Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
Date of report (Date of earliest event reported):
November 4, 2003
RANGE RESOURCES CORPORATION
(Exact name of registrant as specified in its charter)
| Delaware | 0-9592 | 34-1312571 | ||
|
|
||||
| (State or other jurisdiction of incorporation) |
(Commission File Number) |
(IRS Employer Identification No.) |
| 777 Main Street, Suite 800 | ||
| Ft. Worth, Texas | 76102 | |
|
|
||
| (Address of principal executive offices) | (Zip Code) |
Registrant’s telephone number, including area code: (817) 870-2601
(Former name or former address, if changed since last report): Not applicable
1
| ITEM 9. Regulation FD Disclosure. | ||||||||
| ITEM 7. Financial Statements and Exhibits. | ||||||||
| SIGNATURES | ||||||||
| EXHIBIT INDEX | ||||||||
| EX-99.1 Press Release | ||||||||
Table of Contents
ITEM 9. Regulation FD Disclosure.
On November 4, 2003, Range Resources Corporation issued a press release announcing its third quarter of 2003 results. A copy of the press release is being furnished as an exhibit to this report on Form 8-K.
ITEM 7. Financial Statements and Exhibits.
(c) Exhibits:
| 99.1 | Press Release dated November 4, 2003 |
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Table of Contents
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 hereunto duly authorized.
| RANGE RESOURCES CORPORATION | ||||
| By: | /s/ ROGER S. MANNY | |||
| Roger S. Manny Chief Financial Officer |
||||
Date: November 5, 2003
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Table of Contents
EXHIBIT INDEX
| Exhibit Number | Description | |
| 99.1 | Press Release dated November 4, 2003 |
4
NEWS RELEASE
RANGE PRODUCTION AND EARNINGS RISE
FORT WORTH, TEXAS, NOVEMBER 4, 2003...RANGE RESOURCES CORPORATION (NYSE: RRC) today reported third quarter results. Revenues in the quarter totaled $76.2 million, a 48% increase from the prior-year period. Cash flow from operations before changes in working capital rose 20% to $35.6 million as pretax income jumped 168% to $25.8 million. Net income totaled $16.7 million ($0.29 per share fully diluted), a 71% rise. During the period, drilling success led to rising production, debt fell to less than 50% of capitalization and the senior management team was completed.
The quarter’s financial results were significantly impacted by certain items, including an $18.6 million gain on debt retirement and a $2.4 million expense on the redemption of subordinated notes. Excluding such items, pretax income would have been $9.2 million, a 15% increase from the prior-year period. Net income would have been $6.0 million. In 2003, taxes are being recorded at a 35% rate due to increased profitability. In the prior year, tax benefits were recorded. (See table below for calculation of these non-GAAP measures.)
Production in the quarter rose 5.2% to an average of 159 Mmcfe per day, comprised of 120 Mmcf and 6,526 barrels. The growth was achieved through the ongoing exploitation of an extensive development drilling inventory and several meaningful discoveries. Wellhead prices, after hedging, averaged $3.81 per mcfe, a 10% increase. Gas prices rose 9% to $3.81 per mcf, as oil prices increased 8% to $23.76 per barrel. Hedging decreased realized prices by $0.94 per mcf and $3.66 a barrel.
Expenses in the period increased at a slower rate than revenues. Direct operating costs fell on a per unit basis to $0.55 per Mcfe from $0.61 in the prior period but rose $604,000 due to higher production taxes. Exploration expense increased $1.8 million principally due to additional seismic costs. General and administrative expenses rose $266,000 as a result of higher personnel costs and professional fees. Interest expense fell $516,000 due to lower outstanding debt. Depletion, depreciation and amortization expense increased $978,000 due to higher volumes. Accretion expense on asset retirement obligations totaled $1.2 million for the quarter, reflecting the impact of an accounting rule imposed in 2003. IPF expenses decreased $230,000 due to lower interest and administrative expenses. The provision for income taxes increased to $9.0 million, reflecting a full 35% rate and sharply higher pretax income. While increasing profitability now requires a full tax provision, no material cash taxes are expected to be paid in the foreseeable future.
