10-Q 1 rrc-10q_20140331.htm 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark one)

þ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2014

OR

¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 001-12209

RANGE RESOURCES CORPORATION

(Exact Name of Registrant as Specified in Its Charter)

Delaware |  | 34-1312571
(State or Other Jurisdiction of Incorporation or Organization) |  | (IRS Employer Identification No.)
100 Throckmorton Street, Suite 1200 Fort Worth, Texas |  | 76102
(Address of Principal Executive Offices) |  | (Zip Code)

Registrant’s telephone number, including area code

(817) 870-2601

Former Name, Former Address and Former Fiscal Year, if changed since last report: Not applicable

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

Yes þ No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for shorter period that the registrant was required to submit and post such files).

Yes þ No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer |  | þ |  | Accelerated Filer |  | ¨
Non-Accelerated Filer |  | ¨ (Do not check if smaller reporting company) |  | Smaller Reporting Company |  | ¨

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

Yes ¨ No þ

163,879,524 Common Shares were outstanding on April 25, 2014

RANGE RESOURCES CORPORATION

FORM 10-Q

Quarter Ended March 31, 2014

Unless the context otherwise indicates, all references in this report to “Range,” “we,” “us,” or “our” are to Range Resources Corporation and its wholly-owned subsidiaries and its ownership interests in equity method investees.

TABLE OF CONTENTS

|  |  |  | Page
PART I – FINANCIAL INFORMATION |  |
ITEM 1. |  | Financial Statements: |  | 3
|  | Consolidated Balance Sheets (Unaudited) |  | 3
|  | Consolidated Statements of Operations (Unaudited) |  | 4
|  | Consolidated Statements of Comprehensive Income (Loss) (Unaudited) |  | 5
|  | Consolidated Statements of Cash Flows (Unaudited) |  | 6
|  | Selected Notes to Consolidated Financial Statements (Unaudited) |  | 7
ITEM 2. |  | Management’s Discussion and Analysis of Financial Condition and Results of Operations |  | 14
ITEM 3. |  | Quantitative and Qualitative Disclosures about Market Risk |  | 14
ITEM 4. |  | Controls and Procedures |  | 14
PART II – OTHER INFORMATION |  |
ITEM 1. |  | Legal Proceedings |  | 14
ITEM 1A. |  | Risk Factors |  | 14
ITEM 6. |  | Exhibits |  | 14
|  | SIGNATURES |  | 14

2

PART I – FINANCIAL INFORMATION

I TEM 1. | Financial Statements

RANGE RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

| March 31, |  |  | December 31, |
| 2014 |  |  | 2013 |
| (Unaudited) |  |  |  |  |
Assets |  |  |  |  |  |  |
Current assets: |  |  |  |  |  |  |
Cash and cash equivalents | $ | 246 |  |  | $ | 348 |
Accounts receivable, less allowance for doubtful accounts of $2,487 and $2,494 |  | 221,304 |  |  |  | 179,667 |
Derivative assets |  | 80 |  |  |  | 4,421 |
Deferred tax asset |  | 40,362 |  |  |  | 51,414 |
Inventory and other |  | 17,353 |  |  |  | 12,451 |
Total current assets |  | 279,345 |  |  |  | 248,301 |
Derivative assets |  | 15,917 |  |  |  | 9,233 |
Equity method investments |  | 123,791 |  |  |  | 129,034 |
Natural gas and oil properties, successful efforts method |  | 9,309,743 |  |  |  | 9,032,881 |
Accumulated depletion and depreciation |  | (2,397,089 | ) |  |  | (2,274,444 | )
|  | 6,912,654 |  |  |  | 6,758,437 |
Transportation and field assets |  | 120,036 |  |  |  | 118,625 |
Accumulated depreciation and amortization |  | (87,955 | ) |  |  | (85,841 | )
|  | 32,081 |  |  |  | 32,784 |
Other assets |  | 118,987 |  |  |  | 121,297 |
Total assets | $ | 7,482,775 |  |  | $ | 7,299,086 |
Liabilities |  |  |  |  |  |  |
Current liabilities: |  |  |  |  |  |  |
Accounts payable | $ | 273,756 |  |  | $ | 258,431 |
Asset retirement obligations |  | 5,037 |  |  |  | 5,037 |
Accrued liabilities |  | 164,585 |  |  |  | 161,520 |
Accrued interest |  | 32,303 |  |  |  | 44,375 |
Derivative liabilities |  | 72,854 |  |  |  | 26,198 |
Total current liabilities |  | 548,535 |  |  |  | 495,561 |
Bank debt |  | 594,000 |  |  |  | 500,000 |
Subordinated notes |  | 2,640,866 |  |  |  | 2,640,516 |
Deferred tax liability |  | 778,955 |  |  |  | 771,980 |
Derivative liabilities |  | 142 |  |  | 25 |
Deferred compensation liability |  | 235,307 |  |  |  | 247,537 |
Asset retirement obligations and other liabilities |  | 235,289 |  |  |  | 229,015 |
Total liabilities |  | 5,033,094 |  |  |  | 4,884,634 |
Commitments and contingencies |  |  |  |  |  |  |
Stockholders’ Equity |  |  |  |  |  |  |
Preferred stock, $1 par, 10,000,000 shares authorized, none issued and outstanding | — |  |  | — |
Common stock, $0.01 par, 475,000,000 shares authorized, 163,763,190 issued at March 31, 2014 and 163,441,414 issued at December 31, 2013 |  | 1,638 |  |  |  | 1,634 |
Common stock held in treasury, 93,275 shares at March 31, 2014 and 98,520 shares at December 31, 2013 |  | (3,455 | ) |  |  | (3,637 | )
Additional paid-in capital |  | 1,969,948 |  |  |  | 1,959,636 |
Retained earnings |  | 476,554 |  |  |  | 450,583 |
Accumulated other comprehensive income |  | 4,996 |  |  |  | 6,236 |
Total stockholders’ equity |  | 2,449,681 |  |  |  | 2,414,452 |
Total liabilities and stockholders’ equity | $ | 7,482,775 |  |  | $ | 7,299,086 |

See accompanying notes.

3

RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited, in thousands, except per share data)

| Three Months Ended |
| March 31, |
| 2014 |  |  | 2013 |
Revenues and other income: |  |  |  |  |  |  |
Natural gas, NGLs and oil sales | $ | 572,017 |  |  | $ | 398,239 |
Derivative fair value loss |  | (146,850 | ) |  |  | (99,875 | )
Loss on the sale of assets |  | (353 | ) |  |  | (166 | )
Brokered natural gas, marketing and other |  | 32,528 |  |  |  | 21,041 |
Total revenues and other income |  | 457,342 |  |  |  | 319,239 |
Costs and expenses: |  |  |  |  |  |  |
Direct operating |  | 39,795 |  |  |  | 30,188 |
Transportation, gathering and compression |  | 74,161 |  |  |  | 62,416 |
Production and ad valorem taxes |  | 11,678 |  |  |  | 11,383 |
Brokered natural gas and marketing |  | 34,129 |  |  |  | 22,315 |
Exploration |  | 14,846 |  |  |  | 16,780 |
Abandonment and impairment of unproved properties |  | 9,995 |  |  |  | 15,218 |
General and administrative |  | 49,212 |  |  |  | 84,058 |
Deferred compensation plan |  | (2,035 | ) |  |  | 42,360 |
Interest expense |  | 45,401 |  |  |  | 42,210 |
Depletion, depreciation and amortization |  | 128,682 |  |  |  | 115,101 |
Total costs and expenses |  | 405,864 |  |  |  | 442,029 |
Income (loss) from operations before income taxes |  | 51,478 |  |  |  | (122,790 | )
Income tax expense (benefit) |  |  |  |  |  |  |
Current |  | 6 |  |  | 25 |
Deferred |  | 18,951 |  |  |  | (47,205 | )
|  | 18,957 |  |  |  | (47,180 | )
Net income (loss) | $ | 32,521 |  |  | $ | (75,610 | )
Net income (loss) per common share: |  |  |  |  |  |  |
Basic | $ | 0.20 |  |  | $ | (0.47 | )
Diluted | $ | 0.20 |  |  | $ | (0.47 | )
Dividends paid per common share | $ | 0.04 |  |  | $ | 0.04 |
Weighted average common shares outstanding: |  |  |  |  |  |  |
Basic |  | 160,794 |  |  |  | 160,125 |
Diluted |  | 161,825 |  |  |  | 160,125 |

See accompanying notes.

4

RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited, in thousands)

| Three Months Ended |
| March 31, |
| 2014 |  |  | 2013 |
Net income (loss) | $ | 32,521 |  |  | $ | (75,610 | )
Other comprehensive income (loss): |  |  |  |  |  |  |
Realized loss (gain) on hedge derivative contract settlements reclassified into natural gas, NGLs and oil sales from other comprehensive income, net of taxes (1) | — |  |  |  | (14,840 | )
De-designated hedges reclassified into natural gas, NGLs and oil sales, net of taxes (2) |  | (1,240 | ) |  |  | (7,425 | )
De-designated hedges reclassified to derivative fair value income, net of taxes (3) | — |  |  |  | (1,390 | )
Change in unrealized deferred hedging (losses) gains, net of taxes (4) | — |  |  |  | (4,203 | )
Total comprehensive income (loss) | $ | 31,281 |  |  | $ | (103,468 | )

(1) | Amounts are net of income tax benefit of $9,488 for the three months ended March 31, 2013.

(2) | Amounts are net of income tax benefit of $924 for the three months ended March 31, 2014 and $4,747 for the three months ended March 31, 2013.

(3) | Amounts relate to transactions not probable of occurring and are presented net of income tax benefit of $889 for the three months ended March 31, 2013.

(4) | Amounts are net of income tax benefit of $2,687 for the three months ended March 31, 2013.

See accompanying notes.

5

RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, in thousands)

| Three Months Ended |
| March 31, |
| 2014 |  |  | 2013 |
Operating activities: |  |  |  |  |  |  |
Net income (loss) | $ | 32,521 |  |  | $ | (75,610 | )
Adjustments to reconcile net income (loss) to net cash provided from operating activities: |  |  |  |  |  |  |
Loss from equity method investments, net of distributions |  | 2,732 |  |  |  | 610 |
Deferred income tax expense (benefit) |  | 18,951 |  |  |  | (47,205 | )
Depletion, depreciation and amortization |  | 128,682 |  |  |  | 115,101 |
Exploration dry hole costs |  | 1 |  |  |  | (159 | )
Abandonment and impairment of unproved properties |  | 9,995 |  |  |  | 15,218 |
Derivative fair value loss |  | 146,850 |  |  |  | 99,875 |
Cash settlements on derivative financial instruments that do not qualify for hedge accounting |  | (104,584 | ) |  |  | 382 |
Amortization of deferred financing costs and other |  | 2,873 |  |  |  | 2,080 |
Deferred and stock-based compensation |  | 12,593 |  |  |  | 54,991 |
Loss on the sale of assets |  | 353 |  |  |  | 166 |
Changes in working capital: |  |  |  |  |  |  |
Accounts receivable |  | (41,643 | ) |  |  | 1,292 |
Inventory and other |  | (5,358 | ) |  |  | 166 |
Accounts payable |  | 9,997 |  |  |  | 17,061 |
Accrued liabilities and other |  | (32,742 | ) |  |  | 17,281 |
Net cash provided from operating activities |  | 181,221 |  |  |  | 201,249 |
Investing activities: |  |  |  |  |  |  |
Additions to natural gas and oil properties |  | (226,331 | ) |  |  | (259,601 | )
Additions to field service assets |  | (3,084 | ) |  |  | (1,071 | )
Acreage purchases |  | (50,690 | ) |  |  | (8,794 | )
Equity method investments |  | 2,511 |  |  |  | 1,885 |
Proceeds from disposal of assets |  | 294 |  |  |  | 38,196 |
Purchases of marketable securities held by the deferred compensation plan |  | (8,247 | ) |  |  | (17,936 | )
Proceeds from the sales of marketable securities held by the deferred compensation plan |  | 9,310 |  |  |  | 6,316 |
Net cash used in investing activities |  | (276,237 | ) |  |  | (241,005 | )
Financing activities: |  |  |  |  |  |  |
Borrowing on credit facilities |  | 412,000 |  |  |  | 368,000 |
Repayment on credit facilities |  | (318,000 | ) |  |  | (1,060,000 | )
Issuance of subordinated notes |  | — |  |  |  | 750,000 |
Dividends paid |  | (6,550 | ) |  |  | (6,521 | )
Debt issuance costs |  | — |  |  |  | (12,098 | )
Issuance of common stock |  | — |  |  |  | 343 |
Change in cash overdrafts |  | (1,122 | ) |  |  | (12,458 | )
Proceeds from the sales of common stock held by the deferred compensation plan |  | 8,586 |  |  |  | 12,432 |
Net cash provided from financing activities |  | 94,914 |  |  |  | 39,698 |
Decrease in cash and cash equivalents |  | (102 | ) |  |  | (58 | )
Cash and cash equivalents at beginning of period |  | 348 |  |  |  | 252 |
Cash and cash equivalents at end of period | $ | 246 |  |  | $ | 194 |

See accompanying notes.

6

RANGE RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

(1) SUMMARY OF ORGANIZATION AND NATURE OF BUSINESS

Range Resources Corporation (“Range,” “we,” “us,” or “our”) is a Fort Worth, Texas-based independent natural gas, natural gas liquids (“NGLs”) and oil company primarily engaged in the exploration, development and acquisition of natural gas and oil properties in the Appalachian and Southwestern regions of the United States. Our objective is to build stockholder value thro ugh consistent growth in reserves and production on a cost-efficient basis. Range is a Delaware corporation with our common stock listed and traded on the New York Stock Exchange under the symbol “RRC.”

