Grizzly Energy (GRZZP) 8-K/A Financial Statements and Exhibits

Exhibit 99.1

Antero Resources Corporation financial statements and

the notes thereto for each of the three years ended

December 31, 2011, 2010, and 2009

Independent Auditors’ Report

The Stockholder and Board of Directors

Antero Resources Corporation:

We have audited the balance sheets of Antero Resources Corporation (the Company) (a wholly owned subsidiary of Antero Resources LLC) as of December 31, 2011, 2010, and 2009, and the related statements of operations, stockholder’s equity, and cash flows for each of the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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 consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Antero Resources Corporation as of December 31, 2011, 2010, and 2009, and the results of its operations and its cash flows for each of the years then ended, in conformity with accounting principles generally accepted in the United States of America.

/s/ KPMG LLP

Denver, Colorado

May 4, 2012, except for note 10 which is as of June 29, 2012

ANTERO RESOURCES CORPORATION
Balance Sheets
December 31, 2011, 2010, and 2009
(In thousands)
Assets	2011			2010			2009
Current assets:
Cash and cash equivalents	$	1,017		$	—		$	35,516
Accounts receivable		11,332			16,262			19,754
Accounts receivable – related party		—			—			2,137
Accrued revenue		11,962			12,318			12,635
Prepaid expenses		8,774			4,528			5,090
Derivative instruments		54,742			29,337			20,709
Inventories		108			121			110
Total current assets	$	87,935		$	62,566		$	95,951
Property and equipment:
Natural gas properties, at cost (successful efforts method):
Unproved properties		86,967			86,829			139,465
Proved properties		993,882			884,277			745,026
Other property and equipment		4,667			4,068			3,041
		1,085,516			975,174			887,532
Less accumulated depletion, depreciation, and amortization		(314,788	)		(242,650	)		(172,887	)
Property and equipment, net		770,728			732,524			714,645
Derivative instruments		64,502			50,330			11,989
Other assets, net		12,430			12,555			10,154
Total assets	$	935,595		$	857,975		$	832,739
Liabilities and Stockholder’s Equity
Current liabilities:
Accounts payable	$	30,130		$	32,481		$	19,058
Due to affiliates, net		3,036			31,001			—
Accrued expenses		5,046			6,089			6,133
Revenue distributions payable		11,512			13,089			14,138
Advances from joint interest owners		961			1,478			1,400
Derivative instruments		—			2,127			3,959
Note payable to affiliate		—			—			5,000
Total current liabilities		50,685			86,265			49,688
Long-term liabilities:
Bank credit facility		31,000			—			142,080
Senior notes		363,549			318,808			203,081
Derivative instruments		—			—			1,095
Asset retirement obligations		1,308			1,131			917
Deferred gain on sale of assets		17,348			17,348			17,348
Other		69			228			—
Total liabilities	$	463,959		$	423,780		$	414,209
Stockholder’s equity:
Common stock, par value $1.00 per share. Authorized 5,000
shares; issued and outstanding 1,000 shares		1			1			1
Capital in excess of par value		499,873			499,873			499,875
Accumulated deficit		(28,238	)		(65,679	)		(81,346	)
Total stockholder’s equity		471,636			434,195			418,530
Total liabilities and stockholder’s equity	$	935,595		$	857,975		$	832,739

See accompanying notes to financial statements

ANTERO RESOURCES CORPORATION
Statements of Operations
Years ended December 31, 2011, 2010, and 2009
(In thousands)
	2011			2010			2009
Revenue:
Natural gas sales	$	100,999		$	105,089		$	87,868
Natural gas liquids sales		10,565			—			—
Oil sales		1,237			1,834			1,733
Realized and unrealized gain on commodity
derivative instruments, net (including unrealized
gains of $39,577 and $46,969, respectively)		78,983			87,775			38,952
Fee income		120			142			150
Total revenue	$	191,904		$	194,840		$	128,703
Operating expenses:
Lease operating expenses		7,088			9,664			5,336
Gathering, compression, and transportation		30,575			27,191			20,948
Production taxes		615			2,901			3,233
Exploration expenses		851			3,428			4,916
Impairment of unproved properties		1,490			27,974			51,428
Depletion, depreciation, and amortization		72,138			69,762			80,966
Accretion of asset retirement obligations		101			85			73
General and administrative		7,608			5,528			6,071
Total operating expenses		120,466			146,533			172,971
Operating income		71,438			48,307			(44,268	)
Other expense:
Interest expense		(33,949	)		(31,380	)		(19,444	)
Realized and unrealized losses on interest rate
derivative instruments, net (including unrealized
gains of $2,127 and $3,506, respectively)		(48	)		(1,260	)		(2,404	)
Total other expense		(33,997	)		(32,640	)		(21,848	)
Income (loss)  before income taxes		37,441			15,667			(66,116	)
Income tax expense		—			—			—
Net income (loss)	$	37,441		$	15,667		$	(66,116	)