During the third quarter, several material financing transactions were completed. In July, $100 million of ten year 7-3/8% senior subordinated notes were issued. Part of the proceeds was used to retire the remaining $68.8 million of 8-3/4% senior subordinated notes and to repurchase $9.9 million of other debt at a discount. The remainder was used to reduce bank debt. A one-time charge of $2.4 million was incurred in retiring the 8-3/4% notes. In September, $79.5 million of Trust Preferred was extinguished in exchange for $50 million of 5.9% convertible perpetual preferred stock and $10.2 million of cash. The Company recognized a gain on the retirement of $18.6 million ($12.1 million after-tax) in the third quarter. These transactions reduced ongoing financing cost by $4 million per year and extended the average maturity of the Company’s debt. At September 30, debt totaled $280 million, down $88 million since year-end. In the same period, stockholders’ equity increased $77 million due to the issuance of the $50 million of 5.9% preferred stock and $30.8 million of net income offset by $3.8 million of other items. At September 30, the Company’s debt to capitalization ratio had been reduced to 49.7%.
In the third quarter, the Company spent $28 million out of its $105 million 2003 capital budget. The expenditures funded the drilling of 105 (53.2 net) wells of which six (3.9 net) proved unproductive. During the first nine months of the year, 265 (147.8 net) wells were drilled at a cost of $77 million of which eleven (7.9 net) were dry. By September 30, 219 (121.0 net) of these wells had been placed on production, with the remaining wells being in various stages of completion or waiting on pipeline connection. During the quarter, $1.6 million was also spent on acquisitions, bringing the total for the
5
first three quarters to $8.0 million. Drilling activity in the fourth quarter will remain high, with 12 rigs running currently.
Drilling drove the 5.2% increase in production during the period. Two Canyon Sand wells in Sterling and Sutton counties were drilled to 6,700 feet and one Wolfcamp well in Glasscock County was drilled to 8,400 feet. These three wells are currently producing a total of 5.9 (2.8 net) Mmcfe a day. A previously drilled well was recompleted in the upper Strawn for 2.1 (1.6 net) Mmcfe per day. In the Texas Panhandle and western Oklahoma, three wells were drilled to the Morrow formation at approximately 9,000 feet. One was turned to production during the quarter at 1.5 (1.0 net) Mmcfe a day. Since September 30, the two remaining wells were turned on at a combined 4.2 (2.3 net) Mmcfe a day. Casing has been set to test two additional Panhandle wells, which should be completed shortly. In South Louisiana, the Villejoin #1 was completed as a successful offset to a discovery drilled late last year and is currently producing 12.2 (3.9 net) Mmcfe per day. In Appalachia, 76 (59.0 net) wells were successfully drilled in the third quarter.
Commenting, John H. Pinkerton, the Company’s President, noted, “The quarter was highlighted by three major events: the continuing success of our drilling program and rising production, the decline of our debt to capitalization to below 50% and the appointment of Roger Manny as Chief Financial Officer to complete our new management team. With a strong balance sheet, a revitalized management and a lower cost structure, we have significantly enhanced our ability to profitably grow through the drill bit while pursuing complementary acquisitions.”
The Company will host a conference call on Wednesday, November 5 at 2:00 p.m. ET to review its results. To participate, please dial 877-207-5526 about 5-10 minutes prior to the start of the call and ask for the Range Resources Third Quarter Conference Call. A simultaneous webcast of the call may be accessed over the Internet at www.rangeresources.com or www.vcall.com. The webcast will be archived for replay on the Company’s website for 60 days. A replay of the call will be available through November 12 at 800-642-1687. The conference ID is 3660107.
Non-GAAP Financial Measures:
Third quarter 2003 earnings include derivative ineffective hedging gains of $1.1 million, non-cash deferred compensation expense of $898,000, amortization of interest rate swap gains of $157,000, a $18.6 million gain on retirement of securities and a call premium and amortization write off of $2.4 million. Adjusting for the after-tax effect of these items, the Company’s earnings would have been $6.0 million in the third quarter 2003 or $0.11 per share ($0.10 per diluted share). If similar items were excluded, third quarter 2002 earnings would have been $8.2 million or $0.15 per share ($0.15 per diluted share). (See reconciliation of non-GAAP earnings in the table below.) The Company believes results excluding these items are more comparable to estimates provided by security analysts and, therefore, are useful in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. In addition, with the adoption effective January 1, 2003 of the new accounting rule regarding asset retirement obligations, the Company provided $1.2 million of accretion expense in the third quarter or $764,000 after tax ($0.01 per share) which was not similarly provided in the prior period.
