Edgar Filing: RANGE RESOURCES CORP

Large Accelerated Filer

Accelerated Filer

Non-Accelerated Filer

¨ (Do not check if smaller reporting company)

Smaller Reporting Company

FORM 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark one)

þ	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2012

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 001-12209

RANGE RESOURCES CORPORATION

(Exact Name of Registrant as Specified in Its Charter)


Delaware		34-1312571
(State or Other Jurisdiction of Incorporation or Organization)		(IRS Employer Identification No.)

100 Throckmorton Street, Suite 1200 Fort Worth, Texas		76102
(Address of Principal Executive Offices)		(Zip Code)

Registrant’s telephone number, including area code

(817) 870-2601

Former Name, Former Address and Former Fiscal Year, if changed since last report: Not applicable

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for shorter period that the registrant was required to submit and post such files). Yes ¨ No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

162,485,399 Common Shares were outstanding on July 23, 2012.

RANGE RESOURCES CORPORATION

FORM 10-Q

Quarter Ended June 30, 2012

Unless the context otherwise indicates, all references in this report to “Range,” “we,” “us,” or “our” are to Range Resources Corporation and its wholly-owned subsidiaries and its ownership interests in equity method investees.

TABLE OF CONTENTS


		Page
PART I – FINANCIAL INFORMATION

ITEM 1.	Financial Statements:

	Consolidated Balance Sheets (Unaudited)		3

	Consolidated Statements of Operations (Unaudited)		4

	Consolidated Statements of Comprehensive Income (Unaudited)		5

	Consolidated Statements of Cash Flows (Unaudited)		6

	Selected Notes to Consolidated Financial Statements (Unaudited)		7

ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		25

ITEM 3.	Quantitative and Qualitative Disclosures about Market Risk		38

ITEM 4.	Controls and Procedures		41

PART II – OTHER INFORMATION

ITEM 1.	Legal Proceedings		42

ITEM 1A.	Risk Factors		42

ITEM 6.	Exhibits		43

PART I – FINANCIAL INFORMATION

ITEM 1.

Financial Statements

RANGE RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)


	June 30, 2012			December 31, 2011
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	158		$	92
Accounts receivable, less allowance for doubtful accounts of $2,783 and $4,015		104,952			127,180
Unrealized derivative gain		251,236			173,921
Inventory and other		15,997			14,070

Total current assets		372,343			315,263


Unrealized derivative gain		97,750			77,579
Equity method investments		135,825			138,130
Natural gas and oil properties, successful efforts method		7,596,430			6,784,027
Accumulated depletion and depreciation		(1,825,390	)		(1,626,461	)

		5,771,040			5,157,566

Transportation and field assets		117,519			123,349
Accumulated depreciation and amortization		(70,901	)		(70,671	)

		46,618			52,678

Other assets		120,318			104,254

Total assets	$	6,543,894		$	5,845,470


Liabilities
Current liabilities:
Accounts payable	$	266,412		$	311,369
Asset retirement obligations		5,005			5,005
Accrued liabilities		144,765			109,109
Liabilities of discontinued operations		—			653
Deferred tax liability		82,170			56,595
Accrued interest		38,865			29,201
Unrealized derivative loss		3,283			—

Total current liabilities		540,500			511,932

Bank debt		235,000			187,000
Subordinated notes		2,388,562			1,787,967
Deferred tax liability		698,429			710,490
Unrealized derivative loss		2,405			173
Deferred compensation liability		170,763			169,188
Asset retirement obligations and other liabilities		91,514			86,300

Total liabilities		4,127,173			3,453,050

Commitments and contingencies
Stockholders’ Equity
Preferred stock, $1 par, 10,000,000 shares authorized, none issued and outstanding		—			—
Common stock, $0.01 par, 475,000,000 shares authorized, 162,483,363 issued at June 30, 2012 and 161,302,973 issued at December 31, 2011		1,624			1,613
Common stock held in treasury, 153,806 shares at June 30, 2012 and 171,426 shares at December 31, 2011		(5,655	)		(6,343	)
Additional paid-in capital		1,888,841			1,866,554
Retained earnings		374,873			373,969
Accumulated other comprehensive income		157,038			156,627

Total stockholders’ equity		2,416,721			2,392,420

Total liabilities and stockholders’ equity	$	6,543,894		$	5,845,470

See the accompanying notes.

RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited, in thousands, except per share data)


	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Revenues and other income:
Natural gas, NGLs and oil sales	$	298,349		$	285,353		$	615,966		$	537,316
Derivative fair value income		148,569			53,039			87,736			12,205
Loss on the sale of assets		(3,227	)		(1,622	)		(13,653	)		(1,483	)
Other		(1,251	)		(1,475	)		(716	)		(85	)

Total revenues and other income		442,440			335,295			689,333			547,953


Costs and expenses:
Direct operating		27,041			28,509			56,063			57,226
Transportation, gathering and compression		44,744			28,666			85,564			53,748
Production and ad valorem taxes		11,786			7,550			48,420			14,429
Exploration		15,517			11,592			37,033			38,779
Abandonment and impairment of unproved properties		43,641			18,900			63,930			35,437
General and administrative		44,005			39,120			82,734			73,079
Deferred compensation plan		9,333			(5,778	)		1,503			24,852
Interest expense		42,888			31,383			80,093			56,162
Loss on early extinguishment of debt		—			18,580			—			18,580
Depletion, depreciation and amortization		108,802			78,294			208,953			150,510

Total costs and expenses		347,757			256,816			664,293			522,802


Income from continuing operations before income taxes		94,683			78,479			25,040			25,151

Income tax expense
Current		—			8			—			8
Deferred		39,007			32,695			11,164			12,798

		39,007			32,703			11,164			12,806


Income from continuing operations		55,676			45,776			13,876			12,345
Discontinued operations, net of taxes		—			5,517			—			13,915

Net income	$	55,676		$	51,293		$	13,876		$	26,260


Income per common share:
Basic-income from continuing operations	$	0.34		$	0.28		$	0.09		$	0.08
-discontinued operations		—			0.04			—			0.08

-net income	$	0.34		$	0.32		$	0.09		$	0.16


Diluted-income from continuing operations	$	0.34		$	0.28		$	0.09		$	0.08
-discontinued operations		—			0.04			—			0.08

-net income	$	0.34		$	0.32		$	0.09		$	0.16


Dividends per common share	$	0.04		$	0.04		$	0.08		$	0.08


Weighted average common shares outstanding:
Basic		159,412			157,997			159,162			157,772
Diluted		160,030			158,833			159,949			158,729

See the accompanying notes.

RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited, in thousands)


	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011

Net income	$	55,676		$	51,293		$	13,876		$	26,260
Other comprehensive income:
Realized loss (gain) on hedge derivative contract settlements reclassified into earnings from other comprehensive income, net of taxes		(47,934	)		(15,178	)		(83,376	)		(39,068	)
Change in unrealized deferred hedging gains, net of taxes		4,813			17,424			83,787			17,537

Total comprehensive income	$	12,555		$	53,539		$	14,287		$	4,729

See the accompanying notes.

RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, in thousands)


	Six Months Ended June 30,
	2012			2011
Operating activities:
Net income	$	13,876		$	26,260
Adjustments to reconcile net income to net cash provided from operating activities:
Gain from discontinued operations		—			(13,915	)
Income (loss) from equity method investments, net of distributions		2,293			15,102
Deferred income tax expense		11,164			12,798
Depletion, depreciation and amortization		208,953			150,510
Exploration dry hole costs		817			6
Mark-to-market on natural gas, NGL and oil derivatives not designated as hedges		(83,721	)		(8,103	)
Abandonment and impairment of unproved properties		63,930			35,437
Unrealized derivative loss (gain)		354			(6,502	)
Allowance for bad debts		—			(404	)
Amortization of deferred financing costs, loss on extinguishment of debt and other		3,893			21,678
Deferred and stock-based compensation		26,341			48,161
Loss on the sale of assets		13,653			1,483
Changes in working capital:
Accounts receivable		11,611			(9,999	)
Inventory and other		(2,824	)		2,769
Accounts payable		(21,922	)		5,015
Accrued liabilities and other		34,528			7,655

Net cash provided from continuing operations		282,946			287,951
Net cash provided from discontinued operations		—			21,554

Net cash provided from operating activities		282,946			309,505


Investing activities:
Additions to natural gas and oil properties		(781,574	)		(536,776	)
Additions to field service assets		(1,526	)		(2,829	)
Acreage purchases		(147,944	)		(73,070	)
Proceeds from disposal of assets		15,620			23,409
Purchase of marketable securities held by the deferred compensation plan		(7,872	)		(8,832	)
Proceeds from the sales of marketable securities held by the deferred compensation plan		3,590			6,620

Net cash used in investing activities from continuing operations		(919,706	)		(591,478	)
Net cash provided from investing activities from discontinued operations		—			840,723

Net cash (used in) provided from investing activities		(919,706	)		249,245


Financing activities:
Borrowing on credit facilities		697,000			490,826
Repayment on credit facilities		(649,000	)		(764,826	)
Issuance of subordinated notes		600,000			500,000
Repayment of subordinated notes		—			(413,332	)
Dividends paid		(12,972	)		(12,860	)
Debt issuance costs		(12,455	)		(21,653	)
Issuance of common stock		2,074			554
Change in cash overdrafts		3,346			(58,265	)
Proceeds from the sales of common stock held by the deferred compensation plan		8,833			6,797

Net cash provided from (used in) financing activities		636,826			(272,759	)

Increase in cash and cash equivalents		66			285,991
Cash and cash equivalents at beginning of period		92			2,848

Cash and cash equivalents at end of period	$	158		$	288,839

See the accompanying notes.

RANGE RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

(1)

SUMMARY OF ORGANIZATION AND NATURE OF BUSINESS

Range Resources Corporation (“Range,” “we,” “us,” or “our”) is a Fort Worth, Texas-based independent natural gas, natural gas liquids and oil company primarily engaged in the exploration, development and acquisition of natural gas and oil properties in the Appalachian and Southwestern regions of the United States. Our objective is to build stockholder value through consistent growth in reserves and production on a cost-efficient basis. Range is a Delaware corporation with our common stock listed and traded on the New York Stock Exchange under the symbol “RRC.”

(2)

BASIS OF PRESENTATION

Presentation

These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Range Resources Corporation 2011 Annual Report on Form 10-K filed on February 22, 2012, as amended by the Form 10-K/A filed on February 23, 2012. The results of operations for the quarter and the six months ended June 30, 2012 are not necessarily indicative of the results to be expected for the full year. These consolidated financial statements are unaudited but, in the opinion of management, reflect all adjustments necessary for fair presentation of the results for the periods presented. All adjustments are of a normal recurring nature unless disclosed otherwise. These consolidated financial statements, including selected notes, have been prepared in accordance with the applicable rules of the Securities and Exchange Commission (“SEC”) and do not include all of the information and disclosures required by accounting principles generally accepted in the United States of America (“U.S. GAAP”) for complete financial statements. Certain reclassifications have been made to prior year’s reported amounts in order to conform with the current year presentation. This reclassification includes third party transportation and gathering costs which were reflected as a component of natural gas, NGL and oil sales and are currently reported as a separate operating expense. These reclassifications have no impact on previously reported net income.

In first quarter 2012, the Pennsylvania legislature passed an “impact fee” on unconventional natural gas and oil production and as a result, we have recorded in the first six months ended June 30, 2012, a retroactive impact fee of $24.7 million for wells drilled during 2011 and prior. This expense is reflected in our statement of operations category production and ad valorem taxes. The impact fee is a per well annual fee imposed for a period of fifteen years on all unconventional wells drilled in Pennsylvania. The fee is based on the average annual price of natural gas and the Consumer Price Index. The annual fee per well declines each year over the fifteen year time period as long as the well is producing. In second quarter 2012, we also recorded a $23.1 million abandonment and impairment expense related to a transaction involving individually significant unproved leases in two Pennsylvania counties where we do not expect to drill.

Discontinued Operations

In February 2011, we entered into an agreement to sell substantially all of our Barnett Shale assets. In April 2011, we completed the sale of most of these assets and closed the remainder of the sale in August 2011. We have classified the historical results of these operations as discontinued operations, net of tax, in the accompanying consolidated statements of operations. See also Notes 4 and 5 for more information regarding the sale of our Barnett Shale assets. Unless otherwise indicated, the information in these notes to the consolidated financial statements relates to our continuing operations.

(3)

NEW ACCOUNTING STANDARDS

In May 2011, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS.” This pronouncement was issued to provide a consistent definition of fair value and ensure that the fair value measurement and disclosure requirements are similar between U.S. GAAP and International Financial Reporting Standards. ASU 2011-04 changes certain fair value measurement principles and enhances the disclosure requirements, particularly for Level 3 fair value measurements. This pronouncement is effective for reporting periods beginning on or after December 15, 2011, with early adoption prohibited. The new guidance requires prospective application. We adopted this new requirement in first quarter 2012 and it did not have a material effect on our consolidated financial statements.

In December 2011, the FASB issued ASU No. 2011-11, “Disclosures about Offsetting Assets and Liabilities” requiring additional disclosures about offsetting and related arrangements. ASU 2011-11 is effective retrospectively for annual reporting periods beginning on or after January 1, 2013. The adoption of ASU 2011-11 is not expected to impact our future financial position, results of operation or liquidity.

(4)

DISPOSITIONS

2012 Dispositions

In June 2012, we sold a suspended exploratory well in the Marcellus Shale for proceeds of $2.5 million resulting in a pre-tax loss of $2.5 million. In March 2012, we sold seventy-five percent of a prospect in East Texas which included unproved properties and a suspended exploratory well to a third party for $8.6 million resulting in a pre-tax loss of $10.9 million. As part of this agreement, we retained a carried interest on the first well drilled and an overriding royalty of 2.5 to 5.0% in the prospect.

2011 Dispositions

In February 2011, we entered into an agreement to sell substantially all of our Barnett Shale properties located in North Central Texas (Dallas, Denton, Ellis, Hill, Hood, Johnson, Parker, Tarrant and Wise Counties), which was subject to normal post-closing adjustments. We closed substantially all of this sale in April 2011 and closed the remainder in August 2011. The gross cash proceeds were approximately $889.3 million, including certain derivative contracts assumed by the buyer. The agreements had a February 1, 2011 effective date and consequently operating net revenues after January 2011 were a downward adjustment to the sales price. As indicated in Notes 2 and 5, the historic results of our Barnett Shale operations are presented as discontinued operations. In first quarter 2011, we also sold a low pressure pipeline for $14.7 million in proceeds, with no gain or loss recognized.

Also as part of the sale of our Barnett Shale properties, certain derivative contracts were assumed by the buyer. This resulted in a loss of $1.7 million in second quarter 2011, which is included in continuing operations. The hedges assumed as part of the sale were not designated to our Barnett production.

(5)

DISCONTINUED OPERATIONS

The following table represents the components of our Barnett Shale operations as discontinued operations for the three months and the six months ended June 30, 2011 (in thousands).


