Range Resources 10Q 2006 Q2 Quarterly report

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, 2006


o		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.)

777 Main Street, Suite 800, 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.

Yesþ Noo

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer “in Rule 12b-2 of the Exchange Act. (Check one):


Large Accelerated Filerþ		Accelerated Filero		Non-Accelerated Filero

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yeso Noþ

138,075,488 Common Shares were outstanding on July 24, 2006.

RANGE RESOURCES CORPORATION
FORM 10-Q
Quarter Ended June 30, 2006

Unless the context otherwise indicates, all references in this report to “Range” “we” “us” or “our” are to Range Resources Corporation and its subsidiaries.

TABLE OF CONTENTS


	Page
PART I — FINANCIAL INFORMATION

Item 1. Financial Statements:
Consolidated Balance Sheets		3

Consolidated Statements of Operations (unaudited)		4

Consolidated Statements of Cash Flows (unaudited)		5

Consolidated Statements of Comprehensive Income (Loss) (unaudited)		6

Notes to Consolidated Financial Statements (unaudited)		7

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		19

Item 3. Quantitative and Qualitative Disclosures about Market Risk		25

Item 4. Controls and Procedures		26

PART II – OTHER INFORMATION

Item 4. Submission of Matters to a Vote of Security Holders		26

Item 6. Exhibits		27
Sixth Amendment to the Second Amended and Restated Credit Agreement
Certification Pursuant to Section 302
Certification Pursuant to Section 302
Certification Pursuant to Section 906
Certification Pursuant to Section 906

PART I – Financial Information

ITEM 1. – Financial Statements

RANGE RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share data)


	June 30,			December 31,
	2006			2005
	(Unaudited)
Assets
Current assets
Cash and equivalents	$	6,788		$	4,750
Accounts receivable, less allowance for doubtful accounts of $487 and $624		100,520			128,532
Unrealized derivative gain		3,482			425
Deferred tax asset		37,375			61,677
Inventory and other		14,680			12,593
Assets held for sale		140,000			—

Total current assets		302,845			207,977


Unrealized derivative gain		21,488			—
Equity method investment		12,268			—

Oil and gas properties, successful efforts method		3,306,355			2,548,090
Accumulated depletion and depreciation		(873,727	)		(806,908	)

		2,432,628			1,741,182


Transportation and field assets		72,607			65,210
Accumulated depreciation and amortization		(29,467	)		(25,966	)

		43,140			39,244

Other assets		59,417			30,582

Total assets	$	2,871,786		$	2,018,985


Liabilities
Current liabilities
Accounts payable	$	143,346		$	119,907
Asset retirement obligations		3,875			3,166
Accrued liabilities		51,338			28,372
Accrued interest		11,727			10,214
Unrealized derivative loss		67,825			160,101

Total current liabilities		278,111			321,760


Bank debt		397,600			269,200
Subordinated notes		497,102			346,948

Deferred tax, net		418,835			174,817
Unrealized derivative loss		32,816			70,948
Deferred compensation liability		89,309			73,492
Asset retirement obligations		71,194			64,897
Commitments and contingencies

Stockholders’ equity
Preferred stock, $1 par, 10,000,000 shares authorized, none issued and outstanding		—			—
Common stock, $.01 par, 250,000,000 shares authorized, 137,910,629 shares issued at June 30, 2006 and 129,913,046 shares issued at December 31, 2005		1,379			1,299
Common stock held in treasury – 5,826 shares at December 31, 2005		—			(81	)
Capital in excess of par value		1,060,845			845,519
Retained earnings		115,494			13,800
Common stock held by employee benefit trust, 1,959,202 shares and 1,971,605 shares, respectively, at cost		(21,129	)		(11,852	)
Deferred compensation		—			(4,635	)
Accumulated other comprehensive income (loss)		(69,770	)		(147,127	)

Total stockholders’ equity		1,086,819			696,923

Total liabilities and stockholders’ equity	$	2,871,786		$	2,018,985

See accompanying notes

RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited, in thousands except per share data)


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
Revenues
Oil and gas sales	$	157,620	$	118,723	$	333,958	$	226,138
Transportation and gathering		978		631		1,120		1,159
Mark-to-market on oil and gas derivatives		17,503		—		28,784		—
Other		1,572		330		3,004		347

Total revenue		177,673		119,684		366,866		227,644


Costs and expenses
Direct operating		20,181		17,419		39,558		32,227
Production and ad valorem taxes		8,669		7,034		18,396		12,789
Exploration		7,125		9,124		16,643		12,395
General and administrative		9,306		6,241		18,705		12,844
Non-cash stock compensation		2,113		5,276		9,432		9,343
Interest expense		12,003		9,547		22,554		18,131
Depletion, depreciation and amortization		36,833		30,436		71,400		60,198

Total costs and expenses		96,230		85,077		196,688		157,927


Income from continuing operations before income taxes		81,443		34,607		170,178		69,717

Income tax
Current		622		—		1,200		—
Deferred		30,116		12,946		62,598		26,053

		30,738		12,946		63,798		26,053


Income from continuing operations		50,705		21,661		106,380		43,664
Discontinued operations, net of income taxes		565		—		565		—


Net income	$	51,270	$	21,661	$	106,945	$	43,664


Earnings per common share:
Basic — income from continuing operations	$	0.39	$	0.18	$	0.82	$	0.36

— net income	$	0.39	$	0.18	$	0.82	$	0.36


Diluted — income from continuing operations	$	0.37	$	0.17	$	0.79	$	0.35

— net income	$	0.38	$	0.17	$	0.79	$	0.35


Dividends per common share	$	0.02	$	0.013	$	0.04	$	0.027

See accompanying notes

RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, in thousands)


	Six Months Ended
	June 30,
	2006			2005
Increase (decrease) in cash and equivalents
Operating activities:
Net income	$	106,945		$	43,664
Adjustments to reconcile net income to net cash provided from operating activities:
Income from discontinued operations		(565	)		—
Income from equity method investment		(37	)		—
Deferred income tax expense		62,598			26,053
Depletion, depreciation and amortization		71,400			60,198
Unrealized derivative gains		(2,994	)		(293	)
Mark-to-market on oil and gas derivatives		(28,784	)		—
Allowance for bad debts		33			450
Exploration dry hole costs		4,746			1,813
Amortization of deferred issuance costs and other		812			853
Deferred compensation adjustments		11,754			9,960
Loss on sale of assets and other		923			4
Changes in working capital, net of amounts from business acquisition:
Accounts receivable		42,006			18,056
Inventory and other		(1,862	)		(8,074	)
Accounts payable		(5,516	)		(15,166	)
Accrued liabilities and other		(3,880	)		3,778

Net cash provided from continuing operations		257,579			141,296
Net cash provided from discontinued operations		—			—

Net cash provided from operating activities		257,579			141,296


Investing activities:
Additions to oil and gas properties		(195,042	)		(107,228	)
Additions to field service assets		(6,356	)		(3,612	)
Acquisitions, net of cash acquired		(308,516	)		(136,996	)
Investment in equity method affiliate and other assets		(20,916	)		—
Proceeds from disposal of assets and other		141			1,304

Net cash used in investing activities		(530,689	)		(246,532	)


Financing activities:
Borrowings on credit facility		507,900			150,700
Repayments on credit facility		(379,500	)		(308,900	)
Other debt repayments		—			(16	)
Debt issuance costs		(3,662	)		(4,108	)
Treasury stock purchases		—			(2,808	)
Dividends paid – common stock		(5,251	)		(3,263	)
– preferred stock		—			(2,213	)
Issuance of subordinated notes		150,000			150,000
Issuance of common stock		5,661			112,403

Net cash provided from financing activities		275,148			91,795


Net increase (decrease) in cash and equivalents		2,038			(13,441	)
Cash and equivalents at beginning of period		4,750			18,382

Cash and equivalents at end of period	$	6,788		$	4,941

See accompanying notes.

RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited, in thousands)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
Net income	$	51,270		$	21,661		$	106,945		$	43,664
Net deferred hedge gains (losses), net of tax:
Contract settlements reclassified to income		9,559			14,068			20,840			27,258
Change in unrealized deferred hedging gains (losses)		15,525			(6,001	)		56,759			(66,118	)
Change in unrealized gains (losses) on securities held by deferred compensation plan, net of taxes		(1,363	)		366			(242	)		103

Comprehensive income	$	74,991		$	30,094		$	184,302		$	4,907

See accompanying notes.

RANGE RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

(1) ORGANIZATION AND NATURE OF BUSINESS

We are engaged in the exploration, development and acquisition of oil and gas properties primarily in the Southwestern, Appalachian and Gulf Coast regions of the United States. We seek to increase our reserves and production primarily through drilling and complementary acquisitions. Range is a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange.

