2010 (adjusted for quality and basis differentials) and prices in effect at the end of the period for periods ended before December 31, 2009, held flat for the life of production, discounted at 10%, plus the cost of unevaluated properties and major development projects excluded from the costs being amortized. If capitalized costs exceed this limit, the excess is charged to expense and reflected as “Accumulated depletion, depreciation and amortization”.

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

2. Significant Accounting Policies (continued)

In December 2008, the SEC adopted major revisions to its rules governing oil and natural gas Company reporting requirements. The new rules include provisions that permit the use of new technologies to determine proved reserves, and allow companies to disclose their probable and possible reserves to investors in SEC documents outside of the financial statements. The previous rules limited disclosure to only proved reserves. The new rules also require companies that have an audit performed on their reserves to report the independence and qualifications of the reserve auditor, and file the reserve engineer’s reports when a third party reserve engineer is relied upon to prepare reserve estimates. The new rules also require that oil and natural gas reserves be reported and the full cost ceiling value be calculated using an average price based upon the beginning of the month for the prior twelve-month period. The new reporting requirements are effective for reporting periods ending on or after December 31, 2009. The FASB has issued ASU 2010-03 “Extractive Industries – Oil and Gas” to align its rules for oil and natural gas reserves estimation and disclosure requirements with the SEC’s final rule. The impact of these new rules is reflected below in the Supplemental Oil and Gas Disclosure section.

For the quarter ended December 31, 2011, the Company recognized an impairment of $25.7 million for the carrying value of proved oil and gas properties in excess of the ceiling limitation in 2011 as a result of the decline of natural gas prices. The Company did not recognize any impairment charges relating to oil and natural gas properties in 2010. In first quarter of 2009, the Company recognized an impairment of $155.9 million due to a decrease in the period end price reserve estimates, as required under the former SEC rules. In the fourth quarter of 2009, the Company recognized an impairment of $230.1 million, as a result of the change in the reserve estimates defined under the new SEC rules as noted above.

A decline in natural gas and oil prices subsequent to December 31, 2011, could result in the recognition of additional impairment of the carrying value of proved oil and gas properties in 2012. The average of the historical unweighted first-day-of-the-month prices for the prior twelve month periods ended December 31, 2011 and February 29, 2012 was $4.12 and $3.86 for natural gas, respectively. If, the average of the historical unweighted first-day-of-the-month natural gas prices for the prior twelve month periods remains at current levels or decline further through the end of the first quarter of 2012 due to further price decline, we estimate we would have a further reduction in our asset carrying value for oil and gas properties.

Gathering assets and related facilities, certain other property and equipment, and furniture and fixtures are depreciated using the straight-line method based on the estimated useful lives of the respective assets, generally ranging from 3 to 30 years. Leasehold improvements are amortized over the shorter of their economic lives or the lease term. Repairs and maintenance costs are expensed in the period incurred.

The Company’s DD&A expense on our oil and natural gas properties is calculated each quarter utilizing period end reserve quantities.

During 2010, the Company received insurance proceeds of $2.3 million which were netted with the replacement costs recognized in oil and gas properties.

Capitalized Interest

The Company capitalizes interest costs to oil and natural gas properties on expenditures made in connection with exploration and development projects that are not subject to current depletion. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. The Company capitalized $5.9 million of interest during each of the years ended December 31, 2011 and 2010.

Leases

The Company accounts for leases with escalation clauses and rent holidays on a straight-line basis in accordance with Accounting Standards Codification (ASC) 840, “Leases”. The deferred rent expense liability associated with future lease commitments was reported under the caption “Other long term obligations” on our consolidated balance sheet.

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

2. Significant Accounting Policies (continued)

Derivative Instruments and Hedging Activities

The Company uses derivative financial instruments to achieve a more predictable cash flow from its oil and natural gas production by reducing its exposure to price fluctuations. Such derivative instruments, which are placed with major financial institutions who are participants in the Company’s first lien credit facility (the Credit Agreement) (see Note 5) that the Company believes are minimal credit risks, may take the form of forward contracts, futures contracts, swaps, options, or basis swaps.

At December 31, 2011, with the exception of basis swaps, substantially all of our oil and natural gas derivative contracts are settled based upon reported New York Mercantile Exchange (NYMEX) prices. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty and we have netting arrangements with all of our counterparties that provide for offsetting payables against receivables from separate hedging arrangements with that counterparty. The oil and natural gas reference prices, upon which the commodity derivative contracts are based, reflect various market indices that have a generally high degree of historical correlation with actual prices received by the Company for its oil and natural gas production. Our fixed-price swap, and collar agreements are used to fix the sales price for our anticipated future oil and natural gas production. Upon settlement, the Company receives a fixed price for the hedged commodity and receives or pays our counterparty a floating market price, as defined in each instrument. The instruments are settled monthly. When the floating price exceeds the fixed price for a contract month, the Company pays our counterparty. When the fixed price exceeds the floating price, our counterparty is required to make a payment to the Company. The Company has designated these swap and collar agreements as cash flow hedges.

The Company’s non-designated positions at December 31, 2011 included natural gas basis swaps and both oil and natural gas options. The basis swaps are used to minimize exposure to fluctuating differentials on certain pricing indices against other pricing indices. These instruments are settled monthly. Upon settlement, the Company will pay a floating price on a specified index, and the counterparty will pay a floating price on a different specified index, either of which may include a specified differential. When the Company’s specified index price is less than the counterparties, the counterparty will pay the Company. When the Company’s specified index price is greater than the counterparties specified index price, the Company will pay the counterparty. Additionally, the Company has sold natural gas calls, oil calls, and oil puts. For the oil and natural gas calls, the counterparty has the option to purchase a set volume of the contracted commodity at a contracted price on a contracted date in the future. For the oil puts, the counterparty has the option to sell a contracted volume of the commodity at a contracted price on a contracted date in future.

The Company accounts for these activities pursuant to ASC 815, “Derivatives and Hedging” which requires that derivative instruments other than those that meet the normal purchases and sales exception, be recorded on the balance sheets as either an asset or liability measured at fair value (which is generally based on information obtained from independent parties). ASC 815 also requires that changes in fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Hedge accounting treatment allows unrealized gains and losses on cash flow hedges to be deferred in accumulated other comprehensive income. Realized gains and losses from the Company’s oil and natural gas cash flow hedges are generally recognized in gain (loss) on derivative instruments located in operating income in the consolidated statement of operations when the forecasted transaction occurs. Gains and losses from the change in fair value of derivative instruments that do not qualify for hedge accounting are reported in current-period earnings as a gain (loss) on derivative instruments located in other income in the consolidated statement of operations. If at any time the likelihood of occurrence of a hedged forecasted transaction ceases to be “probable,” hedge accounting under ASC 815 will cease on a prospective basis and all future changes in the fair value of the derivative will be recognized directly in earnings. Amounts recorded in accumulated other comprehensive income prior to the change in the likelihood of occurrence of the forecasted transaction will remain in accumulated other comprehensive income until such time as the forecasted transaction impacts earnings. If

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

2. Significant Accounting Policies (continued)

it becomes probable that the original forecasted production will not occur, then the derivative gain or loss would be reclassified from accumulated other comprehensive income into earnings immediately. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative instruments and the hedged item over time, and any ineffectiveness is immediately reported as unrealized gain or loss on derivative instruments in the consolidated statement of operations.

Deferred Financing Costs

Deferred financing costs of approximately $4.5 million and $13.6 million were incurred during 2011 and 2010, respectively. Deferred financing costs in 2011 include costs associated with the amendment of the Company’s senior secured revolving Credit Facility (the Credit Facility). Deferred financing costs in 2010 include costs to amend the Credit Facility and the issuance of our 2017 Notes (see Note 5). Deferred financing costs are being amortized over the life of the respective obligations.