Cash flow from operations before changes in working capital represents net cash provided by operations before changes in working capital adjusted for certain non-cash compensation items and the cash call premium and amortization write off of $2.4 million. Cash flow from operations before changes in working capital is widely accepted by the investment community as a financial indicator of an oil and gas company’s ability to generate cash to internally fund exploration and development activities and to service debt. Cash flow from operations before changes in working capital is also useful because it is
6
widely used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Cash flow from operations before changes in working capital is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operations, investing, or financing activities as an indicator of cash flows, or as a measure of liquidity. A table is included which reconciles net cash provided by operations to Cash flow from operations before changes in working capital as used in this release. On its website, the Company provides additional comparative information on prior periods.
RANGE RESOURCES CORPORATION (NYSE: RRC) is an independent oil and gas company operating in the Permian, Midcontinent, Appalachian and Gulf Coast regions of the United States.
2003-26
| Contact: | Rodney Waller, Senior Vice President | |||
| Karen Giles | ||||
| (817) 870-2601 | ||||
| www.rangeresources.com |
Except for historical information, statements made in this release, including those relating to future earnings, capital expenditures, production, expenses, and reserve replacement targets are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These statements are based on assumptions and estimates that management believes are reasonable based on currently available information; however, management’s assumptions and the Company’s future performance are subject to a wide range of business risks and uncertainties and there is no assurance that these goals and projections can or will be met. Any number of factors could cause actual results to differ materially from those in the forward-looking statements, including, but not limited to, the volatility of oil and gas prices, the costs and results of drilling and operations, the timing of production, mechanical and other inherent risks associated with oil and gas production, weather, the availability of drilling equipment, changes in interest rates, litigation, uncertainties about reserve estimates, and environmental risks. The Company undertakes no obligation to publicly update or revise any forward-looking statements. Further information on risks and uncertainties is available in the Company’s filings with the Securities and Exchange Commission, which are incorporated by reference.
7
RANGE RESOURCES CORPORATION
| STATEMENTS OF INCOME | ||||||||||||||||||||||||||||||||
| (In thousands, except per share data) | ||||||||||||||||||||||||||||||||
| (Unaudited) | Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||||||||||
| 2003 | 2002 | 2003 | 2002 | |||||||||||||||||||||||||||||
Revenues |
||||||||||||||||||||||||||||||||
Oil and gas sales |
$ | 55,723 | $ | 48,112 | $ | 165,326 | $ | 141,021 | ||||||||||||||||||||||||
