UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 8-K

CURRENT REPORT
Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934

RANGE RESOURCES CORPORATION

(Exact name of registrant as specified in its charter)

Delaware		001-12209		34-1312571
(State or other jurisdiction of incorporation)		(Commission File Number)		(IRS Employer Identification No.)
100 Throckmorton Street, Suite 1200 Ft. Worth, Texas				76102
(Address of principal executive offices)				(Zip Code)

Registrant’s telephone number, including area code: (817) 870-2601

(Former name or former address, if changed since last report): Not applicable

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligations of the registrant under any of the following provisions (see General Instruction A.2. below):

     o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

     o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

     o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

     o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

 

 

ITEM 8.01. OTHER EVENTS.

     As of March 30, 2007, we sold our interests in our Gulf of Mexico properties for proceeds of $155.0 million. We reported our operations with respect to these properties as discontinued operations in our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2007.

     This Current Report on Form 8-K was prepared to provide revised financial information that presents these properties as discontinued operations for all periods presented in our Annual Report on Form 10-K for the year ended December 31, 2006, filed on February 26, 2007 (“2006 Form 10-K”). It should be noted that our net income (loss) was not impacted by the reclassification of our operations with respect to these properties to discontinued operations.

     Please note, we have not otherwise updated our financial information or business discussion for activities or events occurring after the date this information was presented in our 2006 Form 10-K. You should read our Quarterly Report on Form 10-Q for the period ended March 31, 2007 and our Current Reports on Form 8-K and any amendments thereto, for updated information.

     This filing includes updated information for the following items included in our 2006 Form 10-K:

ITEM 6. SELECTED FINANCIAL DATA

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF            OPERATIONS

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

     Unaffected items of our 2006 Form 10-K have not been repeated in this Form 8-K.

     Cross-references that are included in the above items and that refer to information included on page numbers that are preceded by an “F” refer to the corresponding page included in this filing. Other cross-references are to pages in our 2006 Form 10-K.

ITEM 6. SELECTED FINANCIAL DATA

     The following table shows selected financial information for the five years ended December 31, 2006. Significant producing property acquisitions in 2006 and 2004 affect the comparability of year-to-year financial and operating data. All weighted average shares and per share data have been adjusted for the three-for-two stock split effected December 2, 2005. This information should be read in conjunction with Item 7 of this report “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and our consolidated financial statements and related notes included elsewhere in this report (in thousands, except per share data).

		Year Ended December 31,
		2006				2005				2004				2003				2002
Balance Sheet Data:
Current assets (a)		$	388,925			$	207,977			$	136,336			$	66,092			$	50,619
Current liabilities (b)			251,685				321,760				177,162				106,964				67,206
Oil and gas properties, net			2,608,088				1,679,593				1,340,077				658,798				474,800
Total assets			3,187,674				2,018,985				1,595,406				830,091				658,484
Bank debt			452,000				269,200				423,900				178,200				115,800
Subordinated debt			596,782				346,948				196,656				109,980				90,901
Stockholders’ equity (c)			1,256,161				696,923				566,340				274,066				206,109
Weighted average dilutive shares outstanding			138,711				129,126				97,998				86,775				81,627
Cash dividends declared per common share			0.09				.0599				.0267				.0067				—
Cash Flow Data:
Net cash provided from operating activities			479,875				325,745				209,249				124,680				114,472
Net cash used in investing activities			911,659				432,377				624,301				186,838				103,950
Net cash provided from (used in) financing activities			429,416				93,000				432,803				61,455				(12,568	)

Statement of Operations Data:

		Year Ended December 31,
		2006				2005				2004				2003				2002
Revenues
Oil and gas sales		$	649,078			$	498,376			$	278,903			$	179,074			$	148,310
Transportation and gathering			2,422				2,306				2,002				3,248				3,216
Gain (loss) on retirement of securities			—				—				(39	)			18,256				3,098
Mark-to-market on oil and gas derivatives			86,491				10,868				—				—				—
Other			6,821				(2,447	)			2,202				(1,877	)			(5,958	)
Total revenue			744,812				509,103				283,068				198,701				148,666
Costs and expenses
Direct operating			81,261				57,866				39,419				28,110				23,052
Production and ad valorem taxes			36,415				30,822				19,845				12,059				7,967
Exploration			44,088				29,529				12,619				12,530				11,233
General and administrative			49,886				33,444				20,634				17,818				16,217
Deferred compensation plan			6,873				29,474				19,176				6,559				1,023
Interest expense and dividends on trust preferred			55,849				37,619				22,437				21,507				22,451
Depletion, depreciation and amortization			154,739				114,364				80,628				62,687				57,249
Total costs and expenses			429,111				333,118				214,758				161,270				139,192
Income from continuing operations before income taxes and accounting change			315,701				175,985				68,310				37,431				9,474
Income tax provision (benefit)
Current			1,912				1,071				(245	)			170				(4	)
Deferred			119,840				64,809				25,327				14,125				(7,881	)
			121,752				65,880				25,082				14,295				(7,885	)
Income from continuing operations			193,949				110,105				43,228				23,136				17,359
Income (loss) from discontinued operations			(35,247	)			906				(997	)			7,788				8,407
Income before cumulative effect of changes in accounting principles			158,702				111,011				42,231				30,924				25,766
Cumulative effect of changes in accounting principles, net of taxes			—				—				—				4,491				—
Net income			158,702				111,011				42,231				35,415				25,766
Preferred dividends			—				—				(5,163	)			(803	)			—
Net income available to common stockholders		$	158,702			$	111,011			$	37,068			$	34,612			$	25,766
Earnings per common share:
Basic - income from continuing operations		$	1.45			$	0.89			$	0.41			$	0.27			$	0.22
- income (loss) from discontinued operations			(0.26	)			—				(0.01	)			0.10				0.10
- cumulative effect of changes in accounting principles			—				—				—				0.05				—
- Net income		$	1.19			$	0.89			$	0.40			$	0.42			$	0.32
Diluted - income from continuing operations		$	1.39			$	0.85			$	0.39			$	0.27			$	0.22
- income (loss) from discontinued operations			(0.25	)			0.01				(0.01	)			0.09				0.10
- cumulative effect of changes in accounting principles			—				—				—				0.05				—
- Net income		$	1.14			$	0.86			$	0.38			$	0.41			$	0.32

ITEM 7. 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. This section should be read in conjunction with Item 6, “Selected Financial Data” and our consolidated financial statements and the accompanying notes included elsewhere in this Form 10-K.

     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. See “Disclosures Regarding Forward-Looking Statements” at the beginning of this Annual Report and “Risk Factors” in Item 1A. for additional discussion of some of these factors and risks.

Overview of Our Business

     We are an independent natural gas and oil company 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 operate in one segment. We have a single company-wide management team that administers all properties as a whole rather than by discrete operating segments. We track only basic operational data by area. We do not maintain complete separate financial statement information by area. We measure financial performance as a single enterprise and not on an area-by-area basis.

     Our strategy is to increase reserves and production through internally generated drilling projects coupled with complementary acquisitions. Our revenues, profitability and future growth depend substantially on prevailing prices for oil and gas and on our ability to find, develop and acquire oil and gas reserves that are economically recoverable. We use the successful efforts method of accounting for our oil and gas activities.

Industry Environment

     We operate entirely within the United States, a mature region for the exploration and production of oil and gas. As a mature region, while new discoveries of oil and gas occur in the United States, the size and frequency of these discoveries is declining, while finding and development costs are increasing. We believe that there remain areas of the United States, such as the Appalachian basin and certain areas in our Southwest and Gulf Coast Divisions, which are underexplored or have not been fully explored and developed with the benefit of newly available exploration, production and reserve enhancement technology. Examples of such technology include advanced 3-D seismic processing, hydraulic reservoir fracture stimulation, advances in well logging and analysis, horizontal drilling and completion techniques, secondary and tertiary recovery practices, and automated remote well monitoring and control devices.

