Exhibit 99.1
Item 8, Annual Report on Form 10-K for the year ended December 31, 2007 — Financial Statements and Supplementary Data
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page(s) | ||||
Report of Independent Registered Public Accounting Firm | 2 | |||
Consolidated Balance Sheets as of December 31, 2007 and 2006 | 3 | |||
Consolidated Statements of Operations for the Years Ended December 31, 2007, 2006 and 2005 | 4 | |||
Consolidated Statements of Changes in Stockholders’ Equity for the Years Ended December 31, 2007, 2006 and 2005 | 5 | |||
Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006 and 2005 | 6 | |||
Notes to Consolidated Financial Statements | 7 |
Report of Independent Registered Public Accounting Firm
To the Board of Directors
and Stockholders of SandRidge Energy, Inc.
and Stockholders of SandRidge Energy, Inc.
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, changes in stockholders’ equity and of cash flows present fairly, in all material respects, the financial position of SandRidge Energy, Inc. and its subsidiaries at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
PricewaterhouseCoopers LLP
Houston, Texas
March 7, 2008, except for Note 24 to the consolidated financial statements, as to which the date is November 6, 2008.
March 7, 2008, except for Note 24 to the consolidated financial statements, as to which the date is November 6, 2008.
2
SandRidge Energy, Inc. and Subsidiaries
Consolidated Balance Sheets
Consolidated Balance Sheets
As of December 31, | ||||||||
2007 | 2006 | |||||||
(In thousands) | ||||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 63,135 | $ | 38,948 | ||||
Accounts receivable, net: | ||||||||
Trade | 94,741 | 89,774 | ||||||
Related parties | 20,018 | 5,731 | ||||||
Derivative contracts | 21,958 | — | ||||||
Inventories | 3,993 | 2,544 | ||||||
Deferred income taxes | 1,820 | 6,315 | ||||||
Other current assets | 20,787 | 31,494 | ||||||
Total current assets | 226,452 | 174,806 | ||||||
Oil and natural gas properties, using full cost method of accounting | ||||||||
Proved | 2,848,531 | 1,636,832 | ||||||
Unproved | 259,610 | 282,374 | ||||||
Less: accumulated depreciation and depletion | (230,974 | ) | (60,752 | ) | ||||
2,877,167 | 1,858,454 | |||||||
Other property, plant and equipment, net | 460,243 | 276,264 | ||||||
Derivative contracts | 270 | — | ||||||
Investments | 7,956 | 3,584 | ||||||
Restricted deposits | 31,660 | 33,189 | ||||||
Other assets | 26,818 | 42,087 | ||||||
Total assets | $ | 3,630,566 | $ | 2,388,384 | ||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
Current liabilities: | ||||||||
Current maturities of long-term debt | $ | 15,350 | $ | 26,201 | ||||
Accounts payable and accrued expenses: | ||||||||
Trade | 215,497 | 129,799 | ||||||
Related parties | 395 | 1,834 | ||||||
Asset retirement obligation | 864 | — | ||||||
Derivative contracts | — | 958 | ||||||
Total current liabilities | 232,106 | 158,792 | ||||||
Long-term debt | 1,052,299 | 1,040,630 | ||||||
Derivative contracts | — | 3,052 | ||||||
Other long-term obligations | 16,817 | 21,219 | ||||||
Asset retirement obligation | 57,716 | 45,216 | ||||||
Deferred income taxes | 49,350 | 24,922 | ||||||
Total liabilities | 1,408,288 | 1,293,831 | ||||||
Commitments and contingencies (Note 16) | ||||||||
Minority interest | 4,672 | 5,092 | ||||||
Redeemable convertible preferred stock, $0.001 par value, 2,625 shares authorized, 2,184 and 2,137 shares issued and outstanding at December 31, 2007 and 2006, respectively | 450,715 | 439,643 | ||||||
Stockholders’ equity: | ||||||||
Preferred stock, $0.001 par value; 47,375 shares authorized; no shares issued and outstanding in 2007 and 2006 | — | — | ||||||
Common stock, $0.001 par value, 400,000 shares authorized; 141,847 issued and 140,391 outstanding at December 31, 2007 and 93,048 issued and 91,604 outstanding at December 31, 2006 | 140 | 92 | ||||||
Additional paid-in capital | 1,686,113 | 574,868 | ||||||
Treasury stock, at cost | (18,578 | ) | (17,835 | ) | ||||
Retained earnings | 99,216 | 92,693 | ||||||
Total stockholders’ equity | 1,766,891 | 649,818 | ||||||
Total liabilities and stockholders’ equity | $ | 3,630,566 | $ | 2,388,384 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
3
SandRidge Energy, Inc. and Subsidiaries
Consolidated Statements of Operations
Years Ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
(In thousands, except per share amounts) | ||||||||||||
Revenues: | ||||||||||||
Natural gas and crude oil | $ | 477,612 | $ | 101,252 | $ | 49,987 | ||||||
Drilling and services | 73,197 | 139,049 | 80,343 | |||||||||
Midstream and marketing | 107,765 | 122,896 | 147,133 | |||||||||
Other | 18,878 | 25,045 | 10,230 | |||||||||
Total revenues | 677,452 | 388,242 | 287,693 | |||||||||
Expenses: | ||||||||||||
Production | 106,192 | 35,149 | 16,195 | |||||||||
Production taxes | 19,557 | 4,654 | 3,158 | |||||||||
Drilling and services | 44,211 | 98,436 | 52,122 | |||||||||
Midstream and marketing | 94,253 | 115,076 | 141,372 | |||||||||
Depreciation, depletion and amortization — natural gas and crude oil | 173,568 | 26,321 | 9,313 | |||||||||
