Draft 10 July 25

 

 

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, 2005
		OR
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 0-9592

RANGE RESOURCES CORPORATION

(Exact name of registrant as specified in its charter)

Delaware		34-1312571
(State or other jurisdiction of		(I.R.S. Employer
Incorporation or organization)		Identification No.)

777 Main Street, Suite 800
Fort Worth, Texas
(Address of principal executive offices)

76102
(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.

YesþNoo

     Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

YesþNoo

86,371,606 Common Shares were outstanding on July 25, 2005.

 

 

RANGE RESOURCES CORPORATION

FORM 10-Q
QUARTER ENDED JUNE 30, 2005

INDEX				PAGE
		PART I – FINANCIAL INFORMATION
Item 1.		Financial Statements
		Consolidated Balance Sheet			3
		Consolidated Statement of Operations			4
		Consolidated Statement of Cash Flows			5
		Consolidated Statement of Comprehensive Income (Loss)			6
		Selected Notes to Consolidated Financial Statements			7
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			23
Item 3.		Quantitative and Qualitative Disclosures about Market Risk			32
Item 4.		Controls and Procedures			33
		PART II – OTHER INFORMATION
Item 2.		Unregistered Sales of Equity Securities and use of Proceeds			33
Item 4.		Submission of Matters to Vote of Security Holders			34
Item 6.		Exhibits			35
Restated Certificate of Incorporation
Certification by the President & CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification by the President & CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906

PART I — FINANCIAL INFORMATION

RANGE RESOURCES CORPORATION

		June 30,				December 31,
		2005				2004
		(Unaudited)
Assets
Current assets
Cash and equivalents		$	4,941			$	18,382
Accounts receivable, less allowance for doubtful accounts of $867 and $967			64,862				81,942
Unrealized derivative gain			641				534
Deferred tax asset			36,249				26,310
Inventory and other			15,903				9,168
Total current assets			122,596				136,336
Unrealized derivative gain			—				206
Oil and gas properties, successful efforts method			2,367,134				2,097,026
Accumulated depletion and depreciation			(749,344	)			(694,667	)
			1,617,790				1,402,359
Transportation and field assets			62,735				59,423
Accumulated depreciation and amortization			(24,863	)			(22,141	)
			37,872				37,282
Other			24,420				19,223
Total assets		$	1,802,678			$	1,595,406
Liabilities
Current liabilities
Accounts payable		$	68,224			$	78,723
Asset retirement obligation			5,706				6,822
Accrued liabilities			23,678				23,292
Accrued interest			9,918				7,320
Unrealized derivative loss			92,831				61,005
Total current liabilities			200,357				177,162
Bank debt			265,700				423,900
Subordinated notes			346,799				196,656
Deferred taxes, net			151,050				117,713
Unrealized derivative loss			40,528				10,926
Deferred compensation liability			49,535				38,799
Asset retirement obligation			66,093				63,905
Long-term capital lease obligation			—				5
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, 86,316,576 issued at June 30, 2005 and 81,219,351 issued at December 31, 2004			863				812
Common stock held in treasury – 115,256 at June 30, 2005			(2,416	)			—
Capital in excess of par value			825,487				707,869
Retained earnings (deficit)			(49,196	)			(89,597	)
Stock held by employee benefit trust, 1,396,454 and 1,441,751 shares, respectively, at cost			(8,691	)			(8,186	)
Deferred compensation			(1,373	)			(1,257	)
Accumulated other comprehensive income (loss)			(82,058	)			(43,301	)
Total stockholders’ equity			682,616				566,340
Total liabilities and stockholders’ equity		$	1,802,678			$	1,595,406

See accompanying notes

RANGE RESOURCES CORPORATION

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2005				2004				2005				2004
Revenues
Oil and gas sales		$	118,723			$	67,553			$	226,138			$	132,921
Transportation and gathering			631				344				1,159				811
Other			330				799				347				(1,503	)
			119,684				68,696				227,644				132,229
Expenses
Direct operating			17,419				10,406				32,227				20,401
Production and ad valorem taxes			7,034				4,801				12,789				9,051
Exploration			9,124				4,200				12,395				7,767
General and administrative			11,517				9,355				22,187				18,176
Interest expense			9,547				4,422				18,131				8,567
Depletion, depreciation and amortization			30,436				22,444				60,198				44,692
			85,077				55,628				157,927				108,654
Income before income taxes			34,607				13,068				69,717				23,575
Income taxes
Current			—				44				—				44
Deferred			12,946				4,835				26,053				8,722
			12,946				4,879				26,053				8,766
Net income			21,661				8,189				43,664				14,809
Preferred dividends			—				(737	)			—				(1,475	)
Net income available to common stockholders		$	21,661			$	7,452			$	43,664			$	13,334
Earnings per common share:
Basic		$	0.27			$	0.13			$	0.54			$	0.24
Diluted		$	0.26			$	0.12			$	0.52			$	0.23
Dividends per common share		$	0.02			$	0.01			$	0.04			$	0.01

See accompanying notes.

RANGE RESOURCES CORPORATION

		Six Months Ended
		June 30,
		2005				2004
Increase (decrease) in cash and equivalents Operating activities:
Net income		$	43,664			$	14,809
Adjustments to reconcile net income to net cash provided from operating activities:
Deferred income tax expense			26,053				8,722
Depletion, depreciation and amortization			60,198				44,692
Unrealized derivative (gains) losses			(293	)			(536	)
Allowance for bad debts			450				1,286
Exploration dry hole costs			1,813				3,429
Amortization of deferred issuance costs and discount			853				472
Deferred compensation adjustments			9,960				9,008
Loss on sale of assets and other			4				(109	)
Changes in working capital:
Accounts receivable			18,056				(4,456	)
Inventory and other			(8,074	)			(5,039	)
Accounts payable			(15,166	)			6,660
Accrued liabilities and other			5,889				2,412
Net cash provided from operating activities			143,407				81,350
Investing activities:
Additions to oil and gas properties			(109,339	)			(62,202	)
Additions to field service assets			(3,612	)			(1,014	)
Acquisitions			(136,996	)			(253,596	)
IPF net repayments			1,163				2,332
Disposal of assets			141				2,432
Net cash used in investing activities			(248,643	)			(312,048	)
Financing activities:
Borrowings on credit facilities			150,700				316,200
Repayments on credit facilities			(308,900	)			(314,400	)
Other debt repayments			(16	)			(2,779	)
Debt issuance costs			(4,108	)			(2,998	)
Treasury stock purchases			(2,808	)			—
Dividends paid — common stock			(3,263	)			(1,134	)
— preferred stock			(2,213	)			(1,475	)
Issuance of subordinated notes			150,000				98,125
Issuance of common stock			112,403				146,099
Net cash provided by financing activities			91,795				237,638
Net increase (decrease) in cash and equivalents			(13,441	)			6,940
Cash and equivalents at beginning of period			18,382				631
Cash and equivalents at end of period		$	4,941			$	7,571

See accompanying notes.

RANGE RESOURCES CORPORATION

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2005				2004				2005				2004
Net income		$	21,661			$	8,189			$	43,664			$	14,809
Net deferred hedge gains (losses), net of tax:
Contract settlements reclassified to income			14,068				14,644				27,258				25,770
Change in unrealized deferred hedging losses			(6,001	)			(19,529	)			(66,118	)			(45,821	)
Change in unrealized gains (losses) on securities held by deferred compensation plan			366				18				103				64
Comprehensive income (loss)		$	30,094			$	3,322			$	4,907			$	(5,178	)

See accompanying notes.