     Another characteristic of a mature region is the historical exit of larger independent producers and major oil companies from such regions. These companies, searching for ever larger new discoveries, have ventured increasingly overseas and offshore, de-emphasizing their onshore United States assets. This movement out of mature basins by larger companies has provided acquisition opportunities for companies like ours that maintain well-equipped technical teams capable of generating additional value from these assets. In other situations, to increase cash flow without increasing capital spending, larger independent producers and major integrated oil companies have allowed smaller companies the opportunity to explore and develop reserves on their undeveloped acreage through joint ventures and farm-in arrangements.

     We believe the acquisition market for natural gas properties has become extremely competitive as producers vie for additional production and expanded drilling opportunities. Acquisition values have reached historic highs and we expect these values to remain high in 2007. In addition, we expect drilling and service costs to remain at a high level in 2007 and for lease operating expenses to continue to rise as producers are forced to make operational enhancements to maintain aging fields.

     Natural gas is a commodity. The price that we receive for the natural gas we produce is largely a function of market supply and demand. Demand for natural gas in the United States has increased dramatically over the last ten years. Demand is impacted by general economic conditions, estimates of gas in storage, weather and other seasonal condition, including hurricanes and tropical storms. Market conditions involving over or under supply of natural gas can result in substantial price volatility. Historically, commodity prices have been volatile and we expect the volatility to continue in the future. A substantial or extended decline in oil and gas prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities of oil and gas reserves that may be economically produced and our ability to access capital markets.

Source of Our Revenues

     We derive our revenues from the sale of natural gas and oil that is produced from our properties. Revenues are a function of the volume produced and the prevailing market price at the time of sale. The price of oil and natural gas is the primary factor affecting our revenues. To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we utilize derivative instruments to hedge future sales prices on a significant portion of our natural gas and oil production. During 2006, 2005 and 2004 the use of derivative instruments prevented us from realizing the full benefit of upward price movements and may continue to do so in future periods. Discontinued operations includes our Gulf of Mexico properties which were sold in March 2007 and our Austin Chalk properties which were presented as Assets Held for Sale at December 31, 2006 and were sold in February 2007. Unless otherwise indicated, the information included herein relates to our continuing operations.

Principal Components of Our Cost Structure

	•		Direct Operating Expenses. These are day-to-day costs incurred to bring hydrocarbons out of the ground and to the market together with the daily costs incurred to maintain our producing properties. Such costs also include workovers and repairs to our oil and gas properties not covered by insurance. These costs are expected to remain high in 2007 as the demand for these services continues to increase. Direct operating expenses includes stock-based compensation expense (non-cash) associated with the adoption of SFAS123(R), amortization of restricted stock grants and mark-to-market of SARs as part of employee compensation.
	•		Production and Ad Valorem Taxes. These costs are primarily paid based on a percentage of market prices and not on hedged prices of production or at fixed rates established by federal, state or local taxing authorities.
	•		Exploration Expense. Geological and geophysical costs, seismic costs, delay rentals and the costs of unsuccessful exploratory wells or dry holes. Exploration expense includes stock-based compensation expense (non-cash) associated with the adoption of SFAS123(R), amortization of restricted stock grants and mark-to-market of SARs as part of employee compensation.
	•		General and Administrative Expense. Overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, audit and other professional fees and legal compliance are included in general and administrative expense. General and administrative expense includes stock-based compensation expense (non-cash) associated with the adoption of SFAS123(R), amortization of restricted stock grants and mark-to-market of SARs as part of employee compensation.
	•		Interest. We typically finance a portion of our working capital requirements and acquisitions with borrowings under our bank credit facility and with our longer term public traded debt securities. As a result, we incur substantial interest expense that is affected by both fluctuations in interest rates and our financing decisions. We may continue to incur significant interest expense as we continue to grow. We expect our 2007 capital budget to be funded with internal cash flow and asset sales.
	•		Depreciation, Depletion and Amortization. The systematic expensing of the capital costs incurred to acquire, explore and develop natural gas and oil. As a successful efforts company, we capitalize all costs associated with our acquisition and development efforts and all successful exploration efforts, and apportion these costs to each unit of production through depreciation, depletion and amortization expense. This also includes the systematic, monthly accretion of the future abandonment costs of tangible assets such as platforms, wells, service assets, pipelines, and other facilities.
	•		Income Taxes. We are subject to state and federal income taxes but are currently not in a tax paying position for regular federal income taxes, primarily due to the current deductibility of intangible drilling costs (“IDC”). We do pay some state income taxes where our IDC deductions do not exceed our taxable income or where state income taxes are determined on another basis. Currently, all of our federal taxes are deferred; however, at some point, we will utilize all of our net operating loss carryforwards and we will recognize current income tax expense and continue to recognize current tax expense as long as we are generating taxable income.

Management’s Discussion and Analysis of Income and Operations

Volumes and Price Data

		2006				2005				2004
Production:
Crude oil (bbls)			3,039,150				2,929,013				2,385,375
NGLs (bbls)			1,091,785				1,011,692				988,192
Natural gas (mcf)			70,712,770				57,608,816				43,051,485
Total (mcfe) (a)			95,498,380				81,253,046				63,292,887
Average daily production:
Crude oil (bbls)			8,326				8,025				6,517
NGLs (bbls)			2,991				2,772				2,700
Natural gas (mcf)			193,734				157,832				117,627
Total (mcfe) (a)			261,639				222,611				172,931
Average sales prices (excluding hedging):
Crude oil (per bbl)		$	62.36			$	53.30			$	39.20
NGLs (per bbl)			33.62				31.52				23.73
Natural gas (per mcf)			6.59				8.00				5.80
Total (per mcfe) (a)			7.25				7.99				5.79
Average sales prices (including hedging):
Crude oil (per bbl)		$	47.46			$	38.63			$	27.98
NGLs (per bbl)			33.62				27.27				19.76
Natural gas (per mcf)			6.62				6.21				4.47
Total (per mcfe) (a)			6.80				6.13				4.41
Average NYMEX prices (b)
Oil (per bbl)		$	66.22			$	56.56			$	41.42
Natural gas (per mcf)			7.26				8.55				6.09

Overview of 2006 Results

     During 2006, we achieved the following results:

	•		15% production growth and 25% reserve growth (including Gulf of Mexico);
	•		Drilled over 700 net wells (including Gulf of Mexico);
	•		Continued expansion of drilling inventory and emerging plays;
	•		Record financial results and continued balance sheet improvement; and
	•		Completed an acquisition of properties containing 171 Bcfe of proved reserves, of which 49 Bcfe were held for sale at December 31, 2006 and included in discontinued operations.

     Our 2006 performance reflects another year of successfully executing our strategy of growth through drilling and complementary acquisitions. The business of exploring for, developing, and acquiring oil and gas is highly competitive and capital intensive. As in any commodity business, the costs associated with finding, acquiring, extracting, and financing the operation are critical to profitability and long-term value creation for stockholders. Generating meaningful growth while containing costs represents an ongoing challenge for management. During periods of historically high oil and gas prices, such as 2005 and 2006, drilling service and operating cost increases are more prevalent due to increased competition for goods and services. We faced other challenges in 2006 including attracting and retaining qualified personnel, consummating and integrating acquisitions, and accessing the capital markets to fund our growth and capital simplification process on sufficiently favorable terms. We have continued to expand and improve the technical staff through the hiring of additional experienced professionals. Our inventory of exploration and development prospects continues to build, providing new growth opportunities, greater diversification of technical risk and better efficiency.