See accompanying notes to financial statements

ANTERO RESOURCES CORPORATION
Statements of Stockholder’s Equity
Years ended December 31, 2011, 2010, and 2009
(In thousands)
						Common
	Common					stock classes			Capital in
	stock, $1.00		Preferred				A, B, C, D,		excess of			Accumulated
	par value		stock			and E			par value			deficit			Total
Balances, December 31, 2008	$	—	$	438,001		$	36		$	314		$	(15,230	)	$	423,121
Issuance of preferred stock		—		50,000			—			(12	)		—			49,988
Stock compensation		—		—			—			889			—			889
Return of capital to common stockholders		—		—			—			(57	)		—			(57	)
Contribution of capital from parent company		—		—			—			10,705			—			10,705
Net loss		—		—			—			—			(66,116	)		(66,116	)
Issuance of $1.00 par value common stock
in exchange for cancellation of preferred
stock and other classes of common stock		1		(488,001	)		(36	)		488,036			—			—
Balances, December 31, 2009		1		—			—			499,875			(81,346	)		418,530
Stock issuance costs		—		—			—			(2	)		—			(2	)
Net income		—		—			—			—			15,667			15,667
Balances, December 31, 2010		1		—			—			499,873			(65,679	)		434,195
Net income		—		—			—			—			37,441			37,441
Balances, December 31, 2011	$	1	$	—		$	—		$	499,873		$	(28,238	)	$	471,636

See accompanying notes to financial statements

ANTERO RESOURCES CORPORATION
Statements of Cash Flows
Years ended December 31, 2011, 2010, and 2009
(In thousands)
	2011			2010			2009
Cash flows from operating activities:
Net income (loss)	$	37,441		$	15,667		$	(66,116	)
Adjustments to reconcile net income to net cash provided by
operating activities:
Depletion, depreciation, and amortization		72,138			69,762			80,966
Dry hole costs		36			1,169			1,671
Impairment of unproved properties		1,490			27,974			51,428
Accretion of asset retirement obligations		101			85			73
Amortization of bond premium		(259	)		(252	)		14
Amortization of deferred financing costs		1,776			2,388			3,690
Stock compensation		—			—			889
Unrealized gains on derivative instruments, net		(41,704	)		(49,896	)		23,137
Changes in current assets and liabilities:
Accounts receivable		4,930			3,492			20,743
Accounts receivable – related parties		—			—			4,337
Due to affiliates		12,005			2,137			—
Accrued revenue		356			317			(942	)
Prepaid expenses		(4,246	)		562			408
Inventory		13			(11	)		378
Accounts payable		(2,134	)		(2,965	)		(2,740	)
Accrued expenses		(1,050	)		(44	)		(1,763	)
Revenue distributions payable		(1,577	)		(1,049	)		(9,782	)
Advance from joint interest owners		(517	)		78			(6,492	)
Payable to affiliates		—			(8,969	)		—
Net cash provided by operating activities	$	78,799		$	60,445		$	99,899
Cash flows from investing activities:
Proved property acquisitions		—			—			(1,029	)
Additions to unproved properties		(8,518	)		(7,639	)		(2,558	)
Drilling costs		(110,971	)		(91,601	)		(121,634	)
Additions to other property and equipment		(599	)		(1,027	)		(115	)
Proceeds from sale of assets		8,079			—			—
Increase in other assets		(897	)		(263	)		25
Net cash used in investing activities	$	(112,906	)	$	(100,530	)	$	(125,311	)
Cash flows from financing activities:
Borrowings (payments) on bank credit facility		31,000			(142,080	)		75,000
Payments on bank credit facility		—			—			(187,780	)
Repayment of second lien term note		—			—			(100,000	)
Issuance of preferred stock		—			—			50,000
Due to affiliate		(39,970	)		39,970			—
Issuance (payment) of note payable to affiliate		—			—			5,000
Payment of note payable to affiliate		—			(5,000	)		—
Issuance of senior notes		45,000			115,980			203,066
Contribution of capital from parent company		—			—			11,000
Return of capital to stockholders		—			—			(57	)
Payment of financing costs		(753	)		(4,527	)		(10,195	)
Stock issuance costs		—			—			(307	)
Other		(153	)		226			—
Net cash provided by financing activities	$	35,124		$	4,569		$	45,727
Net increase (decrease) in cash and cash equivalents		1,017			(35,516	)		20,315
Cash and cash equivalents, beginning of year		—			35,516			15,201
Cash and cash equivalents, end of year	$	1,017		$	—		$	35,516
Supplemental disclosure of cash flow information:
Cash paid during the year for interest	$	31,090		$	28,521		$	15,434
Supplemental disclosure of noncash investing activities:
Changes in accounts payable for additions to natural gas properties, net	$	(217	)	$	16,388		$	(47,379	)

See accompanying notes to financial statements

ANTERO RESOURCES CORPORATION

Notes to Financial Statements

December 31, 2011, 2010, and 2009

(1)   Organization

Antero Resources Corporation (the Company, we, our, or Antero), is an independent exploration and production company engaged in the acquisition and development of oil and natural gas properties. Substantially all of the Company’s oil and gas properties are located in the Arkoma Basin in Coal and Hughes counties in Oklahoma. The Company is headquartered in Denver, Colorado.

As of May 4, 2012, which is the date these financial statements were issued, the Company completed its evaluation of potential subsequent events for disclosure and no items requiring disclosure were identified.

(2)   Summary of Significant Accounting Policies

(a)   Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles 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. Changes in facts and circumstances or discovery of new information may result in revised estimates, and actual results could differ from those estimates.

The Company’s financial statements are based on a number of significant estimates including estimates of gas and oil reserve quantities, which are the basis for the calculation of depreciation, depletion, amortization, and impairment of oil and gas properties. Reserve estimates by their nature are inherently imprecise.

(b)   Risks and Uncertainties

Historically, the market for natural gas has experienced significant price fluctuations. Prices for natural gas have been particularly volatile in recent years. The price fluctuations can result from variations in weather, levels of production in the region, availability of transportation capacity to other regions of the country, and various other factors. Increases or decreases in prices received could have a significant impact on the Company’s future results of operations.