(2) BASIS OF PRESENTATION

These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Range Resources Corporation 2005 Annual Report on Form 10-K. 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 (the SEC) and do not include all of the information and disclosures required by accounting principles generally accepted in the United States for complete financial statements. All common stock shares, treasury stock shares and per-share amounts have been adjusted to reflect the three-for-two stock split effected on December 2, 2005.

(3) ACQUISITIONS AND DISPOSITIONS

Acquisitions are accounted for as purchases, and accordingly, the results of operations are included in our consolidated statements of operations from the date of acquisition. Purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair value at the time of the acquisition. Acquisitions have been funded with internal cash flow, bank borrowings and the issuance of debt and equity securities. We purchased various properties for $696.1 million and $158.9 million during the six months ended June 30, 2006 and 2005, respectively. The purchases included $519.7 and $150.3 million for proved oil and gas reserves for the six months ended June 30, 2006 and 2005, respectively, with the remainder representing unproved acreage.

In late June 2006, we acquired Stroud Energy, Inc., or Stroud, a private oil and gas company with operations in the Barnett Shale in North Texas, the Cotton Valley in East Texas and the Austin Chalk in Central Texas. To acquire the equity of Stroud, we paid $171.3 million of cash (including transaction costs) and issued 6.5 million shares of our common stock. We also assumed $106.7 million of Stroud’s debt which was retired with borrowings under our bank facility. The cash portion of the acquisition was funded with borrowings under our bank facility.

The following table summarizes the estimated fair values of assets acquired and liabilities assumed at closing. We are in the process of finalizing fair value estimates for certain assets and liabilities; thus the allocation of purchase price is preliminary (in thousands):


Purchase price:
Cash paid (including transaction costs)	$	171,310
6.5 million shares of common stock (at fair value of $27.26 per share)		177,679
Stock options assumed		9,478
Debt		106,700

Total	$	465,167


Allocation of purchase price:
Working capital deficit	$	(17,715	)
Long-term assets		620
Other property and equipment		1,124
Oil and gas properties		510,117
Assets held for sale		140,000
Deferred income taxes		(166,891	)
Long-term liabilities		(900	)
Asset retirement obligations		(1,188	)

Total	$	465,167

The following unaudited pro forma data includes the results of operations of the Stroud acquisition as if it had been consummated at the beginning of 2005. The pro forma data is based on historical information and does not necessarily reflect the actual results that would have occurred nor are they necessarily indicative of future results of operations (in thousands, except per share data).


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
Revenues	$	194,405	$	125,761	$	401,541	$	233,491

Income from continuing operations	$	49,089	$	19,860	$	105,291	$	37,008

Net income	$	51,015	$	21,518	$	109,626	$	39,674

Per share data:
Income from continuing operations-basic	$	0.36	$	0.15	$	0.77	$	0.29

Income from continuing operations-diluted	$	0.35	$	0.15	$	0.74	$	0.28

Net income-basic	$	0.37	$	0.17	$	0.81	$	0.31

Net income-diluted	$	0.36	$	0.16	$	0.78	$	0.30

(4) ASSETS HELD FOR SALE AND DISCONTINUED OPERATIONS

As part of the Stroud acquisition (see discussion in Note 3), we purchased Austin Chalk properties in Central Texas which we plan to sell. Management has been authorized to sell the properties, which are expected to be sold within the next twelve months. We have met the criteria of SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets” that allow us to classify these assets as held for sale on our balance sheet. We will present the results of operations (revenues less direct expenses, interest, impairment and taxes) as discontinued operations in all future periods. Discontinued operations for the quarter ended June 30, 2006 includes revenues of $1.0 million.

(5) SUSPENDED EXPLORATORY WELL COSTS

The following table reflects the changes in capitalized exploratory well costs for the six months ended June 30, 2006 and the twelve months ended December 31, 2005 (in thousands):


	June 30,			December 31,
	2006			2005
Beginning balance at January 1	$	25,340		$	7,332
Additions to capitalized exploratory well costs pending the determination of proved reserves		2,975			26,915
Reclassifications to wells, facilities and equipment based on determination of proved reserves		(9,348	)		(8,614	)
Capitalized exploratory well costs charged to expense		(1,038	)		(293	)

Balance at end of period		17,929			25,340
Less exploratory well costs that have been capitalized for a period of one year or less		(14,647	)		(21,589	)

Capitalized exploratory well costs that have been capitalized for a period greater than one year	$	3,282		$	3,751

Number of projects that have exploratory well costs that have been capitalized for a period greater than one year		4			3

As of June 30, 2006, of the $3.3 million of capitalized exploratory well costs that have been capitalized for more than one year, each of the wells have additional exploratory wells in the same prospect area drilling or firmly planned. The $17.9 million of capitalized exploratory well costs at June 30, 2006 was incurred in 2006 ($3.0 million), in 2005 ($12.2 million) in 2004 ($2.5 million) and in 2003 ($200,000).

(6) ASSET RETIREMENT OBLIGATIONS

A reconciliation of our liability for plugging and abandonment costs for the six months ended June 30, 2006 and 2005 is as follows (in thousands):


	Six Months Ended
	June 30,
	2006			2005
Beginning of period	$	68,063		$	70,727
Liabilities incurred		2,328			2,298
Acquisition		1,188			—
Liabilities settled		(2,064	)		(2,295	)
Accretion expense		2,219			2,551
Change in estimate		3,335			(1,482	)

End of period	$	75,069		$	71,799

Accretion expense is recognized as a component of depreciation, depletion and amortization.

(7) STOCK-BASED COMPENSATION

Prior to January 1, 2006, we accounted for stock options granted under our stock-based compensation plans under the recognition and measurement provisions of APB Opinion No. 25, “Accounting for Stock Issued to Employees” and related Interpretations, as permitted by FASB Statement No. 123, “Accounting for Stock-Based Compensation.” For our stock options, no stock-based compensation expense was recognized in our statements of operations prior to January 1, 2006, as all stock options granted had an exercise price equal to the market value of the underlying common stock on the date of grant. Effective January 1, 2006, we adopted the fair value recognition provisions of FASB Statement No. 123(R), “Share-Based Payment,” using the modified prospective transition method. Under this transition method, compensation cost for stock options and stock appreciation rights recognized in the first six months of 2006 includes (a) compensation cost ($2.9 million) for all stock-based payments granted prior to, but not yet vested as of December 31, 2005, based on the remaining service period and the grant date fair value estimated in accordance with the original provisions of Statement No. 123 and (b) compensation cost ($1.4 million) for all stock-based payments granted subsequent to December 31, 2005, based on the service period and the grant-date fair value estimated in accordance with Statement No. 123(R). Pursuant to Statement No. 123(R), results for prior periods have not been restated.

We also began granting stock appreciation rights, or SARs, in July 2005 as part of our stock-based compensation plans to limit the dilutive impact of our equity plans. Prior to January 1, 2006, we also accounted for these SARs grants under the recognition and measurement provisions of Opinion No. 25, which requires expense to be recognized equal to the amount by which the quoted market value exceeds the original grant price on a mark-to-market basis. Therefore, we recognized $5.8 million of compensation cost in the last six months of 2005 related to SARs. Beginning January 1, 2006, as required under the provisions of Statement No. 123(R), those SARs granted prior to, but not yet vested as of December 31, 2005, are being expensed over the service period based on grant date fair value estimated in accordance with the original provisions of Statement No. 123 and all SARs granted subsequent to December 31, 2005 are being expensed over the service period based on grant-date fair value estimated in accordance with Statement No. 123(R).

As a result of adopting Statement No. 123(R) on January 1, 2006, our income from continuing operations before income taxes and net income for the first six months are $4.3 million and $2.7 million lower, respectively, than if we had continued to account for stock-based compensation under Opinion No. 25. Also, as a result of adopting Statement No. 123(R), our December 31, 2005 unearned deferred compensation and additional paid-in capital related to our restricted stock issuances was eliminated. As of June 30, 2006, there was $13.0 million of unrecognized compensation related to restricted stock awards expected to be recognized over the next 3.5 years.

The following table illustrates the effect on net income and earnings per share if we had applied the fair value recognition provisions of Statement No. 123(R) to options and SARs granted under our stock-based compensation plans in all periods presented. For the purposes of this pro forma disclosure, the value is estimated using a Black-Scholes-Merton option-pricing formula and amortized to expense over the option’s vesting periods.