     Total revenues increased 46% in 2006 over the same period of 2005. This increase is due to higher production and realized oil and gas prices. Our 2006 production growth is due to acquisitions completed in 2006 and to the continued success of our drilling program. Realized prices were higher by 11% in 2006 reflecting the expiration of lower priced oil and gas hedges. As discussed in Item 1A of this report, significant changes in oil and gas prices can have a significant impact on our balance sheet and our results of operations, particularly on the fair value of our derivatives.

Comparison of 2006 to 2005

     Oil and gas revenue for the years ended December 31, 2006 and 2005 (in thousands) is summarized in the following table:

		2006				2005				Change				%
Revenues:
Oil wellhead		$	189,516			$	156,102			$	33,414				21	%
Oil hedges			(45,265	)			(42,948	)			(2,317	)			5	%
Total oil revenue		$	144,251			$	113,154			$	31,097				28	%
Gas wellhead		$	466,099			$	461,132			$	4,967				1	%
Gas hedges			2,023				(103,498	)			105,521				102	%
Total gas revenue		$	468,122			$	357,634			$	110,488				31	%
NGL		$	36,705			$	31,890			$	4,815				15	%
NGL hedges			—				(4,302	)			4,302				100	%
Total NGL revenue		$	36,705			$	27,588			$	9,117				33	%
Combined wellhead		$	692,320			$	649,124			$	43,196				7	%
Combined hedges			(43,242	)			(150,748	)			107,506				71	%
Total oil and gas revenue		$	649,078			$	498,376			$	150,702				30	%

     Average realized price received for oil and gas during 2006 was $6.80 per mcfe, up 11% or $0.67 per mcfe from 2005. Oil and gas revenues for 2006 reached a record $649.1 million and were 30% higher than 2005 due to higher realized oil and gas prices and an 18% increase in production. The average price received increased 23% to $47.46 per barrel for oil and increased 7% to $6.62 per mcf for gas from 2005. The effect of our hedging program decreased realized prices $0.45 per mcfe in 2006 versus a decrease of $1.86 in 2005.

     Production volumes increased 18% from 2005 due to continued drilling success and additions from acquisitions consummated in 2006. Production increased 14.2 Bcfe from 2005. Our production volumes increased 10% in our Appalachia Division, increased 29% in our Southwest Division and declined 36% in our Gulf Coast Division.

     Mark-to-market on oil and gas derivatives includes a gain of $86.5 million in 2006. In the fourth quarter of 2005, certain of our gas hedges no longer qualified for hedge accounting due to the effect of gas price volatility on the correlation between realized prices and hedge reference prices.

     Other revenue increased in 2006 to a gain of $6.8 million from a loss of $2.4 million in 2005. The 2006 period includes $6.0 million of ineffective hedging gains and income from equity method investments of $548,000. The 2005 period includes ineffective hedging losses of $3.4 million.

     Our operating expenses have increased as we continue to grow. We believe most of our operating expense fluctuations should be analyzed on a unit-of-production, or per mcfe basis. The following table presents information about our operating expenses on an mcfe basis for 2006 and 2005:

Operating expenses per mcfe		2006				2005				Change				%
Direct operating expense (excluding $0.01 per mcfe stock-based compensation in 2006 and 2005)		$	0.84			$	0.71			$	0.13				18	%
Production and ad valorem tax expense			0.38				0.38				—				—
General and administrative expense (excluding stock-based compensation of $0.15 per mcfe in 2006 and $0.06 per mcfe in 2005)			0.37				0.35				0.02				6	%
Interest expense			0.58				0.46				0.12				26	%
Depletion, depreciation and amortization expense			1.62				1.41				0.21				15	%

     Direct operating expense (excluding stock-based compensation) increased $22.5 million to $79.9 million due to higher oilfield service costs, higher volumes and the integration of our recent acquisitions. Our operating expenses are increasing as we add new wells and maintain production from our existing properties. We incurred $3.5 million of expenses associated with workovers in 2006 versus $2.5 million in 2005. On a per mcfe basis, direct operating expenses (excluding stock-based compensation) were $0.84 per mcfe and increased $0.13 per mcfe from 2005 with the increase consisting primarily of higher utilities ($0.02 per mcfe) and higher water disposal and equipment costs ($0.06 per mcfe).

     Production and ad valorem taxes are paid based on market prices and not hedged prices. These taxes increased $5.6 million, or 18%, from the same period of the prior year. On a per mcfe basis, production and ad valorem taxes remained the same when compared to 2005.

     General and administrative expense (excluding stock-based compensation) for 2006 increased 25%, or $7.0 million, due to higher salaries and benefits ($6.0 million) and higher office rent and general office expense ($1.0 million). On a per mcfe basis, general and administration expense (excluding stock-based compensation) increased from $0.35 per mcfe in 2005 to $0.37 per mcfe in 2006.

     Interest expense for 2006 increased $18.2 million, or 48%, to $55.8 million with higher average interest rates, higher average debt balances and the refinancing of certain debt from short-term floating to longer-term fixed rates. In 2006, we issued $250.0 million of 7.5% senior subordinated notes which added $9.7 million of interest costs. The proceeds from this issuance were used to retire shorter term bank debt. In 2006, the average debt outstanding on the bank credit facility was $347.8 million with an average interest rate of 6.4% compared to an average debt outstanding in 2005 of $314.8 million with an average interest rates of 4.5%. The 2006 period includes $3.2 million of interest expense allocated to discontinued operations versus $1.2 million in 2005.

     Depletion, depreciation and amortization, (“DD&A”), increased $40.4 million, or 35%, due to higher production and higher depletion rates. DD&A increased from $1.41 per mcfe in 2005 to $1.62 per mcfe in 2006. In the fourth quarter of 2006, we lowered our salvage value estimates on our Appalachia wells which increased DD&A expense by $4.6 million. For 2007, based on our current reserve base, we expect our DD&A rate to average approximately $1.85 per mcfe. The increase in DD&A per mcfe is related to our Stroud acquisition, increasing drilling costs and the mix of our production.

     Operating expenses also include other expenses that generally do not trend with production. These expenses include stock-based compensation, exploration expense and deferred compensation plan expense. In 2006, stock-based compensation is a component of direct operating expense ($1.4 million), exploration expense ($3.1 million), general and administrative expense ($14.3 million) and a $320,000 reduction of gas transportation revenues for a total of $19.1 million. In 2005, stock-based compensation is equal to $480,000 included in direct operating, $1.2 million included in exploration expense, $4.9 million included in general and administrative expense and a reduction of $117,000 of gas transportation revenues for a total of $6.7 million. This expense represents the amortization of restricted stock grants in 2006 and 2005, expenses related to the adoption of SFAS No. 123(R) in 2006 and in 2005, the mark-to-market of SARs granted to employees. The increase in stock-based compensation in 2006 is the result of adopting SFAS No. 123(R) which requires expensing of stock options.

     Exploration expense increased 49% to $44.1 million due to higher seismic costs ($2.0 million), higher dry hole costs ($8.5 million) and higher personnel costs. The following table details our exploration-related expenses (in thousands):

Exploration expenses		2006				2005				Change				%
Dry hole expense		$	15,084			$	6,560			$	8,524				130	%
Seismic			15,277				13,292				1,985				15	%
Personnel expense			6,917				5,872				1,045				18	%
Stock-based compensation expense			3,079				1,250				1,829				146	%
Other			3,731				2,555				1,176				46	%
Total exploration expense		$	44,088			$	29,529			$	14,559				49	%

     Deferred compensation plan expense decreased 77%, or $22.6 million from 2005. This non-cash expense relates to the increase or decrease in value of our common stock and other investments held in our deferred compensation plans. Our common stock price increased from $13.64 per share at the end of 2004 to $26.34 per share at the end of 2005 to $27.46 per share at the end of 2006.