(2) BASIS OF PRESENTATION

Presentation

These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Range Resources Corporation 2013 Annual Report on Form 10-K filed on February 26, 2014. The results of operations for the fi rst quarter ended March 31, 2014 are not necessarily indicative of the results to be expected for the full year. 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 otherwise disclosed. 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 of America (“U.S. GAAP”) for complete financial statements. Certain reclassifications have been made to prior years reported amounts in order to conform with the current year presentation including reclassifications between accounts payable and accrued liabilities within cash flow from operating activities and a change in the presentation for our derivative activities. These reclassifications have no impact on previously reported net income, stockholders’ equity or cash flows.

De-designation of Commodity Derivative Contracts

Effective March 1, 2013, we elected to discontinue hedge accounting prospectively. After March 1, 2013, both realized and unrealized gains and losses are recognized in derivative fair value income or loss immediately each quarter as derivative contracts are settled and marked to market. For additional information, see Note 11.

7

(3) NEW ACCOUNTING STANDARDS

Recently Adopted

In February 2013, an accounting standards update was issued to provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date, except for obligations such as asset retirement and environmental obligations, contingencies, guarantees, income taxes and retirement benefits, which are separately addressed within U.S. GAAP. An entity is required to measure obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date as the sum of (1) the amount the entity agreed to pay on the basis of its arrangement among its co-obligors and (2) any amount the entity expects to pay on behalf of its co-obligors. Disclosure of the nature of the obligation, including how the liability arose, the relationship with other co-obligors and the terms and conditions of the arrangement is required. In addition, the total outstanding amount under the arrangement, not reduced by the effect of any amounts that may be recoverable from other entities, plus the carrying amount of any liability or receivable recognized must be disclosed. This accounting standards update is effective for us beginning in first quarter 2014 and should be applied retrospectively for those in-scope obligations resulting from joint and several liability arrangements that exist at the beginning of 2014. Early adoption was permitted and we adopted this new standard in first quarter 2014 which did not have an impact on our consolidated results of operations, financial position or cash flows.

In April 2014, an accounting standards update was issued that raised the threshold for a disposal to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other material disposal transactions that do not meet the revised definition of a discontinued operations. Under the updated standard, a disposal of a component or group of components of an entity is required to be reported as discontinued operations if the disposal represents a strate gic shift that has (or will have) a major effect on an entity’s operations and financial results when the component or group of components of the entity (1) has been disposed of by a sale, (2) has been disposed of other than by sale or (3) is classified as held for sale. This accounting standards update is effective for annual periods beginning on or after December 15, 2014 and is applied prospectively. Early adoption is permitted but only for disposals (or classifications that are held for sale) that have not been reported in financial statements previously issued or available for use. We adopted this new standard in first quarter 2014. There was no impact to our consolidated results of operations, financial position or cash flows as there were no disposals or assets held for sale in first quarter 2014.

(4) DISPOSITIONS

2014 Dispositions

In December 2013, we announced our plan to offer for sale certain of our properties in the Permian Basin. These properties included approximately 90,000 (70,000 net) acres, almost all of which are held by production in Glasscock and Sterling Counties and are currently producing approximately 28 Mmcfe per day. The data room opened in January 2014 and we received bids in late February. In late April, an agreement related to this transaction was executed, subject to board approval. The completion of this transaction is dependent upon continuing due diligence procedures and there can be no assurance the transaction will be completed. In first quarter 2014, we also sold miscellaneous unproved and proved properties for proceeds of $294,000 resulting in a pre-tax loss of $353,000.

2013 Dispositions

In first quarter 2013, we sold miscellaneous proved properties and inventory for proceeds of $38.2 million resulting in a pre-tax loss of $166,000.

(5) INCOME TAXES

Income tax expense (benefit) from operations was as follows (in thousands):

|  | Three Months Ended March 31, |
|  | 2014 |  |  | 2013 |
Income tax expense (benefit) |  | $ | 18,957 |  |  | $ | (47,180 | )
Effective tax rate |  |  | 36.8 | % |  |  | 38.4 | %

We compute our quarterly taxes under the effective tax rate method based on applying an anticipated annual effective rate to our year-to-date income, except for discrete items. Income taxes for discrete items are computed and recorded in the period that the specific transaction occurs. For first quarter ended March 31, 2014 and 2013, our overall effective tax rate on operations was different than the federal statutory rate of 35% due primarily to state income taxes, valuation allowances and other permanent differences.

8

(6) INCOME (LOSS) PER COMMON SHARE

Basic income or loss per share attributable to common shareholders is computed as (1) income or loss attributable to common shareholders (2) less income allocable to participating securities (3) divided by weighted average basic shares outstanding. Diluted income or loss per share attributable to common stockholders is computed as (1) basic income or loss attributable to common shareholders (2) plus diluted adjustments to income allocable to participating s ecurities (3) divided by weighted average diluted shares outstanding. The following tables set forth a reconciliation of income or loss attributable to common shareholders to basic income or loss attributable to common shareholders to diluted income or loss attributable to common shareholders (in thousands except per share amounts):

|  | Three Months Ended March 31, |
|  |  | 2014 |  |  |  | 2013 |
Net income (loss), as reported |  | $ | 32,521 |  |  | $ | (75,610 | )
Participating basic earnings (a) |  |  | (560 | ) |  |  | (109 | )
Basic net income (loss) attributed to common shareholders |  |  | 31,961 |  |  |  | (75,719 | )
Reallocation of participating earnings (a) |  |  | 3 |  |  |  | — |
Diluted net income (loss) attributed to common shareholders |  | $ | 31,964 |  |  | $ | (75,719 | )
Net income (loss) per common share: |  |  |  |  |  |  |  |
Basic |  | $ | 0.20 |  |  | $ | (0.47 | )
Diluted |  | $ | 0.20 |  |  | $ | (0.47 | )

(a) | Restricted Stock Awards represent participating securities because they participate in nonforfeitable dividends or distributions with common equity owners. Income allocable to participating securities represents the distributed and undistributed earnings attributable to the participating securities. Participating securities, however, do not participate in undistributed net losses.

The following table provides a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding (in thousands):

|  | Three Months Ended March 31, |
|  | 2014 |  |  | 2013 |
Denominator: |  |  |  |  |  |  |  |
Weighted average common shares outstanding – basic |  |  | 160,794 |  |  |  | 160,125 |
Effect of dilutive securities: |  |  |  |  |  |  |  |
Director and employee stock options and SARs |  |  | 1,031 |  |  |  | — |
Weighted average common shares outstanding – diluted |  |  | 161,825 |  |  |  | 160,125 |

Weighted average common shares – basic for the three months ended March 31, 2014 excludes 2.8 million shares and the three months ended March 31, 2013 excludes 2.7 million shares of restricted stock held in our deferred compensation plans (although all awards are issued and outstanding upon grant). Due to our loss from continuing operations for the three months ended March 31, 2013, we excluded all outstanding stock appreciation rights (“SARs”) and restricted stock from the computation of diluted net loss per share because the effect would have been anti-dilutive to the computations.

9

(7) SUSPENDED EXPLORATORY WELL COSTS

We capitalize exploratory well costs until a determination is made that the well has either found proved reserves or that it is impaired. Capitalized exploratory well costs are presented in natural gas and oil properties in the accompanying consolidated balance sheets. If an exploratory well is deter mined to be impaired, the well costs are charged to exploration expense in the accompanying consolidated statements of operations. The following table reflects the changes in capitalized exploratory well costs for the three months ended March 31, 2014 and the year ended December 31, 2013 (in thousands except for number of projects):

|  | March 31, 2014 |  |  | December 31, 2013 |
Balance at beginning of period |  | $ | 6,964 |  |  | $ | 57,360 |
Additions to capitalized exploratory well costs pending the determination of proved reserves |  |  | 5,552 |  |  |  | 39,832 |
Reclassifications to wells, facilities and equipment based on determination of proved reserves |  |  | — |  |  |  | (84,840 | )
Capitalized exploratory well costs charged to expense |  |  | — |  |  |  | — |
Divested wells |  |  | — |  |  |  | (5,388 | )
Balance at end of period |  |  | 12,516 |  |  |  | 6,964 |
Less exploratory well costs that have been capitalized for a period of one year or less |  |  | (5,552 | ) |  |  | — |
Capitalized exploratory well costs that have been capitalized for a period greater than one year |  | $ | 6,964 |  |  | $ | 6,964 |
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year |  |  | 1 |  |  |  | 1 |

As of March 31, 2014, $7.0 million of capitalized exploratory well costs have been capitalized for more than one year which relates to one well in our Marcellus Shale area where we are evaluating pipeline options. The following table provides an aging of capitalized exploratory well costs that have been suspended for more than one year as of March 31, 2014 (in thousands):

|  | Total |  |  | 2013 |  |  | 2012 |  |  | 2011 |
Capitalized exploratory well costs that have been capitalized for more than one year |  | $ | 6,964 |  |  | $ | 110 |  |  | $ | 6,801 |  |  | $ | 53 |

(8) INDEBTEDNESS

We had the following debt outstanding as of the dates shown below (bank debt interest rate at March 31, 2014 is shown parenthetically) (in thousands). No interest was capitalized during the three months ended March 31, 2014 or the year ended December 31, 2013:

|  | March 31, 2014 |  |  | December 31, 2013 |
Bank debt (1.9%) |  | $ | 594,000 |  |  | $ | 500,000 |
Senior subordinated notes: |  |  |  |  |  |  |  |
8.00% senior subordinated notes due 2019, net of $9,134 and $9,484 discount, respectively |  |  | 290,866 |  |  |  | 290,516 |
6.75% senior subordinated notes due 2020 |  |  | 500,000 |  |  |  | 500,000 |
5.75% senior subordinated notes due 2021 |  |  | 500,000 |  |  |  | 500,000 |
5.00% senior subordinated notes due 2022 |  |  | 600,000 |  |  |  | 600,000 |
5.00% senior subordinated notes due 2023 |  |  | 750,000 |  |  |  | 750,000 |
Total debt |  | $ | 3,234,866 |  |  | $ | 3,140,516 |

Bank Debt

In February 2011, we entered into an amended and restated revolving bank facility, which we refer to as our bank debt or our 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 the facility amount or the borrowing base. On March 31, 2014, the facility amount was $1.75 billion and the borrowing base was $2.0 billion. The bank credit facility provides for a borrowing base subject to redeterminations semi-annually and for event-driven unscheduled redeterminations. As part of our semi-annual bank review completed on April 3, 2014, our borrowing base was reaffirmed at $2.0 billion and our facility amount was also reaffirmed at $1.75 billion. Our current bank group is composed

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of twenty-eight financial institutions with no one bank holding more than 9% of the total facility. The bank credit facility amount may be increased to the borrowing base amount with twenty days’ notice, subject to the banks agreeing to participate in the facility increase and our payment of a mutually acceptable commitment fee to those banks. As of March 31, 2014, the outstanding balance under our bank credit facility was $594.0 million. Additionally, we had $127.4 million of undrawn letters of credit leaving $1.0 billion of borrowing capacity available under the facility. The bank credit facility matures on February 18, 2016. Borrowings under the bank credit facility can either be at the Alternate Base Rate (as defined in the bank credit facility) plus a spread ranging from 0.50% to 1.5% or LIBOR borrowings at the Adjusted LIBO Rate (as defined in the bank credit facility) plus a spread ranging from 1.5% to 2.5%. The applicable spread is dependent upon borrowings 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 of the base rate loans to LIBOR loans. The weighted average interest rate was 2.0% for the three months ended March 31, 2014 compared to 2.1% for the three months ended March 31, 2013. A commitment fee is paid on the undrawn balance based on an annual rate of 0.35% to 0.50%. At March 31, 2014, the commitment fee was 0.375% and the interest rate margin was 1.75% on our LIBOR loans and 0.75% on our base rate loans.

Senior Subordinated Notes

If we experience a change of control, bondholders may require us to repurchase all or a portion of all of our senior subordinated notes at 101% of the aggregate 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.

Guarantees

Range Resources Corporation is a holding company which owns no operating assets and has no significant operations independent of its subsidiaries. The guarantees by our subsidiaries of our senior subordinated notes are full and unconditional and joint and several, subject to certain customary release provisions. A subsidiary guarantor may be released from its obligations under the guarantee:

— | in the event of a sale or other disposition of all or substantially all of the assets of the subsidiary guarantor or a sale or other disposition of all the capital stock of the subsidiary guarantor, to any corporation or other person (including an unrestricted subsidiary of Range) by way of merger, consolidation, or otherwise; or

— | if Range designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the terms of the indenture.

Debt Covenants and Maturity

Our bank credit facility contains negative covenants that limit our ability, among other things, to pay cash dividends, incur additional indebtedness, sell assets, enter into certain hedging contracts, change the nature of our business or operations, merge, consolidate, or make investments. In addition, we are required to maintain a ratio of debt to EBITDAX (as defined in the credit agreement) of no greater than 4.25 to 1.0 and a current ratio (as defined in the credit agreement) of no less than 1.0 to 1.0. We are in compliance with our covenants under the bank credit facility at March 31, 2014.

The indentures governing our senior subordinated notes contain various restrictive covenants that are substantially identical to each other and may limit our ability to, among other things, pay cash dividends, incur additional indebtedness, sell assets, enter into transactions with affiliates, or change the nature of our business. At March 31, 2014, we are in compliance with these covenants.

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(9) ASSET RETIREMENT OBLIGATIONS

Our asset retirement obligations primarily represent the estimated present value of the amounts we will incur to plug, abandon and remediate our producing properties at the end of their productive lives. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, estimated future inflation rates and well life. The inputs are calculated based on historical data as well as current estimated costs. A reconciliation of our liability for plugging and abandonment c osts for the three months ended March 31, 2014 is as follows (in thousands):

|  | Three Months Ended March 31, 2014 |
Beginning of period |  | $ | 230,077 |
Liabilities incurred |  |  | 2,128 |
Liabilities settled |  |  | (384 | )
Disposition of wells |  |  | (122 | )
Accretion expense |  |  | 3,707 |
Change in estimate |  |  | 1,089 |
End of period |  |  | 236,495 |
Less current portion |  |  | (5,037 | )
Long-term asset retirement obligations |  | $ | 231,458 |

Accretion expense is recognized as a component of depreciation, depletion and amortization expense in the accompanying statements of operations.