	Three Months Ended June 30, 2011		Six Months Ended June 30, 2011
Revenues and other income:
Natural gas, NGLs and oil sales	$	12,751	$	57,324
Other		1		10
Gain on the sale of assets		3,820		3,820

Total revenues and other income		16,572		61,154


Costs and expenses:
Direct operating		2,169		10,446
Transportation, gathering and compression		1,974		4,290
Production and ad valorem taxes		184		1,250
Exploration expense		5		37
Interest expense ^(a)		3,715		14,791
Depletion, depreciation and amortization		14		8,894

Total costs and expenses		8,061		39,708


Income before income taxes		8,511		21,446

Income tax expense
Current		—		—
Deferred		2,994		7,531

		2,994		7,531


Net income from discontinued operations	$	5,517	$	13,915

^(a)	Interest expense is allocated to discontinued operations based on the ratio of net assets of discontinued operations to our consolidated net assets plus long-term debt.

The carrying values of our Barnett operations were included in discontinued operations in the accompanying consolidated balance sheets, which is comprised of the following (in thousands):


	December 31, 2011

Composition of liabilities of discontinued operations:
Accrued liabilities	$	653

Total current liabilities of discontinued operations	$	653

(6)

INCOME TAXES

Income tax expense from continuing operations was as follows (in thousands):


	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011

Income tax expense	$	39,007		$	32,703		$	11,164		$	12,806
Effective tax rate		41.2	%		41.7	%		44.6	%		50.9	%

We compute our quarterly taxes under the effective tax rate method based on applying an anticipated annual effective rate to our year-to-date income, except for discrete items. Income taxes for discrete items are computed and recorded in the period that the specific transaction occurs. For second quarter and six months ended June 30, 2012 and 2011, our overall effective tax rate on pre-tax income from continuing operations was different than the statutory rate of 35% due primarily to state income taxes, valuation allowances and other permanent differences.

(7)

INCOME PER COMMON SHARE

Basic income or loss per share attributable to common shareholders is computed as (1) income or loss attributable to common shareholders (2) less income allocable to participating securities (3) divided by weighted average basic shares outstanding. Diluted income or loss per share attributable to common stockholders is computed as (1) basic income or loss attributable to common shareholders (2) plus diluted adjustments to income allocable to participating securities (3) divided by weighted average diluted shares outstanding. The following table sets forth a reconciliation of income or loss attributable to common shareholders to basic income or loss attributable to common shareholders and to diluted income or loss attributable to common shareholders (in thousands except per share amounts):


	Three Months Ended June 30, 2012								Three Months Ended June 30, 2011
	Continuing Operations			Discontinued Operations		Total			Continuing Operations			Discontinued Operations			Total

Income as reported	$	55,676		$	—	$	55,676		$	45,776		$	5,517		$	51,293
Participating basic earnings ^(a)		(999	)		—		(999	)		(808	)		(97	)		(905	)

Basic income attributed to common shareholders		54,677			—		54,677			44,968			5,420			50,388
Reallocation of participating earnings ^(a)		3			—		3			4			1			5

Diluted income attributed to common shareholders	$	54,680		$	—	$	54,680		$	44,972		$	5,421		$	50,393


Income per common share:
Basic	$	0.34		$	—	$	0.34		$	0.28		$	0.04		$	0.32
Diluted	$	0.34		$	—	$	0.34		$	0.28		$	0.04		$	0.32

^(a)

Restricted Stock Awards represent participating securities because they participate in nonforfeitable dividends or distributions with common equity owners. Income allocable to participating securities represents the distributed and undistributed earnings attributable to the participating securities. Participating securities, however, do not participate in undistributed net losses.


	Six Months Ended June 30, 2012								Six Months Ended June 30, 2011
	Continuing Operations			Discontinued Operations		Total			Continuing Operations			Discontinued Operations			Total

Income as reported	$	13,876		$	—	$	13,876		$	12,345		$	13,915		$	26,260
Participating basic earnings ^(a)		(246	)		—		(246	)		(220	)		(248	)		(468	)

Basic income attributed to common shareholders		13,630			—		13,630			12,125			13,667			25,792
Reallocation of participating earnings ^(a)		—			—		—			—			1			1

Diluted income attributed to common shareholders	$	13,630		$	—	$	13,630		$	12,125		$	13,668		$	25,793


Income per common share:
Basic	$	0.09		$	—	$	0.09		$	0.08		$	0.08		$	0.16
Diluted	$	0.09		$	—	$	0.09		$	0.08		$	0.08		$	0.16

^(a)

The following table provides a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Denominator:
Weighted average common shares outstanding – basic		159,412		157,997		159,162		157,772
Effect of dilutive securities:
Director and employee stock options and SARs		618		836		787		957

Weighted average common shares outstanding – diluted		160,030		158,833		159,949		158,729

Weighted average common shares – basic for the three months ended June 30, 2012 excludes 2.9 million shares and the three months ended June 30, 2011 excludes 2.8 million shares of restricted stock held in our deferred compensation plans (although all awards are issued and outstanding upon grant). Weighted average common shares-basic for the six months ended June 30, 2012 and 2011 excludes 2.9 million shares of restricted stock. SARs of 761,000 for the three months ended June 30, 2012 and 592,000 for the six months ended June 30, 2012 were outstanding but not included in the computations of diluted income from continuing operations per share because the grant prices of the SARs were greater than the average market price of the common shares. SARs of 860,000 for the three months ended June 30, 2011 and 1.0 million for the six months ended June 30, 2011 were outstanding but not included in the computations of diluted income from continuing operations per share because the grant prices of the SARs were greater than the average market price of the common shares.

(8)

SUSPENDED EXPLORATORY WELL COSTS

We capitalize exploratory well costs until a determination is made that the well has either found proved reserves or that it is impaired. Capitalized exploratory well costs are presented in natural gas and oil properties in the accompanying consolidated balance sheets. If an exploratory well is determined to be impaired, the well costs are charged to exploration expense in the accompanying consolidated statements of operations. The following table reflects the changes in capitalized exploratory well costs for the six months ended June 30, 2012 and the year ended December 31, 2011 (in thousands except for number of projects):


	June 30, 2012			December 31, 2011

Balance at beginning of period	$	93,388		$	23,908
Additions to capitalized exploratory well costs pending the determination of proved reserves		150,136			86,996
Reclassifications to wells, facilities and equipment based on determination of proved reserves		(178,423	)		(17,516	)
Divested wells		(4,980	)		—
Capitalized exploratory well costs charged to expense		—			—

Balance at end of period		60,121			93,388
Less exploratory well costs that have been capitalized for a period of one year or less		(39,107	)		(83,860	)

Capitalized exploratory well costs that have been capitalized for a period greater than one year	$	21,014		$	9,528


Number of projects that have exploratory well costs that have been capitalized for a period greater than one year		8			3

As of June 30, 2012, $21.0 million of capitalized exploratory well costs have been capitalized for more than one year with five of the wells waiting on pipelines and three of the wells currently in the completion stage. Seven of the wells are located in our Marcellus Shale area. In second quarter 2012, we sold a Marcellus Shale exploratory well. In the first quarter 2012, we sold a seventy-five percent interest in an East Texas exploratory well. For additional information, see Note 4. The following table provides an aging of capitalized exploratory well costs that have been suspended for more than one year as of June 30, 2012 (in thousands):


	Total		2012		2011		2010		2009		2008

Capitalized exploratory well costs that have been capitalized for more than one year	$	21,014	$	6,933	$	9,602	$	72	$	2,884	$	1,523

(9)

INDEBTEDNESS

We had the following debt outstanding as of the dates shown below (bank debt interest rate at June 30, 2012 is shown parenthetically). No interest was capitalized during the three months or the six months ended June 30, 2012 or 2011 (in thousands):


	June 30, 2012		December 31, 2011

Bank debt (2.2%)	$	235,000	$	187,000

Senior subordinated notes:
7.50% senior subordinated notes due 2017		250,000		250,000
7.25% senior subordinated notes due 2018		250,000		250,000
8.00% senior subordinated notes due 2019, net of $11,438 and $12,033 discount, respectively		288,562		287,967
6.75% senior subordinated notes due 2020		500,000		500,000
5.75% senior subordinated notes due 2021		500,000		500,000
5.00% senior subordinated notes due 2022		600,000		—

Total debt	$	2,623,562	$	1,974,967

Bank Debt

In February 2011, we entered into an amended and restated revolving bank facility, which we refer to as our bank debt or our bank credit facility, which is secured by substantially all of our assets. The bank credit facility provides for an initial commitment equal to the lesser of the facility amount or the borrowing base. On June 30, 2012, the facility amount was $1.75 billion and the borrowing base was $2.0 billion. The bank credit facility provides for a borrowing base subject to redeterminations semi-annually and for event-driven unscheduled redeterminations. Our current bank group is comprised of twenty-eight financial institutions, with no one bank holding more than 9% of the total facility which includes three additional banks that were added in April 2012. The facility amount may be increased to the borrowing base amount with twenty days notice, subject to the banks agreeing to participate in the facility increase and payment of a mutually acceptable commitment fee to those banks. As of June 30, 2012, the outstanding balance under our bank credit facility was $235.0 million as well as $62.1 million of undrawn letters of credit leaving $1.5 billion of borrowing capacity available under the facility amount. The facility matures on February 18, 2016. Borrowings under the bank facility can either be at the Alternate Base Rate (as defined) plus a spread ranging from 0.50% to 1.5% or LIBOR borrowings at the Adjusted LIBO Rate (as defined) plus a spread ranging from 1.5% to 2.5%. The applicable spread is dependent upon borrowings relative to the borrowing base. We may elect, from time to time, to convert all or any part of our LIBOR loans to base rate loans or to convert all or any of the base rate loans to LIBOR loans. The weighted average interest rate was 2.7% for the three months ended June 30, 2012 compared to 2.0% for the three months ended June 30, 2011. The weighted average interest rate was 2.3% for the six months ended June 30, 2012 compared to 2.2% for the six months ended June 30, 2011. A commitment fee is paid on the undrawn balance based on an annual rate of 0.375% to 0.50%. At June 30, 2012, the commitment fee was 0.375% and the interest rate margin was 1.5% on our LIBOR loans and 0.5% on our base rate loans.

Senior Subordinated Notes

In March 2012, we issued $600.0 million aggregate principal amount of 5.00% senior subordinated notes due 2022 (“5.00% Notes”) for net proceeds of $589.5 million after underwriting discounts and commissions of $10.5 million. The 5.00% Notes were issued at par. Interest on the 5.00% Notes is payable semi-annually in February and August and is guaranteed by all of our subsidiary guarantors. We may redeem the 5.00% Notes, in whole or in part, at any time on or after February 15, 2017, at redemption prices of 102.5% of the principal amount as of February 15, 2017, declining to 100% on February 15, 2020 and thereafter. Before February 2015, we may redeem up to 35% of the original aggregate principal amount of the 5.00% Notes at a redemption price equal to 105% of the principal amount thereof, plus accrued and unpaid interest, if any, with the proceeds of certain equity offerings, provided that 65% of the aggregate principal amount of 5.00% Notes remains outstanding immediately after the occurrence of such redemption and also provided such redemption shall occur within 60 days of the date of the closing of the equity offering. On closing of the 5.00% Notes, we used $350.0 million of the proceeds to pay down our outstanding credit facility balance.

If we experience a change of control, bondholders may require us to repurchase all or a portion of all of our senior subordinated notes at 101% of the aggregate principal amount plus accrued and unpaid interest, if any. All of the senior subordinated notes and the guarantees by our subsidiary guarantors are general, unsecured obligations and are subordinated to our bank debt and will be subordinated to future senior debt that we or our subsidiary guarantors are permitted to incur under the bank credit facility and the indentures governing the subordinated notes.

Guarantees

Range Resources Corporation is a holding company which owns no operating assets and has no significant operations independent of its subsidiaries. The guarantees by our subsidiaries of our senior subordinated notes are full and unconditional and joint and several.

Debt Covenants and Maturity

Our bank credit facility contains negative covenants that limit our ability, among other things, to pay cash dividends, incur additional indebtedness, sell assets, enter into certain hedging contracts, change the nature of our business or operations, merge, consolidate, or make investments. In addition, we are required to maintain a ratio of debt to EBITDAX (as defined in the credit agreement) of no greater than 4.25 to 1.0 and a current ratio (as defined in the credit agreement) of no less than 1.0 to 1.0. We were in compliance with our covenants under the bank credit facility at June 30, 2012.

The indentures governing our senior subordinated notes contain various restrictive covenants that are substantially identical to each other and may limit our ability to, among other things, pay cash dividends, incur additional indebtedness, sell assets, enter into transactions with affiliates, or change the nature of our business. At June 30, 2012, we were in compliance with these covenants.

(10)

ASSET RETIREMENT OBLIGATIONS

Our asset retirement obligations primarily represent the estimated present value of the amounts we will incur to plug, abandon and remediate our producing properties at the end of their productive lives. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, estimated future inflation rates and well life. The inputs are calculated based on historical data as well as current estimated costs. A reconciliation of our liability for plugging and abandonment costs for first six months ended June 30, 2012 is as follows (in thousands):


	Six Months Ended June 30, 2012

Beginning of period	$	84,810
Liabilities incurred		4,009
Liabilities settled		(2,142	)
Disposition of wells		(151	)
Accretion expense		3,668
Change in estimate		(5	)

End of period		90,189

Less current portion		(5,005	)


Long-term asset retirement obligations	$	85,184

Accretion expense is recognized as a component of depreciation, depletion and amortization expense in the accompanying statements of operations.

(11)

CAPITAL STOCK

We have authorized capital stock of 485.0 million shares which includes 475.0 million shares of common stock and 10.0 million shares of preferred stock. We currently have no preferred stock issued or outstanding. The following is a schedule of changes in the number of common shares outstanding since the beginning of 2011:


	Six Months Ended June 30, 2012		Year Ended December 31, 2011

Beginning balance		161,131,547		159,909,052
Stock options/SARs exercised		773,299		862,774
Restricted stock grants		354,674		326,591
Restricted stock units vested		52,417		—
Treasury shares		17,620		33,130

Ending balance		162,329,557		161,131,547

(12)

DERIVATIVE ACTIVITIES

We use commodity-based derivative contracts to manage exposure to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. We do not utilize complex derivatives as we typically utilize commodity swap, collar, call or put option contracts to (1) reduce the effect of price volatility of the commodities we produce and sell and (2) support our annual capital budget and expenditure plans. In 2011, we sold natural gas liquids (“NGLs”) derivative swap contracts (“sold swaps”) for the natural gasoline (or C5) component of natural gas liquids and in 2012, we also entered into purchased derivative swaps (“purchased swaps”) for C5 volumes. These purchased swaps were, in some cases, with the same counterparties as our sold swaps. We entered into these purchased swaps to lock in certain natural gasoline derivative gains. In second quarter 2012, we also entered into NGL derivative swap contracts for the propane (or C3) component of natural gas liquids. At June 30, 2012, we had open swap contracts covering 106.2 Bcf of natural gas at prices averaging $3.64 per mcf, 3.2 million barrels of oil at prices averaging $95.61 per barrel, 3.6 million net barrels of NGLs (the C5 component of NGLs) at prices averaging $97.85 per barrel and 2.9 million barrels of NGLs (the C3 component of NGLs) at prices averaging $36.73 per barrel. At June 30, 2012, we had collars covering 228.5 Bcf of natural gas at weighted average floor and cap prices of $4.35 to $4.93 per mcf and 2.2 million barrels of oil at weighted average floor and cap prices of $85.46 to $96.64 per barrel. At June 30, 2012, we also had sold call options for 0.9 million barrels of oil at a weighted average price of $85.00 per barrel and purchased put options for 0.5 million barrels of oil at a weighted average price of $80.00. Their fair value, represented by the estimated amount that would be realized upon termination, based on a comparison of the contract price and a reference price, generally the New York Mercantile Exchange (“NYMEX”), approximated a net unrealized pre-tax gain of $343.3 million at June 30, 2012. These contracts expire monthly through December 2014. The following table sets forth our derivative volumes by year as of June 30, 2012.