Financial Instruments

The Company’s financial instruments including cash and cash equivalents, accounts receivable, and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The Company’s Credit Facility is reported at carrying value which approximates fair value based on current rates applicable to similar instruments. Since considerable judgment is required to develop estimates of fair value, the estimates provided are not necessarily indicative of the amounts the Company could realize upon the purchase or refinancing of such instruments. The Company’s derivative instruments are reported at fair value based on Level 2 fair value methodologies and the 2017 Notes are reported at carrying value but further compared to fair value based on Level 2 fair value methodologies (see Note 9).

Asset Retirement Obligation

The Company follows ASC 410, “Asset Retirement and Environmental Obligations”. If a reasonable estimate of the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells can be made, we record a liability (an asset retirement obligation or ARO) on our consolidated balance sheets and capitalize the present value of the asset retirement cost in oil and natural gas properties in the period in which the retirement obligation is incurred. In general, the amount of an ARO and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation assuming the normal operation of the asset, using current prices that are escalated by an assumed inflation factor up to the estimated settlement date, which is then discounted back to the date that the abandonment obligation was incurred using an assumed cost of funds for our company. After recording these amounts, the ARO is accreted to its future estimated value using the same assumed cost of funds and the additional capitalized costs are depreciated on a unit-of-production basis within the related full cost pool. The capitalized costs associated with an ARO are included in the amortization base for purposes of calculating the ceiling test.

The information below reconciles the value of the asset retirement obligation:


	For the year ended December 31,
	2011			2010
	(in thousands)
Beginning Balance	$	9,213		$	8,155
Liabilities incurred		5,693			595
Liabilities settled		(186	)		(30	)
Accretion expense		628			493

Ending Balance	$	15,348		$	9,213

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

2. Significant Accounting Policies (continued)

Revenue Recognition

The Company records revenues from the sales of natural gas and crude oil when the production is produced and sold, and also when collectability is ensured. The Company may have an interest with other producers in certain properties, in which case the Company uses the sales method to account for gas imbalances. Under this method, revenue is recorded on the basis of natural gas actually sold by the Company. The Company also reduces revenue for other owners’ natural gas sold by the Company that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company’s remaining over- and under-produced gas balancing positions are considered in the Company’s proved oil and natural gas reserves. The Company had no material gas imbalances at December 31, 2011 and did not have gas imbalances at December 31, 2010.

Use of Estimates

The preparation of the consolidated financial statements for the Company in conformity with GAAP 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. Actual results could differ from these estimates.

The Company’s consolidated financial statements are based on a number of significant estimates, including oil and natural gas reserve quantities that are the basis for the calculation of DD&A and impairment of oil and natural gas properties, and timing and costs associated with its retirement obligations.

Income Taxes

The Company is a limited liability company treated as a partnership for federal and state income tax purposes with all income tax liabilities and/or benefits of the Company being passed through to the member. As such, no recognition of federal or state income taxes for the Company or its subsidiaries that are organized as limited liability companies have been provided for in the accompanying consolidated financial statements. Any uncertain tax position taken by the member is not an uncertain position of the Company.

In accordance with the operating agreement of NFR, to the extent possible without impairing the Company’s ability to continue to conduct its business and activities, and in order to permit its member to pay taxes on the taxable income of the Company, NFR would be required to make distributions to the member in the amount equal to the estimated tax liability of the member computed as if the member paid income tax at the highest marginal federal and state rate applicable to an individual resident of New York, New York, in the event that taxable income is generated for the member. There was no taxable income and therefore no distributions in 2011, 2010 or 2009.

Recent Accounting Pronouncements

In June 2011, the FASB issued Accounting Standards Update 2011-5, “Presentation of Comprehensive Income” (ASU 2011-5). The FASB has issued new guidance for how companies must present other comprehensive income (OCI) and its components in their financial statements. The guidance applies to all companies that report items of OCI but perhaps is most relevant for companies that have historically presented components of OCI as part of their statement of changes in stockholders’ equity which is no longer an option available under this guidance. ASU 2011-5 is intended to increase the prominence of items that are recorded in OCI and improve comparability and transparency in financial statements and allow for a more prominent evaluation of the effect of OCI on a company’s overall performance. The new guidance described in ASU 2011-05 will supersede the presentation options in Topic 220 (previously known as Statement of Financial Accounting Standards No. 130, Reporting Comprehensive Income). The guidance, however, affects only the presentation of OCI, not the components that must be reported in OCI. ASU 2011-5 is effective for private companies for annual periods beginning after Dec. 15, 2012, and interim and annual periods thereafter. Early adoption is permitted.

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

2. Significant Accounting Policies (continued)

In December 2011, the FASB issued Accounting Standards Update 2011-11, “Disclosures About Offsetting Assets and Liabilities” (ASU 2011-11). ASU 2011-11 amends the disclosure requirements on offsetting assets and liabilities by requiring improved information about financial instruments and derivative instruments that have a right of offset or are subject to an enforceable master netting arrangement or similar agreement. This information will enable users of a company’s financial statements to evaluate the effect or potential effect of netting arrangements on a company’s financial position, including the effect or potential effect of rights of setoff associated with certain financial instruments and derivative instruments. The Company is required to apply the amendments for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. The Companyshould provide the disclosures required by those amendments retrospectively for all comparative periods presented.

In December 2010, the FASB issued Accounting Standards Update 2010-29, “Business Combinations: Disclosure of Supplementary Pro Forma Information for Business Combinations” (ASU 2010-29). ASU 2010-29 clarifies that when presenting comparative pro forma financial statements in conjunction with business combination disclosures, revenue and earnings of the combined entity should be presented as though the business combination that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period. In addition, the update requires adescription of the nature and amount of material, nonrecurring pro forma adjustments included in pro forma revenue and earnings that are directly attributable to the business combination. This update is effective prospectively for business combinations that occur on or after the beginning of the first annual reporting period after December 15, 2010. As ASU 2010-29 relates to disclosure requirements, there will be no impact on the Company’s financial condition or results of operations.

In December 2010, the FASB issued Accounting Standards Update 2010-28, “Intangibles — Goodwill and Other: When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts” (ASU 2010-28). ASU 2010-28 requires step two of the goodwill impairment test to be performed when the carrying value of a reporting unit is zero or negative, if it is more likely than not that a goodwill impairment exists. The requirements of this update are effective for fiscal years beginning after December 15, 2010. The Company does not currently have goodwill.

In February 2010, the FASB issued Accounting Standards Update 2010-09, “Amendments to Certain Recognition and Disclosure Requirements” (ASU 2010-09). This update amends Subtopic 855-10 and gives a definition to SEC filers, and requires SEC filers to assess for subsequent events through the issuance date of the financial statements. This amendment states that an SEC filer is not required to disclose the date through which subsequent events have been evaluated for a reporting period. The Company adopted the provisions of ASU 2010-09 in the period ended March 31, 2010.

In January 2010, the FASB issued Accounting Standards Update 2010-03, “Oil and Gas Reserve Estimation and Disclosures” (ASU 2010-03), which aligns the FASB’s oil and gas reserve estimation and disclosure requirements with the requirements in the Securities and Exchange Commission’s final rule, Modernization of the Oil and Gas Reporting Requirements, which was issued on December 31, 2008 and became effective for the year ended December 31, 2009. We adopted the final rule and ASU 2010-03 effective December 31, 2009, as a change in accounting principle that is inseparable from a change in accounting estimate. Such a change is accounted for prospectively under the authoritative accounting guidance. Comparative disclosures applying the new rules for periods before the adoption of ASU 2010-03 and the final rule are not required.