RANGE RESOURCES CORPORATION

(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 through drilling and complementary acquisitions. Prior to June 2004, we held our Appalachian oil and gas assets through a 50% owned joint venture, Great Lakes Energy Partners L.L.C., or Great Lakes. In June 2004, we purchased the 50% of Great Lakes that we did not own (see footnote 4). Range is a Delaware corporation whose common stock is listed on the New York Stock Exchange.

(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

     The financial statements included herein should be read in conjunction with the latest Form 10-K for Range Resources Corporation. Unless the context otherwise indicates, all references in this report to “Range” “we” “us” or “our” are to Range Resources Corporation and its subsidiaries. The statements are unaudited but reflect all adjustments which, in our opinion, are necessary to fairly present our financial position and results of operations. All adjustments are of a normal recurring nature unless otherwise noted. These financial statements, including selected notes, have been prepared in accordance with the applicable rules of the Securities and Exchange Commission, or 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.

     The accompanying consolidated financial statements include the accounts of Range, our wholly-owned subsidiaries’ and for the periods prior to June 23, 2004, a 50% pro rata share of the assets, liabilities, income and expenses of Great Lakes. On June 23, 2004, we purchased the 50% of Great Lakes that we did not own (see footnote 4). The statement of operations for the six months ended June 30, 2004 includes 50% of the revenues and expenses of Great Lakes up to June 23, 2004 while the six months ended June 30, 2005 includes 100%. Certain reclassifications have been made to the presentation of prior periods to conform to current year presentation.

     We recognize revenues from the sale of products and services in the period delivered. Although receivables are concentrated in the oil and gas industry, we do not view this as an unusual credit risk. We provide for an allowance for doubtful accounts for specific receivables judged unlikely to be collected based on the age of the receivable, our experience with the debtor, potential offsets to the amount owed and economic conditions. In certain instances, we require purchasers to post stand-by letters of credit, furnish guarantees or pre-pay purchases. In addition to the allowance for doubtful accounts for Independent Producer Finance, or IPF, we have allowances for doubtful accounts relating to exploration and production of $867,000 and $967,000 at June 30, 2005 and December 31, 2004, respectively.

     Cash and equivalents include cash on hand and on deposit and investments in highly liquid debt instruments with maturities of three months or less. The December 31, 2004 balance sheet included $17.3 million of cash in an escrow account. These funds were received from the sale of oil and gas properties which were held in escrow to be used to purchase similar assets. As of June 30, the remaining escrow proceeds were applied toward the bank credit facility.

     We follow the successful efforts method of accounting for oil and gas producing activities. Exploratory drilling costs are capitalized pending determination of whether a well is successful. Exploratory wells subsequently determined to be dry holes are charged to expense. Costs resulting in exploratory discoveries and all development costs, whether successful or not, are capitalized. Geological and geophysical costs, delay rentals and unsuccessful exploratory wells are expensed. Depletion is provided on the unit-of-production method. Oil and NGLs are converted to a natural gas equivalent basis, or mcfe, at the rate of one barrel equals 6 mcf. The depletion, depreciation and amortization, or DD&A, rates were $1.44 per mcfe and $1.36 per mcfe in the three months ended June 30, 2005 and 2004, respectively and $1.44 per mcfe and $1.37 per mcfe in the

six months ended June 30, 2005 and 2004. Unproved properties had a net book value of $20.9 million and $14.8 million at June 30, 2005 and December 31, 2004, respectively. Unproved properties are reviewed quarterly for impairment and impaired if conditions indicate we will not exploit the acreage prior to expiration or the carrying value is above fair value.

     Our long-lived assets are reviewed for impairment quarterly for events or changes in circumstances that indicate that the carrying amount of these assets may not be recoverable. Long-lived assets are reviewed for potential impairments at the lowest levels for which there are identifiable cash flows that are largely independent of other groups of assets. The review is done by determining if the historical cost of proved properties less the applicable accumulated depreciation, depletion and amortization is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on our plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. We estimate prices based upon market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climates. When the carrying value exceeds such cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.

     At June 30, 2005, we have $8.3 million of suspended exploratory well costs, of which approximately $6.7 million have been capitalized for more than one year. The $6.7 million of costs represents a total of eight wells, of which all but one are not operated by Range. Five of the wells are completed and currently waiting on pipeline infrastructure and three wells have additional drilling underway or firmly planned.

     Our gas transportation and gathering systems are located in proximity to certain of our principal fields. Depreciation on these systems is provided on the straight-line method based on estimated useful lives of 10 to 15 years. We receive third-party income for providing transportation and field services which is recognized as earned. Depreciation on the field assets is calculated on the straight-line method based on estimated useful lives of five to seven years. Buildings are depreciated over 10 to 15 years.

     IPF owns dollar denominated overriding royalties in oil and gas properties. The royalties are accounted for as receivables and payments received relating to the return on investment are recognized as income with the remaining receipts reducing receivables. Currently, all receipts are being recognized as a return of capital, thus reducing receivables. The receivables are evaluated quarterly and provisions for the valuation allowance are adjusted accordingly. At June 30, 2005, the receivable balance was $6.7 million, offset by a valuation allowance of $3.3 million resulting in a net receivable balance of $3.4 million. The $3.4 million net receivable is shown on our consolidated balance sheet in other assets ($2.5 million) and accounts receivable ($0.9 million). At December 31, 2004, the receivable balance was $7.4 million, offset by a valuation allowance of $2.9 million resulting in a net receivable balance of $4.5 million. During the second quarter of 2005, IPF net (included in other revenues) included $2,000 of administrative expenses and a $225,000 increase in the valuation allowance. During the same period of the prior year, revenues of $9,000 were offset by $62,000 of interest and administrative expenses, and a $496,000 increase in the valuation allowance. Since 2001, IPF has not acquired new royalties and therefore, the portfolio has declined due to collections and sales.

     The expenses of issuing debt are capitalized and included in other assets on our consolidated balance sheet. These costs are amortized over the expected life of the related securities. When a security is retired prior to maturity, related unamortized costs are expensed. At June 30, 2005 and December 31, 2004, these capitalized costs totaled $8.7 million and $5.7 million, respectively. At June 30, 2005, other assets included $8.7 million of unamortized debt issuance costs, $639,000 of long-term deposits, $12.6 million of marketable securities held in our deferred compensation plans and $2.5 million of long-term IPF receivables.

     We use the sales method to account for gas imbalances, recognizing revenue based on cash received rather than the gas produced. A liability is recognized when the imbalance exceeds the estimate of remaining reserves. Gas imbalances at June 30, 2005 and December 31, 2004 were not significant.

     We use commodity-based derivatives to reduce the volatility associated with oil and gas prices. For derivatives qualifying as hedges of future cash flows, the effective portion of any changes in fair value is recognized in a component of stockholders’ equity called other comprehensive income, or OCI, and then reclassified to income, within oil and gas revenues, when the underlying anticipated transaction occurs. Any ineffective portion (changes in realized prices that do not match changes in the hedge price) is recognized in other revenues in our consolidated statement of operations, as it occurs. Ineffective gains or losses are recorded while the hedge contract is open and may increase or reverse until settlement of the contract. Of the $133.4 million unrealized pre-tax hedging loss at June 30, 2005, $92.8 million of losses will be reclassified to earnings over the next 12 months and $40.6 million for the periods thereafter, if prices remain constant. Actual amounts that will be reclassified will vary as a result of changes in prices. We have also entered into swap agreements to reduce the risk of changing interest rates. These interest rate swaps are not designated as hedges and are marked to market each month as a component of interest expense.