Period	Contract Type	Volume Hedged	Weighted Average Hedge Price

Natural Gas
2012	Collars	279,641 Mmbtu/day	$ 4.76–$ 5.22
2013	Collars	240,000 Mmbtu/day	$ 4.73–$ 5.20
2014	Collars	245,000 Mmbtu/day	$ 3.74–$ 4.50
2012	Swaps	245,000 Mmbtu/day	$3.75
2013	Swaps	167,521 Mmbtu/day	$3.56

Crude Oil
2012	Collars	2,000 bbls/day	$ 70.00–$ 80.00
2013	Collars	3,000 bbls/day	$ 90.60–$ 100.00
2014	Collars	2,000 bbls/day	$ 85.55–$ 100.00
2012	Call Options	4,700 bbls/day	$85.00
2012	Put Option	2,500 bbls/day	$80.00
2013	Swaps	6,313 bbls/day	$96.49
2014	Swaps	4,000 bbls/day	$94.56

NGLs (Natural Gasoline)
2012	Sold Swaps	12,000 bbls/day	$96.28
2013	Sold Swaps	8,000 bbls/day	$89.64
2012	Purchased Swaps	5,500 bbls/day	$82.37
2013	Purchased Swaps	1,500 bbls/day	$76.30

NGLs (Propane)
2012	Swaps	6,000 bbls/day	$38.67
2013	Swaps	5,000 bbls/day	$35.55

Every derivative instrument is required to be recorded on the balance sheet as either an asset or a liability measured at its fair value. Fair value is determined based on the difference between the fixed contract price and the underlying market price at the determination date. Changes in the fair value of our derivatives that qualify for hedge accounting are recorded as a component of accumulated other comprehensive income (“AOCI”) in the stockholders’ equity section of the accompanying consolidated balance sheets, which is later transferred to natural gas, NGLs and oil sales when the underlying physical transaction occurs and the hedging contract is settled. As of June 30, 2012, an unrealized pre-tax derivative gain of $257.4 million was recorded in AOCI. This gain will be reclassified into earnings as a gain of $114.5 million in 2012, a gain of $121.9 million in 2013 and a gain of $21.0 million in 2014 as the contracts settle. The actual reclassification to earnings will be based on market prices at the contract settlement date. If the derivative does not qualify as a hedge or is not designated as a hedge, changes in fair value of these non-hedge derivatives are recognized in earnings in derivative fair value income.

For those derivative instruments that qualify for hedge accounting, settled transaction gains and losses are determined monthly, and are included as increases or decreases to natural gas, NGLs and oil sales in the period the hedged production is sold. Through June 2012, we have elected to designate our commodity derivative instruments that qualify for hedge accounting as cash flow hedges. Natural gas, NGLs and oil sales include $78.6 million of gains in second quarter 2012 compared to gains of $24.3 million in the same period of 2011 related to settled hedging transactions. Natural gas, NGLs and oil sales include $136.2 million of gains in the first six months 2012 compared to $53.9 million in the same period of 2011. Any ineffectiveness associated with these hedge derivatives are reflected in derivative fair value income in the accompanying statements of operations. The ineffective portion is calculated as the difference between the changes in fair value of the derivative and the estimated change in future cash flows from the item hedged. Derivative fair value income for the three months ended June 30, 2012 includes ineffective gains (unrealized and realized) of $1.9 million compared to $7.5 million in the three months ended June 30, 2011. Derivative fair value income for the six months ended June 30, 2012 includes ineffective gains (unrealized and realized) of $2.1 million compared to $9.0 million in the same period of 2011.

Derivative fair value income

The following table presents information about the components of derivative fair value income for the three months and the six months ended June 30, 2012 and 2011 (in thousands):


	Three Months Ended June 30,					Six Months Ended June 30,
	2012		2011			2012			2011

Change in fair value of derivatives that do not qualify for hedge accounting ^(a)	$	135,777	$	48,139		$	83,721		$	8,103
Realized gain (loss) on settlement – natural gas ^(a) ^(b)		—		3,484			—			3,090
Realized gain (loss) on settlement – oil ^{(a) (b)}		768		(6,094	)		(3,854	)		(8,012	)
Realized gain (loss) on settlement – NGLs ^{(a) (b)}		10,152		—			5,760			—
Hedge ineffectiveness – realized		1,278		1,576			2,463			2,522
– unrealized		594		5,934			(354	)		6,502

Derivative fair value income	$	148,569	$	53,039		$	87,736		$	12,205

^(a)	Derivatives that do not qualify for hedge accounting.

^(b)	These amounts represent the realized gains and losses on settled derivatives that do not qualify for hedge accounting, which before settlement are included in the category in this same table referred to as change in fair value of derivatives that do not qualify for hedge accounting.

Derivative assets and liabilities

The combined fair value of derivatives included in the accompanying consolidated balance sheets as of June 30, 2012 and December 31, 2011 is summarized below (in thousands). As of June 30, 2012, we are conducting derivative activities with sixteen financial institutions, of which all but two are secured lenders in our bank credit facility. We believe all of these institutions are acceptable credit risks. At times, such risks may be concentrated with certain counterparties. The credit worthiness of our counterparties is subject to periodic review. The assets and liabilities are netted where derivatives with both gain and loss positions are held by a single counterparty and we have master netting arrangements.


	June 30, 2012			December 31, 2011

Derivative assets:
Natural gas – swaps	$	33,637		$	54,162
– collars		208,178			228,228
Crude oil – swaps		23,744			(263	)
– collars		5,254			(16,607	)
– call options		(4,723	)		(29,348	)
– put options		1,071			—
NGLs – C5 swaps		79,492			15,328
– C3 swaps		2,333			—

	$	348,986		$	251,500

Derivative liabilities:
Natural gas – swaps	$	269		$	—
– collars		(1,112	)		—
NGLs – C5 swaps		(3,232	)		(173	)
– C3 swaps		(1,613	)		—

	$	(5,688	)	$	(173	)

The table below provides data about the fair value of our derivative contracts. Derivative assets and liabilities shown below are presented as gross assets and liabilities, without regard to master netting arrangements, which are considered in the presentation of derivative assets and liabilities in the accompanying consolidated balance sheets (in thousands):


	June 30, 2012								December 31, 2011
	Assets		(Liabilities)						Assets		(Liabilities)
	Carrying Value		Carrying Value			Net Carrying Value			Carrying Value		Carrying Value			Net Carrying Value

Derivatives that qualify for cash flow hedge accounting:
Swaps ^(a)	$	65,114	$	(7,464	)	$	57,650		$	54,318	$	(419	)	$	53,899
Collars ^(a)		221,540		(6,294	)		215,246			228,228		(1,954	)		226,274
Put options ^(a)		1,071		—			1,071			—		—			—

	$	287,725	$	(13,758	)	$	273,967		$	282,546	$	(2,373	)	$	280,173


Derivatives that do not qualify for hedge accounting:
Sold swaps ^(a)	$	87,262	$	(3,342	)	$	83,920		$	17,949	$	(2,794	)	$	15,155
Purchased swaps ^(a)		1,506		(8,447	)		(6,941	)		—		—			—
Collars ^(a)		—		(2,925	)		(2,925	)		—		(14,653	)		(14,653	)
Call options ^(a)		—		(4,723	)		(4,723	)		—		(29,348	)		(29,348	)

	$	88,768	$	(19,437	)	$	69,331		$	17,949	$	(46,795	)	$	(28,846	)

^(a)	Included in unrealized derivative gain or loss in the accompanying consolidated balance sheets.

The effects of our cash flow hedges (or those derivatives that qualify for hedge accounting) on accumulated other comprehensive income in the accompanying consolidated balance sheets is summarized below:


	Three Months Ended June 30,												Six Months Ended June 30,
	Change in Hedge Derivative Fair Value						Realized Gain Reclassified from OCI into Revenue ^(a)						Change in Hedge Derivative Fair Value						Realized Gain Reclassified from OCI into Revenue ^(a)
	2012			2011			2012			2011			2012			2011			2012			2011

Swaps	$	19,665		$	4,655		$	32,334		$	—		$	55,836		$	2,115		$	51,647		$	—
Put options		648			—			(315	)		—			(914	)		—			(315	)		—
Collars		(12,423	)		23,223			46,561			24,285			84,048			22,424			84,878			53,902
Collars – discontinued operations		—			—			—			—			—			412			—			8,607
Income taxes		(3,077	)		(10,454	)		(30,646	)		(9,107	)		(55,183	)		(7,414	)		(52,834	)		(23,441	)

	$	4,813		$	17,424		$	47,934		$	15,178		$	83,787		$	17,537		$	83,376		$	39,068

^(a)	For realized gains upon derivative contract settlement, the reduction in AOCI is offset by an increase in natural gas, NGLs and oil sales. For realized losses upon derivative contract settlement, the increase in AOCI is offset by a decrease in natural gas, NGLs and oil sales.

The effects of our non-hedge derivatives (or those derivatives that do not qualify for hedge accounting) and the ineffective portion of our hedge derivatives on our consolidated statements of operations is summarized below:


	Three Months Ended June 30,
	Gain (Loss) Recognized in Income (Non-hedge Derivatives)					Gain (Loss) Recognized in Income (Ineffective Portion)				Derivative Fair Value Income (Loss)
	2012			2011		2012		2011		2012			2011

Swaps	$	129,313		$	15,613	$	562	$	—	$	129,875		$	15,613
Purchased swaps		(8,744	)		—		—		—		(8,744	)		—
Collars		14,894			6,452		1,310		7,510		16,204			13,962
Call options		11,234			23,464		—		—		11,234			23,464

Total	$	146,697		$	45,529	$	1,872	$	7,510	$	148,569		$	53,039


	Six Months Ended June 30,
	Gain (Loss) Recognized in Income (Non-hedge Derivatives)						Gain (Loss) Recognized in Income (Ineffective Portion)				Derivative Fair Value Income (Loss)
	2012			2011			2012		2011		2012			2011

Swaps	$	76,328		$	13,750		$	666	$	—	$	76,994		$	13,750
Purchased swaps		(8,744	)		—			—		—		(8,744	)		—
Collars		12,392			(1,135	)		1,443		9,024		13,835			7,889
Call options		5,651			(9,391	)		—		—		5,651			(9,391	)
Basis swaps		—			(43)			—		—		—			(43)
Total	$	85,627		$	3,181		$	2,109	$	9,024	$	87,736		$	12,205

(13)

FAIR VALUE MEASUREMENTS

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. There are three approaches for measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which includes multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value amount using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset. This is often referred to as current replacement cost. The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence.

The fair value accounting standards do not prescribe which valuation technique should be used when measuring fair value and does not prioritize among the techniques. These standards establish a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The three levels of the fair value hierarchy are as follows:

•

Level 1 – Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets 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 2 – Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.

•

Level 3 – Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

Fair Values-Recurring

We use a market approach for our recurring fair value measurements and endeavor to use the best information available. Accordingly, valuation techniques that maximize the use of observable impacts are favored. The following tables present the fair value hierarchy table for assets and liabilities measured at fair value, on a recurring basis (in thousands):


	Fair Value Measurements at June 30, 2012 using:
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total Carrying Value as of June 30, 2012

Trading securities held in the deferred compensation plans	$	56,345	$	—		$	—	$	56,345

Derivatives – swaps		—		134,629			—		134,629
– collars		—		212,320			—		212,320
– call options		—		(4,722	)		—		(4,722	)
– put options		—		1,071			—		1,071


	Fair Value Measurements at December 31, 2011 using:
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total Carrying Value as of December 31, 2011

Trading securities held in the deferred compensation plans	$	50,237	$	—		$	—	$	50,237

Derivatives – swaps		—		69,054			—		69,054
– collars		—		211,621			—		211,621
– call options		—		(29,348	)		—		(29,348	)

Our trading securities in Level 1 are exchange-traded and measured at fair value with a market approach using end of period market values. Derivatives in Level 2 are measured at fair value with a market approach using third-party pricing services, which have been corroborated with data from active markets or broker quotes.

Our trading securities held in the deferred compensation plan are accounted for using the mark-to-market accounting method and are included in other assets in the accompanying consolidated balance sheets. We elected to adopt the fair value option to simplify our accounting for the investments in our deferred compensation plan. Interest, dividends, and mark-to-market gains/losses are included in deferred compensation plan expense in the accompanying statement of operations. For second quarter 2012, interest and dividends were $125,000 and mark-to-market was a loss of $2.1 million. For second quarter 2011, interest and dividends were $60,000 and the mark-to-market was a gain of $5,000. For the six months ended June 30, 2012, interest and dividends were $275,000 and mark-to-market was a gain of $1.9 million. For the six months ended June 30, 2011, interest and dividends were $95,000 and mark-to-market was a gain of $1.3 million.

Fair Values – Reported

The following table presents the carrying amounts and the fair values of our financial instruments as of June 30, 2012 and December 31, 2011 (in thousands):


	June 30, 2012						December 31, 2011
	Carrying Value			Fair Value			Carrying Value			Fair Value
Assets:
Commodity swaps, collars, call and put options	$	348,986		$	348,986		$	251,500		$	251,500
Marketable securities^(a)		56,345			56,345			50,237			50,237

Liabilities:
Commodity swaps, collars, call and put options		(5,688	)		(5,688	)		(173	)		(173	)
Bank credit facility^(b)		(235,000	)		(235,000	)		(187,000	)		(187,000	)
7.50% senior subordinated notes due 2017^(b)		(250,000	)		(261,250	)		(250,000	)		(265,625	)
7.25% senior subordinated notes due 2018^(b)		(250,000	)		(265,000	)		(250,000	)		(267,500	)
8.00% senior subordinated notes due 2019^(b)		(288,562	)		(327,750	)		(287,967	)		(334,500	)
6.75% senior subordinated notes due 2020^(b)		(500,000	)		(542,500	)		(500,000	)		(555,000	)
5.75% senior subordinated notes due 2021^(b)		(500,000	)		(522,500	)		(500,000	)		(541,250	)
5.00% senior subordinated notes due 2022^(b)		(600,000	)		(592,500	)		—			—

^(a)	Marketable securities, which are held in our deferred compensation plans, and are actively traded on major exchanges.