     Income tax expense for 2006 increased $55.9 million, or 85%, over 2005 due to a 79% increase in income from continuing operations before taxes. Our effective tax rate was 39% for 2006 and was 37% for 2005. The twelve months ended December 31, 2006 includes a $2.8 million adjustment for changes in state tax rates. Given our available net operating loss carryforward, we do not expect to pay significant federal income taxes. We paid $1.8 million of state income taxes in 2006.

     Discontinued operations includes the operating results and impairment losses on the Austin Chalk properties which were acquired as part of our Stroud transaction. See also Note 4 to our consolidated financial statements. Due to significant price declines subsequent to the purchase of these properties and volumes produced since the acquisition, we recognized impairment charges of $74.9 million. These properties were sold on February 13, 2007 for proceeds of $80.4 million. Discontinued operations also includes the operations results of our Gulf of Mexico properties which were sold in March 2007 for proceeds of $155.0 million.

Comparison of 2005 to 2004

     Oil and gas revenue for the years ended December 31, 2005 and 2004 (in thousands) is summarized in the following table:

		2005				2004				Change				%
Revenues
Oil wellhead		$	156,102			$	93,513			$	62,589				67	%
Oil hedges			(42,948	)			(26,782	)			(16,166	)			60	%
Total oil revenue		$	113,154			$	66,731			$	46,423				70	%
Gas wellhead		$	461,132			$	249,557			$	211,575				85	%
Gas hedges			(103,498	)			(56,910	)			(46,588	)			82	%
Total gas revenue		$	357,634			$	192,647			$	164,987				86	%
NGL		$	31,890			$	23,445			$	8,445				36	%
NGL hedges			(4,302	)			(3,920	)			(382	)			10	%
Total NGL revenue		$	27,588			$	19,525			$	8,063				41	%
Combined wellhead		$	649,124			$	366,515			$	282,609				77	%
Combined hedges			(150,748	)			(87,612	)			(63,136	)			72	%
Total oil and gas revenue		$	498,376			$	278,903			$	219,473				79	%

     Average realized price received for oil and gas during 2005 was $6.13 per mcfe, up 39% or $1.72 per mcfe from 2004. Oil and gas revenues for 2005 reached a record $498.4 million and were 79% higher than 2004 due to higher oil and gas prices and a 28% increase in production. The average price received in 2005 increased 38% to $38.63 per barrel for oil and increased 39% to $6.21 per mcf for gas. The effect of our hedging program decreased realized prices $1.86 per mcfe in 2005 versus a decrease of $1.38 in 2004.

     Production volumes increased 28% from 2004 due to our drilling program and additions from acquisitions consummated in 2004, primarily our purchase of the 50% of Great Lakes that we did not own and Pine Mountain. Production increased 18.0 Bcfe from 2004. Our production volumes increased 69% in our Appalachia Division, increased 14% in our Southwest Division and declined 22% in our Gulf Coast Division.

     Transportation and gathering revenue of $2.3 million increased $304,000 from 2004. This increase is primarily due to higher gas prices and additional throughput volumes offset by lower oil marketing revenue.

     Mark-to-market on oil and gas derivatives includes a gain of $10.9 million in 2005. In the fourth quarter of 2005, certain of our gas hedges no longer qualify for hedge accounting due to the effect of volatility of gas prices on the correlation between realized prices and hedge reference prices.

     Other revenue declined in 2005 to a loss of $2.4 million from a gain of $2.2 million in 2004. The 2005 period includes ineffective hedging losses due to widening basis differentials of $3.4 million. The 2004 period includes a gain on the sale of properties of $5.0 million and $712,000 of ineffective hedging gains offset by $2.0 million write-down of an insurance claim receivable.

     The following table presents information about our operating expenses that generally trend with changes in production for 2005 and 2004:

Operating expenses per mcfe		2005				2004				Change				%
Direct operating expense (excluding $0.01 per mcfe stock-based compensation in 2005)		$	0.71			$	0.62			$	0.09				15	%
Production and ad valorem tax expense			0.38				0.31				0.07				23	%
General and administration expense (excluding stock-based compensation of $0.06 per mcfe in 2005)			0.35				0.32				0.03				9	%
Interest expense			0.46				0.35				0.11				31	%
Depletion, depreciation and amortization expense			1.41				1.27				0.14				11	%

     Direct operating expense (excluding stock-based compensation) increased $18.0 million to $57.4 million due to increased costs from acquisitions, higher oilfield service costs and higher workover costs primarily in our Gulf Coast Division. Our operating expenses are increasing as we add new wells and maintain production from our existing properties. We incurred $2.5 million of expenses associated with workovers in 2005 versus $1.2 million in 2004. On a per mcfe basis, direct operating expenses (excluding stock-based compensation) were $0.71 per mcfe and increased 15% or $0.09 per mcfe from 2004 consisting primarily of higher field level costs ($0.04 per mcfe).

     Production and ad valorem taxes are paid based on market prices and not hedged prices. These taxes increased $11.0 million, or 55%, from the same period of the prior year. On a per mcfe basis, production and ad valorem taxes increased from $0.31 per mcfe to $0.38 per mcfe due to higher market prices.

     General and administrative expense (excluding stock-based compensation) for 2005 increased 42%, or $8.5 million, from 2004 with additional personnel costs due to the Great Lakes and Pine Mountain acquisitions ($1.8 million), higher salaries and benefits ($3.5 million), higher legal expenses ($1.3 million) and a $725,000 legal settlement accrual. On a per mcfe basis, general and administration expense (excluding stock-based compensation) increased 9% from $0.32 per mcfe in 2004 to $0.35 per mcfe in 2005.

     Interest expense for 2005 increased $15.2 million, or 68%, to $37.6 million with higher average interest rates, higher average debt balances and the refinancing of certain debt from short-term floating to longer-term fixed rates. In March 2005, we issued $150.0 million of 6.375% senior subordinated notes which added $7.8 million of interest costs. The proceeds from this issuance were used to retire lower interest bank debt. Average debt outstanding on the bank credit facility was $314.8 million and $296.6 million for 2005 and 2004, respectively, and the average interest rates were 4.3% and 3.5%, respectively. The 2005 period includes $1.2 million of interest expense allocated to discontinued operations versus $700,000 in 2004.

     Depletion, depreciation and amortization (“DD&A”) increased $33.7 million, or 42%, due to higher production and higher depletion rates. DD&A increased from $1.27 per mcfe in 2004 to $1.41 per mcfe in 2005.

     Operating expenses also include stock-based compensation, exploration expense and non-cash compensation expense that generally do not trend with production. In 2005, stock-based compensation expense is a component of direct operating expense ($480,000), exploration expense ($1.2 million) and general and administrative expense ($4.9 million). This expense represents the amortization of restricted stock grants and the market-to-market of SARs granted to employees. In 2004, stock-based compensation is a component of exploration expense ($24,000) and general and administrative expense ($541,000).

     Exploration expense increased 134% to $29.5 million due to higher seismic costs ($10.1 million), higher personnel costs, higher stock-based compensation expense ($1.2 million) and higher dry hole costs ($2.9 million).

Exploration expenses		2005				2004				Change				%
Dry hole expense		$	6,560			$	3,703			$	2,857				77	%
Seismic			13,292				3,155				10,137				321	%
Personnel expense			5,872				4,427				1,445				33	%
Stock-based compensation expense			1,250				24				1,226				5,108	%
Other			2,555				1,310				1,245				95	%
Total exploration expense		$	29,529			$	12,619			$	16,910				134	%

     Deferred compensation plan expense increased 54%, or $10.3 million, from 2004. This non-cash expense relates to the increase in value of our common stock and other investments held in our deferred compensation plans. Our common stock price increased from $13.64 per share at the end of 2004 to $26.34 per share at the end of 2005.