     The fair values of asset retirement obligations are recognized in the period they are incurred if a reasonable estimate of fair value can be made. Asset retirement obligations primarily relate to the abandonment of oil and gas producing facilities and include costs to dismantle and relocate or dispose of production platforms, gathering systems, wells and related structures. Estimates are based on historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. We do not provide for a market risk premium associated with asset retirement obligations because a reliable estimate cannot be determined.

     The preparation of financial statements in accordance with generally accepted accounting principles in the United States 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. Actual results could differ from those estimates and assumptions used. Depletion of oil and gas properties is determined using estimates of proved oil and gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and gas properties are subject to numerous uncertainties including estimates of future recoverable reserves and commodity price outlook. Other estimates which may significantly impact our financial statements involve IPF receivables, deferred tax valuation allowances, fair value of derivatives and asset retirement obligations.

     We have adopted the disclosure-only provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” or SFAS 123. Accordingly, no compensation cost has been recognized for the stock-option compensation plans because the exercise prices of employee option awards equal the market prices of the underlying stock on the date of grant. If compensation cost had been determined based on the fair value at the grant date for awards in the three month and six months ended June 30, 2005 and 2004, consistent with the provisions of SFAS 123, our net income and earnings per share would have been reduced to the pro forma amounts indicated below (in thousands, except per share data):

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2005				2004				2005				2004
Net income, as reported		$	21,661			$	8,189			$	43,664			$	14,809
Plus: Total stock-based employee compensation cost included in net income, net of tax			3,459				2,804				6,275				5,675
Deduct: Total stock-based employee compensation, determined under fair value based method, net of tax			(5,871	)			(3,988	)			(10,250	)			(7,672	)
Pro forma net income		$	19,249			$	7,005			$	39,689			$	12,812
Earnings per share:
Basic-as reported		$	0.27			$	0.13			$	0.54			$	0.24
Basic-pro forma		$	0.24			$	0.11			$	0.49			$	0.20
Diluted-as reported		$	0.26			$	0.12			$	0.52			$	0.23
Diluted-pro forma		$	0.23			$	0.10			$	0.47			$	0.19

     In December 2004, the Financial Accounting Standards Board (FASB) issued FASB Statement No. 123 (revised 2004) “Share-Based Payment,” or SFAS No. 123(R), which is a revision of FASB Statement No. 123, Accounting for Stock-Based Compensation. SFAS No. 123(R) supersedes APB opinion No. 25, Accounting for Stock Issued to employees, and amends FASB Statement No. 95, Statement of Cash Flows. Generally, the approach in SFAS No. 123(R) is similar to the approach described in Statement 123. However, SFAS No.123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values. Pro forma disclosure is no longer an alternative.

     SFAS No. 123(R) permits companies to adopt its requirements using either a “modified prospective” method, or a “modified retrospective” method. Under the “modified prospective” method, compensation cost is recognized in the financial statements beginning with the effective date, based on the requirements of SFAS No. 123(R) for all share-based payments granted after that date, and based on the requirements of SFAS No. 123 for all unvested awards granted prior to the effective date of SFAS No. 123(R). Under the “modified retrospective” method, the requirements are the same as under the “modified prospective” method, but also permits entities to restate financial statements of previous periods based on proforma disclosures made in accordance with SFAS No. 123.

     We currently utilize a standard option pricing model (i.e., Black-Scholes) to measure the fair value of stock options granted. While SFAS No. 123(R) permits entities to continue to use such a model, the standard also permits the use of a “lattice” model. We have not yet determined which model we will use to measure the fair value of employee stock options upon adoption of SFAS No. 123(R).

     We are continuing to evaluate the alternatives allowed under the standard, which we are required to adopt beginning in the first quarter of 2006. In addition, we have not yet determined the financial statement impact of adopting SFAS No. 123(R) for periods beyond 2005. On June 30, 2005, the Compensation Committee of the Board of Directors approved the acceleration of certain unvested options. All unvested options with vesting dates between January 1 and April 1, 2006 were accelerated so they will vest on December 31, 2005, representing an average acceleration of 46 days. There were approximately 1.2 million options affected by the acceleration which was undertaken primarily to reduce future stock-based compensation under SFAS 123(R).

(3) ASSET RETIREMENT OBLIGATION

     A reconciliation of our liability for plugging and abandonment costs for the six months ended June 30, 2005 and 2004 is as follows (in thousands):

		Six Months Ended
		June 30,
		2005				2004
Asset retirement obligation beginning of period		$	70,727			$	51,844
Liabilities incurred			2,298				17,792
Liabilities settled			(2,295	)			(3,152	)
Accretion expense			2,551				2,105
Change in estimate			(1,482	)			109
Asset retirement obligation end of period		$	71,799			$	68,698

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

(4) ACQUISITIONS AND DISPOSITIONS

     Acquisitions are accounted for as purchases, and accordingly, the results of operations are included in our consolidated statement of operations from the date of acquisition. Purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair value at acquisition. Acquisitions have been funded with internal cash flow, bank borrowings and the issuance of debt and equity securities. We purchased various properties for $158.9 million and $324.0 million during the six months ended June 30, 2005 and 2004, respectively. The purchases include $150.3 and $318.4 million for proved oil and gas reserves, respectively, with the remainder representing unproved acreage.

     In June 2005, we purchased Permian Basin oil and gas properties for $116.7 million through the purchase of Plantation Petroleum Acquisition LLC a private company. As a preliminary allocation of purchase price, we have recorded $137.6 million to oil and gas properties, $1.2 million of working capital, $22.3 million deferred tax liability and $119,000 additional asset retirement obligations. The acquisition was funded with the proceeds from a public offering of 4.6 million common shares ($109.4 million).

     In December 2004, we purchased Appalachia oil and gas properties through the purchase of PMOG Holdings, Inc., or Pine Mountain, a private company, for $151.4 million plus $57.2 million for the retirement of debt and $13.3 million for the retirement of oil and gas commodity hedges. The following table summarizes the preliminary allocation of purchase price to assets acquired and liabilities assumed at the date of acquisition (in thousands):

		Pine Mountain
Purchase price:
Cash paid (including transaction costs)		$	222,860
Allocation of purchase price:
Working capital			4,845
Oil and gas properties			297,322
Field assets and gathering system assets			1,046
Deferred income taxes, net			(79,859	)
Asset retirement obligation and other			(494	)
Total		$	222,860

     In June 2004, we purchased the 50% of Great Lakes that we did not previously own for $200.0 million plus the assumption of $70.0 million of Great Lakes bank debt and the retirement of $27.7 million of oil and gas commodity hedges. The debt assumed was refinanced and consolidated with our existing bank credit facility as of the purchase date (See further discussion in Note 6.). The following table summarizes the allocation of the purchase price to the assets acquired and liabilities assumed at the date of acquisition (in thousands):

		Great Lakes
Purchase price:
Cash paid (including transaction costs)		$	228,824
Allocation of purchase price:
Working capital			5,062
Oil and gas properties			296,160
Field assets and gathering system assets			14,429
Other non-current assets			866
Asset retirement obligation and other			(17,693	)
Long-term debt			(70,000	)
Total		$	228,824

     The following unaudited pro forma data includes the results of operations of the above Great Lakes and Pine Mountain acquisitions as if they had been consummated at the beginning of 2004. The pro forma data is based on historical information and does not necessarily reflect the actual results that would have occurred nor is it necessarily indicative of future results of operations (in thousands).