In December 2008, the SEC issued a final rule, “Modernization of Oil and Gas Reporting”, which is effective January 1, 2010 for reporting 2009 oil and gas reserve information. We adopted the guidance as of December 31, 2009. In January 2010, the FASB issued ASU 2010-03 “Extractive Industries – Oil and Gas” to align its rules for oil and natural gas reserves estimation and disclosure requirements with the SEC’s final rule.

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

2. Significant Accounting Policies (continued)

In January 2010, the FASB issued additional disclosure requirements related to fair value measurements. The guidance requires disclosure of transfers of assets and liabilities between Level 1 and Level 2 in the fair value measurement hierarchy, including the reasons for the transfers and disclosure of major purchases, sales, issuances, and settlements on a gross basis in the reconciliation of the assets and liabilities measured under Level 3 of the fair value measurement hierarchy. The guidance is effective in interim and annual periods beginning after December 15, 2009, except for the Level 3 reconciliation disclosures which are effective for interim and annual periods beginning after December 15, 2010. We adopted the provisions for the quarter ending March 31, 2010, except for the Level 3 reconciliation disclosures included in Note 9, which we adopted in the quarter ending March 31, 2011. Adopting the disclosure requirements for the quarter ending March 31, 2010 did not have an impact on our financial position or results of operations. We do not expect adoption of the Level 3 reconciliation disclosures in 2011 to have any impact on our financial position or results of operations.

3. Significant Customers

During the year ended December 31, 2011, purchases by three companies exceeded 10% of the total oil and natural gas sales of the Company. Purchases by Enbridge Pipeline (East Texas) LP, Texla Energy Management LLC and PVR Midstream LLC accounted for approximately 18%, 15% and 13% of oil and natural gas sales, respectively. During the year ended December 31, 2010, purchases by two companies exceeded 10% of the total oil and natural gas sales of the Company. Purchases by Enbridge Pipeline (East Texas) LP and PVR Midstream LLC accounted for approximately 22% and 23% of oil and natural gas sales, respectively. During the year ended December 31, 2009, purchases by one company exceeded 10% of the total oil and natural gas sales of the Company. Purchases by Enbridge Pipeline (East Texas) LP accounted for approximately 28% of total oil and natural gas sales. The Company believes that the loss of any of the purchasers above would not result in a material adverse effect on its ability to market future oil and natural gas production.

4. Property Acquisitions

Total costs incurred for property acquisitions for 2011 and 2010 were approximately $396.4 million and $129.0 million respectively (excluding related asset retirement costs), of which approximately $31.3 million and $68.8 million related to unproved properties and $365.1 million and $60.2 million related to proved property acquisitions.

On September 26, 2011, the Company signed a Purchase and Sale Agreement for the acquisition of certain oil and gas properties in East Texas which closed on November 14, 2011for $222.0 million, net of purchase price adjustments. This acquisition qualified as a business combination pursuant to ASC 805. NFR recorded a fair value of $235.1 million for proved property and $5.3 million for unproved acreage, which resulted in a bargain purchase gain of $18.4 million that was recorded in the current period’s earnings. The valuation to derive the purchase price included both proved and unproved categories of reserves, expectation for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates considering a depressed natural gas market. The gain was a result of fair market value in excess of the discounted purchase price for the proved developed and undeveloped reserves and unproved acreage.

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed as of the date of acquisition (in millions):

		000,000
Recognized amounts of identifiable assets acquired and liabilities assumed:
Proved developed properties	$	235.1
Unproved leasehold properties		5.3
Bargain purchase gain		(18.4	)

Cash, net of accrued purchase price adjustments	$	222.0

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

4. Property Acquisitions (continued)

The unaudited pro forma results presented below have been prepared to give the effect of the acquisition discussed above on our results of operations for the years ended December 31, 2011 and 2010 as if it had been consummated on January 1, 2010. The unaudited pro forma results do not purport to represent what our actual results of operations would have been if the acquisition had been completed on such date or to project our results of operations for any future date or period.


	Year Ended				Year Ended
	December 31, 2011				December 31, 2010
	Actual		Pro Forma		Actual		Pro Forma
	(in thousands)
*Pro Forma (unaudited***)
Total revenues	$	277,637	$	317,254	$	184,556	$	243,220
Total operating expenses (1)	$	193,781	$	222,918	$	113,643	$	154,260
Net income applicable to controlling interests (1)	$	217,015	$	227,495	$	38,769	$	56,816

(1)	Bargain purchase gain of $99.5 million and $18.4 million, recognized in actual and pro forma operating expenses, respectively, has been excluded from actual and pro forma results above.

On July 5, 2011, NFR entered into an agreement to purchase oil and gas properties in East Texas which closed on August 18, 2011 for $102.6 million, net of purchase price adjustments. This acquisition qualified as a business combination pursuant to ASC 805. NFR recorded a fair value of $142.3 million for proved property and $14.8 million for unproved acreage, which resulted in a bargain purchase gain of $54.5 million that was recorded in the current period’s earnings. The valuation to derive the purchase price included both proved and unproved categories of reserves, expectation for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates considering a depressed natural gas market. The gain was a result of fair market value in excess of the discounted purchase price for the proved developed and undeveloped reserves and unproved acreage, as well as an upward shift in the forward price curve at the time of closing.

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed as of the date of acquisition (in millions):

		00,000
Recognized amounts of identifiable assets acquired and liabilities assumed:
Proved properties	$	142.3
Unproved properties		14.8
Bargain purchase gain		(54.5	)

Cash, net of accrued purchase price adjustments	$	102.6

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

4. Property Acquisitions (continued)


	Year Ended				Year Ended
	December 31, 2011				December 31, 2010
	Actual		Pro Forma		Actual		Pro Forma
	(in thousands)
*Pro Forma (unaudited***)
Total revenues	$	277,637	$	292,128	$	184,556	$	210,549
Total operating expenses (1)	$	193,781	$	202,478	$	113,643	$	131,252
Net income applicable to controlling interests (1)	$	217,015	$	222,809	$	38,769	$	47,153

(1)	Bargain purchase gain of $99.5 million and $54.5 million, recognized in actual and pro forma operating expenses, respectively, has been excluded from actual and pro forma results above.

On January 31, 2011 and February 8, 2011, NFR entered into agreements to purchase working interests in developed and undeveloped acreage in East Texas for $60.7 million and $11.2 million, respectively, for a total adjusted purchase price of $71.8 million,which qualified as a business combination pursuant to ASC 805. NFR recorded a fair value of $87.4 million for developed acreage, which resulted in a bargain purchase gain of $26.7 million that was recorded in the current period’s earnings. The valuation to derive the purchase price included proved categories of reserves, expectation for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates considering a depressed natural gas market. The gain was a result of fair market value in excess of the discounted purchase price for both proved developed and undeveloped reserves and unproved acreage, as well as a result of an upward shift in the forward price curve at the time of closing and receipt of updated production data for the recent producing wells that improved the well economics.

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed as of the date of acquisition (in millions):

		000000
Recognized amounts of identifiable assets acquired and liabilities assumed:
Proved developed properties	$	87.4
Unproved leasehold properties		11.2
Asset retirement obligation		(0.1	)
Bargain purchase gain		(26.7	)

Cash, net of accrued purchase price adjustments	$	71.8

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

4. Property Acquisitions (continued)

The unaudited pro forma results presented below have been prepared to give the effect of the acquisitions discussed above on our results of operations for the years ended December 31, 2011 and 2010 as if it had been consummated on January 1, 2010. The unaudited pro forma results do not purport to represent what our actual results of operations would have been if these acquisitions had been completed on such date or to project our results of operations for any future date or period.