     Tax expense for 2005 increased $40.8 million, or 163%, over 2004 due to a 158% increase in income from continuing operations before taxes. Our effective tax rate for 2005 and 2004 was 37%. Given our available net operating loss carryforward, we do not expect to pay significant federal income taxes.

Management’s Discussion and Analysis of Financial Condition, Cash Flows and Liquidity

     During 2006, our cash provided from continuing operations was $442.4 million, and we spent $888.8 million on capital expenditures (including acquisitions). During this period, financing activities provided net cash of $429.4 million. Our financing activities included the sale of $250.0 million of 7.5% senior subordinated notes and additional borrowings under our bank credit agreement. At December 31, 2006 we had $2.4 million in cash, total assets of $3.2 billion and a debt-to-capitalization ratio of 45.5%. Long-term debt at December 31, 2006 totaled $1.0 billion, including $452.0 million of bank debt and $596.8 million of senior subordinated notes. Available borrowing capacity under the bank credit facility at December 31, 2006 was $348.0 million.

     Cash is required to fund capital expenditures necessary to offset inherent declines in production and reserves which is typical in the oil and 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 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 proved reserves.

Bank Debt

     We maintain an $800.0 million revolving credit facility, which we refer to as our bank debt or our bank credit facility. The bank credit facility is secured by substantially all of our assets and matures on October 25, 2011. Availability under the bank credit facility is subject to a borrowing base set by the banks semi-annually with an option to set more often in certain circumstances. The borrowing base is dependent on a number of factors, primarily the lenders’ assessment of future cash flows. Redeterminations of the borrowing base require approval of 75% of the lenders; increases require unanimous approval. At February 22, 2007, the bank credit facility had a $1.2 billion borrowing base and an $800.0 million facility amount. Credit availability is equal to the lesser of the facility amount or the borrowing base resulting in credit availability of $287.0 million on February 20, 2007. The facility amount can be increased to the borrowing base with twenty days notice.

     Limitations on the payment of dividends and other restricted payments as defined are imposed under our bank debt and our subordinated notes. Under the bank credit facility, common and preferred dividends are permitted. The terms of each of our subordinated 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 issuances of the notes. At December 31, 2006, approximately $496.2 million was available under the restricted payment baskets for each of our subordinated notes. The bank credit facility provides for a restricted payment basket of $20.0 million plus 66-2/3% of net cash proceeds from common stock issuances and 50% of net income. Approximately $446.4 million was available under the bank credit facility restricted payment basket as of December 31, 2006. The debt agreements contain customary covenants relating to debt incurrence, working capital, dividends and financial ratios. We were in compliance with all covenants at December 31, 2006.

Cash Flow

     Our principal sources of cash are operating cash flow, bank borrowings and at times, issuance of debt and equity securities. Our operating cash flow is highly dependent on oil and gas prices. As of December 31, 2006, we had entered into hedging agreements covering 84.9 Bcfe and 71.7 Bcfe for 2007 and 2008. The $528.7 million of cash capital expenditures for 2006, excluding acquisitions, was funded with internal cash flow and borrowing under the bank credit facility. The $698.0 million capital budget for 2007, which excludes acquisitions, is expected to increase production and to expand the reserve base. Based on current projections, oil and gas futures prices and our hedge position, the 2007 capital program is expected to be funded with internal cash flow and asset sales.

     Net cash provided from continuing operations in 2006 was $442.4 million, compared with $288.6 million in 2005 and $167.0 million in 2004. In 2006, cash flow from continuing operations increased due to higher production volumes and higher realized prices partially offset by increasing operating costs. In 2005, cash flow from operations increased due to

higher production volumes and prices partially offset by increasing operating, exploration and interest expenses. In 2004, cash flow from operations increased due to higher volumes and prices partially offset by increasing operating costs.

     Net cash used in investing activities in 2006 was $911.7 million, compared with $432.4 million in 2005 and $624.3 million in 2004. In 2006, we spent $493.2 million in additions to oil and gas properties and $360.1 million on acquisitions. The 2005 period included $266.4 million in additions to oil and gas properties and $153.6 million of acquisitions. The 2004 period included $154.6 million in additions to oil and gas properties and $485.6 million of acquisitions.

     Net cash provided from financing activities in 2006 was $429.4 million compared with $93.0 million in 2005 and $432.8 million in 2004. Historically, sources of financing have been primarily bank borrowings and capital raised through equity and debt offerings. During 2006, we received proceeds of $249.5 million from the issuance of our 7.5% Notes. During 2005, we received proceeds of $150.0 million and $109.2 million from the issuance of our 6.375% Notes and a common stock offering. During 2005, the outstanding balance under our bank credit facility declined $154.7 million primarily due to the proceeds received from the 6.375% Notes being applied to our bank debt. During 2004, we received proceeds of $98.1 million and $246.1 million from the issuance of additional 7.375% Notes and two common stock offerings, respectively. During 2004, the outstanding balance under our bank credit facility increased $245.7 million with $70.0 million related to the Great Lakes acquisition and the remaining increase the result of funding other acquisitions. Also in 2004, we redeemed the remaining outstanding 6% Debentures for $11.6 million.

Capital Requirements

     Our primary needs for cash are for exploration, development and acquisition of oil and gas properties, repayment of principal and interest on outstanding debt and payment of dividends. During 2006, $493.2 million of capital was expended on drilling projects. Also in 2006, $360.1 million was expended on acquisitions primarily to purchase producing properties. The capital program, excluding acquisitions, was funded by net cash flow from operations and borrowings under our credit facility and our acquisitions were funded primarily with proceeds received from the issuance of our 7.5% Notes and borrowings under our credit facility. The 2007 capital budget of $698.0 million, excluding acquisitions, is expected to be funded by cash flow from operations and asset sales. In February 2007, we sold the Austin Chalk properties for proceeds of $80.4 million. Development and exploration activities are highly discretionary, and, for the foreseeable future, we expect such activities to be maintained at levels equal to internal cash flow and asset sales. To the extent capital requirements exceed internal cash flow and proceeds from asset sales, debt or equity may be issued to fund these requirements. The Stroud acquisition included the issuance of 6.5 million shares and the assumption of $106.7 million of debt. We currently believe we have sufficient liquidity and cash flow to meet our obligations for the next twelve months; however, a drop in oil and gas prices or a reduction in production or reserves could adversely affect our ability to fund capital expenditures and meet our financial obligations. 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.

Cash Dividend Payments

     The amount of future dividends is subject to declaration by the board of directors and depends on earnings, capital expenditures and various other factors, such as restrictions under our bank debt and our subordinated notes. In 2006, we paid $12.2 million in dividends to our common shareholders ($0.03 per share in the fourth quarter and $0.02 per share in the third, second and first quarters). In 2005, we paid $7.6 million in dividends to our common stockholders ($0.02 per share in the fourth quarter and $0.0133 per share in the third, second and first quarters). In 2004, we paid $3.2 million in dividends to our common stockholders ($0.0067 per share in the second and third quarters and $0.0133 per share in the fourth quarter). Also in 2005 and 2004, we paid $2.2 million and $2.9 million in preferred stock dividends.

Future Commitments

     In addition to our capital expenditure program, we are committed to making cash payments in the future on two types of contracts: note agreements and operating leases. As of December 31, 2006, we do not have any capital leases nor have we entered into any material long-term contracts for equipment. As of December 31, 2006, we do not have any off-balance sheet debt or other such unrecorded obligations and we have not guaranteed the debt of any other party. The table below provides estimates of the timing of future payments that we are obligated to make based on agreements in place at December 31, 2006. In addition to the contractual obligations listed on the table below, our balance sheet at December 31, 2006 reflects accrued interest payable on our bank debt of $925,000 which is payable in January 2007. We expect to make annual interest payments of $14.8 million per year on our 7.375% Notes, $18.8 million per year on our 7.5% Notes and payments of $9.6 million per year on our 6.375% Notes.