^(b)	The book value of our bank debt approximates fair value because of its floating rate structure. The fair value of our senior subordinated notes is based on end of period market quotes which are Level 2 market values.

Our current assets and liabilities contain financial instruments, the most significant of which are trade accounts receivables and payables. We believe the carrying values of our current assets and liabilities approximate fair value. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments and (2) our historical incurrence of and expected future insignificance of bad debt expense.

Concentrations of Credit Risk

As of June 30, 2012, our primary concentrations of credit risk are the risks of collecting accounts receivable and the risk of counterparties’ failure to perform under derivative obligations. Most of our receivables are from a diverse group of companies, including major energy companies, pipeline companies, local distribution companies, financial institutions and end-users in various industries. Letters of credit or other appropriate security are obtained as necessary to limit our risk of loss. Our allowance for uncollectible receivables was $2.8 million at June 30, 2012 compared to $4.0 million at December 31, 2011. As of June 30, 2012, our derivative contracts consist of swaps, collars, call options and put options. Our exposure is diversified primarily among major investment grade financial institutions, the majority of which we have master netting agreements which provide for offsetting payables against receivables from separate derivative contracts. To manage counterparty risk associated with our derivatives, we select and monitor our counterparties based on our assessment of their financial strength and/or credit ratings. We may also limit the level of exposure with any single counterparty. At June 30, 2012 our derivative counterparties include sixteen financial institutions, of which all but two are secured lenders in our bank credit facility. At June 30, 2012, our net derivative assets include a receivable from the two counterparties not included in our bank credit facility of $26.5 million. For those counterparties that are not secured lenders in our bank credit facility or for which we do not have master netting arrangements, net derivative asset values are determined, in part, by reviewing credit default swap spreads for the counterparties. Net derivative liabilities are determined, in part, by using our market-based credit spread. None of our derivative contracts have margin requirements or collateral provisions that would require funding prior to the scheduled cash settlement date. We have also entered into the International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with our counterparties. The terms of the ISDA Agreements provide us and our counterparties with rights of set off upon the occurrence of defined acts of default by either us or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party.

(14)

STOCK-BASED COMPENSATION PLANS

Stock-Based Awards

Stock options represent the right to purchase shares of stock in the future at the fair value of the stock on the date of grant. Most stock options granted under our stock option plans vest over a three-year period and expire five years from the date they are granted. Beginning in 2005, we began granting SARs to reduce the dilutive impact of our equity plans. Similar to stock options, SARs represent the right to receive a payment equal to the excess of the fair market value of shares of common stock on the date the right is exercised over the value of the stock on the date of grant. All SARs granted under the 2005 Plan will be settled in shares of stock, vest over a three-year period and have a maximum term of five years from the date they are granted. Beginning in first quarter 2011, the Compensation Committee also began granting restricted stock units under our equity-based stock compensation plans. These restricted stock units, which we refer to as restricted stock Equity Awards, vest over a three-year period. All awards granted have been issued at prevailing market prices at the time of grant and the vesting of these shares is based upon an employee’s continued employment with us.

The Compensation Committee also grants restricted stock to certain employees and non-employee directors of the Board of Directors as part of their compensation. Compensation expense is recognized over the balance of the vesting period, which is typically three years for employee grants and immediate vesting for non-employee directors. All restricted stock awards are issued at prevailing market prices at the time of the grant and vesting is based upon an employee’s continued employment with us. Prior to vesting, all restricted stock awards have the right to vote such stock and receive dividends thereon. Upon grant of these restricted shares, which we refer to as restricted stock Liability Awards, the shares are placed in our deferred compensation plan and, upon vesting, employees are allowed to take withdrawals either in cash or in stock. These Liability Awards are classified as a liability and are remeasured at fair value each reporting period. This mark-to-market is reported in deferred compensation plan expense in the accompanying consolidated statements of operations.

Total Stock-Based Compensation Expense

Stock-based compensation represents amortization of restricted stock grants and SARs expense. In second quarter 2012, stock-based compensation was allocated to operating expense ($692,000), exploration expense ($994,000) and general and administrative expense ($12.5 million) for a total of $14.6 million. In second quarter 2011, stock-based compensation was allocated to operating expense ($643,000), exploration expense ($937,000) and general and administrative expense ($11.5 million) for a total of $13.4 million. In the first six months ended June 30, 2012, stock-based compensation was allocated to operating expense ($1.0 million), exploration expense ($1.9 million) and general and administrative expense ($20.7 million) for a total of $24.5 million. In the first six months ended June 30, 2011, stock-based compensation was allocated to operating expense ($953,000), exploration expense ($2.3 million) and general and administrative expense ($19.0 million) for a total of $22.9 million. Unlike the other forms of stock-based compensation mentioned above, the mark-to-market of the liability related to the vested restricted stock held in our deferred compensation plans is directly tied to the change in our stock price and not directly related to the functional expenses and therefore, is not allocated to the functional categories.

Stock and Option Plans

We have two active equity-based stock plans, the 2005 Plan and the Director Plan. Under these plans, incentive and non-qualified stock options, SARs, restricted stock units and various other awards may be issued to directors and employees pursuant to decisions of the Compensation Committee, which is made up of non-employee, independent directors from the Board of Directors. All awards granted under these plans have been issued at prevailing market prices at the time of the grant. Of the 4.1 million grants outstanding at June 30, 2012, 32,000 of the grants relate to stock options with the remainder of 4.0 million grants relating to SARs. Information with respect to stock option and SARs activities is summarized below.


	Shares			Weighted Average Exercise Price

Outstanding at December 31, 2011		4,558,609		$	41.47
Granted		754,471			64.14
Exercised		(1,218,780	)		21.90
Expired/forfeited		(6,196	)		48.31

Outstanding at June 30, 2012		4,088,104		$	51.48

Stock Appreciation Right Awards

During first six months 2012, we granted SARs to officers and non-officer employees. The weighted average grant date fair value of these SARs, based on our Black-Scholes-Merton assumptions, is shown below:


	Six Months Ended June 30, 2012

Weighted average exercise price per share	$	64.14
Expected annual dividends per share		0.25	%
Expected life in years		3.7
Expected volatility		45	%
Risk-free interest rate		0.4	%
Weighted average grant date fair value	$	21.32

Restricted Stock Awards

Equity Awards

In the first six months ended June 30, 2012, we granted 360,000 restricted stock Equity Awards to employees compared to 329,000 granted to employees in the same period of 2011. These awards generally vest over a three-year period. We recorded compensation expense for these awards of $5.2 million in first six months ended June 30, 2012 compared to $1.7 million in the same period of 2011. Equity Awards are not issued to employees until they are vested. Employees do not have the option to receive cash.

Liability Awards

In first six months 2012, we granted 355,400 shares of restricted stock Liability Awards as compensation to employees at an average price of $63.87 with vesting generally over a three-year period and 14,700 were granted to directors at an average price of $64.35 with immediate vesting. In the same period of 2011, we granted 334,000 shares of Liability Awards as compensation to employees at an average price of $51.10 with vesting generally over a three-year period and 15,500 shares were granted to directors at an average price of $52.35 with immediate vesting. We recorded compensation expense for Liability Awards of $10.2 million in first six months ended June 30, 2012 compared to $10.4 million in the same period of 2011. Substantially all of these awards are held in our deferred compensation plan, are classified as a liability and are remeasured at fair value each reporting period. This mark-to-market is reported in the deferred compensation expense in our consolidated statements of operations (see additional discussion below).

A summary of the status of our non-vested restricted stock outstanding at June 30, 2012 is summarized below:


	Equity Awards					Liability Awards
	Shares			Weighted Average Grant Date Fair Value		Shares			Weighted Average Grant Date Fair Value

Outstanding at December 31, 2011		221,609		$	49.64		487,244		$	48.76
Granted		359,732			63.37		370,059			63.89
Vested		(85,294	)		56.87		(227,844	)		50.51
Forfeited		(14,307	)		57.56		(1,717	)		51.39

Outstanding at June 30, 2012		481,740		$	58.37		627,742		$	57.04

Deferred Compensation Plan

Our deferred compensation plan gives directors, officers and key employees the ability to defer all or a portion of their salaries and bonuses and invest in Range common stock or make other investments at the individual’s discretion. Range provides a partial matching contribution which vests over three years. The assets of the plans are held in a grantor trust, which we refer to as the Rabbi Trust, and are therefore available to satisfy the claims of our creditors in the event of bankruptcy or insolvency. Our stock held in the Rabbi Trust is treated as a liability award as employees are allowed to take withdrawals from the Rabbi Trust either in cash or in Range stock. The liability for the vested portion of the stock held in the Rabbi Trust is reflected in the deferred compensation liability in the accompanying consolidated balance sheets and is adjusted to fair value each reporting period by a charge or credit to deferred compensation plan expense on our consolidated statements of operations. The assets of the Rabbi Trust, other than our common stock, are invested in marketable securities and reported at their market value in other assets in the accompanying consolidated balance sheets. The deferred compensation liability reflects the vested market value of the marketable securities and Range stock held in the Rabbi Trust. Changes in the market value of the marketable securities and changes in the fair value of the deferred compensation plan liability are charged or credited to deferred compensation plan expense each quarter. We recorded mark-to-market loss of $9.3 million in second quarter 2012 compared to mark-to-market gain of $5.8 million in second quarter 2011. We recorded mark-to-market loss of $1.5 million in the first six months June 30, 2012 compared to mark-to-market loss of $24.9 million in the same period of 2011. The Rabbi Trust held 3.0 million shares (2.3 million of vested shares) of Range stock at June 30, 2012 compared to 2.8 million shares (2.2 million of vested shares) at December 31, 2011.

(15)

SUPPLEMENTAL CASH FLOW INFORMATION


	Six Months Ended June 30,
	2012		2011
	(in thousands)
Net cash provided from operating activities included:
Income taxes paid to taxing authorities	$	246	$	308
Interest paid		66,438		68,002

Non-cash investing and financing activities included:
Asset retirement costs capitalized, net		4,004		12,717

(16)

COMMITMENTS AND CONTINGENCIES

Litigation

We are the subject of, or party to, a number of pending or threatened legal actions and claims arising in the ordinary course of our business. While many of these matters involve inherent uncertainty, we believe that the amount of the liability, if any, ultimately incurred with respect to proceedings or claims will not have a material adverse effect on our consolidated financial position as a whole or on our liquidity, capital resources or future annual results of operations. We will continue to evaluate our litigation on a quarter-by-quarter basis and will establish and adjust any litigation reserves as appropriate to reflect our assessment of the then current status of litigation.

(17)

Capitalized Costs and Accumulated Depreciation, Depletion and Amortization ^(a)


	June 30, 2012		December 31, 2011
	(in thousands)
Natural gas and oil properties:
Properties subject to depletion	$	6,779,021	$	6,035,429
Unproved properties		817,409		748,598

Total		7,596,430		6,784,027
Accumulated depreciation, depletion and amortization		(1,825,390)		(1,626,461)

Net capitalized costs	$	5,771,040	$	5,157,566

^(a)	Includes capitalized asset retirement costs and the associated accumulated amortization.

(18)

Costs Incurred for Property Acquisition, Exploration and Development ^(a)


	Six Months Ended June 30, 2012		Twelve Months Ended December 31, 2011
Acreage purchases	$	151,622	$	220,576
Development		539,122		1,007,049
Exploration:
Drilling		185,081		226,920
Expense		35,112		77,259
Stock-based compensation expense		1,921		4,108
Gas gathering facilities:
Development		23,684		53,387

Subtotal		936,542		1,589,299

Asset retirement obligations		4,004		24,061


Total – continuing operations		940,546		1,613,360
Discontinued operations		—		3,241

Total costs incurred	$	940,546	$	1,616,601

^(a)	Includes cost incurred whether capitalized or expensed.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion is intended to assist you in understanding our business and results of operations together with our present financial condition. Certain sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations include forward-looking statements concerning trends or events potentially affecting our business. These statements contain words such as “anticipates,” “believes,” “expects,” “targets,” “plans,” “projects,” “could,” “may,” “should,” “would” or similar words indicating that future outcomes are uncertain. In accordance with “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ materially from those set forth in the forward-looking statements. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. For additional risk factors affecting our business, see Item 1A. Risk Factors as filed with our Annual Report on Form 10-K for the year ended December 31, 2011 as filed with the SEC on February 22, 2012.

Overview of Our Business

We are a Fort Worth, Texas-based independent natural gas, natural gas liquids (“NGLs”) and oil company primarily engaged in the exploration, development and acquisition of natural gas and oil properties in the Appalachian and Southwestern regions of the United States. We operate in one segment and have a single company-wide management team that administers all properties as a whole rather than by discrete operating segments. Unless otherwise indicated, the information included herein relates to our continuing operations.

Our objective is to build stockholder value through consistent growth in reserves and production on a cost-efficient basis. Our strategy to achieve our objective is to increase reserves and production through internally generated drilling projects occasionally coupled with complementary acquisitions. Our revenues, profitability and future growth depend substantially on prevailing prices for natural gas, NGLs and crude oil and on our ability to economically find, develop, acquire and produce natural gas, NGLs and oil reserves. We use the successful efforts method of accounting for our natural gas, NGLs and oil activities. Our corporate headquarters is located at 100 Throckmorton Street, Fort Worth, Texas.

Market Conditions

Prices for our products significantly impact our revenue, net income and cash flow. Natural gas, NGLs and oil are commodities and prices for commodities are inherently volatile. The following table lists average NYMEX prices for natural gas and oil for three months and six months ended June 30, 2012 and 2011.


	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Average NYMEX prices ^(a)
Natural gas (per mcf)	$	2.26	$	4.36	$	2.50	$	4.25
Oil (per bbl)	$	92.27	$	102.33	$	97.63	$	98.77

^(a)	Based on weighted average of bid week prompt month prices.

Consolidated Results of Operations

Overview of 2012 Results

During second quarter 2012, we achieved the following financial and operating results:

•

increased revenue from the sale of natural gas, NGL and oil by 5% from the same period of 2011;

•

achieved 51% production growth (excluding our Barnett Shale properties which were sold in April 2011);

•

continued expansion of our activities in the Marcellus Shale by growing production, proving up acreage and acquiring additional unproved acreage;

•

reduced direct operating expenses per mcfe 38%;

•

reduced our depletion, depreciation and amortization (“DD&A”) rate 8%;

•

entered into additional derivative contracts for 2012, 2013 and 2014; and

•

realized $127.0 million of cash flow from operating activities.

Total revenues increased $107.1 million or 32% in second quarter 2012 over the same period of 2011. This increase was due to an increase in mark-to-market gain from derivatives and higher production partially offset by lower realized prices. Our second quarter 2012 production growth was due to the continued success of our drilling program, particularly in the Marcellus Shale.