(10) CAPITAL STOCK

We have authorized capital stock of 485.0 million shares which includes 475.0 million shares of common stock and 10.0 million shares of preferred stock. We currently have no preferred stock issued or outstanding. The following is a schedule of changes in the number of common shares outstanding since the beginning of 2013:

|  | Three Months Ended March 31, 2014 |  |  | Year Ended December 31, 2013 |
Beginning balance |  |  | 163,342,894 |  |  |  | 162,514,098 |
SARs exercised |  |  | 48,280 |  |  |  | 278,916 |
Restricted stock granted |  |  | 74,553 |  |  |  | 401,122 |
Restricted stock units vested |  |  | 198,943 |  |  |  | 119,480 |
Treasury shares issued |  |  | 5,245 |  |  |  | 29,278 |
Ending balance |  |  | 163,669,915 |  |  |  | 163,342,894 |

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(11) DERIVATIVE ACTIVITIES

We use commodity-based derivative contracts to manage exposure to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. We do not utilize complex derivatives as we typically utilize commodity swaps or collars to (1) reduce the effect of price volatility of the commodities we produce and sell and (2) support our annual capital budget and expenditure plans. The fair value of our derivative contracts, represented by the estimated amount that would be realize d upon termination, based on a comparison of the contract price and a reference price, generally the New York Mercantile Exchange (“NYMEX”), approximated a net unrealized pre-tax loss of $53.4 million at March 31, 2014. These contracts expire monthly through December 2016. The following table sets forth our derivative volumes by year as of March 31, 2014:

Period |  | Contract Type |  | Volume Hedged |  | Weighted Average Hedge Price
Natural Gas |  |  |  |  |  |
2014 |  | Collars |  | 447,500 Mmbtu/day |  | $ 3.84–$ 4.48
2015 |  | Collars |  | 145,000 Mmbtu/day |  | $ 4.07–$ 4.56
2014 |  | Swaps |  | 240,145 Mmbtu/day |  | $ 4.18
2015 |  | Swaps |  | 234,966 Mmbtu/day |  | $ 4.19
2016 |  | Swaps |  | 60,000 Mmbtu/day |  | $ 4.18
Crude Oil |  |  |  |  |  |
2014 |  | Collars |  | 2,000 bbls/day |  | $ 85.55–$ 100.00
2014 |  | Swaps |  | 9,169 bbls/day |  | $ 94.40
2015 |  | Swaps |  | 6,000 bbls day |  | $ 89.48
NGLs (C3-Propane) |  |  |  |  |  |
2014 |  | Swaps |  | 12,000 bbls/day |  | $ 1.02/gallon
NGLs (NC4-Normal butane) |  |  |  |  |  |
2014 |  | Swaps |  | 4,000 bbls/day |  | $ 1.34/gallon
NGLs (C5-Natural Gasoline) |  |  |  |  |  |
2014 |  | Swaps |  | 1,000 bbls/day |  | $ 2.11/gallon

Every derivative instrument is required to be recorded on the balance sheet as either an asset or a liability measured at its fair value. Through February 28, 2013, changes in the fair value of our derivatives that qualified for hedge accounting were recorded as a component of accumulated other comprehensive income (“ AOCI”) in the stockholders’ equity section of the accompanying consolidated balance sheets, which is later transferred to natural gas, NGLs and oil sales when the underlying physical transaction occurs and the hedging contract is settled. As of March 31, 2014, an unrealized pre-tax derivative gain of $8.1 million ($5.0 million after tax) was recorded in AOCI. See additional discussion below regarding the discontinuance of hedge accounting. If the derivative does not qualify as a hedge or is not designated as a hedge, changes in fair value of these non-hedge derivatives are recognized in earnings in derivative fair value income or loss.

For those derivative instruments that qualified or were designated for hedge accounting, settled transaction gains and losses were determined monthly, and were included as increases or decreases to natural gas, NGLs and oil sales in the period the hedged production was sold. Through February 28, 2013, we had elect ed to designate our commodity derivative instruments that qualified for hedge accounting as cash flow hedges. Natural gas, NGLs and oil sales include $2.2 million of gains in first quarter 2014 compared to gains of $36.5 million in the same period of 2013 related to settled hedging transactions. Any ineffectiveness associated with these hedge derivatives is reflected in derivative fair value income or loss in the accompanying statements of operations. The ineffective portion is generally calculated as the difference between the changes in fair value of the derivative and the estimated change in future cash flows from the item hedged. Derivative fair value loss for the three months ended March 31, 2014 includes no ineffective gains or losses compared to a loss of $2.9 million in the three months ended March 31, 2013. During the three months ended March 31, 2013, we recognized a pre-tax gain of $2.3 million in derivative fair value loss as a result of the discontinuance of hedge accounting where we determined the transaction was probable not to occur primarily due to the sale of our Delaware and Permian Basin properties in New Mexico and West Texas.

Discontinuance of Hedge Accounting

Effective March 1, 2013, we elected to de-designate all commodity contracts that were previously designated as cash flow hedges and elected to discontinue hedge accounting prospectively. AOCI included $103.6 million ($63.2 million after tax) of unrealized net gains, representing the marked-to-market value of the effective portion of our cash flow hedges as of February 28, 2013. As a result of discontinuing hedge accounting, the marked-to-market values included in AOCI as of the de-designation date were frozen and will be reclassified into earnings in natural gas, NGLs and oil sales in future periods as the underlying hedged

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transactions occur. As of March 31, 2014, we expect to reclassify into earnings $8.1 million of unrealized net gains in the remaining months of 2014.

With the election to de-designate hedging instruments, all of our derivative instruments continue to be recorded at fair value with unrealized gains and losses recognized immediately in earnings rather than in AOCI. These marked-to-market adjustments will produce a degree of earnings volatility that can be significa nt from period to period, but such adjustments will have no cash flow impact relative to changes in market prices. The impact to cash flow occurs upon settlement of the underlying contract.

Basis Swap Contracts

At March 31, 2014, we had natural gas basis swap contracts that are not designated for hedge accounting, which lock in the differential between NYMEX and certain of our physical pricing options in Appalachia. These contracts are for 254,164 Mmbtu/day and settle monthly through March 2015. The fair v alue of these contracts was a loss of $3.7 million on March 31, 2014.

Derivative Assets and Liabilities

The combined fair value of derivatives included in the accompanying consolidated balance sheets as of March 31, 2014 and December 31, 2013 is summarized below. The assets and liabilities are netted where derivatives with both gain and loss positions are held by a single counterparty and we have master netting arrangements. The tables below provide additional information relating to our master netting arr angements with our derivative counterparties (in thousands):

|  |  | March 31, 2014 |
|  |  | Gross Amounts of Recognized Assets |  |  | Gross Amounts Offset in the Balance Sheet |  |  | Net Amounts of Assets Presented in the Balance Sheet |
Derivative assets: |  |  |  |  |  |  |  |  |  |  |  |  |
Natural gas | –swaps |  | $ | 8,347 |  |  | $ | — |  |  | $ | 8,347 |
| –collars |  |  | 7,328 |  |  |  | (584 | ) |  |  | 6,744 |
| –basis swaps |  |  | 3,123 |  |  |  | (3,123 | ) |  |  | — |
Crude oil | –swaps |  |  | 1,179 |  |  |  | (273 | ) |  |  | 906 |
NGLs | –C3 swaps |  |  | 1,877 |  |  |  | (1,877 | ) |  |  | — |
| –C4 swaps |  |  | 3,159 |  |  |  | (3,159 | ) |  |  | — |
|  |  | $ | 25,013 |  |  | $ | (9,016 | ) |  | $ | 15,997 |

|  |  | March 31, 2014 |
|  |  | Gross Amounts of Recognized (Liabilities) |  |  | Gross Amounts Offset in the Balance Sheet |  |  | Net Amounts of (Liabilities) Presented in the Balance Sheet |
Derivative (liabilities): |  |  |  |  |  |  |  |  |  |  |  |  |
Natural gas | –swaps |  | $ | (27,720 | ) |  | $ | — |  |  | $ | (27,720 | )
| –collars |  |  | (26,738 | ) |  |  | 584 |  |  |  | (26,154 | )
| –basis swaps |  |  | (6,762 | ) |  |  | 3,123 |  |  |  | (3,639 | )
Crude oil | –swaps |  |  | (10,027 | ) |  |  | 273 |  |  |  | (9,754 | )
| –collars |  |  | (972 | ) |  |  | — |  |  |  | (972 | )
NGLs | –C3 swaps |  |  | (9,692 | ) |  |  | 1,877 |  |  |  | (7,815 | )
| –C4 swaps |  |  | — |  |  |  | 3,159 |  |  |  | 3,159 |
| –C5 swaps |  |  | (101 | ) |  |  | — |  |  |  | (101 | )
|  |  | $ | (82,012 | ) |  | $ | 9,016 |  |  | $ | (72,996 | )

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|  |  | December 31, 2013 |
|  |  | Gross Amounts of Recognized Assets |  |  | Gross Amounts Offset in the Balance Sheet |  |  | Net Amounts of Assets Presented in the Balance Sheet |
Derivative assets: |  |  |  |  |  |  |  |  |  |  |  |  |
Natural gas | –swaps |  | $ | 4,240 |  |  | $ | (1,218 | ) |  | $ | 3,022 |
| –collars |  |  | 16,057 |  |  |  | (7,671 | ) |  |  | 8,386 |
| –basis swaps |  |  | 7,686 |  |  |  | (7,686 | ) |  |  | — |
Crude oil | –swaps |  |  | 3,567 |  |  |  | (1,321 | ) |  |  | 2,246 |
NGLs | –C3 swaps |  |  | 826 |  |  |  | (826 | ) |  |  | — |
| –C4 swaps |  |  | 863 |  |  |  | (863 | ) |  |  | — |
| –C5 swaps |  |  | 121 |  |  |  | (121 | ) |  |  | — |
|  |  | $ | 33,360 |  |  | $ | (19,706 | ) |  | $ | 13,654 |

|  |  | December 31, 2013 |
|  |  | Gross Amounts of Recognized (Liabilities) |  |  | Gross Amounts Offset in the Balance Sheet |  |  | Net Amounts of (Liabilities) Presented in the Balance Sheet |
Derivative (liabilities): |  |  |  |  |  |  |  |  |  |  |  |  |
Natural gas | –swaps |  | $ | (4,790 | ) |  | $ | 1,218 |  |  | $ | (3,572 | )
| –collars |  |  | (13,345 | ) |  |  | 7,671 |  |  |  | (5,674 | )
| –basis swaps |  |  | (3,756 | ) |  |  | 7,686 |  |  |  | 3,930 |
Crude oil | –swaps |  |  | (4,711 | ) |  |  | 1,321 |  |  |  | (3,390 | )
| –collars |  |  | (398 | ) |  |  | — |  |  |  | (398 | )
NGLs | –C3 swaps |  |  | (18,172 | ) |  |  | 826 |  |  |  | (17,346 | )
| –C4 swaps |  |  | (757 | ) |  |  | 863 |  |  |  | 106 |
| –C5 swaps |  |  | — |  |  |  | 121 |  |  |  | 121 |
|  |  | $ | (45,929 | ) |  | $ | 19,706 |  |  | $ | (26,223 | )

The effects of our cash flow hedges (or those derivatives that previously qualified for hedge accounting) on AOCI in the accompanying consolidated balance sheets is summarized below (in thousands):

|  | Three Months Ended March 31, |
|  | Change in Hedge Derivative Fair Value |  |  | Realized Gain (Loss) Reclassified from OCI into Revenue (a) |
|  | 2014 |  |  | 2013 |  |  | 2014 |  |  | 2013 |
Swaps |  | $ | — |  |  | $ | 125 |  |  | $ | 836 |  |  | $ | 8,047 |
Collars |  |  | — |  |  |  | (7,015 | ) |  |  | 1,328 |  |  |  | 30,732 |
Income taxes |  |  | — |  |  |  | 2,687 |  |  |  | (924 | ) |  |  | (15,124 | )
|  | $ | — |  |  | $ | (4,203 | ) |  | $ | 1,240 |  |  | $ | 23,655 |

(a) | For realized gains upon derivative contract settlement, the reduction in AOCI is offset by an increase in revenues, NGLs and oil sales. For realized losses upon derivative contract settlement, the increase in AOCI is offset by a decrease in revenues. See additional discussion above regarding the discontinuance of hedge accounting.

The effects of our non-hedge derivatives (or those derivatives that do not qualify for hedge accounting) and the ineffective portion of our hedge derivatives on our consolidated statements of operations is summarized below (in thousands):

|  | Three Months Ended March 31, |
|  | Gain (Loss) Recognized in Income (Non-hedge Derivatives) |  |  | Gain (Loss) Recognized in Income (Ineffective Portion) |  |  | Derivative Fair Value Income (Loss) |
|  | 2014 |  |  | 2013 |  |  | 2014 |  |  | 2013 |  |  | 2014 |  |  | 2013 |
Swaps |  | $ | (44,073 | ) |  | $ | (43,076 | ) |  | $ | — |  |  | $ | (1,995 | ) |  | $ | (44,073 | ) |  | $ | (45,071 | )
Re-purchased swaps |  |  | — |  |  |  | 1,185 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 1,185 |
Collars |  |  | (39,148 | ) |  |  | (55,003 | ) |  |  | — |  |  |  | (896 | ) |  |  | (39,148 | ) |  |  | (55,899 | )
Call options |  |  | (63,629 | ) |  |  | (90 | ) |  |  | — |  |  |  | — |  |  |  | (63,629 | ) |  |  | (90 | )
Total |  | $ | (146,850 | ) |  | $ | (96,984 | ) |  | $ | — |  |  | $ | (2,891 | ) |  | $ | (146,850 | ) |  | $ | (99,875 | )

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(12) FAIR VALUE MEASUREMENTS

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. There are three approaches for measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which includes multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions invol ving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value amount using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset. This is often referred to as current replacement cost. The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence.