	Three Months Ended			Six Months Ended
	June 30,			June 30,
	2005			2005
Net income, as reported	$	21,661		$	43,664
Plus: Total stock-based employee compensation cost included in net income, net of tax		3,459			6,275

Deduct: Total stock-based employee compensation, determined under fair value based method, net of tax		(5,871	)		(10,250	)

Pro forma net income	$	19,249		$	39,689


Earnings per share:
Basic-as reported	$	0.18		$	0.36
Basic-pro forma	$	0.16		$	0.33

Diluted-as reported	$	0.17		$	0.35
Diluted-pro forma	$	0.15		$	0.32

The weighted average fair value of SARs granted in the first six months of 2006 was determined to be $8.48 based on the following assumptions: risk-free interest rate of 4.8%; dividend yield of 0.3%; expected volatility of 41%; and expected life of 3.52 years.

(8) SUPPLEMENTAL CASH FLOW INFORMATION


	Six Months Ended
	June 30,
	2006			2005
	(in thousands)
Non-cash investing and financing activities included:
Common stock issued under benefit plans	$	916		$	720
Asset retirement costs capitalized		5,709			289
Shares issued for Stroud purchase		177,679			—
Stock options assumed in Stroud purchase		9,478			—

Net cash provided from operating activities included:
Income taxes refunded	$	(673	)	$	—
Interest paid		19,999			14,760

(9) INDEBTEDNESS

We had the following debt outstanding as of the dates shown below (in thousands) (bank debt interest rate at June 30, 2006, is shown parenthetically). No interest expense was capitalized during the three months or the six months ended June 30, 2006 and 2005, respectively.


	June 30,		December 31,
	2006		2005
Bank debt (6.5%)	$	397,600	$	269,200

Subordinated debt:
7-3/8% Senior Subordinated Notes due 2013, net of discount		197,102		196,948
6-3/8% Senior Subordinated Notes due 2015		150,000		150,000
7-1/2% Senior Subordinated Notes due 2016		150,000		—

Total debt	$	894,702	$	616,148

Bank Debt

In June 2004, we entered into an amended and restated $600.0 million revolving bank facility, which is secured by substantially all of our assets. The bank credit facility provides for a borrowing base subject to redeterminations semi-annually each April and October and pursuant to certain unscheduled redeterminations. At June 30, 2006, the borrowing base was $600.0 million. At June 30, 2006, the outstanding balance under the bank credit facility was $397.6 million and there was $202.4 million of borrowing capacity available. In April 2006, the loan maturity was extended two years to January 1, 2011 and the borrowing base was redetermined at $600.0 million. Borrowing under the bank credit facility can either be base rate loans or LIBOR loans. On all base rate loans, the rate per annum is equal to the lesser of (i) the maximum rate (the “weekly ceiling” as defined in Section 303 of the Texas Finance Code or other applicable laws if greater) (the “Maximum Rate”) or, (ii) the sum of (A) the higher of (1) the prime rate for such date, or (2) the sum of the federal funds effective rate for such date plus one-half of one percent (0.50%) per annum, plus a base rate margin of between 0.0% to 0.5% per annum depending on the total outstanding under the bank credit facility relative to the borrowing base. On all LIBOR loans, we pay a varying rate per annum equal to the lesser of (i) the Maximum Rate, or (ii) the sum of the quotient of (A) the LIBOR base rate, divided by (B) one minus the reserve requirement applicable to such interest period, plus a LIBOR margin of between 1.0% and 1.75% per annum depending on the total outstanding under the bank credit facility 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 part of the base rate loans to LIBOR loans. The weighted average interest rate on the bank credit facility was 6.3% and 4.1% for the three months ended June 30, 2006 and 2005, respectively. The weighted average interest rate on the bank credit facility was 5.9% and 4.1% for the six months ended June 30, 2006 and 2005, respectively. A commitment fee is paid on the undrawn balance based on an annual rate of between 0.25% and 0.50%. At June 30, 2006, the commitment fee was 0.375% and the interest rate margin was 1.25%. At July 24, 2006, the interest rate (including applicable margin) was 7.0%.

7-3/8% Senior Subordinated Notes due 2013

In 2003, we issued $100.0 million of 7-3/8% senior subordinated notes due 2013, or the 7-3/8% Notes. In 2004, we issued an additional $100.0 million of 7-3/8% Notes; therefore, $200.0 million of the 7-3/8% Notes are currently outstanding. We pay interest on the 7-3/8% Notes semi-annually in January and July of each year. The 7-3/8% Notes mature in 2013 and are guaranteed by certain of our subsidiaries. The 7-3/8% Notes were issued at a discount which is amortized into interest expense over the life of the 7-3/8% Notes.

We may redeem the 7-3/8% Notes, in whole or in part, at any time on or after July 15, 2008, at redemption prices from 103.7% of the principal amount as of July 15, 2008, and declining to 100.0% on July 15, 2011 and thereafter. Prior to July 15, 2006, we may redeem up to 35% of the original aggregate principal amount of the notes at a redemption price of 107.4% of the principal amount thereof plus accrued and unpaid interest, if any, with the proceeds of certain equity offerings. If we experience a change of control, there may be a requirement to repurchase all or a portion of the 7-3/8% Notes at 101% of the principal amount plus accrued and unpaid interest, if any. The 7-3/8% Notes and the guarantees by our subsidiary guarantors are general, unsecured obligations and are subordinated to our senior debt and will be subordinated to future senior debt that Range and our subsidiary guarantors are permitted to incur under the bank credit facility and the indenture governing the 7-3/8% Notes.

6-3/8% Senior Subordinated Notes due 2015

In 2005, we issued $150.0 million of 6-3/8% Senior Subordinated Notes due 2015, or the 6-3/8% Notes. We pay interest on the 6-3/8% Notes semi-annually in March and September of each year. The 6-3/8% Notes mature in 2015 and are guaranteed by certain of our subsidiaries.

We may redeem the 6-3/8% Notes, in whole or in part, at any time on or after March 15, 2010, at redemption prices from 103.2% of the principal amount as of March 15, 2010 and declining to 100% on March 15, 2013 and thereafter. Prior to March 15, 2008, we may redeem up to 35% of the original aggregate principal amount of the notes at a redemption price of 106.4% of the principal amount thereof plus accrued and unpaid interest, if any, with the proceeds of certain equity offerings. If we experience a change of control, there may be a requirement to repurchase all or a portion of the 6-3/8% Notes at 101% of the principal amount plus accrued and unpaid interest, if any. The 6-3/8% 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 Range and our subsidiary guarantors are permitted to incur under the bank credit facility and the indenture governing the 6-3/8% Notes.

7-1/2% Senior Subordinated Notes due 2016

In May 2006, we issued $150.0 million of 7-1/2% Senior Subordinated Notes due 2016, or the 7-1/2% Notes. We pay interest on the 7-1/2% Notes semi-annually in May and November of each year. The 7-1/2% Notes mature in 2016 and are guaranteed by certain of our subsidiaries.

We may redeem the 7-1/2% Notes, in whole or in part, at any time on or after May 15, 2011 at redemption prices from 103.75% of the principal amount as of May 15, 2011 and declining to 100% on May 15, 2014 and thereafter. Prior to May 15, 2009, we may redeem up to 35% of the original aggregate principal amount of the notes at a redemption price of 107.5% of principal amount thereof plus accrued and unpaid interest if any, with the proceeds of certain equity offerings; provided that at least 65% of the original aggregate principal amount of our 7-1/2% Notes remains outstanding immediately after the occurrence of such redemption and provided that such redemption occurs within 60 days of the date of closing the equity sale. If we experience a change of control, there may be a requirement to purchase all or a portion of the 7-1/2% Notes at 101% of the principal amount plus accrued and unpaid interest, if any. The 7-1/2% Notes and the guarantees by our subsidiary guarantors are, general, unsecured obligations and are subordinated to our bank debt and will be subordinated to further senior debt that Range and our subsidiary guarantors are permitted to incur under the bank credit facility and the indenture governing the 7-1/2% Notes.

Subsidiary Guarantors

Range Resources Corporation is a holding company which owns no operating assets and has no significant operations independent of its subsidiaries. The guarantees of the 7-3/8% Notes, the 6-3/8% Notes and the 7-1/2% Notes are full and unconditional and joint and several; any subsidiaries, other than the subsidiary guarantors, are either minor subsidiaries or indirect subsidiaries, or both.

Debt Covenants

The debt agreements contain covenants relating to working capital, dividends and financial ratios. We were in compliance with all covenants at June 30, 2006. Under the bank credit facility, dividends are permitted, subject to the provisions of the restricted payment basket. The bank credit facility provides for a restricted payment basket of $20.0 million plus 50% of net income plus 66-2/3% of net cash proceeds from common stock issuances. Approximately $421.7 million was available under the bank credit facility’s restricted payment basket on June 30, 2006. The terms of the 6-3/8% Notes, the 7-3/8% Notes and the 7-1/2% Notes limit restricted payments (including dividends) to the greater of $20.0 million or a formula based on earnings and equity issuances since the original issuance of the notes. At June 30, 2006, $480.3 million was available under the 6-3/8% Notes, the 7-3/8% Notes, and the 7-1/2% Notes restricted payment baskets.