During the first six months ending June 30, 2012, we achieved the following financial and operating results:

•

increased revenue from the sale of natural gas, NGL and oil by 15% from the same period of 2011;

•

achieved 51% production growth (excluding our Barnett Shale properties which were sold in April 2011);

•

reduced direct operating expenses per mcfe 35%;

•

reduced our DD&A rate 9%;

•

maintained a strong balance sheet by issuing $600.0 million of new 10-year subordinated notes;

•

entered into additional derivative contracts for 2012, 2013 and 2014; and

•

realized $282.9 million of cash flow from operating activities.

Total revenues increased $141.4 million or 26% in the first six months 2012 over the same period of 2011. This increase was due to an increase in the mark-to-market gain from derivatives and higher production partially offset by lower realized prices. Our first six months 2012 production growth is due to our successful drilling program, particularly in the Marcellus Shale.

We believe natural gas, NGLs and oil prices will remain volatile and will be affected by, among other things, weather, the U.S. and worldwide economy, new technology and the level of oil and gas production in North America and worldwide. Although we have entered into derivative contracts covering a portion of our production volumes for 2012, 2013 and 2014, a sustained lower price environment would result in lower prices for unprotected volumes and reduce the prices that we can enter into derivative contracts for additional volumes in the future. As a result of the decline in natural gas prices, we continue to focus our capital budget expenditures on oil and liquids-rich-gas drilling activities.

Natural Gas, NGLs and Oil Sales, Production and Realized Price Calculations

Our revenues vary primarily as a result of changes in realized commodity prices, production volumes and the value of certain derivative contracts. We generally sell natural gas, NGLs and oil under two types of agreements, which are common in our industry. Revenue from the sale of natural gas, NGLs and oil sales include netback arrangements where we sell natural gas and oil at the wellhead and collect a price, net of transportation incurred by the purchaser. We record revenue at the price we receive from the purchaser. Revenues are also realized from sales arrangements where we sell natural gas or oil at a specific delivery point and receive proceeds from the purchaser with no transportation deduction. Third party transportation costs we incur to get our commodity to the delivery point are reported in transportation, gathering and compression expense. Hedges included in natural gas, NGLs and oil sales reflect settlements on those derivatives that qualify for hedge accounting.

Cash settlements and changes in the market value of derivative contracts that are not accounted for as hedges are included in derivative fair value income in the statement of operations. For more information on revenues from derivative contracts that are not accounted for as hedges, see Derivative fair value income discussion below.

In second quarter 2012, natural gas, NGLs and oil sales increased 5% from the same period 2011 with a 51% increase in production partially offset by a 31% decrease in realized prices. In the first six months 2012, natural gas, NGLs and oil sales increased 15% from the same period of 2011 with a 51% increase in production partially offset by a 25% decrease in realized prices. The following table illustrates the primary components of natural gas, NGLs and oil sales for the three months and the six months ended June 30, 2012 and 2011 (in thousands):


	Three Months Ended June 30,											Six Months Ended June 30,
	2012			2011		Change			%			2012			2011		Change			%

Natural gas, NGLs and oil sales

Gas wellhead	$	111,413		$	150,188	$	(38,775	)		(26	%)	$	239,481		$	280,983	$	(41,502	)		(15	%)
Gas hedges realized		78,896			24,285		54,611			225	%		136,525			53,901		82,624			153	%

Total gas revenue	$	190,309		$	174,473	$	15,836			9	%	$	376,006		$	334,884	$	41,122			12	%


Total NGLs revenue	$	56,280		$	64,376	$	(8,096	)		(13	%)	$	132,778		$	119,421	$	13,357			11	%


Oil wellhead	$	52,075		$	46,504	$	5,571			12	%	$	107,497		$	83,011	$	24,486			29	%
Oil hedges realized		(315	)		—		(315	)		100	%		(315	)		—		(315	)		100	%

Total oil revenue	$	51,760		$	46,504	$	5,256			11	%	$	107,182		$	83,011	$	24,171			29	%


Combined wellhead	$	219,768		$	261,068	$	(41,300	)		(16	%)	$	479,756		$	483,415	$	(3,659	)		(1	%)
Combined hedges ^(a)		78,581			24,285		54,296			224	%		136,210			53,901		82,309			153	%

Total natural gas, NGLs and oil sales	$	298,349		$	285,353	$	12,996			5	%	$	615,966		$	537,316	$	78,650			15	%

^(a)	Cash settlements related to derivatives that qualify for hedge accounting.

Our production continues to grow through drilling success as we place new wells on production offset by the natural decline of our natural gas and oil wells and asset sales. For second quarter 2012, our production volumes increased 67% in our Appalachian region and increased 5% in our Southwestern region when compared to the same period of 2011. For the six months ended June 30, 2012, our production volumes increased 68% in our Appalachian region and increased 8% in our Southwestern region when compared to the same period of 2011. Our production for the three months and the six months ended June 30, 2012 and 2011 is set forth in the following table:


	Three Months Ended June 30,									Six Months Ended June 30,
	2012		2011		Change		%			2012		2011		Change		%

Production ^(a)
Natural gas (mcf)		52,293,227		32,811,471		19,481,756		59	%		98,926,434		62,616,994		36,309,440		58	%
NGLs (bbls)		1,570,593		1,236,502		334,091		27	%		3,131,419		2,368,067		763,352		32	%
Crude oil (bbls)		623,026		502,962		120,064		24	%		1,231,103		939,094		292,009		31	%
Total (mcfe) ^(b)		65,454,941		43,248,255		22,206,686		51	%		125,101,566		82,459,960		42,641,606		52	%

Average daily production ^(a)
Natural gas (mcf)		574,651		360,566		214,085		59	%		543,552		345,950		197,602		57	%
NGLs (bbls)		17,259		13,588		3,671		27	%		17,206		13,083		4,123		32	%
Crude oil (bbls)		6,846		5,527		1,319		24	%		6,764		5,188		1,576		30	%
Total (mcfe) ^(b)		719,285		475,256		244,029		51	%		687,371		455,580		231,791		51	%

^(a)	Represents volumes sold regardless of when produced.

^(b)	Oil and NGLs are converted to mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural gas, which is not necessarily indicative of the relationship of oil and natural gas prices.

Our average realized price (including all derivative settlements and third-party transportation costs) received during second quarter 2012 was $4.06 per mcfe compared to $5.91 per mcfe in the same period of 2011. Our average realized price (including all derivative settlements and third-party transportation costs) received was $4.27 per mcfe in the six months ended June 30, 2012 compared to $5.84 per mcfe in the same period of the prior year. Because we record transportation costs on two separate bases, as required by GAAP, we believe computed final realized prices should include the total impact of transportation, gathering and compression expense. Our average realized price (including all derivative settlements and third-party transportation costs) calculation also includes all cash settlements for derivatives, whether or not they qualify for hedge accounting. Average sales prices (wellhead) do not include derivative settlements or third party transportation costs which are reported in transportation, gathering and compression expense on the accompanying statements of operations. Average sales prices (wellhead) do include transportation costs where we receive net proceeds. Average realized price calculations for the three months and the six months ended June 30, 2012 and 2011 are shown below:


	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Average Prices
Average sales prices (wellhead):
Natural gas (per mcf)	$	2.13	$	4.58	$	2.42	$	4.49
NGLs (per bbl)		35.83		52.06		42.40		50.43
Crude oil (per bbl)		83.58		92.46		87.32		88.39
Total (per mcfe) ^(a)		3.36		6.04		3.83		5.86

Average realized prices (including derivative settlements that qualify for hedge accounting):
Natural gas (per mcf)	$	3.64	$	5.32	$	3.80	$	5.35
NGLs (per bbl)		35.83		52.06		42.40		50.43
Crude oil (per bbl)		83.08		92.46		87.06		88.39
Total (per mcfe) ^(a)		4.56		6.60		4.92		6.52

Average realized prices (including all derivative settlement):
Natural gas (per mcf)	$	3.66	$	5.47	$	3.83	$	5.44
NGLs (per bbl)		42.30		52.06		44.24		50.43
Crude oil (per bbl)		84.31		80.34		83.93		79.86
Total (per mcfe) ^(a)		4.74		6.57		4.96		6.49

Average realized prices (including all derivative settlements and third party transportation costs paid by Range):
Natural gas (per mcf)	$	2.86	$	4.65	$	3.01	$	4.62
NGLs (per bbl)		40.66		50.62		42.68		49.44
Crude oil (per bbl)		84.31		80.34		83.93		79.86
Total (per mcfe) ^(a)		4.06		5.91		4.27		5.84

^(a)	Oil and NGLs are converted to mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural gas, which is not indicative of the relationship of oil and natural gas prices.

Derivative fair value income was $148.6 million in second quarter 2012 compared to $53.0 million in the same period of 2011. Derivative fair value income was $87.7 million in the six months ended June 30, 2012 compared to $12.2 million in the same period of 2011. Some of our derivatives do not qualify for hedge accounting and are accounted for using the mark-to-market accounting method whereby all realized and unrealized gains and losses related to these contracts are included in derivative fair value income in the accompanying consolidated statements of operations. Mark-to-market accounting treatment results in volatility of our revenues as unrealized gains and losses from derivatives are included in total revenues. As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our derivatives. Gains on our derivatives indicate lower wellhead revenues in the future while losses indicate higher future wellhead revenues. The increase in the mark-to-market gain in the second quarter and the six months ended June 30, 2012 is primarily due the change in the fair value of our NGL derivatives. Hedge ineffectiveness, also included in derivative fair value income, is associated with contracts that qualify for hedge accounting. The ineffective portion is calculated as the difference between the change in the fair value of the derivative and the estimated change in future cash flows from the item being hedged.

The following table presents information about the components of derivative fair value income for the three months and the six months ended June 30, 2012 and 2011 (in thousands):


	Three Months Ended June 30,					Six Months Ended June 30,
	2012		2011			2012			2011

Change in fair value of derivatives that do not qualify for hedge accounting^(a)	$	135,777	$	48,139		$	83,721		$	8,103
Realized gain (loss) on settlements – natural gas ^{(b) (c)}		—		3,484			—			3,090
Realized gain (loss) on settlements – oil ^{(b) (c)}		768		(6,094	)		(3,854	)		(8,012	)
Realized gain (loss) on settlements – NGLs ^{(b) (c)}		10,152		—			5,760			—
Hedge ineffectiveness – realized ^(c)		1,278		1,576			2,463			2,522
– unrealized ^(a)		594		5,934			(354	)		6,502

Derivative fair value income	$	148,569	$	53,039		$	87,736		$	12,205

^(a)	These amounts are unrealized and are not included in average realized price calculations.

^(b)	These amounts represent realized gains and losses on settled derivatives that do not qualify for hedge accounting.

^(c)	These settlements are included in average realized price calculations (including all derivative settlements and third party transportation costs paid by Range).

Loss on the sale of assets was $3.2 million in second quarter 2012 compared to a loss of $1.6 million in the same period of 2012. In the second quarter 2012, we recorded a $2.5 million loss on the sale of a Marcellus exploration well where we received proceeds of $2.5 million. In the second quarter 2011, we recorded a loss of $1.7 million related to the sale of certain derivatives included with the sale of our Barnett Shale properties. Loss on the sale of assets was $13.7 million in the first six months 2012 compared to $1.5 million in the same period of 2011. In the first six months 2012, we also sold a seventy five percent interest in an East Texas prospect which included a suspended exploratory well and unproved properties for proceeds of $8.6 million resulting in a pre-tax loss of $10.9 million.

Other revenue in second quarter 2012 was a loss of $1.3 million compared to a loss of $1.5 million in the same period of 2011. The second quarter 2012 includes income from equity method investments of $502,000 offset by a loss of $1.1 million related to transportation and gathering revenue. The second quarter 2011 includes loss from equity method investments of $1.0 million and a loss of $1.0 million related to transportation and gathering revenue. Other revenue for the six months ended June 30, 2012 was a loss of $716,000 compared to a loss of $85,000 in the same period of 2011. The six months ended June 30, 2012 includes income from equity method investments of $818,000 offset by a loss of $1.9 million related to transportation and gathering revenue. The six months ended June 30, 2011 includes various lawsuit proceeds and refunds partially offset by a loss from equity method investments of $759,000.

We believe some of our expense fluctuations are best analyzed on a unit-of-production, or per mcfe, basis. The following presents information about certain of our expenses on a per mcfe basis for the three months and the six months ended June 30, 2012 and 2011. For the six months ended June 30, 2012, production and ad valorem tax expense includes a Pennsylvania impact fee of $0.30 per mcfe of which $0.20 per mcfe is a retroactive adjustment for wells drilled prior to 2012.


	Three Months Ended June 30,										Six Months Ended June 30,
	2012		2011		Change			% Change			2012		2011		Change			% Change

Direct operating expense	$	0.41	$	0.66	$	(0.25	)		(38	%)	$	0.45	$	0.69	$	(0.24	)		(35	%)
Production and ad valorem tax expense		0.18		0.17		0.01			6	%		0.39		0.17		0.22			129	%
General and administrative expense		0.67		0.90		(0.23	)		(26	%)		0.66		0.89		(0.23	)		(26	%)
Interest expense		0.66		0.73		(0.07	)		(10	%)		0.64		0.68		(0.04	)		(6	%)
Depletion, depreciation and amortization expense		1.66		1.81		(0.15	)		(8	%)		1.67		1.83		(0.16	)		(9	%)

Direct operating expense was $27.0 million in second quarter 2012 compared to $28.5 million in the same period of 2011. We experience increases in operating expenses as we add new wells and manage existing properties. Direct operating expenses include normally recurring expenses to operate and produce our wells, non-recurring well workovers and repair-related expenses. On an absolute basis, our spending for direct operating expenses for second quarter 2012 decreased 5% with an increase in the number of producing wells more than offset by lower water hauling and disposal costs and equipment rental. We incurred $632,000 of workover costs in second quarter 2012 compared to $596,000 of workover costs in the same period of 2011.

On a per mcfe basis, operating expense in second quarter 2012 declined 38% to $0.41 from the same period of 2011, with the decrease consisting of lower water hauling and disposal costs, equipment rental and well services. We expect to experience lower costs per mcfe as we increase production from our dry gas Marcellus Shale wells due to their lower operating cost relative to our other operating areas somewhat offset by higher operating costs on our liquids-rich wells.

Direct operating expense was $56.1 million in the first six months ended June 30, 2012 compared to $57.2 million in the same period of 2011. On an absolute basis, our spending for direct operating expenses decreased 2% with an increase in the number of producing wells and higher workover costs offset by lower water hauling and disposal costs, equipment rental and well service costs. We incurred $2.2 million of workover costs in 2012 compared to $986,000 in the same period of 2011.