Depreciation, depletion and amortization — other | 53,541 | 29,305 | 14,893 | |||||||||
General and administrative | 61,780 | 55,634 | 11,908 | |||||||||
(Gain) loss on derivative contracts | (60,732 | ) | (12,291 | ) | 4,132 | |||||||
(Gain) loss on sale of assets | (1,777 | ) | (1,023 | ) | 547 | |||||||
Total expenses | 490,593 | 351,261 | 253,640 | |||||||||
Income from operations | 186,859 | 36,981 | 34,053 | |||||||||
Other income (expense): | ||||||||||||
Interest income | 5,423 | 1,109 | 206 | |||||||||
Interest expense | (117,185 | ) | (16,904 | ) | (5,277 | ) | ||||||
Minority interest | 276 | (296 | ) | (737 | ) | |||||||
Income (loss) from equity investments | 4,372 | 967 | (384 | ) | ||||||||
Total other income (expense) | (107,114 | ) | (15,124 | ) | (6,192 | ) | ||||||
Income before income tax expense | 79,745 | 21,857 | 27,861 | |||||||||
Income tax expense | 29,524 | 6,236 | 9,968 | |||||||||
Income from continuing operations | 50,221 | 15,621 | 17,893 | |||||||||
Income from discontinued operations (net of tax expense of $118 in 2005) | — | — | 229 | |||||||||
Net income | 50,221 | 15,621 | 18,122 | |||||||||
Preferred stock dividends and accretion | 39,888 | 3,967 | — | |||||||||
Income available to common stockholders | 10,333 | $ | 11,654 | $ | 18,122 | |||||||
Basic and Diluted Earnings Per Share: | ||||||||||||
Income from continuing operations | $ | 0.46 | $ | 0.21 | $ | 0.31 | ||||||
Income from discontinued operations, net of income tax | — | — | 0.01 | |||||||||
Preferred dividends | (0.37 | ) | (0.05 | ) | — | |||||||
Basic and diluted income per share available to common stockholders | $ | 0.09 | $ | 0.16 | $ | 0.32 | ||||||
Weighted average number of common shares outstanding: | ||||||||||||
Basic | 108,828 | 73,727 | 56,559 | |||||||||
Diluted | 110,041 | 74,664 | 56,737 | |||||||||
The accompanying notes are an integral part of these consolidated financial statements.
4
SandRidge Energy, Inc. and Subsidiaries
Consolidated Statements of Changes in Stockholders’ Equity
Additional | ||||||||||||||||||||||||||||
Preferred | Common | Paid-In | Deferred | Treasury | Retained | |||||||||||||||||||||||
Stock | Stock | Capital | Compensation | Stock | Earnings | Total | ||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||
Balance, December 31, 2004 | $ | 23 | $ | 200 | $ | — | $ | — | $ | — | $ | 59,108 | $ | 59,331 | ||||||||||||||
Exchange of preferred stock for common stock | (23 | ) | 1 | 22 | — | — | — | — | ||||||||||||||||||||
Purchase of treasury shares | — | (5 | ) | — | — | (17,335 | ) | — | (17,340 | ) | ||||||||||||||||||
Stock split (change in par value) | — | (141 | ) | 141 | — | — | — | — | ||||||||||||||||||||
Issuance of stock in acquisitions | — | 4 | 55,281 | — | — | — | 55,285 | |||||||||||||||||||||
Stock offering, net of $18.0 million in offering costs | — | 12 | 173,110 | — | — | — | 173,122 | |||||||||||||||||||||
Restricted shares | — | 2 | 15,366 | (15,366 | ) | — | — | 2 | ||||||||||||||||||||
Amortization of deferred compensation | — | — | — | 481 | — | — | 481 | |||||||||||||||||||||
Net income | — | — | — | — | — | 18,122 | 18,122 | |||||||||||||||||||||
Dividends on preferred stock | — | — | — | — | — | (1 | ) | (1 | ) | |||||||||||||||||||
Balance, December 31, 2005 | — | 73 | 243,920 | (14,885 | ) | (17,335 | ) | 77,229 | 289,002 | |||||||||||||||||||
Stock offering | — | — | 3,343 | — | — | — | 3,343 | |||||||||||||||||||||
Change in accounting principle for stock-based compensation | — | — | (14,885 | ) | 14,885 | — | — | — | ||||||||||||||||||||
Issuance of stock in acquisitions | — | 13 | 236,271 | — | — | — | 236,284 | |||||||||||||||||||||
Stock offering, net of $3.9 million in offering costs | — | 6 | 97,427 | — | — | 97,433 | ||||||||||||||||||||||
Stock-based compensation | — | — | 8,792 | — | — | — | 8,792 | |||||||||||||||||||||
Accretion on redeemable convertible preferred stock | — | — | — | — | — | (157 | ) | (157 | ) | |||||||||||||||||||
Purchase of treasury shares | — | — | — | — | (500 | ) | — | (500 | ) | |||||||||||||||||||
Net income | — | — | — | — | — | 15,621 | 15,621 | |||||||||||||||||||||
Balance, December 31, 2006 | — | 92 | 574,868 | — | (17,835 | ) | 92,693 | 649,818 | ||||||||||||||||||||
Stock offerings, net of $4.5 million in offering costs | — | 50 | 1,113,314 | — | — | — | 1,113,364 | |||||||||||||||||||||
Conversion of common stock to redeemable convertible preferred stock | — | (1 | ) | (9,650 | ) | — | — | — | (9,651 | ) | ||||||||||||||||||
Accretion on redeemable convertible preferred stock | — | — | — | — | — | (1,421 | ) | (1,421 | ) | |||||||||||||||||||
Purchase of treasury stock | — | (1 | ) | — | — | (1,660 | ) | — | (1,661 | ) | ||||||||||||||||||
Common stock issued under retirement plan | — | — | 379 | — | 917 | — | 1,296 | |||||||||||||||||||||
Stock-based compensation | — | — | 7,202 | — | — | — | 7,202 | |||||||||||||||||||||
Net income | — | — | — | — | — | 50,221 | 50,221 | |||||||||||||||||||||
Redeemable convertible preferred stock dividend | — | — | — | — | — | (42,277 | ) | (42,277 | ) | |||||||||||||||||||