     The following summarizes our contractual financial obligations at December 31, 2006 and their future maturities. We expect to fund these contractual obligations with cash generated from operating activities, borrowings under the bank credit facility and proceeds from asset sales proceeds.

		Payment due by period
						2008 and				2010 and
		2007				2009				2011				Thereafter				Total
		(in thousands)
Bank debt due 2011		$	—			$	—			$	452,000	(a)		$	—			$	452,000
7.375% senior subordinated notes due 2013			—				—				—				200,000				200,000
6.375% senior subordinated notes due 2015			—				—				—				150,000				150,000
7.5% senior subordinated notes due 2016			—				—				—				250,000				250,000
Operating leases			5,010				10,236				6,431				9,610				31,287
Drilling contracts			12,830				2,160				—				—				14,990
Service contracts			1,794				3,705				2,754				—				8,253
Derivative obligations (b)			4,621				266				—				—				4,887
Asset retirement obligation liability			4,216				8,651				8,423				74,298				95,588
Total contractual obligations (c)		$	28,471			$	25,018			$	469,608			$	683,908			$	1,207,005

Hedging — Oil and Gas Prices

     We enter into derivative agreements to reduce the impact of oil and gas price volatility on our operations. At December 31, 2006, swaps were in place covering 73.6 Bcf of gas at prices averaging $9.29 per mcf. We also had collars covering 56.1 Bcf of gas at weighted average floor and cap prices of $7.42 to $10.49 and 4.5 million barrels of oil at weighted average floor and cap prices of $55.72 to $70.11. The derivative 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 $149.8 million at December 31, 2006. The contracts expire monthly through December 2008. Transaction gains and losses are determined monthly and are included as increases or decreases on oil and gas revenue in the period the hedged production is sold. Realized hedging losses of $46.5 million were recognized in 2006 compared to losses of $171.1 million in 2005 and losses of $100.1 million in 2004. Changes in the value of the ineffective portion of all open hedges are recognized in earnings quarterly in other revenue. Unrealized effective gains and losses on hedging positions are recorded at an estimate of fair value based on a comparison of the contract price and a reference price, generally NYMEX, on our consolidated balance sheet as other comprehensive income (“OCI”) a component of stockholders’ equity. As of the fourth quarter of 2005, certain of our gas hedges no longer qualify for hedge accounting due to the effect of volatility of gas prices in the fourth quarter of 2005 and on the correlation between realized prices and hedge reference prices. These derivatives were marked-to-market in the amount of a gain of $10.9 million in the fourth quarter of 2005 and as a gain of $86.5 million in the year December 31, 2006.

     At December 31, 2006, the following commodity derivative contracts were outstanding:

Period		Contract Type				Volume Hedged				Average Hedge Price
Natural Gas
2007		Swaps				96,336 Mmbtu/day				$	9.13
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
2007		Collars				6,300 bbl/day				$	53.46 - $65.33
2008		Collars				6,000 bbl/day				$	58.09 - $75.11

Interest Rates

     At December 31, 2006, we had $1.0 billion of debt outstanding. Of this amount, $600.0 million bears interest at fixed rates averaging 7.2%. Bank debt totaling $452.0 million bears interest at floating rates, which averaged 6.4% at year-end 2006. The 30-day LIBOR rate on December 31, 2006 was 5.3%. A 1% increase in short-term interest rates on the floating-rate debt outstanding at December 31, 2006 would cost us approximately $4.5 million in additional annual interest.

Off-Balance Sheet Arrangements

     We do not currently utilize any off-balance sheet arrangements to enhance liquidity and capital resource position, or for any other purpose.

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 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. Although certain of our costs and expenses are affected by general inflation, inflation does not normally have a significant effect on our business. In a trend that began in 2004 and accelerated during 2005 and 2006, commodity prices for oil and gas increased significantly. The higher prices have led to increased activity in the industry and, consequently, rising costs. These costs trends have put pressure not only on our operating costs but also on our capital costs. We expect further increases in these costs for 2007.

     The following table indicates the average oil and gas prices received over the last five years and quarterly for 2006, 2005 and 2004. Average price calculations exclude hedging gains and losses. Oil is converted to natural gas equivalent at the rate of one barrel equals six mcfe.

		Average Prices (Excluding Hedging)												Average NYMEX Prices (a)
										Equivalent
		Oil				Natural Gas				Mcf				Oil				Natural Gas
		(Per bbl)				(Per mcf)				(Per mcfe)				(Per bbl)				(Per mcf)
Annual
2006		$	62.36			$	6.59			$	7.25			$	66.22			$	7.26
2005			53.30				8.00				7.99				56.56				8.55
2004			39.20				5.80				5.79				41.42				6.09
2003			28.23				5.03				4.85				31.04				5.44
2002			23.16				3.02				3.16				26.08				3.25
Quarterly
2006
First		$	59.74			$	8.33			$	8.41			$	63.48			$	9.07
Second			65.36				6.28				7.17				70.70				6.82
Third			64.53				6.12				7.00				70.48				6.53
Fourth			59.80				5.91				6.58				60.21				6.62
2005
First		$	47.01			$	5.98			$	6.25			$	49.84			$	6.32
Second			48.72				6.41				6.65				53.17				6.80
Third			59.94				7.88				8.16				63.19				8.25
Fourth			56.38				11.30				10.54				60.02				12.85
2004
First		$	31.95			$	5.20			$	5.06			$	35.15			$	5.69
Second			35.76				5.51				5.43				38.32				5.97
Third			41.01				5.60				5.72				43.88				5.84
Fourth			45.76				6.66				6.71				48.23				6.87

Management’s Discussion of Critical Accounting Estimates

     Our discussion and analysis of our financial condition and results of operations are based upon consolidated financial statements which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at year-end and the reported amounts of revenues and expenses during the year. We base our estimates on historical experience and various other assumptions that we believe are reasonable; however, actual results may differ.

     Certain accounting estimates are considered to be critical if (a) the nature of the estimates and assumptions is material due to the level of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to changes; and (b) the impact of the estimates and assumptions on financial condition or operating performance is material.

Oil and Gas Properties

     Proved reserves are defined by the SEC as those volumes of crude oil, condensate, natural gas liquids and natural gas that geological and engineering data demonstrate with reasonable certainty are recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are volumes expected to be recovered through existing wells with existing equipment and operating methods. Although our engineers are knowledgeable of and follow the guidelines for reserves established by the SEC, the estimation of reserves requires engineers to make a significant number of assumptions based on professional judgment. Reserve estimates are updated at least annually and consider recent production levels and other technical information. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information, including: reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price and cost changes and other economic factors. Changes in oil and gas prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserve quantities. Reserve revisions in turn cause adjustments in the depletion rates utilized by us. We cannot predict what reserve revisions may be required in future periods. Reserve estimates are reviewed and approved by our Vice President of Reservoir Engineering who reports directly to our Chief Operating Officer. To further ensure the reliability of our reserve estimates, we engage independent petroleum consultants to review our estimates of proved reserves. Historical variances between our reserve estimates and the aggregate estimates of our consultants have been less than 5%.

     The following table sets forth a summary of the percent of reserves which were reviewed by independent petroleum consultants for each of the years ended 2006, 2005 and 2004.

		Audited (a)
		2006				2005				2004
			87	%			84	%			88	%

     We utilize the successful efforts method to account for exploration and development expenditures. Unsuccessful exploration drilling costs are expensed and can have a significant effect on reported operating results. Successful exploration drilling costs and all development costs are capitalized and systematically charged to expense using the units of production method based on proved developed oil and gas reserves as estimated by our engineers and reviewed by independent engineers. Costs incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized on our balance sheet if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) we are making sufficient progress assessing the reserves and the economic and operating viability of the project. Otherwise, well costs are expensed if a determination as to whether proved reserves were found cannot be made within one year following completion of drilling and these criteria are not met. Proven property leasehold costs are charged to expense using the units of production method based on total proved reserves. Unproved properties are assessed periodically (at least annually) and impairments to value are charged to expense. The successful efforts method inherently relies upon the estimation of proved reserves, which includes proved developed and proved undeveloped volumes.