	Year Ended				Year Ended
	December 31, 2011				December 31, 2010
	Actual		Pro Forma		Actual		Pro Forma
	(in thousands)
*Pro Forma (unaudited***)
Total revenues	$	277,637	$	280,519	$	184,556	$	215,385
Total operating expenses (1)	$	193,781	$	194,412	$	113,643	$	132,848
Net income applicable to controlling interests (1)	$	217,015	$	219,266	$	38,769	$	50,393

(1)	Bargain purchase gain of $99.5 million and $26.7 million, recognized in actual and pro forma operating expenses, respectively, has been excluded from actual and pro forma results above.

On October 7, 2010, NFR entered into an agreement to purchase working interests in developed and undeveloped acreage for an adjusted purchase price of $64.5 million, which qualified as a business combination pursuant to ASC 805. NFR recorded a fair value of $64.9 million, which resulted in a bargain purchase gain of $0.4 million that was recorded in the current period’s earnings.

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed as of the date of acquisition (in millions):

		000000
Proved developed and undeveloped properties	$	48.8
Unproved leasehold properties		16.4
Asset retirement obligation		(0.3	)
Bargain purchase gain		(0.4	)

Cash, net of accrued purchase price adjustments	$	64.5

The unaudited pro forma results presented below have been prepared to give effect to the acquisition discussed above on our results of operations as if it had been consummated at the beginning of the comparable period for the year ended December 31, 2009. The unaudited pro forma results do not purport to represent what our actual results of operations would have been if this acquisition had been completed on such date or to project our results of operations for any future date or period.


	Year Ended				Year Ended
	December 31, 2010				December 31, 2009
	Actual		Pro Forma		Actual			Pro Forma
	(in thousands)
*Pro Forma (unaudited***)
Total revenues	$	184,556	$	193,240	$	143,580		$	155,952
Total operating expenses	$	113,643	$	118,627	$	499,263		$	498,390
Net income (loss) applicable to controlling interests	$	38,769	$	42,469	$	(370,276	)	$	(357,031	)

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

4. Property Acquisitions (continued)

In May 2010, NFR entered into an agreement to purchase working interests in 16,339 net undeveloped acres that are prospective for the Haynesville Shale formation in Harrison, Panola and Rusk Counties, Texas, for $42.6 million. None of the acreage was developed or proved at the time of acquisition.

In June 2009, NFR entered into an agreement to acquire the deep rights (Haynesville Shale) with approximately 23,000 net acres in East Texas for a cash purchase price of approximately $60 million as adjusted in accordance with the purchase and sale agreement. The acquisition closed on June 22, 2009. None of the acreage was developed or proved at the time of acquisition.

Additionally, during 2009 NFR acquired leases for acreage in the same areas as the acquisitions listed above for $6.3 million.

Acquired properties that are considered to be business combinations are recorded at their fair value. In determining the fair value of the proved and unproved properties, the Company prepares estimates of oil and natural gas reserves. The Company estimates future prices to apply to the estimatedreserve quantities acquired and the estimated future operating and development costs to arrive at the estimates of future net revenues. For the fair value assigned to proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. To compensate for inherent risks of estimating and valuing unproved reserves, probable and possible reserves are reduced by additional risk-weighting factors.

The results of each of the acquisitions are included in the accompanying consolidated statement of operations since the respective date of purchase.

The Company incurred $274.6 million and $238.8 million in development costs, for 2011 and 2010 respectively. All development related costs were included in proved properties. The Company incurred exploration costs of $0.5 million and $0.2 million in 2011 and 2010, respectively.

The unproved costs associated with the Company’s drilling projects will be transferred to proved properties as the wells are drilled or impaired.

5. Long-Term Debt

Senior Notes

On February 12, 2010, we and our subsidiary NFR Energy Finance Corporation co-issued $200 million in 9.75% senior unsecured notes due 2017 (the 2017 Notes) in a private placement to qualified institutional buyers in accordance with Rule 144A under the Securities Act of 1933 and to persons outside the United States in compliance with Regulation S of the Securities Act of 1933. The 2017 Notes bear interest at a rate of 9.75% per annum, payable semi-annually on February 15 and August 15 each year commencing August 15, 2010. The 2017 Notes were issued at 98.73% of par. In conjunction with the issuance of the 2017 Notes, the Company recorded a discount of $2.53 million to be amortized over the remaining life of the 2017 Notes utilizing the simple interest method. The remaining unamortized discount was $1.85 million and $2.21 million at December 31, 2011 and 2010, respectively. The 2017 Notes were issued under and are governed by an indenture dated February 12, 2010 between the Company, NFR Energy Finance Corporation, the Bank of New York Mellon Trust Company, N.A. as trustee, and the Company’s subsidiaries named therein as guarantors.

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

5. Long-Term Debt (continued)

All of our domestic restricted subsidiaries that guarantee our Credit Facility (other than NFR Energy Finance Corporation) have guaranteed the 2017 Notes on a senior unsecured basis. We utilized the net proceeds from the sale to repay in full our second lien term loan facility, including the associated prepayment premium, which had an outstanding balance of $50.0 million, and to repay approximately $138.0 million in outstanding borrowings under our Credit Facility. The second lien term loan was paid in full and extinguished on February 12, 2010. The Company paid $3.1 million in early termination fees associated with the repayment of the second lien term loan facility. Additionally, the Company expensed $1.8 million of accumulated deferred financing costs associated with the second lien. Both the early termination fee and the amortization of deferred financing costs are included in interest expense on the statement of operations.

On April 14, 2010, we and NFR Energy Finance Corporation issued an additional $150 million in senior notes at 9.75% due 2017. The additional notes were issued at 98.75% of par and bear interest at a rate of 9.75% per annum, payable semi-annually on February 15 and August 15 of each year commencing August 15, 2010. The additional notes were issued under the same indenture as the 2017 Notes issued on February 12, 2010. The Company recorded a discount of $1.87 million to be amortized over the remaining life of the 2017 Notes utilizing the simple interest method. The remaining unamortized discount was $1.37 million and $1.63 million at December 31, 2011 and 2010, respectively. Proceeds were used to repay the entire outstanding balance under our Credit Facility, to purchase assets in East Texas, and to provide working capital for general corporate purposes in 2010.

We may redeem the 2017 Notes, in whole or in part, at any time on or after February 15, 2014, at a redemption price (expressed as a percentage of principal amount) set forth in the following table plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the twelve-month period beginning on February 15 of the years indicated below:


Year	Percentage
2014		104.875
2015		102.438
2016		100.000

At any time before February 15, 2013, we may redeem up to 35% of the aggregate principal amount of the 2017 Notes issued under the indenture with the net cash proceeds of one or more equity offerings at a redemption price equal to 109.750% of the principal amount of the notes to be redeemed, plus accrued and unpaid interest to the date of such redemption, provided that: at least 50% of the aggregate principal amount of the notes remains outstanding immediately after the occurrence of such redemption, and such redemption occurs within 180 days of the date of the closing of any such equity offering.

In addition, we may redeem some or all of the 2017 Notes prior to February 15, 2014 at a redemption price equal to 100% of the principal amount thereof, plus accrued and unpaid interest to the date of such redemption, plus a “make-whole” premium equal to the greater of (1) 1% of the principal amount of such note or (2) the excess of (a) the present value at such time of (i) the redemption price of such note at February 15, 2014, plus (ii) all required interest payments due on the 2017 Notes through February 15, 2014, computed using a discount rate equal to the yield of United States Treasury securities with a constant maturity most nearly equal to the period from the redemption date to February 15, 2014 plus 50 basis points, over (b) the principal amount of such note. Each holder of the notes will also be entitled to require us to repurchase all or a portion of its notes at a purchase price equal to 101% of the principal amount thereof, plus accrued and unpaid interest to the date of such repurchase upon a change of control.