(10) DERIVATIVE ACTIVITIES

At June 30, 2006, we had open swap contracts covering 70.5 Bcf of gas at prices averaging $9.30 per mcf and 0.1 million barrels of oil at prices averaging $35.00 per barrel. We also had collars covering 82.4 Bcf of gas at weighted average floor and cap prices which range from $7.09 to $9.86 per mcf and 4.8 million barrels of oil at weighted average floor and cap prices that range from $50.70 to $63.62 per barrel. Their fair value, represented by the estimated amount that would be realized upon termination, based on a comparison of the contract prices and a reference price, generally New York Mercantile Exchange, or the NYMEX, on June 30, 2006, was a net unrealized pre-tax loss of $75.7 million. The contracts expire monthly through December 2008. Transaction gains and gains on settled contracts are determined monthly and are included as increases or decreases to oil and gas revenues in the period the hedged production is sold. Oil and gas revenues were decreased by $33.1 million and $43.3 million due to realized hedging losses in the six months ended June 30, 2006 and 2005, respectively. Other revenues in our consolidated statements of operations include ineffective hedging gains on hedges that qualified for hedge accounting of $3.3 million and $248,000 in the six months ended June 30, 2006 and 2005, respectively and $1.9 million and $123,000 in the three months ended June 30, 2006 and 2005, respectively. In the fourth quarter of 2005, certain of our gas hedges no longer qualified for hedge accounting and were marked-to-market in the first six months of 2006 which resulted in a gain of $28.8 million and a gain of $17.5 million in the three months ended June 2006.

The following table sets forth our derivative volumes by year as of June 30, 2006:


Period	Contract Type	Volume Hedged	Average Hedge Price
Natural Gas
2006	Swaps	10,761 Mmbtu/day	$6.34
2006	Collars	143,283 Mmbtu/day	$6.39 — $8.52
2007	Swaps	82,500 Mmbtu/day	$9.34
2007	Collars	98,500 Mmbtu/day	$7.13 — $9.99
2008	Swaps	105,000 Mmbtu/day	$9.42
2008	Collars	55,000 Mmbtu/day	$7.93 — $11.39

Crude Oil
2006	Swaps	400 bbl/day	$35.00
2006	Collars	6,863 bbl/day	$39.83 — $49.05
2007	Collars	5,800 bbl/day	$52.90 — $64.58
2008	Collars	4,000 bbl/day	$56.89 — $74.78

We have used interest rate swap agreements to manage the risk that interest payments on amounts outstanding under the variable rate bank credit facility may be adversely affected by volatility in market rates. Our interest rate swap agreements ended on June 30, 2006.

Hedging activities are conducted with major financial and commodities trading institutions which we believe are acceptable credit risks. At times, such risks may be concentrated with certain counterparties. The creditworthiness of the counterparties is subject to continuing review.

(11) COMMITMENTS AND CONTINGENCIES

We are involved in various legal actions and claims arising in the ordinary course of business, one of which isJack Freeman, et al. v. Great Lakes Energy Partners L.L.C., et al.This was a class-action suit filed in 2000 against Great Lakes and Range in the state court of Chautauqua County, New York. The plaintiffs were seeking to recover actual damages and expenses plus punitive damages based on allegations that we sold gas to affiliates and gas marketers at low prices, and that inappropriate post production expenses were used to reduce proceeds to the royalty owners, and that improper accounting was used for the royalty owners’ share of gas. A negotiated settlement obligation of $725,000 was reflected in general and administrative expense in the fourth quarter of 2005, subject to approval by the Court. During the second quarter of 2006, the Court approved the negotiated settlement and in July 2006, this lawsuit was settled at the previously negotiated amount. In management’s opinion, we are not involved in any litigation, the outcome of which would have a material adverse effect on our financial position, results of operations or liquidity.

As of June 30, 2006, we have contracts with two drilling contractors to use two drilling rigs with terms of up to two years and minimum future commitments of $7.0 million in 2006, $12.8 million in 2007 and $2.2 million in 2008. Early termination of these contracts at June 30, 2006 would have required us to pay maximum penalties of $16.7 million. We do not expect to pay any early termination penalties related to these contracts. We also entered into a new ten-year office lease which begins in April 2007 with payments of $1.4 million per year for the first five years and $1.6 million for the next five years.

(12) CAPITAL STOCK

We have authorized capital stock of 260 million shares, which includes 250 million shares of common stock and 10 million shares of preferred stock. All shares have been adjusted to reflect the three-for-two common stock split effected on December 2, 2005. The following is a schedule of changes in the number of common shares outstanding from January 1, 2005 to June 30, 2006:


	Six Months		Twelve Months
	Ended		Ended
	June 30, 2006		December 31, 2005
Beginning balance		129,907,220		121,829,027
Public offerings		—		6,900,000
Shares issued for Stroud purchase		6,416,929		—
Stock options/SARs exercised		1,132,670		1,105,549
Restricted stock grants		415,609		—
Deferred compensation plan		11,689		20,885
Shares issued in lieu of bonuses		20,686		25,590
Shares contributed to 401(k) plan		—		33,018
Fractional shares		—		(1,023	)
Treasury shares		5,826		(5,826	)

		8,003,409		8,078,193


Ending balance		137,910,629		129,907,220

Treasury Stock

In 2005, we bought in open market purchases, 201,000 shares at an average price of $14.00. As of June 30, 2006, all of these shares had been used for equity compensation. The Board of Directors has approved up to $10.0 million of additional repurchases of common stock based on market conditions and opportunities.

(13) EMPLOYEE BENEFIT AND EQUITY PLANS

We have six equity-based stock plans, of which two are active. Under the active plans, incentive and non-qualified options, stock appreciation rights (or SARs), restricted stock awards, phantom stock rights and annual cash incentive awards may be issued to directors and employees pursuant to decisions of the Compensation Committee of the Board of Directors which is made up of independent directors. Information with respect to stock option and SARs activities is summarized below:


				Weighted
				Average
	Shares			Exercise Price
Outstanding on December 31, 2005		8,742,305		$	9.31
Granted		1,579,910			24.23
Stock options assumed in Stroud acquisition		652,062			19.67
Exercised		(1,200,505	)		6.39
Expired/forfeited		(92,326	)		16.11

Outstanding on June 30, 2006^(a)		9,681,446		$	12.74


^(a)		Includes options outstanding under our inactive plans of 5.6 million under the 1999 Stock Option plan, 252,000 under the Outside Directors’ Stock Option plan, 116,200 under the 1989 Stock Option plan and 652,000 under the Stroud plan. The total outstanding at June 30, 2006 includes 2.9 million SARs.

The following table shows information with respect to outstanding stock options and SARs at June 30, 2006:


	Outstanding						Exercisable
			Weighted-
			Average						Weighted-
			Remaining		Weighted-				Average
Range of			Contractual		Average				Exercise
Exercise Prices	Shares		Life		Exercise Price		Shares		Price
$1.29—$4.99		2,789,288		3.29	$	3.59		2,670,787	$	3.55
5.00 — 9.99		1,487,888		2.63		7.01		771,786		7.02
10.00 — 14.99		432,398		3.33		11.40		129,789		12.84
15.00 — 19.99		3,211,714		4.74		17.23		1,229,900		18.03
20.00 — 24.99		1,671,658		4.97		24.13		158,798		23.84
25.00 — 27.31		88,500		4.53		26.15		—		—

Total		9,681,446		3.97	$	12.74		4,961,060	$	8.57

The 9.7 million shares outstanding at June 30, 2006 had an aggregate intrinsic value (or difference in value between exercise and market price) of $139.9 million and the 5.0 million shares exercisable at June 30, 2006 had an aggregate intrinsic value of $92.4 million. The total intrinsic value of options/SARs exercised during the six months ended June 30, 2006 was $24.8 million. Cash received from option exercises during the six months ended June 30, 2006 totaled $5.7 million.

Restricted Stock Grants

During the first six months of 2006, 415,600 shares of restricted stock (5,100 shares from treasury stock) were issued to directors and employees at an average price of $24.34. These grants included 15,000 issued to directors, which vest immediately and 400,600 to employees with a three-year vesting period. In 2005, we issued 192,500 shares of restricted stock (from treasury stock) as compensation to directors and employees at an average price of $22.47. The restricted grants included 26,200 issued to directors, which vest immediately, and 166,300 to employees with vesting ranging from three to four years. We recorded compensation expense related to these grants which is based upon the market value of the shares on the date of grant of $1.5 million and $347,000 in the six-month periods ended June 30, 2006 and 2005, respectively.