Transportation and processing |
841 | 1,037 | 2,808 | 2,735 | ||||||||||||||||||||||||||||
IPF |
297 | 1,313 | 1,264 | 3,476 | ||||||||||||||||||||||||||||
Gain on retirement of securities |
18,572 | 1,050 | 18,712 | 3,080 | ||||||||||||||||||||||||||||
Ineffective hedging gain (loss) (a) |
1,093 | (419 | ) | (178 | ) | (2,581 | ) | |||||||||||||||||||||||||
Interest and other (a) |
(370 | ) | 294 | (84 | ) | (788 | ) | |||||||||||||||||||||||||
| 76,156 | 51,387 | 48 | % | 187,848 | 146,943 | 28 | % | |||||||||||||||||||||||||
Expenses |
||||||||||||||||||||||||||||||||
Direct operating |
11,120 | 10,516 | 36,792 | 29,658 | ||||||||||||||||||||||||||||
IPF expenses |
578 | 808 | 1,764 | 4,758 | ||||||||||||||||||||||||||||
Exploration |
3,633 | 1,814 | 8,773 | 9,257 | ||||||||||||||||||||||||||||
General and administrative |
4,595 | 4,329 | 13,457 | 12,212 | ||||||||||||||||||||||||||||
Non-cash deferred compensation adjustment (b) |
898 | (1,249 | ) | 2,195 | 71 | |||||||||||||||||||||||||||
Interest |
5,329 | 5,845 | 16,048 | 17,476 | ||||||||||||||||||||||||||||
Call premium and unamortized offering costs (c) |
2,376 | — | 2,376 | — | ||||||||||||||||||||||||||||
Debt conversion expense |
— | — | 465 | — | ||||||||||||||||||||||||||||
Accretion expense (d) |
1,175 | — | 3,446 | — | ||||||||||||||||||||||||||||
Depletion, depreciation and amortization |
20,694 | 19,716 | 60,666 | 57,120 | ||||||||||||||||||||||||||||
| 50,398 | 41,779 | 21 | % | 145,982 | 130,552 | 12 | % | |||||||||||||||||||||||||
Pretax income |
25,758 | 9,608 | 168 | % | 41,866 | 16,391 | 155 | % | ||||||||||||||||||||||||
Income taxes (benefit) |
||||||||||||||||||||||||||||||||
Current |
6 | 23 | 4 | 68 | ||||||||||||||||||||||||||||
Deferred |
9,015 | 363 | 15,571 | (4,550 | ) | |||||||||||||||||||||||||||
| 9,021 | 386 | 15,575 | (4,482 | ) | ||||||||||||||||||||||||||||
Income before accounting change |
16,737 | 9,222 | 81 | % | 26,291 | 20,873 | 26 | % | ||||||||||||||||||||||||
Cumulative effect of accounting change, net of tax |
— | — | 4,491 | — | ||||||||||||||||||||||||||||
Net income |
16,737 | 9,222 | 81 | % | 30,782 | 20,873 | 47 | % | ||||||||||||||||||||||||
Preferred stock dividends |
(65 | ) | — | (65 | ) | — | ||||||||||||||||||||||||||
Net income available to common shareholders |
$ | 16,672 | $ | 9,222 | 81 | % | $ | 30,717 | $ | 20,873 | 47 | % | ||||||||||||||||||||
Earnings per common share |
||||||||||||||||||||||||||||||||
Before accounting change |
||||||||||||||||||||||||||||||||
— basic |
$ | 0.31 | $ | 0.17 | 82 | % | $ | 0.49 | $ | 0.39 | 26 | % | ||||||||||||||||||||
— diluted |
$ | 0.29 | $ | 0.17 | 71 | % | $ | 0.47 | $ | 0.38 | 24 | % | ||||||||||||||||||||
After accounting change |
||||||||||||||||||||||||||||||||
— basic |
$ | 0.31 | $ | 0.17 | 82 | % | $ | 0.57 | $ | 0.39 | 46 | % | ||||||||||||||||||||
— diluted |
$ | 0.29 | $ | 0.17 | 71 | % | $ | 0.55 | $ | 0.38 | 45 | % | ||||||||||||||||||||
Weighted average shares outstanding, as reported |
||||||||||||||||||||||||||||||||
Basic |
54,415 | 53,448 | 2 | % | 54,151 | 52,924 | 2 | % | ||||||||||||||||||||||||
Diluted |
61,091 | 55,088 | 11 | % | 56,241 | 54,434 | 3 | % | ||||||||||||||||||||||||
