e10vq
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark one)
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þ |
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended March 31, 2011
OR
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o |
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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)
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Delaware
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34-1312571 |
(State or Other Jurisdiction of Incorporation or Organization)
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(IRS Employer Identification No.) |
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100 Throckmorton Street, Suite 1200 |
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Fort Worth, Texas
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76102 |
(Address of Principal Executive Offices)
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(Zip Code) |
Registrants 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 o
Indicate by check mark whether the registrant has submitted electronically and posted on
its corporate website, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for shorter period that
the registrant was required to submit and post such files). Yes
o No
þ
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.
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Large Accelerated Filer þ
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Accelerated Filer o
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Non-Accelerated Filer o
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Smaller Reporting Company o |
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(Do not check if a smaller reporting company) |
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Indicate by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act). Yes o No þ
160,703,877 Common Shares were outstanding on April 25, 2011.
RANGE RESOURCES CORPORATION
FORM 10-Q
Quarter Ended March 31, 2011
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
2
PART I FINANCIAL INFORMATION
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ITEM 1. |
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Financial Statements |
RANGE
RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(Unaudited, in thousands, except per share data)
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March 31, 2011 |
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December 31, 2010 |
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Assets |
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Current assets: |
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Cash and cash equivalents |
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$ |
1,681 |
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$ |
2,848 |
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Accounts receivable, less allowance for doubtful accounts of $4,285 and $5,001 |
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75,530 |
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76,683 |
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Unrealized derivative gain |
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62,286 |
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123,255 |
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Assets of discontinued operations |
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856,195 |
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876,304 |
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Inventory and other |
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18,605 |
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21,352 |
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Deferred tax asset |
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1,639 |
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Total current assets |
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1,015,936 |
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1,100,442 |
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Equity method investments |
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142,353 |
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155,105 |
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Natural gas and oil properties, successful efforts method |
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5,669,791 |
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5,390,391 |
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Accumulated depletion and depreciation |
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(1,373,652 |
) |
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(1,306,378 |
) |
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4,296,139 |
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4,084,013 |
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Transportation and field assets |
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121,274 |
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134,980 |
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Accumulated depreciation and amortization |
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(61,303 |
) |
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(60,931 |
) |
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59,971 |
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74,049 |
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Other assets |
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100,848 |
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84,977 |
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Total assets |
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$ |
5,615,247 |
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$ |
5,498,586 |
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Liabilities |
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Current liabilities: |
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Accounts payable |
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$ |
245,446 |
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$ |
289,109 |
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Asset retirement obligations |
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4,020 |
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4,020 |
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Accrued liabilities |
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44,629 |
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60,082 |
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Deferred tax liability |
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11,848 |
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Accrued interest |
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39,496 |
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32,189 |
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Unrealized derivative loss |
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593 |
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352 |
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Current liabilities of discontinued operations |
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16,288 |
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32,962 |
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Total current liabilities |
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350,472 |
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430,562 |
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Bank debt |
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480,000 |
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274,000 |
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Subordinated notes |
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1,686,816 |
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1,686,536 |
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Deferred tax liability |
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646,427 |
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672,041 |
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Unrealized derivative loss |
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30,242 |
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13,412 |
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Deferred compensation liability |
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169,278 |
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134,488 |
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Asset retirement obligations and other liabilities |
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66,168 |
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59,885 |
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Long-term liabilities of discontinued operations |
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2,226 |
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3,901 |
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Commitments and contingencies |
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Stockholders Equity |
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Preferred stock, $1 par, 10,000,000 shares authorized, none issued and outstanding |
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Common stock, $0.01 par, 475,000,000 shares authorized, 160,668,296 issued
at March 31, 2011 and 160,113,608 issued at December 31, 2010 |
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1,607 |
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1,601 |
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Common stock held in treasury, 196,016 shares at March 31, 2011
and 204,556 shares at December 31, 2010 |
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(7,190 |
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(7,512 |
) |
Additional paid-in capital |
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1,835,261 |
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1,820,503 |
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Retained earnings |
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310,246 |
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341,699 |
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Accumulated other comprehensive income |
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43,694 |
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67,470 |
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Total stockholders equity |
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2,183,618 |
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2,223,761 |
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Total liabilities and stockholders equity |
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$ |
5,615,247 |
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$ |
5,498,586 |
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See the accompanying notes.
3
RANGE
RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited, in thousands, except per share data)
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Three Months Ended March 31, |
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2011 |
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2010 |
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Revenues and other income |
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Natural gas, NGL and oil sales |
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$ |
226,881 |
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$ |
187,673 |
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Transportation and gathering |
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313 |
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2,081 |
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Derivative fair value (loss) income |
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(40,834 |
) |
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42,333 |
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Gain on the sale of assets |
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139 |
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67,913 |
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Other |
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1,077 |
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(1,575 |
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Total revenues and other income |
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187,576 |
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298,425 |
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Costs and expenses |
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Direct operating |
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28,717 |
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21,836 |
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Production and ad valorem taxes |
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6,879 |
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6,542 |
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Exploration |
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27,187 |
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14,139 |
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Abandonment and impairment of unproved properties |
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16,537 |
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6,551 |
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General and administrative |
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33,959 |
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28,170 |
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Termination costs |
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7,938 |
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Deferred compensation plan |
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30,630 |
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(5,712 |
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Interest expense |
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24,779 |
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20,931 |
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Depletion, depreciation and amortization |
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72,216 |
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64,807 |
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Impairment of proved properties |
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6,505 |
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Total costs and expenses |
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240,904 |
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171,707 |
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(Loss) income from continuing operations before income taxes |
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(53,328 |
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126,718 |
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Income tax (benefit) expense |
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Current |
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Deferred |
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(19,897 |
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49,012 |
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Total income tax (benefit) expense |
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(19,897 |
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49,012 |
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(Loss) income from continuing operations |
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(33,431 |
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77,706 |
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Discontinued operations, net of taxes |
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8,398 |
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(127 |
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Net (loss) income |
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$ |
(25,033 |
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$ |
77,579 |
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(Loss) income per common share |
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Basic-(loss) income from continuing operations |
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$ |
(0.21 |
) |
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$ |
0.50 |
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-discontinued operations |
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0.05 |
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-net (loss) income |
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$ |
(0.16 |
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$ |
0.50 |
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Diluted-(loss) income from continuing operations |
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$ |
(0.21 |
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$ |
0.48 |
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-discontinued operations |
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0.05 |
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-net (loss) income |
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$ |
(0.16 |
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$ |
0.48 |
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Dividends per common share |
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$ |
0.04 |
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$ |
0.04 |
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Weighted average common shares outstanding |
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Basic |
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157,545 |
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156,393 |
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Diluted |
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157,545 |
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160,292 |
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See the accompanying notes.
4
RANGE
RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited, in thousands)
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Three Months Ended March 31, |
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2011 |
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2010 |
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Operating activities |
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Net (loss) income |
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$ |
(25,033 |
) |
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$ |
77,579 |
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Adjustments to reconcile net cash provided from operating activities: |
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(Gain) loss from discontinued operations |
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(8,398 |
) |
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127 |
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Loss from equity method investments, net of distributions |
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14,738 |
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1,621 |
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Deferred income tax (benefit) expense |
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(19,897 |
) |
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49,012 |
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Depletion, depreciation, amortization and proved property impairment |
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72,216 |
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71,312 |
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Exploration dry hole costs |
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10 |
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Mark-to-market loss (gain) on gas and oil derivatives not designated as hedges |
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40,036 |
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(46,578 |
) |
Abandonment and impairment of unproved properties |
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16,537 |
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6,551 |
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Unrealized derivative (gain) loss |
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(568 |
) |
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249 |
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Allowance for bad debts |
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(688 |
) |
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Deferred and stock-based compensation |
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40,650 |
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7,277 |
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Amortization of deferred financing costs and other |
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(78 |
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1,167 |
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Gain on sale of assets |
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(139 |
) |
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(67,913 |
) |
Changes in working capital: |
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Accounts receivable |
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1,689 |
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8,111 |
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Inventory and other |
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3,574 |
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(700 |
) |
Accounts payable |
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2,302 |
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17,452 |
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Accrued liabilities and other |
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(18,210 |
) |
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(8,998 |
) |
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Net cash provided from continuing operations |
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118,741 |
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116,269 |
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Net cash provided from discontinued operations |
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21,881 |
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36,605 |
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Net cash provided from operating activities |
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140,622 |
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152,874 |
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Investing activities |
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Additions to oil and gas properties |
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(250,766 |
) |
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(153,971 |
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Additions to field service assets |
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(1,022 |
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(6,355 |
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Acreage and proved property purchases |
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(24,316 |
) |
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(19,849 |
) |
Other assets |
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(45 |
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Investing activities of discontinued operations |
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(8,219 |
) |
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(12,273 |
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Proceeds from disposal of assets |
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15,197 |
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301,648 |
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Purchase of marketable securities held by the deferred compensation plan |
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(6,260 |
) |
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(3,690 |
) |
Proceeds from the sales of marketable securities held by the deferred
compensation plan |
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3,557 |
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2,613 |
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Net cash (used in) provided from investing activities |
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(271,829 |
) |
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108,078 |
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Financing activities |
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Borrowing on credit facilities |
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372,826 |
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148,000 |
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Repayment on credit facilities |
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(166,826 |
) |
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(118,000 |
) |
Dividends paid |
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(6,420 |
) |
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(6,373 |
) |
Issuance of common stock |
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503 |
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5,437 |
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Debt issuance costs |
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(12,356 |
) |
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Change in cash overdrafts |
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(60,979 |
) |
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(5,162 |
) |
Proceeds from the sales of common stock held by the deferred compensation plan |
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3,292 |
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|
893 |
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Net cash provided from financing activities |
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130,040 |
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24,795 |
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(Decrease) increase in cash and equivalents |
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(1,167 |
) |
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285,747 |
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Cash and cash equivalents at beginning of period |
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2,848 |
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|
767 |
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Cash and cash equivalents at end of period |
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$ |
1,681 |
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$ |
286,514 |
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|
See the accompanying notes.
5
RANGE
RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Unaudited, in thousands)
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Three Months Ended March 31, |
|
|
|
2011 |
|
|
2010 |
|
Net (loss) income |
|
$ |
(25,033 |
) |
|
$ |
77,579 |
|
Other comprehensive (loss) income: |
|
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|
Realized gain on hedge derivative
contract settlements reclassified into
earnings from other comprehensive
income, net of taxes |
|
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(23,889 |
) |
|
|
(753 |
) |
Change in unrealized deferred
hedging gains (losses), net of taxes |
|
|
113 |
|
|
|
52,582 |
|
|
|
|
|
|
|
|
Total comprehensive (loss) income |
|
$ |
(48,809 |
) |
|
$ |
129,408 |
|
|
|
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|
|
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|
See the accompanying notes.
6
RANGE RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
(1) ORGANIZATION AND NATURE OF BUSINESS
We are a Fort Worth, Texas-based independent natural gas and oil company engaged in
the exploration, development and acquisition of natural gas and oil properties, mostly in the
Appalachia and the Southwest 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 Resources Corporation 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
These interim financial statements should be read in conjunction with the consolidated
financial statements and notes thereto included in the Range Resources Corporation 2010 Annual
Report on Form 10-K filed on March 1, 2011. These consolidated financial statements are unaudited
but, in the opinion of management, reflect all adjustments necessary for fair presentation of the
results for the periods presented. All adjustments are of a normal recurring nature unless
disclosed otherwise. These consolidated financial statements, including selected notes, have been
prepared in accordance with the applicable rules of the Securities and Exchange Commission (SEC)
and do not include all of the information and disclosures required by accounting principles
generally accepted in the United States of America for complete financial statements.
In February 2011, we entered into an agreement to sell our Barnett Shale assets. Accordingly,
we have classified the assets and liabilities as discontinued operations in the accompanying
consolidated balance sheets along with the historic results
of operations of our Barnett Shale operations as discontinued operations, net of tax, in the
accompanying consolidated statements of operations. See also Note 4 and 5.
(3) NEW ACCOUNTING STANDARDS
There have been no developments to recently issued accounting standards, including the
expected dates of adoption and estimated effects on our consolidated financial statements, from
those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2010.
(4) DISPOSITIONS
2011 Asset Sales
In February 2011, we entered into an agreement to sell our Barnett Shale natural gas
properties in North Central Texas for a price of $900.0 million, which also includes the assumption
of certain derivative contracts by the buyer and is subject to normal post closing adjustments.
The completion of the sale is dependent upon customary prospective buyer due diligence procedures.