Deferred Compensation Plan

In December 2004, we adopted the Range Resources Corporation Deferred Compensation Plan, or the 2005 Deferred Compensation Plan. The 2005 Deferred Compensation Plan gives directors, officers and key employees the ability to defer all or a portion of their salaries and bonuses and invests such amounts in Range common stock or makes other investments at the individual’s discretion. The assets of the plan are held in a rabbi 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 in a manner similar to treasury stock with an offsetting amount reflected as a deferred compensation liability and the carrying value of the deferred compensation liability is adjusted to fair value each reporting period by a charge or credit to non-cash stock compensation expense on our consolidated statement of operations. The assets of the Rabbi Trust, other than Range common stock, are invested in marketable securities and reported at market value in other assets on our consolidated balance sheet. The deferred compensation liability on our balance sheet reflects the market value of the securities held in the Rabbi Trusts. The cost of common stock held in the Rabbi Trusts is shown as a reduction to stockholders’ equity. Changes in the market value of the marketable securities are reflected in other comprehensive income, or OCI, while changes in the market value of the Range common stock held in the Rabbi Trust is charged or credited to non-cash stock compensation expense each quarter. Based on end of quarter stock prices of $27.19 and $26.90, we recorded non-cash mark-to-market (income) expense related to deferred compensation of $(2.1) million and $5.3 million in the three months ended June 30, 2006 and 2005, respectively and $2.4 million and $9.3 million in the six months ended June 30, 2006 and 2005, respectively.

(14) INCOME TAXES

The significant components of deferred tax liabilities and assets on June 30, 2006 and December 31, 2005 were as follows (in thousands):


	June 30,			December 31,
	2006			2005
Deferred tax assets (liabilities)
Net unrealized loss in OCI	$	41,161		$	85,462
Net operating loss carryover and other		145,688			147,468
Depreciation and depletion		(568,309	)		(346,070	)


Net deferred tax liability	$	(381,460	)	$	(113,140	)

At December 31, 2005, we had regular net operating loss, or NOL, carryovers of $207.2 million and alternative minimum tax, or AMT, NOL carryovers of $179.2 million that expire between 2012 and 2025. At December 31, 2005, we had AMT credit carryovers of $0.7 million that are not subject to limitation or expiration.

(15) EARNINGS PER COMMON SHARE

The following table sets forth the computation of basic and diluted earnings per common share (in thousands except per share amounts):


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
Numerator:
Income from continuing operations	$	50,705		$	21,661		$	106,380		$	43,664
Income from discontinued operations		565			—			565			—

Net income	$	51,270		$	21,661		$	106,945		$	43,664


Denominator:
Weighted average shares outstanding		132,156			123,738			131,453			122,889
Stock held in the deferred compensation plan and treasury shares		(1,403	)		(2,063	)		(1,413	)		(2,112	)

Weighted average shares, basic		130,753			121,675			130,040			120,777


Effect of dilutive securities:
Weighted average shares outstanding		132,156			123,738			131,453			122,889
Employee stock options and other		3,802			2,521			3,825			2,468

Dilutive potential common shares for diluted earnings per share		135,958			126,259			135,278			125,357


Earnings per common share:
Income from continuing operations
-Basic	$	0.39		$	0.18		$	0.82		$	0.36
-Diluted	$	0.37		$	0.17		$	0.79		$	0.35
Income from discontinued operations
-Basic	$	—		$	—		$	—		$	—
-Diluted	$	0.01		$	—		$	—		$	—
Net income
-Basic	$	0.39		$	0.18		$	0.82		$	0.36
-Diluted	$	0.38		$	0.17		$	0.79		$	0.35

Stock appreciation rights (SARs) for 18,000 shares were outstanding but not included in the computations of diluted net income per share for the three months and the six months ended June 30, 2006 because the exercise price of the SARs was greater than the average price of the common shares and would be anti-dilutive to the computations.

(16) CAPITALIZED COSTS AND ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION


	June 30,			December 31,
	2006			2005
Oil and gas properties:
Properties subject to depletion	$	3,105,807		$	2,519,454
Unproved properties		200,548			28,636

Total		3,306,355			2,548,090
Accumulated depletion		(873,727	)		(806,908	)

Net	$	2,432,628		$	1,741,182

(17) COSTS INCURRED FOR PROPERTY ACQUISITIONS, EXPLORATION AND DEVELOPMENT^(a)


	Six Months		Twelve Months
	Ended		Ended
	June 30,		December 31,
	2006		2005
Costs incurred:
Acquisitions:
Acreage purchases	$	43,579	$	20,674
Proved oil and gas properties		351,575		131,748
Unproved property		132,821		—
Purchase price adjustment^(b)		166,891		20,966
Asset retirement obligations		1,188		119
Gas gathering facilities		—		8

Development		176,583		252,574

Exploration^(c)		29,735		59,539

Gas gathering facilities		9,556		11,415

Subtotal		911,928		497,043

Asset retirement obligations		5,709		(1,730	)

Total	$	917,637	$	495,313


^(a)		Includes costs incurred whether capital or expense.

^(b)		Represents non-cash gross up to account for difference in book and tax basis.

^(c)		Includes $16,643 and $29,437 of exploration costs expensed in the six months ended June 30, 2006 and the twelve months ended December 31, 2005, respectively.

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read in conjunction with management’s discussion and analysis contained in our 2005 Annual Report on Form 10-K, as well as the consolidated financial statements and notes thereto included in this quarterly report on 10-Q.

Statements in our discussion may be forward-looking. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause future production, revenues and expenses to differ materially from our expectations. For additional risk factors affecting our business, see the information in Item 1A in our 2005 Annual Report on Form 10-K and subsequent filings.

Results of Operations

Volumes and sales data:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
Production:
Crude oil (bbls)		782,429		723,441		1,552,124		1,434,524
NGLs (bbls)		287,600		247,354		554,653		496,297
Natural gas (mcfs)		17,601,601		15,363,873		34,521,707		30,198,139
Total (mcfe)^(a)		24,021,775		21,188,643		47,162,369		41,783,065

Average daily production:
Crude oil (bbls)		8,598		7,950		8,575		7,926
NGLs (bbls)		3,160		2,718		3,064		2,742
Natural gas (mcfs)		193,424		168,834		190,728		166,840
Total (mcfe)^(a)		263,976		232,842		260,566		230,846

Average sales prices (excluding hedging):
Crude oil (per bbl)	$	66.25	$	48.79	$	63.04	$	47.94
NGLs (per bbl)	$	35.19	$	28.67	$	32.58	$	27.13
Natural gas (per mcf)	$	6.30	$	6.42	$	7.27	$	6.20
Total (per mcfe)^(a)	$	7.19	$	6.65	$	7.78	$	6.45

Average sales price (including hedging):
Crude oil (per bbl)	$	47.30	$	35.94	$	46.94	$	36.08
NGLs (per bbl)	$	35.19	$	25.33	$	32.58	$	23.88
Natural gas (per mcf)	$	6.28	$	5.63	$	7.04	$	5.38
Total (per mcfe)^(a)	$	6.56	$	5.60	$	7.08	$	5.41


^(a)		Oil and NGLs are converted at the rate of one barrel equals six mcfe. Excludes discontinued operations.

Overview

Total revenues increased 48% for the second quarter of 2006 over the same period of 2005. This increase is due to higher production and realized prices and a favorable mark-to-market value adjustment on oil and gas derivatives that do not qualify for hedge accounting. For the second quarter of 2006, production increased 13% from last year due to the continued success of our drilling program. Realized oil and gas prices were higher by 17% in the second quarter of 2006 compared to the same period of 2005 reflecting higher market prices and the expiration of lower priced oil and gas hedges. Our remaining hedges reduced revenue by $15.2 million in the second quarter of 2006 and by $22.3 million in the same period of 2005.

Higher production volumes and higher realized oil and gas prices have improved our profit margins. However, it is our belief that Range and the oil and gas industry as a whole continues to experience higher costs due to heightened competition for qualified employees, goods and services. On a unit cost basis, our direct operating costs and general and administrative expense increased $0.02 and $0.10 per mcfe, respectively, which reflects a 2% and 34%, respectively, increase from the second quarter of 2005 to the second quarter of 2006. Service and personnel cost increases are occurring in all facets of our business as oil and gas industry fundamentals remain favorable and it is anticipated that upward pressure on costs will continue.