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2005				2004				2005				2004
Revenues		$	119,684			$	89,125			$	227,644			$	174,592
Income before income taxes			34,607				18,756				69,717				36,399
Net income			21,661				11,770				43,664				22,889
Earnings per share:
Diluted-as reported		$	0.26			$	0.12			$	0.52			$	0.23
Diluted-pro forma		$	0.26			$	0.14			$	0.52			$	0.28

(5) SUPPLEMENTAL CASH FLOW INFORMATION

		Six Months Ended
		June 30,
		2005				2004
		(in thousands)
Non-cash investing and financing activities:
Common stock issued under benefit plans		$	720			$	1,120
Debt assumed in Great Lakes acquisition			—				70,000
Cash used in operating activities included:
Income taxes paid		$	—			$	150
Interest paid			14,760				8,838

(6) INDEBTEDNESS

     We had the following debt outstanding as of the dates shown below (in thousands) (interest rates at June 30, 2005, excluding the impact of interest rate swaps, is shown parenthetically). No interest expense was capitalized during the six months ended June 30, 2005 and 2004, respectively.

		June 30,				December 31,
		2005				2004
Bank debt (4.3%)		$	265,700			$	423,900
Subordinated debt:
7-3/8% Senior Subordinated Notes due 2013, net of discount			196,799				196,656
6-3/8% Senior Subordinated Notes due 2015			150,000				—
Total debt		$	612,499			$	620,556

     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, 2005, the outstanding balance under the bank credit facility was $265.7 million and there was $334.3 million of borrowing capacity available. In April 2005, the loan maturity was extended one year to January 1, 2009, the borrowing base was increased to $600.0 million and certain reductions to interest rate margins and fees were enacted. Borrowings 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 data 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 its LIBOR loans to base rate loans or to convert all or any part of its base rate loans to LIBOR loans. The average interest rate on the bank credit facility, excluding the effect of the interest rate swaps, was 4.1% for the three months and the six months ended June 30, 2005. After the effect of the interest rate swaps (see Note 7), the rate was 3.9% for the three months and 4.0% for the six months ended June 30, 2005. The weighted average interest rate (including applicable margin) was 3.1% for the six months ended June 30, 2004. A commitment fee is paid on the undrawn balance based on an annual rate of between 0.25% and 0.50%. At June 30, 2005, the commitment fee was 0.25% and the interest rate margin was 1.0%. At July 25, 2005, the interest rate (including applicable margin) was 4.4% excluding interest rate swaps and 4.2% after interest rate swaps.

     Prior to June 2004, we consolidated our proportionate share of borrowings on the Great Lakes credit facility. Simultaneously with our purchase of the 50% of Great Lakes we did not own, the outstanding balance under the Great Lakes credit facility was fully repaid through a consolidation with our revolving credit facility.

     In July 2003, we issued $100.0 million of 7-3/8% Senior Subordinated Notes due 2013, or the 7-3/8% Notes. In June 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 each January and July of each year. The 7-3/8% Notes mature in July 2013 and are guaranteed by certain of our subsidiaries, or the Subsidiary Guarantors. 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 the Subsidiary Guarantors are general, unsecured obligations and are subordinated to our senior debt and will be subordinated to future senior debt that Range and the Subsidiary Guarantors are permitted to incur under the bank credit facility and the indenture governing the 7-3/8% Notes. In June 2004, we issued an additional $100.0 million of 7-3/8% Notes, or the Additional Notes. The Additional Notes were issued at a $1.9 million discount which is amortized into interest expense over the remaining life of the 7-3/8% Senior Notes.

     In March 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 each March and September of each year. The 6-3/8% Notes mature in March 2015 and are guaranteed by certain of our subsidiaries. The offering of the 6-3/8% Notes was not registered under the Securities Act of 1933, as amended, or the Securities Act, or under any state securities laws because the 6-3/8% Notes were only offered to qualified institutional buyers and to non-U.S. persons outside the United States in compliance with Rule 144A and Regulation S under the Securities Act. In May 2005, $150.0 million aggregate principal amount of the 6-3/8% Notes were exchanged for $150.0 million aggregate principal amount of our 6-3/8% Senior Subordinated Notes due 2013 issued in a registered exchange offer for which a registration statement on Form S-4 was filed under the Securities Act, or the Exchange Notes. The Exchange Notes are identical to the 6-3/8% Notes except that the Exchange Notes are registered under the Securities Act and do not have restrictions on transfer, registration rights or provisions for additional interest.

     We may redeem the Exchange Notes, in whole or in part, at any time on or after March 15, 2010, at redemption prices from 103.7% 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 principle 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 Exchange Notes at 101% of the principal amount plus accrued and unpaid interest, if any.

     In 1996, we issued $55.0 million of 6% Convertible Subordinated Debentures due 2007. We redeemed the outstanding debentures in August 2004 at 102.0% of principal amount, plus accrued interest, which totaled $9.1 million.

     The debt agreements contain covenants relating to working capital, dividends and financial ratios. We were in compliance with all covenants at June 30, 2005. 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 $338.7 million was available under the bank credit facility’s restricted payment basket on June 30, 2005. The terms of both the 6-3/8% Notes and the 7-3/8% 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, 2005, approximately $395.8 million was available under both the 6-3/8% Notes and the 7-3/8% Notes restricted payments basket.

(7) FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES

     Financial instruments include cash and equivalents, receivables, payables, debt and commodity and interest rate derivatives. The book value of cash and equivalents, receivables and payables is considered to be representative of fair value given their short maturity. We mark to market all derivatives; therefore, the book value is assumed to be equal to fair value. The book value of bank borrowings is believed to approximate fair value because of their floating rate structure.

     The following table sets forth the book and estimated fair values of financial instruments as of June 30, 2005 and December 31, 2004 (in thousands):

		June 30, 2005								December 31, 2004
		Book				Fair				Book				Fair
		Value				Value				Value				Value
Assets
Cash and equivalents		$	4,941			$	4,941			$	18,382			$	18,382
Accounts receivable			63,973				63,973				80,562				80,562
IPF receivables			3,380				3,380				4,508				4,508
Marketable securities			12,579				12,579				9,866				9,866
Interest rate swaps			641				641				740				740
Total			85,514				85,514				114,058				114,058
Liabilities
Accounts payable			(68,224	)			(68,224	)			(78,723	)			(78,723	)
Commodity swaps and collars			(133,359	)			(133,359	)			(71,931	)			(71,931	)
Long-term debt (1)			(612,499	)			(629,100	)			(620,556	)			(633,556	)
Total			(814,082	)			(830,683	)			(771,210	)			(784,210	)
Net financial instruments		$	(728,568	)		$	(745,169	)		$	(657,152	)		$	(670,152	)

     At June 30, 2005, we had open hedging contracts covering 14.9 Bcf of gas at prices averaging $5.26 per mcf, 0.4 million barrels of oil at prices averaging $30.18 per barrel and 0.1 million barrels of NGLs at prices averaging $19.20 per barrel. We also had collars covering 55.1 Bcf of gas at weighted averaged floor and cap prices of $5.14 to $9.54 per mcf and 4.3 million barrels of oil at prices of $29.84 to $58.44 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, 2005, was a net unrealized pre-tax loss of $133.4 million. The contracts expire monthly through December 2007. Transaction gains and losses 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 $22.3 million and $23.2 million due to hedging in the three months ended June 30, 2005 and 2004, respectively. Oil and gas revenues were decreased by $43.3 million and $40.1 million due to realized hedging in the six months ended June 30, 2005 and 2004, respectively. Other revenues in our consolidated statement of operations include ineffective hedging gains of $123,000 and of $971,000 in the three months ended June 30, 2005 and 2004, respectively. Other revenues for the six months ended June 2005 and 2004 include gains of $248,000 and losses of $583,000 for ineffective hedging, respectively.