We expect to complete the sale by the end of April 2011. As of March 31, 2011, we have classified
these assets and liabilities held for sale as discontinued operations. As of February 28, 2011, the carrying value of the
asset group, which excludes the derivative contracts to be sold, was approximately $827.9 million. As indicated in Note 2, our Barnett operations are presented as
discontinued operations.
2010 Asset Sales
In February 2010, we entered into an agreement to sell our tight gas sand properties in Ohio.
We closed approximately 90% of the sale in March 2010 and closed the remainder in June 2010.
Proceeds received in first quarter 2010 were approximately $300.0 million and we recorded a
gain of $67.0 million in continuing operations. The agreement had an effective date of January 1,
2010, and consequently operating net revenues after January 1, 2010 were a downward adjustment to
the selling price. The proceeds we received were placed in a like-kind exchange account and in
June 2010, we used a portion of the proceeds to purchase proved and unproved natural gas properties
in Virginia. In September 2010, the like-kind exchange account was closed and the balance of these
proceeds ($135.0 million) was used to repay amounts outstanding under our bank credit facility.
7
(5) DISCONTINUED OPERATIONS
The following table presents the components of our Barnett operations as discontinued operations for the three months
ended March 31, 2011 and 2010 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2011 |
|
|
2010 |
|
Revenues and other income |
|
|
|
|
|
|
|
|
Natural gas, NGL and oil sales |
|
$ |
42,257 |
|
|
$ |
49,087 |
|
Transportation and gathering |
|
|
5 |
|
|
|
12 |
|
Gain on the sale of assets |
|
|
|
|
|
|
955 |
|
Other |
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues and other income |
|
|
42,266 |
|
|
|
50,054 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses |
|
|
|
|
|
|
|
|
Direct operating |
|
|
8,277 |
|
|
|
9,204 |
|
Production and ad valorem taxes |
|
|
1,066 |
|
|
|
1,528 |
|
Exploration |
|
|
32 |
|
|
|
496 |
|
Abandonment and impairment of unproved properties |
|
|
|
|
|
|
5,856 |
|
Interest expense (a) |
|
|
11,076 |
|
|
|
9,356 |
|
Depletion, depreciation and amortization |
|
|
8,880 |
|
|
|
23,819 |
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
29,331 |
|
|
|
50,259 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from discontinued operations before income taxes |
|
|
12,935 |
|
|
|
(205 |
) |
|
|
|
|
|
|
|
|
|
Income tax expense (benefit) |
|
|
|
|
|
|
|
|
Current |
|
|
|
|
|
|
|
|
Deferred |
|
|
4,537 |
|
|
|
(78 |
) |
|
|
|
|
|
|
|
Total income tax expense (benefit) |
|
|
4,537 |
|
|
|
(78 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) from discontinued operations |
|
$ |
8,398 |
|
|
$ |
(127 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production: |
|
|
|
|
|
|
|
|
Natural gas (mcf) |
|
|
8,885,498 |
|
|
|
9,378,392 |
|
NGLs (bbls) |
|
|
158,843 |
|
|
|
207,662 |
|
Crude oil (bbls) |
|
|
6,988 |
|
|
|
9,577 |
|
Total (mcfe) (b) |
|
|
9,880,483 |
|
|
|
10,681,826 |
|
|
|
|
(a) |
|
Interest expense is allocated to discontinued operations based on the ratio of
the net assets of discontinued operations to our consolidated net assets plus long-term debt. |
|
(b) |
|
NGLs and oil are converted at a rate of one barrel equals six mcf. |
The carrying values of our Barnett operations are included in discontinued operations in
the accompanying consolidated balance sheets which is comprised of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2011 |
|
|
2010 |
|
Composition of assets of discontinued operations: |
|
|
|
|
|
|
|
|
Natural gas and oil properties, net |
|
$ |
827,172 |
|
|
$ |
838,044 |
|
Transportation and field assets, net |
|
|
666 |
|
|
|
684 |
|
Accounts receivable |
|
|
28,276 |
|
|
|
29,300 |
|
Unrealized derivative gain |
|
|
|
|
|
|
8,195 |
|
Inventory and other |
|
|
81 |
|
|
|
81 |
|
|
|
|
|
|
|
|
Total assets of discontinued operations |
|
$ |
856,195 |
|
|
$ |
876,304 |
|
|
|
|
|
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2011 |
|
|
2010 |
|
Composition of liabilities of discontinued operations: |
|
|
|
|
|
|
|
|
Account payable |
|
$ |
9,514 |
|
|
$ |
23,366 |
|
Accrued liabilities |
|
|
6,774 |
|
|
|
9,596 |
|
|
|
|
|
|
|
|
Total current liabilities of discontinued operations |
|
$ |
16,288 |
|
|
$ |
32,962 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations |
|
$ |
2,025 |
|
|
$ |
1,980 |
|
Other liabilities |
|
|
201 |
|
|
|
1,921 |
|
|
|
|
|
|
|
|
Total long-term liabilities of discontinued operations |
|
$ |
2,226 |
|
|
$ |
3,901 |
|
|
|
|
|
|
|
|
(6) INCOME TAXES
Income tax (benefit) expense from continuing operations was as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
March 31, |
|
|
2011 |
|
2010 |
Income tax (benefit) expense |
|
$ |
(19,897 |
) |
|
$ |
49,012 |
|
Effective tax rate |
|
|
37.3 |
% |
|
|
38.7 |
% |
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 the three months ended March 31, 2011 and 2010, our overall effective tax rate on
pre-tax income from operations was different than the statutory rate of 35% due primarily to state
income taxes, valuation allowances and other permanent differences.
9
(7) (LOSS) INCOME FROM CONTINUING OPERATIONS PER COMMON SHARE
Basic income or loss from continuing
operations per share is computed as (i) income or loss from continuing operations (ii) less income
allocable to participating securities (iii) divided by weighted average basic shares outstanding.
Diluted income or loss from continuing operations per share is computed as (i) basic income or loss from continuing operations attributable to
common shareholders (ii) plus diluted adjustments to income allocable to participating securities
(iii) divided by weighted average diluted shares outstanding. The following table sets forth a
reconciliation of income (loss) from continuing operations to basic income (loss) from continuing operations attributable to common shareholders
and to diluted income (loss) from continuing operations attributable to common shareholders and a reconciliation of basic
weighted average common shares outstanding to diluted weighted average common shares outstanding
(in thousands except per share amounts):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2011 |
|
|
2010 |
|
Numerator: |
|
|
|
|
|
|
|
|
(Loss) income from continuing operations |
|
$ |
(33,431 |
) |
|
$ |
77,706 |
|
Less: Basic income allocable to participating securities (a) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic (loss) income from continuing operations attributable to common shareholders |
|
|
(33,431 |
) |
|
|
77,706 |
|
Diluted adjustments to income allocable to participating securities (a) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted (loss) income from continuing operations attributable to common shareholders |
|
$ |
(33,431 |
) |
|
$ |
77,706 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator: |
|
|
|
|
|
|
|
|
Weighted average common shares outstanding basic |
|
|
157,545 |
|
|
|
156,393 |
|
Effect of dilutive securities: |
|
|
|
|
|
|
|
|
Employee stock options, SARs, restricted stock units and stock held in the deferred
compensation plan |
|
|
|
|
|
|
3,899 |
|
|
|
|
|
|
|
|
Weighted average common shares diluted |
|
|
157,545 |
|
|
|
160,292 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income from continuing operations per common share: |
|
|
|
|
|
|
|
|
Basic net (loss) income |
|
$ |
(0.21 |
) |
|
$ |
0.50 |
|
Diluted net (loss) income |
|
$ |
(0.21 |
) |
|
$ |
0.48 |
|
|
|
|
(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. Restricted stock awards do not participate in
undistributed net losses. |
The weighted average common shares basic for the three months ended March 31, 2011
excludes 2.9 million shares of restricted stock compared to 2.7 million shares of restricted stock
excluded at March 31, 2010 which are held in our deferred compensation plans (although all
restricted stock is issued and outstanding upon grant). Due to our loss from continuing operations for
the three months ended March 31, 2011, we excluded all outstanding stock options, stock appreciation
rights (SARs) and restricted stock from computations of diluted net income per share because the
effect would have been anti-dilutive to the computations. SARs of 1.1 million for the three months
ended March 31, 2010 were outstanding but not included in the computations of diluted income from continuing operations
per share because the grant prices of the SARs were greater than the average market price of the
common shares.
10
(8) SUSPENDED EXPLORATORY WELL COSTS
The following table reflects the changes in capitalized exploratory well costs for the three
months ended March 31, 2011 and the year ended December 31, 2010 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2011 |
|
|
2010 |
|
Beginning balance at January 1 |
|
$ |
23,908 |
|
|
$ |
19,052 |
|
Additions to capitalized exploratory well costs pending the determination of proved
reserves |
|
|
15,329 |
|
|
|
28,897 |
|
Reclassifications based on determination of proved reserves |
|
|
(11,619 |
) |
|
|
(24,041 |
) |
Capitalized exploratory well costs charged to expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at end of period |
|
|
27,618 |
|
|
|
23,908 |
|
Less exploratory well costs that have been capitalized for a period of one year or less |
|
|
(22,388 |
) |
|
|
(13,181 |
) |
|
|
|
|
|
|
|
Capitalized exploratory well costs that have been capitalized for a period greater than
one year |
|
$ |
5,230 |
|
|
$ |
10,727 |
|
|
|
|
|
|
|
|
Number of projects that have exploratory well costs that have been capitalized for a
period greater than one year |
|
|
3 |
|
|
|
4 |
|
|
|
|
|
|
|
|
As of March 31, 2011 the $5.2 million of capitalized exploratory well costs that have been
capitalized for more than one year, all are Marcellus Shale wells and are waiting on the completion
of pipelines. The following provides an aging of capitalized exploratory well costs that have been
suspended for more than one year as of March 31, 2011 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
2011 |
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
Capitalized
exploratory well
costs that have
been capitalized
for more than one
year |
|
$ |
5,230 |
|
|
$ |
252 |
|
|
$ |
334 |
|
|
$ |
3,065 |
|
|
$ |
1,579 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(9) INDEBTEDNESS
We had the following debt outstanding as of the dates shown below (in thousands) (bank debt
interest rate at March 31, 2011 is shown parenthetically). No interest expense was capitalized
during the three months ended March 31, 2011 and 2010.
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2011 |
|
|
2010 |
|
Bank debt (1.9%) |
|
$ |
480,000 |
|
|
$ |
274,000 |
|
|
|
|
|
|
|
|
|
|
Subordinated debt: |
|
|
|
|
|
|
|
|
6.375% Senior Subordinated Notes due 2015 |
|
|
150,000 |
|
|
|
150,000 |
|
7.5% Senior Subordinated Notes due 2016, net of discount |
|
|
249,695 |
|
|
|
249,683 |
|
7.5% Senior Subordinated Notes due 2017 |
|
|
250,000 |
|
|
|
250,000 |
|
7.25% Senior Subordinated Notes due 2018 |
|
|
250,000 |
|
|
|
250,000 |
|
8.0% Senior Subordinated Notes due 2019, net of discount |
|
|
287,121 |
|
|
|
286,853 |
|
6.75% Senior Subordinated Notes due 2020 |
|
|
500,000 |
|
|
|
500,000 |
|
|
|
|
|
|
|
|
Total debt |
|
$ |
2,166,816 |
|
|
$ |
1,960,536 |
|
|
|
|
|
|
|
|
11
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. Our new borrowing base was set without our Barnett shale assets, which are presented as held for sale at March 31, 2011.
The bank credit facility provides for an initial commitment equal to the lesser of the facility amount or the borrowing base. On March 31, 2011,
the borrowing base was $2.0 billion and our facility amount was $1.5 billion. The bank credit
facility provides for a borrowing base subject to redeterminations semi-annually and for
event-driven unscheduled redeterminations. Our current bank group is comprised of twenty-seven
commercial banks, with no one bank holding more than 7% of the total facility. The facility amount
may be increased up to the borrowing base amount with twenty days notice, subject to payment of a
mutually acceptable commitment fee to those banks agreeing to participate in the facility amount
increase. At March 31, 2011, the outstanding balance under the bank credit facility was $480.0
million and we had $8.3 million of undrawn letters of credit leaving $1.0 billion of borrowing
capacity available under the facility amount. The loan matures in February 2016. Borrowing under
the bank credit facility can either be the Alternate Base Rate (as defined) plus a spread ranging
from 0.50% to 1.50% or LIBOR borrowings at the Adjusted LIBO Rate (as defined) plus a spread
ranging from 1.50% to 2.50%. 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 part of the base rate loans to LIBOR loans. The weighted
average interest rate on the bank credit facility was 2.3% for the three months ended March 31,
2011 compared to 2.1% for the three months ended March 31, 2010. A commitment fee is paid on the
undrawn balance based on an annual rate of between 0.375% and 0.50%. At March 31, 2011, 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.