| (a) | Included in Other revenues in 10-Q. | ||
| (b) | Included in General and administrative expenses in 10-Q. It is based upon increases (decreases) in Company’s stock price between periods. | ||
| (c) | Due to redeeming the 8.75% notes and included in Interest expense in 10-Q. | ||
| (d) | Applicable to the new accounting rule adopted on January 1, 2003 regarding asset retirement obligations. |
8
RANGE RESOURCES CORPORATION
OPERATING HIGHLIGHTS
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||||
| 2003 | 2002 | 2003 | 2002 | |||||||||||||||||||||||
Average Daily Production |
||||||||||||||||||||||||||
Oil (bbl) |
5,526 | 5,096 | 8 | % | 5,589 | 4,999 | 12 | % | ||||||||||||||||||
Natural gas liquids (bbl) |
1,000 | 1,186 | -16 | % | 1,056 | 1,125 | -6 | % | ||||||||||||||||||
Gas (mcf) |
120,005 | 113,555 | 6 | % | 117,284 | 113,627 | 3 | % | ||||||||||||||||||
Equivalents (mcfe) (a) |
159,162 | 151,246 | 5 | % | 157,155 | 150,367 | 5 | % | ||||||||||||||||||
Prices Realized |
||||||||||||||||||||||||||
Oil (bbl) |
$ | 23.76 | $ | 22.05 | 8 | % | $ | 23.51 | $ | 22.32 | 5 | % | ||||||||||||||
Natural gas liquids (bbl) |
$ | 17.64 | $ | 13.49 | 31 | % | $ | 18.76 | $ | 12.39 | 51 | % | ||||||||||||||
Gas (mcf) |
$ | 3.81 | $ | 3.48 | 9 | % | $ | 3.87 | $ | 3.44 | 13 | % | ||||||||||||||
Equivalents (mcfe) (a) |
$ | 3.81 | $ | 3.46 | 10 | % | $ | 3.85 | $ | 3.44 | 12 | % | ||||||||||||||
Operating Costs per mcfe |
||||||||||||||||||||||||||
Field expenses |
$ | 0.52 | $ | 0.57 | -9 | % | $ | 0.59 | $ | 0.53 | 11 | % | ||||||||||||||
Workovers |
0.03 | 0.04 | -25 | % | 0.04 | 0.04 | 0 | % | ||||||||||||||||||
Production/ad valorem
taxes |
0.21 | 0.15 | 40 | % | 0.23 | 0.15 | 53 | % | ||||||||||||||||||
Total Operating Costs |
$ | 0.76 | $ | 0.76 | 0 | % | $ | 0.86 | $ | 0.72 | 19 | % | ||||||||||||||
(a) Oil and natural gas liquids are converted to gas equivalents on a basis of six mcf per barrel.
BALANCE SHEETS
(In thousands)
| September 30, | December 31, | ||||||||||
| 2003 | 2002 | ||||||||||
| (Unaudited) | |||||||||||
Assets |
|||||||||||
Current assets |
$ | 48,646 | $ | 37,354 | |||||||
Current deferred tax asset |
14,956 | — | |||||||||
IPF receivables |
9,695 | 18,351 | |||||||||
Oil and gas properties |
640,808 | 564,406 | |||||||||
Transportation and field assets |
17,781 | 18,072 | |||||||||
Unrealized hedging gain and other |
4,663 | 20,301 | |||||||||
| $ | 736,549 | $ | 658,484 | ||||||||
Liabilities and Stockholders’ Equity |
|||||||||||
Current liabilities |
$ | 44,486 | $ | 41,171 | |||||||
Current asset retirement obligation |
8,335 | — | |||||||||
Current unrealized hedging loss |
31,849 | 26,035 | |||||||||
Senior debt |
94,300 | 115,800 | |||||||||
Nonrecourse debt of subsidiary |
71,500 | 76,500 | |||||||||
Subordinated notes |
112,656 | 90,901 | |||||||||
Trust preferred |
1,411 | 84,840 | |||||||||
Total long-term debt |
279,867 | 368,041 | |||||||||
Deferred taxes |
12,918 | — | |||||||||
Unrealized hedging loss |
15,783 | 9,079 | |||||||||
Deferred compensation liability |
12,732 | 8,049 | |||||||||
Long-term asset retirement obligation |
47,507 | — | |||||||||
Stockholders’ equity |
320,644 | 233,573 | |||||||||
