Range Resources - 10-Q quarterly report FY

 

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(Exact Name of Registrant as Specified in Its Charter)

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

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

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

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

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

     These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Range Resources Corporation 2005 Annual Report on Form 10-K. These consolidated financial statements are unaudited but, in the opinion of management, reflect all adjustments necessary for fair presentation of the results for the periods presented. All adjustments are of a normal recurring nature unless disclosed otherwise. These consolidated financial statements, including selected notes, have been prepared in accordance with the applicable rules of the Securities and Exchange Commission (the SEC) and do not include all of the information and disclosures required by accounting principles generally accepted in the United States for complete financial statements. All common stock shares, treasury stock shares and per-share amounts have been adjusted to reflect the three-for-two stock split effected on December 2, 2005.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

     In December 2004, we adopted the Range Resources Corporation Deferred Compensation Plan, or the 2005 Deferred Compensation Plan. The 2005 Deferred Compensation Plan gives directors, officers and key employees the ability to defer all or a portion of their salaries and bonuses and invests such amounts in Range common stock or makes other investments at the individual’s discretion. The assets of the plan are held in a rabbi trust, which we refer to as the Rabbi Trust, and are therefore

available to satisfy the claims of our creditors in the event of bankruptcy or insolvency. Our stock held in the Rabbi Trust is treated in a manner similar to treasury stock with an offsetting amount reflected as a deferred compensation liability and the carrying value of the deferred compensation liability is adjusted to fair value each reporting period by a charge or credit to non-cash stock compensation expense on our consolidated statement of operations. The assets of the Rabbi Trust, other than Range common stock, are invested in marketable securities and reported at market value in other assets on our consolidated balance sheet. The deferred compensation liability on our balance sheet reflects the market value of the securities held in the Rabbi Trusts. The cost of common stock held in the Rabbi Trusts is shown as a reduction to stockholders’ equity. Changes in the market value of the marketable securities are reflected in other comprehensive income, or OCI, while changes in the market value of the Range common stock held in the Rabbi Trust is charged or credited to non-cash stock compensation expense each quarter. Based on end of quarter stock prices of $27.19 and $26.90, we recorded non-cash mark-to-market (income) expense related to deferred compensation of $(2.1) million and $5.3 million in the three months ended June 30, 2006 and 2005, respectively and $2.4 million and $9.3 million in the six months ended June 30, 2006 and 2005, respectively.

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

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

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

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

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

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

     Volumes and sales data:

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

     Cash is required to fund capital expenditures necessary to offset inherent declines in production and proven reserves which is typical in the capital-intensive extractive industry. Future success in growing reserves and production will be highly dependent on capital resources available and the success of finding or acquiring additional reserves. We believe that net cash generated from operating activities and unused committed borrowing capacity under the bank credit facility combined with our oil and gas price hedges currently in place will be adequate to satisfy near-term financial obligations and liquidity needs. However, long-term cash flows are subject to a number of variables including the level of production and prices as well as various economic conditions that have historically affected the oil and gas business. A material drop in oil and gas prices or a reduction in production and reserves would reduce our ability to fund capital expenditures, reduce debt, meet financial obligations and remain profitable. We operate in an environment with numerous financial and operating risks, including, but not limited to, the inherent risks of the search for, development and production of oil and gas, the ability to buy properties and sell production at prices which

provide an attractive return and the highly competitive nature of the industry. Our ability to expand our reserve base is, in part, dependent on obtaining sufficient capital through internal cash flow, bank borrowings or the issuance of debt or equity securities. There can be no assurance that internal cash flow and other capital sources will provide sufficient funds to maintain capital expenditures that we believe are necessary to offset inherent declines in production and proven reserves.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

July 27, 2006