Debt Covenants
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 were in compliance with our covenants under the bank
credit facility at March 31, 2011.
The indentures governing our senior subordinated notes contain various restrictive covenants
that are substantially identical to each other and may limit our ability to, among other things,
pay cash dividends, incur additional indebtedness, sell assets, enter into transactions with
affiliates or change the nature of our business. At March 31, 2011, we were in compliance with
these covenants.
(10) ASSET RETIREMENT OBLIGATIONS
Our asset retirement obligations primarily represent the estimated present value of
the amount 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. A
reconciliation of our liability for plugging, abandonment and remediation costs for the three
months ended March 31, 2011 is as follows (in thousands):
|
|
|
|
|
|
|
Three Months |
|
|
|
Ended |
|
|
|
March 31, |
|
|
|
2011 |
|
Beginning of period |
|
$ |
62,673 |
|
Liabilities incurred |
|
|
699 |
|
Liabilities settled |
|
|
(622 |
) |
Liabilities reclassified to discontinued operations |
|
|
(2,025 |
) |
Accretion expense continuing operations |
|
|
1,193 |
|
Accretion expense discontinued operations |
|
|
45 |
|
Change in estimate |
|
|
1,584 |
|
|
|
|
|
End of period |
|
$ |
63,547 |
|
|
|
|
|
Accretion expense is recognized as a component of depreciation, depletion and amortization
expense on our consolidated statements of operations.
12
(11) CAPITAL STOCK
We have authorized capital stock of 485 million shares, which includes 475 million shares of
common stock and 10 million shares of preferred stock. The following is a summary of changes in
the number of common shares outstanding since the beginning of 2010:
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Year |
|
|
|
Ended |
|
|
Ended |
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2011 |
|
|
2010 |
|
Beginning balance |
|
|
159,909,052 |
|
|
|
158,118,937 |
|
Stock options/SARs exercised |
|
|
439,558 |
|
|
|
991,988 |
|
Restricted stock grants |
|
|
115,130 |
|
|
|
405,127 |
|
Treasury shares issued |
|
|
8,540 |
|
|
|
12,771 |
|
Shares issued for acreage purchases |
|
|
|
|
|
|
380,229 |
|
|
|
|
|
|
|
|
Ending balance |
|
|
160,472,280 |
|
|
|
159,909,052 |
|
|
|
|
|
|
|
|
Treasury Stock
The Board of Directors has approved up to $10.0 million of repurchases of common stock based
on market conditions and opportunities and on March 31, 2011, we have $6.8 million remaining under
this authorization.
(12) DERIVATIVE ACTIVITIES
We use commoditybased 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 such as swaptions, knockouts or extendable swaps. We typically
utilize commodity swap, collar or call option contracts 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. Historically, our derivative activities have consisted of collars and fixed
price swaps. At March 31, 2011, we had open swap contracts covering 25.6 Bcf of natural gas at
prices averaging $5.00 per mcf and 1.5 million barrels of NGLs at prices averaging $101.88 per
barrel. At March 31, 2011, we had collars covering 195.3 Bcf of natural gas at weighted average
floor and cap prices of $5.42 to $6.27 per mcf and 0.7 million barrels of oil at weighted average
floor and cap prices of $70.00 to $80.00 per barrel. At March 31, 2011, we also had sold call
options for 3.2 million barrels of oil at a weighted average price of $82.66. In first quarter
2011, we entered into NGL derivative swap contracts for the natural gasoline (or C5) component of
natural gas liquids. The fair value of these commodity derivatives, represented by the estimated
amount that would be realized upon termination, based on a comparison of the contract prices and a
reference price, generally New York Mercantile Exchange (NYMEX), on March 31, 2011, was a net
unrealized pre-tax gain of $31.4 million. These contracts expire monthly through December 2013.
The following table sets forth our derivative volumes and average hedge prices as of March 31,
2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
Period |
|
Contract Type |
|
Volume Hedged |
|
Hedge Price |
Natural Gas |
|
|
|
|
|
|
2012
|
|
Swaps
|
|
70,192 Mmbtu/day
|
|
$5.00 |
2011
|
|
Collars
|
|
418,236 Mmbtu/day
|
|
$5.52-$6.45 |
2012
|
|
Collars
|
|
119,641 Mmbtu/day
|
|
$5.50-$6.25 |
2013
|
|
Collars
|
|
100,000 Mmbtu/day
|
|
$5.00-$5.73 |
|
|
|
|
|
|
|
Crude Oil |
|
|
|
|
|
|
2012
|
|
Collars
|
|
2,000 bbls/day
|
|
$70.00-$80.00 |
2011
|
|
Call options
|
|
5,500 bbls/day
|
|
$80.00 |
2012
|
|
Call options
|
|
4,700 bbls/day
|
|
$85.00 |
|
|
|
|
|
|
|
NGLs |
|
|
|
|
|
|
2011
|
|
Swaps
|
|
2,676 bbls/day
|
|
$102.80 |
2012
|
|
Swaps
|
|
2,000 bbls/day
|
|
$100.96 |
13
Every derivative instrument is recorded on the accompanying balance sheets as either an asset
or a liability measured at its fair value. Fair value is generally determined based on the
difference between the fixed contract price and the underlying market price at the determination
date. Changes in the fair value of derivatives that qualify for hedge accounting are recorded
as a component of accumulated other comprehensive income (AOCI) in the stockholders equity
section of the accompanying consolidated balance sheets, which is later transferred to natural gas,
NGL and oil sales when the underlying physical transaction occurs and the hedging contract is
settled. Amounts included in AOCI at March 31, 2011 and December 31, 2010 relate solely to our
commodity derivative activities. As of March 31, 2011, an unrealized pre-tax derivative gain of
$69.9 million was recorded in AOCI. This gain is expected to be reclassified into earnings as a
$68.6 million gain in 2011, a $4.3 million gain in 2012 and a $2.9 million loss in 2013. The
actual reclassification to earnings will be based on market prices at the contract settlement date.
For those derivative instruments that qualify for hedge accounting, settled transaction gains
and losses are determined monthly, and are included as increases or decreases to natural gas, NGL
and oil sales in the period the hedged production is sold. Natural gas, NGL and oil sales include
$29.6 million of gains in the three months ended March 31, 2011 compared to gains of $1.2 million
in the same period of 2010 related to settled hedging transactions. Any ineffectiveness associated
with these hedge derivatives is included in derivative fair value income (loss) in the accompanying
consolidated statements of operations. The ineffective portion is calculated as the difference
between the change in fair value of the derivative and the estimated change in future cash flows
from the item hedged. The three months ended March 31, 2011 includes ineffective gains (unrealized
and realized) of $1.5 million compared to losses of $606,000 in the same period of 2010.
Through March 31, 2011, we have elected to designate our commodity derivative instruments that
qualify for hedge accounting as cash flow hedges. To designate a derivative as a cash flow hedge,
we document at the hedges inception our assessment that the derivative will be highly effective in
offsetting expected changes in cash flows from the item hedged. This assessment, which is updated
at least quarterly, is generally based on the most recent relevant historical correlation between
the derivative and the item hedged. The ineffective portion of the hedge is calculated as the
difference between the change in fair value of the derivative and the estimated change in cash
flows from the item hedged. If, during the derivatives term, we determine the hedge is no longer
highly effective, hedge accounting is prospectively discontinued and any remaining unrealized gains
or losses, based on the effective portion of the derivative at that date, are reclassified to
earnings as natural gas, NGL and oil sales when the underlying transaction occurs. If it is
determined that the designated hedge transaction is not probable to occur, any unrealized gains or
losses are recognized immediately in derivative fair value income (loss) in the accompanying
consolidated statements of operations. During the first three months of 2011 or 2010 there were no
gains or losses recorded due to the discontinuance of hedge accounting treatment for these
derivatives.
Some of our derivatives do not qualify for hedge accounting or are not designated as a hedge
but provide an economic hedge of our exposure to commodity price risk associated with anticipated
future natural gas and oil production. These contracts are accounted for using the mark-to-market
accounting method. We recognize all unrealized and realized gains and losses related to these
contracts in derivative fair value (loss) income in the accompanying consolidated statements of
operations (for additional information see table below).
Derivative Fair Value (Loss) Income
The following table presents information about the components of derivative fair
value (loss) income in the three months ended March 31, 2011 and 2010 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2011 |
|
|
2010 |
|
Hedge ineffectiveness realized |
|
$ |
946 |
|
|
$ |
(357 |
) |
unrealized |
|
|
568 |
|
|
|
(249 |
) |
Change in fair value of derivatives that do
not qualify for hedge accounting(a) |
|
|
(40,036 |
) |
|
|
46,578 |
|
Realized loss on settlements gas(a) (b) |
|
|
(394 |
) |
|
|
(3,639 |
) |
Realized loss on settlements oil (a) (b) |
|
|
(1,918 |
) |
|
|
|
|
|
|
|
|
|
|
|
Derivative fair value (loss) income |
|
$ |
(40,834 |
) |
|
$ |
42,333 |
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Derivatives that do not qualify for hedge accounting. |
|
(b) |
|
These amounts represent the realized losses on settled derivatives that do not qualify
for hedge accounting, which before settlement are included in the category described above
called change in fair value of derivatives that do not qualify for hedge accounting. |
14
The combined fair value of derivatives included in the accompanying consolidated balance
sheets as of March 31, 2011 and December 31, 2010 is summarized below (in thousands). We conduct
commodity derivative activities with nine financial institutions, all of which are secured lenders
in our bank credit facility. We believe all of these institutions are acceptable credit risks. At
times, such risks may be concentrated with certain counterparties. The credit worthiness of our
counterparties is subject to periodic review. In our accompanying consolidated balance sheets,
derivative assets and liabilities are netted where derivatives with both gain and loss positions
are held by a single counterparty.