     The following schedule shows the effect of closed oil, gas and NGL hedges since January 1, 2004 and the value of open contracts at June 30, 2005 (in thousands):

Quarter		Hedging Gain
Ended		(Loss)
Closed Contracts
2004
March 31		$	(16,896	)
June 30			(23,245	)
September 30			(24,382	)
December 31			(35,598	)
Subtotal			(100,121	)
2005
March 31			(20,936	)
June 30			(22,330	)
Subtotal			(43,266	)
Total net realized loss		$	(143,387	)
Open Contracts
2005
September 30		$	(27,518	)
December 31			(33,965	)
Subtotal			(61,483	)
2006
March 31			(16,186	)
June 30			(15,162	)
September 30			(14,561	)
December 31			(15,175	)
Subtotal			(61,084	)
2007
March 31			(2,690	)
June 30			(2,699	)
September 30			(2,767	)
December 31			(2,636	)
Subtotal			(10,792	)
Total net liability		$	(133,359	)

     We use interest rate swap agreements to manage the risk that future cash flows associated with interest payments on certain amounts outstanding under the variable rate bank credit facility may be adversely affected by volatility in market rates. Under the interest rate swap agreements, we agree to pay an amount equal to a specified fixed rate of interest times a notional principal amount, and to receive in return, a specified variable rate of interest times the same notional principal amount. Changes in the fair value of interest rate swaps, which qualify for cash flow hedge accounting treatment, are reflected as adjustments to OCI to the extent the swaps are effective and are recognized as an adjustment to interest expense during the period in which the cash flow related to the interest payments are made. Due to the Great Lakes acquisition, these interest rate swaps are no longer designated as hedges and are marked to market each month in interest expense. At June 30, 2005, we had two interest rate swap agreements with a notional amount of $35.0 million. These swaps consist of agreements totaling $35.0 million at 1.8% which expire in June 2006. The fair value of the swaps at June 30, 2005 was a net unrealized pre-tax gain of $641,000.

     The combined fair value of net unrealized losses on oil and gas hedges and net unrealized gain on interest rate swaps totaled $132.7 million and appear as short-term and long-term unrealized derivative gains and losses on the balance sheet. 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.

     The following table sets forth quantitative information of derivative instruments at June 30, 2005 (in thousands):

		As of June 30, 2005
		Assets				Liabilities
Commodity swaps		$	—			$	(46,052	)(a)
Commodity collars		$	—			$	(87,307	)(b)
Interest rate swaps		$	641			$	—

(8) COMMITMENTS AND CONTINGENCIES

     We are involved in various legal actions and claims arising in the ordinary course of business, the most significant of which is Jack Freeman, et al. v. Great Lakes Energy Partners L.L.C., et al., a class-action suit filed in 2000 which is currently pending against Great Lakes and Range in the state court of Chautauqua County, New York. The plaintiffs are 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. Management believes these allegations are without merit and will vigorously defend our position. We do not believe that this litigation will have a material adverse effect on our financial position or results of operations.

(9) STOCKHOLDERS’ EQUITY

     We have authorized capital stock of 260 million shares, which includes 250 million shares of common stock and 10 million shares of preferred stock. In September 2003, we issued 1.0 million shares of 5.9% Convertible Preferred Stock, par value $1.00 and liquidation preference $50 per share. Effective December 31, 2004, all outstanding shares of Convertible Preferred were converted into 5.9 million shares of common stock.

     The following is a schedule of changes in the number of common shares issued from December 31, 2003 to June 30, 2005:

		Six Months				Twelve Months
		Ended				Ended
		June 30, 2005				December 31, 2004
Beginning balance			81,219,351				56,409,791
Public offerings			4,600,000				17,940,000
Stock options exercised			466,242				834,537
Restricted stock grants			—				80,900
Deferred compensation plan			13,923				3,671
In lieu of fees and bonuses			17,060				30,459
Contributed to 401(k) plan			—				37,640
Exchanged for preferred			—				5,882,353
			5,097,225				24,809,560
Ending balance			86,316,576				81,219,351

     The Board of Directors has approved of up to $5.0 million of repurchases of common stock based on market conditions and opportunities. During the second quarter, we bought, in open market purchases, 133,700 shares at an average price of $21.00 which are being held as treasury shares. Also during the second quarter, 18,444 of these treasury shares were used for equity compensation to directors and employees.

(10) EQUITY-BASED AND STOCK PURCHASE PLANS

     We have five equity-based stock plans, of which two are active, and a stock purchase plan. Under the active plans, incentive and non-qualified options, stock appreciation rights, restricted stock awards, phantom stock rights and annual cash incentive awards are 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 the equity-based plans is summarized below:

		Active								Inactive
						Non-
		2005				Employee				1999				Directors’				1989
		Plan				Plan				Plan				Plan				Plan				Total
Outstanding on December 31, 2004			—				—				4,262,220				232,000				87,850				4,582,070
Granted			—				56,000				983,050				—				—				1,039,050
Exercised			—				—				(456,942	)			—				(9,300	)			(466,242	)
Expired/forfeited			—				—				(69,457	)			—				(750	)			(70,207	)
			—				56,000				456,651				—				(10,050	)			502,601
Outstanding on June 30, 2005			—				56,000				4,718,871				232,000				77,800				5,084,671

     In May 2005, shareholders approved the 2005 Equity Based Compensation Plan, or the 2005 Plan, under which the number of shares that may be granted is equal to 10.0 million shares less the number of shares issued under the 1999 Plan plus the number of shares that become available from 1999 Plan awards that lapse or terminate. Effective July 1, 2005, 981,100 stock appreciation rights were granted to eligible employees at a price of $26.90.

     In May 2004, shareholders approved the Non-Employee Director Stock Option Plan, or the Non-Employee Plan, under which 300,000 stock options may be granted. Director’s options are granted upon initial election as a director and annually upon a director’s re-election at the annual meeting. Options granted under the Non-Employee Plan are fully vested upon grant and have a term of five years. During the six months ended June 30, 2005, 56,000 options were granted to directors at an exercise price of $21.71 a share. At June 30, 2005, 56,000 options were outstanding at exercise prices of $21.71 a share.

     We maintain the 1999 Stock Plan, or the 1999 Plan, which authorized the issuance of 9.25 million stock options. All options issued under the 1999 Plan through May 2002 vest over 4 years and have a term of 10 years, while options issued after May 2002 vest over a three year period and have a term of five years. During the six months ended June 30, 2005, 983,050 options were granted to eligible employees at an exercise price of $23.28 a share. At June 30, 2005, 4.7 million options were outstanding at exercise prices ranging from $1.94 to $23.28 a share. No further options will be granted under this plan.