On a per mcfe basis, operating expense in the first six months ended June 30, 2012 decreased 35% to $0.45 from the same period of 2011, with the decrease consisting of lower water hauling and disposal costs, lower equipment rental and well services somewhat offset by higher workover costs. Stock-based compensation expense represents the amortization of restricted stock grants and SARs as part of the compensation of field employees. The following table summarizes direct operating expenses per mcfe for the three months and the six months ended June 30, 2012 and 2011:


	Three Months Ended June 30,										Six Months Ended June 30,
	2012		2011		Change			% Change			2012		2011		Change			% Change

Lease operating expense	$	0.39	$	0.64	$	(0.25	)		(39	%)	$	0.42	$	0.67	$	(0.25	)		(37	%)
Workovers		0.01		0.01		—			—	%		0.02		0.01		0.01			100	%
Stock-based compensation (non-cash)		0.01		0.01		—			—	%		0.01		0.01		—			—	%

Total direct operating expenses	$	0.41	$	0.66	$	(0.25	)		(38	%)	$	0.45	$	0.69	$	(0.24	)		(35	%)

Production and ad valorem taxes are paid based on market prices, not hedged prices. This expense category also includes the new Pennsylvania impact fee. Production and ad valorem taxes (excluding the impact fee) were $4.7 million in second quarter 2012 compared to $7.6 million in the same period of 2011. On a per mcfe basis, production and ad valorem taxes (excluding the impact fee) decreased to $0.07 in second quarter 2012 compared to $0.17 in the same period of 2011 due to lower oil and gas prices and an increase in volumes not subject to production taxes. In February 2012, the commonwealth of Pennsylvania enacted an “impact fee” on unconventional natural gas and oil production which includes the Marcellus Shale. Included in second quarter 2012 is a $6.4 million impact fee ($0.10 per mcfe) accrual.

Production and ad valorem taxes (excluding the impact fee) were $11.1 million ($0.09 per mcfe) in the first six months 2012 compared to $14.4 million ($0.17 per mcfe) in the same period of 2011 due to lower oil and gas prices and an increase in volumes not subject to production taxes. The six months ended June 30, 2012 also includes a $24.7 million ($0.20 per mcfe) retroactive impact fee which covers all wells drilled prior to 2012 which is to be paid in September 2012. Also included in first six months 2012 is a $12.6 million impact fee ($0.10 per mcfe) for wells drilled prior to 2012 and wells drilled in the first six months 2012 to be paid April 2013.

General and administrative expense was $44.0 million in second quarter 2012 compared to $39.1 million for the same period of 2011. The 2012 increase of $4.9 million when compared to 2011 is due to higher salaries and benefits ($4.0 million), an increase in stock-based compensation of $1.1 million and higher advertising costs, partially offset by a decrease in legal expenses. We continue to incur higher wages which we consider necessary to remain competitive in the industry. Our number of employees increased 15% at June 30, 2012 when compared to June 30, 2011. General and administrative expense for the first six months ended June 30, 2012 increased $9.7 million or 13% from the same period of the prior year primarily due to higher salaries and benefits ($7.0 million), an increase in stock-based compensation of $1.7 million and higher advertising costs, partially offset by a decrease in legal expenses which also includes an insurance recovery. Our personnel costs continue to increase as we invest in our technical teams and other staffing to support our expansion into our various shale plays. Stock-based compensation expense represents the amortization of restricted stock grants and stock appreciation rights granted to our employees and directors as part of compensation. The following table summarizes general and administrative expenses per mcfe for the first three months and six months ended June 30, 2012 and 2011:


	Three Months Ended June 30,										Six Months Ended June 30,
	2012		2011		Change			% Change			2012		2011		Change			% Change

General and administrative	$	0.48	$	0.63	$	(0.15	)		(24	%)	$	0.48	$	0.66	$	(0.18	)		(27	%)
Stock-based compensation (non-cash)		0.19		0.27		(0.08	)		(30	%)		0.17		0.23		(0.06	)		(26	%)

Total general and administrative expenses	$	0.67	$	0.90	$	(0.23	)		(26	%)	$	0.65	$	0.89	$	(0.24	)		(27	%)

Interest expense was $42.9 million for second quarter 2012 and $80.1 million in the first six months ended June 30, 2012 compared to $31.4 million for second quarter 2011 and $56.2 million in the first six months ended June 30, 2011. The following table presents information about interest expense for the three months and the six months ended June 30, 2012 and 2011 (in thousands):


	Three Months Ended June 30,					Six Months Ended June 30,
	2012		2011			2012		2011

Bank credit facility	$	2,140	$	2,130		$	4,660	$	5,411
Subordinated notes		38,344		31,299			71,022		62,034
Other		2,404		1,669			4,411		3,508
Allocated to discontinued operations		—		(3,715	)		—		(14,791	)

Total interest expense	$	42,888	$	31,383		$	80,093	$	56,162

The increase in interest expense for second quarter 2012 from the same period of 2011 was primarily due to an increase in outstanding debt balances. In March 2012, we issued $600.0 million of 5.0% senior subordinated notes due 2022. We used the proceeds to repay $350.0 million of our outstanding credit facility balance and for general corporate purposes. In May 2011, we issued $500.0 million of 5.75% senior subordinated notes due 2021. We used the proceeds for general corporate purposes and to purchase or redeem $150.0 million of our 6.375% senior subordinated notes due 2015 and $250.0 million of our 7.5% senior subordinated notes due 2016. The 2012 and 2011 note issuances were undertaken to better match the maturities of our debt with the life of our properties and to give us greater liquidity for the near term. Average debt outstanding on the bank credit facility for the second quarter 2012 was $91.3 million compared to $171.5 million for the same period of 2011 and the weighted average interest rate on the bank credit facility was 2.7% in 2012 compared to 2.0% in 2011.

The increase in interest expenses for the first six months ended June 30, 2012 from the same period of 2011 was due to an increase in outstanding debt balances and higher interest rates. Average debt outstanding on the bank credit facility was $172.2 million compared to $296.3 million for 2011 and the weighted average interest rate on the bank credit facility was 2.3% in the first six months ended June 30, 2012 compared to 2.2% in the same period of 2011.

Depletion, depreciation and amortization (“DD&A”) was $108.8 million in second quarter 2012 compared to $78.3 million in the same period of 2011. The increase in 2012 when compared to 2011 is due to a 7% decrease in depletion rates more than offset by a 51% increase in production. Depletion expense, the largest component of DD&A, was $1.58 per mcfe in second quarter 2012 compared to $1.70 per mcfe in the same period of 2011.

DD&A was $209.0 million in the first six months ended June 30, 2012 compared to $150.5 million in the same period of 2011. Depletion expense was $1.59 per mcfe in the first six months ended June 30, 2012 compared to $1.71 per mcfe in the same period of 2011. We have historically adjusted our depletion rates in the fourth quarter of each year based on the year-end reserve report and other times during the year when circumstances indicate there has been a significant change in reserves or costs. The following table summarizes DD&A expense per mcfe for the three months and the six months ended June 30, 2012 and 2011:


	Three Months Ended June 30,										Six Months Ended June 30,
	2012		2011		Change			% Change			2012		2011		Change			% Change

Depletion and amortization	$	1.58	$	1.70	$	(0.12	)		(7	%)	$	1.59	$	1.71	$	(0.12	)		(7	%)
Depreciation		0.05		0.08		(0.03	)		(38	%)		0.05		0.09		(0.04	)		(44	%)
Accretion and other		0.03		0.03		—			—	%		0.03		0.03		—			—	%

Total DD&A expense	$	1.66	$	1.81	$	(0.15	)		(8	%)	$	1.67	$	1.83	$	(0.16	)		(9	%)

Other Operating Expenses

Our total operating expenses also include other expenses that generally do not trend with production. These expenses include stock-based compensation, transportation, gathering and compression, exploration expense, abandonment and impairment of unproved properties and deferred compensation plan expenses. In second quarter 2012, stock-based compensation was a component of direct operating expense ($692,000), exploration expense ($994,000) and general and administrative expense ($12.5 million) for a total of $14.6 million. In second quarter 2011, stock-based compensation was a component of direct operating expense ($643,000), exploration expense ($937,000) and general and administrative expense ($11.5 million) for a total of $13.4 million. In the first six months ended June 30, 2012, stock-based compensation was allocated to direct operating expense ($1.0 million), exploration expense ($1.9 million) and general and administrative expense ($20.7 million) for a total of $24.5 million. In the first six months ended June 30, 2011, stock-based compensation was allocated to direct operating expense ($953,000), exploration expense ($2.3 million) and general and administrative expense ($19.0 million) for a total of $22.9 million. Stock-based compensation includes the amortization of restricted stock grants and SARs grants.

Transportation, gathering and compression expense was $44.7 million in second quarter 2012 compared to $28.7 million in the same period of 2011. Transportation, gathering and compression expenses was $85.6 million in the first six months ended June 30, 2012 compared to $53.7 million in the same period of 2011. These third party costs are higher than 2011 due to our production growth in the Marcellus Shale where we have third party gathering and compression agreements. We have included these costs in the calculation of average realized prices (including all derivative settlements and third party transportation expenses paid by Range).

Exploration expense was $15.5 million in second quarter 2012 compared to $11.6 million in the same period of 2011. Exploration expense was higher in second quarter 2012 when compared to 2011 due to higher seismic costs, partially offset by lower delay rentals. The six months ended June 30, 2012 also includes higher seismic costs compared to the same period of 2011, which was more than offset by lower delay rentals when compared to the same period of 2011. The following table details our exploration related expenses for the three months and the six months ended June 30, 2012 and 2011 (in thousands):


	Three Months Ended June 30,											Six Months Ended June 30,
	2012		2011			Change			% Change			2012		2011		Change			% Change

Seismic	$	9,096	$	4,365		$	4,731			108	%	$	19,768	$	17,537	$	2,231			13	%
Delay rentals and other		1,886		3,143			(1,257	)		(40	%)		7,589		11,793		(4,204	)		(36	%)
Personnel expense		3,434		3,150			284			9	%		6,938		7,176		(238	)		(3	%)
Stock-based compensation expense		993		937			56			6	%		1,921		2,266		(345	)		(15	%)
Dry hole expense		108		(3	)		111			3700	%		817		7		810			11,571	%

Total exploration expense	$	15,517	$	11,592		$	3,925			34	%	$	37,033	$	38,779	$	(1,746	)		(5	%)

Abandonment and impairment of unproved properties was $43.6 million in second quarter 2012 compared to $18.9 million in the same period of 2011. Abandonment and impairment of unproved properties was $63.9 million in the first six months ended June 30, 2012 compared to $35.4 million in the same period of 2011. We assess individually significant unproved properties for impairment on a quarterly basis and recognize a loss where circumstances indicate impairment in value. In determining whether a significant unproved property is impaired we consider numerous factors including, but not limited to, current exploration plans, favorable or unfavorable activity on the property being evaluated and/or adjacent properties, our geologists’ evaluation of the property and the remaining months in the lease term for the property. Impairment of individually insignificant unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success. As we continue to review our acreage positions and high grade our drilling inventory based on the current price environment, additional leasehold impairments and abandonments will likely be recorded. The increase from 2011 to 2012 is primarily related to our Marcellus Shale operations and is due, in part, to lower natural gas prices and plans to move towards areas with higher expectation of wet gas. Also, due to a transaction in second quarter 2012, we impaired individually significant unproved properties in Pennsylvania for $23.1 million because we will not drill in these areas.

Deferred compensation plan expense was $9.3 million in second quarter 2012 compared to a income of $5.8 million in the same period of 2011. Our stock price increased from $58.14 at March 31, 2012 to $61.87 at June 30, 2012. In the same quarter of the prior year, our stock price decreased from $58.46 at March 31, 2011 to $55.50 at June 30, 2011. Deferred compensation plan expense was $1.5 million at June 30, 2012 compared to $24.9 million in the same period of 2011. During the first six months ended June 30, 2012, our stock price was approximately the same. In the first six months ended June 30, 2011, our stock price increased from $44.98 at December 31, 2010 to $55.50 at June 30, 2011. This non-cash item relates to the increase or decrease in value of the liability associated with our common stock that is vested and held in our deferred compensation plan. The deferred compensation liability is adjusted to fair value by a charge or a credit to deferred compensation plan expense.

Loss on extinguishment of debt for the second quarter and the six months ended June 30, 2011 was $18.6 million. In May and June 2011, we purchased or redeemed our 6.375% senior subordinated notes due 2015 at a price equal to 102.31% and we purchased or redeemed our 7.5% senior subordinated notes due 2016 at a price equal to 103.95%. We recorded a loss on extinguishment of debt of $18.6 million which includes a call premium and other consideration of $13.3 million and expensing of related deferred financing costs on the repurchased debt.

Income tax expense was $39.0 million in second quarter 2012 compared to $32.7 million in second quarter 2011. The 2012 increase in income taxes reflects a 21% increase in income from continuing operations when compared to the same period of 2011. For the second quarter, the effective tax rate was 41.2% in 2012 compared to 41.7% in 2011. Income tax expense was $11.2 million in the first six months June 30, 2012 compared to $12.8 million in the same period of 2011. For the six months ended June 30, 2012, the decrease in income taxes reflects an effective tax rate of 44.6% in 2012 compared to 50.9% in the six months ended June 30, 2011. The 2012 and 2011 effective tax rates were different than the statutory tax rate due to state income taxes and changes in our valuation allowances related to our deferred tax asset for future deferred compensation plan distributions to senior executives to the extent their estimated future compensation (including these distributions) would exceed the $1.0 million deductible limit provided under section 162 (m) of the Internal Revenue Code. We expect our effective tax rate to be approximately 40% for the remainder of 2012.

Discontinued operations include the operating results and impairment losses related to our Barnett Shale properties. Substantially all of these properties were sold in April 2011 for proceeds of $889.3 million including certain derivatives assumed by the buyer and we recorded a gain of $4.8 million on the sale. See also Note 4 to the accompanying financial statements. Interest expense is allocated to discontinued operations based on the ratio of net assets of discontinued operations to our consolidated net assets plus long-term debt.

Management’s Discussion and Analysis of Financial Condition, Capital Resources and Liquidity

Our main sources of liquidity and capital resources are internally generated cash flow from operations, a bank credit facility with uncommitted and committed availability, access to the debt and equity capital markets and asset sales. We continue to take steps to ensure adequate capital resources and liquidity to fund our capital expenditure program. In the first six months ended June 30, 2012, we entered into additional commodity derivative contracts for 2012, 2013 and 2014 to protect future cash flows. In March 2012, we issued $600.0 million of new 5.0% ten-year senior subordinated notes. On April 9, 2012, we increased our committed facility amount under our bank credit facility from $1.5 billion to $1.75 billion.

During first six months 2012, our net cash provided from continuing operations of $282.9 million, proceeds from the sale of assets of $15.6 million, proceeds from the issuance of our 5.00% senior subordinated notes and borrowings under our bank credit facility were used to fund $931.0 million of capital expenditures (including acreage acquisitions). At June 30, 2012, we had $158,000 in cash and total assets of $6.5 billion.