(c)   Cash and Cash Equivalents

The Company considers all liquid investments purchased with an initial maturity of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments. The Company and its affiliates have a combined cash management facility. The Company had a negative cash balance of $40.0 million at December 31, 2010 that was classified as due to affiliate. The Company’s policy is to present changes in due to affiliates related to negative book balances as financing activities in the statements of cash flows.

(d)   Oil and Gas Properties

The Company accounts for its natural gas and crude oil exploration and development activities under the successful efforts method of accounting. Under such method, costs of productive wells, development dry holes, and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, geological and geophysical expenses, and delay rentals for gas and oil leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the units-of-production amortization rate. A gain or loss is recognized for all other sales of producing properties.

Unproved properties with significant acquisition costs are assessed for impairment on a property-by-property basis and any impairment in value is charged to expense. Impairment is assessed based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks, and future plans to develop acreage. Other unproved properties are assessed for impairment on an aggregate basis. Unproved properties and the related costs are transferred to proved properties when reserves are discovered on or otherwise attributed to the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of cost without recognizing any gain or loss until the cost has been recovered. Impairments of unproved properties for leases, which have expired or are expected to expire, were $1.5 million for the year ended December 31, 2011, $28.0 million for the year ended December 31, 2010, and $51.4 million for the year ended December 31, 2009.

The Company reviews its proved oil and gas properties for impairment whenever events and circumstances indicate that the carrying value of the properties may not be recoverable. When determining whether impairment has occurred, the Company estimates the expected future cash flows of its oil and gas properties and compares such future cash flows to the carrying amount of the properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company reduces the carrying amount of the properties to their estimated fair value. The factors used to determine fair value include estimates of proved reserves, future commodity prices, future production estimates, anticipated capital expenditures, and a commensurate discount rate. There were no impairments of proved natural gas properties during the years ended December 31, 2011, 2010, and 2009.

The provision for depreciation, depletion, and amortization (DDA) of natural gas properties is calculated on a geological reservoir basis using the units-of-production method. DDA expense for oil and gas properties was $71.3 million, $69.0 million, and $80.3 million for the years ended December 31, 2011, 2010 and 2009, respectively.

(e)   Other Property and Equipment

Other property and equipment, consisting of vehicles and office equipment, are depreciated using the straight-line method over estimated useful lives, ranging from three to five years. For the years ended December 31, 2011 and 2010, depreciation expense for other property and equipment was $839,000 and $762,000, respectively. A gain or loss is recognized upon the sale or disposal of property and equipment.

(f)   Deferred Financing Costs

Deferred financing costs represent loan origination fees, initial purchasers’ discounts, and other borrowing costs and are included in noncurrent other assets on the balance sheet. These costs are being amortized over the term of the notes using the effective-interest method. The amounts amortized of previously deferred debt issuance costs were $1.8 million, $2.4 million and $3.7 million for the years ended December 31, 2011, 2010 and 2009, respectively.

(g)   Derivative Financial Instruments

In order to manage its exposure to oil and gas price volatility, the Company enters into derivative transactions from time to time, including commodity swap agreements, collar agreements, and other similar agreements relating to natural gas expected to be produced. From time to time, the Company also enters into derivative contracts to mitigate the effects of interest rate fluctuations. To the extent legal right of offset with a counterparty exists, the Company reports derivative assets and liabilities on a net basis. The Company has exposure to credit risk to the extent the counterparty is unable to satisfy its settlement obligation. The Company actively monitors the creditworthiness of each counterparty and assesses the impact, if any, on its derivative position.

The Company records derivative instruments on the balance sheet as either an asset or liability measured at fair value and records changes in the fair value of derivatives in current earnings as they occur. Changes in the fair value of commodity derivatives are classified as revenues and changes in the fair value of interest rate derivatives are classified as other income (expense).

(h)   Asset Retirement Obligations

The Company is obligated to dispose of certain long-lived assets upon their retirement. The Company’s asset retirement obligations (ARO) relate primarily to its obligation to plug and abandon oil and gas wells at the end of their life. The ARO is recorded at its estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at the Company’s credit-adjusted risk-free interest rate. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment. The fair value of the liability is added to the carrying amount of the associated asset, and this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expense. If the obligation is settled for an amount other than the carrying amount of the liability, we will recognize a gain or loss on settlement.

(i)   Environmental Liabilities

Environmental expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation are expensed as incurred. Liabilities are accrued when environmental assessments and/or clean up is probable, and the costs can be reasonably estimated. These liabilities are adjusted as additional information becomes available or circumstances change. As of December 31, 2011 and 2010, the Company has not accrued for nor been fined or cited for any environmental violations that could have a material adverse effect on future capital expenditures or operating results of the Company.

(j)   Natural Gas, Natural Gas Liquids, and Oil Revenues

Sales of natural gas, natural gas liquids (NGLs), and crude oil are recognized when the products are delivered to the purchaser and title transfers to the purchaser. Payment is generally received one to three months after the sale has occurred. Variances between estimated sales and actual amounts received are recorded in the month payment is received and are not material. The Company recognizes natural gas revenues based on its entitlement share of natural gas that is produced based on its working interests in the properties. The Company records a receivable (payable) to the extent it receives less (more) than its proportionate share natural gas revenues. At December 31, 2010 and 2011, the Company had no significant imbalance positions.