The fair value accounting standards do not prescribe which valuation technique should be used when measuring fair value and does not prioritize among the techniques. These standards establish a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The three levels of the fair value hierarchy are as follows:

— | Level 1 – Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

— | Level 2 – Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.

— | Level 3 – Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair va lue hierarchy.

Fair Values – Recurring

We use a market approach for our recurring fair value measurements and endeavor to use the best information available. The following tables present the fair value hierarchy table for assets and liabilities measured at fair value, on a recurring basis (in thousands):

|  | Fair Value Measurements at March 31, 2014 using: |
|  | Quoted Prices in Active Markets for Identical Assets (Level 1) |  |  | Significant Other Observable Inputs (Level 2) |  |  | Significant Unobservable Inputs (Level 3) |  |  | Total Carrying Value as of March 31, 2014 |
Trading securities held in the deferred compensation plans |  | $ | 67,119 |  |  | $ | — |  |  | $ | — |  |  | $ | 67,119 |
Derivatives –swaps |  |  | — |  |  |  | (32,979 | ) |  |  | — |  |  |  | (32,979 | )
–collars |  |  | — |  |  |  | (20,381 | ) |  |  | — |  |  |  | (20,381 | )
–basis swaps |  |  | — |  |  |  | (3,611 | ) |  |  | (28 | ) |  |  | (3,639 | )

|  | Fair Value Measurements at December 31, 2013 using: |
|  | Quoted Prices in Active Markets for Identical Assets (Level 1) |  |  | Significant Other Observable Inputs (Level 2) |  |  | Significant Unobservable Inputs (Level 3) |  |  | Total Carrying Value as of December 31, 2013 |
Trading securities held in the deferred compensation plans |  | $ | 67,766 |  |  | $ | — |  |  | $ | — |  |  | $ | 67,766 |
Derivatives –swaps |  |  | — |  |  |  | (18,812 | ) |  |  | — |  |  |  | (18,812 | )
–collars |  |  | — |  |  |  | 2,314 |  |  |  | — |  |  |  | 2,314 |
–basis swaps |  |  | — |  |  |  | 3,381 |  |  |  | 548 |  |  |  | 3,929 |

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Our trading securities in Level 1 are exchange-traded and measured at fair value with a market approach using end of period market values. Derivatives in Level 2 are measured at fair value with a market approach using third-party pricing services, which have been corroborated with data from active markets or broker quotes. As of March 31, 2014, we have four natural gas basis swaps categorized as Level 3 due to the forward price curve being unavailable for the regional sales point. We based the fair value on the most similar regional forward natural gas basis curve received from a third party pricing service along with assumed basis differentials based on historical trends.

Our trading securities held in the deferred compensation plan are accounted for using the mark-to-market accounting method and are included in other assets in the accompanying consolidated balance sheets. We elected to adopt the fair value option to simplify our accounting for the investments in our deferred compensation plan. Interest, di vidends, and mark-to-market gains or losses are included in deferred compensation plan expense in the accompanying statement of operations. For first quarter 2014, interest and dividends were $274,000 and the mark-to-market adjustment was a gain of $429,000 compared to interest and dividends of $40,000 and mark-to-market gain of $1.6 million in the same period of the prior year.

Fair Values—Reported

The following table presents the carrying amounts and the fair values of our financial instruments as of March 31, 2014 and December 31, 2013 (in thousands):

|  | March 31, 2014 |  |  | December 31, 2013 |
|  | Carrying Value |  |  | Fair Value |  |  | Carrying Value |  |  | Fair Value |
Assets: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity swaps, collars and basis swaps |  | $ | 15,997 |  |  | $ | 15,997 |  |  | $ | 13,654 |  |  | $ | 13,654 |
Marketable securities(a) |  |  | 67,119 |  |  |  | 67,119 |  |  |  | 67,766 |  |  |  | 67,766 |
(Liabilities): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity swaps, collars and basis swaps |  |  | (72,996 | ) |  |  | (72,996 | ) |  |  | (26,223 | ) |  |  | (26,223 | )
Bank credit facility(b) |  |  | (594,000 | ) |  |  | (594,000 | ) |  |  | (500,000 | ) |  |  | (500,000 | )
Deferred compensation plan(c) |  |  | (262,123 | ) |  |  | (262,123 | ) |  |  | (271,738 | ) |  |  | (271,738 | )
8.00% senior subordinated notes due 2019(b) |  |  | (290,866 | ) |  |  | (313,875 | ) |  |  | (290,516 | ) |  |  | (319,500 | )
6.75% senior subordinated notes due 2020(b) |  |  | (500,000 | ) |  |  | (540,000 | ) |  |  | (500,000 | ) |  |  | (541,250 | )
5.75% senior subordinated notes due 2021(b) |  |  | (500,000 | ) |  |  | (535,625 | ) |  |  | (500,000 | ) |  |  | (530,625 | )
5.00% senior subordinated notes due 2022(b) |  |  | (600,000 | ) |  |  | (611,250 | ) |  |  | (600,000 | ) |  |  | (588,750 | )
5.00% senior subordinated notes due 2023(b) |  |  | (750,000 | ) |  |  | (759,375 | ) |  |  | (750,000 | ) |  |  | (732,188 | )

(a) | Marketable securities, which are held in our deferred compensation plans, are actively traded on major exchanges. Refer to Note 13 for additional information.

(b) | The book value of our bank debt approximates fair value because of its floating rate structure. The fair value of our senior subordinated notes is based on end of period market quotes which are Level 2 market values. Refer to Note 8 for additional information.

(c) | The fair value of our deferred compensation plan is updated on the closing price on the balance sheet date which is a Level 1 market value.

Our current assets and liabilities contain financial instruments, the most significant of which are trade accounts receivable and payable. We believe the carrying values of our current assets and liabilities approximate fair value. Our fair value assessment incorporates a variety of considerations including (1) the short-term duration of the instruments and (2) our historical and expected incurrence of bad debt expense. Non-financial liabilities initially measured at fair value include asset retirement obligations. For additional information, see Note 9.

Concentrations of Credit Risk

As of March 31, 2014, our primary concentrations of credit risk are the risks of collecting accounts receivable and the risk of counterparties’ failure to perform under derivative obligations. Most of our receivables are from a diverse group of companies, including major energy companies, pipeline companies, local distribution companies, financial institutions and end-users in various industries. Letters of credit or other appropriate security are obtained as deemed necessary to limit our risk of loss. Our allowance for uncollectible receivables was $2.5 million at both March 31, 2014 and December 31, 2013. As of March 31, 2014, our derivative contracts consist of swaps and collars. Our exposure to credit risk is diversified primarily among major investment grade financial institutions, the majority of which we have master netting agreements which provide for offsetting payables against receivables from separate derivative contracts. To manage counterparty risk associated with our derivatives, we select and monitor our counterparties based on our assessment of their financial strength and/or credit ratings. We may also limit the level of exposure with any single counterparty. At March 31, 2014, our derivative counterparties include fourteen financial institutions, of which all but two are secured lenders in our bank credit facility. At March 31, 2014, our net derivative assets include a net payable to these two counterparties that are not included in our bank credit facility of $3.8 million.

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(13) STOCK-BASED COMPENSATION PLANS

Stock-Based Awards

Stock options represent the right to purchase shares of stock in the future at the fair value of the stock on the date of grant. Most stock options granted under our stock option plans vest over a three-year period and expire five years from the date they are granted. In 2005, we began granting SARs to reduce the dilutive impact of our equity plans. Similar to stock options, SARs represent the right to receive a payment equal to the excess of the fair market value of shares of common stock on the date the right is exercised over the value of the stock on the date of grant. All SARs granted under our Amended and Restated 2005 Equity-Based Incentive Compensation Plan (the “2005 Plan”) will be settled in shares of stock, vest over a three-year period and have a maximum term of five years from the date they are granted. Beginning in first quarter 2011, the Compensation Committee of the Board of Directors also began granting restricted stock units under our equity-based stock compensation plans. These restricted stock units, which we refer to as restricted stock Equity Awards, vest over a three-year period. All awards granted have been issued at prevailing market prices at the time of grant and the vesting of these shares is based upon an employee’s continued employment with us.

In first quarter 2014, the Compensation Committee of the Board of Directors began granting performance share unit awards (“PSUs”) under our 2005 Plan. The number of shares to be issued is determined by our total shareholder return compared to the total shareholder return of a predetermined group of peer companies over the performance period. The performance unit awards vest at the end of three years. The grant date fair value of the PSUs is determined using a Monte Carlo simulation and is recognized as stock-based compensation expense over the three-year performance period.

The Compensation Committee also grants restricted stock to certain employees and non-employee directors of the Board of Directors as part of their compensation. Upon grant of these restricted shares, which we refer to as restricted stock Liability Awards, the shares generally are placed in our deferred compensation plan and, upon vesting, employees are allowed to take withdrawals either in cash or in stock. Compensation expense is rec ognized over the balance of the vesting period, which is typically three years for employee grants and immediate vesting for non-employee directors. All restricted stock awards are issued at prevailing market prices at the time of the grant and vesting is based upon an employee’s continued employment with us. Prior to vesting, all restricted stock awards have the right to vote such shares and receive dividends thereon. These Liability Awards are classified as a liability and are remeasured at fair value each reporting period. This mark-to-market adjustment is reported as deferred compensation plan expense in the accompanying consolidated statements of operations.

Total Stock-Based Compensation Expense

Stock-based compensation represents amortization of restricted stock, PSUs and SARs expense. Unlike the other forms of stock-based compensation, the mark-to-market adjustment of the liability related to the vested restricted stock held in our deferred compensation plans is directly tied to the change in our st ock price and not directly related to the functional expenses and therefore, is not allocated to the functional categories. The following table details the allocation of stock-based compensation that is allocated to functional expense categories (in thousands):

|  | Three Months Ended March 31, |
|  | 2014 |  |  | 2013 |
Operating expense |  | $ | 852 |  |  | $ | 661 |
Brokered natural gas and marketing expense |  |  | 528 |  |  |  | 249 |
Exploration expense |  |  | 1,153 |  |  |  | 1,070 |
General and administrative expense |  |  | 11,604 |  |  |  | 10,306 |
Total |  | $ | 14,137 |  |  | $ | 12,286 |

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Stock Appreciation Right Awards

We have two active equity-based stock plans, the 2005 Plan and the 2004 Non-Employee Director Stock Option Plan. Under these plans, incentive and non-qualified stock options, SARs, restricted stock units and various other awards may be issued to non-employee directors and employees pursuant to decisions of the Compensation Committee, which is comprised of only non-employee, independent directors. Of the 2.4 million grants outstanding at March 31, 2014, all are grants relating to SARs. Information with respect to SARs activity is summarized below:

|  | Shares |  |  | Weighted Average Exercise Price |
Outstanding at December 31, 2013 |  |  | 2,582,074 |  |  | $ | 56.36 |
Granted |  |  | 1,104 |  |  |  | 81.74 |
Exercised |  |  | (137,271 | ) |  |  | 45.45 |
Expired/forfeited |  |  | — |  |  |  | — |
Outstanding at March 31, 2014 |  |  | 2,445,907 |  |  | $ | 56.98 |

During first three months 2014, we granted SARs to our non-executive chairman in conjunction with his retirement from Range as an employee. The weighted average grant date fair value of these SARs, based on our Black-Scholes-Merton assumptions, is shown below:

|  | Three Months Ended March 31, 2014 |
Weighted average exercise price per share |  | $ | 81.74 |
Expected annual dividends per share |  |  | 0.20 | %
Expected life in years |  |  | 4.3 |
Expected volatility |  |  | 33 | %
Risk-free interest rate |  |  | 1.4 | %
Weighted average grant date fair value |  | $ | 23.17 |

Performance Share Unit Awards

A summary of our performance share unit awards (“PSUs”) outstanding at March 31, 2014 is summarized below:

|  | Number of Units (a) |  |  | Weighted Average Grant Date Fair Value |
Outstanding at December 31, 2013 |  |  | — |  |  | $ | — |
Units granted |  |  | 57,421 |  |  |  | 82.60 |
Outstanding at March 31, 2014 |  |  | 57,421 |  |  | $ | 82.60 |

(a) | These amounts reflect the number of performance units granted. The actual payout of shares may be between zero percent and 150% of the performance units granted depending on the total shareholder return ranking compared to the peer companies at the vesting date.

The following assumptions were used to estimate the fair value of PSUs granted during the first three months 2014:

|  | Three Months Ended March 31, 2014 |
Risk-free interest rate |  |  | 0.71 | %
Expected annual volatility |  |  | 34 | %
Grant date fair value per unit |  | $ | 82.60 |

We recorded PSU compensation expense of $533,000 in the first three months 2014 compared to none in the same period of 2013.

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Restricted Stock Awards

Equity Awards

In first three months 2014, we granted 351,000 restricted stock Equity Awards to employees at an average grant price of $84.89 compared to 386,000 restricted stock Equity Awards granted to employees at an average grant price of $71.02 in the same period of 2013. These awards generally vest over a three-year period. We recorded compensation expense for these Equity Awards of $6.5 million in the first three months 2014 compared to $4.3 million in the same period of 2013. Equity Awards are not issued to employees until they are vested. Employees do not have the option to receive cash.