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2011 |
|
|
2010 |
|
Derivative assets: |
|
|
|
|
|
|
|
|
Natural gas collars |
|
$ |
122,843 |
|
|
$ |
163,354 |
|
swaps |
|
|
(524 |
) |
|
|
|
|
Crude oil collars |
|
|
(5,172 |
) |
|
|
|
|
call options |
|
|
(53,799 |
) |
|
|
(31,904 |
) |
NGL swaps |
|
|
(1,062 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
62,286 |
|
|
$ |
131,450 |
|
|
|
|
|
|
|
|
Derivative liabilities: |
|
|
|
|
|
|
|
|
Natural gas collars |
|
$ |
18,015 |
|
|
$ |
27,032 |
|
basis swaps |
|
|
|
|
|
|
(352 |
) |
swaps |
|
|
(881 |
) |
|
|
|
|
Crude oil collars |
|
|
(14,866 |
) |
|
|
(12,051 |
) |
call options |
|
|
(32,301 |
) |
|
|
(28,393 |
) |
NGL swaps |
|
|
(802 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(30,835 |
) |
|
$ |
(13,764 |
) |
|
|
|
|
|
|
|
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 our accompanying consolidated balance sheets (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2011 |
|
|
December 31, 2010 |
|
|
|
Assets |
|
|
(Liabilities) |
|
|
|
|
|
Assets |
|
|
(Liabilities) |
|
|
|
|
|
|
Carrying |
|
|
Carrying |
|
|
Net
Carrying |
|
|
Carrying |
|
|
Carrying |
|
|
Net Carrying |
|
|
|
Value |
|
|
Value |
|
|
Value |
|
|
Value |
|
|
Value |
|
|
Value |
|
Derivatives that qualify for
cash flow hedge accounting: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swaps (1) |
|
$ |
|
|
|
$ |
(1,405 |
) |
|
$ |
(1,405 |
) |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Collars(1) |
|
|
136,578 |
|
|
|
(3,390 |
) |
|
|
133,188 |
|
|
|
173,128 |
|
|
|
|
|
|
|
173,128 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
136,578 |
|
|
$ |
(4,795 |
) |
|
$ |
131,783 |
|
|
$ |
173,128 |
|
|
$ |
|
|
|
$ |
173,128 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives that do not qualify
for hedge accounting: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swaps (1) |
|
$ |
|
|
|
$ |
(1,864 |
) |
|
$ |
(1,864 |
) |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Collars(1) |
|
|
7,844 |
|
|
|
(20,211 |
) |
|
|
(12,367 |
) |
|
|
17,259 |
|
|
|
(12,052 |
) |
|
|
5,207 |
|
Call options(1) |
|
|
|
|
|
|
(86,101 |
) |
|
|
(86,101 |
) |
|
|
|
|
|
|
(60,297 |
) |
|
|
(60,297 |
) |
Basis swaps(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(352 |
) |
|
|
(352 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
7,844 |
|
|
$ |
(108,176 |
) |
|
$ |
(100,332 |
) |
|
$ |
17,259 |
|
|
$ |
(72,701 |
) |
|
$ |
(55,442 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Included in unrealized derivative gain or loss in the accompanying consolidated
balance sheets. |
15
The effects of our cash flow hedges (or those derivatives that qualify for hedge
accounting) on accumulated other comprehensive income (loss) included in the accompanying
consolidated balance sheets are summarized below (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
|
|
|
|
|
|
|
|
Realized Gain |
|
|
|
Change in Hedge |
|
|
Reclassified from AOCI |
|
|
|
Derivative Fair Value |
|
|
into Revenue (a) |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
Swaps |
|
$ |
(2,540 |
) |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Collars |
|
|
(387 |
) |
|
|
84,811 |
|
|
|
38,223 |
|
|
|
1,215 |
|
Income taxes |
|
|
3,040 |
|
|
|
(32,229 |
) |
|
|
(14,334 |
) |
|
|
(462 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
113 |
|
|
$ |
52,582 |
|
|
$ |
23,889 |
|
|
$ |
753 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
For realized gains upon contract settlement, the reduction in AOCI is offset by an
increase in natural gas, NGL and oil sales. For realized losses upon contract settlement, the
increase in AOCI is offset by a decrease in natural gas, NGL and oil sales. |
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 included in the accompanying
consolidated statements of operations are summarized below (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
Gain (Loss) Recognized in |
|
|
Gain Recognized in Income |
|
|
Derivative Fair Value |
|
|
|
Income (Non-hedge Derivatives) |
|
|
(Ineffective Portion) |
|
|
(Loss) Income |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
Swaps |
|
$ |
(1,864 |
) |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
(1,864 |
) |
|
$ |
|
|
Collars |
|
|
(7,586 |
) |
|
|
46,956 |
|
|
|
1,514 |
|
|
|
(606 |
) |
|
|
(6,072 |
) |
|
|
46,350 |
|
Call options |
|
|
(32,855 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(32,855 |
) |
|
|
|
|
Basis swaps |
|
|
(43 |
) |
|
|
(4,017 |
) |
|
|
|
|
|
|
|
|
|
|
(43 |
) |
|
|
(4,017 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
(42,348 |
) |
|
$ |
42,939 |
|
|
$ |
1,514 |
|
|
$ |
(606 |
) |
|
$ |
(40,834 |
) |
|
$ |
42,333 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(13) 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 managements best estimate of fair
value. |
16
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.
Fair Values-Recurring
We use a market approach for our fair value measurements and endeavor to use the best
information available. Accordingly, valuation techniques that maximize the use of observable
impacts are favored. The following presents the fair value hierarchy table for assets and
liabilities measured at fair value, on a recurring basis (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at March 31, 2011 Using: |
|
|
|
|
Quoted Prices in |
|
Significant |
|
|
|
|
|
Total |
|
|
Active Markets |
|
Other |
|
Significant |
|
Carrying |
|
|
for Identical |
|
Observable |
|
Unobservable |
|
Value as of |
|
|
Assets |
|
Inputs |
|
Inputs |
|
March 31, |
|
|
(Level 1) |
|
(Level 2) |
|
(Level 3) |
|
2011 |
Trading securities
held in our
deferred
compensation plans |
|
$ |
52,682 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
52,682 |
|
Derivatives swaps |
|
|
|
|
|
|
(3,269 |
) |
|
|
|
|
|
|
(3,269 |
) |
collars |
|
|
|
|
|
|
120,821 |
|
|
|
|
|
|
|
120,821 |
|
call options |
|
|
|
|
|
|
(86,101 |
) |
|
|
|
|
|
|
(86,101 |
) |
Our trading securities in Level 1 are exchange-traded and measured at fair value with a market
approach using March 31, 2011 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 our 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/losses
are included in deferred compensation plan expense in our consolidated statements of operations.
For the three months ended March 31, 2011, interest and dividends were $35,000 and mark-to-market
was a gain of $1.3 million. For the three months ended March 31, 2010, interest and dividends were
$32,000 and mark-to-market was a gain of $596,000. For additional information on the
accounting for our deferred compensation plan, see Note 14.
Fair Values-Nonrecurring
We review our long-lived assets to be held and used, including proved natural gas and oil
properties, whenever events or circumstances indicate the carrying value of those assets may not be
recoverable. Several long-lived assets held for use were evaluated for impairment during 2010 due
to reductions in estimated reserves and natural gas prices. The fair value of our onshore Gulf
Coast assets in 2010 was measured using an income approach based upon internal estimates of future
production levels, prices, drilling and operating costs and discount rates, which are Level 3
inputs. Our projected undiscounted cash flows associated with these assets was less than their
carrying value and therefore, we recorded an impairment of $6.5 million in 2010 related to our
onshore Gulf Coast proved properties.
The following table presents the value of these assets measured at fair value on a
nonrecurring basis (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2011 |
|
2010 |
|
|
|
|
|
|
|
|
|
|
Fair |
|
|
|
|
Fair Value |
|
Impairment |
|
Value |
|
Impairment |
Natural gas and oil properties |
|
$ |
|
|
|
$ |
|
|
|
$ |
16,075 |
|
|
$ |
6,505 |
|
17
Fair Values-Reported
The following table presents the carrying amounts and the fair values of our financial
instruments as of March 31, 2011 and December 31, 2010 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2011 |
|
December 31, 2010 |
|
|
Carrying |
|
Fair |
|
Carrying |
|
Fair |
|
|
Value |
|
Value |
|
Value |
|
Value |
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity swaps, collars, call options and basis swaps |
|
$ |
62,286 |
|
|
$ |
62,286 |
|
|
$ |
131,450 |
|
|
$ |
131,450 |
|
Marketable securities(a) |
|
|
52,682 |
|
|
|
52,682 |
|
|
|
47,794 |
|
|
|
47,794 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity swaps, collars, call options and basis swaps |
|
|
(30,835 |
) |
|
|
(30,835 |
) |
|
|
(13,764 |
) |
|
|
(13,764 |
) |
Bank credit facility (b) |
|
|
(480,000 |
) |
|
|
(480,000 |
) |
|
|
(274,000 |
) |
|
|
(274,000 |
) |
6.375% senior subordinated notes due 2015 (b) |
|
|
(150,000 |
) |
|
|
(153,000 |
) |
|
|
(150,000 |
) |
|
|
(153,000 |
) |
7.5% senior subordinated notes due 2016 (b) |
|
|
(249,695 |
) |
|
|
(259,375 |
) |
|
|
(249,683 |
) |
|
|
(259,375 |
) |
7.5% senior subordinated notes due 2017 (b) |
|
|
(250,000 |
) |
|
|
(266,250 |
) |
|
|
(250,000 |
) |
|
|
(263,438 |
) |
7.25% senior subordinated notes due 2018 (b) |
|
|
(250,000 |
) |
|
|
(267,500 |
) |
|
|
(250,000 |
) |
|
|
(263,750 |
) |
8.0% senior subordinated notes due 2019 (b) |
|
|
(287,121 |
) |
|
|
(330,750 |
) |
|
|
(286,853 |
) |
|
|
(326,625 |
) |
6.75% senior subordinated notes due 2020 (b) |
|
|
(500,000 |
) |
|
|
(532,500 |
) |
|
|
(500,000 |
) |
|
|
(515,625 |
) |
|
|
|
(a) |
|
Marketable securities are held in our deferred compensation plans. |
|
(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. |
Concentration of Credit Risk
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 risk of loss. Our allowance for uncollectible receivables was $4.3 million at
March 31, 2011 and $5.0 million at December 31, 2010. Commodity-based contracts expose us to the
credit risk of nonperformance by the counterparty to the contracts. As of March 31, 2011, these
contracts consist of swaps, collars and call options. This exposure is diversified among major
investment grade financial institutions and we have master netting agreements with the
counterparties that provide for offsetting payables against receivables from separate derivative
contracts. Our derivative counterparties include nine financial institutions, all of which are
secured lenders in our bank credit facility. Our natural gas and oil properties provide collateral under our
credit facility and our derivative exposure. None of our derivative contracts have margin
requirements or collateral provisions that would require funding prior to the scheduled cash
settlement date.
(14) EMPLOYEE BENEFIT AND EQUITY PLANS
We have two active equity-based stock plans. Under these plans, incentive and
non-qualified stock options, SARs, restricted stock, restricted stock units, phantom stock and
various other awards may be issued to employees and directors pursuant to decisions of the
Compensation Committee, which is made up of non-employee, independent directors from the Board of
Directors. All awards granted have been issued at prevailing market prices at the time of the
grant. Information with respect to stock option/SARs activity is summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
Average |
|
|
|
|
|
|
|
Exercise |
|
|
|
Shares |
|
|
Price |
|
Outstanding at December 31, 2010 |
|
|
6,461,839 |
|
|
$ |
37.20 |
|
Granted |
|
|
317,451 |
|
|
|
49.18 |
|
Exercised |
|
|
(1,169,831 |
) |
|
|
26.63 |
|
Expired/forfeited |
|
|
(147,375 |
) |
|
|
55.94 |
|
|
|
|
|
|
|
|
Outstanding at March 31, 2011 |
|
|
5,462,084 |
|
|
$ |
39.65 |
|
|
|
|
|
|
|
|
18
The weighted average fair value of a
SAR to purchase one share of common stock granted during
2011 was $17.60. The fair value of each SAR granted during 2011 was estimated as of the date of
grant using the Black-Scholes-Merton option-pricing model based on the following average
assumptions: risk-free interest rate of 1.7%; dividend yield of 0.3%; expected volatility of 47% and an expected life of 3.6 years. Of the 5.5 million stock option/SARs
outstanding at March 31, 2011, 671,000 are stock options and 4.8 million are SARs.
Equity Awards-Restricted Stock Units
Beginning in first quarter 2011, the compensation committee began granting restricted stock
units under our equity-based stock plans. These restricted stock units 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 employees continued employment with us. Net shares
will be issued to employees as the restricted stock units vest. A summary of the outstanding
restricted stock unit awards at March 31, 2011 is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
Average |
|
|
|
|
|
|
|
Grant Date |
|
|
|
Shares |
|
|
Fair Value |
|
Outstanding at December 31, 2010 |
|
|
|
|
|
$ |
|
|
Granted |
|
|
297,349 |
|
|
|
49.18 |
|
Exercised |
|
|
(1,054 |
) |
|
|
49.18 |
|
Expired/forfeited |
|
|
(2,555 |
) |
|
|
49.18 |
|
|
|
|
|
|
|
|
Outstanding at March 31, 2011 |
|
|
293,740 |
|
|
$ |
49.18 |
|
|
|
|
|
|
|
|
Liability Awards-Restricted Stock
These restricted stock shares are placed into our deferred compensation plan when granted.
During the first three months of 2011, 130,000 shares of restricted stock (or non-vested shares)
were issued to certain employees at an average price of $49.14 with a three-year vesting period.
In the first three months of 2010, we issued 172,000 shares of restricted stock as compensation to
employees at an average price of $46.45 with a three-year vesting period. All restricted stock
awards held in our deferred compensation plans are classified as a liability award and remeasured
at fair value each reporting period. This mark-to-market is included in deferred compensation plan
expense in our accompanying consolidated statements of operations (see additional discussion
below). All awards granted have been issued at prevailing market prices at the time of the grant
and the vesting of these shares is based upon an employees continued employment with us.