(k)   Concentrations of Credit Risk

The Company’s revenues are derived principally from uncollateralized sales to purchasers in the oil and gas industry. The concentration of credit risk in a single industry affects the Company’s overall exposure to credit risk because purchasers may be similarly affected by changes in economic and other conditions. The Company has not experienced significant credit losses on its receivables.

The Company’s sales to major customers (purchase in excess of 10% of total sales) for the years ended December 31, 2011 and 2010 are as follows:

	2011			2010			2009
Company A		54	%		44	%		65	%
Company B		21			26			5
All others		25			30			30
		100	%		100	%		100	%

Although a substantial portion of production is purchased by these major customers, the Company does not believe the loss of any one or several customers would have a material adverse effect on its business as other customers or markets would be accessible to it.

The Company is also exposed to credit risk on its commodity derivative portfolio. Any default by the counterparties to these derivative contracts when they become due would have a material adverse effect on our financial condition and results of operations. The fair value of our commodity derivative contracts of approximately $119 million at December 31, 2011 includes the following values by bank counterparty: JP Morgan – $80 million; Wells Fargo – $18 million; Credit Suisse – $10 million; Key Bank – $8 million, and Credit Agricole – $3 million. The credit ratings of certain of these banks have been downgraded in 2011 because of the sovereign debt crisis in Europe. The estimated fair value of our commodity derivative assets has been risk adjusted using a discount rate based upon the respective published credit default swap rates at December 31, 2011 for each of the European and American banks. We believe that all of these institutions currently are acceptable credit risks.

The Company, at times, may have cash in banks in excess of federally insured amounts.

(l)   Income Taxes

Deferred tax assets and liabilities are recognized for net operating loss carryforwards for income tax purposes and the temporary differences between the financial statement and tax basis of assets and liabilities. The effect of changes in the tax laws or tax rates is recognized in income in the period such changes are enacted. Deferred tax assets are reduced by a valuation allowance, when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

Unrecognized tax benefits represent potential future tax obligations for uncertain tax positions taken on previously filed tax returns that may not ultimately be sustained. The Company recognizes interest on income tax liabilities as interest expense and fines and penalties as income tax expense. At December 31, 2011 and 2010, the Company has no unrecognized tax benefits from uncertain tax positions that would impact the Company’s effective tax rate and has made no provisions for interest or penalties related to uncertain tax positions. The tax years 2008 through 2011 remain open to examination by the U.S. Internal Revenue Service. The Company files tax returns with various state taxing authorities which remain open to examination for tax years 2007 through 2011.

(m)   Fair Value Measures

ASC Topic 820, Fair Value Measurements and Disclosures, clarifies the definition of fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. This guidance also relates to all nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis (e.g. those measured at fair value in a business combination, the initial recognition of asset retirement obligations, and impairments of proved oil and gas properties and other long-lived assets). The fair value is the price that the Company estimates would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. A fair value hierarchy is used to prioritize input to valuation techniques used to estimate fair value. An asset or liability subject to the fair value requirements is categorized within the hierarchy 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 in its entirety requires judgment and considers factors specific to the asset or liability. The highest priority (Level 1) is given to unadjusted quoted market prices in active markets for identical assets or liabilities and the lowest priority (Level 3) is given to unobservable inputs. Level 2 inputs are data, other than quoted prices included within Level 1, that are observable for the asset or liability, either directly or indirectly. Instruments that are valued using Level 2 inputs include nonexchange-traded derivatives such as over-the-counter commodity price swaps, basis swaps, and interest rate swaps. Valuation models used to measure fair value of these instruments consider various Level 2 inputs including (i) quoted forward prices for commodities, (ii) time value, (iii) quoted forward interest rates, (iv) current market prices and contractual prices for the underlying instruments, and (v) risk of nonperformance by the Company and the counterparty, and other relevant economic measures. The Company utilizes its counterparties to assess the reasonableness of its prices and valuation techniques. To the extent a legal right of offset with a counterparty exists, the derivative assets and liabilities are reported on a net basis.

(3)   Credit Facilities

(a)   Senior Secured Credit Facility

The Company along with other subsidiaries of Antero Resources LLC (Antero Entities) has a senior secured revolving bank credit facility (the Credit Facility) with a consortium of bank lenders. The maximum amount of the Credit Facility is $1.5 billion. Borrowings under the Credit Facility are subject to borrowing base limitations based on the collateral value of our proved properties and hedge positions and are subject to regular semiannual redeterminations. As of December 31, 2011, the borrowing base was $1.2 billion and lender commitments totaled $850 million. Lender commitments can be increased to the full $1.2 billion borrowing base upon approval of the lending bank group. The maturity date of the Credit Facility is May 12, 2016. The next redetermination of the borrowing base is scheduled to occur in May 2012.

The Credit Facility is secured by mortgages on substantially all of the Antero Entities’ properties and guarantees from the each of the Antero Entities. The Credit Facility contains certain covenants, including restrictions on indebtedness and dividends, and requirements with respect to working capital and interest coverage ratios. Interest is payable at a variable rate based on LIBOR or the prime rate based on the Company’s election at the time of borrowing. The Company was in compliance with all of the financial debt covenants under the Credit Facility as of December 31, 2011 and 2010.