     We maintain the Outside Directors’ Stock Option Plan, or the Directors’ Plan, which authorized the issuance of 300,000 options. At June 30, 2005, 232,000 options were outstanding under the Directors’ Plan at exercise prices ranging from $2.81 to $11.30 a share. No further options will be granted under this plan.

     We maintain the 1989 Stock Option Plan, or the 1989 Plan, which authorized the issuance of 3.0 million options. Options issued under the 1989 Plan vested over a three year period and expire in ten years. At June 30, 2005, 77,800 options remained outstanding under the 1989 Plan at exercise prices ranging from $2.62 to $7.62 a share. No options have been granted under the plan since March 1999. The last of these options expire in 2009.

     At June 30, 2005, 5.1 million options were outstanding at exercise prices of $1.94 to $23.28 a share as follows:

						Active								Inactive
										Non-
Range of		Average				2005				Employee				1999				Director’s				1989
Exercise Prices		Exercise Price				Plan				Plan				Plan				Plan				Plan				Total
$  1.94 - $  4.99		$	3.52				—				—				374,535				48,000				72,500				495,035
5.00 -     9.99			5.83				—				—				1,923,926				136,000				5,300				2,065,226
10.00 -   14.99			10.54				—				—				1,144,860				48,000				—				1,192,860
15.00 -   19.99			16.17				—				—				297,200				—				—				297,200
20.00 -   23.28			23.20				—				56,000				978,350				—				—				1,034,350
Total							—				56,000				4,718,871				232,000				77,800				5,084,671

     In 1997, shareholders approved a stock purchase plan where up to 1.75 million shares of common stock can be sold to directors, employees and consultants. Under the stock purchase plan, the right to purchase shares may be granted at prices ranging from 50% to 85% of market value. To date, all purchase rights have been granted at 75% of market. At June 30, 2005, there were no rights outstanding to purchase shares.

     In May 2005, we issued 17,500 shares of restricted stock grants to directors with immediate vesting at an average price of $21.71. In 2004, we issued 80,900 shares of restricted stock grants to directors and employees at an average price of $11.90. The restricted grants included 24,000 issued to directors (with immediate vesting) and 56,900 to employees with vesting over a three year period. During 2003, we issued 234,000 restricted stock grants to directors and employees at an average price of $6.40. The restricted grants included 136,000 issued to directors (with immediate vesting) and 98,000 to employees with vesting over a three year period. We recorded compensation expense based upon the fair market value of the shares on the date of grant of $348,000 and $233,000 during the six month periods ended June 30, 2005 and 2004 related to these grants, respectively. Effective July 1, 2005, an additional 36,200 restricted stock grants were issued to employees at an average price of $26.90.

(11) DEFERRED COMPENSATION

     In 1996, the Board of Directors adopted a deferred compensation plan, or the Plan. The 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 our

common stock or makes other investments at the employee’s discretion. Great Lakes also had a deferred compensation plan that allowed officers and key employees to defer all or a portion of their salaries and bonuses and invest such amounts in certain investments at the employee’s discretion. In December 2004, in connection with changes to regulations governing deferred compensation plans, we adopted the Range Resources Corporation Deferred Compensation Plan, or the 2005 Deferred Compensation Plan. The 2005 Deferred Compensation Plan is intended to operate in a manner substantially similar to the old plans, subject to new requirements and changes mandated under Section 409A of the Internal Revenue Code. The old plans were frozen and will not receive additional contributions. The assets of the all of the plans are held in rabbi trusts, or the Rabbi Trusts, and are 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 general and administrative expense on our consolidated statement of operations. The assets of the Rabbi Trust, other than 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 Trust. The cost of common stock held in the Rabbi Trust is shown as a reduction to stockholders’ equity. Changes in the market value of the marketable securities are reflected in OCI, while changes in the market value of the common stock held in the Rabbi Trust is charged or credited to general and administrative expense each quarter. We recorded mark-to-market expense related to deferred compensation of $5.3 million and $4.3 million in the three months ended June 30, 2005 and 2004, respectively and $9.3 million and $8.7 million in the six months ended June 30, 2005 and 2004, respectively.

(12) BENEFIT PLAN

     We maintain a 401(k) plan for our employees that permit employees to contribute a portion of their salary, subject to Internal Revenue Service limitations. Historically, we have made discretionary contributions of our common stock to the 401(k) plan annually. In 2005, we began matching employee contributions up to 3% of salary in cash. Great Lakes also had a 401(k) in which their contributions were made in cash. Also in 2005, the Great Lakes 401(k) plan was merged into the Range plan. All of our contributions become fully vested after the individual employee has three years of service with us. In 2004, 2003 and 2002, we contributed $1.2 million, $912,000 and $877,000 respectively, to the 401(k) plan. We do not require that employees hold contributed Range stock in their account. Employees have a variety of investment options in the 401(k) plan and may, at any time, diversify out of our stock based on their personal investment strategy.

(13) INCOME TAXES

     The significant components of deferred tax liabilities and assets on June 30, 2005 and December 31, 2004 were as follows (in thousands):

		June 30,				December 31,
		2005				2004
Deferred tax assets (liabilities)
Net unrealized loss in OCI		$	48,830			$	25,930
Other			86,787				107,809
Depreciation and depletion			(250,418	)			(225,142	)
Net deferred tax liability		$	(114,801	)		$	(91,403	)

     At December 31, 2004, we had regular net operating loss, or NOL, carryovers of $237.2 million and alternative minimum tax, or AMT, NOL carryovers of $205.9 million that expire between 2012 and 2023. At December 31, 2004, we had AMT credit carryovers of $1.8 million that are not subject to limitation or expiration.

(14) COMPUTATION OF EARNINGS PER 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,
		2005				2004				2005				2004
Numerator:
Net income		$	21,661			$	8,189			$	43,664			$	14,809
Preferred dividends			—				(737	)			—				(1,475	)
Numerator for basic and diluted earnings per share		$	21,661			$	7,452			$	43,664			$	13,334
Denominator:
Weighted average shares outstanding			82,492				58,988				81,926				57,817
Stock held in the deferred compensation plan and treasury shares			(1,375	)			(1,673	)			(1,408	)			(1,672	)
Weighted average shares, basic			81,117				57,315				80,518				56,145
Effect of dilutive securities:
Weighted average shares outstanding			82,492				58,988				81,926				57,817
Employee stock options and other			1,737				1,257				1,673				1,131
Treasury shares			(56	)			—				(28	)			—
Dilutive potential common shares for diluted earnings per share			84,173				60,245				83,571				58,948
Earnings per common share:
— Basic		$	0.27			$	0.13			$	0.54			$	0.24
— Diluted		$	0.26			$	0.12			$	0.52			$	0.23

     Options to purchase 6,000 shares of common stock were outstanding but not included in the computations of diluted net income per share for the six months ended June 30, 2004 because the exercise prices of the options were greater than the average market price of the common shares and would be anti-dilutive to the computations. Prior to its redemption in December 2004, 5.9 million shares of Convertible Preferred were excluded from the dilutive calculation for the quarter and the six months ended June 30, 2004 as the effect was antidilutive.