19
A summary of the status of our non-vested restricted stock outstanding at March 31, 2011 is
presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
Average Grant Date |
|
|
|
Shares |
|
|
Fair Value |
|
Non-vested restricted stock outstanding at December 31, 2010 |
|
|
582,751 |
|
|
$ |
44.81 |
|
Granted |
|
|
129,602 |
|
|
|
49.14 |
|
Vested |
|
|
(101,300 |
) |
|
|
46.47 |
|
Forfeited |
|
|
(4,268 |
) |
|
|
40.63 |
|
|
|
|
|
|
|
|
Non-vested restricted stock outstanding at March 31, 2011 |
|
|
606,785 |
|
|
$ |
45.48 |
|
|
|
|
|
|
|
|
Deferred Compensation Plan
Our deferred compensation plan gives directors, officers and key employees the ability to
defer all or a portion of their salaries and bonuses and invest such amounts in Range common stock
or make other investments at the individuals discretion. The assets of the plan are held in a
grantor trust, which we refer to as the Rabbi Trust, and are therefore available to satisfy the
claims of our creditors in the event of bankruptcy. Our stock granted and held in the Rabbi Trust
is treated as a liability award as employees are allowed to take withdrawals either in cash or in
Range stock. The liability associated with the vested portion of the stock 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 Range common
stock, are invested in marketable securities and reported at market value in other assets in the
accompanying consolidated balance sheets. Changes in the market value of the marketable securities
are charged or credited to deferred compensation plan expense each quarter. The deferred
compensation liability included in our consolidated balance sheets reflects the vested market value
of the marketable securities and Range common stock held in the Rabbi Trust. We recorded non-cash,
mark-to-market expense related to our deferred compensation plan of $30.6 million in the three
months ended March 31, 2011 compared to income of $5.7 million in the same period of 2010.
(15) SUPPLEMENTAL CASH FLOW INFORMATION
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
March 31, |
|
|
2011 |
|
2010 |
|
|
(in thousands) |
Non-cash investing and financing activities included: |
|
|
|
|
|
|
|
|
Asset retirement costs capitalized, net |
|
$ |
2,284 |
|
|
$ |
376 |
|
Unproved property purchased with stock(a) |
|
$ |
|
|
|
$ |
20,000 |
|
Net cash provided from operating activities included: |
|
|
|
|
|
|
|
|
Interest paid |
|
$ |
24,240 |
|
|
$ |
15,625 |
|
Income taxes paid (refunded) |
|
$ |
300 |
|
|
$ |
(1,684 |
) |
|
|
|
(a) |
|
Three months ended March 31, 2010 included shares that were issued in
January 2010 while the value was accrued and included in costs incurred for the year
ended December 31, 2009. |
(16) COMMITMENTS AND CONTINGENCIES
Litigation
We are involved in various legal actions and claims arising in the ordinary course of our
business. While the outcome of these lawsuits cannot be predicted with certainty, we do not expect
these matters to have a material adverse effect on our financial position, cash flows or results of
operations.
Transportation
Contracts
During
the first quarter 2011, we entered into additional transportation
agreement in Appalachia which total approximately $100.0 million over
the next seven years.
20
(17) CAPITALIZED COSTS AND ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION(a)
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2011 |
|
|
2010 |
|
|
|
(in thousands) |
|
Natural gas and oil properties: |
|
|
|
|
|
|
|
|
Properties subject to depletion |
|
$ |
5,023,170 |
|
|
$ |
4,742,248 |
|
Unproved properties |
|
|
646,621 |
|
|
|
648,143 |
|
|
|
|
|
|
|
|
Total |
|
|
5,669,791 |
|
|
|
5,390,391 |
|
Accumulated depreciation, depletion and amortization |
|
|
(1,373,652 |
) |
|
|
(1,306,378 |
) |
|
|
|
|
|
|
|
Net capitalized costs |
|
$ |
4,296,139 |
|
|
$ |
4,084,013 |
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Includes capitalized asset retirement costs and associated accumulated
amortization. |
(18) COSTS INCURRED FOR PROPERTY ACQUISITIONS, EXPLORATION AND DEVELOPMENT(a)
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Year |
|
|
|
Ended |
|
|
Ended |
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2011 |
|
|
2010 |
|
|
|
(in thousands) |
|
Acquisitions: |
|
|
|
|
|
|
|
|
Unproved leasehold |
|
$ |
|
|
|
$ |
3,697 |
|
Proved properties |
|
|
|
|
|
|
130,767 |
|
Asset retirement obligations |
|
|
|
|
|
|
556 |
|
Acreage purchases |
|
|
18,816 |
|
|
|
166,677 |
|
Development |
|
|
237,954 |
|
|
|
784,153 |
|
Exploration: |
|
|
|
|
|
|
|
|
Drilling |
|
|
29,441 |
|
|
|
50,737 |
|
Expense |
|
|
25,890 |
|
|
|
56,879 |
|
Stock-based compensation expense |
|
|
1,329 |
|
|
|
4,209 |
|
Gas gathering facilities: |
|
|
|
|
|
|
|
|
Development |
|
|
5,610 |
|
|
|
20,726 |
|
|
|
|
|
|
|
|
Subtotal |
|
|
319,040 |
|
|
|
1,218,401 |
|
Asset retirement obligations |
|
|
2,284 |
|
|
|
(6,523 |
) |
|
|
|
|
|
|
|
Total costs incurred |
|
$ |
321,324 |
|
|
$ |
1,211,878 |
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Includes costs incurred whether capitalized or expensed and
include our Barnett operations. |
21
(19) OFFICE CLOSING AND EXIT ACTIVITIES
In February 2010, we
entered into an agreement to sell our natural gas properties in Ohio.
We closed approximately 90% of the sale in March 2010 and closed the remainder of the sale in June
2010. The first quarter 2010 includes $5.1 million accrued severance costs, which is reflected in
termination costs in the accompanying consolidated statements of operations. As part of their
severance agreement, our Ohio employees vesting of SARs and restricted stock grants was
accelerated, increasing termination costs for stock compensation expense in first quarter 2010 by
approximately $2.8 million.
The following table details our exit activities, which are included in accrued liabilities in
the accompanying consolidated balance sheets as of March 31, 2011 and December 31, 2010 (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Year |
|
|
|
Ended |
|
|
Ended |
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2011 |
|
|
2010 |
|
|
|
(in thousands) |
|
Balance at beginning of period |
|
$ |
1,092 |
|
|
$ |
1,568 |
|
Accrued one-time termination costs |
|
|
|
|
|
|
5,138 |
|
Office lease |
|
|
|
|
|
|
514 |
|
Payments |
|
|
(323 |
) |
|
|
(6,128 |
) |
|
|
|
|
|
|
|
Balance at end of period |
|
$ |
769 |
|
|
$ |
1,092 |
|
|
|
|
|
|
|
|
22
ITEM 2. MANAGEMENTS 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 Managements
Discussion and Analysis of Financial Condition and Results of Operations include forward-looking
statements concerning trends or events potentially affecting our business. These statements
typically contain words such as anticipates, believes, estimates, expects, targets,
plans, 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 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 as and 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, 2010 filed with the
SEC on March 1, 2011.
Critical Accounting Estimates and Policies
The preparation of financial statements in accordance with generally accepted accounting
principles requires us to make estimates and assumptions that affect the reported amounts of assets
and liabilities and the disclosure of contingent assets and liabilities as of the date of the
consolidated financial statements and the reported amounts of revenues and expenses during the
respective reporting periods. Actual results could differ from the estimates and assumptions used.
These policies and estimates are described in our Annual Report on Form 10-K for the year ended
December 31, 2010. We have identified the following critical accounting policies and estimates
used in the preparation of our financial statements: accounting for natural gas, NGL and oil
revenue, natural gas and oil properties, stock-based compensation, derivative financial
instruments, asset retirement obligations and deferred income taxes.
Market Conditions
Prices for various quantities of natural gas, natural gas liquids (NGLs) and oil that we
produce significantly impact our revenues and cash flows. Commodity prices have been volatile in
recent years. The following table lists average New York Mercantile Exchange (NYMEX) prices for
natural gas and oil for the three months ended March 31, 2011 and 2010.
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2011 |
|
|
2010 |
|
Average NYMEX prices(a) |
|
|
|
|
|
|
|
|
Natural gas (per mcf) |
|
$ |
4.12 |
|
|
$ |
5.37 |
|
Oil (per bbl) |
|
$ |
94.67 |
|
|
$ |
78.82 |
|
|
|
|
(a) |
|
Based on average of bid week prompt month prices. |
Consolidated Results of Operations
Overview
We are an independent natural gas and oil company engaged in the exploration, development and
acquisition of natural gas and oil properties, mostly in the Appalachia and Southwest regions
of the United States. 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 and oil and on our ability to economically find,
develop, acquire and produce natural gas and oil reserves. We use the successful efforts method of
accounting for our natural gas, NGLs and oil activities. Our corporate headquarters is located in
Fort Worth, Texas.
23
Discontinued operations
consists of
our Barnett Shale properties which are reported as
discontinued operations as of March 31, 2011. Unless otherwise indicated, the information included
herein relates to our continuing operations.
During the first three months of 2011, we achieved the following financial and operating
results:
|
|
|
recorded our 33rd consecutive quarter of sequential production growth; |
|
|
|
|
achieved 26% year-over-year production growth; |
|
|
|
|
daily production now exceeds 435.0 mmcfe per day; |
|
|
|
|
natural gas, NGL and oil sales increased 21% from first quarter 2010; |
|
|
|
|
reduced our DD&A rate 12% from first quarter 2010; |
|
|
|
|
year-over-year direct operating expense per mcfe increased 4% while production
and ad valorem tax expense per mcfe declined 14% and general and administrative expense per mcfe
declined 3%; |
|
|
|
|
entered into additional commodity derivative contracts for 2011, 2012 and 2013; and |
|
|
|
|
renewed our bank credit facility, with a borrowing base of $2.0 billion. |
Total
revenues decreased $110.8 million, or 37% for first quarter 2011 over the same period of
2010. The decrease includes a $39.2 million increase in natural gas, NGL and oil sales offset by a
decrease in derivative fair value income (loss) of $83.2 million and a lower gain on sale of assets
of $67.8 million. Natural gas, NGL and oil sales vary due to changes in volumes of production sold
and realized commodity prices. Realized prices declined
from the same period of the prior year, which was more than offset by an increase in production,
including a 81% increase in NGL production primarily due to increased liquids-rich production in
our Appalachia area. For first quarter 2011, production increased 26% from the same period of the
prior year while realized prices (including all derivative settlements) declined 3%. We believe
natural gas, NGL and oil prices will remain volatile and will be affected by, among other things,
weather, the U.S. and worldwide economy, new regulations, 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 2011, 2012 and 2013, a sustained lower price
environment would result in lower realized prices for unprotected volumes and reduce the prices we
can enter into derivative contracts for additional volumes in the future.
Natural Gas, NGL and Oil Sales Production and Realized Price Calculation
Our natural gas, NGL and oil sales vary from quarter to quarter as a result of
changes in realized commodity prices and volumes of production sold. Hedges included in natural
gas, NGL and oil sales reflect settlements on those derivatives that qualify for hedge accounting.