As of December 31, 2011, the Credit Facility had a total outstanding balance of $365 million, with a weighted average interest rate of 2.12%, and total outstanding letters of credit of approximately $21 million. At December 31, 2011, Antero Resources Corporation had $31 million of borrowings under the Credit Facility. As of December 31, 2010, the Credit Facility had a total outstanding balance of $100 million, with a weighted average interest rate of 2.56%, and outstanding letters of credit of approximately $18 million. Commitment fees of from 0.375% to 0.50% are payable on the unused borrowing base.

(b)   9.375% Senior Notes Due 2017

On November 17, 2009, an indirect wholly owned finance subsidiary of Antero Resources LLC, Antero Finance, issued $375 million of 9.375% senior notes due December 1, 2017 at a discount of $2.6 million. In January 2010, the Company issued an additional $150 million of the same series of 9.375% senior notes at a premium of $6 million. The notes are unsecured and subordinate to the Company’s Credit Facility to the extent of the value of the collateral securing the Credit Facility. The notes are guaranteed on a full and unconditional basis and joint and severally by Antero Resources LLC, all of its wholly owned subsidiaries (other than Antero Finance), and certain of its future restricted subsidiaries. Antero Resources LLC has no independent assets or operations. Interest on the notes is payable on June 1 and December 1 of each year. Antero Finance may redeem all or part of the notes at any time on or after December 1, 2013 at redemption prices ranging from 104.688% on or after December 1, 2013 to 100.00% on or after December 1, 2015. In addition, on or before December 1, 2012, Antero Finance may redeem up to 35% of the aggregate principal amount of the notes with the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 109.375%. At any time prior to December 1, 2013, Antero Finance may also redeem the notes, in whole or in part, at a price equal to 100% of the principal amount of the notes plus a “make-whole” premium. If Antero Resources LLC undergoes a change of control, Antero Finance may be required to offer to purchase notes from the holders. Antero Resources Corporation, the stand-alone parent entity, has insignificant independent assets and no operations. There are no restrictions on the Company’s ability to obtain cash dividends or other distributions of funds from its subsidiaries, except those imposed by applicable law.

The Company was allocated $317 million of the senior notes and executed a note payable to Antero Finance for a like amount. The terms and conditions of the note are substantially similar to the senior notes.

(c)   7.25% Senior Notes Due 2019

On August 1, 2011, Antero Finance issued $400 million of 7.25% senior notes due August 1, 2019 at par. The notes are unsecured and effectively subordinated to the Company’s Credit Facility to the extent of the value of the collateral securing the Credit Facility. The notes rank pari passu to the existing 9.375% senior notes. The notes are guaranteed on a senior unsecured basis by Antero Resources LLC, all of its wholly owned subsidiaries (other than Antero Finance), and certain of its future restricted subsidiaries. Interest on the notes is payable on August 1 and February 1 of each year, commencing on February 1, 2012. Antero Finance may redeem all or part of the notes at any time on or after August 1, 2014 at redemption prices ranging from 105.438% on or after August 1, 2014 to 100.00% on or after August 1, 2017. In addition, on or before August 1, 2014, Antero Finance may redeem up to 35% of the aggregate principal amount of the notes with the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 107.25% of the principal amount of the notes, plus accrued interest. At any time prior to August 1, 2014, Antero Finance may redeem the notes, in whole or in part, at a price equal to 100% of the principal amount of the notes plus a “make-whole” premium and accrued interest. If a change of control (as defined in the bond indenture) occurs at any time prior to January 1, 2013, Antero Finance may, at its option, redeem all, but not less than all, of the notes at a redemption price equal to 110% of the principal amount of the notes, plus accrued interest. If Antero Finance has not exercised its optional redemption rights upon a change of control, the note holders will have the right to require Antero Finance to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the notes, plus accrued interest.

The Company was allocated $45 million of the senior notes and executed a note payable to Antero Finance for a like amount. The terms and conditions of the note are substantially similar to the senior notes.

(4)   Asset Retirement Obligations

The following is a reconciliation of the Company’s asset retirement obligations for the years ended December 31, 2011 and 2010 (in thousands):

	2011		2010
Asset retirement obligations – beginning of year	$	1,131	$	917
Obligations incurred		77		129
Accretion expense		100		85
Asset retirement obligations – end of year	$	1,308	$	1,131

The fair value of obligations incurred is valued utilizing Level 3 inputs.

(5)   Financial Instruments

The carrying values of trade receivables, trade payables, and credit facilities at December 31, 2011 and 2010 approximated market value. The carrying value of the Credit Facility approximated fair value because the variable interest rates are reflective of current market conditions. The fair value of the senior notes was approximately $384 million based Level 2 on market data at December 31, 2011.

(6)   Derivative Instruments and Hedging Activities

(a)   Commodity Derivatives

The Company periodically enters into natural gas derivative contracts with counterparties to hedge the price risk associated with a portion of its production. These derivatives are not held for trading purposes. To the extent that changes occur in the market prices of natural gas, the Company is exposed to market risk on these open contracts. This market risk exposure is generally offset by the change in market prices of natural gas recognized upon the ultimate sale of the gas produced.

For the years ended December 31, 2011 and 2010, the Company was party to natural gas fixed price swaps. When actual commodity prices exceed the fixed price provided by the swap contracts, the Company pays the excess to the counterparty, and when actual commodity prices are below the contractually provided fixed price receives the difference from the counterparty. The Company’s natural gas swaps have not been designated as hedges for accounting purposes; therefore, all gains and losses were recognized in income currently.