Comparison of Quarter Ended June 30, 2006 and 2005

Net incomeincreased $29.6 million to $51.3 million primarily due to higher realized oil and gas prices, higher production volumes and a favorable mark-to-market value adjustment on oil and gas derivatives that do not qualify for hedge accounting. Oil and gas revenues for the second quarter of 2006 reached $157.6 million and were 33% higher than 2005 due to higher oil and gas prices and a 13% increase in production. A 48% increase in total revenues was partially offset by higher general and administrative expense, operating costs, DD&A and interest expense.

Average realized pricereceived for oil and gas during the second quarter of 2006 was $6.56 per mcfe, up 17% or $0.96 per mcfe from the same quarter of the prior year. The average price received in the second quarter for oil increased 32% to $47.30 per barrel and increased 12% to $6.28 per mcf for gas from the same period of 2005. The effect of our hedging program decreased realized prices $0.63 per mcfe in the second quarter of 2006 versus a decrease of $1.05 per mcfe in the same period of 2005.

Production volumesincreased 13% from the second quarter of 2005 primarily due to continued drilling success. Our production for the second quarter was 264.0 mmcfe per day of which 53% was attributable to our Southwestern division, 39% to our Appalachian division and 8% to our Gulf Coast division.

Other revenueincreased in 2006 to $1.6 million from $330,000 in 2005. The 2006 period includes $1.9 million of ineffective hedging gains. Other revenue for 2005 includes $123,000 of ineffective hedging gains and $85,000 of proceeds from the sale of miscellaneous inventory.

Direct operating expenseincreased $2.8 million in the second quarter of 2006 to $20.2 million due to higher oilfield service costs and higher volumes. Our operating expenses are increasing as we add new wells and maintain production from our existing properties. We incurred $1.4 million ($0.06 per mcfe) of workover costs in 2006 versus $2.7 million ($0.13 per mcfe) in 2005. On a per mcfe basis, direct operating expenses increased $0.02 per mcfe from the same period of 2005. The workover costs were primarily attributable to workovers on properties located in the Gulf of Mexico (continuing costs associated with the 2005 hurricanes) and our Southwestern properties.

Production and ad valorem taxesare paid based on market prices, not hedged prices. These taxes increased $1.6 million or 23% from the same period of the prior year due to higher volumes and increasing prices and assessed values. On a per mcfe basis, production and ad valorem taxes increased to $0.36 per mcfe in 2006 from $0.33 per mcfe in the same period of 2005.

Exploration expensedecreased $2.0 million from the same period of the prior year due principally to lower seismic expenditures ($3.2 million) offset by higher dry hole expense ($698,000). Exploration expense includes exploration personnel costs of $1.8 million in 2006 versus $1.4 million in 2005.

General and administrative expensefor the second quarter of 2006 increased $3.1 million from 2005 due to higher salaries and benefits ($963,000), higher restricted stock amortization ($891,000) and higher franchise tax expenses ($393,000). On a per mcfe basis, general and administration expense increased from $0.29 per mcfe in 2005 to $0.39 per mcfe in 2006.

Non-cash stock compensationfor the second quarter of 2006 decreased $3.2 million from 2005 primarily due to less volatility in our common stock held in our deferred compensation plans and a decline in the market value of trading securities also held in those plans. The second quarter of 2006 also includes $4.3 million compensation expense as a result of the adoption of Statement No. 123(R).

Interest expensefor the second quarter of 2006 increased $2.5 million to $12.0 million due to rising interest rates and the refinancing of certain debt from floating to higher fixed rates. In May 2006, we issued $150.0 million of 7-1/2% Notes which added $1.2 million of interest costs in the second quarter of 2006. The proceeds from the issuance of the 7-1/2% Notes were used to retire lower interest rate floating bank debt. Average debt outstanding on the bank credit facility was $264.6 million and $273.2 million for the second quarter of 2006 and 2005, respectively and the average interest rates were 6.3% and 4.1%, respectively.

Depletion, depreciation and amortization, or DD&A, increased $6.4 million or 21% to $36.8 million in the second quarter of 2006 with a 13% increase in production and a 8% increase in depletion rates. On a per mcfe basis, DD&A increased from $1.44 per mcfe in the second quarter of 2005 to $1.53 per mcfe in the second quarter of 2006.

Tax expensefor 2006 increased to $30.7 million reflecting the 135% increase in income from continuing operations before taxes compared to the same period of 2005. The second quarter of 2006 and 2005 provide for a tax expense at an effective rate of approximately 37%. Current income taxes for the three months ended June 30, 2006 of $622,000 represent state income taxes. During the second quarter of 2006, we adjusted our deferred tax balances to reflect the enactment of the new Texas franchise tax laws. The impact of the adoption was not material to our statement of operations.

The following table presents information about our operating expenses per mcfe for the three months ended June 30, 2006 and 2005:


	Three Months Ended June 30,
	2006		2005		Change		%
Direct operating expense	$	0.84	$	0.82	$	0.02		2	%
Production and ad valorem tax expense		0.36		0.33		0.03		9	%
General and administration expense		0.39		0.29		0.10		34	%
Interest expense		0.50		0.45		0.05		11	%
Depletion, depreciation and amortization expense		1.53		1.44		0.09		6	%

Comparison of the Six Months Ended June 30, 2006 and 2005

Net incomeincreased $63.3 million to $106.9 million primarily due to higher realized oil and gas prices, higher production volumes and a favorable mark-to-market value adjustment on oil and gas derivatives that do not qualify for hedge accounting. Oil and gas revenues for the first six months of 2006 reached $334.0 million and were 48% higher than 2005 due to higher oil and gas prices and a 13% increase in production. A 61% increase in total revenues was partially offset by higher exploration expenses, non-cash stock compensation expense, general and administrative, costs operating costs, DD&A and interest expense.

Average realized pricereceived for oil and gas during the first six months of 2006 was $7.08 per mcfe, up 31% or $1.67 per mcfe from the same period of the prior year. The average price received in the first six months for oil increased 30% to $46.94 per barrel and increased 31% to $7.04 per mcf for gas from the same period of 2005. The effect of our hedging program decreased realized prices $0.70 per mcfe in the first six months of 2006 versus a decrease of $1.03 per mcfe in the same period of 2005.

Production volumesincreased 13% from the same period of 2005 primarily due to continued drilling success. Our production for the first six months was 260.6 mmcfe per day of which 53% was attributable to our Southwestern division, 39% to our Appalachian division and 8% to our Gulf Coast division.

Other revenueincreased in 2006 to $3.0 million from $347,000 in 2005. The 2006 period includes $3.3 million of ineffective hedging gains. Other revenue for 2005 includes $248,000 of ineffective hedging gains, a legal settlement for $110,000 and $85,000 of proceeds from the sale of miscellaneous inventory.

Direct operating expenseincreased $7.3 million in the first six months of 2006 to $39.6 million due to higher oilfield service costs and higher volumes. Our operating expenses are increasing as we add new wells and maintain production from our existing properties. We incurred $2.6 million ($0.05 per mcfe) of workover costs in 2006 versus $3.7 million ($0.09 per mcfe) in 2005. On a per mcfe basis, direct operating expenses increased $0.07 per mcfe from the same period of 2005. The workover costs were primarily attributable to workovers on properties located in the Gulf of Mexico and included continuing costs associated with the 2005 hurricanes.

Production and ad valorem taxesare paid based on market prices, not hedged prices. These taxes increased $5.6 million or 44% from the same period of the prior year due to higher volumes and increasing prices and assessed values. On a per mcfe basis, production and ad valorem taxes increased to $0.39 per mcfe in 2006 from $0.31 per mcfe in the same period of 2005.

Exploration expensefor the six months of 2006 increased $4.2 million from 2005 due principally to higher dry hole costs ($2.9 million) and higher seismic expenditures ($308,000). Exploration expense includes exploration personnel costs of $3.4 million in 2006 versus $2.8 million in 2005.

General and administrative expensefor the first six months of 2006 increased $5.9 million from 2005 due to higher salaries and benefits ($2.2 million), higher amortization of restricted stock ($1.1 million), higher franchise tax expense ($281,000), higher legal fees ($539,000) and office costs ($283,000). On a per mcfe basis, general and administration expense increased from $0.31 per mcfe in 2005 to $0.40 per mcfe in 2006.

Non-cash stock compensationfor the second quarter of 2006 was about the same as 2005. The first six months of 2006 includes $7.1 million compensation expense as a result of the adoption of Statement No. 123(R). This expense was offset by less volatility of our common stock held in the deferred compensation plan.