Balance, December 31, 2007 | $ | — | $ | 140 | $ | 1,686,113 | $ | — | $ | (18,578 | ) | $ | 99,216 | $ | 1,766,891 | |||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
5
SandRidge Energy, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
Years Ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
(In thousands) | ||||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||||||||
Net income | $ | 50,221 | $ | 15,621 | $ | 18,122 | ||||||
Income from discontinued operations, net of tax | — | — | 229 | |||||||||
Income from continuing operations | 50,221 | 15,621 | 17,893 | |||||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||
Provision for doubtful accounts | — | 2,528 | 33 | |||||||||
Depreciation, depletion and amortization | 227,109 | 55,626 | 24,206 | |||||||||
Debt issuance cost amortization | 15,998 | 299 | — | |||||||||
Deferred income taxes | 28,923 | 348 | 9,460 | |||||||||
Provision for inventory obsolescence | 203 | — | — | |||||||||
Unrealized (gain) loss on derivatives | (26,238 | ) | 1,878 | 1,296 | ||||||||
(Income) loss on sale of assets | (1,777 | ) | (1,023 | ) | 547 | |||||||
Interest income — restricted deposits | (1,354 | ) | (151 | ) | — | |||||||
(Gain) loss from equity investments, net of distributions | (4,372 | ) | (956 | ) | 846 | |||||||
Stock-based compensation | 7,202 | 8,792 | 481 | |||||||||
Minority interest | (276 | ) | 296 | 737 | ||||||||
Changes in operating assets and liabilities increasing (decreasing) cash: | ||||||||||||
Receivables | (19,061 | ) | (2,648 | ) | (25,494 | ) | ||||||
Inventories | (1,730 | ) | (938 | ) | (46 | ) | ||||||
Other current assets | 12,374 | (22,238 | ) | (1,146 | ) | |||||||
Other assets and liabilities, net | (5,069 | ) | (2,131 | ) | 775 | |||||||
Accounts payable and accrued expenses | 75,299 | 12,046 | 33,709 | |||||||||
Net cash provided by operating activities by continuing operations | 357,452 | 67,349 | 63,297 | |||||||||
Net cash provided by operating activities by discontinued operations | — | — | 347 | |||||||||
Net cash provided by operating activities | 357,452 | 67,349 | 63,644 | |||||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||||||
Capital expenditures for property, plant and equipment | (1,280,848 | ) | (306,541 | ) | (134,596 | ) | ||||||
Acquisitions of assets, net of cash received of $0, $21,100 and $66 | (116,650 | ) | (1,054,075 | ) | (21,247 | ) | ||||||
Proceeds from sale of assets | 9,034 | 19,742 | 3,327 | |||||||||
Proceeds from sale of investments | — | 2,373 | 413 | |||||||||
Contributions on equity investments | — | (3,388 | ) | (1,350 | ) | |||||||
Refunds of restricted deposits | 10,328 | — | — | |||||||||
Fundings of restricted deposits | (7,445 | ) | (1,051 | ) | — | |||||||
Restricted cash | — | 2,373 | (2,373 | ) | ||||||||
Net cash used in investing activities for continuing operations | (1,385,581 | ) | (1,340,567 | ) | (155,826 | ) | ||||||
Net cash used in investing activities for discontinued operations | — | — | (1,473 | ) | ||||||||
Net cash used in investing activities | (1,385,581 | ) | (1,340,567 | ) | (157,299 | ) | ||||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||||||
Proceeds from borrowings | 1,331,541 | 1,261,910 | 247,460 | |||||||||
Repayments of borrowings | (1,332,219 | ) | (518,870 | ) | (301,285 | ) | ||||||
Dividends paid-preferred | (33,321 | ) | — | (1 | ) | |||||||
Minority interests contributions (distributions) | (144 | ) | (618 | ) | 7,117 | |||||||
Proceeds from issuance of common stock | 1,114,660 | 100,776 | 173,122 | |||||||||
Proceeds from issuance of redeemable convertible preferred stock | — | 439,486 | — | |||||||||
Purchase of treasury shares | (1,661 | ) | (500 | ) | — | |||||||
Debt issuance costs | (26,540 | ) | (15,749 | ) | — | |||||||
Net cash provided by financing activities for continuing operations | 1,052,316 | 1,266,435 | 126,413 | |||||||||
Net cash provided by financing activities for discontinued operations | — | — | — | |||||||||
Net cash provided by financing activities | 1,052,316 | 1,266,435 | 126,413 | |||||||||
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | 24,187 | (6,783 | ) | 32,758 | ||||||||
CASH AND CASH EQUIVALENTS, beginning of year | 38,948 | 45,731 | 12,973 | |||||||||
CASH AND CASH EQUIVALENTS, end of year | $ | 63,135 | $ | 38,948 | $ | 45,731 | ||||||
Supplemental Disclosure of Cash Flow Information: | ||||||||||||
Cash paid for interest, net of amounts capitalized | $ | 83,567 | $ | 15,079 | $ | 7,222 | ||||||
Cash paid for income taxes | 2,371 | 1,599 | — | |||||||||
Supplemental Disclosure of Noncash Investing and Financing Activities: | ||||||||||||
Redeemable convertible preferred stock dividends, net of dividends paid | $ | 8,956 | $ | — | $ | — | ||||||
Insurance premium financed | 1,496 | 5,023 | 2,133 | |||||||||
Accretion on redeemable convertible preferred stock | 1,421 | 157 | — | |||||||||
Common stock issued in connection with acquisitions | — | 236,284 | 55,285 | |||||||||
Assumption of restricted deposits and notes payable in connection with acquisition | — | 313,628 | — | |||||||||
Assets disposed in exchange for common stock | — | — | 17,335 |
The accompanying notes are an integral part of these consolidated financial statements.
