Range Resources - 10-Q quarterly report FY

 

(Mark one)

(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

     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yesþ          No o

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

Large Accelerated Filer þ          Accelerated Filer o          Non-Accelerated Filer o

     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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148,015,600 Common Shares were outstanding on April 24, 2007.

     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 2006 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 (“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. Certain reclassifications have been made to the presentation of prior periods to conform to current year presentation.

     During the first quarter of 2007, we sold our interests in the following oil and gas assets:

     In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” we have reflected the results of operations of the above divestitures as discontinued operations, rather than a component of continuing operations. See Note 4 for additional information regarding discontinued operations.

     Acquisitions are accounted for as purchases, and accordingly, the results of operations are included in our consolidated statements of operations from the closing 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 $49.0 million in the first three months of 2007 compared to $10.0 million during the three months ended March 31, 2006. The purchases included $31.4 million and $335,000 for proved oil and gas reserves for the three months ended March 31, 2007 and 2006, respectively, with the remainder representing acreage purchases.

     In June 2006 we acquired Stroud Energy, Inc. (“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 Stroud, we paid $171.5 million of cash and issued 6.5 million shares of our common stock.

     The following table summarizes the final purchase price allocation of fair values of assets acquired and liabilities assumed at closing (in thousands):

     The following unaudited pro forma data includes the results of operations as if the Stroud acquisition had been consummated at the beginning of 2006. See also Note 4 for discontinued operations. 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).

     In February 2007, we sold our Austin Chalk properties for proceeds of $80.4 million. These properties were originally acquired in mid-2006 as part of our Stroud acquisition and were classified as assets held for sale since the acquisition date. On March 30, 2007, we sold our Gulf of Mexico properties for proceeds of $155.0 million. The properties included our interests in 37 platforms in water depths ranging from 11 to 240 feet. None of these Gulf of Mexico properties were operated by Range. Both dispositions are subject to typical post-closing adjustments (see also Note 4).

     As part of the Stroud acquisition, we purchased Austin Chalk properties in Central Texas which we sold in February 2007 for proceeds of $80.4 million. As of March 30, 2007, we sold our Gulf of Mexico properties for proceeds of $155.0 million. Discontinued operations for the three months ended March 31, 2007 and 2006 are summarized as follows (in thousands):

     The significant components of deferred tax liabilities and assets on March 31, 2007 and December 31, 2006 were as follows (in thousands):

     At December 31, 2006, we had regular net operating loss (“NOL”) carryovers of $229.6 million and alternative minimum tax (“AMT”) NOL carryovers of $192.4 million that expire between 2012 and 2026. At December 31, 2006, we had AMT credit carryovers of $700,000 that are not subject to limitation or expiration. We anticipate that a significant portion of our NOL will be used in conjunction with the sale of our Gulf of Mexico properties.

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

     Stock appreciation rights for 525,975 shares were outstanding but not included in the computations of diluted net income per share for the three months ended March 31, 2007 because the grant prices of the SARs were greater than the average market price of the common shares and would be anti-dilutive to the computations.

     The following table reflects the changes in capitalized exploratory well costs for the three months ended March 31, 2007 and the year ended December 31, 2006 (in thousands):

     The $8.4 million of capitalized exploratory well costs at March 31, 2007 was incurred in 2007 ($3.9 million) and in 2006 ($4.5 million).

     We had the following debt outstanding as of the dates shown below (in thousands) (bank debt interest rate at March 31, 2007 is shown parenthetically). No interest expense was capitalized during the three months ended March 31, 2007 and 2006.

     In October 2006, we entered into an amended and restated $800.0 million revolving bank facility, which we refer to as our bank debt or bank credit facility, which is secured by substantially all of our assets. The bank credit facility provides for an initial commitment equal to the lesser of an $800.0 million facility amount or the borrowing base. On March 23, 2007, the facility amount was increased to $900.0 million and the borrowing base was redetermined as $1.2 billion. The bank credit facility provides for a borrowing base subject to redeterminations semi-annually each April and October and pursuant to certain unscheduled redeterminations. Subject to certain conditions, the facility amount may be increased to the borrowing base amount with twenty days notice. At March 31, 2007, the outstanding balance under the bank credit facility was $537.5 million and there was $362.5 million of borrowing capacity available. On March 30, 2007, we received cash proceeds of $155.0 million from the sale of our Gulf of Mexico properties. These proceeds were used to pay down the credit facility in April. The loan matures October 25, 2011. 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 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 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 6.4% for the three months ended March 31, 2007 compared to 5.6% for the three months ended March 31, 2006. A commitment fee is paid on the undrawn balance based on an annual rate of between 0.25% and 0.375%. At March 31, 2007, the commitment fee was 0.25% and the interest rate margin was 1.0%. At April 24, 2007, the interest rate (including applicable margin) was 7.0%.