Interest expensefor the first six months of 2006 increased $4.4 million to $22.6 million due to rising interest rates and the refinancing of certain debt from floating to higher fixed rates. In May 2006, we issued $150.0 million of 7-1/2% Notes which added $1.2 million of interest costs in the first six months of 2006. The proceeds from the issuance of the 7-1/2% Notes were used to retire lower interest bank debt. Average debt outstanding on the bank credit facility was $271.6 million and $335.8 million for the first six months of 2006 and 2005, respectively and the average interest rates were 5.9% and 4.1%, respectively.

Depletion, depreciation and amortization, or DD&A, increased $11.2 million or 19% to $71.4 million in the first six months of 2006 with a 13% increase in production and a 7% increase in depletion rates. On a per mcfe basis, DD&A increased from $1.44 per mcfe in the first six months of 2005 to $1.51 per mcfe in the first six months quarter of 2006.

Tax expensefor 2006 increased to $63.8 million reflecting the 144% increase in income from continuing operations before taxes compared to the same period of 2005. The first six months of 2006 and 2005 provide for a tax expense at an effective rate of approximately 37%. Current income taxes of $1.2 million represent state income taxes.

The following table presents information about our operating expenses per mcfe for the first six months of June 2006 and 2005:


	Six Months Ended June 30,
	2006		2005		Change		%
Direct operating expense	$	0.84	$	0.77	$	0.07		9	%
Production and ad valorem tax expense		0.39		0.31		0.08		26	%
General and administration expense		0.40		0.31		0.09		29	%
Interest expense		0.48		0.43		0.05		12	%
Depletion, depreciation and amortization expense		1.51		1.44		0.07		5	%

Liquidity and Capital Resources

During the six months ended June 30, 2006, our cash provided from operations was $257.6 million and we spent $530.7 million on capital expenditures (including acquisitions). During this period, financing activities provided net cash of $275.1 million. At June 30, 2006, we had $6.8 million in cash, total assets of $2.9 billion and a debt-to-capitalization ratio of 45.1%. Long-term debt at June 30, 2006 totaled $894.7 million including $397.6 million of bank credit facility debt and $497.1 million of senior subordinated notes. Available borrowing capacity under the bank credit facility at June 30, 2006 was $202.4 million.

Cash is required to fund capital expenditures necessary to offset inherent declines in production and proven reserves which is typical in the capital-intensive extractive 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 believe that net cash generated from operating activities and unused committed borrowing capacity under the bank credit facility combined with our oil and gas price hedges currently in place will be adequate to satisfy near-term financial obligations and liquidity needs. However, 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 gas business. A material drop in oil and gas prices or a reduction in production and reserves would reduce our ability to fund capital expenditures, reduce debt, 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 oil and gas, 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 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.

Debt

The debt agreements contain covenants relating to working capital, dividends and financial ratios. We were in compliance with all covenants at June 30, 2006. Under the bank credit facility, common and preferred dividends are permitted, subject to the terms of the restricted payment basket. The bank credit facility provides for a restricted payment basket of $20.0 million plus 50% of net income plus 66-2/3% of net cash proceeds from common stock issuances occurring since December 31, 2001. Approximately $421.7 million was available under the bank credit facility’s restricted payment basket on June 30, 2006. The terms of the 6-3/8% Notes, the 7-3/8% Notes and the 7-1/2% Notes limit restricted payments (including dividends) to the greater of $20.0 million or a formula based on earnings since the issuance of the notes and 100% of net cash proceeds from common stock issuances. Approximately $480.3 million was available under the 6-3/8% Notes, the 7-3/8% Notes and the 7-1/2% Notes restricted payment baskets on June 30, 2006.

We maintain a $600.0 million revolving bank credit facility. The facility is secured by substantially all our assets. Availability under the facility is subject to a borrowing base set by the banks semi-annually and in certain other circumstances more frequently. Redeterminations, other than increases, require the approval of 75% of the lenders while increases require unanimous approval. At July 24, 2006, the bank credit facility had a $600.0 million borrowing base of which $134.7 million was available.

Cash Flow

Our principal sources of cash are operating cash flow and bank borrowings and at times, the sale of assets and the issuance of debt and equity securities. Our operating cash flow is highly dependent on oil and gas prices. As of June 30, 2006, we have entered into hedging agreements covering 36.4 Bcfe, 78.8 Bcfe and 67.3 Bcfe for 2006, 2007 and 2008, respectively. Net cash provided by operations for the six months ended June 30, 2006 and 2005 was $257.6 million and $141.3 million, respectively. Cash flow from operations was higher than the prior year due to higher prices and volumes, partially offset by higher operating expenses. Net cash used in investing for the six months ended June 30, 2006 and 2005 was $530.7 million and $246.5 million, respectively. The 2006 period includes $195.0 million of additions to oil and gas properties and $308.5 million of acquisitions. The 2005 period included $107.2 million of additions to oil and gas properties and $137.0 million of acquisitions. Net cash provided from financing for the six months ended June 30, 2006 and 2005 was $275.1 million and $91.8 million, respectively. This increase was primarily the result of borrowings to fund acquisitions and new fixed interest rate notes. During the first six months of 2006 total debt increased $278.6 million.

Dividends

On June 1, 2006, the Board of Directors declared a dividend of two cents per share ($2.6 million) on our common stock, payable on June 30, 2006 to stockholders of record at the close of business on June 15, 2006.

Capital Requirements

The 2006 capital budget is currently set at $551.2 million (excluding acquisitions) and based on current projections, is expected to be funded with internal cash flow, borrowings under the bank credit facility and proceeds from assets held for sale. For the six months ended June 30, 2006, $206.3 million of development and exploration spending was funded with internal cash flow.

Contractual Cash Obligations

Subsequent to December 31, 2005, there have been no significant changes to our contractual obligations other than the extension of the maturity date on our credit facility by two years, a new ten-year office lease and a commitment for two drilling rigs. The new office lease begins in April 2007 with payments of $1.4 million per year for the first five years and $1.6 million for the next five years. We have entered into a contract with drilling contractors to use two rigs for up to two years with a minimum future commitment of $7.0 million in 2006, $12.8 million in 2007 and $2.2 million in 2008. Early termination of this contract at June 30, 2006 would have required us to pay maximum penalties of $16.7 million. We do not expect to pay any termination penalties related to this contract. There have been no significant changes to our off-balance sheet arrangements subsequent to December 31, 2005.

Other Contingencies

We are involved in various legal actions and claims arising in the ordinary course of business as described in Footnote 10 of the notes to consolidated financial statements. We believe the resolution of these proceedings will not have a material adverse effect on the liquidity or consolidated financial position of Range.

Hedging – Oil and Gas Prices

We enter into hedging agreements to reduce the impact of oil and gas price volatility on our operations. At June 30, 2006, swaps were in place covering 70.5 Bcf of gas at prices averaging $9.30 per mcf and 0.1 million barrels of oil at prices averaging $35.00 per barrel. We also have collars covering 82.4 Bcf of gas at weighted average floor and cap prices which range from $7.09 to $9.86 per mcf and 4.8 million barrels of oil at weighted average floor and cap prices that range from $50.70 to $63.62 per barrel. Their fair value at June 30, 2006 (the estimated amount that would be realized on termination based on contract price and a reference price, generally NYMEX) was a net unrealized pre-tax loss of $75.7 million. Gains and losses are determined monthly and are included as increases or decreases in oil and gas revenues in the period the hedged production is sold. An ineffective portion (changes in contract prices that do not match changes in the hedge price) of open hedge contracts is recognized in earnings quarterly in other revenue. As of the fourth quarter of 2005, certain of our gas hedges no longer qualify for hedge accounting and were marked-to-market in the first six months of 2006 resulting in a gain of $28.8 million.

At June 30, 2006, the following commodity derivative contracts were outstanding:


Period	Contract Type	Volume Hedged	Average Hedge Price
Natural Gas
2006	Swaps	10,761 Mmbtu/day	$6.34
2006	Collars	143,283 Mmbtu/day	$6.39 — $8.52
2007	Swaps	82,500 Mmbtu/day	$9.34
2007	Collars	98,500 Mmbtu/day	$7.13 — $9.99
2008	Swaps	105,000 Mmbtu/day	$9.42
2008	Collars	55,000 Mmbtu/day	$7.93 — $11.39

Crude Oil
2006	Swaps	400 bbl/day	$35.00
2006	Collars	6,863 bbl/day	$39.83 — $49.05
2007	Collars	5,800 bbl/day	$52.90 — $64.58
2008	Collars	4,000 bbl/day	$56.89 — $74.78

Inflation and Changes in Prices

Our revenues, the value of our assets, our ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by interest rates, changes in oil and gas prices and the costs to produce our reserves. Oil and gas prices are subject to significant fluctuations that are beyond our ability to control or predict. During the second quarter of 2006, we received an average of $66.25 per barrel of oil and $6.30 per mcf of gas before hedging compared to $48.79 per barrel of oil and $6.42 per mcf of gas in the same period of the prior year. Increases in commodity prices and the increased demand for services can cause inflationary pressures specific to the industry to increase for both services and personnel costs. We expect these costs to continue to increase during the next twelve months.