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

5. Long-Term Debt (continued)

The indenture governing the 2017 Notes contains covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to incur additional indebtedness unless the ratio of our adjusted consolidated EBITDA to our adjusted consolidated interest expense over the trailing four fiscal quarters will be at least 2.0 to 1.0 (subject to exceptions for borrowings within certain limits under our Credit Facility); pay dividends or repurchase or redeem equity interests; limit dividends or other payments by restricted subsidiaries that are not guarantors to us or our other subsidiaries; make certain investments; incur liens; enter into certain types of transactions with our affiliates; and sell assets or consolidate or merge with or into other companies. However, if and for as long as the 2017 Notes have an investment grade rating from Standard & Poor’s Ratings Group, Inc. and Moody’s Investors Service, Inc., and no default or event of default exists under the indenture, we will not be subject to certain of the foregoing covenants.

First Lien Revolving Credit Facility

On November 30, 2007, the Company entered into a first lien revolving Credit Facility with a syndicate of banks. BNP Paribas is the Credit Facility’s administration agent. Subsequently, through a series of redeterminations, the Company has amended and restated the Credit Facility. The most recent redetermination on November 14, 2011, increased the borrowing base from $500 million to $625 million. The next redetermination will be in March 2012.

As of December 31, 2011, commitments under the facility are $750 million, the borrowing base is $625 million, and the Credit Facility’s maturity date is April 7, 2016.

Borrowings made under the Credit Facility are guaranteed by first priority perfected liens and security interests on substantially all assets of NFR and its wholly-owned domestic subsidiaries and a pledge of 100% of NFR’s ownership of equity units of all non-wholly owned domestic subsidiaries.

Interest on borrowings under the Credit Facility accrues at variable interest rates at either a Eurodollar rate or an alternate base rate (ABR). The Eurodollar rate is calculated as London Interbank Offered Rate (LIBOR) plus an applicable margin that varies from 1.75% (for periods in which NFR has utilized less than 30% of the borrowing base) to 2.75% (for periods in which NFR has utilized equal to or greater than 90% of the borrowing base). The ABR is calculated as the greater of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.50%, or (c) Eurodollar rate on such day (or if such day is not a business day, the immediately preceding business day) plus 1.5%. The Company elects the basis of the interest rate at the time of each borrowing. In addition, NFR pays a commitment fee of 0.50% under the Credit Facility (quarterly in arrears) for the amount that the aggregate commitments exceed borrowings under the Credit Facility.

Under the Credit Facility, the Company may request letters of credit, provided that the borrowing base is not exceeded or will not be exceeded as a result of issuance of the letter of credit. There were no outstanding letters of credit on December 31, 2011 or December 31, 2010.

The Credit Facility requires the Company to comply with certain financial covenants to maintain (a) a current ratio, defined as a ratio of consolidated current assets (including the unused amount of the total commitments under the Credit Facility, but excluding noncash assets under ASC 815, Derivatives and Hedging (formerly Statements of Financial Accounting Standards (SFAS) 133), to consolidated current liabilities (excluding noncash obligations under ASC 815 and the current maturities under the Credit Facility, determined at the end of each quarter), of not less than 1.0 to 1.0; (b) an interest coverage ratio at the end of each quarter defined as a ratio of EBITDA (as such terms are defined in the Credit Facility) for the period of four fiscal quarters then ending to interest expense for such period of not less than 2.5 to 1.0.

In addition, the Credit Facility contains covenants that restrict, among other things, the Company’s ability to incur other indebtedness, create liens, or sell itsassets; merge with other entities; pay dividends; and make certain investments.

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

5. Long-Term Debt (continued)

At December 31, 2011 and December 31, 2010, NFR was in compliance with its financial debt covenants under the Credit Facility. At December 31, 2011, the outstanding balance under our Credit Facility was $418 million and we were able to incur approximately $207 million of secured indebtedness under our Credit Facility, which amount represents the available portion of our adjusted borrowing base of $625 million. At December 31, 2010, we had available to us $206 million remaining on our borrowing base of $300 million.

Subsequent to the period ended December 31, 2011 through the date of the report on February 23, 2012, the Company has drawn an additional $39 million and has repaid $15 million under our Credit Facility.

In addition to the Credit Agreement, NFR entered into a second lien term loan facility for $50 million on April 28, 2009 which was paid in full and extinguished on February 12, 2010. The average annual interest rate for our term loan borrowings for the twelve months ended December 31, 2009 was 4%, plus an applicable margin of 1,000 basis points, or 14%.

6. Member’s Capital

The Company is authorized to issue one class of units to be designated as “Common Units”. The Units are not represented by certificates. All Common Units are issued at a price equal to $1,000 per unit.

7. Statement of Cash Flows

During the year ended December 31, 2011, the Company’s noncash investing and financing activities consisted of the following transactions:

•

Recognition of an asset retirement obligation for the plugging and abandonment costs related to the Company’s oil and natural gas properties valued at $5.7 million.

•

Recognition of bargain purchase gains of $99.5 million related to the recognition of the fair market value in excess of the consideration paid for proved developed and undeveloped reserves and undeveloped acreage.

•

Changes to oil and natural gas properties of $47.3 million, included in accrued exploration and development.

During the year ended December 31, 2010, the Company’s noncash investing and financing activities consisted of the following transactions:

•

Recognition of an asset retirement obligation for the plugging and abandonment costs related to the Company’s oil and natural gas properties valued at $0.6 million.

•

Recognition of bargain purchase gains of $0.4 million related to the recognition of the fair market value in excess of the consideration paid for proved developed and undeveloped reserves and undeveloped acreage.

•

Changes to oil and natural gas properties of $23.4 million, included in accrued exploration and development.

During the year ended December 31, 2009, the Company’s noncash investing and financing activities consisted of the following transactions:

•

Recognition of an asset retirement obligation for the plugging and abandonment costs related to the Company’s oil and natural gas properties valued at $1.1 million.

•

Changes to oil and natural gas properties of $36.6 million, included in accrued exploration and development.

NFR paid $41.1 million, $20.9 million and $11.8 million for interest during 2011, 2010 and 2009, respectively.

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

8. Derivative Financial Instruments

The Company is exposed to risks associated with unfavorable changes in the market price of natural gas as a result of the forecasted sale of its production and uses derivative instruments to hedge or reduce its exposure to certain of these risks. During 2011, a portion of commodity derivative instruments were designated as cash flow hedges and were subject to cash flow hedge accounting under ASC 815. For the remaining derivative instruments, the Company either did not elect hedge accounting for accounting purposes or did not qualify for hedge accounting treatment and, accordingly, recorded the net change in the mark-to-market valuation of these derivative instruments in the consolidated statement of operations.

During February 2011, the Company restructured its hedge portfolio through the execution of new financial commodity derivative contracts, the restructuring of certain existing derivative contracts and the liquidation of certain derivative contract positions as follows:

•

The Company liquidated and settled all existing hedge contracts covering volumes for the years 2014 and 2015.

•

The Company “re-couponed” all volumes covered by the existing 2013 swap contracts from $7.40/MMBTU to $6.0/MMBTU.

•

The Company added new swap contracts of 9.6BCF at an average price of $6.17/MMBTU and 16.4BCF at an average price of $5.67/MMBTU in 2011 and 2012, respectively. Proceeds from the liquidation and re-couponing actions taken in the bullets above were used to execute the new swap contracts that were added for 2011 and 2012.

The net impact of the restructure on the fair market value of derivative instruments was $2.9 million, recognized in other expenses as a loss on derivative instruments.

During June 2011, the Company added oil contracts to its hedge portfolio. These contracts were executed in order to hedge future oil production against volatility in commodity prices through December 31, 2012.

During December 2011, the Company executed the sale of oil and natural gas options for which a premium was received that will be amortized as the contracts settle each month. The Company used the premium received to execute natural gas swap contracts above market.