The Company’s derivative positions are with major financial institutions that the Company believes to be sound financially. The Company has no collateral from any counterparties. Commodity and interest rate derivative positions are with institutions that have a position in our Credit Facility and are secured by the collateral pledged on the Credit Facility and cross default provisions between the Credit Facility and the derivative instruments. There are no past-due receivables from or payables to any of its counterparties.

At December 31, 2011, the Company has entered into fixed price natural gas swaps in order to hedge a portion of its natural gas production from January 1, 2012 to December 31, 2015 as summarized in the following table:

			Weighted
			average
			index
	MMbtu/day		price
Year ending December 31, 2012:
Transco Zone 4		45,000	$	6.60
Year ending December 31, 2013:
Transco Zone 4		40,000		6.51
Year ending December 31, 2014:
Transco Zone 4		20,000		6.51
Centerpoint		10,000		6.20
Year ending December 31, 2015:
Transco Zone 4		20,000		5.58

(b)   Interest Rate Derivatives

Historically, the Company has entered into various floating-to-fixed interest rate swap derivative contracts to manage exposures to changes in interest rates from variable rate obligations. Under the swaps, the Company made payments to the swap counterparty when the variable LIBOR three-month rate fell below the fixed rate or received payments from the swap counterparty when the variable LIBOR three-month rate went above the fixed rate. The Company has no outstanding interest rate swap agreements at December 31, 2011.

(c)   Summary

The following is a summary of the fair values of derivative instruments not designated as hedges for accounting purposes and where such values are recorded in the balance sheets as of December 31, 2011 and 2010. None of the Company’s derivative instruments are designated as hedges for accounting purposes.

	2011			2010
	Balance sheet			Balance sheet
	location	Fair value		location	Fair value
		(In thousands)			(In thousands)
Asset derivatives not designated as hedges for accounting purposes:
Commodity contracts	Current assets	$	54,742	Current assets	$	29,337
Commodity contracts	Long-term			Long-term
	assets		64,502	assets		50,330
Total asset derivatives		$	119,244		$	79,667
Liability derivatives not designated as hedges for accounting purposes:
Interest rate contracts	Current liabilities	$	—	Current liabilities	$	2,127
Interest rate contracts	Long-term			Long-term
	liabilities		—	liabilities		—
Total liability derivatives		$	—		$	2,127

The following is a summary of realized and unrealized gains (losses) on derivative instruments and where such values are recorded in the statements of operations for the years ended December 31, 2011 and 2010 (in thousands):

		Statement of
		operations
		location		2011	2010	2009
Realized gains on commodity contracts		Revenue	$	39,406	40,806	65,224
Unrealized gains on commodity contracts		Revenue		39,577	46,969	(26,272)
	Total gains on commodity contracts			78,983	87,775	38,952
Realized losses on interest rate contracts		Other expense		(2,175)	(4,766)	(5,539)
Unrealized gains on interest rate contracts		Other income		2,127	3,506	3,135
	Total losses on interest rate contracts			(48)	(1,260)	(2,404)
	Net gains on derivative contracts		$	78,935	86,515	36,548

The following table summarizes the valuation of investments and financial instruments by the fair value hierarchy described in note 1 at December 31, 2011 (in thousands):

		Fair value measurements using
		Quoted pries
		in active	Significant
		markets for	other	Significant
		identical	observable	unobservable
		assets	inputs	inputs
Description		(Level 1)	(Level 2)	(Level 3)	Total
Derivatives asset:
	Fixed price commodity swaps	$ —	$ 119,244	$ —	$ 119,244

(7)   Income Taxes

The income tax expense differs from the amount that would be computed by applying the U.S. statutory federal income tax rate of 35% to pretax income for the years ended December 31, 2011, 2010 and 2009, respectively, as a result of the following (in thousands):

	2011			2010			2009
Federal income tax expense at 35% of income before income taxes	$	13,104		$	5,483		$	(22,479	)
State income tax, net of federal benefit		1,382			629			(2,609	)
Change in valuation allowance		(13,706	)		(6,113	)		26,400
Other		(780	)		1			(1,312	)
Total income tax expense	$	—		$	—		$	—

Deferred income taxes reflect the impact of temporary differences between amounts of assets and liabilities for financial reporting purposes and such amounts as measured by tax laws. The tax effect of the temporary differences giving rise to the Company’s net deferred tax assets and liabilities at December 31, 2011 and 2010 are as follows (in thousands):

	2011			2010
Deferred tax assets:
Net operating loss carryforwards	$	131,443		$	97,019
Accrued liabilities		189			151
Oil and gas properties		506			426
Capital loss carryforwards		2,696			1,817
Other		66			74
Total deferred tax assets		134,900			99,487
Valuation allowance		(11,237	)		(24,943	)
Net deferred tax assets	$	123,663		$	74,544
Deferred tax liabilities:
Unrealized gains on derivative instruments		46,794			30,193
Oil and gas properties		76,869			44,351
Total deferred tax liabilities		123,663			74,544
Net deferred taxes	$	—		$	—

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Due to the lack of historical profitable operations and based upon the projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that the Company will not realize the benefits of all of these deductible differences, and has recorded a valuation allowance of approximately $11.2 million at December 31, 2011. The amount of the deferred tax asset considered realizable, however, could be reduced in the near term if estimates of future taxable income during the carryforward period are reduced.

The Company has approximately $340 million of net operating loss carryforwards as of December 31, 2011. The tax years 2008 through 2011 remain open to examination by the Internal Revenue Service. These carryforwards expire starting in 2024 through 2031.

