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 September 30, 2013
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).
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
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
163,421,596 Common Shares were outstanding on October 27, 2013.
Quarter Ended September 30, 2013
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
PART I – FINANCIAL INFORMATION
Page
ITEM 1.
Financial Statements:
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
26
ITEM 3.
Quantitative and Qualitative Disclosures about Market Risk
41
ITEM 4.
Controls and Procedures
43
PART II – OTHER INFORMATION
Legal Proceedings
44
ITEM 1A.
Risk Factors
ITEM 6.
Exhibits
45
SIGNATURES
46
2
ITEM 1. Financial Statements
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
September 30, 2013
December 31, 2012
(Unaudited)
Assets
Current assets:
Cash and cash equivalents
$
255
252
Accounts receivable, less allowance for doubtful accounts of $2,496 and $2,374
151,407
167,495
Unrealized derivatives
55,993
137,552
Deferred tax asset
2,179
—
Inventory and other
12,898
22,315
Total current assets
222,732
327,614
18,074
15,715
Equity method investments
127,236
132,449
Natural gas and oil properties, successful efforts method
8,667,682
8,111,775
Accumulated depletion and depreciation
(2,160,378
)
(2,015,591
6,507,304
6,096,184
Transportation and field assets
117,566
117,717
Accumulated depreciation and amortization
(82,652
(76,150
34,914
41,567
Other assets
120,370
115,206
Total assets
7,030,630
6,728,735
Liabilities
Current liabilities:
Accounts payable
251,635
234,651
Asset retirement obligations
2,366
2,470
Accrued liabilities
159,697
139,379
Deferred tax liability
37,924
Accrued interest
31,914
36,248
7,971
4,471
Total current liabilities
453,583
455,143
Bank debt
427,000
739,000
Subordinated notes
2,640,170
2,139,185
759,556
698,302
103
3,463
Deferred compensation liability
207,404
187,604
Asset retirement obligations and other liabilities
151,813
148,646
Total liabilities
4,639,629
4,371,343
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, 163,418,445 issued at September 30, 2013 and 162,641,896 issued at December 31, 2012
1,634
1,626
Common stock held in treasury, 101,301 shares at September 30, 2013 and 127,798 shares at December 31, 2012
(3,751
(4,760
Additional paid-in capital
1,944,437
1,915,627
Retained earnings
428,948
360,990
Accumulated other comprehensive income
19,733
83,909
Total stockholders’ equity
2,391,001
2,357,392
Total liabilities and stockholders’ equity
See accompanying notes.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited, in thousands, except per share data)
Three Months Ended
September 30,
Nine Months
Ended September 30,
2013
2012
Revenues and other income:
Natural gas, NGLs and oil sales
431,214
337,040
1,267,131
953,006
Derivative fair value (loss) income
(40,355
(40,728
(2,470
47,008
Gain (loss) on the sale of assets
6,008
949
89,129
(12,704
Brokered natural gas, marketing and other
45,171
2,519
80,843
12,356
Total revenues and other income
442,038
299,780
1,434,633
999,666
Costs and expenses:
Direct operating
30,907
29,628
93,731
85,691
Transportation, gathering and compression
60,958
51,600
189,422
137,164
Production and ad valorem taxes
11,454
8,819
33,950
57,239
Brokered natural gas and marketing
51,117
4,887
90,094
15,440
Exploration
20,496
14,752
50,344
51,785
Abandonment and impairment of unproved properties
11,692
40,118
46,066
104,048
General and administrative
44,919
44,497
230,964
127,231
Deferred compensation plan
(2,225
20,052
33,257
21,555
Interest expense
44,321
43,997
131,602
124,090
Loss on early extinguishment of debt
12,280
Depletion, depreciation and amortization
130,343
123,059
365,439
332,012
Impairment of proved properties and other assets
7,012
1,281
7,753
Total costs and expenses
410,994
382,690
1,284,902
1,057,536
Income (loss) from operations before income taxes
31,044
(82,910
149,731
(57,870
Income tax expense (benefit)
Current
Deferred
11,866
(29,074
62,180
(17,910
Net income (loss)
19,178
(53,836
87,551
(39,960
Net income (loss) per common share:
Basic
0.12
(0.34
0.54
(0.25
Diluted
0.53
Dividends paid per common share
0.04
Weighted average common shares outstanding:
160,500
159,563
160,398
159,297
161,374
161,321
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Unaudited, in thousands)
Nine Months Ended
Other comprehensive income:
Realized loss (gain) on hedge derivative contract settlements reclassified into natural gas, NGLs and oil sales from other comprehensive income, net of taxes (1)
(37,495
(14,840
(120,871
De-designated hedges reclassified into natural gas, NGLs and oil sales, net of taxes (2)
(16,717
(42,758
De-designated hedges reclassified to derivative fair value income, net of taxes (3)
(438
(2,376
Change in unrealized deferred hedging (losses) gains, net of taxes (4)
(52,246
(4,203
31,541
Total comprehensive income (loss)
2,023
(143,577
23,374
(129,290
(1) Amounts are net of income tax expense of $23,972 for the three months ended September 30, 2012 and $9,488 and $76,806 for the nine months ended September 30, 2013 and 2012.
(2) Amounts are net of income tax expense of $10,688 for the three months ended September 30, 2013 and $27,337 for the nine months ended September 30, 2013.
(3) Amounts relate to transactions not probable of occurring and are presented net of income tax expense of $279 for the three months ended September 30, 2013 and $1,518 for the nine months ended September 30, 2013.
(4) Amounts are net of income tax expense of $33,403 for the three months ended September 30, 2012 and income tax benefit of $21,780 for the nine months ended September 30, 2012. Amounts are net of income tax expense of $2,687 for the nine months ended September 30, 2013.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Operating activities:
Adjustments to reconcile net income (loss) to net cash provided from operating activities:
(Gain) loss from equity method investments, net of distributions
(1,174
2,252
Deferred income tax expense (benefit)
Depletion, depreciation and amortization and impairment
373,192
333,293
Exploration dry hole costs
3,904
832
Mark-to-market on natural gas, NGLs and oil derivatives not designated as hedges
(28,350
(30,076
Unrealized derivative loss
2,485
5,061
Allowance for bad debt
250
Amortization of deferred financing costs, loss on extinguishment of debt and other
19,735
5,970
Deferred and stock-based compensation
74,187
58,573
(Gain) loss on the sale of assets
(89,129
12,704
Changes in working capital:
Accounts receivable
(6,506
(9,479
3,259
(5,394
(29,234
11,074
Accrued liabilities and other
(15,550
30,135
Net cash provided from operating activities
502,866
461,123
Investing activities:
Additions to natural gas and oil properties
(907,813
(1,151,167
Additions to field service assets
(4,326
(3,056
Acreage purchases
(70,187
(175,041
3,799
Proceeds from disposal of assets
311,748
32,082
Purchases of marketable securities held by the deferred compensation plan
(23,729
(33,997
Proceeds from the sales of marketable securities held by the deferred compensation plan
19,375
21,485
Net cash used in investing activities
(671,133
(1,309,694
Financing activities:
Borrowing on credit facilities
1,310,000
1,139,000
Repayment on credit facilities
(1,622,000
(865,000
Issuance of subordinated notes
750,000
600,000
Repayment of subordinated notes
(259,063
Dividends paid
(19,593
(19,475
Debt issuance costs
(12,448
(12,606
Issuance of common stock
343
2,073
Change in cash overdrafts
4,704
(15,750
Proceeds from the sales of common stock held by the deferred compensation plan
16,327
20,388
Net cash provided from financing activities
168,270
848,630
Increase in cash and cash equivalents
59
Cash and cash equivalents at beginning of period
92
Cash and cash equivalents at end of period
151
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 through 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 2012 Annual Report on Form 10-K filed on February 27, 2013. The results of operations for the third quarter and the nine months ended September 30, 2013 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. These reclassifications include gas purchases and other marketing costs which were previously reported in other income and are currently reported as a separate operating expense. These reclassifications have no impact on previously reported net income.
Impact Fee
In first quarter 2012, the Pennsylvania legislature passed an “impact fee” on unconventional natural gas and oil production. The impact fee is a per well annual fee imposed for a period of fifteen years on all unconventional wells drilled in Pennsylvania. The fee is based on the average annual price of natural gas and the Consumer Price Index. The annual fee per well declines each year over the fifteen-year time period as long as the well is producing. In first nine months 2012, we recorded a retroactive impact fee of $24.7 million for wells drilled during 2011 and prior. This expense is reflected in our statements of operations as production and ad valorem taxes.
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 will be recognized in earnings in derivative fair value income (loss) immediately each quarter as derivative contracts are settled and marked to market. For third quarter 2013, unrealized gains of $3.1 million and for the nine months ended September 30, 2013, unrealized gains of $25.5 million were included in our statements of operations in derivative fair value income (loss) that, prior to March 1, 2013, would have been deferred in accumulated other comprehensive income (“AOCI”) if we had continued using hedge accounting. Refer to Note 11 for additional information.