6
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
1. Summary of Significant Accounting Policies
Nature of Business.SandRidge Energy, Inc. and its subsidiaries (formerly known as Riata Energy, Inc.) (collectively, the “Company” or “SandRidge”) is an oil and gas company with its principal focus on exploration, development and production related to oil and gas activities. SandRidge also owns and operates drilling rigs and provides related oil field services, midstream gas services operations, and CO(2) and tertiary oil recovery operations. SandRidge’s primary exploration, development and production areas are concentrated in West Texas. The Company also operates significant interests in the Cotton Valley Trend in East Texas, Gulf Coast area, the Gulf of Mexico, Oklahoma, and the Piceance Basin in Colorado.
On November 21, 2006, the Company acquired all of the outstanding membership interests of NEG Oil & Gas LLC (“NEG”) (See Note 2).
Principles of Consolidation.The consolidated financial statements include the accounts of SandRidge Energy, Inc. and its wholly owned or majority owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.
Reclassifications.Certain reclassifications have been made in prior period financial statements to conform with current period presentation.
Use of Estimates.The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Estimates of oil and natural gas reserves and their values, future production rates and future costs and expenses are inherently uncertain for numerous reasons, including many factors beyond the Company’s control. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploitation and development activities, prevailing commodity prices, operating costs and other factors. These revisions may be material and could materially affect the Company’s future depletion, depreciation and amortization expenses.
The Company’s revenue, profitability, and future growth are substantially dependent upon the prevailing and future prices for oil and natural gas, which are dependent upon numerous factors beyond its control such as economic, regulatory developments and competition from other energy sources. The energy markets have historically been volatile and there can be no assurance that oil and natural gas prices will not be subject to wide fluctuations in the future. A substantial or extended decline in oil and natural gas prices could have a material adverse effect on the Company’s financial position, results of operations, cash flows and quantities of oil and natural gas reserves that may be economically produced.
Cash and Cash Equivalents.The Company considers all highly-liquid instruments with a maturity of three months or less when purchased to be cash equivalents. Those securities are readily convertible to known amounts of cash and bear insignificant risk of changes in value due to their short maturity period.
Restricted Cash.Restricted cash of approximately $2.4 million at December 31, 2005 was pledged as collateral on certain bank debt. The restriction was released in April 2006.
Accounts Receivable, Net.The Company has receivables for sales of oil, gas and natural gas liquids, as well as receivables related to the exploration and extraction services for oil, gas and natural gas liquids. Management has established an allowance for doubtful accounts. The allowance is evaluated by management and is based on management’s periodic review of the collectibility of the receivables in light of historical experience, the nature and volume of the receivables, and other subjective factors.
Inventories.Inventories consist of oil field services supplies and are stated at the lower of cost or market with cost determined on an average cost basis.
7
Debt Issue Costs.The Company amortizes debt issue costs related to its senior credit facility, senior bridge facility and term loans as interest expense over the scheduled maturity period of the debt. Unamortized debt issuance costs were approximately $26.0 million as of December 31, 2007 and approximately $15.5 million as of December 31, 2006. The Company includes those unamortized costs in other assets.
Revenue Recognition and Gas Balancing.Oil and natural gas revenues are recorded when title passes to the customer, net of royalties, discounts and allowances, as applicable. The Company accounts for oil and natural gas production imbalances using the sales method, whereby the Company recognizes revenue on all oil and natural gas sold to its customers notwithstanding the fact that its ownership may be less than 100% of the oil and natural gas sold. Liabilities are recorded by the Company for imbalances greater than the Company’s proportionate share of remaining estimated oil and natural gas reserves. The Company has recorded a liability for gas imbalance positions related to gas properties with insufficient proved reserves of $1.6 million and $0.9 million at December 31, 2007 and 2006, respectively. The Company includes the gas imbalance positions in other long-term obligations.
The Company recognizes revenues and expenses generated from “daywork” drilling contracts as the services are performed, because the Company does not bear the risk of completion of the well. Under “footage” and “turnkey” contracts, the Company bears the risk of completion of the well; therefore, revenues and expenses are recognized when the well is substantially completed. Under this method, substantial completion is determined when the well bore reaches the negotiated depth as stated in the contract. The duration of all three types of contracts ranges typically from 20 to 90 days. The entire amount of a loss, if any, is recorded when the loss is determinable. The costs of uncompleted drilling contracts include expenses incurred to date on “turnkey” contracts that are still in process at the end of the period.