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

8. Derivative Financial Instruments (continued)

The following swaps, basis swaps and costless collars were outstanding with associated notional volumes and contracted swap, floor, and ceiling prices that represent hedge weighted average prices for the index specified as of December 31, 2011:


	Future production designated for hedge accounting
	2012		2013
Swaps—Natural Gas
Volume (MMBTU)		24,787,101		32,238,731
Price	$	6.19	$	5.23

Collars—Natural Gas
Volume (MMBTU)		7,233,210		—
Price (Floor/Ceiling)	$	6.00 / $8.65		—

Collars—Oil
Volume (Bbls) (1)		128,100		—
Price (Floor/Ceiling) (1)	$	85.00 / $110.10		—


	Future production not designated for hedge accounting
	2012		2013		2014		2015
Puts—Oil (Sell)
Volume (Bbls) (1)		128,100		—		—		—
Price (1)	$	70.00		—		—		—

Calls—Oil (Sell)
Volume (Bbls)		—		127,750		127,750		127,750
Price		—	$	110.00	$	110.00	$	110.00

Calls—Natural Gas (Sell)
Volume (MMBTU)		—		—		21,900,000		21,900,000
Price		—		—	$	5.25	$	5.25

Basis Swap, NYMEX—East Texas (Houston Ship Channel)
Volume (MMBTU)		4,002,250		1,277,500		—		—
Contract differential (2)	$	0.10 - $0.15	$	0.11 - $0.15		—		—

Basis Swap, NYMEX—TEXOK (NGLP)
Volume (MMBTU)		12,006,750		3,869,000		—		—
Contract differential (2)	$	0.16 - $0.29	$	0.21 - $0.25		—		—

(1)

The Company sold options on a like amount of oil volume as the standard collar noted above. The addition of the put contract establishes a derivative contract structure which will require the Company to make payment to the counterparty if the settlement price for any settlement period is below the put price. The Company will be entitled to a net payment equal to the difference between the floor price of the standard collar ($85) and the additional put price of ($70), should the settlement price be equal to or less than the additional put price. If the settlement price is greater than the additional put price, the result is the same as it would have been with a standard collar contract.

(2)	Basis swaps settle based on NYMEX pricing minus a differential, which is then compared to Inside Federal Energy Regulatory Commission (FERC) for the index on which volumes are being hedged.

For our energy commodity derivative instruments that were designated as cash flow hedges, the portion of the change in the value of derivative instruments that is effective in offsetting changes in expected cash flows (the effective portion) is reported as a component of accumulated other comprehensive income, but only to the extent that they can later offset the undesired changes in expected cash flows during the period in which the hedged cash flows affect earnings. To the contrary, the portion of the change in the value of derivative instruments that is not effective in offsetting undesired changes in expected cash flows (the ineffective portion), as well as any component excluded from the assessment of the effectiveness of the derivative instruments, is required to be recognized currently in earnings. The Company excludes time value associated with costless collars from the assessment of effectiveness.

The Company recorded a short term and a longterm derivative asset of $90.8 million and $36.9 million, respectively, and recorded a short term and a long term derivative liability of $0.1 million and $17.4 million, respectively, related to the fair value of the derivatives instrument’s prices on remaining volumes as of December 31, 2011 after application of ASC 820, “Fair Value Measurements”.

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

8. Derivative Financial Instruments (continued)

The table below provides data about the carrying values of derivatives instruments as of December 31, 2011.


	Assets Derivatives
Derivatives designated as hedging instruments			December 31, 2011			December 31, 2010
			(in thousands)
			Fair Value
Current		Derivative Instruments	$	92,760		$	41,805
Long term		Derivative Instruments		41,007			69,309

Total derivatives designated as hedging instruments			$	133,767		$	111,114


	Assets Derivatives
Derivatives not designated as hedging instruments			December 31, 2011			December 31, 2010
			(in thousands)
			Fair Value
Current		Derivative Instruments	$	—		$	—
Long term		Derivative Instruments		6			5

Total derivatives not designated as hedging instruments			$	6		$	5


	Liabilities Derivatives
Derivatives not designated as hedging instruments			December 31, 2011			December 31, 2010
			(in thousands)
			Fair Value
Current		Derivative Instruments	$	(1,978	)	$	(1,056	)
Long term		Derivative Instruments		(21,502	)		(1,042	)

Total derivatives not designated as hedging instruments			$	(23,480	)	$	(2,098	)

The following table summarizes the cash flow hedge gains and losses and their locations on the Consolidated Balance Sheets as of December 31, 2011 and 2010 and Consolidated Statement of Operations for the year ended December 31, 2011 and 2010:


Derivatives in Cash Flow Hedging Relationships	Amount of Gain Recognized in Other Comprehensive Income (OCI)		Location of Gain Reclassified from Accumulated OCI into Operating Income	Amount of Gain Reclassified from Accumulated OCI into Operating Income		Location of Gain (loss) in Other Income Ineffective Hedges	Amount of Gain (loss) Recognized in Income (Ineffective portion and Amount Excluded from Effectiveness Testing)
	(in thousands)
For the Year Ended December 31, 2011

Derivative			Gain on			Gain on
Instruments	$	97,632	derivative instruments	$	72,517	derivative instruments	$	409

Total	$	97,632		$	72,517		$	409


For the Year Ended December 31, 2010

Derivative			Gain on			Loss on
Instruments	$	105,629	derivative instruments	$	55,305	derivative instruments	$	(533	)

Total	$	105,629		$	55,305		$	(533	)

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

8. Derivative Financial Instruments (continued)

The following table summarizes the location in the Consolidated Statement of Operations and amounts of gains and losses on derivative instruments that do not qualify for hedge accounting for the year ended December 31, 2011 and December 31, 2010:


Derivatives Not Designated as Hedging Instruments	Location of Loss Recognized in Other Income	Recognized in Other Income on Derivatives for the Years Ended
	Location of Loss Recognized in Other Income	December 31, 2011		December 31, 2010
		(in thousands)
	Loss on
Derivative Instruments	Derivative Instruments	$	(26,208)	$	(1,121)

The consolidated accumulated other comprehensive income balance was $130.8 million as of December 31, 2011, and $105.7 million as of December 31, 2010. Approximately $74.7 million of this total accumulated gain associated with commodity price risk management activities as of December 31, 2011, is expected to be reclassified into earnings during the next twelve months (when the associated forecasted sales and purchases are also expected to occur.)

9. Fair Value Measurements

In September 2006, the FASB issued ASC 820, “Fair Value Measurements”, which defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. The provisions of ASC 820 are effective January 1, 2008. The FASB has also issued ASC 820-10-55, which delayed the effective date of ASC 820 for nonfinancial assets and liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), until fiscal years beginning after November 15, 2008. Effective January 1, 2008, the Company adopted ASC 820 as discussed above and elected to defer the application thereof to nonfinancial assets and liabilities in accordance with ASC 820-10-55 until January 1, 2009.

As discussed in Note 8, the Company utilizes derivative instruments to hedge against the variability in cash flows associated with the forecasted sale of its anticipated future natural gas production. The Company generally hedges a substantial, but varying, portion of anticipated natural gas production for the next 12 to 60 months. These derivatives are carried at fair value on the consolidated balance sheets.

As defined in ASC 820, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs. ASC 820 establishes afair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

9. Fair Value Measurements (continued)

The three levels of the fair value hierarchy defined by ASC 820 are as follows:

Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, marketable securities and listed equities.

Level 2—Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category generally include non-exchange-traded derivatives such as commodity swaps, basis swaps, options, and collars.

Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

The following table sets forth, by level, within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value as of December 31, 2011 and 2010. As required by ASC 820, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

		$00000000		$00000000			$00000000		$00000000
	Recurring Fair Value Measures
	(in millions)
	Level 1		Level 2			Level 3		Total
As of December 31, 2011
Derivative Assets	$	—	$	127.8		$	—	$	127.8
Derivative Liabilities		—		(17.5	)		—		(17.5	)

Total	$	—	$	110.3		$	—	$	110.3


	Level 1		Level 2			Level 3		Total
As of December 31, 2010
Derivative Assets	$	—	$	109.0		$	—	$	109.0

Total	$	—	$	109.0		$	—	$	109.0

Derivatives listed above include commodity swaps, basis swaps, put and call options and collars that are carried at fair value. The fair value amounts on the consolidated balance sheets associated with the Company’s derivatives resulted from Level 2 fair value methodologies, that is, the Company is able to value the assets and liabilities based on observable market data for similar instruments. The amounts above include the impact of netting assets and liabilities with counterparties with which the right of offset exists.

This observable data includes the forward curve for commodity prices and interest rates based on quoted markets prices and prospective volatility factors related to changes in commodity prices, as well as the impact of our non-performance risk of the counterparties which is derived using credit default swap values.

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

9. Fair Value Measurements (continued)

The Company measures fair value of its long term debt based on quoted market prices with consideration given to the effect of the Company’s credit risk. The carrying value of the Company’s Credit Facility approximates fair value based on current rates applicable to similar instruments. The following table outlines the fair value of our 2017 Notes as of December 31, 2011 and 2010:


	December 31, 2011		December 31, 2010
	(in thousands)
2017 Senior Notes
Carrying Value	$	346,782	$	346,153
Fair Value	$	323,456	$	322,207

10. Related-Party Transactions

NFR paid $87.7 million, $58.7 million and $42.2 million during 2011, 2010 and 2009, respectively, to Nabors and its subsidiaries for drilling and other oilfield services and the Company has recognized a liability on our consolidated balance sheets as of December 31, 2011 and 2010 of $12.1 million and $16.0 million, respectively, for these services.

NFR paid $0.8 million during 2010 and 2009, to Smith International, Inc. (Smith), an oil and natural gas services company, for services provided. A member of the Company’s board of representatives was the Chief Executive Officer, President, and Chief Operating Officer of Smith through August of 2010.

11. Commitments

The Company leases approximately 55,000 square feet of office space in downtown Houston, Texas, under a lease, which terminates on May 13, 2013. The average rent for this space over the life of the lease is approximately $0.6 million per year. The Company has an option to extend its lease term for an additional 60 months. As of December 31, 2011, total future commitments are $1.2 million.

The Company leases approximately 14,100 square feet of office space in downtown Denver, Colorado, under two leases. One lease terminates on August 31, 2014 and the Company has the option to extend its lease term for an additional 60 months. This lease, which is approximately 11,000 square feet, is sub leased out with proceeds to offset the rent commitments. The average rent for this space over the life of the lease is approximately $0.2 million per year. As of December 31, 2011 total future commitments are $0.6 million. The second lease continues with a month to month lease term.

The Company leases various office and production equipment. As of December 31, 2011, total future commitments are $0.8 million. The majority of our operating leases continue with a month to month lease term after initial contractual obligations have expired.

As part of our ongoing operations, we have contracted with affiliates of Nabors to secure drilling rigs for drilling the oil and natural gas well activity we expect to undertake. As of December 31, 2011 total future commitments are $37.1 million.

As of December 31, 2011, future minimum lease payments were as follows (in millions):


	Estimated Payments
	(in millions)
Year Ending December 31,
2012	$	24.9
2013		14.5
2014		0.2
Thereafter		—

	$	39.6

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

11. Commitments (continued)

Rent expense was approximately $1.6 million for the year ended December 31, 2011, $1.2 million for the year ended December 31, 2010 and $1.1 million for the year ended December 31, 2009.

As is customary in the oil and natural gas industry, the Company may at times have commitments in place to reserve or earn certain acreage positions or wells. If the Company does not pay such commitments, the acreage positions or wells may be lost.

The Company is at risk of lawsuits arising in the ordinary course of our business. In Management’s opinion, the Company is not currently involved in any legal proceedings which, individually or in aggregate, could have a material effect on the financial condition, operations or cashflows of the Company.

12. Employee Benefit Plans

The Company co-sponsors a 401(k) tax deferred savings plan (the Plan) and makes it available to employees. The Plan is a defined contribution plan, and the Company may make discretionary matching contributions of up to 6% of each participating employee’s compensation to the Plan. The contributions made by the Company totaled approximately $845,000 during the year ended December 31, 2011, $643,000 during the year ended December 31, 2010, and $502,000 for the period ended December 31, 2009.

13. Subsequent Events

Management has evaluated subsequent events through February 23, 2012, which represents the date the consolidated financial statements were issued, and have no reportable events.

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

The following supplemental information regarding our natural gas and oil producing activities is presented in accordance with the requirements of Section 932-235-50 of the ASC.

Costs Incurred

The costs incurred in oil and natural gas acquisitions, exploration and development activities were as follows:


	For the Year Ended December 31,
	2011		2010		2009
	(in thousands)
Property acquisition costs, proved (1)	$	466,874	$	60,252	$	6,297
Property acquisition costs, unproved (1)		28,663		68,758		62,725
Exploration and extension well costs		507		218		2,263
Development costs		274,631		238,850		252,838
Asset retirement costs		5,693		595		1,100

Total Costs	$	776,368	$	368,673	$	325,223

(1)	Property acquisition costs for the year ended December 31, 2011include bargain purchase gains of $79.4 million allocated to proved property acquisition costs and $20.1 million allocated to unproved property acquisition costs.

Capitalized Costs

The capitalized costs in oil and natural gas properties were as follows:


	For the Year Ended December 31,
	2011			2010			2009
	(in thousands)
Proved properties	$	2,292,875		$	1,506,565		$	1,177,439
Unproved properties		208,230			218,172			178,625

		2,501,105			1,724,737			1,356,064

Accumulated depletion, depreciation and amortization		(1,029,535	)		(925,874	)		(877,190	)

Net capitalized costs	$	1,471,570		$	798,863		$	478,874

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

Results of Operations

Results of operations for oil and natural gas producing activities, which exclude processing and other activities, corporate general and administrative expenses, and straight-line depreciation expense on non-oil and gas assets, were as follows:


	For the Year Ended December 31,
	2011		2010		2009
	(in thousands)
Revenues	$	204,989	$	132,062	$	81,937
Gain on derivative instruments		72,517		51,104		60,686
Operating costs:
Lease operating expenses		27,113		18,637		18,253
Workover expenses		2,903		848		482
Marketing, gathering, transportation and other		19,717		13,730		6,031
Production and ad valorem taxes		7,775		5,483		4,228
Depletion, depreciation and amortization		77,932		48,685		41,137
Impairments		29,921		1,711		407,295

Results of operations	$	112,145	$	94,072	$	(334,803	)

Oil and Natural Gas Reserves and Related Financial Data

Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir also may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates may occur from time to time.

The following tables set forth our total proved reserves and the changes in our total proved reserves. These reserve estimates are based in part on reports prepared by Miller and Lents, Ltd. (Miller and Lents), independent petroleum engineers, utilizing data compiled by us. In preparing its reports, Miller and Lents evaluated properties representing all of our proved reserves at December 31, 2011, 2010 and 2009. Our proved reserves are located onshore in the United States. There are many uncertainties inherent in estimating proved reserve quantities, and projecting future production rates and the timing of future development expenditures. In addition, reserve estimates of new discoveries are more imprecise than those of properties with production history. Accordingly, these estimates are subject to change as additional information becomes available. Proved reserves are the estimated quantities of natural gas, natural gas liquids and oil that geoscience and engineering data demonstrate with reasonable certainty to be economically producible in future years from known oil and natural gas reservoirs under existing economic conditions, operating methods and government regulations at the end of the respective years. Proved developed reserves are those reserves expected to be recovered through existing wells with existing equipment and operating methods.