Cash settlements of derivative contracts that are not accounted for as hedges are included in
derivative fair value (loss) income in the accompanying consolidated statements of operations. The
following table summarizes the primary components of natural gas, NGL and oil sales for the three
months ended March 31, 2011 and 2010 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2011 |
|
|
2010 |
|
|
Change |
|
|
% |
|
Gas wellhead |
|
$ |
106,283 |
|
|
$ |
123,270 |
|
|
$ |
(16,987 |
) |
|
|
(14 |
%) |
Gas hedges realized |
|
|
29,616 |
|
|
|
1,215 |
|
|
|
28,401 |
|
|
|
2,338 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gas sales |
|
|
135,899 |
|
|
|
124,485 |
|
|
|
11,414 |
|
|
|
9 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL |
|
|
54,475 |
|
|
|
28,024 |
|
|
|
26,451 |
|
|
|
94 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil wellhead |
|
|
36,507 |
|
|
|
35,164 |
|
|
|
1,343 |
|
|
|
4 |
% |
Oil hedges realized |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil sales |
|
|
36,507 |
|
|
|
35,164 |
|
|
|
1,343 |
|
|
|
4 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Combined wellhead |
|
|
197,265 |
|
|
|
186,458 |
|
|
|
10,807 |
|
|
|
6 |
% |
Combined hedges realized |
|
|
29,616 |
|
|
|
1,215 |
|
|
|
28,401 |
|
|
|
2,338 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total natural gas, NGL and oil sales |
|
$ |
226,881 |
|
|
$ |
187,673 |
|
|
$ |
39,208 |
|
|
|
21 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24
Our production continues to grow through continued drilling success as we place new wells into
production, partially offset by the natural decline of our wells and asset sales. For first
quarter 2011, total production volumes, when compared to the same period of the prior year,
increased 40% in our Appalachia area and remained the same in our
Southwest area. For first
quarter 2011, NGL production increased 81% from the same period of the prior year primarily due to
increased liquids-rich gas production in our Appalachia area along with an increase in processing
capacity in the region. Our production for the three months ended March 31, 2011 and 2010 is shown
below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
March 31, |
|
|
2011 |
|
2010 |
|
Change |
|
% |
Production(a): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mcf) |
|
|
29,805,523 |
|
|
|
24,372,167 |
|
|
|
5,433,356 |
|
|
|
22 |
% |
NGLs (bbls) |
|
|
1,131,565 |
|
|
|
623,474 |
|
|
|
508,091 |
|
|
|
81 |
% |
Crude oil (bbls) |
|
|
436,132 |
|
|
|
505,101 |
|
|
|
(68,969 |
) |
|
|
(14 |
%) |
Total (mcfe)(b) |
|
|
39,211,706 |
|
|
|
31,143,617 |
|
|
|
8,068,089 |
|
|
|
26 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average daily
production(a): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mcf) |
|
|
331,172 |
|
|
|
270,802 |
|
|
|
60,370 |
|
|
|
22 |
% |
NGLs (bbls) |
|
|
12,573 |
|
|
|
6,927 |
|
|
|
5,646 |
|
|
|
81 |
% |
Crude oil (bbls) |
|
|
4,846 |
|
|
|
5,612 |
|
|
|
(766 |
) |
|
|
(14 |
%) |
Total (mcfe)(b) |
|
|
435,686 |
|
|
|
346,040 |
|
|
|
89,646 |
|
|
|
26 |
% |
|
|
|
(a) |
|
Represents volumes sold regardless of when produced. |
|
(b) |
|
NGLs and oil are converted at the rate of one barrel equals six mcf based upon the
approximate relative energy content of oil and natural gas, which is not indicative of the
relationship of oil and natural gas prices. |
Our average realized price (including all derivative settlements) received was $5.75 per
mcfe in first quarter 2011 compared to $5.90 per mcfe in the same period of the prior year. Our
average realized price calculation (including all derivative settlements) includes all cash
settlements for derivatives, whether or not they qualify for hedge accounting. Average price
calculations for the three months ended March 31, 2011 and 2010 are shown below:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
March 31, |
|
|
2011 |
|
2010 |
Average sales prices (wellhead): |
|
|
|
|
|
|
|
|
Natural gas (per mcf) |
|
$ |
3.57 |
|
|
$ |
5.06 |
|
NGLs (per bbl) |
|
|
48.14 |
|
|
|
44.95 |
|
Crude oil (per bbl) |
|
|
83.71 |
|
|
|
69.62 |
|
Total (per mcfe)(a) |
|
|
5.03 |
|
|
|
5.99 |
|
|
|
|
|
|
|
|
|
|
Average realized price (including derivatives that qualify
for hedge accounting): |
|
|
|
|
|
|
|
|
Natural gas (per mcf) |
|
$ |
4.56 |
|
|
$ |
5.11 |
|
NGLs (per bbl) |
|
|
48.14 |
|
|
|
44.95 |
|
Crude oil (per bbl) |
|
|
83.71 |
|
|
|
69.62 |
|
Total (per mcfe)(a) |
|
|
5.79 |
|
|
|
6.02 |
|
|
|
|
|
|
|
|
|
|
Average realized price (including all derivative settlements): |
|
|
|
|
|
|
|
|
Natural gas (per mcf) |
|
|
4.58 |
|
|
|
4.94 |
|
NGLs (per bbl) |
|
|
48.14 |
|
|
|
44.95 |
|
Crude oil (per bbl) |
|
|
79.31 |
|
|
|
69.62 |
|
Total (per mcfe)(a) |
|
|
5.75 |
|
|
|
5.90 |
|
|
|
|
(a) |
|
NGLs and oil are converted at the rate of one barrel equals six mcf based upon
the approximate relative energy content of oil and natural gas, which is not indicative of the
relationship of oil and natural gas prices. |
25
Derivative fair value income (loss) was a loss of $40.8 million in first quarter 2011
compared to a gain of $42.3 million in the same period of 2010. Some of our derivatives do not
qualify for hedge accounting and 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 (loss) income in the accompanying consolidated statements of operations.
Mark-to-market accounting treatment creates volatility in our revenues as unrealized gains and
losses from non-hedge derivatives are included in total revenues and are not included in
accumulated other comprehensive income in the accompanying consolidated balance sheets. Hedge
ineffectiveness, also included in this statement of operations category, is associated with our
hedging contracts that qualify for hedge accounting.
The following table presents information about the components of derivative fair value (loss)
income for the three months ended March 31, 2011 and 2010 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2011 |
|
|
2010 |
|
Hedge ineffectiveness realized(c) |
|
$ |
946 |
|
|
$ |
(357 |
) |
unrealized(a) |
|
|
568 |
|
|
|
(249 |
) |
Change in fair value of derivatives that do not
qualify for hedge accounting(a) |
|
|
(40,036 |
) |
|
|
46,578 |
|
Realized loss on settlements gas(b)(c) |
|
|
(394 |
) |
|
|
(3,639 |
) |
Realized loss on settlements oil(b)(c) |
|
|
(1,918 |
) |
|
|
|
|
Derivative fair value (loss) income |
|
$ |
(40,834 |
) |
|
$ |
42,333 |
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
These amounts are unrealized and are not included in average sales price
calculations. |
|
(b) |
|
These amounts represent realized gains and losses on settled derivatives that do
not qualify for hedge accounting. |
|
(c) |
|
These settlements are included in average realized price calculations (average
realized price including all derivative settlements). |
Gain
on the sale of assets for first quarter 2011 decreased $67.8 million from the same
period of the prior year. For the three months ended March 31, 2010, we recorded a total gain of $67.0 million from
the sale of our properties in Ohio and we received proceeds of $300.0 million.
Other income (loss) for first
quarter 2011 was income of $1.1 million compared to a loss of
$1.6 million in the same period of 2010. First quarter 2011 includes income from equity method
investments of $262,000. The first quarter of 2010 includes a loss from equity method investments
of $1.6 million.
We believe some of our expense fluctuations are best analyzed on a unit-of-production, or per
mcfe, basis. The following presents information about these expenses on a per mcfe basis for the
three months ended March 31, 2011 and 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
March 31, |
|
|
2011 |
|
2010 |
|
Change |
|
% |
Direct operating expense |
|
$ |
0.73 |
|
|
$ |
0.70 |
|
|
$ |
0.03 |
|
|
|
4 |
% |
Production and ad valorem tax expense |
|
|
0.18 |
|
|
|
0.21 |
|
|
|
(0.03 |
) |
|
|
(14 |
%) |
General and administrative expense |
|
|
0.87 |
|
|
|
0.90 |
|
|
|
(0.03 |
) |
|
|
(3 |
%) |
Interest expense |
|
|
0.63 |
|
|
|
0.67 |
|
|
|
(0.04 |
) |
|
|
(6 |
%) |
Depletion, depreciation and
amortization expense |
|
|
1.84 |
|
|
|
2.08 |
|
|
|
(0.24 |
) |
|
|
(12 |
%) |
Direct operating expense increased $6.9 million in first quarter 2011 to $28.7
million. We experience increases in operating expenses as we add new wells and maintain production
from existing properties. We incurred $390,000 ($0.01 per mcfe) of workover costs in first quarter
2011 versus $777,000 ($0.02 per mcfe) in 2010. On a per mcfe basis, direct operating expenses for
first quarter 2011 increased $0.03, or 4%, from the same period of 2010 with the increase primarily
due to higher water hauling and disposal costs ($0.04 per mcfe) and higher equipment rental ($0.02
per mcfe) somewhat offset by
the impact of the sale of certain higher operating cost assets
during 2010. In the future, we expect to experience lower costs per
mcfe as we increase production from our Marcellus Shale wells due to their lower operating costs
relative to our other operating areas. Stock-based compensation included in this category
represents amortization of restricted stock grants and expense related to SAR grants. The
following table summarizes direct operating expenses per mcfe for the three months ended March 31,
2011 and 2010:
26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2011 |
|
|
2010 |
|
|
Change |
|
|
% |
|
Lease operating expense |
|
$ |
0.71 |
|
|
$ |
0.67 |
|
|
$ |
0.04 |
|
|
|
6 |
% |
Workovers |
|
|
0.01 |
|
|
|
0.02 |
|
|
|
(0.01 |
) |
|
|
(50 |
%) |
Stock-based compensation (non-cash) |
|
|
0.01 |
|
|
|
0.01 |
|
|
|
|
|
|
|
|
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total direct operating expenses |
|
$ |
0.73 |
|
|
$ |
0.70 |
|
|
$ |
0.03 |
|
|
|
4 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and ad valorem taxes are paid based on market prices and not hedged prices. For
first quarter 2011, these taxes increased $337,000 or 5% from the same period of the prior year due
to a decrease in the number of wells receiving high cost tax credits which was partially offset by
an increase in production volumes not subject to production taxes and lower prices. On a per mcfe
basis, production and ad valorem taxes decreased from $0.21 per mcf in first quarter 2010 to
$0.18 per mcfe in 2011.
General and administrative expense
for first quarter 2011 increased $5.8 million or 21% from
the same period of the prior year due primarily to higher community relations costs ($1.3 million),
higher salaries and benefits ($3.0 million), higher legal costs ($1.7 million) and higher office
expenses, including information technology somewhat offset by lower bad debt expense ($688,000).
Stock-based compensation included in this category represents amortization of restricted stock
grants and expense related to SAR grants. The following table summarizes general and
administrative expenses per mcfe for the three months ended March 31, 2011 and 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2011 |
|
|
2010 |
|
|
Change |
|
|
% |
|
General and administrative |
|
$ |
0.68 |
|
|
$ |
0.65 |
|
|
$ |
0.03 |
|
|
|
5 |
% |
Stock-based compensation (non-cash) |
|
|
0.19 |
|
|
|
0.25 |
|
|
|
(0.06 |
) |
|
|
(24 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total general and administrative expenses |
|
$ |
0.87 |
|
|
$ |
0.90 |
|
|
$ |
(0.03 |
) |
|
|
(3 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense for first quarter 2011 increased $3.8 million from the same period of the
prior year due to the refinancing of certain debt from floating to higher fixed rates and higher
overall debt balances. In August 2010, we issued $500.0 million of 6.75% senior subordinated notes
due 2020, which added $8.4 million of interest costs in first quarter 2011. The proceeds from the
issuance were used to retire our 7.375% senior subordinated notes due 2013 and to lower our
floating interest rate bank debt, which better matches the maturities of our debt with the life of
our properties and gives us greater liquidity for the near term. Average debt outstanding on the
bank credit facility for first quarter 2011 was $421.1 million compared to $359.6 million for the
same period of the prior year and the weighted average interest rate was 2.3% in first quarter 2011
compared to 2.1% in the same period of the prior year.
Depletion, depreciation and amortization (DD&A) increased $7.4 million, or 11%, to $72.2
million in first quarter 2011. The increase was due to a 26% increase in production partially
offset by a 10% decrease in depletion rates. On a per mcfe basis, DD&A decreased from $2.08 in
first quarter 2010 to $1.84 in first quarter 2011. Depletion rates are declining due to our lower
finding and development costs and the mix of our production. The following table summarizes DD&A
expense per mcfe for the three months ended March 31, 2011 and 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2011 |
|
|
2010 |
|
|
Change |
|
|
% |
|
Depletion and amortization |
|
$ |
1.71 |
|
|
$ |
1.89 |
|
|
$ |
(0.18 |
) |
|
|
(10 |
%) |
Depreciation |
|
|
0.10 |
|
|
|
0.15 |
|
|
|
(0.05 |
) |
|
|
(33 |
%) |
Accretion and other |
|
|
0.03 |
|
|
|
0.04 |
|
|
|
(0.01 |
) |
|
|
(25 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total DD&A expense |
|
$ |
1.84 |
|
|
$ |
2.08 |
|
|
$ |
(0.24 |
) |
|
|
(12 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
27
Our total operating expenses also include other expenses that generally do not trend with
production. These expenses include stock-based compensation, exploration expense, abandonment and
impairment of unproved properties, termination costs, deferred compensation plan expenses and
impairment of proved properties. In the three months ended March 31, 2011 and 2010, stock-based
compensation represents the amortization of restricted stock grants and expenses related to SAR
grants. In first quarter 2011, stock-based compensation is a component of direct operating expense
($310,000), exploration expense ($1.3 million) and general and administrative expense ($7.5
million) for a total of $9.6 million. In first quarter 2010, stock-based compensation was a
component of direct operating expense ($362,000), exploration expense ($1.1 million) and general
and administrative expense ($7.8 million) for a total of $9.7 million.