Liability Awards

In first three months 2014, we granted 76,000 shares of restricted stock Liability Awards as compensation to employees at an average price of $85.02 with vesting generally over a three-year period. We also granted 950 shares at an average price of $81.74 to a director, which vested immediately. In the same period of 2013, we granted 125,000 shares of Liability Awards as compensation to employees at an average price of $71.40 with vesting generally over a three-year period. We recorded compensation expense for Liability Awards of $4.7 million in first three months 2014 compared to $4.5 million in the same period of 2013. Substantially all of these awards are held in our deferred compensation plan, are classified as a liability and are remeasured at fair value each reporting period. This mark-to-market adjustment is reported as deferred compensation expense in our consolidated statements of operations (see additional discussion below).

A summary of the status of our non-vested restricted stock and restricted stock units outstanding at March 31, 2014 is summarized below:

|  | Equity Awards |  |  | Liability Awards |
|  | Shares |  |  | Weighted Average Grant Date Fair Value |  |  | Shares |  |  | Weighted Average Grant Date Fair Value |
Outstanding at December 31, 2013 |  |  | 385,063 |  |  | $ | 68.24 |  |  |  | 389,013 |  |  | $ | 71.02 |
Granted |  |  | 350,594 |  |  |  | 84.89 |  |  |  | 77,435 |  |  |  | 84.98 |
Vested |  |  | (93,241 | ) |  |  | 69.86 |  |  |  | (77,142 | ) |  |  | 69.55 |
Forfeited |  |  | (1,418 | ) |  |  | 79.41 |  |  |  | (90 | ) |  |  | 71.03 |
Outstanding at March 31, 2014 |  |  | 640,998 |  |  | $ | 77.09 |  |  |  | 389,216 |  |  | $ | 74.09 |

Deferred Compensation Plan

Our deferred compensation plan gives non-employee directors, officers and key employees the ability to defer all or a portion of their salaries and bonuses and invest in Range common stock or make other investments at the individual’s discretion. Range provides a partial matching contribution which vests over three years. The assets of the plans are held in a grantor trus t, which we refer to as the Rabbi Trust, and are therefore available to satisfy the claims of our general creditors in the event of bankruptcy or insolvency. Our stock held in the Rabbi Trust is treated as a liability award as employees are allowed to take withdrawals from the Rabbi Trust either in cash or in Range stock. The liability for the vested portion of the stock held in the Rabbi Trust is reflected as deferred compensation liability in the accompanying consolidated balance sheets and is adjusted to fair value each reporting period by a charge or credit to deferred compensation plan expense on our consolidated statements of operations. The assets of the Rabbi Trust, other than our common stock, are invested in marketable securities and reported at their market value as other assets in the accompanying consolidated balance sheets. The deferred compensation liability reflects the vested market value of the marketable securities and Range stock held in the Rabbi Trust. Changes in the market value of the marketable securities and changes in the fair value of the deferred compensation plan liability are charged or credited to deferred compensation plan expense each quarter. We recorded mark-to-market income of $2.0 million in first quarter 2014 compared to mark-to-market loss of $42.4 million in first quarter 2013. The Rabbi Trust held 2.8 million shares (2.4 million of vested shares) of Range stock at March 31, 2014 compared to 2.8 million shares (2.4 million of vested shares) at December 31, 2013.

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(14) SUPPLEMENTAL CASH FLOW INFORMATION

|  | Three Months Ended March 31, |
|  | 2014 |  |  | 2013 |
|  | (in thousands) |
Net cash provided from operating activities included: |  |  |  |  |  |  |  |
Income taxes (refunded) paid to taxing authorities |  | $ | 39 |  |  | $ | (162 | )
Interest paid |  |  | 55,190 |  |  |  | 37,541 |
Non-cash investing and financing activities included: |  |  |  |  |  |  |  |
Asset retirement costs capitalized, net |  |  | 3,218 |  |  |  | 1,690 |
Increase in accrued capital expenditures |  |  | 6,808 |  |  |  | 128,136 |

(15) COMMITMENTS AND CONTINGENCIES

Litigation

We are the subject of, or party to, a number of pending or threatened legal actions, administrative proceedings and claims arising in the ordinary course of our business. While many of these matters involve inherent uncertainty, we believe that the amount of the liability, if any, ultimately incurred wi th respect to proceedings or claims will not have a material adverse effect on our consolidated financial position as a whole or on our liquidity, capital resources or future annual results of operations. We will continue to evaluate our litigation quarterly and will establish and adjust any litigation reserves as appropriate to reflect our assessment of the then current status of litigation.

Transportation and Gathering Contracts

In the three months ended March 31, 2014, our transportation and gathering commitments increased by approximately $628.4 million over the next 25 years primarily due to two new firm transportation contracts. In addition, we have entered into additional agreements which are contingent on certain pipeline and gathering modifications and/or construction, that will range between five and fifteen year terms and are expected to begin in late 2014 through 2017. Based on these new contracts, we will have transportation and gathering obligations for a range of natural gas volumes from 25,000 mcf per day to 300,000 mcf per day through the end of the contract term.

(16) Capitalized Costs and Accumulated Depreciation, Depletion and Amortization (a)

|  | March 31, 2014 |  |  | December 31, 2013 |
|  | (in thousands) |
Natural gas and oil properties: |  |  |  |  |  |  |  |
Properties subject to depletion |  | $ | 8,467,064 |  |  | $ | 8,225,859 |
Unproved properties |  |  | 842,679 |  |  |  | 807,022 |
Total |  |  | 9,309,743 |  |  |  | 9,032,881 |
Accumulated depreciation, depletion and amortization |  |  | (2,397,089 | ) |  |  | (2,274,444 | )
Net capitalized costs |  | $ | 6,912,654 |  |  | $ | 6,758,437 |

(a) | Includes capitalized asset retirement costs and the associated accumulated amortization.

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(17) Costs Incurred for Property Acquisition, Exploration and Development (a)

|  | Three Months Ended March 31, 2014 |  |  | Year Ended December 31, 2013 |
|  | (in thousands) |
Acreage purchases |  | $ | 48,597 |  |  | $ | 137,538 |
Development |  |  | 223,912 |  |  |  | 938,668 |
Exploration: |  |  |  |  |  |  |  |
Drilling |  |  | 7,737 |  |  |  | 189,742 |
Expense |  |  | 13,694 |  |  |  | 60,384 |
Stock-based compensation expense |  |  | 1,153 |  |  |  | 4,025 |
Gas gathering facilities: |  |  |  |  |  |  |  |
Development |  |  | 3,618 |  |  |  | 47,086 |
Subtotal |  |  | 298,711 |  |  |  | 1,377,443 |
Asset retirement obligations |  |  | 3,218 |  |  |  | 76,373 |
Total costs incurred |  | $ | 301,929 |  |  | $ | 1,453,816 |

(a) | Includes cost incurred whether capitalized or expensed.

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IT EM 2. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion is intended to assist you in understanding our business and results of operations together with our present financial condition. Certain sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations include forward-looking statements concerning trends or events potentially affecting our business. These statements contain words such as “anticipates,” “believes,” “expects,” “targets,” “plans,” “projects,” “could,” “may,” “should,” “would” or similar words indicating that future outcomes are uncertain. In accordance with “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ materially from those set forth in the forward-looking statements. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. For additional risk factors affecting our business, see Item 1A. Risk Factors as set forth in our Annual Report on Form 10-K for the year ended December 31, 2013, as filed with the SEC on February 26, 2014.

Overview of Our Business

We are a Fort Worth, Texas-based independent natural gas, natural gas liquids (“NGLs”) and oil company primarily engaged in the exploration, development and acquisition of natural gas and oil properties in the Appalachian and Southwestern regions of the United States. We operate in one segment and have a single company-wide management team that administers all pro perties as a whole rather than by discrete operating segments. We track only basic operational data by area.

Our objective is to build stockholder value through consistent growth in reserves and production on a cost-efficient basis. Our strategy to achieve our objective is to increase reserves and production through internally generated drilling projects occasionally coupled with complementary acquisitions. Our revenues, profitability and future growth depend substantially on prevailing prices for natural g as, NGLs, crude oil and condensate and on our ability to economically find, develop, acquire and produce natural gas, NGLs and crude oil reserves. Prices for natural gas, NGLs and oil fluctuate widely and affect:

— | the amount of cash flows available for capital expenditures;

— | our ability to borrow and raise additional capital; and

— | the quantity of natural gas, NGLs and oil we can economically produce.

We prepare our financial statements in conformity with generally accepted accounting principles, which require us to make estimates and assumptions that affect our reported results of operations and the amount of our reported assets, liabilities and proved natural gas, NGLs and oil reserves. We use the successful efforts method of accounting for our natural gas, NGLs and oil activities.

Market Conditions

Prices for our products significantly impact our revenue, net income and cash flow. Natural gas, NGLs and oil are commodities and prices for commodities are inherently volatile. The following table lists average New York Mercantile Exchange (“NYMEX”) prices for natural gas and oil and the Mont Belvieu NGL composite price for the three months ended March 31, 2014 and 2013:

|  | Three Months Ended March 31, |
|  | 2014 |  |  | 2013 |
Average NYMEX prices (a) |  |  |  |  |  |  |  |
Natural gas (per mcf) |  | $ | 4.89 |  |  | $ | 3.35 |
Oil (per bbl) |  | $ | 98.61 |  |  | $ | 94.25 |
Mont Belvieu NGL Composite (per gallon) |  | $ | 0.91 |  |  | $ | 0.78 |

(a) | Based on weighted average of bid week prompt month prices.

Consolidated Results of Operations

Overview of First Quarter 2014 Results

During first quarter 2014, we achieved the following financial and operating results:

— | increased revenue from the sale of natural gas, NGLs and oil by 44% from the same period of 2013;

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— | achieved 21% production growth over the same period of 2013;

— | continued expansion of our activities in the Marcellus Shale in Pennsylvania by growing production, proving up acreage and acquiring additional unproved acreage;

— | excluding workovers, our direct operating expenses per mcfe remained flat from the same period of 2013;

— | reduced our depletion, depreciation and amortization (“DD&A”) rate 8% over the same period of 2013;

— | entered into additional derivative contracts for 2014, 2015 and 2016; and

— | realized $181.2 million of cash flow from operating activities.

Our first quarter 2014 net income was $32.5 million, or $0.20 per diluted common share compared to a net loss of $75.6 million, or a loss of $0.47 per diluted common share in the same period 2013. During first quarter 2014, we had an increase in revenue from the sale of natural gas, NGLs and oil driven by higher production volumes of 21%. Our first quarter 2014 producti on growth was due to the continued success of our drilling program, particularly in the Marcellus Shale. First quarter 2014 production for NGLs increased 137% from the same period of 2013 due to our sales of ethane based on our new ethane sales/transport agreements which commenced initial deliveries in late 2013. When comparing first quarter 2014 to the same period of 2013, we also experienced a favorable increase in our non-cash mark-to-market related to our deferred compensation plans along with favorable non-cash fair value adjustments on our commodity derivatives, a non-GAAP measure and lower general and administrative expense, all of which were somewhat offset by lower realized prices. Realized prices include the impact of basis differentials. Average natural gas differentials were $0.66 per mcf above NYMEX in the first quarter 2014 compared to $0.15 per mcf above NYMEX in the same quarter 2013. This increase was more than offset by realized losses on our basis hedging in the first quarter 2014 of $0.90 per mcfe.

We believe natural gas, NGLs and oil prices will remain volatile and will be affected by, among other things, weather, the U.S. and worldwide economy, new technology and the level of oil and gas production in North America and worldwide. Although we have entered into derivative contracts covering a portion of our production volumes for the remainder of 2014 and for 2015 and 2016, a sustained lower price environment would result in lower prices for unprotected volumes and reduce the prices that we can enter into derivative contracts for additional volumes in the future.

Natural Gas, NGLs and Oil Sales, Production and Realized Price Calculations

Our revenues vary primarily as a result of changes in realized commodity prices, production volumes and the value of certain of our derivative contracts. We generally sell natural gas, NGLs and oil under two types of agreements, which are common in our industry. Revenue from the sale of natural gas, NGLs and oil sales include netback arrangements where we se ll natural gas and oil at the wellhead and collect a price, net of transportation incurred by the purchaser. In this instance, we record revenue at the price we receive from the purchaser. Revenues are also realized from sales arrangements where we sell natural gas or oil at a specific delivery point and receive proceeds from the purchaser with no transportation deduction. Third party transportation costs we incur to get our commodity to the delivery point are reported in transportation, gathering and compression expense. Hedges included in natural gas, NGLs and oil sales reflect settlements on those derivatives that qualified for hedge accounting. Cash settlements and changes in the market value of derivative contracts that are not accounted for as hedges are included in derivative fair value income or loss in the statement of operations. For more information on revenues from derivative contracts that are not accounted for as hedges, see the derivative fair value loss discussion below. Effective March 1, 2013, we elected to de-designate all commodity contracts that were previously designated as cash flow hedges and elected to discontinue hedge accounting prospectively. Refer to Note 11 to the consolidated financial statements for more information.