     In 2003, we issued $100.0 million aggregate principal amount of 7.375% senior subordinated notes due 2013 (“7.375% Notes”). In 2004, we issued an additional $100.0 million of 7.375% Notes; therefore, $200.0 million of the 7.375% Notes are currently outstanding. The 7.375% Notes were issued at a discount which will be amortized into interest expense over the life of the 7.375% Notes. In 2005, we issued $150.0 million of 6.375% senior subordinated notes due 2015 (“6.375% Notes”). In May 2006, we issued $150.0 million of the 7.5% senior subordinated notes due 2016 (“7.5% Notes”). In August 2006, we issued an additional $100.0 million of the 7.5% Notes; therefore, $250.0 million of the 7.5% Notes are currently outstanding. Interest on our senior subordinated notes is payable semi-annually and each of the notes are guaranteed by certain of our subsidiaries.

     We may redeem the 7.375% Notes, in whole or in part, at any time on or after July 15, 2008, at redemption prices of 103.7% of the principal amount as of July 15, 2008, and declining to 100.0% on July 15, 2011 and thereafter. We may redeem the 6.375% 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 6.375% 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. We may redeem the 7.5% 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 7.5% 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 7.5% 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 repurchase all or a portion of the senior subordinated notes at 101% of the principal amount plus accrued and unpaid interest, if any. All of the senior subordinated notes and the guarantees by our subsidiary guarantors are general, unsecured obligations and are subordinated to our bank debt and will be subordinated to future senior debt that we or our subsidiary guarantors are permitted to incur under the bank credit facility and the indentures governing the subordinated notes.

     Range Resources Corporation is a holding company which owns no operating assets and has no significant operations independent of its subsidiaries. The guarantees of the 7.5% Notes, the 7.375% Notes and the 6.375% Notes are full and unconditional and joint and several; any subsidiaries other than the subsidiary guarantors are minor subsidiaries.

     The debt agreements contain covenants relating to working capital, dividends and financial ratios. We were in compliance with all covenants at March 31, 2007. 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 $482.2 million was available under the bank credit facility’s restricted payment basket on March 31, 2007. The terms of each of our subordinated notes limit restricted payments (including dividends) to the greater of $20.0 million or a formula based on earnings and equity issuances since the original issuance of the notes. The 7.5% Notes also allows for any cash proceeds received from the sale of oil and gas property purchased in the Stroud acquisition to be added to the restricted payment basket. At March 31, 2007, $559.1 million was available under the restricted payment baskets for each of the 7.375% Notes and the 6.375% Notes. There was $640.1 million available under the 7.5% Notes restricted payment basket.

     A reconciliation of our liability for plugging and abandonment costs for the three months ended March 31, 2007 and 2006 is as follows (in thousands):

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

     We have authorized capital stock of 260 million shares, which includes 250 million shares of common stock and 10 million shares of preferred stock. The following is a schedule of changes in the number of common shares outstanding:

     The Board of Directors has approved up to $10.0 million of repurchases of common stock based on market conditions and opportunities.

     At March 31, 2007, we had open swap contracts covering 66.2 Bcf of gas at prices averaging $9.18 per mcf. We also had collars covering 47.2 Bcf of gas at weighted average floor and cap prices which range from $7.28 to $10.35 per mcf and 5.9 million barrels of oil at weighted average floor and cap prices that range from $57.76 to $72.53 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 (“NYMEX”), on March 31, 2007, was a net unrealized pre-tax gain of $21.6 million. These contracts expire monthly through December 2009. Transaction gains and gains on settled contracts are determined monthly and are included as increases or decreases to oil and gas revenues in the period the hedged production is sold. Oil and gas revenues were increased by gains of $35.5 million in the first three months of 2007 compared with losses of $17.1 million in the three months ended March 31, 2006. Other revenues in our consolidated statement of operations include ineffective hedging losses on hedges that qualified for hedge accounting of $219,000 in the first three months of 2007 compared with gains of $1.4 million in the three months ended March 31, 2006. In the fourth quarter of 2005, certain of our gas hedges no longer qualified for hedge accounting and are marked to market. This resulted in a loss of $66.1 million in the first quarter of 2007 compared to a gain of $11.3 million in the first three months of 2006.