The Company may receive lump-sum fees for the mobilization of equipment and personnel. Mobilization fees received and costs incurred to mobilize a rig from one market to another are recognized over the term of the related drilling contract. The contract terms are typically from 20 to 90 days.
Revenues from the midstream services segment are derived from providing gathering, compression, treating, processing, transportation, balancing and sales services for producers and wholesale customers on natural gas pipelines, as well as other interconnected pipeline systems. Midstream gas services are primarily undertaken to realize incremental margins on gas purchased at the wellhead, and provide value-added services to customers. In general, natural gas purchased and sold by the midstream gas business is priced at a published daily or monthly index price. Sales to wholesale customers typically incorporate a premium for managing their transmission and balancing requirements. Revenues are recognized upon delivery of natural gas to customers and/or when services are rendered, pricing is determinable and collectibility is reasonably assured.
Revenue from sales of CO(2) is recognized when the product is delivered to the customer. The Company recognizes service fees related to the transportation of CO(2) as revenue when the related service is provided.
Environmental Costs.Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not have future economic benefit, are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and costs can be reasonably estimated. Environmental costs accrued at December 31, 2007 and 2006 were not material.
Oil and Natural Gas Operations.The Company uses the full cost method to account for its natural gas and oil properties. Under full cost accounting, all costs directly associated with the acquisition, exploration and development of natural gas and oil reserves are capitalized into a “full cost pool.” These capitalized costs include costs of all unproved properties, internal costs directly related to the Company’s acquisition, exploration and development activities and capitalized interest. During 2007, the Company capitalized internal costs and interest expenses of $4.6 million and $0.3 million, respectively, to the full cost pool. No internal costs or interest expense was capitalized to the full cost pool in 2006 or 2005.
Capitalized costs are amortized using a unit-of-production method. Under this method, the provision for depreciation, depletion and amortization is computed at the end of each quarter by multiplying total production for such quarter by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the quarter.
Costs associated with unproved properties are excluded from the total unamortized cost base until a determination has been made as to the existence of proved reserves. Unproved properties are reviewed at the end of each quarter to determine whether the costs
8
incurred should be reclassified to the full cost pool and, thereby, subject to amortization. Sales and abandonments of natural gas and oil properties being amortized are accounted for as adjustments to the full cost pool, with no gain or loss recognized, unless the adjustments would significantly alter the relationship between capitalized costs and proved natural gas and oil reserves. A significant alteration would not ordinarily be expected to occur upon the sale of reserves involving less than 25% of the reserve quantities of a cost center.
Under full cost accounting, total capitalized costs of natural gas and oil properties (net of accumulated depreciation, depletion and amortization) less related deferred income taxes may not exceed an amount equal to the present value of future net revenues from proved reserves, discounted at 10% per annum, plus the lower of cost or fair value of unevaluated properties, plus estimated salvage value, less income tax effects (the “ceiling limitation”). A ceiling limitation calculation is performed at the end of each quarter. If total capitalized costs (net of accumulated depreciation, depletion and amortization) less related deferred taxes are greater than the ceiling limitation, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts stockholders’ equity in the period of occurrence and typically results in lower depreciation, depletion and amortization expense in future periods. Once incurred, a write-down is not reversible at a later date.
The ceiling test is calculated using natural gas and oil prices in effect as of the balance sheet date, as adjusted for “basis” or location differentials as of the balance sheet date and held constant over the life of the reserves (“net wellhead prices”). If applicable, these net wellhead prices would be further adjusted to include the effects of any fixed price arrangements for the sale of natural gas and oil. The Company may, from time-to-time, use derivative financial instruments to hedge against the volatility of natural gas prices. Derivative contracts that qualify and are designated as cash flow hedges are included in estimated future cash flows. Historically, the Company has not designated any of its derivative contracts as cash flow hedges. In addition, the future cash outflows associated with future development or abandonment of wells are included in the computation of the discounted present value of future net revenues for purposes of the ceiling test calculation.
The costs associated with unproved properties are not initially included in the amortization base and relate to unproved leasehold acreage, wells and production facilities in progress and wells pending determination of the existence of proved reserves, together with capitalized interest costs for these projects. Unproved leasehold costs are transferred to the amortization base with the costs of drilling the related well once a determination of the existence of proved reserves has been made or upon impairment of a lease. Costs of seismic data are allocated to various unproved leaseholds and transferred to the amortization base with the associated leasehold costs on a specific project basis. Costs associated with wells in progress and completed wells that have yet to be evaluated are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. Costs of dry holes are transferred to the amortization base immediately upon determination that the well is unsuccessful.
All items classified as unproved property are assessed on a quarterly basis for possible impairment or reduction in value. Properties are assessed on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.
Property, Plant and Equipment, Net.Other capitalized costs, including drilling equipment, natural gas gathering and processing equipment, transportation equipment and other property and equipment are carried at cost. Renewals and improvements are capitalized while repairs and maintenance are expensed. Depreciation of drilling equipment is recorded using the straight-line method based on estimated useful lives. Depreciation of other property and equipment is computed using the straight-line method over the estimated useful lives of the assets ranging from 3 to 39 years.
Realization of the carrying value of property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset including disposal value if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. An estimate of fair value is based on the best information available, including prices for similar assets. Changes in such estimates could cause the Company to reduce the carrying value of property and equipment.
When property and equipment components are disposed of, the cost and the related accumulated depreciation are removed from the accounts and any resulting gain or loss is generally reflected in operations.