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In first quarter 2014, natural gas, NGLs and oil sales increased 44% compared to the same period of 2013 with a 21% increase in production and a 19% increase in realized prices. The following table illustrates the primary components of natural gas, NGLs, crude oil and condensate sales for the three months ended March 31, 2014 and 2013 (in thousands):

|  | Three Months Ended March 31, |
|  | 2014 |  |  | 2013 |  |  | Change |  | % Change |
Natural gas, NGLs and oil sales |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Gas wellhead |  | $ | 346,226 |  |  | $ | 217,088 |  |  | $ | 129,138 |  |  | 59 | %
Gas hedges realized (a) |  |  | 1,168 |  |  |  | 35,478 |  |  |  | (34,310 | ) |  | (97 | %)
Total gas revenue |  | $ | 347,394 |  |  | $ | 252,566 |  |  | $ | 94,828 |  |  | 38 | %
Total NGLs revenue |  | $ | 135,504 |  |  | $ | 67,571 |  |  | $ | 67,933 |  |  | 101 | %
Oil and condensate wellhead |  | $ | 88,121 |  |  | $ | 77,080 |  |  | $ | 11,041 |  |  | 14 | %
Oil hedges realized (a) |  |  | 998 |  |  |  | 1,022 |  |  |  | (24 | ) |  | (2 | %)
Total oil and condensate revenue |  | $ | 89,119 |  |  | $ | 78,102 |  |  | $ | 11,017 |  |  | 14 | %
Combined wellhead |  | $ | 569,851 |  |  | $ | 361,739 |  |  | $ | 208,112 |  |  | 58 | %
Combined hedges (a) |  |  | 2,166 |  |  |  | 36,500 |  |  |  | (34,334 | ) |  | (94 | %)
Total natural gas, NGLs and oil sales |  | $ | 572,017 |  |  | $ | 398,239 |  |  | $ | 173,778 |  |  | 44 | %

(a) | Cash settlements related to derivatives that qualified or were historically designated for hedge accounting.

Our production continues to grow through drilling success as we place new wells on production partially offset by the natural decline of our natural gas and oil wells and asset sales. When compared to the same period of 2013, our first quarter 2014 production volumes increased 25% in our Appalachian region and decreased 5% in our Southwestern region. When compared to the same period of 2013, our Marcellus production volumes increased 29% for the first quarter. The decline in natural gas production volumes is primarily related to the increased sales of ethane, the extraction of which reduces natural gas volumes to be sold and, to a lesser extent, adverse weather conditions during first quarter 2014. Ethane production volumes are reported with NGLs in the table below. Our production for the three months ended March 31, 2014 and 2013 is set forth in the following table:

|  | Three Months Ended March 31, |
|  | 2014 |  |  | 2013 |  |  | Change |  |  | % Change |
Production (a) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Natural gas (mcf) |  |  | 62,017,581 |  |  |  | 62,023,956 |  |  |  | (6,375 |  | ) |  |  | % |  |
NGLs (bbls) |  |  | 4,471,481 |  |  |  | 1,889,424 |  |  |  | 2,582,057 |  |  |  |  | 151 | % |
Crude oil and condensate (bbls) |  |  | 1,035,145 |  |  |  | 912,662 |  |  |  | 122,483 |  |  |  |  | 13 | % |
Total (mcfe) (b) |  |  | 95,057,337 |  |  |  | 78,836,472 |  |  |  | 16,220,865 |  |  |  |  | 21 | % |
Average daily production (a) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Natural gas (mcf) |  |  | 689,084 |  |  |  | 689,155 |  |  |  | (71 |  | ) |  |  | % |  |
NGLs (bbls) |  |  | 49,683 |  |  |  | 20,994 |  |  |  | 28,689 |  |  |  |  | 137 | % |
Crude oil and condensate (bbls) |  |  | 11,502 |  |  |  | 10,141 |  |  |  | 1,361 |  |  |  |  | 13 | % |
Total (mcfe) (b) |  |  | 1,056,193 |  |  |  | 875,961 |  |  |  | 180,232 |  |  |  |  | 21 | % |

(a) | Represents volumes sold regardless of when produced.

(b) | Oil and NGLs are converted to mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural gas, which is not necessarily indicative of the relationship between oil and natural gas prices.

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Our average realized price (including all derivative settlements and third-party transportation costs) received during first quarter 2014 was $4.14 per mcfe compared to $4.26 per mcfe in the same period of 2013. Because we record transportation costs on two separate bases, as required by U.S. GAAP, we believe computed final realized prices should include the total impact of transportation, gathering and compression expense. Our average realized price (including all derivative settlements and third-party transportation costs) calculation also includes all cash settlements for derivatives, whether or not they qualified for hedge accounting. Average sales prices (wellhead) do not include derivative settlements or third party transportation costs which are reported in transportation, gathering and compression expense on the accompanying statements of operations. Average sales prices (wellhead) do include transportation costs where we receive net revenue proceeds from purchasers. Average realized price calculations for the three months ended March 31, 2014 and 2013 are shown below:

|  | Three Months Ended March 31, |
|  | 2014 |  |  | 2013 |
Average Prices |  |  |  |  |  |  |  |
Average sales prices (wellhead): |  |  |  |  |  |  |  |
Natural gas (per mcf) |  | $ | 5.58 |  |  | $ | 3.50 |
NGLs (per bbl) |  |  | 30.30 |  |  |  | 35.76 |
Crude oil and condensate (per bbl) |  |  | 85.13 |  |  |  | 84.46 |
Total (per mcfe) (a) |  |  | 5.99 |  |  |  | 4.59 |
Average realized prices (including derivative settlements that qualified for hedge accounting): |  |  |  |
Natural gas (per mcf) |  | $ | 5.60 |  |  | $ | 4.07 |
NGLs (per bbl) |  |  | 30.30 |  |  |  | 35.76 |
Crude oil and condensate (per bbl) |  |  | 86.09 |  |  |  | 85.58 |
Total (per mcfe) (a) |  |  | 6.02 |  |  |  | 5.05 |
Average realized prices (including all derivative settlements): |  |  |  |
Natural gas (per mcf) |  | $ | 4.20 |  |  | $ | 4.09 |
NGLs (per bbl) |  |  | 27.34 |  |  |  | 35.29 |
Crude oil and condensate (per bbl) |  |  | 82.03 |  |  |  | 85.46 |
Total (per mcfe) (a) |  |  | 4.92 |  |  |  | 5.06 |
Average realized prices (including all derivative settlements and third party transportation costs paid by Range): |  |  |  |
Natural gas (per mcf) |  | $ | 3.14 |  |  | $ | 3.14 |
NGLs (per bbl) |  |  | 25.35 |  |  |  | 33.61 |
Crude oil and condensate (per bbl) |  |  | 82.03 |  |  |  | 85.46 |
Total (per mcfe) (a) |  |  | 4.14 |  |  |  | 4.26 |

(a) | Oil and NGLs are converted to mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural gas, which is not indicative of the relationship between oil and natural gas prices.

Derivative fair value loss was $146.9 million in first quarter 2014 compared to $99.9 million in the same period of 2013. Through February 28, 2013, some of our derivatives did not qualify for hedge accounting and were accounted for using the mark-to-market accounting method whereby all realized and unrealized gains and losses related to these contracts are included in derivative fair value income or loss in the accompanying consolidated statements of operations. Effective March 1, 2013, we discontinued hedge accounting prospectively. Since March 1, 2013, all of our derivatives are accounted for using the mark-to-market accounting method. Mark-to-market accounting treatment results in volatility of our revenues as unrealized gains and losses from derivatives are included in total revenue. As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our derivatives. Gains on our derivatives generally indicate lower wellhead revenues in the future while losses indicate higher future wellhead revenues.

Loss on the sale of assets was $353,000 in first quarter 2014 compared to a loss of $166,000 in the same period of 2013. In first quarter 2014 and 2013, we sold miscellaneous proved and unproved oil and gas properties and inventory for proceeds re ceived of $294,000 in first quarter 2014 compared to $38.2 million in the same period of 2013.

Brokered natural gas, marketing and other revenue in first quarter 2014 was $32.5 million compared to $21.0 million in the same period of 2013. The first three months 2014 includes a loss from equity method investments of $133,000 and $33.2 million of revenue from marketing and the sale of brokered gas. The first three months 2013 includes loss from equity method investments of $80,000 and $21.1 million of revenue from marketing and the sale of brokered gas. These revenues increased due to an increase in brokered volumes.

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We believe some of our expense fluctuations are best analyzed on a unit-of-production, or per mcfe, basis. The following presents information about certain of our expenses on a per mcfe basis for the three months ended March 31, 2014 and 2013:

|  | Three Months Ended March 31, |
|  | (per mcfe) |
|  | 2014 |  |  | 2013 |  |  | Change |  |  | % Change |
Direct operating expense |  | $ | 0.42 |  |  | $ | 0.38 |  |  | $ | 0.04 |  |  |  | 11 | %
Production and ad valorem tax expense |  |  | 0.12 |  |  |  | 0.14 |  |  |  | (0.02 | ) |  |  | (14 | %)
General and administrative expense |  |  | 0.52 |  |  |  | 1.07 |  |  |  | (0.55 | ) |  |  | (51 | %)
Interest expense |  |  | 0.48 |  |  |  | 0.54 |  |  |  | (0.06 | ) |  |  | (11 | %)
Depletion, depreciation and amortization expense |  |  | 1.35 |  |  |  | 1.46 |  |  |  | (0.11 | ) |  |  | (8 | %)

Direct operating expense was $39.8 million in first quarter 2014 compared to $30.2 million in the same period of 2013. We experience increases in operating expenses as we add new wells and manage existing properties. Direct operating expenses include normally recurring expenses to operate and produce our wells, non-recurring well workovers and repair-related expenses. Our production volumes increased 21% but, on an absolute basis, our spending for direct operating expenses for first quarter 2014 increased 32% with an increase in the number of producing wells, higher workover costs, higher water handling and winter operations costs somewhat offset by the sale of certain non-core assets at the beginning of second quarter 2013. We incurred $5.6 million of workover costs in first quarter 2014 compared to $1.4 million of workover costs in the same period of 2013.

On a per mcfe basis, direct operating expense in first quarter 2014 increased 11% from the same period of 2013 with the increase consisting of higher workover costs. We expect to experience lower costs per mcfe as we increase production from our Marcellus Shale wells due to their lower operating cost relative to our other operating areas. However, our operating costs in the Mississippian play are higher on a per mcfe basis than the Marcellus Shale play. As production increases from the Mississippian play, our direct operating expenses per mcfe are expected to increase. The following table summarizes direct operating expenses per mcfe for the three months ended March 31, 2014 and 2013:

|  | Three Months Ended March 31, |
|  | (per mcfe) |
|  | 2014 |  |  | 2013 |  |  | Change |  |  | % Change |
Lease operating expense |  | $ | 0.35 |  |  | $ | 0.35 |  |  | $ | ¾ |  |  |  | ¾ | %
Workovers |  |  | 0.06 |  |  |  | 0.02 |  |  |  | 0.04 |  |  |  | 200 | %
Stock-based compensation (non-cash) |  |  | 0.01 |  |  |  | 0.01 |  |  |  | ¾ |  |  |  | ¾ | %
Total direct operating expense |  | $ | 0.42 |  |  | $ | 0.38 |  |  | $ | 0.04 |  |  |  | 11 | %

Production and ad valorem taxes are paid based on market prices, not hedged prices. This expense category also includes the Pennsylvania impact fee that was initially assessed in 2012. Production and ad valorem taxes (excluding the impact fee) were $5.2 million in first quarter 2014 compared to $4.2 million in the same period of 2013. On a per mcfe basis, production and ad valorem taxes (excluding the impact fee) was $0.05 in both first quarter 2014 and first quarter 2013 with an increase in volumes not subject to production taxes more than offset by higher prices. In February 2012, the Commonwealth of Pennsylvania enacted an “impact fee” on unconventional natural gas and oil production which includes the Marcellus Shale. Included in first quarter 2014 is a $6.5 million impact fee ($0.07 per mcfe) compared to $7.1 million ($0.09 per mcfe) in the same period of the prior year.

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General and administrative (“G&A”) expense was $49.2 million in first quarter 2014 compared to $84.1 million for the same period of 2013. The first quarter 2014 decrease of $34.8 million when compared to 2013 is primarily due to lower lawsuit settlements. The first quarter 2013 included an accrual of $35.0 million related to an Oklahoma lawsuit that was settled in second quarter 2013 for $87.5 million. Stock-based compensation expense represents the amortization of restricted stock grants and performance shares granted to our employees and non-employee directors as part of compensation. On a per mcfe basis, G&A expense decreased 51% from first quarter 2013 primarily due to the settlement of the Oklahoma lawsuit which was partially accrued in first quarter 2013 and lower salaries and benefits. The following table summarizes general and administrative expenses per mcfe for the three months ended March 31, 2014 and 2013:

|  | Three Months Ended March 31, |
|  | (per mcfe) |
|  | 2014 |  |  | 2013 |  |  | Change |  |  | % Change |
General and administrative |  | $ | 0.40 |  |  | $ | 0.50 |  |  | $ | (0.10 | ) |  |  | (20 | %)
Oklahoma legal settlement |  |  | ¾ |  |  |  | 0.44 |  |  |  | (0.44 | ) |  |  | (100 | %)
Stock-based compensation (non-cash) |  |  | 0.12 |  |  |  | 0.13 |  |  |  | (0.01 | ) |  |  | (8 | %)
Total general and administrative expenses |  | $ | 0.52 |  |  | $ | 1.07 |  |  |  | (0.55 | ) |  |  | (51 | %)

Interest expense was $45.4 million for first quarter 2014 compared to $42.2 million for first quarter 2013. The following table presents information about interest expense per mcfe for the three months ended March 31, 2014 and 2013:

|  | Three Months Ended March 31, |
|  | (per mcfe) |
|  | 2014 |  |  | 2013 |  |  | Change |  |  | % Change |
Bank credit facility |  | $ | 0.05 |  |  | $ | 0.06 |  |  | $ | (0.01 | ) |  |  | (17 | %)
Subordinated notes |  |  | 0.41 |  |  |  | 0.45 |  |  |  | (0.04 | ) |  |  | (9 | %)
Amortization of deferred financing costs and other |  |  | 0.02 |  |  |  | 0.03 |  |  |  | (0.01 | ) |  |  | (33 | %)
Total interest expense |  | $ | 0.48 |  |  | $ | 0.54 |  |  |  | (0.06 | ) |  |  | (11 | %)

On an absolute basis, the increase in interest expense for first quarter 2014 from the same period of 2013 was primarily due to an increase in outstanding debt balances. In March 2013, we issued $750.0 million of 5.0% senior subordinated notes due 2023. We used the proceeds to repay our outstanding bank debt which carries a lower interest rate. We used the proceeds to repay $350.0 mil lion of our outstanding credit facility balance and for general corporate purposes. The 2013 note issuance was undertaken to better match the maturities of our debt with the life of our properties and to give us greater liquidity for the near term. Average debt outstanding on the bank credit facility for first quarter 2014 was $611.8 million compared to $685.6 million in the same period of 2013 and the weighted average interest rate on the bank credit facility was 2.0% in first quarter 2014 compared to 2.1% in the same period of 2013.