     The following table sets forth our derivative volumes by year as of March 31, 2007:

     The combined fair values of net unrealized gains on oil and gas derivatives totaled $21.6 million and appear as 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.

     We have six equity-based stock plans, of which two are active. Under the active plans, incentive and non-qualified options, stock appreciation rights (“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. All awards granted have been issued at prevailing market prices at the time of the grant. 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 March 31, 2007:

     The weighted average fair value of an option/SAR to purchase one share of common stock granted during 2007 was $10.00. The fair value of each stock option/SAR granted during 2007 was estimated as of the date of grant using the Black-Scholes-Merton option pricing model based on the following assumptions: risk-free interest rate of 4.72%; dividend yield of 0.38%; expected volatility of 36%; and an expected life of 3.55 years.

     As of March 31, 2007, the aggregate intrinsic value (the difference in value between exercise and market price) of the awards outstanding was $168.1 million. The aggregate intrinsic value and weighted average remaining contractual life of stock option awards currently exercisable was $132.7 million and 2.84 years. As of March 31, 2007, the number of fully-vested awards and awards expected to vest was 8.9 million. The weighted average exercise price and weighted average remaining contractual life of these awards were $14.68 and 3.2 years and the aggregate intrinsic value was $166.2 million. As of March 31, 2007, unrecognized compensation cost related to the awards was $22.9 million, which is expected to be recognized over a weighted average period of 1.4 years.

     During the first quarter of 2007, 10,000 shares of restricted stock were issued to employees at an average price of $31.00 and have a three-year vesting period. In the first quarter of 2006, we issued 328,600 shares of restricted stock as compensation to directors and employees at an average price of $24.32. We recorded compensation expense related to restricted stock grants which is based upon the market value of the shares on the date of grant of $1.2 million in the first three months of 2007 compared to $472,000 in the three-month period ended March 31, 2006. As of March 31, 2007, unrecognized compensation cost related to these restricted stock awards was $11.5 million, which is expected to be recognized over the next 3 years.

     In December 2004, we adopted the Range Resources Corporation Deferred Compensation Plan (“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 deferred compensation plan 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 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 other comprehensive income (“OCI”), while changes in the market value of the Range common stock held in the Rabbi Trust is charged or credited to deferred compensation plan expense each quarter. We recorded non-cash mark-to-market expense related to our deferred compensation plan of $11.2 million in the first three months of 2007 compared to $4.5 million in the three months ended March 31, 2006.

     We are involved in various legal actions and claims arising in the ordinary course of our business. While the outcome of these lawsuits cannot be predicted with certainty, we do not expect these matters to have a material adverse effect on our financial position, cash flows or results of operations.

     In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN48”). FIN 48 is an interpretation of FASB Statement No. 109, “Accounting for Income Taxes,” and seeks to reduce the diversity in practice associated with certain aspects of measurement and recognition in accounting for income taxes. In addition, FIN 48 provides guidance on de-recognition, classification, interest and penalties, and accounting in interim periods and requires expanded disclosure with respect to the uncertainty in income taxes.

     We adopted the provisions of FIN 48 on January 1, 2007. There was no cumulative effect as a result of applying FIN 48. No adjustment was made to our opening balance of retained earnings. We have approximately $600,000 of unrecognized tax benefits recorded as of the date of adoption.

     We file consolidated and separate income tax returns in the United States federal jurisdiction and in many state jurisdictions. We are subject to US Federal income tax examinations for years after 2002 and we are subject to various state tax examinations for years after 2001.

     Our continuing practice is to recognize interest related to income tax expense in interest expense and penalties in general and administrative expense. We do not have any accrued interest or penalties as of March 31, 2007.