Exploration expense increased $13.0 million in first quarter 2011 with higher seismic costs
and higher delay rental expense. The higher delay rental payments, or costs to defer the
commencement of drilling, are primarily attributed to our Marcellus Shale operations. The
following table details our exploration-related expenses for the three months ended March 31, 2011
and 2010 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2011 |
|
|
2010 |
|
|
Change |
|
|
% |
|
Dry hole expense |
|
$ |
10 |
|
|
$ |
|
|
|
$ |
10 |
|
|
|
|
% |
Seismic |
|
|
13,172 |
|
|
|
7,213 |
|
|
|
5,959 |
|
|
|
83 |
% |
Personnel expense |
|
|
4,026 |
|
|
|
2,730 |
|
|
|
1,296 |
|
|
|
47 |
% |
Stock-based compensation expense |
|
|
1,329 |
|
|
|
1,136 |
|
|
|
193 |
|
|
|
17 |
% |
Delay rentals and other |
|
|
8,650 |
|
|
|
3,060 |
|
|
|
5,590 |
|
|
|
183 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total exploration expense |
|
$ |
27,187 |
|
|
$ |
14,139 |
|
|
$ |
13,048 |
|
|
|
92 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Abandonment and impairment of unproved properties expense was $16.5 million during the three
months ended March 31, 2011 compared to $6.6 million during the same period of 2010. We assess
individually significant unproved properties for impairment on a quarterly basis and recognize a
loss where circumstances indicate an 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. The increase from the prior year is primarily due to increasing
expirations in the Marcellus Shale.
Termination costs in the first three months of 2010 includes severance costs of $5.1 million
related to the sale of our properties in Ohio and $2.8 million of non-cash stock-based compensation
expense related to the accelerated vesting of SARs and restricted stock as part of the severance
agreement for our Ohio personnel.
Deferred compensation plan expense was $30.6 million in first quarter 2011 compared to income
of $5.7 million in the same period of the prior year. This non-cash expense relates to the
increase or decrease in value of the liability associated with our common stock that is vested and
held in the deferred compensation plan. Our deferred compensation liability is adjusted to fair
value by a charge or a credit to deferred compensation plan expense in the accompanying statements
of operations. Our stock price increased from $44.98 at December 31, 2010 to $58.46 at March 31,
2011. During the same period in the prior year, our stock price decreased from $49.85 at December
31, 2009 to $46.87 at March 31, 2010.
Impairment of proved properties in the first three months of 2010 of $6.5 million was
recognized due to declining gas prices and is related to a portion of our onshore Gulf Coast
properties. Our estimated fair value of producing properties is generally calculated as the
discounted present value of future net cash flows. Our estimates of cash flow were based on the
latest available proved reserve and production information and managements estimates of future
product prices and costs, based on available information such as forward strip prices, at the time
of the impairment.
Income tax (benefit) expense for first
quarter 2011 decreased to a benefit of $19.9 million
from income tax expense of $49.0 million in first quarter 2010,
reflecting a 142% decrease in
income from continuing operations before taxes compared to the same period of 2010. First quarter 2011
provided for tax benefit at an effective rate of 37.3% compared to tax expense at an effective rate
of 38.7% in the same period of 2010. We expect our effective tax rate to be approximately 40% for
the remainder of 2011.
28
Liquidity, Capital Resources and Financial Conditions
Our main sources of liquidity and capital resources are internally generated cash
flow from operations, a bank credit facility with both uncommitted and committed availability,
asset sales and access to both the debt and equity capital markets. We continue to take steps to
ensure adequate capital resources and liquidity to fund our capital expenditure program. In
February 2011, we announced we had entered into a definitive agreement to sell our Barnett Shale
properties along with certain derivative contracts for $900.0 million. The sale is expected to
close at the end of April 2011. For additional information, see Notes 4 and 5 to the accompanying
consolidated financial statements. In the first three months of 2011, we also entered into
additional commodity derivative contracts for 2011, 2012 and 2013 to protect future cash flows. On
February 18, 2011, we announced we had entered into an amended and restated revolving bank credit
facility, which replaced our previous credit facility. At closing, the facility amount was $1.5
billion and the borrowing base was $2.0 billion.
During the three months ended March 31, 2011, our cash provided from operating activities was
$140.6 million and we spent $260.0 million on capital expenditures and $24.3 million on proved and
unproved property purchases. At March 31, 2011, we had $1.7 million in cash, total assets of $5.6
billion and a debt-to-capitalization ratio of 49.8%. Long-term debt at March 31, 2011 totaled $2.2
billion, which included $480.0 million of bank credit facility debt and $1.7 billion of senior
subordinated notes. Available committed borrowing capacity under the bank credit facility at March
31, 2011 was $1.0 billion.
In June 2009, we filed a universal shelf registration statement with the Securities and
Exchange Commission, under which we, as a well-known seasoned issuer, have the ability, subject to
market conditions, to issue and sell an indeterminate amount of various types of registered debt
and equity securities.
We establish a capital budget at the beginning of each calendar year. Our 2011 capital budget
(excluding acquisitions) now stands at $1.38 billion and focuses on projects we believe will
generate and lay the foundation for economic, long-term production growth. In the past, we often
have increased our capital budget during the year as a result of acquisitions or successful
drilling. We continue to screen for attractive acquisition opportunities; however, the timing and
size of acquisitions are unpredictable.
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 believe that net cash generated from
operating activities, unused committed borrowing capacity under the bank credit facility and
proceeds from asset sales will be adequate to satisfy near-term financial obligations and liquidity
needs. However, our 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
natural gas and oil business. Sustained lower prices or a reduction in production and reserves
would reduce our ability to fund capital expenditures, reduce debt, meet financial obligations and
remain profitable. We operate in an environment with numerous financial and operating risks,
including, but not limited to, the inherent risks of the search for, development and production of
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 opinions 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. Estimates may differ from actual results. 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 outstanding debt
and credit ratings by rating agencies.
Credit Arrangements
On March 31, 2011, the bank credit facility had a $2.0 billion borrowing base and a $1.5
billion facility amount. The borrowing base represents an amount approved by the bank group that
can be borrowed based on our assets, while our $1.5 billion facility amount is the amount we have
requested that the banks commit to fund pursuant to the credit agreement. The bank credit facility
provides for a borrowing base subject to redeterminations semi-annually each April and October and
for event-driven unscheduled redeterminations. Remaining credit
availability was $924.0 million on
April 25, 2011. Our bank group is comprised of twenty-seven commercial banks, with no one bank
holding more than 7.0% of the bank credit facility. We believe our large number of banks and
relatively low hold levels allow for significant lending capacity should we elect to increase our
$1.5 billion commitment up to the $2.0 billion borrowing base and also allow for flexibility should
there be additional consolidation within the banking sector.
29
Our bank credit facility and our indentures governing our senior subordinated notes all
contain covenants that, among other things, limit our ability to pay dividends, incur additional
indebtedness, sell assets, enter into hedging contracts change the nature of our business or
operations, merge or consolidate or make certain 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 were
in compliance with these covenants at March 31, 2011. Please see Note 9 to the accompanying
consolidated financial statements for additional information.
Cash Flow
Cash flows from operating activities primarily are affected by production and commodity
prices, net of the effects of settlements of our derivatives. Our cash flows from operating
activities also are impacted by changes in working capital. We sell substantially all of our
natural gas, NGL and oil production at the wellhead under floating market contracts. However, we
generally hedge a substantial, but varying, portion of our anticipated future natural gas and oil
production for the next 12 to 36 months. 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 borrowing under the credit facility. As of March 31, 2011, we have entered into
derivative agreements covering 128.5 Bcfe for 2011, 88.5 Bcfe for 2012 and 36.5 Bcfe for 2013.
Net cash provided from continuing operations for the three months ended March 31, 2011 was
$118.7 million compared to $116.3 million in the three months ended March 31, 2010. Cash flow from
continuing operations for the first three months of 2011 was higher than the same period of the prior
year, as higher production from development activity
and a $15.0 million equity method investment distribution
was more than offset by lower realized prices
and higher operating costs. Net cash provided from operating activities 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) in the three months ended March
31, 2011 was a decrease of $10.6 million compared to a increase of $15.9 million in the same period
of the prior year.
Net
cash used in investing activities for the three months ended
March 31, 2011 was $271.8
million compared to net cash provided from investing activities of $108.1 million in the same
period of 2010. During the three months ended March 31, 2011, we:
|
|
|
spent $250.8 million on natural gas and oil property additions; |
|
|
|
|
spent $24.3 million on acreage primarily in the Marcellus Shale; |
|
|
|
|
received proceeds of $15.2 million primarily from the sale of a low pressure pipeline;
and |
|
|
|
|
spent $8.2 million on discontinued operations. |
During the three months ended March 31, 2010, we:
|
|
|
spent $154.0 million on natural gas and oil property additions; |
|
|
|
|
spent $19.8 million on acreage primarily in the Marcellus Shale; |
|
|
|
|
received proceeds of $301.6 million primarily from the sale of Ohio oil and gas
properties; and |
|
|
|
|
spent $12.3 million on discontinued operations. |
Net cash provided from financing activities for the three months ended March 31, 2011 was
$130.0 million compared to $24.8 million in the same period of 2010. During the three months ended
March 31, 2011, we:
|
|
|
borrowed $372.8 million and repaid $166.8 million under our bank credit facility,
ending the period with a $206.0 million higher bank credit facility balance. |
|
|
|
spent $12.4 million related to debt issuance costs; and |
|
|
|
recorded as decrease of $61.0 million in cash overdrafts. |
During the three months ended March 31, 2010, we:
|
|
|
borrowed $148.0 million and repaid $118.0 million under our bank credit facility,
ending the period with a $30.0 million higher bank credit facility balance. |
Dividends
On March 1, 2011, the Board of Directors declared a dividend of four cents per share ($6.4
million) on our common stock, which was paid on March 31, 2011 to stockholders of record at the
close of business on March 15, 2011.
30
Capital Requirements and Contractual Cash Obligations
We currently estimate our 2011 capital spending will approximate $1.38 billion
(excluding acquisitions) and based on current projections is expected to be funded with internal
cash flow, property sales and our bank credit facility. Acreage purchases during the first three
months include $14.7 million of purchases in the Marcellus Shale, which were funded with borrowings
under our credit facility. For the three months ended March 31, 2011, $294.6 million of our
development and exploration spending was funded with internal cash flow and borrowings under our
bank credit facility. We monitor our capital expenditures on a regular basis, adjusting the amount
up or down and 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 choose to sell assets, issue subordinated notes or other debt securities,
or issue additional shares of stock to fund capital expenditures or acquisitions, extend maturities
or repay debt.
Our contractual obligations include long-term debt, operating leases, drilling commitments,
derivative obligations, transportations commitments and other purchase obligations. Since December
31, 2010, there have been no material changes to our contractual obligations other than our
outstanding bank credit facility amount increased to $480.0 million at March 31, 2011 and the
credit facility loan maturity was extended to 2016. In addition,
we entered into additional transportation agreements in Appalachia which totals approximately $100.0 million
over the next seven years.
Other Contingencies
We are involved in various legal actions and claims arising in the ordinary course of
business. We believe the resolution of these proceedings will not have a material adverse effect
on our liquidity or consolidated financial position.
Hedging Natural Gas and Oil Prices
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.
Historically, these contracts consisted of collars and fixed price swaps. We do not utilize
complex derivatives such as swaptions, knockouts or extendable swaps. Reducing our exposure to
price volatility helps ensure that we have adequate funds available for our capital program. Our
decision on the quantity and price at which we choose to hedge our future production is based in
part on our view of current and future market conditions. In light of current worldwide economic
uncertainties, we have employed a strategy to hedge a portion of our production looking out 12 to
36 months from each quarter. At March 31, 2011, we had open swap contracts covering 25.6 Bcf of
natural gas at prices averaging $5.00 and $1.5 million barrels of NGLs at an average price of
$101.88 per barrel. At March 31, 2011, we had collars covering 195.3 Bcf of natural gas at
weighted average floor and cap prices of $5.42 and $6.27 per mcf and 0.7 million barrels of oil at
weighted average floor and cap prices of $70.00 and $80.00 per barrel. At March 31, 2011, we also
had sold call options covering 3.2 million barrels of oil at a weighted average price of $82.66.
The fair value of all of our derivative contracts, represented by the estimated amount that would be realized upon termination,
based on a comparison of contract prices and a reference price, generally NYMEX, on March 31, 2011
was a net unrealized pre-tax gain of $31.5 million. The contracts expire monthly through December
2013. Settled transaction gains and losses for derivatives that qualify for hedge accounting are
determined monthly and are included as increases or decreases in natural gas, NGLs and oil sales in
the period the hedged production is sold. In the first three months of 2011, natural gas, NGLs and
oil sales included realized hedging gains of $29.6 million compared to gains of $1.2 million in the
same period of 2010.