Depletion, depreciation and amortization (“DD&A”) was $128.7 million in first quarter 2014 compared to $115.1 million in the same period of 2013. The increase in first quarter 2014 when compared to the same period of 2013 is due to a 7% decrease in depletion rates more than offset by a 21% increase in production. Depletion expense, the largest component of DD&A, was $1.28 per mcfe in first quarter 2014 compared to $1.38 per mcfe in the same period of 2013. We have historically adjusted our depletion rates in the fourth quarter of each year based on the year-end reserve report and other times during the year when circumstances indicate there has been a significant change in reserves or costs. Our depletion rate per mcfe continues to decline due to our drilling success in the Marcellus Shale. The following table summarizes DD&A expense per mcfe for the three months ended March 31, 2014 and 2013:

|  | Three Months Ended March 31, |
|  | (per mcfe) |
|  | 2014 |  |  | 2013 |  |  | Change |  |  | % Change |
Depletion and amortization |  | $ | 1.28 |  |  | $ | 1.38 |  |  | $ | (0.10 | ) |  |  | (7 | %)
Depreciation |  |  | 0.03 |  |  |  | 0.05 |  |  |  | (0.02 | ) |  |  | (40 | %)
Accretion and other |  |  | 0.04 |  |  |  | 0.03 |  |  |  | 0.01 |  |  |  | 33 | %
Total DD&A expense |  | $ | 1.35 |  |  | $ | 1.46 |  |  | $ | (0.11 | ) |  |  | (8 | %)

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Other Operating Expenses

Our total operating expenses also include other expenses that generally do not trend with production. These expenses include stock-based compensation, transportation, gathering and compression expense, brokered natural gas and marketing expense, exploration expense, abandonment and impairment of unproved properties and deferred compensation plan expense. Stock-based compensation includes the amortization of restricted stock grants, PSUs and SARs grants. The following table details the allocation of stock-based compensation that is allocated to functional expense categories for the three months ended March 31, 2014 and 2013 (in thousands):

|  | Three Months Ended March 31, |
|  | 2014 |  |  | 2013 |
Direct operating expense |  | $ | 852 |  |  | $ | 661 |
Brokered natural gas and marketing expense |  |  | 528 |  |  |  | 249 |
Exploration expense |  |  | 1,153 |  |  |  | 1,070 |
General and administrative expense |  |  | 11,604 |  |  |  | 10,306 |
Total stock-based compensation |  | $ | 14,137 |  |  | $ | 12,286 |

Transportation, gathering and compression expense was $74.2 million in first quarter 2014 compared to $62.4 million in the same period of 2013. These third party costs are higher than 2013 due to our production growth in the Marcellus Shale where we have third party gathering, compression and transportation agreements. First quarter 2014 also includes the impact of an ethane transportation contract. We have included these costs in the calculation of average realized prices (including all derivative settlements and third party transportation expenses paid by Range).

Brokered natural gas and marketing expense was $34.1 million in first quarter 2014 compared to $22.3 million in the same period of 2013. These costs are higher than 2013 primarily due to an increase in brokered volumes.

Exploration expense was $14.8 million in first quarter 2014 compared to $16.8 million in the same period of 2013 due to lower seismic costs and delay rental payments. The following table details our exploration related expenses for the three months ended March 31, 2014 and 2013 (in thousands):

|  | Three Months Ended March 31, |
|  | 2014 |  |  | 2013 |  |  | Change |  |  | % Change |
Seismic |  | $ | 5,245 |  |  | $ | 7,168 |  |  | $ | (1,923 | ) |  |  | (27 | %)
Delay rentals and other |  |  | 4,094 |  |  |  | 5,050 |  |  |  | (956 | ) |  |  | (19 | %)
Personnel expense |  |  | 4,353 |  |  |  | 3,651 |  |  |  | 702 |  |  |  | 19 | %
Stock-based compensation expense |  |  | 1,153 |  |  |  | 1,070 |  |  |  | 83 |  |  |  | 8 | %
Dry hole expense |  |  | 1 |  |  |  | (159 | ) |  |  | 160 |  |  |  | (101 | %)
Total exploration expense |  | $ | 14,846 |  |  | $ | 16,780 |  |  | $ | (1,934 | ) |  |  | (12 | %)

Abandonment and impairment of unproved properties was $10.0 million in first quarter 2014 compared to $15.2 million in the same period of 2013. We assess individually significant unproved properties for impairment on a quarterly basis and recognize a loss where circumstances indicate impairment in value. In determining whether a significant unproved property is impaired we consider numerous factors including, but not limited to, current exploration plans, favorable or unfavorable activity on the property being evaluated and/or adjacent properties, our geologists’ evaluation of the property and the remaining months in the lease term for the property. Impairment of individually insignificant unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success. As we continue to review our acreage positions and high grade our drilling inventory based on the current price environment, additional leasehold impairments and abandonments will likely be recorded. The decline in first quarter 2014 when compared to the same quarter of 2013 is primarily due to lower expected forfeiture rates in the Marcellus Shale.

Deferred compensation plan expense was a gain of $2.0 million in first quarter 2014 compared to a loss of $42.4 million in the same period of 2013. This non-cash item relates to the increase or decrease in value of the liability associated with our common stock that is vested and held in our deferred compensation plan. The deferred compensation liability is adjusted to fair value by a charge or a credit to deferred compensation plan expense. Our stock price decreased from $84.31 at December 31, 2013 to $82.97 at March 31, 2014. In the same quarter of the prior year, our stock price increased from $62.83 at December 31, 2012 to $81.04 at March 31, 2013.

Income tax expense (benefit) was an expense of $19.0 million in first quarter 2014 compared to a benefit of $47.2 million in first quarter 2013. The increase in income taxes in first quarter 2014 reflects a 142% increase in income from operations when

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compared to the same period of 2013. For the first quarter, the effective tax rate was 36.8% in 2014 compared to 38.4% in 2013. The 2014 and 2013 effective tax rates were different than the statutory tax rate due to state income taxes, permanent differences and changes in our valuation allowances related to deferred tax assets associated with senior executives to the extent their estimated future compensation, which includes distributions from the deferred compensation plan, is expected to exceed the $1.0 million deductible limit provided under section 162 (m) of the Internal Revenue Code. We expect our effective tax rate to be approximately 39% for the remainder of 2014, before any discrete tax items.

Management’s Discussion and Analysis of Financial Condition, Capital Resources and Liquidity

Cash Flow

Cash flows from operations are primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivatives. Our cash flows from operations are also impacted by changes in working capital. We generally maintain low cash and cash equivalent balances because we use available funds to reduce our bank debt. Short-term liquidity needs are satisfied by borrowings under ou r bank credit facility. Because of this, and since our principal source of operating cash flows (proved reserves to be produced in the following year) cannot be reported as working capital, we often have low or negative working capital. We sell a large portion of our production at the wellhead under floating market contracts. From time to time, we enter into various derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future natural gas, NGLs and oil production. The production we hedge has varied and will continue to vary from year to year depending on, among other things, our expectation of future commodity prices. Any payments due to counterparties under our derivative contracts should ultimately be funded by prices received from the sale of our production. Production receipts, however, often lag payments to the counterparties. Any interim cash needs are funded by borrowings under the bank credit facility. As of March 31, 2014, we have entered into hedging agreements covering 234.5 Bcfe for the remainder of 2014, 151.8 Bcfe for 2015 and 22.0 Bcfe for 2016. We have also entered into basis hedges for 254,164 Mmbtu/day through March 2015.

Net cash provided from operations in the first three month s 2014 was $181.2 million compared to $201.2 million in the same period of 2013. Cash provided from continuing operations is largely dependent upon commodity prices and production volumes, net of the effects of settlement of our derivative contracts. The decrease in cash provided from operating activities from 2013 to 2014 reflects a 21% increase in production offset by lower realized prices (a decline of 3%), higher operating costs and unfavorable working capital. As of March 31, 2014, we have hedged approximately 78% of our projected production for the remainder of 2014, with approximately 89% of our projected natural gas production hedged. Net cash provided from continuing operations is affected by working capital changes or the timing of cash receipts and disbursements. Changes in working capital (as reflected in our consolidated statements of cash flows) for first three months 2014 was negative $69.7 million compared to positive $35.8 million for the same period of 2013. The prior year working capital was impacted by a lawsuit settlement accrual of $35.0 million.

Net cash used in investing activities from operations in first three months 2014 was $276.2 million compared to $241.0 million in the same period of 2013.

During the three months ended March 31, 2014, we:

— | spent $226.3 million on natural gas and oil property additions;

— | spent $50.7 million on acreage, primarily in the Marcellus Shale; and

— | received proceeds from asset sales of $294,000.

During the three months ended March 31, 2013, we:

— | spent $259.6 million on natural gas and oil property additions;

— | spent $8.8 million on acreage primarily in the Marcellus Shale; and

— | received proceeds from asset sales of $38.2 million.

Net cash provided from financing activities in first three months 2014 was $94.9 million compared to $39.7 million in the same period of 2013. Historically, sources of financing have been primarily bank borrowings and capital raised through equity and debt offerings.

During the three months ended March 31, 2014, we:

— | borrowed $412.0 million and repaid $318.0 million under our bank credit facility, ending the quarter with a $594.0 million outstanding balance on our bank debt.

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During the three months ended March 31, 2013, we:

— | borrowed $368.0 million and repaid $1.1 billion under our bank credit facility, ending the quarter with $47.0 million outstanding borrowings under our bank credit facility; and

— | issued $750.0 million principal amount of 5.00% senior subordinated notes due 2023, at par, with net proceeds of approximately $738.8 million.

Liquidity and Capital Resources

Our main sources of liquidity and capital resources are internally generated cash flow from operations, a bank credit facility with uncommitted and committed availability, access to the debt and equity capital markets and asset sales. We must find new reserves and develop existing reserves to maintain and grow our production and cash flows. We accomplish this primarily through successful drilling programs which require substantial capital expenditures. We continue to take steps to ensure adequate capital resources and liquidity to fund our capital expenditure program. In first three months 2014, we entered into additional commodity derivative contracts for 2014, 2015 and 2016 to protect future cash flows. On April 3, 2014, our borrowing base and our credit facility amounts were reaffirmed.

During first three months 2014, our net cash provided from operating activities of $181.2 million and borrowing under our bank credit facility were used to fund $280.1 million of capital expenditures (including acreage acquisitions). At March 31, 2014, we had $246,000 in cash and total assets of $7.5 billion.

Long-term debt at March 31, 2014 totaled $3.2 billion, including $594.0 million outstanding on our bank credit facility and $2.6 billion of senior subordinated notes. Our available committed borrowing capacity at March 31, 2014 was $1.0 billion. Cash is required to fund capital expenditures necessary to offset inherent declines in production and reserves that are typical in the oil and natural gas industry. Future success in growing reserves and production will be highly dependent on capital resources available and the success of finding or acquiring additional reserves. We currently believe that net cash generated from operating activities, unused committed borrowing capacity under the bank credit facility and proceeds from asset sales combined with our natural gas, NGLs and oil derivatives contracts currently in place will be adequate to satisfy near-term financial obligations and liquidity needs. To the extent our capital requirements exceed our internally generated cash flow and proceeds from asset sales, debt or equity securities may be issued to fund these requirements. 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 natural gas business. A material drop in natural gas, NGLs and oil prices or a reduction in production and reserves would reduce our ability to fund capital expenditures, meet financial obligations and remain profitable. We establish a capital budget at the beginning of each calendar year and review it during the course of the year. Our 2014 capital budget is $1.52 billion. 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 natural gas, NGLs and oil, 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.

Credit Arrangements

As of March 31, 2014, we maintained a $2.0 billion revolving credit facility, which we refer to as our bank credit facility. The bank credit facility is secured by substantially all of our assets and has a maturity date of February 18, 2016. Availability under the bank credit facility is subject to a borrowing base set by the lenders semi-a nnually with an option to set more often in certain circumstances. The borrowing base is dependent on a number of factors but primarily on the lenders’ assessment of future cash flows. Redeterminations of the borrowing base require approval of two thirds of the lenders; increases to the borrowing base require 97% lender approval. On April 3, 2014, the facility amount on our bank credit facility was reaffirmed at $1.75 billion and our borrowing base was reaffirmed at $2.0 billion. Our current bank group is currently composed of twenty-eight financial institutions.

Our bank debt and our subordinated notes impose limitations on the payment of dividends and other restricted payments (as defined under the debt agreements for our bank debt and our subordinated notes). The debt agreements also contain customary covenants relating to debt incurrence, working capital, dividends and financial ratios. We are in compliance with all covenants at March 31, 2014.

Cash Dividend Payments

On March 1, 2014, the Board of Directors declared a dividend of four cents per share ($6.6 million) on our common stock, which was paid on March 31, 2014 to stockholders of record at the close of business on March 14, 2014. The amount of future

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dividends is subject to declaration by the Board of Directors and primarily depends on earnings, capital expenditures, debt covenants and various other factors.