(3) NEW ACCOUNTING STANDARDS
Recently Adopted
In December 2011, the Financial Accounting Standards Board (the “FASB”) issued ASU No. 2011-11, “Disclosures about Offsetting Assets and Liabilities,” requiring additional disclosures about offsetting and related arrangements. ASU 2011-11 is effective retrospectively for annual reporting periods beginning on or after January 1, 2013. Also, in January 2013, the FASB issued ASU No. 2013-01, “Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities.” ASU 2013-01 revised and clarified the disclosures required by ASU No. 2011-11. We adopted these new requirements in first quarter 2013 and they did not have a material effect on our consolidated financial statements.
In February 2013, the FASB issued ASU No. 2013-02, “Comprehensive Income (Topic 220): Reporting of Amounts Reclassified out of Accumulated Other Comprehensive Income.” ASU 2013-02 requires information to be disclosed about the amounts reclassified out of AOCI by component. We adopted this new requirement in first quarter 2013 and it did not have a material effect on our consolidated financial statements.
(4) DISPOSITIONS
2013 Dispositions
In September 2013, we sold our equity method investment in a drilling company for proceeds of $7.0 million and recognized a gain of $4.4 million. In addition, in the third quarter 2013 we sold unproved leases in West Texas for proceeds of $2.6 million where we recognized a gain of $1.7 million and sold surface acreage in North Texas for proceeds of $5.3 million with a loss of $253,000 recognized.
In December 2012, we announced our plan to offer for sale certain of our Delaware and Permian Basin properties in southeast New Mexico and West Texas. On February 26, 2013, we announced we signed a definitive agreement to sell these assets for a price of $275.0 million, subject to normal post-closing adjustments. The agreement had an effective date of January 1, 2013 and consequently, operating net revenues after January 1, 2013 were a downward adjustment to the sales price. We closed this disposition on April 1 and we recognized a gain of approximately $83.5 million in second quarter 2013 related to this sale, before selling expenses of $4.2 million. Also in second quarter 2013, we received $14.2 million of proceeds from the sale of miscellaneous oil and gas properties in Pennsylvania and West Texas and we recognized a gain of $4.0 million on these transactions. In the first nine months 2013, we also received $10.0 million of proceeds from the sale of miscellaneous oil and gas property in Pennsylvania, with no gain or loss recognized.
2012 Dispositions
In September 2012, we sold unproved properties in three counties in Pennsylvania for proceeds of $13.9 million resulting in a pre-tax gain of $746,000. As part of this agreement, we retained an overriding royalty of 1% to 5% on a large portion of the leases.
In June 2012, we sold a suspended well in the Marcellus Shale for proceeds of $2.5 million resulting in a pre-tax loss of $2.5 million. In March 2012, we sold seventy-five percent of a prospect in East Texas which included unproved properties and a suspended exploratory well to a third party for $8.6 million resulting in a pre-tax loss of $10.9 million. As part of this agreement, we retained a carried interest on the first well drilled and an overriding royalty of 2.5% to 5.0% in the prospect.
(5) INCOME TAXES
Income tax expense (benefit) from operations was as follows (in thousands):
Three Months Ended September 30,
Nine Months Ended September 30,
Effective tax rate
38.2
%
35.1
41.5
30.9
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 third quarter and the nine months ended September 30, 2013 and 2012, 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 securities (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):
Net income (loss), as reported
Participating basic earnings (a)
(341
(119
(1,479
(348
Basic net income (loss) attributed to common shareholders
18,837
(53,955
86,072
(40,308
Reallocation of participating earnings (a)
1
Diluted net income (loss) attributed to common shareholders
18,838
86,078
(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):
Denominator:
Weighted average common shares outstanding – basic
Effect of dilutive securities:
Director and employee stock options and SARs
874
923
Weighted average common shares outstanding – diluted
Weighted average common shares – basic for the three months ended September 30, 2013 excludes 2.9 million shares and the three months ended September 30, 2012 excludes 3.0 million shares of restricted stock held in our deferred compensation plans (although all awards are issued and outstanding upon grant). Weighted average common shares – basic for the nine months ended September 30, 2013 excludes 2.8 million shares of restricted stock compared to 2.9 million in the same period of 2012. Stock appreciation rights (“SARs”) of 796 for the three months ended September 30, 2013 and 181,000 for the nine months ended September 30, 2013 were outstanding but not included in the computations of diluted income from operations per share because the grant prices of the SARs were greater than the average market price of the common shares. Due to our loss from continuing operations for the three months and the nine months ended September 30, 2012, we excluded all outstanding SARs and restricted stock from the computation of diluted net income (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 determined 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 nine months ended September 30, 2013 and the year ended December 31, 2012 (in thousands except for number of projects):
Balance at beginning of period
57,360
93,388
Additions to capitalized exploratory well costs pending the determination of proved reserves
61,751
153,250
Reclassifications to wells, facilities and equipment based on determination of proved reserves
(80,358
(184,298
Capitalized exploratory well costs charged to expense
(3,950
Divested wells
(4,980
Balance at end of period
34,803
Less exploratory well costs that have been capitalized for a period of one year or less
(21,923
(45,965
Capitalized exploratory well costs that have been capitalized for a period greater than one year
12,880
11,395
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year
As of September 30, 2013, $12.9 million of capitalized exploratory well costs have been capitalized for more than one year which relates to two wells waiting on pipelines and two wells currently in the completion stage. One of the wells is not operated by us and all of the wells are in Pennsylvania. In 2012, we sold a seventy-five percent interest in an East Texas exploratory well. Refer to Note 4 for additional information.
The following table provides an aging of capitalized exploratory well costs that have been suspended for more than one year as of September 30, 2013 (in thousands):
Total
2011
2010
2009
2008
Capitalized exploratory well costs that have been capitalized for more than one year
208
6,904
1,289
72
2,884
1,523
10
(8) INDEBTEDNESS
We had the following debt outstanding as of the dates shown below (in thousands) (bank debt interest rate at September 30, 2013 is shown parenthetically; no interest was capitalized during the three months or the nine months ended September 30, 2013 or 2012):
Bank debt (1.9%)
Senior subordinated notes:
7.25% senior subordinated notes due 2018
250,000
8.00% senior subordinated notes due 2019, net of $9,830 and $10,815 discount, respectively
290,170
289,185
6.75% senior subordinated notes due 2020
500,000
5.75% senior subordinated notes due 2021
5.00% senior subordinated notes due 2022
5.00% senior subordinated notes due 2023
Total debt
3,067,170
2,878,185
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 September 30, 2013, 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 October 18, 2013, 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 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 payment of a mutually acceptable commitment fee to those banks. As of September 30, 2013, the outstanding balance under our bank credit facility was $427.0 million. Additionally, we had $84.9 million of undrawn letters of credit leaving $1.2 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 1.9% for the three months ended September 30, 2013 compared to 2.1% for the three months ended September 30, 2012. The weighted average interest rate was 2.0% for the nine months ended September 30, 2013 compared to 2.2% for the nine months ended September 30, 2012. A commitment fee is paid on the undrawn balance based on an annual rate of 0.35% to 0.50%. At September 30, 2013, the commitment fee was 0.375% and the interest rate margin was 1.5% on our LIBOR loans and 0.5% on our base rate loans.
Senior Subordinated Notes
In March 2013, we issued $750.0 million aggregate principal amount of 5.00% senior subordinated notes due 2023 (the “Outstanding Notes”) at par for net proceeds of $738.8 million after underwriting commissions of $11.2 million. The offering of the Outstanding Notes were only offered to qualified institutional buyers and to Non-U.S. persons outside the United States in compliance with Rule 144A and Regulation S under the Securities Act of 1933, as amended (the “Securities Act”). On June 19, 2013, substantially all of the Outstanding Notes were exchanged for an equal principal amount of registered 5.00% senior subordinated notes due 2023 pursuant to an effective registration statement on Form S-4 filed on April 26, 2013 under the Securities Act (the “Exchange Notes”). The Exchange Notes are identical to the Outstanding Notes except that the Exchange Notes are registered under the Securities Act and do not have restrictions on transfer, registration rights or provisions for additional interest. As used in this Form 10-Q, the term “5.00% Notes due 2023” refer to both the Outstanding Notes and the Exchange Notes. Interest on the 5.00% Notes due 2023 is payable semi-annually in March and September and is guaranteed by all of our subsidiary guarantors. We may redeem the 5.00% Notes due 2023, in whole or in part, at any time on or after March 15, 2018, at a redemption price of 102.5% of the principal amount as of March 15, 2018, declining to 100% on March 15, 2021 and thereafter. Before March 15, 2016, we may redeem up to 35% of the original aggregate principal amount of the 5.00% Notes due 2023 at a redemption price equal to 105% of the principal amount thereof, plus accrued and unpaid
11
interest, if any, with the proceeds of certain equity offerings, provided that 65% of the aggregate principal amount of 5.00% Notes due 2023 remains outstanding immediately after the occurrence of such redemption and also provided such redemption shall occur within 60 days of the date of the closing of the equity offering. On closing of the 5.00% Notes due 2023, we used the proceeds to pay down our outstanding bank credit facility balance. We did not receive any proceeds from the issuance of the Exchange 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.