(8)   Related-Party Transactions

(a)   General and Administrative Services

The Company has a services agreement with Antero Resources Midstream Corporation, Antero Resources Piceance Corporation, Antero Resources Pipeline Corporation, and Antero Resources Appalachian Corporation. This agreement covers general and administrative services that the Company performs on behalf of the other Antero Entities. In return for these services, these affiliates pay the Company a monthly reimbursement of all direct costs incurred by the Company on behalf of other Antero subsidiaries. For the year ended December 31, 2011, the Company was reimbursed $16.5 million from the affiliates. For the year ended December 31, 2010, the Company was reimbursed $12.5 million from the affiliates.

(b)   Related-Party Accounts Receivable and Payable

The Company pays general and administrative expenses for other Antero subsidiaries and then receives reimbursements for those expenditures. In addition, on occasion, other expenses and capital expenditures are paid by the Company on behalf of the other Antero subsidiaries. The Company is subsequently reimbursed for those expenditures. As of December 31, 2011, the Company had an account receivable balance of $1.1 million from Antero Resources Appalachian Corporation. As of December 31, 2010, the Company had accounts receivable balances of $4.3 million from Antero Resources Appalachian Corporation, $5.3 million from Antero Resources Piceance Corporation, and $2.2 million from Antero Resources Pipeline Corporation.

At December 31, 2011, the Company had a $3.8 million account payable to Antero Finance for interest payable on the senior notes. The Company also had a payable to Antero Resources LLC for $355,000.

(9)   Commitments

The following is a schedule of future minimum payments for firm transportation agreements, drilling and compression facility obligations, and leases that have remaining lease terms in excess of one year as of December 31, 2011 (in millions).

	Firm		Drilling and		Office and
	transportation (a)		frac services (b)		equipment (c)		Total
Year ending December 31:
2012	$	8.9		0.5		0.9		10.3
2013		8.4		—		0.7		9.1
2014		6.3		—		0.6		6.9
2015		3.1		—		0.7		3.8
2016		1.0		—		0.5		1.5
Thereafter		—		—		—		—
Total	$	27.7		0.5		3.4		31.6

(a)   Firm Transportation

The Company has entered into firm transportation agreements with various pipelines in order to facilitate the delivery of production to market. These contracts commit the Company to transport minimum daily natural gas volumes at a negotiated rate, or pay for any deficiencies at a specified reservation fee rate. The amounts in this table represent our minimum daily volumes at the reservation fee rate.

(b)   Drilling Rig Service Commitments

At December 31, 2011, the Company had a contract for the service of one rig. The contract expires in 2012.

(c)   Office and Equipment Leases

The Company leases various office space and equipment under operating lease arrangements. Rental expense included in general and administrative expenses under operating leases was $712,000 and $591,000 for the years ended December 31, 2011 and 2010, respectively.

(10)   Supplemental Information on Oil and Gas Producing Activities (Unaudited)

The following is supplemental information regarding our consolidated oil and gas producing activities. The amounts shown include our net working and royalty interests in all of our oil and gas properties.

(a)   Capitalized costs Relating to Oil and Gas Producing Activities

	Year ended December 31
	2011			2010
	(In thousands)
Producing properties	$	993,882		$	884,277
Unproved properties		86,967			86,829
		1,080,849			971,106
Accumulated depreciation and depletion		(311,275	)		(239,675	)
Net capitalized costs	$	769,574		$	731,431

(b)   Costs Incurred in Certain Oil and Gas Activities

	Year ended December 31
	2011		2010		2009
	(In thousands)
Proved property acquisition costs	$	—	$	—	$	1,029
Unproved property acquisition costs		8,518		7,639		2,558
Development costs and other		110,971		91,601		121,634
Asset retirement obligation		77		129		77
Total costs incurred	$	119,566	$	99,369	$	125,298

(c)   Results of Operations for Oil and Gas Producing Activities

	Year ended December 31
	2011			2010			2009
	(In thousands)
Revenues	$	112,801		$	106,923		$	89,601
Operating expenses:
Production expenses		38,278			39,756			29,517
Exploration expenses		851			3,428			4,916
Depreciation and depletion expense		71,300			68,700			81,457
Impairment		1,490			27,974			51,428
Results of operations before income tax expense (benefit)		882			(32,935	)		(77,717	)
Income tax (expense) benefit		(309	)		11,180			26,424
Results of operations	$	573		$	(21,755	)	$	(51,293	)

(d)   Oil and Gas Reserves

The following table sets forth the net quantities of proved reserves and proved developed reserves during the periods indicated. This information includes the oil and gas segment’s royalty and net working interest share of the reserves in oil and gas properties. Net proved oil and gas reserves for the year ended December 31, 2011 were prepared by the Company’s reserve engineers and audited by DeGolyer and McNaughton utilizing data compiled by us. All reserves are located in the United States. There are many uncertainties inherent in estimating proved reserve quantities, and projecting future production rates and timing of future development costs. In addition, reserve estimates of new discoveries are more imprecise than those of properties with a production history. Accordingly, these estimates are subject to change as additional information becomes available.

Proved reserves are the estimated quantities of crude oil, condensate, and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known oil and gas reservoirs under existing economic and operating conditions 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.

We adopted the SEC’s amendments to the rules for oil and gas reserve reporting for the year ended December 31, 2009. These amendments increased disclosure requirements regarding reserves, changed the definition of proved reserves, and changed pricing assumptions.