(15) MAJOR CUSTOMERS

     We market our production on a competitive basis. Gas is sold under various types of contracts including month-to-month, one-to-five year contracts or short-term contracts that are cancelable within 30 days. The price for oil is generally equal to a posted price set by major purchasers in the area. We sell to oil purchasers on the basis of price and service and may be changed on 30 days notice. For the six months ended June 30, 2005, four customers accounted for 10% or more of total oil and gas revenues and the combined sales to those four customers accounted for 15%, 12%, 10% and 10% of total oil gas revenues, respectively. We believe that the loss of any one customer would not have a material long-term adverse effect on our results.

(16) OIL AND GAS ACTIVITIES

     The following summarizes selected information with respect to producing activities. Exploration costs include capitalized as well as expensed outlays (in thousands):

		June 30,				December 31,
		2005				2004
Oil and gas properties:
Properties subject to depletion		$	2,346,275			$	2,082,236
Unproved properties			20,859				14,790
Total			2,367,134				2,097,026
Accumulated depletion			(749,344	)			(694,667	)
Net		$	1,617,790			$	1,402,359

		Six Months				Twelve Months
		Ended				Ended
		June 30,				December 31,
		2005				2004
Costs incurred:
Acquisitions:
Acreage purchases		$	8,585			$	9,690
Unproved leasehold acquired			—				4,043
Proved oil and gas properties			127,376				522,126
Purchase price adjustment (a)			22,779				79,352
Asset retirement obligations			119				17,524
Subtotal			158,859				632,735
Development			103,334				144,007
Exploration (b)			19,974				31,830
Gas gathering facilities
Acquisitions			—				15,539
Development			2,887				4,778
Subtotal			285,054				828,889
Asset retirement obligations			289				3,994
Total		$	285,343			$	832,883

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

     Our discussion and analysis of our financial condition and results of operations are based upon unaudited consolidated financial statements, which have been prepared in accordance with accounting principles generally adopted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the amounts reported in the financial statements and related footnote disclosures. Application of certain of our accounting policies, including those related to oil and gas revenues, bad debts, oil and gas properties, income taxes, marketable securities, fair value of derivatives, asset retirement obligations, contingencies and litigation require significant estimates. We base our estimates on historical experience and various assumptions that are believed to be reasonable under the circumstances. Actual results may differ from these estimates. We believe the following critical accounting policies reflect our more significant judgments and estimates used in the preparation of our financial statements.

     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 as established by the SEC, the estimation of reserves requires the engineers to make a significant number of assumptions based on professional judgment. Reserves estimates are updated at least annually and consider recent production levels and other technical information. Estimated reserves are often subject to future revision, 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.

     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 costs capitalized. 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 its oil and gas producing activities and the reserve quantities annual disclosure in our consolidated financial statements. Changes in the estimated reserves are considered changes in estimates for accounting purposes and are reflected on a prospective basis.

     We utilize the successful efforts method to account for exploration and development expenditures. Unsuccessful exploration wells 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. Proven property leasehold costs are charged to expense using the units of production method based on total proved reserves. Unproved properties are assessed periodically and impairments to value are charged to expense.

     We monitor our long-lived assets recorded in property, plant and equipment in our consolidated balance sheet to ensure that they are fairly presented. We must evaluate each property 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 gas sales prices, an estimate of the ultimate amount of recoverable oil and natural gas reserves that will be produced, the timing of future production, future production 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, 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 use commodity derivative contracts to manage our exposure to oil and gas price volatility. We account for our commodity derivatives in accordance with Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities,” or SFAS 133. 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, or OCI, and then reclassified to earnings in oil and gas revenue, when the 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.

     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 drilling and production enhancement programs, more consistent returns on invested capital, and better access to bank and other credit markets. We also have some interest rate swap agreements to protect against the volatility of variable interest rates under our bank credit facility.

     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.

     Asset retirement obligations are not unique to us or to the oil and gas industry and in 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations,” or SFAS 143. We adopted this statement effective January 1, 2003, as discussed in Note 3 to our consolidated financial statements. SFAS 143 significantly changed the method of accruing for costs an entity is legally obligated to incur related to the retirement of fixed assets, or asset retirement obligations or ARO. Primarily, the new statement requires us to record a separate liability for the fair value of our asset retirement obligations, with an offsetting increase to the related oil and gas properties on our consolidated balance sheet.

     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 ARO liability, 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 will be reflected as accretion expense in our consolidated statement of operations.

     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 months after the close of a calendar year, tax returns are subject to audit which can often take years to complete and settle 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 carry forwards and other deductible differences. We routinely evaluate our deferred tax assets to determine the likelihood of their realization. A valuation allowance is recognized for deferred tax assets when we believe that certain of these assets are not likely to be realized.

     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. Currently, none of our consolidated tax returns is under audit or review by the IRS.

     A provision for legal, environmental, and other contingent matters is charged to expense when the loss is probable and the 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 interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental and other contingent matters, and make our best estimate of when we should record losses for these 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.

     We periodically assess the recoverability of all material trade and other receivables to determine their collectability. At IPF, receivables are evaluated quarterly and provisions for uncollectible amounts are established. Such provisions for uncollectible amounts are recorded when we believe that a receivable is not recoverable based on current estimates of expected discounted cash flows and other factors which could affect the collection.

     We recognize revenues from the sale of products and services in the period delivered. We use the sales method to account for gas imbalances, recognizing revenue based on cash received rather than gas produced. Revenues are sensitive to changes in prices received for our products. A substantial portion of production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control. Changes in the imbalances in the supply and demand for oil and gas can have dramatic effects on prices. Political instability and availability of alternative fuels could impact worldwide supply, while economic factors can impact demand. At IPF, payments believed to relate to return are recognized as income. Currently, all IPF receipts are being recognized as a return of capital.

     We recognize a write down of marketable securities when the decline in market value is considered to be other than temporary. Third party reimbursements for administrative overhead costs incurred due to our role as an operator of oil and gas properties are applied to reduce general and administrative expense. Salaries and other employment costs of those employees working on our exploration efforts are expensed as exploration expense. We do not capitalize general and administrative expense or interest expense.

Liquidity and Capital Resources

     During the six months ended June 30, 2005, our cash provided from operations was $143.4 million and we spent $285.3 million on development, exploration and acquisitions. During this period, financing activities provided net cash of $91.8 million. Our financing activity included the sale in March 2005 of $150.0 million of 6-3/8% Notes, which enabled us to better match the maturities of our debt with the life of our properties and decrease our interest rate volatility. In addition, in June 2005, we issued 4.6 million common shares in a public offering for net proceeds of $109.4 million. At June 30, 2005, we had $4.9 million in cash, total assets of $1.8 billion and a debt-to-capitalization ratio of 47.3%. Long-term debt at June 30, 2005 totaled $612.5 million including $265.7 million of bank credit facility debt, $196.8 million of 7-3/8% Notes and $150.0 million of 6-3/8% Notes. Available borrowing capacity at June 30, 2005 was $334.3 million under the bank credit facility.

     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 the 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 industry. 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, 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.

     The debt agreements contain covenants relating to working capital, dividends and financial ratios. We were in compliance with all covenants at June 30, 2005. 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 $338.7 million was available under the bank credit facility’s restricted payment basket on June 30, 2005. The terms of the 6-3/8% Notes and the 7-3/8% 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 $395.8 million was available under both the 6-3/8% Notes and the 7-3/8% Notes restricted payment basket on June 30, 2005.