Long-term debt at June 30, 2012 totaled $2.6 billion, including $235.0 million outstanding on our bank credit facility and $2.4 billion of senior subordinated notes. Our available committed borrowing capacity at June 30, 2012 was $1.5 billion. Cash is required to fund capital expenditures necessary to offset inherent declines in production and reserves that are typical in the oil and natural gas industry. Future success in growing reserves and production will be highly dependent on capital resources available and the success of finding or acquiring additional reserves. We currently believe that net cash generated from operating activities, unused committed borrowing capacity under the bank credit facility and proceeds from asset sales combined with our natural gas, NGLs and oil derivatives currently in place will be adequate to satisfy near-term financial obligations and liquidity needs. To the extent our capital requirements exceed our internally generated cash flow and proceeds from asset sales, debt or equity may be issued to fund these requirements. Long-term cash flows are subject to a number of variables including the level of production and prices as well as various economic conditions that have historically affected the oil and natural gas business. A material drop in natural gas, NGLs and oil prices or a reduction in production and reserves would reduce our ability to fund capital expenditures, meet financial obligations and remain profitable. We operate in an environment with numerous financial and operating risks, including, but not limited to, the inherent risks of the search for, development and production of natural gas, NGLs and oil, the ability to buy properties and sell production at prices which provide an attractive return and the highly competitive nature of the industry. Our ability to expand our reserve base is, in part, dependent on obtaining sufficient capital through internal cash flow, bank borrowings, asset sales or the issuance of debt or equity securities. There can be no assurance that internal cash flow and other capital sources will provide sufficient funds to maintain capital expenditures that we believe are necessary to offset inherent declines in production and proven reserves.

Our opinions concerning liquidity and our ability to avail ourselves in the future of the financing options mentioned in the above forward-looking statements are based on currently available information. If this information proves to be inaccurate, future availability of financing may be adversely affected. Factors that affect the availability of financing include our performance, the state of the worldwide debt and equity markets, investor perceptions and expectations of past and future performance, the global financial climate and, in particular, with respect to borrowings, the level of our working capital or outstanding debt and credit ratings by rating agencies.

Credit Arrangements

As of June 30, 2012, we maintained a $2.0 billion revolving credit facility, which we refer to as our bank credit facility. The bank credit facility is secured by substantially all of our assets and has a maturity date of February 18, 2016. Availability under the bank credit facility is subject to a borrowing base set by the lenders semi-annually with an option to set more often in certain circumstances. The borrowing base is dependent on a number of factors but primarily on the lenders’ assessment of future cash flows. Redeterminations of the borrowing base require approval of two thirds of the lenders; increases to the borrowing base require 97% lender approval. On April 9, 2012, the facility amount on our bank credit facility was increased from $1.5 billion to $1.75 billion and we added three additional banks. Our current bank group is comprised of twenty-eight financial institutions. The borrowing base remained unchanged at $2.0 billion.

Our bank debt and our subordinated notes impose limitations on the payment of dividends and other restricted payments (as defined under the debt agreements for our bank debt and our subordinated notes). The debt agreements also contain customary covenants relating to debt incurrence, working capital, dividends and financial ratios. We were in compliance with all covenants at June 30, 2012.

Capital Requirements

Our primary capital requirements are for exploration, development and acquisition of natural gas and oil properties, repayment of principal and interest on outstanding debt and payment of dividends. During the first six months of 2012, $761.2 million of capital was expended on drilling projects. Also in the first six months of 2012, $151.6 million was expended on acquisitions of unproved acreage, primarily in the Marcellus Shale. Our 2012 capital program, excluding acquisitions, is expected to be funded by net cash flow from operations, a debt offering, proceeds from asset sales and borrowings under our credit facility. Our capital expenditure budget for 2012 is currently set at $1.6 billion, excluding acquisitions. To the extent capital requirements exceed internally generated cash flow, proceeds from asset sales and our committed capacity under our bank credit facility, then debt or equity may be issued to fund these requirements. We monitor our capital expenditures on an ongoing basis, adjusting the amount up or down and also between our operating regions, depending on commodity prices, cash flow and projected returns. Also, our obligations may change due to acquisitions, divestitures and continued growth. We may issue additional shares of stock, subordinated notes or other debt securities to fund capital expenditures, acquisitions, extend maturities or to repay debt.

The forward-looking statements about our capital budget are based on current expectations, estimates and projections and are not guarantees of future performance. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Some factors that could cause actual results to differ materially include prices of and demand for natural gas and oil, actions of competitors, disruptions or interruptions of our production and unforeseen hazards such as weather conditions, acts of war or terrorists acts and the government or military response, and other operating and economic considerations.

Cash Flow

Cash flows from operations are primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivatives. Our cash flows from operations are also impacted by changes in working capital. We generally maintain low cash and cash equivalent balances because we use available funds to reduce our bank debt. Short-term liquidity needs are satisfied by borrowings under our bank credit facility. Because of this, and since our principal source of operating cash flows (proved reserves to be produced in the following year) cannot be reported as working capital, we often have low or negative working capital. We sell a large portion of our production at the wellhead under floating market contracts. From time to time, we enter into various derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future natural gas, NGLs and oil production. The production we hedge has varied and will continue to vary from year to year depending on, among other things, our expectation of future commodity prices. Any payments due to counterparties under our derivative contracts should ultimately be funded by prices received from the sale of our production. Production receipts, however, often lag payments to the counterparties. Any interim cash needs are funded by borrowings under the bank credit facility. As of June 30, 2012, we have entered into hedging agreements covering 120.5 Bcfe for 2012, 190.9 Bcfe for 2013 and 102.6 Bcfe for 2014.

Net cash provided from continuing operations in first six months 2012 was $282.9 million compared to $288.0 million in the same period of 2011. Cash provided from continuing operations is largely dependent upon commodity prices and production, net of the effects of settlement of our derivative contracts. The decrease in cash provided from operating activities from 2011 to 2012 reflects a 51% increase in production offset by lower realized prices (a decline of 27%) and higher operating costs. As of June 30, 2012, we have hedged approximately 75% of our projected 2012 production (based on the mid-point of our projected 2012 production), with approximately 80% of our projected natural gas production hedged. Net cash provided from continuing operations is also affected by working capital changes or the timing of cash receipts and disbursements. Changes in working capital (as reflected in our consolidated statements of cash flows) for first six months ended June 30, 2012 was a positive $21.4 million compared to $5.4 million for the same period of 2011.

Net cash provided from discontinued operations for the first six months ended June 30, 2011 was $21.6 million. Substantially all of our Barnett Shale properties were sold in April 2011 with a February 1, 2011 effective date.

Net cash used in investing activities from continuing operations in first six months ended June 30, 2012 was $919.7 million compared to $591.5 million in the same period of 2011.

During the first six months of 2012, we:

•

spent $781.6 million on natural gas and oil property additions;

•

spent $147.9 million on acreage primarily in the Marcellus Shale; and

•

received proceeds from asset sales of $15.6 million.

During the first six months of 2011, we:

•

spent $536.8 million on natural gas and oil property additions;

•

spent $73.1 million on acreage primarily in the Marcellus Shale; and

•

received proceeds from asset sales of $23.4 million.

Net cash provided from financing activities in the first six months ended June 30, 2012 was an increase of $636.8 million compared to a decrease of $272.8 million in the same period of 2011. Historically, sources of financing have been primarily bank borrowings and capital raised through equity and debt offerings.

During the first six months of 2012, we:

•

borrowed $697.0 million and repaid $649.0 million under our bank credit facility; ending the quarter with a $235.0 million outstanding balance on our bank debt;

•

issued $600.0 million aggregate principal amounts of 5.00% senior subordinated notes due 2022 with net proceeds of approximately $589.5 million; and

•

spent $12.5 million related to debt issuance costs.

During the first six months of 2011, we:

•

borrowed $490.8 million and repaid $764.8 million under our bank credit facility, ending the period with no outstanding borrowings under our bank credit facility;

•

issued $500.0 million principal amount of 5.75% senior subordinated notes due 2021, at par;

•

purchased or redeemed $150.0 million principal amount of our 6.375% senior subordinated notes due 2015 at a redemption price of 102.31% and purchased or redeemed $250.0 million principal amount of our 7.5% senior subordinated notes due 2016 at a redemption price of 103.9%;

•

spent $21.7 million related to debt issuance costs; and

•

recorded a decrease of $58.3 million in cash overdrafts.

Cash Dividend Payments

The amount of future dividends is subject to declaration by the Board of Directors and primarily depends on earnings, capital expenditures and various other factors. On June 1, 2012, the Board of Directors declared a dividend of four cents per share ($6.5 million) on our common stock, which was paid on June 29, 2012 to stockholders of record at the close of business on June 15, 2012.

Cash Contractual Obligations

Our contractual obligations include long-term debt, operating leases, drilling commitments, derivative obligations, asset retirement obligations and transportation commitments. As of June 30, 2012, we do not have any capital leases. As of June 30, 2012, we do not have any significant off-balance sheet debt or other such unrecorded obligations and we have not guaranteed any debt of any unrelated party. As of June 30, 2012, we had a total of $62.1 million of letters of credit outstanding under our bank credit facility supporting obligations in the table below. The table below provides estimates of the timing of future payments that we are obligated to make based on agreements in place at June 30, 2012.

The following summarizes our contractual financial obligations at June 30, 2012 and their future maturities. In addition to the table below, we have contracted with several pipeline companies through 2028 to deliver natural gas production volumes from Marcellus Shale wells which is contingent on pipeline modifications and therefore, is not included below. We expect to fund these contractual obligations with cash generated from operating activities, borrowings under our bank credit facility, additional debt issuances and proceeds from asset sales (in thousands).


	Payment due by period
	Remaining 2012		2013		2014		2015 and 2016			Thereafter		Total

Bank debt due 2016	$	—	$	—	$	—	$	235,000	^(a)	$	—	$	235,000
7.50% senior subordinated notes due 2017		—		—		—		—			250,000		250,000
7.25% senior subordinated notes due 2018		—		—		—		—			250,000		250,000
8.00% senior subordinated notes due 2019		—		—		—		—			300,000		300,000
6.75% senior subordinated notes due 2020		—		—		—		—			500,000		500,000
5.75% senior subordinated notes due 2021		—		—		—		—			500,000		500,000
5.00% senior subordinated notes due 2022											600,000		600,000
Operating leases		5,861		11,589		11,057		19,232			27,701		75,440
Drilling rig commitments		7,323		14,189		895		—			—		22,407
Transportation commitments		61,449		122,107		120,476		262,344			652,271		1,218,647
Hydraulic fracturing services		43,040		64,560		—		—			—		107,600
Other purchase obligations		1,566		2,637		158		314			1,626		6,301
Derivative obligations ^(b⁾		2,684		1,892		1,112		—			—		5,688
Asset retirement obligation liability ^(c⁾		5,005		10,530		105		788			73,761		90,189

Total contractual obligations ^(d⁾	$	126,928	$	227,504	$	133,803	$	517,678		$	3,155,359	$	4,161,272

⁽^a⁾	Due at termination date of our bank credit facility. Interest paid on our bank credit facility would be approximately $5.1 million each year assuming no change in the interest rate or outstanding balance.

⁽^b⁾

Derivative obligations represent net open derivative contracts valued as of June 30, 2012. While such payments will be funded by higher prices received from the sale of our production, production receipts may be received after our payments to counterparties, which can result in borrowings under our bank credit facility.

^(c⁾	The ultimate settlement amount and timing cannot be precisely determined in advance. See Note 10 to our consolidated financial statements.

^(d⁾	This table excludes the liability for the deferred compensation plans since these obligations will be funded with existing plan assets.

Hedging – Oil and Gas Prices

We use commodity-based derivative contracts to manage our exposure to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. We do not utilize complex derivatives, as we typically utilize commodity swap, collar and call option contracts to (1) reduce the effect of price volatility on the commodities we produce and sell and (2) support our annual capital budget and expenditure plans. In 2011, we also entered into “sold” NGL derivative swap contracts for the natural gasoline component of natural gas liquids and in 2012 we entered into “purchased” derivative swaps for natural gasoline. In addition, in the second quarter of 2012, we entered into NGL derivative swap contracts for propane. While there is a risk that the financial benefit of rising natural gas, NGLs and oil prices may not be captured, we believe the benefits of stable and predictable cash flow are more important. Among these benefits are a more efficient utilization of existing personnel and planning for future staff additions, the flexibility to enter into long-term projects requiring substantial committed capital, smoother and more efficient execution of our ongoing development drilling and production enhancement programs, more consistent returns on invested capital, and better access to bank and other credit markets.

At June 30, 2012, we had open swap contracts covering 106.2 Bcf of natural gas at prices averaging $3.64 per mcf, 3.2 million barrels of oil at prices averaging $95.61 per barrel, 3.6 million net barrels of NGLs (the C5 component of NGLs) at prices averaging $97.85 per barrel and 2.9 million barrels of NGLs (the C3 component of NGLs) at prices averaging $36.73 per barrel. We had collars covering 228.5 Bcf of natural gas at weighted average floor and cap prices of $4.35 to $4.93 per mcf and 2.2 million barrels of oil at weighted average floor and cap prices of $85.46 to $96.64 per barrel. We also have sold call options covering 0.9 million barrels of oil at a weighted average price of $85.00 per barrel and purchased put options for 0.5 million barrels of oil at a weighted average price of $80.00. The fair value, represented by the estimated amount that would be realized or payable on termination, based on a comparison of the contract price and a reference price, generally NYMEX, approximated a pretax gain of $343.3 million at June 30, 2012. The contracts expire monthly through December 2014.

At June 30, 2012, the following commodity derivative contracts were outstanding:


Period	Contract Type	Volume Hedged	Weighted Average Hedge Price

Natural Gas
2012	Collars	279,641 Mmbtu/day		$ 4.76–$ 5.22
2013	Collars	240,000 Mmbtu/day		$ 4.73–$ 5.20
2014	Collars	245,000 Mmbtu/day		$ 3.74–$ 4.50
2012	Swaps	245,000 Mmbtu/day		$ 3.75
2013	Swaps	167,521 Mmbtu/day		$ 3.56

Crude Oil
2012	Collars	2,000 bbls/day	$	70.00–$ 80.00
2013	Collars	3,000 bbls/day	$	90.60–$ 100.00
2014	Collars	2,000 bbls/day	$	85.55–$ 100.00
2012	Call Options	4,700 bbls/day		$ 85.00
2012	Put Option	2,500 bbls/day		$ 80.00
2013	Swaps	6,313 bbls/day		$ 96.49
2014	Swaps	4,000 bbls/day		$ 94.56

NGLs (Natural Gasoline)
2012	Sold Swaps	12,000 bbls/day		$ 96.28
2013	Sold Swaps	8,000 bbls/day		$ 89.64
2012	Purchased Swaps	5,500 bbls/day		$ 82.37
2013	Purchased Swaps	1,500 bbls/day		$ 76.30

NGLs (Propane)
2012	Swaps	6,000 bbls/day		$ 38.67
2013	Swaps	5,000 bbls/day		$ 35.55

The United States Congress adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as Range, that participate in that market. The new regulation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act required the Commodities Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the new legislation. In July 2012 certain definitions were adopted by the SEC and the CFTC and based on those definitions, we believe we will qualify for the end-user exception related to the clearing requirement for swaps but we will be required to adhere to new reporting requirements.

Interest Rates

At June 30, 2012, we had $2.6 billion of debt outstanding. Of this amount, $2.4 billion bears interest at fixed rates averaging 6.4%. Bank debt totaling $235.0 million bears interest at floating rates, which averaged 2.2% at June 30, 2012. The 30-day LIBOR rate on June 30, 2012 was 0.2%. A 1% increase in short-term interest rates on the floating-rate debt outstanding on June 30, 2012 would cost us approximately $2.4 million in additional annual interest expense.