     We adhere to the Statement of Financial Accounting Standards No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies,” for recognizing any impairment of capitalized costs to unproved properties. The greatest portion of these costs generally relate to the acquisition of leasehold costs. The costs are capitalized and periodically evaluated (at least annually) as to recoverability, based on changes brought about by economic factors and potential shifts in business strategy employed by management. We consider a combination of time, geologic and engineering factors to

evaluate the need for impairment of these costs. Unproved properties had a net book value of $226.3 million in 2006 compared to $28.6 million in 2005 and $14.8 million in 2004.

     Depletion rates are determined based on reserve quantity estimates and the capitalized costs of producing properties. As the estimated reserves are adjusted, the depletion expense for a property will change, assuming no change in production volumes or the capitalized costs. Estimated reserves are used as the basis for calculating the expected future cash flows from a property, which are used to determine whether that property may be impaired. Reserves are also used to estimate the supplemental disclosure of the standardized measure of discounted future net cash flows relating to oil and gas producing activities and reserve quantities in Note 19, “Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities” to our consolidated financial statements. Changes in the estimated reserves are considered in estimates for accounting purposes and are reflected on a prospective basis.

     We monitor our long-lived assets recorded in property, plant and equipment in our consolidated balance sheet to ensure they are fairly presented. We must evaluate our properties for potential impairment when circumstances indicate that the carrying value of an asset could exceed its fair value. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Such events include a projection of future oil and natural gas sales prices, an estimate of the ultimate amount of recoverable oil and gas reserves that will be produced from a field, the timing of future production, future production costs, future abandonment costs, and future inflation. The need to test a property for impairment can be based on several factors, including a significant reduction in sales prices for oil and/or gas, unfavorable adjustment to reserves, physical damage to production equipment and facilities, a change in costs, or other changes to contracts, environmental regulations or tax laws. All of these factors must be considered when testing a property’s carrying value for impairment. We cannot predict whether impairment charges may be required in the future.

     We are required to develop estimates of fair value to allocate purchase prices paid to acquire businesses to the assets acquired and liabilities assumed under the purchase method of accounting. The purchase price paid to acquire a business is allocated to its assets and liabilities based on the estimated fair values of the assets acquired and liabilities assumed as of the date of acquisition. We use all available information to make these fair value determinations. See Note 3 to the consolidated financial statements for information on these acquisitions.

Derivatives

     We use commodity derivative contracts to manage our exposure to oil and gas price volatility. We account for our commodity derivatives in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” For derivative contracts designated as hedges, earnings are affected by the ineffective portion of a hedge contract (changes in realized prices that do not match the changes in the hedge price). Ineffective gains or losses are recorded in other revenue while the hedge contract is open and may increase or reverse until settlement of the contract. This may result in significant volatility to current period income. For derivatives qualifying as hedges, the effective portion of any changes in fair value is recognized in stockholders’ equity as other comprehensive income (“OCI”), and then reclassified to earnings, in oil and gas revenue, when the hedged transaction is consummated. This may result in significant volatility in stockholders’ equity. The fair value of open hedging contracts is an estimated amount that could be realized upon termination. As of the fourth quarter of 2005, certain of our gas hedges no longer qualify for hedge accounting due to the volatility of gas prices and their effect on our basis differentials and are marked-to-market.

     The commodity derivatives we use include commodity collars and swaps. While there is a risk that the financial benefit of rising 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.

Asset Retirement Obligations

     We have significant obligations to remove tangible equipment and restore land or seabed at the end of oil and gas production operations. Removal and restoration obligations are primarily associated with plugging and abandoning wells and removing and disposing of offshore oil and gas platforms. Estimating the future asset removal costs is difficult and requires us to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

     Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate retirement costs, inflation factors, credit adjusted discount rates, timing of retirement, and changes in the legal, regulatory,

environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation, (“ARO”), a corresponding adjustment is made to the oil and gas property balance. In addition, increases in the discounted ARO liability resulting from the passage of time are reflected as accretion expense, a component of depletion, depreciation and amortization in our consolidated statement of operations.

Deferred Taxes

     We are subject to income and other taxes in all areas in which we operate. When recording income tax expense, certain estimates are required because income tax returns are generally filed many months after the close of a calendar year, tax returns are subject to audit which can take years to complete and future events often impact the timing of when income tax expenses and benefits are recognized. We have deferred tax assets relating to tax operating loss carryforwards and other deductible differences. We routinely evaluate deferred tax assets to determine the likelihood of realization. A valuation allowance is recognized on deferred tax assets when we believe that certain of these assets are not likely to be realized.

     In determining deferred tax liabilities, accounting rules require OCI to be considered, even though such income or loss has not yet been earned. At year-end 2005, deferred tax liabilities exceeded deferred tax assets by $113.1 million, with $85.5 million of deferred tax assets related to unrealized deferred hedging losses included in OCI. At year-end 2006, deferred tax liabilities exceeded deferred tax assets by $468.6 million, with $21.3 million of deferred tax liabilities related to unrealized hedging gains included in OCI.

     We may be challenged by taxing authorities over the amount and/or timing of recognition of revenues and deductions in our various income tax returns. Although we believe that we have adequately provided for all taxes, gains or losses could occur in the future due to changes in estimates or resolution of outstanding tax matters.

Contingent Liabilities

     A provision for legal, environmental and other contingent matters is charged to expense when the loss is probable and the cost or range of cost can be reasonably estimated. Judgment is often required to determine when expenses should be recorded for legal, environmental and contingent matters. In addition, we often must estimate the amount of such losses. In many cases, our judgment is based on the input of our legal advisors and on the interpretation of laws and regulations, which can be interpreted differently by regulators and/or the courts. We monitor known and potential legal, environmental and other contingent matters and make our best estimate of when to record losses for these matters based on available information. Although we continue to monitor all contingencies closely, particularly our outstanding litigation, we currently have no material accruals for contingent liabilities.

Accounting Standards Not Yet Adopted

     In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” This statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements but may require some entities to change their measurement practices. For Range, SFAS No. 157 will be effective January 1, 2008, with early application permitted. We are currently evaluating the provisions of this statement.

     In July 2006, FASB Interpretation (“FIN”) No. 48, “Accounting for Uncertainty in Income Taxes - An Interpretation of FASB Statement No. 109” was issued. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The new standard also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods and disclosure. For Range, the provisions of FIN 48 are effective January 1, 2007. The cumulative effect of adopting FIN 48 will be recorded in retained earnings. Range is currently evaluating the provisions of FIN 48 to determine the impact on its consolidated financial statements but we do not expect a material impact on our financial position or results of operations.

RANGE RESOURCES CORPORATION

INDEX TO FINANCIAL STATEMENTS

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

     Our financial statements and financial statement schedules are set forth at pages F-2 through F-37 inclusive.

		Page
		Number
Report of Independent Registered Public Accounting Firm — Financial Statements		F- 2
Consolidated Balance Sheets at December 31, 2006 and 2005		F- 3
Consolidated Statements of Operations for the Year Ended December 31, 2006, 2005 and 2004		F- 4
Consolidated Statements of Cash Flows for the Year Ended December 31, 2006, 2005 and 2004		F- 5
Consolidated Statements of Stockholders’ Equity for the Year Ended December 31, 2006, 2005 and 2004		F- 6
Consolidated Statements of Comprehensive Income (Loss) for the Year Ended December 31, 2006, 2005 and 2004		F- 7
Notes to Consolidated Financial Statements		F-8
Selected Quarterly Financial Information (Unaudited)		F-29
Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited)		F-30

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
Range Resources Corporation:

     We have audited the accompanying consolidated balance sheets of Range Resources Corporation (the “Company”) as of December 31, 2006 and 2005, and the related consolidated statements of operations, stockholders’ equity, comprehensive income (loss) and cash flows for each of the three years in the period ended December 31, 2006. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

     We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

     In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Range Resources Corporation at December 31, 2006 and 2005, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.