Stock in deferred compensation plan |
(8,675 | ) | (6,313 | ) | |||||||
Other comprehensive loss |
(28,897 | ) | (21,151 | ) | |||||||
Total stockholder’s equity |
283,072 | 206,109 | |||||||||
| $ | 736,549 | $ | 658,484 | ||||||||
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RANGE RESOURCES CORPORATION
| CASH FLOWS FROM OPERATIONS | |||||||||||||||||||
| (Unaudited, in thousands) | Three Months Ended | Nine Months Ended | |||||||||||||||||
| September 30, | September 30, | ||||||||||||||||||
| 2003 | 2002 | 2003 | 2002 | ||||||||||||||||
Net income |
$ | 16,737 | $ | 9,222 | $ | 30,782 | $ | 20,873 | |||||||||||
Adjustments to reconcile net income to
net cash provided by operations: |
|||||||||||||||||||
Cumulative effect of change in accounting principle, net |
— | — | (4,491 | ) | — | ||||||||||||||
Deferred income tax expense (benefit) |
9,015 | 363 | 15,571 | (4,550 | ) | ||||||||||||||
Depletion, depreciation and amortization |
21,869 | 19,716 | 64,112 | 57,120 | |||||||||||||||
Exploration expense |
3,633 | 1,814 | 8,773 | 9,257 | |||||||||||||||
Write-down of marketable securities |
— | — | — | 1,220 | |||||||||||||||
Unrealized hedging (gains) losses |
(1,250 | ) | 681 | (62 | ) | 2,771 | |||||||||||||
Adjustment to IPF valuation allowance |
401 | 251 | 1,109 | 2,818 | |||||||||||||||
Amortization of deferred issuance costs and discount |
606 | 259 | 1,052 | 670 | |||||||||||||||
Gain on retirement of securities |
(19,152 | ) | (1,052 | ) | (19,292 | ) | (3,107 | ) | |||||||||||
Debt conversion expense |
— | — | 465 | — | |||||||||||||||
Deferred compensation adjustment |
997 | (1,199 | ) | 2,593 | 1,677 | ||||||||||||||
(Gain) loss on sale of assets |
275 | (266 | ) | 118 | (292 | ) | |||||||||||||
Changes in working capital: |
|||||||||||||||||||
Accounts receivable |
2,494 | 2,502 | (10,363 | ) | (1,009 | ) | |||||||||||||
Inventory and other |
(2,471 | ) | (1,922 | ) | (1,688 | ) | (1,366 | ) | |||||||||||
Accounts payable |
3,112 | 2,278 | 3,647 | 3,724 | |||||||||||||||
Accrued liabilities |
(256 | ) | 2,286 | 1,180 | (1,416 | ) | |||||||||||||
Net changes in working capital |
2,879 | 5,144 | (7,224 | ) | (67 | ) | |||||||||||||
Net cash provided by operations |
$ | 36,010 | $ | 34,933 | $ | 93,506 | $ | 88,390 | |||||||||||
| RECONCILIATION OF CASH FLOWS | |||||||||||||||||
| (In thousands, except per share data) | Three Months Ended | Nine Months Ended | |||||||||||||||
| September 30, | September 30, | ||||||||||||||||
| 2003 | 2002 | 2003 | 2002 | ||||||||||||||
Net cash provided by operations |
$ | 36,010 | $ | 34,933 | $ | 93,506 | $ | 88,390 | |||||||||
Net change in working capital |
(2,879 | ) | (5,144 | ) | 7,224 | 67 | |||||||||||
Call premium on 8.75% notes |
2,006 | — | 2,006 | — | |||||||||||||
Non-cash compensation adjustments and other |
481 | (49 | ) | 182 | (1,580 | ) | |||||||||||
Cash flow from operations before changes in working capital, non-GAAP measure |
$ | 35,618 | $ | 29,740 | $ | 102,918 | $ | 86,877 | |||||||||
ADJUSTED WEIGHTED AVERAGE SHARES OUTSTANDING
| Three Months Ended | Nine Months Ended | ||||||||||||||||
| September 30, | September 30, | ||||||||||||||||
| 2003 | 2002 | 2003 | 2002 | ||||||||||||||
Basic: |