At March 31, 2011, the following commodity derivative contracts were outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
Period |
|
Contract Type |
|
Volume Hedged |
|
Hedge Price |
Natural Gas |
|
|
|
|
|
|
2012
|
|
Swaps
|
|
70,192 Mmbtu/day
|
|
$5.00 |
2011
|
|
Collars
|
|
418,236 Mmbtu/day
|
|
$5.52-$6.45 |
2012
|
|
Collars
|
|
119,641 Mmbtu/day
|
|
$5.50-$6.25 |
2013
|
|
Collars
|
|
100,000 Mmbtu/day
|
|
$5.00-$5.73 |
|
|
|
|
|
|
|
Crude Oil |
|
|
|
|
|
|
2012
|
|
Collars
|
|
2,000 bbls/day
|
|
$70.00-$80.00 |
2011
|
|
Call options
|
|
5,500 bbls/day
|
|
$80.00 |
2012
|
|
Call options
|
|
4,700 bbls/day
|
|
$85.00 |
|
|
|
|
|
|
|
NGLs |
|
|
|
|
|
|
2011
|
|
Swaps
|
|
2,676 bbls/day
|
|
$102.80 |
2012
|
|
Swaps
|
|
2,000 bbsl/day
|
|
$100.96 |
31
Some of our derivatives do not qualify for hedge accounting or are not designated as a hedge
but provide an economic hedge of our exposure to commodity price risk associated with anticipated
future natural gas and oil production. These contracts are accounted for using the mark-to-market
accounting method. Under this method, the contracts are carried at their fair value as unrealized
derivative gains and losses in the accompanying consolidated balance sheets. We recognize all
unrealized and realized gains and losses related to these contracts as derivative fair value income
or loss in our consolidated statements of operations. As of March 31, 2011, derivatives on 56.0
Bcfe no longer qualify or are not designated for hedge accounting.
Interest Rates
At March 31, 2011, we had $2.2 billion of debt outstanding. Of this amount, $1.7 billion bore
interest at fixed rates averaging 7.2%. Bank debt totaling $480.0 million bears interest at
floating rates, which approximated 1.9% at March 31, 2011. The 30-day LIBOR rate on March 31, 2011
was 0.2%.
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
and oil prices and the costs to produce our reserves. Natural gas and oil prices are subject to
fluctuations that are beyond our ability to control or predict. During first quarter 2011, we
received an average of $3.57 per mcf of gas and $83.71 per barrel of oil before derivative
contracts compared to $5.06 per mcf of gas and $69.62 per barrel of oil in the same period of the
prior year. Although certain of our costs are affected by general inflation, inflation does not
normally have a significant effect on our business. In a trend that began in 2004 and accelerated
through the middle of 2008, commodity prices for oil and gas increased significantly. The higher
prices led to increased activity in the industry and, consequently, rising costs. These cost
trends put pressure not only on our operating costs but also on capital costs. Due to the decline
in commodity prices since then, costs have generally moderated but are increasing in areas with
high levels of drilling activity that utilize specialized services for horizontal drilling and
completions. We expect costs in 2011 to continue to be a function of supply and demand.
32
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 oil and gas prices and interest rates.
The disclosures are not meant to be indicators of expected future losses, but rather indicators of
reasonably possible losses. This forward-looking information provides indicators of how we view
and manage our ongoing market-risk exposures. All of our market-risk sensitive instruments were
entered into for purposes other than trading. All accounts are U.S. dollar denominated.
Market Risk
Our major market risk is exposure to natural gas, NGL and oil prices. Realized prices are
primarily driven by worldwide prices for oil and spot market prices for North American gas
production. Natural gas, NGL and oil prices have been volatile and unpredictable for many years.
Commodity Price Risk
We periodically enter into derivative arrangements with respect to our natural gas, oil and
NGL production. These arrangements are intended to reduce the impact of natural gas and oil price
fluctuations. Some of our derivatives have been 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. We have also
entered into call option derivative contracts under which we sold call options in exchange for a
premium from the counterparty. Historically, we applied hedge accounting to derivatives utilized
to manage price risk associated with our natural gas and oil production. Accordingly, we recorded
the change in the fair value of our swap and collar contracts under the balance sheet caption
accumulated other comprehensive income and into natural gas, NGLs and oil sales when the forecasted
sale of production occurred. Any hedge ineffectiveness associated with contracts qualifying for
and designated as a cash flow hedge is reported currently each period in derivative fair value
income or loss in our consolidated statements of operations. Some of our derivatives do not
qualify for hedge accounting but provide an economic hedge of our exposure to commodity price risk
associated with anticipated future natural gas, oil and NGL production. These contracts are
accounted for using the mark-to-market accounting method. Under this method, the contracts are
carried at their fair value in unrealized derivative gains and losses in our consolidated balance sheets.
We recognize all unrealized and realized gains and losses related to these contracts in derivative
fair value (loss) income in our consolidated statements of operations. Generally, derivative
losses occur when market prices increase, which are offset by gains on the underlying physical
commodity transaction. Conversely, derivative gains occur when market prices decrease, which are
offset by losses on the underlying commodity transaction. Our derivative counterparties include
nine financial institutions, all of which are in our bank group. None of our derivative contracts
have margin requirements or collateral provisions that would require funding prior to the scheduled
cash settlement date.
As of March 31, 2011, we had swaps covering 25.6 Bcf of natural gas and 1.5 million barrels of
NGLs, collars covering 195.3 Bcf of natural gas and 0.7 million barrels of oil and oil call options
for 3.2 million barrels of oil. These contracts expire monthly through December 2013. The fair
value, represented by the estimated amount that would be realized upon immediate liquidation as of
March 31, 2011, approximated a net unrealized pre-tax gain of $31.5 million.
We expect our NGL production to continue to increase. In the first quarter 2011, we entered
into NGL swap contracts for the natural gasoline component of NGLs. In our Marcellus Shale
operations, propane is a large product component of our NGL production, we believe NGL prices are
somewhat seasonal. Therefore, the percentage of NGL prices to NYMEX WTI (or West Texas
Intermediate) will vary due to product components, seasonality and geographic supply and demand.
33
At March 31, 2011, the following commodity derivative contracts were outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Market Value |
|
|
|
|
|
|
|
|
as of |
|
|
|
|
|
|
|
|
March 31, 2011 |
Period |
|
Contract Type |
|
Volume Hedged |
|
Average Hedge Price |
|
Asset (Liability) |
|
|
|
|
|
|
|
|
(in thousands) |
Natural Gas |
|
|
|
|
|
|
|
|
2012
|
|
Swaps
|
|
70,192 Mmbtu/day
|
|
$5.00
|
|
$(1,405) |
2011
|
|
Collars
|
|
418,236 Mmbtu/day
|
|
$5.52-$6.45
|
|
$116,271 |
2012
|
|
Collars
|
|
119,641 Mmbtu/day
|
|
$5.50-$6.25
|
|
$27,532 |
2013
|
|
Collars
|
|
100,000 Mmbtu/day
|
|
$5.00-$5.73
|
|
$(2,945) |
|
|
|
|
|
|
|
|
|
Crude Oil |
|
|
|
|
|
|
|
|
2012
|
|
Collars
|
|
2,000 bbls/day
|
|
$70.00-$80.00
|
|
$(20,037) |
2011
|
|
Call options
|
|
5,500 bbls/day
|
|
$80.00
|
|
$(42,949) |
2012
|
|
Call options
|
|
4,700 bbls/day
|
|
$85.00
|
|
$(43,152) |
|
|
|
|
|
|
|
|
|
NGLs |
|
|
|
|
|
|
|
|
2011
|
|
Swaps
|
|
2,676 bbls/day
|
|
$102.80
|
|
$(1,104) |
2012
|
|
Swaps
|
|
2,000 bbls/day
|
|
$100.96
|
|
$(760) |
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. We currently have not
entered into any basis derivatives.
The following table shows the fair value of our swaps, collars and call options and the
hypothetical change in the fair value that would result from a 10% and a 25% change in commodity
prices at March 31, 2011 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hypothetical Change in |
|
Hypothetical Change in |
|
|
|
|
|
|
Fair Value |
|
Fair Value |
|
|
|
|
|
|
Increase of |
|
Decrease of |
|
|
Fair Value |
|
10% |
|
25% |
|
10% |
|
25% |
Swaps |
|
$ |
(3,269 |
) |
|
$ |
(12,592 |
) |
|
$ |
(31,487 |
) |
|
$ |
12,792 |
|
|
$ |
32,020 |
|
Collars |
|
|
120,821 |
|
|
|
(86,266 |
) |
|
|
(210,057 |
) |
|
|
89,681 |
|
|
|
229,520 |
|
Call options |
|
|
(86,101 |
) |
|
|
(30,695 |
) |
|
|
(79,080 |
) |
|
|
28,395 |
|
|
|
62,831 |
|
Interest rate risk. At March 31, 2011, we had $2.2 billion of debt outstanding. Of this
amount, $1.7 billion bore interest at fixed rates averaging 7.2%. Senior bank debt totaling $480.0
million bore interest at floating rates averaging 1.9%. A 1% increase or decrease in short-term
interest rates would affect interest expense by approximately $4.8 million per year.
ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
As required by Rule 13a-15(b) of 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
34
accumulated and communicated to our management,
including our principal executive officer and principal financial officer, as appropriate, to allow
timely decisions regarding required disclosure and is recorded, processed, summarized and reported
within the time periods specified in the rules and forms of the SEC. Based upon the evaluation,
our principal executive officer and principal financial officer have concluded that our disclosure
controls and procedures were effective as of March 31, 2011 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 15-d-15(f) under the Exchange Act) during the quarter ended March 31, 2011 that
has materially affected, or is reasonably likely to materially affect, our internal control over
financial reporting.
35
PART II OTHER INFORMATION
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, 2010. There have been no material changes from the risk factors previously
disclosed in that Form 10-K.
36
ITEM 6. EXHIBITS
(a) EXHIBITS
|
|
|
Exhibit |
|
|
Number |
|
Exhibit Description |
|
|
|
3.1
|
|
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 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) |
|
|
|
10.1*
|
|
Purchase and Sale Agreement between Range Texas Production,
LLC, Energy Assets Operating Company, LLC and Range Resources
Corporation as Seller and Legend Natural Gas IV, LP as Buyer
dated February 28, 2011 |
|
|
|
10.2
|
|
Fourth Amended and Restated Credit Agreement dated February 18,
2011 (incorporated by reference to Exhibit 10.1 to our Form 8-K
(File No. 001-12009) as filed with the SEC on February 22,
2011) |
|
|
|
31.1*
|
|
Certification by the Chairman 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 Chairman 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 |
37
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
Date: April 27, 2011
|
|
|
|
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RANGE RESOURCES CORPORATION
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By: |
/s/ ROGER S. MANNY
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Roger S. Manny |
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Executive Vice President and Chief Financial Officer |
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Date: April 27, 2011
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RANGE RESOURCES CORPORATION
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By: |
/s/ DORI A. GINN
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Dori A. Ginn |
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Principal Accounting Officer and Vice President Controller |
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II-1
Exhibit index
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Exhibit |
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Number |
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Exhibit Description |
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3.1
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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 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) |
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3.2
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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) |
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10.1*
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Purchase and Sale Agreement between Range Texas Production,
LLC, Energy Assets Operating Company, LLC and Range Resources
Corporation as Seller and Legend Natural Gas IV, LP as Buyer
dated February 28, 2011 |
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10.2
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Fourth Amended and Restated Credit Agreement dated February 18,
2011 (incorporated by reference to Exhibit 10.1 to our Form 8-K
(File No. 001-12009) as filed with the SEC on February 22,
2011) |
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31.1*
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Certification by the Chairman and Chief Executive Officer of
Range Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
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31.2*
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Certification by the Chief Financial Officer of Range Pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002 |
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32.1**
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Certification by the Chairman 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 |
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32.2**
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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 |
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101. INS
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XBRL Instance Document |
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101. SCH
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XBRL Taxonomy Extension Schema |
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101. CAL
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XBRL Taxonomy Extension Calculation Linkbase Document |
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101. DEF
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XBRL Taxonomy Extension Definition Linkbase Document |
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101. LAB
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XBRL Taxonomy Extension Label Linkbase Document |
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101. PRE
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XBRL Taxonomy Extension Presentation Linkbase Document |
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* |
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filed herewith |
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** |
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furnished herewith |
II-2