     On April 13, 2007, we entered into certain agreements, with certain subsidiaries of Equitable Resources, Inc. (“Equitable”), with respect to a development plan for the Nora field, a gas field located in southwestern Virginia. Range and Equitable both own interests in the Nora field, which currently encompasses approximately 1,600 producing wells and 300,000 gross acres. Under the plan, Equitable and Range will equalize their interests in the Nora field, including the producing wells, undrilled acreage and a gathering system. We entered into a Purchase and Sale Agreement (the “Purchase Agreement”), pursuant to which we will acquire one-half of Equitable’s interest in leases on the Nora field (subject to specific exclusions) as well as new and additional incremental interest in existing wells in the Nora field (the “Acquisition”). The oil and gas property Acquisition purchase price is $262 million, subject to certain adjustments. The pipeline and

gathering system acquisition price is $53.0 million. The Purchase Agreement contains customary representations, warranties and covenants by each of Range and Equitable.

     The Purchase Agreement is subject to termination by mutual agreement of Range and Equitable, by either party if the Acquisition is not closed by June 12, 2007, or by either party if (subject to the other party’s right to cure) the representations and warranties of the other party contained in the Purchase Agreement shall not be true and correct in all material respects, or the other party breaches, in any material respect, any of its obligations under the Purchase Agreement.

     On April 17, 2007, we entered into an underwriting agreement to sell 7,000,000 shares of common stock at $36.28 per share, subject to an over-allotment option for a period of 30 days to purchase an additional 1,050,000 shares. The proceeds of the offering will be used to fund a portion of the Equitable transaction. Pending such use, the proceeds will be used to pay down a portion of the outstanding balance on our credit facility. On April 23, 2007, the underwriters exercised the over-allotment option, the offering of the common stock closed and we received $280.4 million of proceeds from the sale of 8,050,000 shares of common stock.

     The following discussion should be read in conjunction with management’s discussion and analysis contained in our 2006 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 2006 Annual Report on Form 10-K and subsequent filings. Except where noted, discussions in this report relate to our continuing operations.

     The preparation of financial statements in accordance with generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Actual results could differ from the estimates and assumptions used. There have been no significant changes to our critical accounting estimates or policies subsequent to December 31, 2006.

     Revenues decreased 15% for the first quarter of 2007 over the same period of 2006. This decrease is due to an unfavorable mark-to-market value adjustment on oil and gas derivatives that do not qualify for hedge accounting partially offset by higher production and realized prices. For the first quarter of 2007, production increased 21% due to the continued success of our drilling program and our acquisitions. Realized oil and gas prices were higher by 8% in the first quarter of 2007 compared to the same period of 2006 reflecting the expiration of lower priced oil and gas hedges. Our remaining hedges increased revenue by $35.5 million in the first three months of 2007 compared to a decrease of $17.1 million in the same period of 2006.

     Higher production volumes and higher oil and gas prices have improved our profit margins. However, Range and the oil and gas industry as a whole continues to experience higher operating costs due to heightened competition for qualified employees, goods and services. On a unit cost basis, our direct operating costs increased $0.13 per mcfe, a 16% increase from the first quarter of 2006 to the first quarter of 2007. It is anticipated that service and personnel costs will remain high as oil and gas industry fundamentals remain favorable.

     On March 30, 2007, we sold our Gulf of Mexico properties. For the three months ended March 31, 2007 and 2006, these operations are shown in discontinued operations.

     Oil and gas revenue for the three months ended March 31, 2007 and 2006 (in thousands) is summarized in the following table:

     Average realized prices received for oil and gas during the first quarter of 2007 was $8.23 per mcfe, up 8% or $0.60 per mcfe from the same quarter of the prior year. The average price received in the first quarter for oil increased 20% to $55.99 per barrel and increased 5% to $8.22 per mcf for gas from the same period of 2006. The effect of our hedging program increased realized prices $1.35 per mcfe in the first quarter of 2007 versus a decrease of $0.78 per mcfe in the same period of 2006.

     Production volumes increased 21% from the first quarter of 2006 primarily due to continued drilling success and our acquisitions. Our production for the first quarter was 292.9 Mmcfe per day of which 61% was attributable to our Southwestern division, 36% to our Appalachian division and 3% to our Gulf Coast division.

     Mark-to-market on oil and gas derivatives includes a loss of $66.1 million in 2007 compared to a gain of $11.3 million in the same period of 2006. In the fourth quarter of 2005, certain of our gas hedges no longer qualified for hedge accounting due to the effect of gas price volatility on the correlation between realized prices and hedge reference prices. The loss of hedge accounting treatment creates volatility in our revenues as gains and losses from ineffective hedges are not included in other comprehensive income. Because gas prices increased in the first quarter, our hedges became comparatively less valuable. However, we expect these losses will be offset by higher revenues in the future.