Early Extinguishment of Debt
On April 2, 2013, we announced a call for the redemption of $250.0 million of our outstanding 7.25% senior subordinated notes due 2018 at 103.625% of par which were redeemed on May 2, 2013. In second quarter 2013, we recognized a $12.3 million loss on extinguishment of debt, including transaction call premium costs as well as expensing of the remaining deferred financing costs on the repurchased debt.
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 September 30, 2013.
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 September 30, 2013, 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 costs for the nine months ended September 30, 2013 is as follows (in thousands):
Ended September 30, 2013
Beginning of period
146,478
Liabilities incurred
5,267
Liabilities settled
(398
Disposition of wells
(3,104
Accretion expense
8,011
Change in estimate
(6,231
End of period
150,023
Less current portion
(2,366
Long-term asset retirement obligations
147,657
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 2012:
Nine Months Ended September 30, 2013
Year Ended December 31, 2012
Beginning balance
162,514,098
161,131,547
Stock options/SARs exercised
257,103
926,425
Restricted stock granted
401,122
354,674
Restricted stock units vested
118,324
57,824
Treasury shares issued
26,497
43,628
Ending balance
163,317,144
(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. In 2011, we sold NGLs derivative swap contracts (“sold swaps”) for the natural gasoline (or C5) component of natural gas liquids and in 2012, we entered into purchased derivative swaps (“re-purchased swaps”) for C5 volumes. These re-purchased swaps were, in some cases, with the same counterparties as our sold swaps. We entered into these re-purchased swaps to lock in certain natural gasoline derivative gains. In second quarter 2012, we entered into NGLs derivative swap contracts for the propane (or C3) component of NGLs and in third quarter 2013, we also entered into NGLs derivative swap contracts for the normal butane (or C4) component of NGLs. The fair value of our
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derivative contracts, represented by the estimated amount that would be realized 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 gain of $66.0 million at September 30, 2013. These contracts expire monthly through December 2015.
The following table sets forth our derivative volumes by year as of September 30, 2013:
Period
Contract Type
Volume Hedged
Weighted Average Hedge Price
Natural Gas
Collars
280,000 Mmbtu/day
$ 4.59–$ 5.05
2014
447,500 Mmbtu/day
$ 3.84–$ 4.48
2015
145,000 Mmbtu/day
$ 4.07–$ 4.56
Swaps
293,370 Mmbtu/day
$ 3.82
30,000 Mmbtu/day
$ 4.17
7,500 Mmbtu/day
$ 4.16
Crude Oil
3,000 bbls/day
$ 90.60–$ 100.00
2,000 bbls/day
$ 85.55–$ 100.00
6,825 bbls/day
$ 96.79
7,000 bbls/day
$ 94.14
2,000 bbls day
$ 90.20
NGLs (Natural Gasoline)
Sold Swaps
8,000 bbls/day
$89.64
Re-purchased Swaps
1,500 bbls/day
$76.30
NGLs (Propane)
11,000 bbls/day
$37.87
$40.38
NGLs (Normal butane)
$55.44
$54.60
Every derivative instrument is required to be recorded on the balance sheet as either an asset or a liability measured at its fair value. Fair value is determined based on the difference between the fixed contract price and the underlying market price at the determination date. Through February 28, 2013, changes in the fair value of our derivatives that qualified for hedge accounting were recorded as a component of 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 September 30, 2013, an unrealized pre-tax derivative gain of $32.3 million ($19.7 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.
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For those derivative instruments that qualified or were designated for hedge accounting, settled transaction gains and losses are determined monthly, and are included as increases or decreases to natural gas, NGLs and oil sales in the period the hedged production is sold. Through February 28, 2013, we had elected to designate our commodity derivative instruments that qualified for hedge accounting as cash flow hedges. Natural gas, NGLs and oil sales include $27.4 million of gains in third quarter 2013 compared to gains of $61.5 million in the same period of 2012 related to settled hedging transactions. Natural gas, NGLs and oil sales include $94.4 million of gains in the first nine months 2013 compared to gains of $197.7 million in the same period of 2012. 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) income for the three months ended September 30, 2013 includes ineffective losses (unrealized and realized) of $39,000 compared to a loss of $3.7 million in the three months ended September 30, 2012. Derivative fair value (loss) income for the nine months ended September 30, 2013 includes ineffective losses (unrealized and realized) of $2.9 million compared to a loss of $1.6 million in the same period of 2012. During the nine months ended September 30, 2013, we recognized a pre-tax gain of $3.9 million in derivative fair value (loss) income 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 transactions occur. As of September 30, 2013, we expect to reclassify into earnings $22.1 million of unrealized net gains in the remaining months of 2013 and $10.2 million of unrealized net gains in 2014 from AOCI.
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 significant 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.
Derivative Fair Value (Loss) Income
The following table presents information about the components of derivative fair value (loss) income for the three months and the nine months ended September 30, 2013 and 2012 (in thousands):
Change in fair value of derivatives that did not qualify or were not designated for hedge accounting (a)
(34,219
(53,646
28,350
30,075
Realized gain (loss) on settlement–natural gas (a) (b)
5,815
(17,913
Realized (loss) gain on settlement–oil (a) (b)
(8,005
1,955
(8,218
(1,899
Realized (loss) gain on settlement–NGLs (a) (b)
(3,907
14,682
(1,759
20,442
Hedge ineffectiveness
–realized
(854
988
(445
3,451
–unrealized
815
(4,707
(2,485
(5,061
(a) Derivatives that did not qualify or were not designated for hedge accounting. Change in fair value of derivatives line also includes gains of $3.1 million in third quarter 2013 and gains of $25.5 million in the first nine months 2013 related to discontinuance of hedge accounting.
(b) These amounts represent the realized gains and losses on settled derivatives that did not qualify or were not designated for hedge accounting, which before settlement are included in the category in this same table referred to as change in fair value of derivatives that did not qualify or were not designated for hedge accounting.
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Derivative Assets and Liabilities
The combined fair value of derivatives included in the accompanying consolidated balance sheets as of September 30, 2013 and December 31, 2012 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 arrangements with our derivative counterparties (in thousands):
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
10,965
(2,046
8,919
–collars
71,699
(1,720
69,979
Crude oil
2,962
(7,766
(4,804
137
(1,803
(1,666
NGLs
–C5 swaps
3,374
(1,461
1,913
–C3 swaps
(552
(545
–C4 swaps
406
(135
271
89,550
(15,483
74,067
Gross Amounts of Recognized (Liabilities)
Net Amounts of (Liabilities) Presented in the Balance Sheet
Derivative (liabilities):
(1,219
2,046
827
1,720
7,766
1,803
(9
1,461
1,452
(10,469
552
(9,917
(571
135
(436
(23,557
15,483
(8,074
10,746
(3,242
7,504
128,410
(6,155
122,255
–basis swaps
993
9,650
2,222
13,055
(2,412
10,643
165,076
(11,809
153,267
16
(221
(3,463
(9,618
9,618
(137
2,412
2,275
(6,746
(19,743
11,809
(7,934
The table below provides data about the fair value of our derivative contracts. Derivative assets and liabilities shown below are presented as gross assets and liabilities, without regard to master netting arrangements, which are considered in the presentation of derivative assets and liabilities in the accompanying consolidated balance sheets (in thousands):
(Liabilities)
Carrying Value
Net Carrying Value
Derivatives that qualified for cash flow hedge accounting (before discontinuance of hedge accounting):
Swaps (a)
7,091
(3,960
3,131
22,236
18,994
Collars (a)
38,685
(10,356
28,329
129,878
(9,721
120,157
45,776
(14,316
31,460
152,114
(12,963
139,151
Derivatives that did not qualify or were not designated for hedge accounting:
Sold swaps (a)
16,159
(23,072
(6,913
7,316
(8,904
(1,588
Re-purchased swaps (a)
1,462
5,920
42,943
(2,959
39,984
857
Basis swaps (a)
60,564
(26,031
34,533
15,086
6,182
(a) Included in unrealized derivatives in the accompanying consolidated balance sheets. See additional discussion above regarding the discontinuance of hedge accounting.
The effects of our cash flow hedges (or those derivatives that previously qualified for hedge accounting) on accumulated other comprehensive income in the accompanying consolidated balance sheets is summarized below (in thousands):
Change in Hedge Derivative Fair Value
Realized Gain (Loss) Reclassified from OCI into Revenue (a)
(33,311
2,765
18,204
125
22,525
14,687
69,851
Put options
(994
(682
(1,908
(998
(51,344
25,357
43,945
(7,015
32,704
83,630
128,823
Income taxes
33,403
(10,967
(23,972
2,687
(21,780
(38,343
(76,805
17,155
37,495
59,974
120,871
(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.