Off-Balance Sheet Arrangements

We do not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance our liquidity or capital resource position, or for any other purpose. However, as is customary in the oil and gas industry, we have various contractual work commitments some of which are described above under cash contractual obligations.

Inflation and Changes in Prices

Our revenues, the value of our assets and our ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by changes in natural gas, NGLs and oil prices and the costs to produce our reserves. Natural gas, NGLs and oil prices are subject to significant fluctuations that are beyond our ability to control or predict. Although certain of our costs and expenses are affected by general inflation, inflation does not normally have a significant effect on our business. We expect costs in 2012 to continue to be a function of supply and demand.

ITEM 3.

QUANTITIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas, NGLs and oil prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market-risk exposure. All of our market-risk sensitive instruments were entered into for purposes other than trading. All accounts are US dollar denominated.

Market Risk

We are exposed to market risks related to the volatility of natural gas, NGLs and oil prices. We employ various strategies, including the use of commodity derivative instruments, to manage the risks related to these price fluctuations. These derivatives instruments apply to a varying portion of our production and provide only partial price protection. These arrangements limit the benefit to us of increases in prices but offer protection in the event of price declines. Further, if our counterparties defaulted, this protection might be limited as we might not receive the benefits of the derivatives. Realized prices are primarily driven by worldwide prices for oil and spot market prices for North American gas production. Natural gas and oil prices have been volatile and unpredictable for many years. Natural gas prices affect us more than oil prices because approximately 79% of our December 31, 2011 proved reserves are natural gas. We are also exposed to market risks related to changes in interest rates. These risks did not change materially from December 31, 2011 to June 30, 2012.

Commodity Price Risk

We use commodity-based derivative contracts to manage exposures to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. We do not utilize complex derivatives such as swaptions, knockouts or extendable swaps. At times, certain of our derivatives are swaps where we receive a fixed price for our production and pay market prices to the counterparty. Our derivatives program also includes collars, which establishes a minimum floor price and a predetermined ceiling price. We have also entered into call option derivative contracts under which we sold call options in exchange for a premium from the counterparty. At the time of settlement of these monthly call options, if the market price exceeds the fixed price of the call option, we will pay the counterparty such excess and if the market settle below the fixed price of the call option, no payment is due from either party. At June 30, 2012, our derivatives program includes swaps (both purchased and sold NGL swaps), collars, call and put options. As of June 30, 2012, we had open swap contracts covering 106.2 Bcf of natural gas at price averaging $3.64 per mcf, 3.2 million barrels of oil at prices averaging $95.61 per barrel, 3.6 million net barrels of NGLs (the C5 component of NGLs) at prices averaging $97.85 per barrel and 2.9 million barrels of NGLs (the C3 component of NGLs) at prices averaging $36.73 per barrel. We had collars covering 228.5 Bcf of natural gas at weighted average floor and cap prices of $4.35 to $4.93 per mcf and 2.2 million barrels of oil at weighted average floor and cap prices of $85.46 to $96.64 per barrel. We also have sold call options covering 0.9 million barrels of oil at a weighted average price of $85.00 per barrel and purchased put options for 0.5 million barrels of oil at a weighted average price of $80.00. These contracts expire monthly through December 2014. The fair value, represented by the estimated amount that would be realized upon immediate liquidation as of June 30, 2012, approximated a net unrealized pre-tax gain of $343.3 million.

At June 30, 2012, the following commodity derivative contracts were outstanding:


Period	Contract Type	Volume Hedged	Weighted Average Hedge Price	Fair Market Value
				(in thousands)
Natural Gas
2012	Collars	279,641 Mmbtu/day	$ 4.76–$ 5.22	$	93,278
2013	Collars	240,000 Mmbtu/day	$ 4.73–$ 5.20	$	104,707
2014	Collars	245,000 Mmbtu/day	$ 3.74–$ 4.50	$	9,081
2012	Swaps	245,000 Mmbtu/day	$ 3.75	$	34,986
2013	Swaps	167,521 Mmbtu/day	$ 3.56	$	(1,080	)

Crude Oil
2012	Collars	2,000 bbls/day	$ 70.00–$ 80.00	$	(2,925	)
2013	Collars	3,000 bbls/day	$ 90.60–$ 100.00	$	5,873
2014	Collars	2,000 bbls/day	$ 85.55–$ 100.00	$	2,306
2012	Call options	4,700 bbls/day	$ 85.00	$	(4,723	)
2012	Put options	2,500 bbls/day	$ 80.00	$	1,071
2013	Swaps	6,313 bbls/day	$ 96.49	$	13,878
2014	Swaps	4,000 bbls/day	$ 94.56	$	9,866

NGLs (Natural Gasoline)
2012	Sold Swaps	12,000 bbls/day	$ 96.28	$	46,454
2013	Sold Swaps	8,000 bbls/day	$ 89.64	$	36,746
2012	Purchased Swaps	5,500 bbls/day	$ 82.37	$	(7,251	)
2013	Purchased Swaps	1,500 bbls/day	$ 76.30	$	311

NGLs (Propane)
2012	Swaps	6,000 bbls/day	$ 38.67	$	3,313
2013	Swaps	5,000 bbls/day	$ 35.55	$	(2,593	)

We expect our NGL production to continue to increase. In our Marcellus Shale operations, propane is a large product component of our NGL production and we also believe NGL prices are somewhat seasonal. Therefore, the percentage of NGL prices to NYMEX WTI (or West Texas Intermediate) will vary due to product components, seasonality and geographic supply and demand.

As of June 30, 2012, the relationship between the price of oil and the price of natural gas is at an unprecedented spread. Normally, natural gas liquids production is a by-product of natural gas production. Due to the current differences in prices, we and other producers may choose to sell natural gas at below cost or otherwise dispose of natural gas to allow for the sale of only natural gas liquids.

Currently, because there is little demand, or facilities to supply the existing demand, for ethane in the Appalachian region, for our Appalachian production volumes, ethane remains in the natural gas stream. We currently have waivers from two transmission pipelines that allow us to leave ethane in the residue natural gas. We believe the limits are sufficient to cover our production through 2014. We have recently announced two ethane agreements where we have contracted to either sell or transport ethane from our Marcellus Shale area, both to begin operations in late 2013 and early 2014. We cannot assure you that these facilities will become available. If we are not able to sell ethane, we may be required to curtail production which will adversely affect our revenues.

Other Commodity Risk

We are impacted by basis risk, caused by factors that affect the relationship between commodity futures prices reflected in derivative commodity instruments and the cash market price of the underlying commodity. Natural gas transaction prices are frequently based on industry reference prices that may vary from prices experienced in local markets. If commodity price changes in one region are not reflected in other regions, derivative commodity instruments may no longer provide the expected hedge, resulting in increased basis risk. At times, we have entered into basis swap agreements. The price we receive for our gas production can be more or less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors; therefore, we have entered into basis swap agreements in the past that effectively fix the basis adjustments. We currently have no financial basis swap agreements outstanding.

The following table shows the fair value of our collars, swaps, put and call options and the hypothetical change in fair value that would result from a 10% and a 25% change in commodity prices at June 30, 2012. We remain at risk for possible changes in the market value of commodity derivative instruments; however, such risks should be mitigated by price changes in the underlying physical commodity (in thousands):


				Hypothetical Change in Fair Value Increase of						Hypothetical Change in Fair Value Decrease of
	Fair Value			10%			25%			10%		25%
Collars	$	212,320		$	(87,232	)	$	(218,224	)	$	87,670	$	221,859
Call options		(4,722	)		(5,254	)		(15,248	)		2,961		4,488
Swaps		134,629			(99,954	)		(249,012	)		100,341		251,055
Put options		1,071			(650	)		(968	)		1,629		6,228

Our commodity-based contracts expose us to the credit risk of non-performance by the counterparty to the contracts. Our exposure is diversified among major investment grade financial institutions and we have master netting agreements with the majority of our counterparties that provide for offsetting payables against receivables from separate derivative contracts. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. At June 30, 2012, our derivative counterparties include sixteen financial institutions, of which all but two are secured lenders in our bank credit facility. Counterparty credit risk is considered when determining the fair value of our derivative contracts. While counterparties are major investment grade financial institutions, the fair value of our derivative contracts have been adjusted to account for the risk of non-performance by certain of our counterparties, which was immaterial.

Interest Rate Risk

We are exposed to interest rate risk on our bank debt. We attempt to balance variable rate debt, fixed rate debt and debt maturities to manage interest costs, interest rate volatility and financing risk. This is accomplished through a mix of fixed rate senior subordinated debt and variable rate bank debt. At June 30, 2012, we had $2.6 billion of debt outstanding. Of this amount, $2.4 billion bears interest at fixed rates averaging 6.4%. Bank debt totaling $235.0 million bears interest at floating rates, which was 2.2% on June 30, 2012. On June 30, 2012, the 30-day LIBOR rate was 0.2%. A 1% increase in short-term interest rates on the floating-rate debt outstanding on June 30, 2012, would cost us approximately $2.4 million in additional annual interest expense.

ITEM 4.

CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of June 30, 2012 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

There was no change in our system of internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended June 30, 2012 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

On December 7, 2010, Region VI of the EPA issued an administrative order under the Safe Drinking Water Act against Range and our subsidiary Range Production Company. The EPA filed suit against us in January 2011 seeking to enforce the order in United States District Court for the Northern District of Texas. We filed an appeal of the December 7, 2010 order with the Fifth Circuit Court of Appeals. Effective March 29, 2012, the EPA withdrew the December 7, 2010 administrative order and the suit seeking enforcement of the order was dismissed by EPA with our concurrence. Our appeal of the December 7, 2010 order, having been mooted by the withdrawal of the order, was dismissed by us.

ITEM 1A.

RISK FACTORS

We are subject to various risks and uncertainties in the course of our business. In addition to the factors discussed elsewhere in this report, you should carefully consider the risks and uncertainties described under Item 1A. Risk Factors filed in our Annual Report on Form 10-K for the year ended December 31, 2011. There have been no material changes from the risk factors previously disclosed in that Form 10-K.

ITEM 6.

EXHIBITS

(a) EXHIBITS


Exhibit Number		Exhibit Description

3.1		Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on May 5, 2004, as amended by the Certificate of Second Amendment to Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on July 28, 2005) and the Certificate of Second Amendment to the Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on July 24, 2008)

3.2		Amended and Restated By-laws of Range (incorporated by reference to Exhibit 3.1 to our Form 8-K (File No. 001-12209) as filed with the SEC on May 20, 2010)

4.1		Form of 5.0% Senior Subordinated Notes due 2022 (incorporated by Reference to Exhibit A to Exhibit 4.2 (File No. 001-12209) as filed with the SEC on March 9, 2012

4.2		Indenture dated March 9, 2012 by and among Range Resources Corporation, as issuer, the subsidiary guarantors named therein and the Bank of New York Mellon Trust Company, N.A. as trustee (incorporated by reference to Exhibit 4.1 to our Form 8-K (File No. 001-12209) as filed with the SEC on March 9, 2012)

4.3		First Supplemental Indenture, dated March 9, 2012, among Range Resources Corporation, the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A. as trustee, including the form of 5% Senior Subordinated Notes due 2022 (incorporated by reference to Exhibit 4.2 to our Form 8-K (File No. 001-12209) as filed with the SEC on March 9, 2012)

10.1		Second Amendment to the Fourth Amended and Restated Credit Agreement as of April 9, 2012 among Range (as borrower) and J.P. Morgan Chase Bank, N.A. and the institutions named (therein) as lenders, J.P. Morgan Chase as Administrative Agent (incorporated by reference to Exhibit 10.1 to our Form 10-Q (File No. 001-12009) as filed with the SEC on April 25, 2012)

31.1*		Certification by the President and Chief Executive Officer of Range Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2*		Certification by the Chief Financial Officer of Range Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1**		Certification by the President and Chief Executive Officer of Range Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2**		Certification by the Chief Financial Officer of Range Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101. INS		XBRL Instance Document

101. SCH		XBRL Taxonomy Extension Schema

101. CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101. DEF		XBRL Taxonomy Extension Definition Linkbase Document

101. LAB		XBRL Taxonomy Extension Label Linkbase Document

101. PRE		XBRL Taxonomy Extension Presentation Linkbase Document

*	filed herewith

**	furnished herewith

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Date: July 24, 2012


RANGE RESOURCES CORPORATION

By:		/s/ ROGER S. MANNY
		Roger S. Manny
		*Executive Vice President and Chief Financial Officer*

Date: July 24, 2012


RANGE RESOURCES CORPORATION

By:		/s/ DORI A. GINN
		Dori A. Ginn
		*Principal Accounting Officer and Vice President Controller*

II-1

Exhibit index


Exhibit Number		Exhibit Description

3.1		Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on May 5, 2004, as amended by the Certificate of Second Amendment to Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on July 28, 2005) and the Certificate of Second Amendment to the Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on July 24, 2008)

3.2		Amended and Restated By-laws of Range (incorporated by reference to Exhibit 3.1 to our Form 8-K (File No. 001-12209) as filed with the SEC on May 20, 2010)

4.1		Form of 5.0% Senior Subordinated Notes due 2022 (incorporated by Reference to Exhibit A to Exhibit 4.2 (File No. 001-12209) as filed with the SEC on March 9, 2012

4.2		Indenture dated March 9, 2012 by and among Range Resources Corporation, as issuer, the subsidiary guarantors named therein and the Bank of New York Mellon Trust Company, N.A. as trustee (incorporated by reference to Exhibit 4.1 to our Form 8-K (File No. 001-12209) as filed with the SEC on March 9, 2012)

4.3		First Supplemental Indenture, dated March 9, 2012, among Range Resources Corporation, the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A. as trustee, including the form of 5% Senior Subordinated Notes due 2022 (incorporated by reference to Exhibit 4.2 to our Form 8-K (File No. 001-12209) as filed with the SEC on March 9, 2012)

10.1		Second Amendment to the Fourth Amended and Restated Credit Agreement as of April 9, 2012 among Range (as borrower) and J.P. Morgan Chase Bank, N.A. and the institutions named (therein) as lenders, J.P. Morgan Chase as Administrative Agent (incorporated by reference to Exhibit 10.1 to our Form 10-Q (File No. 001-12009) as filed with the SEC on April 25, 2012)

31.1*		Certification by the President and Chief Executive Officer of Range Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2*		Certification by the Chief Financial Officer of Range Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1**		Certification by the President and Chief Executive Officer of Range Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2**		Certification by the Chief Financial Officer of Range Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101. INS		XBRL Instance Document

101. SCH		XBRL Taxonomy Extension Schema

101. CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101. DEF		XBRL Taxonomy Extension Definition Linkbase Document

101. LAB		XBRL Taxonomy Extension Label Linkbase Document

101. PRE		XBRL Taxonomy Extension Presentation Linkbase Document

*	filed herewith

**	furnished herewith

II-2