     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, 2005, we have entered into hedging swap agreements covering 14.9 Bcf of gas, 0.4 million barrels of oil and 0.1 million barrels of NGLs. We also have collars covering 55.1 Bcf of gas and 4.3 million barrels of oil. Net cash provided by operations for the six months ended June 30, 2005 and 2004 was $143.4 million and $81.4 million, respectively. Cash flow from operations was higher than the prior year due to higher prices and volumes, partially offset by higher direct operating and interest expenses. Net cash used in investing for the six months ended June 30, 2005 and 2004 was $248.6 million and $312.0 million, respectively. The 2005 period includes $109.3 million of additions to oil and gas properties and $137.0 million of acquisitions. The 2004 period included $62.2 million of additions to oil and gas properties and $253.6 million of acquisitions. Net cash provided by financing for the six months ended June 30, 2005 and 2004 was $91.8 million and $237.6 million, respectively. This decrease was primarily the result of the 2004 issuance of an additional $100.0 million of our 7-3/8% Notes and higher proceeds received in 2004 from equity offerings. In 2004, we sold 12.2 million shares resulting in net proceeds of $142.9 million. In 2005, we sold 4.6 million shares resulting in net proceeds of $109.4 million. During the first six months of 2005, total debt decreased $8.1 million.

     On June 1, 2005, the Board of Directors declared a dividend of two cents per share ($1.6 million) on our common stock, payable on June 30, 2005 to stockholders of record at the close of business on June 10, 2005.

     The 2005 capital budget is currently set at $261.0 million (excluding acquisitions) and based on current projections, the capital budget is expected to be funded with internal cash flow. During the six months ended June 30, 2005, $123.3 million of development and exploration spending was funded with internal cash flow.

     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 25, 2005, the bank credit facility had a $600.0 million borrowing base of which $311.6 million was available.

     We enter into hedging agreements to reduce the impact of oil and gas price volatility on our operations. At June 30, 2005, swaps were in place covering 14.9 Bcf of gas at prices averaging $5.26 per Mmbtu, 0.4 million barrels of oil at prices averaging $30.18 per barrel and 0.1 million barrels of NGLs at prices averaging $19.20 per barrel. We also have collars covering 55.1 Bcf of gas at prices of $5.14 to $9.54 per mcf and 4.3 million barrels of oil at prices of $29.84 to $58.44 per barrel. Their fair value at June 30, 2005 (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 $133.4 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. Net decreases to oil and gas revenues from realized hedging were $43.3 million and $40.1 million for the six months ended June 30, 2005 and 2004, respectively.

     At June 30, 2005, the following commodity derivative contracts were outstanding:

				Volume		Average Hedge
Contract Type		Period		Hedged		Price
Natural gas
Swaps		July-December 2005		44,793 MMBtu/day		$4.17
Swaps		2006		10,788 MMBtu/day		$6.43
Swaps		2007		7,500 MMBtu/day		$6.86
Collars		July-December 2005		69,397 MMBtu/day		$5.14-$7.09
Collars		2006		78,363 MMBtu/day		$5.63-$8.79
Collars		2007		37,500 MMBtu/day		$5.90-$9.54
Crude oil
Swaps		July-December 2005		1,143 Bbl/day		$26.83
Swaps		2006		400 Bbl/day		$35.00
Collars		July-December 2005		4,414 Bbl/day		$29.84-$37.05
Collars		2006		6,464 Bbl/day		$38.69-$47.87
Collars		2007		3,200 Bbl/day		$48.71-$58.44
Natural gas liquids
Swaps		July-December 2005		652 Bbl/day		$19.20

     At June 30, 2005, we had $612.5 million of debt outstanding. Of this amount, $346.8 million bore interest at fixed rates averaging 6.9%. Bank debt totaling $265.7 million bears interest at floating rates, which average 4.3% at June 30, 2005. At times, we enter into interest rate swap agreements to limit the impact of interest rate fluctuations on our floating rate debt. At June 30, 2005, we had interest rate swap agreements totaling $35.0 million. These swaps consist of two agreements at 1.8% which expire in June 2006. The fair value of the swaps, based on then current quotes for equivalent agreements at June 30, 2005 was a net gain of $641,000. The 30 day LIBOR rate on June 30, 2005 was 3.3%.

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 changes in oil and gas prices. Oil and gas prices are subject to significant fluctuations that are beyond our ability to control or predict. During the second quarter of 2005, we received an average of $48.79 per barrel of oil and $6.42 per mcf of gas before hedging compared to $35.87 per barrel of oil and $5.56 per mcf of gas in the same period of the prior year. Although certain of our costs and expenses are affected by general inflation, inflation does not normally have a significant effect on us. During 2004, we experienced an overall increase in drilling and operational costs when compared to the prior year. Increases in commodity prices can cause inflationary pressures specific to the industry to also increase certain costs. We expect an increase in these costs during the next twelve months.

     Volumes and sales data:

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2005				2004				2005				2004
Production:
Crude oil (bbls)			723,441				586,074				1,434,524				1,132,859
NGLs (bbls)			247,354				238,336				496,297				469,411
Natural gas (mcfs)			15,363,873				11,585,072				30,198,139				23,061,527
Total (mcfe)			21,188,643				16,531,529				41,783,065				32,675,147
Average daily production:
Crude oil (bbls)			7,950				6,440				7,926				6,224
NGLs (bbls)			2,718				2,619				2,742				2,579
Natural gas (mcfs)			168,834				127,308				166,840				126,712
Total (mcfe)			232,842				181,665				230,846				179,534
Average sales prices (excluding hedging):
Crude oil (per bbl)		$	48.79			$	35.87			$	47.94			$	34.08
NGLs (per bbl)		$	28.67			$	22.18			$	27.13			$	21.75
Natural gas (per mcf)		$	6.42			$	5.57			$	6.20			$	5.39
Total (per mcfe)		$	6.65			$	5.49			$	6.45			$	5.30
Average sales price (including hedging):
Crude oil (per bbl)		$	35.94			$	27.11			$	36.08			$	25.79
NGLs (per bbl)		$	25.33			$	19.71			$	23.88			$	19.36
Natural gas (per mcf)		$	5.63			$	4.05			$	5.38			$	4.10
Total (per mcfe)		$	5.60			$	4.09			$	5.41			$	4.07

     The following table identifies certain items included in our results of operations and is presented to assist in comparing the second quarter and six months of 2005 to the same periods of the prior year. The table should be read in conjunction with the following discussion of results of operations (in thousands):

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2005				2004				2005				2004
Increase (decrease) in revenues:
Ineffective portion of commodity hedges gain (loss)		$	123			$	971			$	248			$	(583	)
Gains (losses) from sale of assets			25				11				16				10
Net adjustment to IPF valuation allowance			(225	)			(305	)			(450	)			(834	)
Realized hedging losses			(22,330	)			(23,245	)			(43,266	)			(40,141	)
		$	(22,407	)		$	(22,568	)		$	(43,452	)		$	(41,548	)
Increase (decrease) to expenses:
Mark-to-market deferred compensation adjustment		$	5,276			$	4,303			$	9,343			$	8,688
Ineffective interest rate swaps			137				(320	)			(46	)			(1,119	)
		$	5,413			$	3,983			$	9,297			$	7,569