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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):
Gain (Loss) Recognized in Income (Non-hedge Derivatives)
Gain (Loss) Recognized in Income (Ineffective Portion)
Derivative Fair Value Income (Loss)
(48,277
(45,998
(39
(1,556
(48,316
(47,554
Re-purchased swaps
1,595
12,822
6,366
(1,714
(2,163
(3,877
Call options
(2,119
(40,316
(37,009
(3,719
(26,350
30,330
(2,034
(890
(28,384
29,440
1,117
4,078
25,783
3,381
(896
(720
24,887
2,661
10,829
Basis swaps
(90
460
48,618
(2,930
(1,610
(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 involving 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 value hierarchy.
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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 September 30, 2013 using:
Quoted Prices in Active Markets for Identical Assets
(Level 1)
Significant
Other
Observable Inputs
(Level 2)
Unobservable
Inputs
(Level 3)
Total Carrying
Value as of
Trading securities held in the deferred compensation plans
65,663
Derivatives
(2,320
68,313
Fair Value Measurements at December 31, 2012 using:
December 31,
57,776
23,326
121,014
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.
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, dividends, and mark-to-market gains or losses are included in deferred compensation plan expense in the accompanying statement of operations. For third quarter 2013, interest and dividends were $111,000 and the mark-to-market adjustment was a gain of $3.2 million compared to interest and dividends of $122,000 and mark-to-market gain of $3.8 million in the same period of the prior year. For nine months ended September 30, 2013, interest and dividends were $779,000 and the mark-to-market adjustment was a gain of $3.8 million compared to interest and dividends of $279,000 and a mark-to-market gain of $5.7 million in the same period of the prior year.
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Fair Values—Non-recurring
We review our long-lived assets to be held and used for impairment including proved natural gas and oil properties, whenever events or circumstances indicate the carrying value of those assets may not be recoverable. In third quarter 2013, we recognized an impairment expense of $7.0 million on certain of our oil and gas properties in South Texas due to reduction in reserves due to a failed well recompletion. Their fair value was measured using an income approach based upon internal estimates of future production levels, drilling and operating costs as well as discount rates, which are Level 3 inputs. In second quarter 2013, we evaluated certain surface property we own which included consideration of the potential sale of the assets and recognized an impairment charge of $741,000. The following table presents the fair value of these assets at September 30, 2013 measured at fair value on a non-recurring basis (in thousands):
Fair Value
Impairment
Natural gas and oil properties
500
Surface property
6,269
741
Fair Values—Reported
The following table presents the carrying amounts and the fair values of our financial instruments as of September 30, 2013 and December 31, 2012 (in thousands):
Fair
Value
Assets:
Commodity swaps and collars
Marketable securities(a)
Liabilities:
Bank credit facility(b)
(427,000
(739,000
Deferred compensation plan(c)
(207,404
(204,404
(187,604
7.25% senior subordinated notes due 2018(b)
(250,000
(262,500
8.00% senior subordinated notes due 2019(b)
(290,170
(322,125
(289,185
(332,250
6.75% senior subordinated notes due 2020(b)
(500,000
(538,750
(542,500
5.75% senior subordinated notes due 2021(b)
(525,000
(535,000
5.00% senior subordinated notes due 2022(b)
(600,000
(580,500
(627,000
5.00% senior subordinated notes due 2023(b)
(750,000
(720,000
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 incurrence of and expected future insignificance of bad debt expense. Non-financial liabilities initially measured at fair value include asset retirement obligations. Refer to Note 9 for additional information.
Concentrations of Credit Risk
As of September 30, 2013, 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
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of loss. Our allowance for uncollectible receivables was $2.5 million at September 30, 2013 and $2.4 million at December 31, 2012. As of September 30, 2013, 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 September 30, 2013, our derivative counterparties include fifteen financial institutions, of which all but two are secured lenders in our bank credit facility. At September 30, 2013, our net derivative assets include a net payable to the two counterparties not included in our bank credit facility of $53,000. For those counterparties that are not secured lenders in our bank credit facility or for which we do not have master netting arrangements, net derivative asset values are determined, in part, by reviewing credit default swap spreads for such counterparties. Net derivative liabilities are determined, in part, by using our market-based credit spread. None of our derivative contracts have margin requirements or collateral provisions that would require funding prior to the scheduled cash settlement date. We have also entered into the International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with our counterparties. The terms of the ISDA Agreements provide us and our counterparties with rights of set off upon the occurrence of defined acts of default by either us or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. We continue to monitor developments surrounding the derivative regulations adopted under the Dodd-Frank Wall Street Reform and Consumer Protection Act. We do not anticipate any significant changes to our hedging program as a result of this law.
(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. Beginning 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 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.
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 recognized 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, restricted stock units 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 stock price and not directly related to the functional expenses and therefore, is not allocated to the functional categories.
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The following table details the allocation of stock-based compensation that is allocated to functional expense categories (in thousands):
Operating expense
699
598
2,056
1,647
Brokered natural gas and marketing expense
531
452
1,310
1,313
Exploration expense
983
1,126
3,013
3,048
General and administrative expense
11,031
10,057
34,600
30,755
13,244
12,233
40,979
36,763
Stock and Option Plans
We have two active equity-based stock plans, the 2005 Plan and the Director 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 2.6 million grants outstanding at September 30, 2013, all are grants relating to SARs. Information with respect to SARs activity is summarized below:
Shares
Weighted Average Exercise Price
Outstanding at December 31, 2012
3,433,362
52.52
Granted
470,617
75.82
Exercised
(1,205,186
53.78
Expired/forfeited
(50,974
53.69
Outstanding at September 30, 2013
2,647,819
56.00
Stock Appreciation Right Awards
During first nine months 2013, we granted SARs to officers and non-officer employees. The weighted average grant date fair value per share of these SARs, based on our Black-Scholes-Merton assumptions, is shown below:
Weighted average exercise price per share
Expected annual dividends per share
0.21
Expected life in years
3.7
Expected volatility
35
Risk-free interest rate
0.6
Weighted average grant date fair value per share
20.20
Restricted Stock Awards
Equity Awards
In first nine months 2013, we granted 394,100 restricted stock Equity Awards to employees at an average grant price of $71.13 compared to 359,700 restricted stock Equity Awards granted to employees at an average grant price of $63.37 in the same period of 2012. These awards generally vest over a three-year period. We recorded compensation expense for these
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Equity Awards of $14.6 million in the first nine months 2013 compared to $8.2 million in the same period of 2012. Equity Awards are not issued to employees until they are vested. Employees do not have the option to receive cash.
Liability Awards
In first nine months 2013, we granted 406,300 shares of restricted stock Liability Awards as compensation to employees at an average price of $75.45 with vesting generally over a three-year period and 18,300 shares were granted to non-employee directors at an average price of $77.26 with immediate vesting. In the same period of 2012, we granted 365,000 shares of Liability Awards as compensation to employees at an average price of $63.88 with vesting generally over a three-year period and 14,700 shares were granted to non-employee directors at an average price of $64.35 with immediate vesting. We recorded compensation expense for Liability Awards of $16.0 million in first nine months 2013 compared to $15.2 million in the same period of 2012. 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 September 30, 2013 is summarized below:
Weighted Average Grant Date Fair Value
349,156
59.08
423,478
58.91
394,053
71.13
424,624
75.53
Vested
(235,580
62.30
(267,621
62.07
Forfeited
(45,589
65.32
(21,704
57.31
462,040
67.11
558,777
70.09
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 trust, 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 $2.2 million in third quarter 2013 compared to mark-to-market loss of $20.1 million in third quarter 2012. We recorded mark-to-market loss of $33.3 million in the nine months ended September 30, 2013 compared to $21.6 million in the same period of 2012. The Rabbi Trust held 2.9 million shares (2.3 million of vested shares) of Range stock at September 30, 2013 compared to 2.7 million shares (2.3 million of vested shares) at December 31, 2012.
23
(14) SUPPLEMENTAL CASH FLOW INFORMATION
(in thousands)
Net cash provided from operating activities included:
Income taxes (refunded) paid to taxing authorities
(237
436
Interest paid
129,043
99,828
Non-cash investing and financing activities included:
Asset retirement costs (removed) capitalized, net
(964
29,695
Increase in accrued capital expenditures
32,776
6,605
(15) COMMITMENTS AND CONTINGENCIES
Litigation
James A. Drummond and Chris Parrish v. Range Resources-Midcontinent, LLC et al.; pending in the District Court of Grady County, State of Oklahoma; Case No. CJ-2010-510
As we previously disclosed, the parties successfully mediated the case in May 2013 resulting in a settlement and we executed a Stipulation and Agreement of Settlement, with an effective date of May 31, 2013, providing for a cash payment to the class in the amount of $87.5 million in settlement of all claims made by the class for the period prior to May 31, 2013. Pursuant to the settlement agreement, on June 28, 2013, we paid $87.5 million into an escrow account. On September 9, 2013, the Court approved the settlement thereby finally concluding this matter.
We are the subject of, or party to, a number of other 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 with 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 nine months ended September 30, 2013, our transportation and gathering commitments increased by approximately $150.0 million over the next 10 years primarily due to increases in existing transportation and gathering contracts.