Item 3. QUANTITATIVE 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 oil and gas prices and interest rates. The disclosures are not meant to be 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 exposures. All of our market-risk sensitive instruments were entered into for purposes other than trading. All accounts are US dollar denominated.

Market Risk.Our major market risk is exposure to oil and gas price volatility. Realized prices are primarily driven by worldwide prices for oil and spot market prices for North American gas production. Oil and gas prices have been volatile and unpredictable for many years.

Commodity Price Risk.We periodically enter into hedging arrangements with respect to our oil and gas production. Hedging is intended to reduce the impact of oil and gas price fluctuations. A portion of our hedges are swaps where we receive a fixed price for our production and pay market prices to the counterparty. Our hedging program also includes collars which establish a minimum floor price and a maximum ceiling price. In times of increasing price volatility, we may experience losses from our hedging arrangements and increased basis differentials at the delivery points where we market our production. Widening basis differentials occur when the physical delivery market prices do not increase proportionately to the increased prices in the financial trading markets. Realized gains or losses are recognized in oil and gas revenue when the associated production occurs. Gains or losses on open contracts are recorded either in current period income or OCI. Generally, derivative losses occur when market prices increase, which are offset by gains on the underlying commodity transaction. Conversely, derivative gains occur when market prices decrease, which are offset by losses on the underlying commodity transaction. Ineffective gains and losses are recognized in earnings in other revenues. We do not enter into derivative instruments for trading purposes.

As of June 30, 2006, we had oil and gas swap hedges in place covering 70.5 Bcf of gas and 0.1 million barrels of oil at prices averaging $9.30 per mcf and $35.00 per barrel. We also had collars covering 82.4 Bcf of gas at weighted average floor and cap prices which range from $7.09 to $9.86 per mcf and 4.8 million barrels of oil at weighted average floor and cap prices that range from $50.70 to $63.62 per barrel. Their fair value, represented by the estimated amount that would be realized upon immediate liquidation, based on contract versus NYMEX prices, approximated a net unrealized pre-tax loss of $75.7 million at that date. These contracts expire monthly through December 2008. Gains or losses on open and closed hedging transactions are determined as the difference between the contract price received by us for the sale of our hedged production and the hedge price, generally closing prices on the NYMEX. Net realized losses relating to these derivatives for the six months ended June 30, 2006 and 2005 were $33.1 million and $43.3 million, respectively. Losses or gains due to commodity hedge ineffectiveness are recognized in earnings in other revenues in our consolidated statement of operations. The ineffective portion of hedges was a gain of $3.3 million in the six months of 2006 and a gain of $248,000 in the six months of 2005. As of the fourth quarter of 2005, certain of our gas hedges no longer qualified for hedge accounting were marked-to-market in the first six months of 2006 at a gain of $28.8 million.

In the first six months of 2006, a 10% reduction in oil and gas prices, excluding amounts fixed through hedging transactions, would have reduced revenue by $36.7 million. If oil and gas future prices at June 30, 2006 declined 10%, the unrealized hedging loss on June 30, 2006 of $76.6 million would have increased to a gain of $52.2 million.

Interest rate risk.At June 30, 2006, we had $894.7 million of debt outstanding. Of this amount, $500.0 million bore interest at fixed rates averaging 7.1%. Senior debt totaling $397.6 million bore interest at floating rates averaging 6.5%. A 1% increase or decrease in short-term interest rates would affect interest expense by approximately $4.0 million.

Item 4. CONTROLS AND PROCEDURES

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures (as defined in 13a-15(e) of the Securities Exchange Act of 1934 or the Exchange Act). Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective in timely alerting us to material information required to be included in this report. There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

PART-II-OTHER INFORMATION

Item 4. Submission of Matters to a Vote of Security Holders

On May 24, 2006, we held our annual meeting of stockholders to elect a Board of eight directors, each for a one-year term, vote on proposals to add to the business criteria defined in our 2005 Equity Based Compensation Plan to measure senior management performance, increase the number of common stock authorized to be issued under the 2005 Equity Based Compensation Plan and appoint Ernst & Young LLP as our independent auditors for 2006. At the meeting, Charles L. Blackburn, Anthony V. Dub, V. Richard Eales, Allen Finkelson, Jonathan S. Linker, Kevin S. McCarthy, John H. Pinkerton and Jeffrey L. Ventura were re-elected as Directors. Charles L. Blackburn remains the non-executive Chairman of the Board.

The following is a summary of the votes cast at the annual meeting:


	Results of Voting			Votes For		Withheld
1.	Election of Directors
	Charles L. Blackburn				121,202,301		739,221
	Anthony V. Dub				104,982,781		16,958,741
	V. Richard Eales				121,650,136		291,386
	Allen Finkelson				104,971,461		16,970,061
	Jonathan S. Linker				107,446,223		14,495,299
	Kevin S. McCarthy				121,218,683		722,838
	John H. Pinkerton				119,287,618		2,653,903
	Jeffrey L. Ventura				119,307,640		2,633,881

		Votes For		Against		Abstentions
2.	Add business criteria to 2005 Equity Plan		118,795,644		3,079,805		66,072
3.	Increase authorized shares under the Plan		57,428,222		51,018,137		87,642
4.	Appointment of Ernst & Young LLP		121,831,062		82,776		27,683

PART II. OTHER INFORMATION

Item 6. Exhibits

(a) EXHIBITS


Exhibit
Number		Description
2.1		Agreement and Plan of Merger, dated May 10, 2006, by and among Range Resources Corporation, Range Acquisition Texas, Inc. and Stroud Energy, Inc. (incorporated by reference to exhibit 2.1 to our Form 8-K/A (File No. 001-12209) as filed with the SEC on May 16, 2006)

3.1		Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on May 5, 2004 as amended by the Certificate of First 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)

3.2		Amended and Restated By-laws of Range (incorporated by reference to Exhibit 3.2 to our Form 10-K (File No. 001-12209) as filed with the SEC on March 3, 2004)

4.1		Registration Rights Agreement, dated May 10, 2006, by and among Range Resources Corporation and Stroud Energy, Inc. for the benefit of Holders defined therein (incorporated by reference to exhibit 4.1 to our Form 8-K/A (File No. 001-12209) as filed with the SEC on May 16, 2006)

10.1*		Sixth Amendment to the Second Amended and Restated Credit Agreement dated May 10, 2006 among Range and Great Lakes Energy Partners L.L.C. (as borrowers) and JPMorgan Chase Bank, N.A. (successor to merger to Bank One N.A.), a national banking association (JPMorgan Chase) and the institutions named (therein) as lenders, JPMorgan Chase as Administrative Agent

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


*		filed 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.


	RANGE RESOURCES CORPORATION
	By:	/s/ ROGER S. MANNY
		Roger S. Manny
		Senior Vice President and Chief Financial Officer (Principal Financial Officer and duly authorized to sign this report on behalf of the Registrant)

July 27, 2006

Exhibit index


Exhibit
Number		Description
2.1		Agreement and Plan of Merger, dated May 10, 2006, by and among Range Resources Corporation, Range Acquisition Texas, Inc. and Stroud Energy, Inc. (incorporated by reference to exhibit 2.1 to our Form 8-K/A (File No. 001-12209) as filed with the SEC on May 16, 2006)

3.1		Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on May 5, 2004 as amended by the Certificate of First 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)

3.2		Amended and Restated By-laws of Range (incorporated by reference to Exhibit 3.2 to our Form 10-K (File No. 001-12209) as filed with the SEC on March 3, 2004)

4.1		Registration Rights Agreement, dated May 10, 2006, by and among Range Resources Corporation and Stroud Energy, Inc. for the benefit of Holders defined therein (incorporated by reference to exhibit 4.1 to our Form 8-K/A (File No. 001-12209) as filed with the SEC on May 16, 2006)

10.1*		Sixth Amendment to the Second Amended and Restated Credit Agreement dated May 10, 2006 among Range and Great Lakes Energy Partners L.L.C. (as borrowers) and JPMorgan Chase Bank, N.A. (successor to merger to Bank One N.A.), a national banking association (JPMorgan Chase) and the institutions named (therein) as lenders, JPMorgan Chase as Administrative Agent

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


*		filed herewith

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. sophomore Good

Range Resources (RRC) 10-Q2006 Q2 Quarterly report

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