     Transportation and gathering revenue of $184,000 increased $223,000 from 2006. This increase is primarily due to higher processing margins.

     Other revenue increased in 2007 to $1.7 million from $1.4 million in 2006. The 2007 period includes insurance proceeds of $1.0 million and income from equity method investments of $411,000 somewhat offset by $219,000 of ineffective hedging losses. Other revenue for 2006 includes $1.4 million of ineffective hedging gains.

     Our operating expenses have increased as we continue to grow. We believe most of our operating expense fluctuations are best analyzed on a unit-of-production, or per mcfe basis. The following presents information about our operating expenses on an mcfe basis for the three months ended March 31, 2007 and 2006:

     Direct operating expense (excluding stock-based compensation) increased $7.2 million in the first quarter of 2007 to $25.0 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 ($0.05 per mcfe) of workover costs in 2007 versus $599,000 ($0.03 per mcfe) in 2006. On a per mcfe basis, direct operating expenses (excluding stock-based compensation) increased $0.13 per mcfe from the same period of 2006 with the increase consisting primarily of higher water disposal costs ($0.07 per mcfe) and higher well service costs ($0.06 per mcfe).

     Production and ad valorem taxes are paid based on market prices, not hedged prices. These taxes increased $861,000 million or 9% from the same period of the prior year due to higher volumes offset by lower prices and assessed values. On a per mcfe basis, production and ad valorem taxes decreased to $0.39 per mcfe in 2007 from $0.44 per mcfe in the same period of 2006.

     General and administrative expense (excluding stock-based compensation) for the first quarter of 2007 increased $2.1 million from 2006 due to higher salaries and benefits ($1.5 million), higher office rent and general office expense ($211,000) and higher franchise taxes ($139,000). On a per mcfe basis, general and administration expense (excluding stock-based compensation) increased from $0.41 per mcfe in 2006 to $0.42 per mcfe in the first quarter 2007.

     Interest expense for the first quarter of 2007 increased $8.6 million to $18.8 million due to rising interest rates and the refinancing of certain debt from floating to higher fixed rates in the second and third quarters of 2006. In 2006, we issued $250.0 million of 7.5% Notes which added $4.7 million of interest costs in the first quarter of 2007. The proceeds from the issuance of the 7.5% Notes were used to retire lower interest bank debt and to better match the maturities of our debt with the life of our properties. Average debt outstanding on the bank credit facility for the first quarter of 2007 was $507.4 million compared to $278.6 million for the first quarter of 2006 and the average interest rates were 6.4% in the first quarter of 2007 compared to 5.6% in the same quarter of the prior year.

     Depletion, depreciation and amortization (“DD&A”) increased $15.7 million or 50% to $47.3 million in the first quarter of 2007 with a 21% increase in production and a 25% increase in depletion rates. The increase in DD&A per mcfe is related to our Stroud acquisition, increasing drilling costs and the mix of our production. On a per mcfe basis, DD&A increased from $1.45 per mcfe in the first quarter of 2006 to $1.80 per mcfe in the first quarter of 2007.

     Operating expenses also include stock-based compensation, exploration expense and non-cash deferred compensation plan expenses that generally do not trend with production. In 2006 and 2007, stock-based compensation represents the amortization of restricted stock grants and expenses related to the adoption of SFAS No. 123(R). In 2007, stock-based compensation is a component of direct operating expense ($398,000), exploration expense ($739,000), general and administrative expense ($3.6 million) and a $93,000 reduction of net gas transportation revenues for a total of $4.9 million. In 2006, stock-based compensation is a component of direct operating expense ($285,000), exploration expense ($609,000), general and administrative expense ($2.4 million) and a $65,000 reduction of net gas transportation revenues for a total of $3.3 million.

     Exploration expense increased $2.8 million due to higher dry hole costs. The following table details our exploration-related expenses for the three months ended March 31, 2007 and 2006 (in thousands):

     Deferred compensation plan expense for the first quarter of 2007 increased $6.8 million from 2006 due to an increase in our stock price. Our stock price increased from $27.46 at December 31, 2006 to $33.40 at March 31, 2007. This non-cash expense relates to the increase or decrease in value of our common stock and other investments held in our deferred compensation plans.

     Income tax expense for 2007 decreased to $4.8 million reflecting the 84% decrease in income from continuing operations before taxes compared to the same period of 2006. The first quarter of 2007 and 2006 provide for a tax expense at an effective rate of approximately 37%. Current income taxes of $384,000 represent state income taxes.