(16) Capitalized Costs and Accumulated Depreciation, Depletion and Amortization (a)
Natural gas and oil properties:
Properties subject to depletion
7,919,627
7,368,308
Unproved properties
748,055
743,467
Accumulated depreciation, depletion and amortization
Net capitalized costs
(a) Includes capitalized asset retirement costs and the associated accumulated amortization.
24
(17) Costs Incurred for Property Acquisition, Exploration and Development (a)
69,987
188,843
Development
727,386
1,049,129
Exploration:
Drilling
173,298
309,816
Expense
47,331
65,758
Stock-based compensation expense
4,049
Gas gathering facilities:
40,626
41,035
Subtotal
1,061,641
1,658,630
57,982
Total costs incurred
1,060,677
1,716,612
(a)Includes cost incurred whether capitalized or expensed.
25
ITEM 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 filed with our Annual Report on Form 10-K for the year ended December 31, 2012, as filed with the SEC on February 27, 2013.
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 properties as a whole rather than by discrete operating segments.
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 gas, NGLs and crude oil and on our ability to economically find, develop, acquire and produce natural gas, NGLs and crude oil reserves. We include condensate in our crude oil captions below. We use the successful efforts method of accounting for our natural gas, NGLs and oil activities. Our corporate headquarters is located at 100 Throckmorton Street, Fort Worth, Texas.
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 and the nine months ended September 30, 2013 and 2012:
Average NYMEX prices (a)
Natural gas (per mcf)
3.60
2.81
3.68
2.61
Oil (per bbl)
105.87
92.58
98.47
95.78
Mont Belvieu NGL Composite (per gallon)
0.78
0.79
0.77
0.92
(a) Based on weighted average of bid week prompt month prices.
Consolidated Results of Operations
Overview of Third Quarter 2013 Results
During third quarter 2013, we achieved the following financial and operating results:
increased revenue from the sale of natural gas, NGLs and oil by 28% from the same period of 2012;
achieved 21% production growth from the same period of 2012;
continued expansion of our activities in the Marcellus Shale in Pennsylvania by growing production, proving up acreage and acquiring additional unproved acreage;
continued expansion of our activities in the horizontal Mississippian play in Oklahoma by growing production;
reduced direct operating expenses per mcfe 15% from the same period of 2012;
reduced our depletion, depreciation and amortization (“DD&A”) rate 12% from the same period of 2012;
received proceeds of $15.7 million from the sale of an equity method investment and other non-core assets;
entered into additional derivative contracts for 2013, 2014 and 2015; and
realized $223.0 million of cash flow from operating activities.
For the third quarter, total revenues increased $142.3 million or 47% over the same period of 2012. This increase was due to significantly higher production volumes, an increase in brokered natural gas volumes and a higher gain on the sale of assets. Our third quarter 2013 production growth was due to the continued success of our drilling program, particularly in the Marcellus Shale.
Overview of Nine Months 2013 Results
During the nine months ending September 30, 2013, we achieved the following financial and operating results:
increased revenue from the sale of natural gas, NGLs and oil by 33% from the same period of 2012;
achieved 26% production growth from the same period of 2012;
reduced direct operating expense per mcfe 12% from the same period of 2012;
reduced our DD&A rate 13% from the same period of 2012;
continued our expansion in the Marcellus Shale and the horizontal Mississippian plays;
issued $750.0 million of new 5% senior subordinated notes due 2023;
redeemed all $250.0 million aggregate principal amount of our 7.25% senior subordinated notes due 2018;
received proceeds of $311.7 million from the sale of non-core assets;
realized $502.9 million of cash flow from operating activities (after giving effect to the $87.5 million Oklahoma lawsuit settlement payment).
Total revenues increased $435.0 million or 44% in the nine months ended September 30, 2013 compared to the same period in 2012. This increase was due to significantly higher production volumes, an increase in brokered natural gas volumes and higher gains on the sale of assets partially offset by lower realized gains on derivative settlements. For the nine months ended September 30, 2013, natural gas production increased 25% while oil and NGLs production increased 32% from the same period of the prior year.
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 2013 and for 2014 and 2015, 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.
27
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 sell 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) income 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.
In third quarter 2013, natural gas, NGLs and oil sales increased 28% from the same period of 2012 with a 21% increase in production and a 5% increase in realized prices. In the first nine months 2013, natural gas, NGLs and oil sales increased 33% from the same period of 2012 with a 26% increase in production and a 5% increase in realized prices. The following table illustrates the primary components of natural gas, NGLs and oil sales for the three months and the nine months ended September 30, 2013 and 2012 (in thousands):
Change
Gas wellhead
233,019
159,525
73,494
718,176
399,006
319,170
80
Gas hedges realized (a)
25,870
62,150
(36,280
(58
%)
90,693
198,675
(107,982
(54
Total gas revenue
258,889
221,675
37,214
808,869
597,681
211,188
Total NGLs revenue
77,317
56,826
20,491
36
211,475
189,604
21,871
Oil wellhead
93,473
59,221
34,252
58
243,057
166,718
76,339
Oil hedges realized (a)
1,535
2,217
325
3,730
(997
4,727
474
Total oil revenue
95,008
58,539
36,469
62
246,787
165,721
81,066
49
Combined wellhead
403,809
275,572
128,237
47
1,172,708
755,328
417,380
55
Combined hedges (a)
27,405
61,468
(34,063
(55
94,423
197,678
(103,255
(52
Total natural gas,
NGLs and oil sales
94,174
28
314,125
33
(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 2012, our third quarter 2013 production volumes increased 25% in our Appalachian region and increased 3% in our Southwestern region despite the second quarter 2013 sale of our Delaware and Permian Basin properties in New Mexico and West Texas. When compared to the same period of 2012, our production volumes for the nine months 2013 increased 33% in our Appalachian region and decreased 4% in our Southwestern region with the decrease primarily due to the sale of our properties in New Mexico and West Texas. When compared to the same period of 2012, our Marcellus production volumes increased 32% for the third quarter and 44% for the nine months 2013. Our production for the three months and the nine months ended September 30, 2013 and 2012 is set forth in the following table:
Production (a)
Natural gas (mcf)
68,024,813
57,347,638
10,677,175
194,975,047
156,274,072
38,700,975
NGLs (bbls)
2,362,340
1,843,667
518,673
6,367,253
4,975,086
1,392,167
Crude oil (bbls)
1,018,013
712,858
305,155
2,795,192
1,943,961
851,231
Total (mcfe) (b)
88,306,931
72,686,788
15,620,143
249,949,717
197,788,354
52,161,363
Average daily production (a)
739,400
623,344
116,056
714,194
570,343
143,851
25,678
20,040
5,638
23,323
18,157
5,166
11,065
7,748
3,317
10,239
7,095
3,144
959,858
790,074
169,784
915,567
721,855
193,712
Represents volumes sold regardless of when produced.
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 of oil and natural gas prices.
29
Our average realized price (including all derivative settlements and third-party transportation costs) received during third quarter 2013 was $4.11 per mcfe compared to $4.17 per mcfe in the same period of 2012. Our average realized price (including all derivative settlements and third-party transportation costs) received was $4.20 in the nine months ended September 30, 2013 compared to $4.24 in the same period of the prior year. 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 and the nine months ended September 30, 2013 and 2012 are shown below:
Average Prices
Average sales prices (wellhead):
3.43
2.78
2.55
NGLs (per bbl)
32.73
30.82
33.21
38.11
Crude oil (per bbl)
91.82
83.08
86.96
85.76
Total (per mcfe) (a)
4.57
3.79
4.69
3.82
Average realized prices (including derivative settlements that
qualified for hedge accounting):
3.81
3.87
4.15
93.33
82.12
88.29
85.25
4.88
4.64
5.07
4.82
Average realized prices (including all derivative settlements):
3.88
4.05
3.85
31.08
38.79
32.94
42.22
85.46
84.86
85.35
84.27
4.80
4.96
4.93
Average realized prices (including all derivative settlements
and third party transportation costs paid by Range):
3.03
3.13
3.02
29.64
37.23
31.39
40.66
4.11
4.17
4.20
4.24
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) income was a loss of $40.4 million in third quarter 2013 compared to a loss of $40.7 million in the same period of 2012. Derivative fair value (loss) income was a loss of $2.5 million in the nine months ended September 30, 2013 compared to income of $47.0 million in the same period of 2012. Our derivatives that do not qualify or are not designated for hedge accounting are 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. 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. Hedge ineffectiveness, also included in derivative fair value income or loss, is associated with contracts that qualified for hedge accounting. The ineffective portion is calculated as the difference between the changes in the fair value of the derivative and the estimated change in future cash flows from the item being hedged. Effective March 1, 2013, we elected to discontinue hedge accounting prospectively. After March 1, 2013, all realized and unrealized gains and losses will be recognized in earnings in derivative fair value income or loss immediately as derivative contracts are settled or marked to market.
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Change in fair value of derivatives that did not qualify for hedge accounting (a)
Realized gain (loss) on settlements – natural gas (b) (c)
Realized (loss) gain on settlements – oil (b) (c)
Realized (loss) gain on settlements – NGLs (b) (c)
Hedge ineffectiveness – realized (c)
– unrealized (a)
These amounts are unrealized and are not included in average realized price calculations.