|||||||||||||||||
Weighted average shares outstanding |
56,022 | 54,765 | 55,636 | 54,101 | |||||||||||||
Stock held by deferred compensation plan |
(1,607 | ) | (1,316 | ) | (1,485 | ) | (1,177 | ) | |||||||||
Adjusted basic |
54,415 | 53,449 | 54,151 | 52,924 | |||||||||||||
Dilutive: |
|||||||||||||||||
Weighted average shares outstanding |
56,022 | 54,765 | 55,636 | 54,101 | |||||||||||||
Dilutive stock options under treasury method |
517 | 323 | 433 | 333 | |||||||||||||
Dilutive effect of 6% debentures (dilutive when EPS over $0.19 per qtr) |
1,023 | — | — | — | |||||||||||||
Dilutive effect of 5.75% trust preferred (dilutive when EPS over $0.22 per qtr) |
3,017 | — | — | — | |||||||||||||
Dilutive effect of 5.9% preferred (dilutive when EPS over $0.12 per qtr) |
512 | — | 172 | — | |||||||||||||
Adjusted dilutive |
61,091 | 55,088 | 56,241 | 54,434 | |||||||||||||
10
RANGE RESOURCES CORPORATION
RECONCILATION OF NET INCOME BEFORE ACCOUNTING CHANGE
AS REPORTED TO NET INCOME BEFORE ACCOUNTING CHANGE
EXCLUDING CERTAIN ITEMS – NON-GAAP MEASURE
| Three Months Ended | Nine Months Ended | |||||||||||||||||
| September 30, | September 30, | |||||||||||||||||
| 2003 | 2002 | 2003 | 2002 | |||||||||||||||
Pretax income as reported |
25,758 | 9,608 | 41,866 | 16,391 | ||||||||||||||
Adjustment for certain items |
||||||||||||||||||
Gain on retirement of securities |
(18,572 | ) | (1,050 | ) | (18,712 | ) | (3,080 | ) | ||||||||||
Call premium and unamortized offering costs on 8.75% notes |
2,376 | — | 2,376 | — | ||||||||||||||
Ineffective commodity hedging (gain) loss |
(1,093 | ) | 419 | 178 | 2,581 | |||||||||||||
Amortization of ineffective interest hedges (gain) loss |
(157 | ) | 262 | (240 | ) | 190 | ||||||||||||
Deferred compensation adjustment |
898 | (1,249 | ) | 2,195 | 71 | |||||||||||||
Debt conversion expense |
— | — | 465 | — | ||||||||||||||
Pretax income as adjusted |
9,210 | 7,990 | 28,128 | 16,153 | ||||||||||||||
Income taxes (benefit) adjusted |
||||||||||||||||||
Current |
6 | 23 | 4 | 68 | ||||||||||||||
Deferred |
3,224 | (203 | ) | 10,762 | (4,633 | ) | ||||||||||||
Net income before accounting change excluding certain
items, a non-GAAP measure |
$ | 5,981 | $ | 8,170 | $ | 17,362 | $ | 20,718 | ||||||||||
Non-GAAP earnings per share before accounting change |
||||||||||||||||||
Basic |
$ | 0.11 | $ | 0.15 | $ | 0.32 | $ | 0.39 | ||||||||||
Diluted |
$ | 0.10 | $ | 0.15 | $ | 0.31 | $ | 0.38 | ||||||||||
| HEDGING POSITION | ||||||||||||||||||||
| As of November 4, 2003 | Gas | Oil | ||||||||||||||||||
| Volume | Average | Volume | Average | |||||||||||||||||
| Hedged | Hedge | Hedged | Hedged | |||||||||||||||||
| (MMBtu/d) | Prices | (Bbl/d) | Prices | |||||||||||||||||
4th Qtr 2003 |
Swaps | 95,929 | $ | 4.06 | 4,114 | $ | 25.03 | |||||||||||||
Calendar 2004 |
Swaps | 89,440 | $ | 4.05 | 2,378 | $ | 24.99 | |||||||||||||
Calendar 2004 |
Collars | 1,475 | $ | 4.50 - $5.47 | 2,128 | $ | 24.23 - $28.39 | |||||||||||||
Calendar 2005 |
Swaps | 48,945 | $ | 4.19 | 791 | $ | 24.79 | |||||||||||||
Calendar 2005 |
Collars | 8,123 | $ | 4.05 - $5.98 | 250 | $ | 24.00 - $26.70 | |||||||||||||
Calendar 2006 |
Swaps | 1,644 | $ | 4.80 | — | — | ||||||||||||||
11