9
Investments.Investments in affiliated companies are accounted for under the cost or equity method, based on the Company’s ability to exercise significant influence.
Asset Retirement Obligation.The Company owns oil and natural gas properties which require expenditures to plug and abandon the wells when the oil and natural gas reserves in the wells are depleted. These expenditures are recorded in the period in which the liability is incurred (at the time the wells are drilled or acquired). Asset retirement obligations are recorded as a liability at their estimated present value at the asset’s inception, with the offsetting increase to property cost. Periodic accretion expense of the estimated liability is recorded in the statements of operations.
Asset retirement obligations primarily represent the Company’s estimate of fair value to plug, abandon and remediate the oil and natural gas properties at the end of their productive lives, in accordance with applicable state laws. The Company has determined its asset retirement obligations by calculating the present value of estimated expenses related to the liability. Estimating the future asset retirement obligations requires management to make estimates and judgments regarding timing, existence of a liability, and what constitutes adequate restoration. Inherent in the present value calculation rates, are the timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligations liability, a corresponding adjustment is made to the related asset. The following is a reconciliation of the asset retirement obligation for the years ended December 31 (in thousands).
2007 | 2006 | 2005 | ||||||||||
Asset retirement obligation, January 1 | $ | 45,216 | $ | 6,979 | $ | 4,394 | ||||||
Liability incurred upon acquiring and drilling wells | 3,265 | 2,996 | 2,779 | |||||||||
NEG acquisition | — | 40,343 | — | |||||||||
Revisions in estimated cash flows | 5,971 | (5,700 | ) | — | ||||||||
Liability settled in current period | (9 | ) | — | (512 | ) | |||||||
Accretion of discount expense | 4,137 | 598 | 318 | |||||||||
Asset retirement obligation, December 31 | 58,580 | 45,216 | 6,979 | |||||||||
Less: current portion | 864 | — | — | |||||||||
Asset retirement obligation, net of current | $ | 57,716 | $ | 45,216 | $ | 6,979 | ||||||
Income Taxes.Deferred income taxes are provided on temporary differences between financial statement and income tax reporting. Temporary differences are differences between the amounts of assets and liabilities reported for financial statement purposes and their tax bases. Deferred tax assets are recognized for temporary differences that will be deductible in future years’ tax returns and for operating loss and tax credit carryforwards. Deferred tax assets are reduced by a valuation allowance if it is deemed more likely than not that some or all of the deferred tax assets will not be realized. Deferred tax liabilities are recognized for temporary differences that will be taxable in future years’ tax returns.
The Company accounts for uncertain tax positions in accordance with FASB Interpretation No. 48 (“FIN 48), “Accounting for Uncertainty in Income Taxes”. Accordingly, the Company reports a liability for unrecognized tax benefits resulting from uncertain tax positions taken or expected to be taken in a tax return. The Company recognizes interest and penalties, if any, related to unrecognized tax benefits in income tax expense.
Minority Interest.As of December 31, 2007, minority interest in the Company’s consolidated subsidiaries consisted of the following:
• | 26.19% interest in Sagebrush Pipeline, LLC; and | ||
• | 1.29% interest in Cholla Pipeline, LP. |
Concentration of Risk.The Company maintains cash balances at several banks. Accounts at each institution are insured by the Federal Deposit Insurance Corporation up to $100,000. From time to time, the Company may have balances in these accounts that exceed the federally insured limit. The Company does not anticipate any loss associated with balances in excess of the federally insured limit.
Fair Value of Financial Instruments.For certain of the Company’s financial instruments, including cash, accounts receivable and accounts payable, the carrying value approximates fair value because of their short maturity. The carrying value of borrowings under the senior credit facility and the notes payable approximates fair value because their interest rates are based on market indexes. The fair value of the fixed portion of the Company’s senior credit facility and convertible preferred stock approximate book value as reflected in the accompanying balance sheets.
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Derivative Financial Instruments.To manage risks related to increases in interest rates and changes in oil and gas prices, the Company occasionally enters into interest rate swaps and oil and gas derivatives contracts.
The Company recognizes all of its derivative instruments as either assets or liabilities at fair value. The accounting for changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship, and further, on the type of hedging relationship. For those derivative instruments that are designated and qualify as hedging instruments, the Company designates the hedging instrument, based on the exposure being hedged, as either a fair value hedge or a cash flow hedge. For derivative instruments not designated as hedging instruments, the gain or loss is recognized in current earnings during the period of change. None of the Company’s derivatives were designated as hedging instruments during 2007, 2006 and 2005.
Stock-Based Compensation.Effective January 1, 2006, the Company adopted SFAS No. 123-R, “Share-Based Payment” (“SFAS 123R”). SFAS 123R establishes the accounting for equity instruments exchanged for employee services. Under SFAS 123R, share-based compensation cost is measured at the grant date based on the calculated fair value of the award. The expense is recognized over the employees’ requisite service period, generally the vesting period of the award. SFAS 123R also requires the related excess tax benefit received upon exercise of stock options or vesting of restricted stock, if any, to be reflected in the statement of cash flows as a financing activity rather than an operating activity. The Company does not have any excess tax benefits.