In accordance with these new rules, as of December 31, 2009, the Company changed its definition of proved undeveloped reserves to include drilling locations that are more than one offset location away from productive wells and are reasonably certain of containing proved reserves and which are scheduled to be drilled within five years under the Company’s development plans. Additionally, the Company estimated proved reserves using 12 month average pricing, beginning as of December 31, 2009, as required by the rules. The Company’s development plans related to scheduled drilling over the next five years are subject to many uncertainties and variables, including availability of capital; future oil and gas prices; and cash flows from operations, future drilling costs, demand for natural gas, and other economic factors.

							Oil and			Total
	Natural			NGLS			condensate			equivalents
	gas (Bef)			(MMBbI)			(MMBbI)			(Bcfe)
Proved developed and undeveloped reserves:
December 31, 2008		331			—			—	(a)		331
Revisions		(10	)		—			—	(a)		(10	)
Extensions, discoveries and other additions		311			—			—	(a)		311
Production		(23	)		—			—	(a)		(23	)
December 31, 2009		609			—			—	(a)		609
Revisions		(28	)		10			—	(a)		32
Extensions, discoveries and other additions		266			2			—	(a)		278
Production		(24	)		—			—	(a)		(24	)
Purchase of reserves		—			—			—			—
Sale of reserves in place		—			—			—			—
December 31, 2010		823			12			—	(a)		895
Revisions		(288	)		(2	)		—	(a)		(300	)
Extensions, discoveries and other additions		92			2			—			104
Production		(33	)		—			—	(a)		(33	)
Purchase of reserves		—			—			—			—
Sale of reserves in place		(1	)		—			—	(a)		(1	)
December 31, 2011		593			12			—	(a)		665

					Oil and
	Natural		NGLS		condensate		Equivalents
	gas (Bcf)		(MMBbI)		(MMBbI)		(Bcfe)
Proved developed reserves:
December 31, 2011		226.0		2.0		—		238.0
December 31, 2010		190.0		2.0		—		202.0
December 31, 2009		164.0		—		—		164.0
Proved undeveloped reserves:
December 31, 2011		368.0		10.0		—		428.0
December 31, 2010		633.0		10.0		—		693.0
December 31, 2009		445.0		—		—		445.0
(a) Less than 1.0

Significant items included in the categories of proved developed and undeveloped reserve changes for the years, 2011, 2010, and 2009 in the above table include the following:

·   Extensions and Discoveries – The additions to the Company’s proved reserves through new discoveries and extensions result from (i) extensions of the proved acreage of previously discovered reservoirs through additional drilling of development wells and (ii) discovery of new fields with proved reserves through drilling of exploratory wells.

·   2011 – Of the 106 Bcfe of extensions and discoveries in 2011, 93 Bcfe related to the Arkoma Basin in Oklahoma and 12 Bcfe related to other areas.

·   2010 – Of the 280 Bcfe of extensions and discoveries in 2010, 249 Bcfe related to the Arkoma Basin in Oklahoma and 32 Bcfe related to other areas.

·   2009 – Of the 311 Bcfe of 2009 extensions and discoveries, 280 Bcfe related to the Arkoma Basin in Oklahoma and 31 Bcfe related to our other areas. The increase in extensions and discoveries is the result of the changes in rules for estimating proved reserves.

The following table sets forth the standardized measure of the discounted future net cash flows attributable to our proved reserves. Future cash inflows were computed by applying historical 12-month unweighted first day of the month average prices. Future prices actually received may materially differ from current prices or the prices used in the standardized measure.

Future production and development costs represent the estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. Future income tax expenses were computed by applying statutory income tax rates to the difference between pretax net cash flows relating to our proved reserves and the tax basis of proved oil and gas properties. In addition, the effects of statutory depletion in excess of tax basis, available net operating loss carryforwards, and alternative minimum tax credits were used in computing future income tax expense. The resulting annual net cash inflows were then discounted using a 10% annual rate.

	Year ended December 31
	2011			2010			2009
	(In millions)
Future cash inflows	$	2,357		$	3,588		$	2,021
Future production costs		(483	)		(698	)		(429	)
Future development costs		(664	)		(989	)		(683	)
Future net cash flows before income tax		1,210			1,901			909
Future income tax expense		(131	)		(409	)		(60	)
Future net cash flows		1,079			1,492			849
10% annual discount for estimated timing of cash flows		(694	)		(1,009	)		(622	)
Standardized measure of discounted future net cash flows	$	385		$	483		$	227

The 12-month weighted average prices used to estimate the Company’s total equivalent reserves were as follows:

	Arkoma
	(Per Mcfe)
December 31, 2011	$	3.90
December 31, 2010		4.18
December 31, 2009		3.25

(e)   Changes in Standardized Measure of Discounted Future Net Cash Flow

	Year ended December 31
	2011			2010			2009
	(In millions)
Sales of oil and gas, net of productions costs	$	(75	)	$	(67	)	$	(60	)
Net changes in prices and production costs		(52	)		131			(135	)
Development costs incurred during the period		40			53			6
Net changes in future development costs		(43	)		12			(1	)
Extensions, discoveries and other additions		65			187			120
Acquisitions		(1	)		—			—
Revisions of previous quantity estimates		(199	)		23			(12	)
Accretion of discount		60			24			37
Net change in income taxes		90			(106	)		(25	)
Other changes		17			(1	)		(79	)
Net increase (decrease)	$	(98	)	$	256		$	(149	)
Beginning of year		483			227			376
End of year	$	385		$	483		$	227