     Discontinued operations include the operating results related to our Gulf of Mexico properties and Austin Chalk properties that we sold in the first quarter of 2007. We recorded a pre-tax gain on sale of our Gulf of Mexico properties of $95.6 million. The first quarter of 2007 and 2006 provide for a tax expense at an effective rate of approximately 35%. See also Note 4 to our consolidating financial statements.

     During the three months ended March 31, 2007, our cash provided from continuing operations was $84.1 million and we spent $239.2 million on capital expenditures (including acquisitions). During this period, financing activities provided net cash of $86.0 million. At March 31, 2007, we had $167.9 million in cash, total assets of $3.3 billion and a debt-to-capitalization ratio of 46.6%. The cash balance includes proceeds received from the March 30, 2007 sale of our Gulf Coast properties of $155.0 million. These proceeds were used to pay down our credit facility balance in April. Long-term debt at March 31, 2007 totaled $1.1 billion including $537.5 million of bank credit facility debt and $596.9 million of senior subordinated notes. Available borrowing capacity under the bank credit facility at March 31, 2007 was $362.5 million. On April 23, 2007, we received $280.4 million of proceeds from the sale of 8,050,000 shares of common stock. These proceeds were used to pay down a portion of our outstanding balance on our credit facility and will be used to fund a portion of the proposed Equitable transaction.

     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, asset sales or the issuance of debt or equity securities. There can be no assurance that internal cash flow and other capital sources will provide sufficient funds to maintain capital expenditures that we believe are necessary to offset inherent declines in production and proven reserves.

     The debt agreements contain covenants relating to working capital, dividends and financial ratios. We were in compliance with all covenants at March 31, 2007. 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 $482.2 million was available under the bank credit facility’s restricted payment basket on March 31, 2007. The terms of our senior subordinated 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. The 7.5% Notes also allow for any cash proceeds received from the sale of oil and gas properties purchased in the Stroud acquisition to be added to the restricted payment baskets. Approximately $559.1 million was available under each of the 7.375% Notes and the 6.375% Notes restricted payment basket on March 31, 2007. There was $640.1 million available under the 7.5% Note restricted payment baskets.

     We maintain a $900.0 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. The borrowing base in dependent on a number of factors, primarily the lenders assessment of future cash flows. Redeterminations, other than increases, require the approval of 75% of the lenders while increases require unanimous approval. At April 24, 2007, the bank credit facility had a $1.2 billion borrowing base and an $900.0 million facility amount. Credit availability is equal to the lesser of the facility amount or the borrowing base resulting in credit availability of $758.5 million on April 24, 2007.

     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 March 31, 2007, we have entered into hedging agreements covering 65.2 Bcfe, 77.2 Bcfe and 6.6 Bcfe for 2007, 2008 and 2009, respectively. Net cash provided from continuing operations for the three months ended March 31, 2007 was $84.1 million compared to $116.4 million in the three months ended March 31, 2006. Cash flow from operations was lower than the prior year due to timing of working capital changes. Net cash used in investing for the three months ended March 31, 2007 was $12.2 million compared to $107.4 million in the same period of 2006. The 2007 period includes $182.8 million of additions to oil and gas properties, $49.1 million of acquisitions offset by proceeds of $234.3 million from asset sales. The 2006 period included $91.1 million of additions to oil and gas properties and $10.0 million of acquisitions. Net cash provided from financing for the three months ended March 31, 2007 was $86.0 million compared to net cash used in financing of $21.5 million in the first three months of 2006. This increase was primarily the result of borrowings under our credit facility. During the first three months of 2007 total debt increased $85.6 million.

     On March 1, 2007, the Board of Directors declared a dividend of three cents per share ($4.2 million) on our common stock, payable on March 30, 2007 to stockholders of record at the close of business on March 15, 2007.

     The 2007 capital budget is currently set at $822.0 million (excluding acquisitions) and based on current projections, is expected to be funded with internal cash flow and asset sales. For the three months ended March 31, 2007, $183.8 million of development and exploration spending was funded with internal cash flow and borrowings under our credit facility.

     Other than our pending development plan with respect to the Nora field (as discussed in Note 18 to the consolidated financial statements), there have been no significant changes to our contractual obligations subsequent to December 31, 2006. The proposed Nora field acquisition purchase price is approximately $315.0 million. There have been no significant changes to our off-balance sheet arrangements subsequent to December 31, 2006.