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

Proved reserves as of December 31, 2011 and 2010 were estimated using the average of the historical unweighted first-day-of-the-month prices of oil and natural gas for the prior twelve months as required under new SEC rules. The average of the historical unweighted first-day-of-the-month prices for the prior twelve month periods ended December 31, 2011 and 2010 were $4.12 and $4.38, respectively. The average of the historical unweighted first-day-of-the-month prices for the prior twelve months ended February 29, 2012 is $3.86 and the future prices actually received may materially differ from current prices or the prices used in making the reserve estimates impacting the amount of proved developed and proved undeveloped reserves as of December 31, 2011. With respect to future development costs and operating expenses, the Company derived estimates using the current cost environment at year end, which is consistent with both the current and former SEC rules. The new SEC rules, which were adopted for the year ended December 31, 2009, also contain new reserve definitions and permit the use of new technologies to determine proved reserves, if those technologies have been demonstrated to result in reliable conclusions about reserve volumes. The new SEC rules further state that any proved undeveloped reserves (“PUD”) associated with undeveloped acreage must be part of a development drilling program and be drilled within five years of such reserves being originally booked in order to maintain their proved reserve status. Any PUDs not meeting these criteria will be reclassified as unproved reserves. As reflected in the table below, approximately 472.4 Bcfe of the increase in our total estimated proved reserves from December 31, 2008 to December 31, 2009 relates to the application of the new SEC rules discussed herein.


	Natural									Natural Gas
	Gas			NGLS			Oil			Equivalents
Estimated Proved Reserves	(Bcf)			(BBLS)			(BBLS)			(Bcfe)
December 31, 2008		375.8			5.3			2.7			423.8

Revisions—Performance		14.1			0.3			0.2			17.0
Revisions—Pricing		(86.2	)		(1.3	)		(0.5	)		(96.9	)
Extensions, Additions and Discoveries (Old SEC Rules)		192.7			0.6			1.7			207.1
Extensions, Additions and Discoveries (New SEC Rules) (1)		460.9			1.3			0.6			472.4
Production		(18.9	)		(0.3	)		(0.1	)		(21.4	)
Purchases in Place		—			—			—			—
Sales in Place		—			—			—			—

December 31, 2009		938.4			5.9			4.6			1,002.0

Revisions—Performance		(127.1	)		4.4			(0.9	)		(106.0	)
Revisions—SEC Rule Revision (2)		(121.1	)		(0.5	)		—			(124.3	)
Revisions—Pricing		8.8			0.1			—			9.4
Extensions, Additions and Discoveries		218.1			0.8			0.5			226.2
Production		(24.8	)		(0.4	)		(0.1	)		(28.2	)
Purchases in Place (3)		220.8			0.9			0.8			230.3
Sales in Place		(2.1	)		—			(0.1	)		(2.7	)

December 31, 2010		1,111.0			11.2			4.8			1,206.7

Revisions—Performance		(101.2	)		(5.0	)		0.5			(128.2	)
Revisions—SEC Rule Revision (2)		(590.2	)		(0.2	)		(3.6	)		(613.0	)
Revisions—Pricing		(28.8	)		(0.4	)		0.3			(29.4	)
Extensions, Additions and Discoveries		207.1			5.1			1.3			245.7
Production		(39.0	)		(0.2	)		(0.7	)		(44.3	)
Purchases in Place (3)		611.1			15.5			3.3			723.9
Sales in Place		—			—			—			—

December 31, 2011		1,170.0			26.0			5.9			1,361.4


Estimated Proved Developed Reserves
December 31, 2009		214.5			2.3			1.3			236.0
December 31, 2010		295.6			4.6			1.5			332.6
December 31, 2011		515.0			10.3			2.4			591.2

(1)

Primarily due to the application of revised definitions contained in the SEC’s new rules, particularly the definition of proved oil and natural gas reserves, which now permits the addition of undrilled locations beyond immediate offsets of producing wells that are supported by a determination, with reasonable certainty, of reservoir continuity.

(2)	In 2010 and 2011, we had negative revisions of 124.3 Bcfe and 613.0 Bcfe, respectively, which was primarily the result of proved undeveloped reserves being reclassified to non-proved status for adherence with the SEC five year guidance for recording proved reserves.

(3)	Attributable to the purchase of oil and gas properties in East Texas as described in Note 4 in the “Notes to Consolidated Financial Statements”.

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following information was developed utilizing procedures prescribed byASC 932, Disclosures about Oil and Gas Producing Activities. The information is based on estimates prepared by our petroleum engineering staff. The “standardized measure of discounted future net cash flows” should not be viewed as representative of the current value of our proved oil and natural gas reserves. It and the other information contained in the following tables may be useful for certain comparative purposes, but should not be solely relied upon in evaluating us or our performance.

In reviewing the information that follows, we believe that the following factors should be taken into account:

•

future costs and sales prices will probably differ from those required to be used in these calculations;

•

actual production rates for future periods may vary significantly from the rates assumed in the calculations;

•

a 10% discount rate may not be reasonable relative to risk inherent in realizing future net oil and natural gas revenues.

Under the standardized measure, future cash inflows were estimated by using the average of the historical unweighted first-day-of-the-month prices of oil and natural gas for the prior twelve month periods ended December 31,2011, 2010 and 2009. Future cash inflows do not reflect the impact of open hedge positions. Future cash inflows were reduced by estimated future developmentand production costs based on year end costs in order to arrive at net cash flows before tax. Use of a 10% discount rate and year-end prices and costs are required by ASC 932.

In general, management does not rely on the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible outcomes.

The standardized measure of discounted future net cash flows from our estimated proved oil and natural gas reserves follows:


	For the Year Ended December 31,
	2011			2010			2009
	(in thousands)
Future cash inflows	$	6,724,283		$	5,807,655		$	3,915,847
Less related future:
Production costs		(2,020,736	)		(1,513,149	)		(1,257,905	)
Development costs		(1,326,857	)		(1,708,651	)		(1,307,147	)

Future net cash inflows		3,376,690			2,585,855			1,350,795
10% annual discount for estimated timing of cash flows (1)		(2,207,421	)		(2,000,181	)		(1,244,380	)

Standardized measure of discounted future net cash flows	$	1,169,269		$	585,674		$	106,415

(1)	The negative present value factor is due to the addition of proved undeveloped properties that require a large amount of development costs. Additionally, these costs are weighted heavily in the first five years.

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved natural gas and crude oil reserves follows:


	For the Year Ended December 31,
	2011			2010			2009
	(in thousands)
Beginning Balance	$	585,674		$	106,415		$	280,427
Revisions of previous estimates
Changes in prices and costs		(41,896	)		296,445			(147,028	)
Changes in quantities		40,535			154,218			1,803
Additions to proved reserves (1)		168,123			40,663			(52,953	)
Purchases of reserves		527,760			10,960			—
Sales of reserves		—			(2,907	)		—
Accretion of discount		58,567			10,642			28,043
Sales of oil and gas, net		(147,481	)		(93,364	)		(52,943	)
Change in estimated future development costs		(102,647	)		(113,582	)		27,954
Previously estimated development costs incurred		88,980			139,109			12,279
Changes in rate of production and other, net		(8,346	)		37,075			8,833

Net change		583,595			479,259			(174,012	)

Ending Balance	$	1,169,269		$	585,674		$	106,415

(1)

The negative value of additions in 2009 is attributable to a large number of wells that were proved as a result of the new SEC rules. Consistent with the new SEC rules, the Company only adds proved undeveloped reserves that will be developed within a five year time horizon. As a result, a large amount of future development costs are included in the present value calculation. Additionally, these costs are not discounted as heavily as costs in the later years, thus causing the total present value to be negative.

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Nabors Industries (NBR) 10-K2011 FY Annual report

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