Recent Accounting Pronouncements.In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which establishes a formal framework for measuring fair values of assets and liabilities in financial statements that are already required by U.S generally accepted accounting principles to be measured at fair value. SFAS No. 157 clarifies guidance in FASB Concepts Statement No. 7 which discusses present value techniques in measuring fair value. Additional disclosures are also required for transactions measured at fair value. No new fair value measurements are prescribed, and SFAS No. 157 is intended to codify the several definitions of fair value included in various accounting standards. However, the application of this Statement may change current practices for certain companies. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. The Company will implement SFAS No. 157 on January 1, 2008. The Company continues to evaluate the impact of SFAS No. 157 on the consolidated financials statements.
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option For Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115”, which permits an entity to choose to measure certain financial assets and liabilities at fair value. SFAS No. 159 also revises provisions of SFAS No. 115 that apply to available-for-sale and trading securities. This statement is effective for fiscal years beginning after November 15, 2007. We do not believe the adoption of SFAS No. 159 will have a material impact on our consolidated financial position, results of operations, or cash flows.
In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations”, which replaces SFAS No. 141. SFAS No. 141(R) establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any noncontrolling interest in the acquiree and the goodwill acquired. The Statement also establishes disclosure requirements which will enable users to evaluate the nature and financial effects of the business combination. SFAS No. 141(R) is effective for fiscal years beginning after December 15, 2008. The Company plans to implement this standard on January 1, 2009. The Company has not yet evaluated the potential impact of this standard.
In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment of Accounting Research Bulletin No. 51”, which establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, changes in a parent’s ownership interest and the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated. The Statement also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. SFAS No. 160 is effective for fiscal years beginning after December 15, 2008. The Company plans to implement this standard on January 1, 2009. The Company has not evaluated the potential impact of this standard.
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2. Acquisitions and Dispositions
2005 Acquisitions
The Company closed the following acquisitions in 2005:
• | Acquired additional equity interests in PetroSource Energy Company, LLC (“PetroSource”), which increased the Company’s ownership from 22.4% to 86.5%, resulting in the consolidation of PetroSource in the Company’s financial statements; | ||
• | Acquired from an executive officer and director the remaining 50% equity interest in the Company’s compression services subsidiary, Lariat Compression Company (“Larco”), resulting in it becoming a wholly-owned subsidiary; | ||
• | Acquired from an executive officer and director approximately 7,400 net acres of additional leasehold interest in West Texas in properties in which the Company previously held interests; | ||
• | Acquired approximately 2,503 net acres additional leasehold interest in property in the Piceance Basin in which the Company previously held interests; | ||
• | Acquired from a director additional working interests in Missouri and Nevada leases in which the Company previously held interests; | ||
• | Acquired an additional 19.5% before pay-out interest in the Company’s subsidiary, Sagebrush Pipeline LLC; and | ||
• | Acquired certain interests in several oil and natural gas properties in West Texas from Carl E. Gungoll Exploration, LLC and certain other parties. The purchase price was approximately $8.0 million, comprised of $5.4 million in cash, and 174,833 shares of common stock (valued at $2.6 million). |
The acquisitions were financed with approximately $21.3 million in cash and the issuance of 3,685,690 shares of common stock with an aggregate value of approximately $55.3 million. Details are set forth below for each of the acquisition transactions (in thousands):
Addition to | Consideration Paid | |||||||||||||||||||||||||||
Property, | Elimination | Change in | Common | Common | Cash, Net | |||||||||||||||||||||||
Plant & | Addition to Net | of | Minority | Stock No. | Stock at | of Cash | ||||||||||||||||||||||
Acquisition Transaction | Equipment | Assets(1) | Investments | Interest | of Shares | $15/Share | Acquired | |||||||||||||||||||||
PetroSource additional interests | $ | 73,744 | $ | (37,381 | ) | $ | (3,052 | ) | $ | 3,253 | 958 | $ | 14,372 | $ | 15,686 | |||||||||||||
Larco remaining interest | 5,054 | — | — | (2,446 | ) | 500 | 7,500 | — | ||||||||||||||||||||
West Texas additional lease interests | 10,000 | — | — | — | 667 | 10,000 | — | |||||||||||||||||||||
Piceance Basin additional interests | 17,565 | — | — | — | 1,164 | 17,456 | 109 | |||||||||||||||||||||
Various additional lease interests | 268 | — | — | — | 17 | 268 | — | |||||||||||||||||||||
Sagebrush additional interests | 689 | — | — | (2,378 | ) | 204 | 3,067 | — | ||||||||||||||||||||
Gungoll lease interests | 8,074 | — | — | — | 176 | 2,622 | 5,452 | |||||||||||||||||||||
Totals | $ | 115,394 | $ | (37,381 | ) | $ | (3,052 | ) | $ | (1,571 | ) | 3,686 | $ | 55,285 | $ | 21,247 | ||||||||||||
(1) | The purchase price for additional interests in PetroSource was approximately $30.1 million, comprised of $15.7 million in cash (net of $0.1 million in cash acquired), and approximately 958,000 shares of SandRidge common stock (valued at $14.4 million). The purchase price has been allocated to accounts receivable of $4.5��million, other current assets of $0.1 million, other assets of $0.4 million, accounts payable and accrued expenses of $2.6 million, long-term debt of $37.4 million, and asset retirement obligations of $2.4 million. |
The Company completed its purchase accounting allocations for the 2005 acquisitions in 2006 and recorded an additional $3.8 million deferred tax liability related to the Larco equity acquisition.