Cash Contractual Obligations

Our contractual obligations include long-term debt, operating leases, drilling commitments, derivative obligations, asset retirement obligations and transportation and gathering commitments. As of March 31, 2014, we do not have any capital leases. As of March 31, 2014, we do not have any significant off-balance sheet debt or other such unrecorded obligations and we have not guaranteed any debt of any unrelated party. As of March 31, 2014, we had a total of $127.4 million of undrawn letters of credit under our bank credit facility.

Since December 31, 2013, there have been no material changes to our contractual obligations other than a $94.0 million increase in our outstanding bank credit facility balance and new transportation contracts which increased these commitments by approximately $628.4 million over the next 25 years.

Hedging – Oil and Gas Prices

We use commodity-based derivative contracts to manage our exposure to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. We do not utilize complex derivatives, as we typically utilize commodity swap and collar contracts to (1) reduce the effect of price volatility on the commodities we produce and sell and (2) support our annual capital budget and expenditure plans. While there is a risk that the financial benefit of rising natural gas, NGLs and oil pr ices may not be captured, we believe the benefits of stable and predictable cash flow are more important. Among these benefits are a more efficient utilization of existing personnel and planning for future staff additions, the flexibility to enter into long-term projects requiring substantial committed capital, smoother and more efficient execution of our on-going development drilling and production enhancement programs, more consistent returns on invested capital, and better access to bank and other credit markets. The fair value of these contracts, represented by the estimated amount that would be realized or payable on termination, based on a comparison of the contract price and a reference price, generally NYMEX, approximated a pretax loss of $53.4 million at March 31, 2014. The contracts expire monthly through December 2016. At March 31, 2014, the following commodity derivative contracts were outstanding:

Period |  | Contract Type |  | Volume Hedged |  | Weighted Average Hedge Price
Natural Gas |  |  |  |  |  |
2014 |  | Collars |  | 447,500 Mmbtu/day |  | $3.84–$ 4.48
2015 |  | Collars |  | 145,000 Mmbtu/day |  | $4.07–$ 4.56
2014 |  | Swaps |  | 240,145 Mmbtu/day |  | $4.18
2015 |  | Swaps |  | 234,966 Mmbtu/day |  | $4.19
2016 |  | Swaps |  | 60,000 Mmbtu/day |  | $4.18
Crude Oil |  |  |  |  |  |
2014 |  | Collars |  | 2,000 bbls/day |  | $85.55–$ 100.00
2014 |  | Swaps |  | 9,169 bbls/day |  | $94.40
2015 |  | Swaps |  | 6,000 bbls/day |  | $89.48
NGLs (C3-Propane) |  |  |  |  |  |
2014 |  | Swaps |  | 12,000 bbls/day |  | $ 1.02/gallon
NGLs (NC4-Normal butane) |  |  |  |  |  |
2014 |  | Swaps |  | 4,000 bbls/day |  | $ 1.34/gallon
NGLs (C5-Natural Gasoline) |  |  |  |  |  |
2014 |  | Swaps |  | 1,000 bbls/day |  | $ 2.11/gallon

Interest Rates

At March 31, 2014, we had approximately $3.2 billion of debt outstanding. Of this amount, $2.7 billion bears interest at fixed rates averaging 5.8%. Bank debt totaling $594.0 million bears interest at floating rates, which averaged 1.9% at March 31, 2014. The 30-day LIBOR rate on March 31, 2014 was approximately 0.2%. A 1% increase in short-term interest rates on the floating-rate debt outstanding on March 31, 2014 would cost us approximately $5.9 million in additional annual interest expense.

Off-Balance Sheet Arrangements

We do not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance our liquidity or capital resource position, or for any other purpose. However, as is customary in the oil and gas industry, we have various contractual work commitments some of which are desc ribed above under cash contractual obligations.

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Inflation and Changes in Prices

Our revenues, the value of our assets and our ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by changes in natural gas, NGLs and oil prices and the costs to produce our reserves. Natural gas, NGLs and oil prices are subject to significant fluctuations that are beyond our ability to control or predict. Although certain of our costs and expenses are affected by g eneral inflation, inflation does not normally have a significant effect on our business. We expect costs for the remainder of 2014 to continue to be a function of supply and demand.

IT EM 3. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Market Risk

We are exposed to market risks related to the volatility of natural gas, NGLs and oil prices. We employ various strategies, including the use of commodity derivative instruments, to manage the risks related to these price fluctuations. These derivatives instruments apply to a varying portion of our production and provid e only partial price protection. These arrangements limit the benefit to us of increases in prices but offer protection in the event of price declines. Further, if our counterparties defaulted, this protection might be limited as we might not receive the benefits of the derivatives. Realized prices are primarily driven by worldwide prices for oil and spot market prices for North American natural gas production. Natural gas and oil prices have been volatile and unpredictable for many years. Natural gas prices affect us more than oil prices because approximately 69% of our December 31, 2013 proved reserves are natural gas. We are also exposed to market risks related to changes in interest rates. These risks did not change materially from December 31, 2013 to March 31, 2014.

Commodity Price Risk

We use commodity-based derivative contracts to manage exposures to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. We do not utilize complex derivatives such as swaptions, knockouts or extendable swaps. At times, 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. At March 31, 2014, our derivatives program includes swaps and collars. These contracts expire monthly through December 2016. The fair value of these contracts, represented by the estimated amount that would be realized upon immediate liquidation as of March 31, 2014, approximated a net unrealized pretax loss of $53.4 million. At March 31, 2014, the following commodity derivative contracts were outstanding:

Period |  | Contract Type |  | Volume Hedged |  | Weighted Average Hedge Price |  | Fair Market Value
|  |  |  |  |  |  |  | (in thousands)
Natural Gas |  |  |  |  |  |  |  |
2014 |  | Collars |  | 447,500 Mmbtu/day |  | $ 3.84–$ 4.48 |  | $ (22,369)
2015 |  | Collars |  | 145,000 Mmbtu/day |  | $ 4.07–$ 4.56 |  | $ 2,959
2014 |  | Swaps |  | 240,145 Mmbtu/day |  | $ 4.18 |  | $ (18,737)
2015 |  | Swaps |  | 234,966 Mmbtu/day |  | $ 4.19 |  | $ (1,249)
2016 |  | Swaps |  | 60,000 Mmbtu/day |  | $ 4.18 |  | $ 613
Crude Oil |  |  |  |  |  |  |  |
2014 |  | Collars |  | 2,000 bbls/day |  | $ 85.55–$ 100.00 |  | $ (972)
2014 |  | Swaps |  | 9,169 bbls/day |  | $ 94.40 |  | $ (7,976)
2015 |  | Swaps |  | 6,000 bbls/day |  | $ 89.48 |  | $ (871)
NGLs (C3-Propane) |  |  |  |  |  |  |  |
2014 |  | Swaps |  | 12,000 bbls/day |  | $ 1.02/gallon |  | $ (7,816)
NGLs (NC4-Normal butane) |  |  |  |  |  |  |  |
2014 |  | Swaps |  | 4,000 bbls/day |  | $ 1.34/gallon |  | $ 3,159

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Period |  | Contract Type |  | Volume Hedged |  | Weighted Average Hedge Price |  | Fair Market Value
|  |  |  |  |  |  |  | (in thousands)
NGLs (C5-Natural Gasoline) |  |  |  |  |  |  |  |
2014 |  | Swaps |  | 1,000 bbls/day |  | $ 2.11/gallon |  | $ (101)

We expect our NGLs production to continue to increase. In our Marcellus Shale operations, propane is a large product component of our NGLs production and we believe NGL prices are somewhat seasonal. Therefore, the relationship of NGLs prices to NYMEX WTI (or West Texas Intermediate) will vary due to product components, seasonality and geographic supply and demand. We sell NGLs in several regional markets.

Currently, there is little demand, or facilities to supply the existing demand, for ethane in the Appalachian region. We have previously announced three ethane agreements wherein we have contracted to either sell or transport ethane from our Marcellus Shale area, two of which began operations in late 2013. The remaining facility is expected to begin operations in mid-2015. We cannot assure you that this last facility will become available. If we are not able to sell ethane, we may be required to curtail production or purchase natural gas to blend with our rich residue gas, which will adversely affect our revenues.

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 i n increased basis risk. In addition to the collars and swaps discussed above, we have entered into basis swap agreements. The price we receive for our gas production can be more or less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors; therefore, we have entered into basis swap agreements that effectively fix the basis adjustments. The fair value of the basis swaps was a loss of $3.6 million at March 31, 2014, the volumes are for 254,164 Mmbtu/day and they expire monthly through March 2015.

The following table shows the fair value of our collars, swaps and basis swaps and the hypothetical change in fair value that would result from a 10% and a 25% change in commodity prices at March 31, 2014. We remain at risk for possible changes in the market value of commodity derivative instruments; however, such risks should be mitigated by price changes in the underlying physical commodity (in thousands):

|  |  |  |  |  | Hypothetical Change in Fair Value |  |  | Hypothetical Change in Fair Value |
|  |  |  |  |  | Increase of |  |  | Decrease of |
|  |  | Fair Value |  |  | 10% |  |  | 25% |  |  | 10% |  |  | 25% |
Collars |  | $ | (20,381 | ) |  | $ | (61,374 | ) |  | $ | (168,347 | ) |  | $ | 53,858 | $ |  |  | 147,812 |
Swaps |  |  | (32,979 | ) |  |  | (137,656 | ) |  |  | (344,130 | ) |  |  | 139,462 |  |  |  | 349,499 |
Basis swaps |  |  | (3,639 | ) |  |  | 1,254 |  |  |  | 3,134 |  |  |  | (1,340 | ) |  |  | (3,254 | )

Our commodity-based contracts expose us to the credit risk of non-performance by the counterparty to the contracts. Our exposure is diversified among major investment grade financial institutions and we have master netting agreements with the majority of our c ounterparties that provide for offsetting payables against receivables from separate derivative contracts. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. At March 31, 2014, our derivative counterparties include fourteen financial institutions, of which all but two are secured lenders in our bank credit facility. Counterparty credit risk is considered when determining the fair value of our derivative contracts. While counterparties are major investment grade financial institutions, the fair value of our derivative contracts have been adjusted to account for the risk of non-performance by certain of our counterparties, which was immaterial.

Interest Rate Risk

We are exposed to interest rate risk on our bank debt. We attempt to balance variable rate debt, fixed rate debt and debt maturities to manage interest costs, interest rate volatility and financing risk. This is accomplished through a mix of fixed rate senior subordinated debt and variab le rate bank debt. At March 31, 2014, we had $3.2 billion of debt outstanding. Of this amount, $2.7 billion bears interest at fixed rates averaging 5.8%. Bank debt totaling $594.0 million bears interest at floating rates, which was 1.9% on March 31, 2014. On March 31, 2014, the 30-day LIBOR rate was approximately 0.2%. A 1% increase in short-term interest rates

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on the floating-rate debt outstanding on March 31, 2014, would cost us approximately $5.9 million in additional annual interest expense.

IT EM 4. | CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedure

As required by Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of March 31, 2014 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

There was no change in our system of internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended March 31, 2014 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II – OTHER INFORMATION

IT EM 1. | LEGAL PROCEEDINGS

See Note 15 to our unaudited consolidated financial statements entitled “Commitments and Contingencies” included in Part I Item 1 above for a summary of our legal proceedings, such information being incorporated herein by reference.

IT EM 1A. | RISK FACTORS

We are subject to various risks and uncertainties in the course of our business. In addition to the factors discussed elsewhere in this report, you should carefully consider the risks and uncertainties described under Item 1A. Risk Factors filed in our Annual Report on Form 10-K for the year ended December 31, 2013. There have been no material changes from the risk factors previously disclosed in that Form 10-K.

IT EM 6. | EXHIBITS

Exhibits included in this report are set forth in the Index to Exhibits which immediately precedes such exhibits, and are incorporated herein by reference.

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SIGNATURES

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

Date: April 28, 2014

RANGE RESOURCES CORPORATION
By: |  | /s/ ROGER S. MANNY
|  | Roger S. Manny
|  | Executive Vice President and Chief Financial Officer

Date: April 28, 2014

RANGE RESOURCES CORPORATION
By: |  | /s/ DORI A. GINN
|  | Dori A. Ginn
|  | Senior Vice President – Controller and Principal Accounting Officer

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Exhibit index

Exhibit Number |  |  | Exhibit Description
| 3.1 |  |  | Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on May 5, 2004, as amended by the Certificate of First Amendment to Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on July 28, 2005) and the Certificate of Second Amendment to Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on July 24, 2008)
| 3.2 |  |  | Amended and Restated By-laws of Range Resources Corporation (incorporated by reference to Exhibit 3.1 to our Form 8-K (File No. 001-12209) as filed with the SEC on May 20, 2010)
| 10.1* |  |  | Fourth Amendment to the Fourth Amended and Restated Credit Agreement as of April 3, 2014 among Range (as borrower) and JPMorgan Chase Bank, N.A. and the institutions named (therein) as lenders, JPMorgan as Administrative Agent
| 31.1* |  |  | Certification by the President and Chief Executive Officer of Range Resources Corporation Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
| 31.2* |  |  | Certification by the Chief Financial Officer of Range Resources Corporation Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
| 32.1** |  |  | Certification by the President and Chief Executive Officer of Range Resources Corporation Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
| 32.2** |  |  | Certification by the Chief Financial Officer of Range Resources Corporation Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
| 101. INS* |  |  | XBRL Instance Document
| 101. SCH* |  |  | XBRL Taxonomy Extension Schema
| 101. CAL* |  |  | XBRL Taxonomy Extension Calculation Linkbase Document
| 101. DEF* |  |  | XBRL Taxonomy Extension Definition Linkbase Document
| 101. LAB* |  |  | XBRL Taxonomy Extension Label Linkbase Document
| 101. PRE* |  |  | XBRL Taxonomy Extension Presentation Linkbase Document

* | filed herewith

** | furnished herewith

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