     We are involved in various legal actions and claims arising in the ordinary course of business. 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 March 31, 2007, swaps were in place covering 66.2 Bcf of gas at prices averaging $9.18 per mcf. We also have collars covering 47.2 Bcf of gas at weighted average floor and cap prices which range from $7.28 to $10.35 per mcf and 5.9 million barrels of oil at weighted average floor and cap prices that range from $57.76 to $72.53 per barrel. Their fair value at March 31, 2007 (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 gain of $21.6 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 are marked to market. In the first quarter of 2007, this resulted in a loss of $66.1 million compared to a gain of $11.3 million in the first quarter of 2006.

     At March 31, 2007, the following commodity derivative contracts were outstanding:

     At March 31, 2007, we had $1.1 billion of debt outstanding. Of this amount, $600.0 million bore interest at fixed rates averaging 7.2%. Bank debt totaling $537.5 million bears interest at floating rates, which average 6.5% at March 31, 2007. The 30 day LIBOR rate on March 31, 2007 was 5.3%.

     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 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 first quarter of 2007, we received an average of $56.00 per barrel of oil and $6.42 per mcf of gas before hedging compared to $59.74 per barrel of oil and $8.33 per mcf of gas in the same period of the prior year. Although certain of our costs are affected by general inflation, inflation does not normally have a significant effect on our business. In a trend that began in 2004 and accelerated during 2005 and 2006, commodity prices for oil and gas increased significantly. The higher prices have led to increased activity in the industry and, consequently, rising costs. These costs trends have put pressure not only on our operating costs but also on capital costs. We expect these costs to remain high in 2007.

     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 prices. 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. These arrangements are intended to reduce the impact of oil and gas price fluctuations. Certain of our derivatives are swaps where we receive a fixed price for our production and pay market prices to the counterparty. Our derivatives program also includes collars which establish a minimum floor price and a predetermined ceiling price. 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 other comprehensive income. 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. Though not all of our derivatives qualify as accounting hedges, the purpose of entering into the contracts is to economically hedge oil and gas prices. Those that do not qualify as accounting hedges are marked to market through current period income.

     As of March 31, 2007, we had gas swaps in place covering 66.2 Bcf of gas. We also had collars covering 47.2 Bcf of gas and 5.9 million barrels of oil. 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 gain of $21.6 million at that date. These contracts expire monthly through December 2009. 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 gains relating to these derivatives for the three months ended March 31, 2007 was $35.5 million compared to losses of $17.1 million in the first three months of 2006. 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 loss of $219,000 in the first three months of 2007 compared to a gain of $1.4 million in the first three months of 2006.

     Other Commodity Risk. We are impacted by basis risk, caused by factors that affect the relationship between commodity futures prices reflected in derivative commodity instruments and the cash market price of the underlying commodity. Natural gas transaction prices are frequently based on industry reference prices that may vary from prices experienced in local markets. If commodity price changes in one region are not reflected in other regions, derivative commodity instruments may no longer provide the expected hedge, resulting in increased basis risk. As of the fourth quarter of 2005, certain of our gas hedges no longer qualify for hedge accounting due to the volatility in gas prices and its effect on our basis differentials and are marked to market. This resulted in a loss of $66.1 million in the first three months of 2007 compared to a gain of $11.3 million in the same period of 2006.

     At March 31, 2007, the following commodity derivative contracts were outstanding:

     In the first three months of 2007, a 10% reduction in oil and gas prices, excluding amounts fixed through hedging transactions, would have reduced revenue by $17.9 million. If oil and gas future prices at March 31, 2007 declined 10%, the unrealized hedging gain at that date would have increased by $82.6 million.

     Interest rate risk. At March 31, 2007, we had $1.1 billion of debt outstanding. Of this amount, $600.0 million bore interest at fixed rates averaging 7.2%. Senior debt totaling $537.5 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 $5.4 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.

     The closing of the Equitable transaction is subject to Hart-Scott-Rodino clearance and other customary closing conditions. We expect that the transaction will close in May 2007, but we cannot assure you that the transaction will close at such time or at all. This offering is not conditioned on the closing of the Equitable transaction, and we cannot predict the impact on our stock price if the Equitable transaction does not close.

     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.

April 26, 2007

     Exhibit index