These amounts represent realized gains and losses on settled derivatives that did not qualify or were not designated for hedge accounting.
These settlements are included in average realized price calculations (including all derivative settlements and third party transportation costs paid by Range).
Gain (loss) on the sale of assets was a gain of $6.0 million in third quarter 2013 compared to a gain of $949,000 in the same period of 2012. In third quarter 2013, we recorded gains of $6.0 million on the sale of our equity method investment in a drilling company and other non-core assets, from which we received total proceeds of $15.7 million. In third quarter 2012, we recorded a $746,000 gain on the sale of unproved property in Pennsylvania where we received proceeds of $13.9 million. Gain (loss) on the sale of assets was a gain of $89.1 million in the first nine months 2013 compared to a loss of $12.7 million in the same period of 2012. In the first nine months 2013, we also sold our New Mexico and certain West Texas properties where we recognized a gain of $83.3 million, before selling expenses. In the first nine months 2012, we also sold a seventy-five percent interest in an East Texas prospect which included a suspended exploratory well and unproved properties for proceeds of $8.6 million resulting in a pre-tax loss of $10.9 million and we recorded a $2.5 million pre-tax loss on the sale of a Marcellus exploratory well where we received proceeds of $2.5 million.
Brokered natural gas, marketing and other revenue in third quarter 2013 was $45.2 million compared to $2.5 million in the same period of 2012. The third quarter 2013 includes income from equity method investments of $268,000 and revenue from marketing and the sale of brokered gas of $45.5 million. The third quarter 2012 includes loss from equity method investments of $1.0 million and revenue from marketing and the sale of brokered gas of $3.4 million. Brokered natural gas, marketing and other revenue in the first nine months 2013 was $80.8 million compared to $12.4 million in the same period of 2012. The first nine months 2013 includes income from equity method investments of $541,000 and $81.0 million of revenue from marketing and the sale of brokered gas. The first nine months 2012 includes loss from equity method investments of $195,000 and $12.1 million of revenue from marketing and the sale of brokered gas. These revenues are increasing due to an increase in brokered volumes, due in part to our purchase (and sale) of natural gas which is used to blend our rich residue gas from the Southwest Marcellus Shale.
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 and the nine months ended September 30, 2013 and 2012:
(per mcfe)
% Change
Direct operating expense
0.35
0.41
(0.06
(15
0.38
0.43
(0.05
(12
Production and ad valorem tax expense
0.13
0.01
0.14
0.29
(0.15
0.51
0.61
(0.10
(16
0.64
0.28
0.50
(0.11
(18
0.63
Depletion, depreciation and amortization expense
1.48
1.69
(0.21
1.46
1.68
(0.22
(13
31
Direct operating expense was $30.9 million in third quarter 2013 compared to $29.6 million in the same period of 2012. 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. Even though our production volumes increased 21%, on an absolute basis, our spending for direct operating expenses for third quarter 2013 only increased 4% with an increase in the number of producing wells, higher workover costs and higher utility costs somewhat offset by the sale of certain non-core assets at the beginning of second quarter 2013. We incurred $2.0 million of workover costs in third quarter 2013 compared to $1.4 million of workover costs in the same period of 2012.
On a per mcfe basis, direct operating expense in third quarter 2013 declined 15% from the same period of 2012 with the decrease consisting of lower well services and water handling 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. 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 begin to increase.
Direct operating expense was $93.7 million in the nine months ended September 30, 2013 compared to $85.7 million in the same period of 2012. Even though our production volumes increased 26%, on an absolute basis, our spending for direct operating expenses only increased 9% with an increase in the number of producing wells and higher utilities, well services, workovers, well insurance and personnel costs somewhat offset by the sale of certain non-core assets. We incurred $5.5 million of workover costs in the nine months ended September 30, 2013 compared to $3.5 million in the same period of 2012. On a per mcfe basis, direct operating expense in the nine months ended September 30, 2013 decreased 12% to $0.38 from $0.43 in the same period of 2012, with the decrease consisting of lower well services, water handling and personnel costs. Stock-based compensation expense represents the amortization of restricted stock grants and SARs as part of the compensation of field employees. The following table summarizes direct operating expenses per mcfe for the three months and the nine months ended September 30, 2013 and 2012:
Lease operating expense
0.32
0.40
Workovers
0.02
Stock-based compensation (non-cash)
Total direct operating expense
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 $4.5 million in third quarter 2013 compared to $3.4 million in the same period of 2012. On a per mcfe basis, production and ad valorem taxes (excluding the impact fee) was $0.05 in both third quarter 2013 and third quarter 2012 with an increase in volumes not subject to production taxes and the sale of non-core assets in New Mexico and West Texas 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 third quarter 2013 is a $7.0 million impact fee ($0.08 per mcfe) compared to $5.4 million ($0.07 per mcfe) in the same period of the prior year.
Production and ad valorem taxes (excluding the impact fee) were $12.8 million ($0.05 per mcfe) in the first nine months 2013 compared to $14.5 million ($0.07 per mcfe) in the same period of 2012 due to an increase in volumes not subject to production taxes and the sale of certain non-core assets in New Mexico and West Texas partially offset by higher prices. Included in the nine months 2013 is a $21.2 million ($0.08 per mcfe) impact fee compared to $18.0 million ($0.09 per mcfe) in the same period of 2012. The nine months ended September 30, 2012 also includes $24.7 million ($0.12 per mcfe) retroactive impact fee which covered wells drilled prior to 2012.
32
General and administrative (“G&A”) expense was $44.9 million in third quarter 2013 compared to $44.5 million for the same period of 2012. The third quarter 2013 increase of $422,000 when compared to 2012 is primarily due to higher salary and benefit expenses of $1.5 million and an increase in stock-based compensation of $974,000 partially offset by lower legal and office expenses, including information technology. We continue to incur higher wages which we consider necessary to remain competitive in the industry. G&A expense for the nine months ended September 30, 2013 increased $103.7 million or 82% from the same period of the prior year primarily due to a legal settlement related to an Oklahoma lawsuit of $87.5 million, higher salary and benefit expenses of $6.0 million, an increase in stock-based compensation of $3.8 million and higher legal and office expenses, including information technology. Our number of G&A employees increased 6% from September 30, 2012 to September 30, 2013. Stock-based compensation expense represents the amortization of restricted stock grants and SARs granted to our employees and non-employee directors as part of compensation. On a per mcfe basis, G&A expense decreased 16% from third quarter 2012 and increased 44% from the nine months ended September 30, 2012 primarily due to the Oklahoma legal settlement. The following table summarizes general and administrative expenses per mcfe for the three months and the nine months ended September 30, 2013 and 2012:
0.39
0.47
0.08
(17
0.48
(10
Oklahoma legal settlement
(0.02
(14
0.16
Total general and administrative expenses
Interest expense was $44.3 million for third quarter 2013 compared to $44.0 million for third quarter 2012 and was $131.6 million in the nine months ended September 30, 2013 compared to $124.1 million in the nine months ended September 30, 2012. The following table presents information about interest expense for the three months and nine months ended September 30, 2013 and 2012 (in thousands):
Bank credit facility
3,168
3,224
10,022
7,884
38,501
38,344
113,571
109,365
Amortization of deferred financing costs and other
2,652
2,429
8,009
6,841
Total interest expense
The increase in interest expense for third quarter 2013 from the same period of 2012 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. In March 2012, we issued $600.0 million of 5.00% senior subordinated notes due 2022. We used the proceeds to repay $350.0 million of our outstanding credit facility balance and for general corporate purposes. The 2013 and 2012 note issuances were 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 third quarter 2013 was $409.8 million compared to $375.2 million in the same period of 2012 and the weighted average interest rate on the bank credit facility was 1.9% in third quarter 2013 compared to 2.1% in the same period of 2012.
The increase in interest expense for the nine months ended September 30, 2013 from the same period of 2012 was primarily due to an increase in outstanding debt balances. Average debt outstanding on the bank credit facility was $419.6 million compared to $239.9 million for 2012 and the weighted average interest rate on the bank credit facility was 2.0% in the nine months ended September 30, 2013 compared to 2.2% in the same period of 2012.
Depletion, depreciation and amortization (“DD&A”) was $130.3 million in third quarter 2013 compared to $123.1 million in the same period of 2012. The increase in third quarter 2013 when compared to the same period of 2012 is due to a 12% decrease in depletion rates more than offset by a 21% increase in production. Depletion expense, the largest component of DD&A, was $1.41 per mcfe in third quarter 2013 compared to $1.61 per mcfe in the same period of 2012. 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.