     As discussed in Note 2 to the consolidated financial statements, in 2006, the Company adopted Statement of Financial Accounting Standards No. 123(R), “Share-Based Payment.”

     We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 26, 2007 expressed an unqualified opinion thereon.

Ernst & Young LLP

Fort Worth, Texas
February 26, 2007, except for Note 4 and 17 as to
which the date is June 18, 2007

RANGE RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands, except per share data)

		December 31,
		2006				2005
Assets
Current assets:
Cash and equivalents		$	2,382			$	4,750
Accounts receivable, less allowance for doubtful accounts of $746 and $624			125,421				123,875
Assets held for sale			79,304				—
Assets of discontinued operation			78,161				5,670
Unrealized derivative gain			93,588				425
Deferred tax asset			—				61,677
Inventory and other			10,069				11,580
Total current assets			388,925				207,977
Unrealized derivative gain			61,068				—
Equity method investment			13,618				—
Oil and gas properties, successful efforts method			3,359,093				2,284,313
Accumulated depletion and depreciation			(751,005	)			(604,720	)
			2,608,088				1,679,593
Transportation and field assets			80,066				65,210
Accumulated depreciation and amortization			(32,923	)			(25,966	)
			47,143				39,244
Assets of discontinued operation			—				61,589
Other assets			68,832				30,582
Total assets		$	3,187,674			$	2,018,985
Liabilities
Current liabilities:
Accounts payable		$	171,914			$	113,503
Asset retirement obligations			3,853				3,121
Accrued liabilities			30,026				26,043
Liabilities of discontinued operation			28,333				8,778
Accrued interest			12,938				10,214
Unrealized derivative loss			4,621				160,101
Total current liabilities			251,685				321,760
Bank debt			452,000				269,200
Subordinated notes			596,782				346,948
Deferred tax, net			468,643				174,817
Unrealized derivative loss			266				70,948
Deferred compensation liability			90,094				73,492
Asset retirement obligations			72,043				53,443
Liabilities of discontinued operation			—				11,454
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, 138,931,565 issued at December 31, 2006 and 129,913,046 issued at December 31, 2005			1,389				1,299
Common stock held in treasury – 5,826 shares at December 31, 2005			—				(81	)
Additional paid-in capital			1,079,994				845,519
Retained earnings			160,313				13,800
Common stock held by employee benefit trust, 1,853,279 and 1,971,605 shares, respectively, at cost			(22,056	)			(11,852	)
Deferred compensation			—				(4,635	)
Accumulated other comprehensive income (loss)			36,521				(147,127	)
Total stockholders’ equity			1,256,161				696,923
Total liabilities and stockholders’ equity		$	3,187,674			$	2,018,985

See accompanying notes.

RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)

		Year Ended December 31,
		2006				2005				2004
Revenues
Oil and gas sales		$	649,078			$	498,376			$	278,903
Transportation and gathering			2,422				2,306				2,002
Mark-to-market on oil and gas derivatives			86,491				10,868				—
Other			6,821				(2,447	)			2,163
Total revenue			744,812				509,103				283,068
Costs and expenses
Direct operating			81,261				57,866				39,419
Production and ad valorem taxes			36,415				30,822				19,845
Exploration			44,088				29,529				12,619
General and administrative			49,886				33,444				20,634
Deferred compensation plan			6,873				29,474				19,176
Interest expense			55,849				37,619				22,437
Depletion, depreciation and amortization			154,739				114,364				80,628
Total costs and expenses			429,111				333,118				214,758
Income from continuing operations before income taxes			315,701				175,985				68,310
Income tax provision (benefit)
Current			1,912				1,071				(245	)
Deferred			119,840				64,809				25,327
			121,752				65,880				25,082
Income from continuing operations			193,949				110,105				43,228
Income (loss) from discontinued operations, net of taxes			(35,247	)			906				(997	)
Net income			158,702				111,011				42,231
Preferred dividends			—				—				(5,163	)
Net income available to common stockholders		$	158,702			$	111,011			$	37,068
Earnings per common share:
Basic – income from continuing operations		$	1.45			$	0.89			$	0.41
– discontinued operations			(0.26	)			—				(0.01	)
– net income		$	1.19			$	0.89			$	0.40
Diluted – income from continuing operations		$	1.39			$	0.85			$	0.39
– discontinued operations			(0.25	)			0.01				(0.01	)
– net income		$	1.14			$	0.86			$	0.38

See accompanying notes.

RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)

		Year Ended December 31,
		2006				2005				2004
Operating activities:
Net income		$	158,702			$	111,011			$	42,231
Adjustments to reconcile net cash provided from operating activities:
(Income) loss from discontinued operations			35,247				(906	)			997
Gain from equity method investment			(548	)			—				—
Deferred income tax expense			119,840				64,809				25,327
Depletion, depreciation and amortization			154,738				114,364				80,627
Exploration dry hole costs			15,085				6,559				1,100
Mark-to-market on oil and gas derivatives gains			(86,491	)			(10,868	)			—
Unrealized derivative (gains) losses			(5,654	)			3,505				(1,793	)
Allowance for bad debts			80				675				1,762
Amortization of deferred financing costs and discount			1,827				1,662				1,071
Non-cash compensation			27,455				37,391				20,667
(Gain) loss on sale of assets and other			940				(512	)			(3,109	)
Changes in working capital, net of amounts from business acquisitions:
Accounts receivable			30,286				(64,333	)			(38,741	)
Inventory and other			(1,157	)			(3,452	)			(6,080	)
Accounts payable			(5,049	)			27,472				34,746
Accrued liabilities and other			(2,949	)			1,219				8,162
Net cash provided from continuing operations			442,352				288,596				166,967
Net cash provided from discontinued operations			37,523				37,149				42,282
Net cash provided from operating activities			479,875				325,745				209,249
Investing activities:
Additions to oil and gas properties			(493,236	)			(266,396	)			(154,612	)
Additions to field service assets			(14,449	)			(11,310	)			(4,237	)
Acquisitions, net of cash acquired			(360,149	)			(153,600	)			(485,564	)
Investing activities of discontinued operations			(23,204	)			(10,511	)			(11,948	)
Investment in equity method affiliate and other assets			(21,009	)			—				—
Proceeds from disposal of assets and other repayments			388				9,440				32,060
Net cash used in investing activities			(911,659	)			(432,377	)			(624,301	)
Financing activities:
Borrowings on credit facilities			802,500				299,000				634,578
Repayments on credit facilities			(619,700	)			(453,700	)			(528,878	)
Issuance of subordinated notes			249,500				150,000				98,125
Treasury stock purchases			—				(2,808	)			—
Dividends paid – common stock			(12,189	)			(7,614	)			(3,219	)
– preferred stock			—				(2,213	)			(2,950	)
Debt issuance costs			(6,960	)			(4,119	)			(3,630	)
Issuance of common stock			16,265				114,470				250,460
Other debt repayments			—				(16	)			(11,683	)
Net cash provided from financing activities			429,416				93,000				432,803
Net increase (decrease) in cash and equivalents			(2,368	)			(13,632	)			17,751
Cash and equivalents at beginning of year			4,750				18,382				631
Cash and equivalents at end of year		$	2,382			$	4,750			$	18,382