DD&A was $365.4 million in the nine months ended September 30, 2013 compared to $332.0 million in the same period of 2012. Depletion expense was $1.39 per mcfe in the nine months ended September 30, 2013 compared to $1.60 per mcfe in the same period of 2012. The following table summarizes DD&A expense per mcfe for the three months and nine months ended September 30, 2013 and 2012:
Depletion and amortization
1.41
1.61
(0.20
1.39
1.60
Depreciation
0.05
(0.01
(20
Accretion and other
0.03
(25
Total DD&A expense
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, deferred compensation plan expense, loss on extinguishment of debt and impairment of proved properties. Stock-based compensation includes the amortization of restricted stock grants and SARs grants. The following table details the allocation of stock-based compensation that is allocated to functional expense categories for the three months and the nine months ended September 30, 2013 and 2012 (in thousands):
Total stock-based compensation
Transportation, gathering and compression expense was $61.0 million in third quarter 2013 compared to $51.6 million in the same period of 2012. Transportation, gathering and compression expense was $189.4 million in the nine months ended September 30, 2013 compared to $137.2 million in the same period of 2012. These third party costs are higher than 2012 due to our production growth in the Marcellus Shale where we have third party gathering, compression and transportation agreements. 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 $51.1 million in third quarter 2013 compared to $4.9 million in the same period of 2012. Brokered natural gas and marketing expense was $90.1 million in the nine months ended September 30, 2013 compared to $15.4 million in the same period of 2012. These costs are higher than 2012 primarily due to an increase in brokered volumes due in part to our purchase (and sale) of natural gas which is used to blend our rich residue gas from the Southwest Marcellus Shale.
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Exploration expense was $20.5 million in third quarter 2013 compared to $14.8 million in the same period of 2012. Exploration expense was higher in third quarter 2013 when compared to 2012 due to higher seismic, dry hole costs and delay rentals. The nine months ended September 30, 2013 includes lower seismic partially offset by higher dry hole and personnel costs compared to the same period of 2012. The following table details our exploration related expenses for the three months and nine months ended September 30, 2013 and 2012 (in thousands):
Seismic
7,621
6,995
626
20,866
26,763
(5,897
(22
Delay rentals and other
4,337
3,495
842
11,439
11,084
355
Personnel expense
3,493
3,121
372
11,122
10,059
1,063
(143
3,047
(34
(1
Dry hole expense
4,062
4,047
NM
3,072
369
Total exploration expense
5,744
39
(1,441
(3
Abandonment and impairment of unproved properties was $11.7 million in third quarter 2013 compared to $40.1 million in the same period of 2012. Abandonment and impairment was $46.1 million in the nine months ended September 30, 2013 compared to $104.0 million in the same period of 2012. 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. In second quarter 2012, we impaired individually significant unproved properties in Pennsylvania for $23.1 million because we determined that we were not going to drill in the area. In third quarter 2012, we impaired individually significant unproved properties in the Barnett Shale of North Texas for $19.6 million because we determined we would not drill and would allow the leases to expire.
Deferred compensation plan expense was a gain of $2.2 million in third quarter 2013 compared to a loss of $20.1 million in the same period of 2012. 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 $77.32 at June 30, 2013 to $75.89 at September 30, 2013. In the same quarter of the prior year, our stock price increased from $61.87 at June 30, 2012 to $69.87 at September 30, 2012. During the nine months ended September 30, 2013 deferred compensation plan expense was $33.3 million compared to $21.6 million in the same period of 2012. Our stock price increased from $62.83 at December 31, 2012 to $75.89 at September 30, 2013. In the same nine months of 2012, our stock price decreased from $61.94 at December 31, 2011 to $69.87 at September 30, 2012.
Loss on extinguishment of debt for the nine months ended September 30, 2013 was $12.3 million. On May 2, 2013, we redeemed all of our $250.0 million aggregate principal amount of 7.25% senior subordinated notes due 2018 at 103.625% of par and we recorded a loss on extinguishment of debt of $12.3 million which includes a call premium and the expensing of related deferred financing costs on the repurchased debt.
Impairment of proved properties and other assets was $7.0 million in third quarter 2013 and $7.8 million in the nine months ended September 30, 2013 compared to $1.3 million in the third quarter and the nine months ended September 30, 2012. The third quarter 2013 includes a $7.0 million impairment related to certain South Texas wells. Our analysis of these properties determined that undiscounted cash flows were less than their carrying value. We compared the carrying value to their estimated fair value and recognized an impairment charge. We evaluated these assets for impairment due to declining reserves. The nine months ended September 30, 2013 also includes a $741,000 impairment related to some surface acreage in North Texas. The third quarter and the nine months ended September 30, 2012 includes a $1.3 million impairment on surface acreage in North Texas.
Income tax expense (benefit) was an expense of $11.9 million in third quarter 2013 compared to a benefit of $29.1 million in third quarter 2012. The increase in income taxes in third quarter 2013 reflects a 137% increase in income from operations when compared to the same period of 2012. For the third quarter, the effective tax rate was 38.2% in 2013 compared to 35.1% in 2012. Income tax expense was $62.2 million in the nine months ended September 30, 2013 compared to an income tax benefit of $17.9 million in the same period of 2012. For the nine months ended September 30, 2013, the increase in income taxes reflects a 359% increase in income from operations when compared to the prior year period. For the nine months September 30, 2013, the effective tax rate was 41.5% compared to 30.9% in the nine months ended September 30, 2012. The 2013 and 2012 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. Our 2013 effective tax rate was also different from the statutory rate due to deferred tax assets related to capital losses realized which are more likely than not recoverable and the reversal of a valuation allowance previously recorded related to our Pennsylvania net operating losses due to a change in Pennsylvania legislation enacted in July 2013. The U.S. Treasury Department issued the final Tangible Property Regulations in third quarter 2013. The adoption of these final regulations are not expected to have a material impact on our financial statements or our federal or state income tax positions. We expect our effective tax rate to be approximately 40% for the remainder of 2013.
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 our 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 September 30, 2013, we have entered into hedging agreements covering 68.9 Bcfe for the remainder of 2013, 213.7 Bcfe for 2014 and 60.0 Bcfe for 2015.
Net cash provided from operations in the first nine months 2013 was $502.9 million compared to $461.1 million in the same period of 2012. 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 increase in cash provided from operating activities from 2012 to 2013 reflects a 26% increase in production offset by lower realized prices (a decline of 1%) and higher operating costs, including the settlement payment of the $87.5 million related to Oklahoma lawsuit settlement. As of September 30, 2013, we have hedged approximately 76% of our projected production for the remainder of 2013, with approximately 76% of our projected natural gas production hedged. Net cash provided from continuing operations is also 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 nine months 2013 was negative $48.0 million compared to positive $26.3 million for the same period of 2012.
Net cash used in investing activities from operations in first nine months 2013 was $671.1 million compared to $1.3 billion in the same period of 2012.
During the nine months ended September 30, 2013, we:
spent $907.8 million on natural gas and oil property additions;
spent $70.2 million on acreage primarily in the Marcellus Shale; and
received proceeds from asset sales of $311.7 million.
During the nine months ended September 30, 2012, we:
spent $1.2 billion on natural gas and oil property additions;
spent $175.0 million on acreage primarily in the Marcellus Shale; and
received proceeds from asset sales of $32.1 million.
Net cash provided from financing activities in first nine months 2013 was $168.3 million compared to $848.6 million in the same period of 2012. Historically, sources of financing have been primarily bank borrowings and capital raised through equity and debt offerings.
borrowed $1.3 billion and repaid $1.6 billion under our bank credit facility, ending the quarter with a $427.0 million outstanding balance on our bank debt;
issued $750.0 million aggregate principal amount of 5.00% senior subordinated notes due 2023, at par, with net proceeds of approximately $738.8 million;
redeemed all $250.0 million aggregate principal amount of 7.25% senior subordinated notes due 2018 including related expenses.
borrowed $1.1 billion and repaid $865.0 million under our bank credit facility, ending the quarter with $461.0 million outstanding borrowings under our bank credit facility;
issued $600.0 million principal amount of 5.00% senior subordinated notes due 2022, at par, with net proceeds of approximately $589.5 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 continue to take steps to ensure adequate capital resources and liquidity to fund our capital expenditure program. In first nine months 2013, we entered into additional commodity derivative contracts for 2013, 2014 and 2015 to protect future cash flows. In March 2013, we issued $750.0 million of new 5.00% ten-year senior subordinated notes due 2023. On April 2, 2013, we called for redemption the entire $250.0 million outstanding principal amount of our 7.25% senior subordinated notes due 2018 which were redeemed on May 2, 2013. On October 18, 2013, our borrowing base and our credit facility amounts were reaffirmed.
During the first nine of months 2013, our net cash provided from continuing operations of $502.9 million, proceeds from the sale of assets of $311.7 million, proceeds from the issuance of our 5.00% senior subordinated notes due 2023 and borrowings under our bank credit facility were used to fund $982.2 million of capital expenditures (including acreage acquisitions). At September 30, 2013, we had $255,000 in cash and total assets of $7.0 billion.
Long-term debt at September 30, 2013 totaled $3.1 billion, including $427.0 million outstanding on our bank credit facility and $2.6 billion of senior subordinated notes. Our available committed borrowing capacity at September 30, 2013 was $1.2 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.
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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.
Our expectations concerning liquidity and our ability to avail ourselves in the future of the financing options mentioned in the above forward-looking statements are based on currently available information. If this information proves to be inaccurate, future availability of financing may be adversely affected. Factors that affect the availability of financing include our performance, the state of the worldwide debt and equity markets, investor perceptions and expectations of past and future performance, the global financial climate and, in particular, with respect to borrowings, the level of our working capital or outstanding debt and credit ratings by rating agencies.
Credit Arrangements
As of September 30, 2013, 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-annually 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 October 18, 2013, 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 September 30, 2013.
Capital Requirements
Our primary capital requirements are for exploration, development and acquisition of natural gas and oil properties, repayment of principal and interest on outstanding debt and payment of dividends. During the first nine months of 2013, $951.0 million of capital was expended on drilling projects. Also in the first nine months of 2013, $70.0 million was expended on acquisitions of unproved acreage, primarily in the Marcellus Shale. Our 2013 capital program, excluding acquisitions, is expected to be funded by net cash flow from operations, our prior debt offering, proceeds from asset sales and borrowings under our bank credit facility. Our capital expenditure budget for 2013 is currently set at $1.35 billion, excluding proved property acquisitions. To the extent capital requirements exceed internally generated cash flow, proceeds from asset sales and our committed capacity under our bank credit facility will be used to fund these requirements. In addition, debt or equity may also be issued in capital market transactions to fund these requirements. We monitor our capital expenditures on an ongoing basis, adjusting the amount up or down and also between our operating regions, depending on commodity prices, cash flow and projected returns. Also, our obligations may change due to acquisitions, divestitures and continued growth. We may issue additional shares of stock, subordinated notes or other debt securities to fund capital expenditures, acquisitions, extend maturities or to repay debt.
The forward-looking statements about our capital budget are based on current expectations, estimates and projections and are not guarantees of future performance. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Some factors that could cause actual results to differ materially include prices of and demand for natural gas and oil, actions of competitors, disruptions or interruptions of our production and unforeseen hazards such as weather conditions, acts of war or terrorists acts and the government or military response, and other operating and economic considerations.
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Cash Dividend Payments
The amount of future dividends is subject to declaration by the Board of Directors and primarily depends on earnings, capital expenditures, debt covenants and various other factors. On September 1, 2013, the Board of Directors declared a dividend of four cents per share ($6.5 million) on our common stock, which was paid on September 30, 2013 to stockholders of record at the close of business on September 16, 2013.
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 September 30, 2013, we do not have any capital leases. As of September 30, 2013, 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 September 30, 2013, we had a total of $84.9 million of undrawn letters of credit under our bank credit facility.
Since December 31, 2012, there have been no material changes to our contractual obligations other than a $312.0 million reduction to our outstanding bank credit facility balance, an issuance of $750.0 million of new 5.00% senior subordinated notes due 2023, a redemption of $250.0 million 7.25% senior subordinated notes due 2018 and rate adjustments to certain transportation and gathering contracts which increased these commitments by approximately $150.0 million over the next 10 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. In 2011, we also entered into “sold” NGLs derivative swap contracts for the natural gasoline component of NGLs and in 2012 we entered into “re-purchased” derivative swaps for the natural gasoline component of NGLs. In addition, in third quarter 2012, we entered into NGLs derivative swap contracts for propane and in third quarter 2013, we entered into NGLs derivative swap contracts for normal butane. While there is a risk that the financial benefit of rising natural gas, NGLs and oil prices may not be captured, we believe the benefits of stable and predictable cash flow are more important. Among these benefits are a more efficient utilization of existing personnel and planning for future staff additions, the flexibility to enter into long-term projects requiring substantial committed capital, smoother and more efficient execution of our on-going development drilling and production enhancement programs, more consistent returns on invested capital, and better access to bank and other credit markets.
At September 30, 2013, we had open swap contracts covering 40.7 Bcf of natural gas at prices averaging $3.94 per mcf, 3.9 million barrels of oil at prices averaging $93.83 per barrel, 0.6 million net barrels of NGLs (the C5 component of NGLs) at prices averaging $92.72 per barrel, 3.6 million barrels of NGLs (the C3 component of NGLs) at prices averaging $39.67 per barrel and 0.9 million barrels of NGLs (the C4 component of NGLs) at prices averaging $54.77. We had collars covering 242.0 Bcf of natural gas at weighted average floor and cap prices of $3.97 to $4.56 per mcf and 1.0 million barrels of oil at weighted average floor and cap prices of $86.94 to $100.00 per barrel. 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 gain of $66.0 million at September 30, 2013. The contracts expire monthly through December 2015.
At September 30, 2013, the following commodity derivative contracts were outstanding:
$3.82
$4.17
$4.16
$96.79
$94.14
$90.20
Interest Rates
At September 30, 2013, we had approximately $3.1 billion of debt outstanding. Of this amount, $2.7 billion bears interest at fixed rates averaging 5.8%. Bank debt totaling $427.0 million bears interest at floating rates, which averaged 1.9% at September 30, 2013. The 30-day LIBOR rate on September 30, 2013 was approximately 0.2%. A 1% increase in short-term interest rates on the floating-rate debt outstanding on September 30, 2013 would cost us approximately $4.3 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 described above under cash contractual obligations.
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 general inflation, inflation does not normally have a significant effect on our business. We expect costs for the remainder of 2013 to continue to be a function of supply and demand.
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ITEM 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 manage 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 provide 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 74% of our December 31, 2012 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, 2012 to September 30, 2013.
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 September 30, 2013, our derivatives program includes swaps (both purchased and sold NGLs swaps) and collars. As of September 30, 2013, we had open swap contracts covering 40.7 Bcf of natural gas at prices averaging $3.94 per mcf, 3.9 million barrels of oil at prices averaging $93.83 per barrel, 0.6 million net barrels of NGLs (the C5 component of NGLs) at prices averaging $92.72 per barrel, 3.6 million barrels of NGLs (the C3 component of NGLs) at prices averaging $39.67 per barrel and 0.9 million barrels of NGLs (the C4 component of NGLs) at prices averaging $54.77 per barrel. We had collars covering 242.0 Bcf of natural gas at weighted average floor and cap prices of $3.97 to $4.56 per mcf and 1.0 million barrels of oil at weighted average floor and cap prices of $86.94 to $100.00 per barrel. These contracts expire monthly through December 2015. The fair value of these contracts, represented by the estimated amount that would be realized upon immediate liquidation as of September 30, 2013, approximated a net unrealized pretax gain of $66.0 million.
Market Value
$25,983
$34,197
$9,799
$6,068
$3,393
$285
$(870)
$(796)
$(2,983)
$(3,028)
$1,207
$1,461
$1,902
$(6,927)
$(3,534)
$(570)
$406
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 percentage 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. Over 70% of our NGLs production is in the Marcellus Shale.
Currently, because there is little demand, or facilities to supply the existing demand, for ethane in the Appalachian region, for our Appalachian production volumes, ethane remains in the natural gas stream. In third quarter 2013, we began purchasing natural gas to blend with our rich residue gas to meet transmission pipeline specifications. We have announced three ethane agreements where we have contracted to either sell or transport ethane from our Marcellus Shale area, which are expected to begin operations at various times in late 2013 through 2015. We cannot assure you that these facilities will become available.
Other Commodity Risk
We are impacted by basis risk, caused by factors that affect the relationship between commodity futures prices reflected in derivative commodity instruments and the cash market price of the underlying commodity. Natural gas transaction prices are frequently based on industry reference prices that may vary from prices experienced in local markets. If commodity price changes in one region are not reflected in other regions, derivative commodity instruments may no longer provide the expected hedge, resulting in increased basis risk. At times, 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 in the past that effectively fix the basis adjustments. We currently have no financial basis swap agreements outstanding.
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The following table shows the fair value of our collars and swaps and the hypothetical change in fair value that would result from a 10% and a 25% change in commodity prices at September 30, 2013. 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
Increase of
Decrease of
10%
25%
(79,068
(201,246
79,434
211,730
(76,462
(190,960
77,348
193,500
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 counterparties 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 September 30, 2013, our derivative counterparties include fifteen 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 variable rate bank debt. At September 30, 2013, we had $3.1 billion of debt outstanding. Of this amount, $2.7 billion bears interest at fixed rates averaging 5.8%. Bank debt totaling $427.0 million bears interest at floating rates, which was 1.9% on September 30, 2013. On September 30, 2013, the 30-day LIBOR rate was approximately 0.2%. A 1% increase in short-term interest rates on the floating-rate debt outstanding on September 30, 2013, would cost us approximately $4.3 million in additional annual interest expense.
ITEM 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 September 30, 2013 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 September 30, 2013 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
ITEM 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.
ITEM 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, 2012. There have been no material changes from the risk factors previously disclosed in that Form 10-K.
ITEM 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.
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: October 29, 2013
By:
/s/ ROGER S. MANNY
Roger S. Manny
Executive Vice President and Chief Financial Officer
/s/ DORI A. GINN
Dori A. Ginn
Principal Accounting Officer and Vice President Controller
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 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 28, 2005) and the Certificate of Second Amendment to the 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 (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)
31.1*
Certification by the President and Chief Executive Officer of Range Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*
Certification by the Chief Financial Officer of Range Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1**
Certification by the President and Chief Executive Officer of Range 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 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