12
2006 Acquisitions and Dispositions
The Company closed the following acquisitions in 2006:
• | On March 15, 2006, the Company acquired from an executive officer and director, an additional 12.5% interest in PetroSource. The acquisition consisted of the retirement of subordinated debt of approximately $1.0 million and a $4.5 million cash payment for the ownership interest acquired for a total acquisition price of approximately $5.5 million. | ||
• | On May 1, 2006, the Company purchased certain leases in developed and undeveloped properties from an oil and gas company. The purchase price was approximately $40.9 million in cash. The cash consideration was paid in July 2006. | ||
• | On May 26, 2006, the Company purchased several oil and natural gas properties from an oil and gas company. The purchase price was approximately $12.9 million, comprised of $8.2 million in cash, and 251,351 shares of Company common stock (valued at $4.7 million). The cash and equity consideration was paid in July 2006. | ||
• | On June 1, 2006, the Company purchased certain producing well interests from an executive officer and director. The purchase price was approximately $9.0 million in cash. | ||
• | On June 7, 2006, the Company acquired the remaining 1% interest in PetroSource Energy Company, a consolidated subsidiary, from an oil and gas company. The purchase price was 27,749 shares of Company common stock (valued at $0.5 million). As a result of this acquisition, the Company became the 100% owner of PetroSource. |
The 2006 acquisitions described above were financed with approximately $63.7 million in cash and the issuance of 279,100 shares of common stock with an aggregate value of approximately $5.1 million. Details are set forth below for each of the acquisition transactions (in thousands):
Consideration Paid | ||||||||||||||||||||||||
Addition to | Change in | Retirement | Common | |||||||||||||||||||||
Acquisition | Property, Plant | Minority | of Subordinated | Stock No. | Common | |||||||||||||||||||
Transaction | & Equipment | Interest | Debt(1) | of Shares | Stock | Cash | ||||||||||||||||||
PetroSource additional interests | $ | 2,116 | $ | (2,370 | ) | $ | (1,003 | ) | — | $ | — | $ | 5,489 | |||||||||||
Purchased leases | 40,960 | — | — | — | — | 40,960 | ||||||||||||||||||
Oil and natural gas properties | 12,850 | — | — | 251 | 4,650 | 8,200 | ||||||||||||||||||
Producing well interest from executive officer and director | 9,000 | — | — | — | — | 9,000 | ||||||||||||||||||
PetroSource additional interest (remaining 1% interest) | 85 | (393 | ) | — | 28 | 478 | — | |||||||||||||||||
Totals | $ | 65,011 | $ | (2,763 | ) | $ | (1,003 | ) | 279 | $ | 5,128 | $ | 63,649 | |||||||||||
(1) | Includes retirement of subordinated debt of $972,000 and accrued interest of $31,000. |
In July 2006, the Company sold leaseholds and lease and well equipment for $16.0 million. The book basis of the assets at the time of the sale transaction was $3.7 million resulting in a gain of $12.3 million. The sale was accounted for as an adjustment to the full cost pool, with no gain recognized.
On November 21, 2006, the Company acquired all of the outstanding membership interests in NEG Oil & Gas, or NEG, for approximately $990.4 million in cash, the assumption of $300.0 million in debt, the receipt of cash of $21.1 million, and the issuance of 12,842,000 shares of the Company’s common stock (valued at approximately $231.2 million). With core assets in the Val Verde and Permian Basins of West Texas, including overlapping or contiguous interests in the WTO, the NEG acquisition has dramatically increased our exploration and production segment operations. To finance the NEG acquisition, the Company entered into a new $750 million senior secured credit facility and an $850 million senior unsecured bridge loan facility. The Company also issued $550 million of redeemable convertible preferred stock and common units (consisting of shares of common stock and a warrant to purchase convertible preferred stock upon the surrender of the common stock) in a private placement to certain eligible purchasers.
In the fourth quarter of 2007, we completed our valuation of assets acquired and liabilities assumed related to the NEG acquisition and allocated the appropriate fair values. Upon further refinement of the appraisal values, we have increased our values assigned to the properties acquired and reduced the value assigned to goodwill of $26.2 million. The accompanying balance sheet at December 31, 2006 includes the preliminary allocations of the purchase price for the NEG acquisition. The allocation of the purchase price to specific assets and liabilities were based, in part, upon an appraisal of the fair value of NEG assets.
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The following table presents the final NEG acquisition purchase price allocation, including professional fees and other related acquisition costs, to the net assets acquired and liabilities assumed, based on the fair values at the acquisition date and including subsequent adjustments to the purchase price allocation (in thousands):
Cash and cash equivalents | $ | 21,100 | ||
Accounts receivable | 30,840 | |||
Other current assets | 6,025 | |||
Property, plant and equipment | 1,524,072 | |||
Restricted deposits | 31,987 | |||
Other assets | 270 | |||
Total assets acquired | 1,614,294 | |||
Accounts payable and other current liabilities | 46,082 | |||
Deferred income taxes | 2,189 | |||
Long-term debt | 281,641 | |||
Other long-term obligations | 1,357 | |||
Asset retirement obligation | 40,343 | |||
Net assets acquired | 1,242,682 | |||
Less: Cash and cash equivalents acquired | (21,100 | ) | ||
Net amount paid for acquisition | $ | 1,221,582 | ||
Pro Forma Information
The unaudited financial information in the table below summarizes the combined results of operations of SandRidge and NEG, on a pro forma basis, as though the companies had been combined as of January 1, 2005. The pro forma financial information is presented for informational purposes only and is not indicative of the results of operations that would have been achieved if the acquisition had taken place on January 1, 2005 or of results that may occur in the future. The pro forma adjustments include estimates and assumptions based on currently available information. The Company believes the estimates and assumptions are reasonable, and the significant effects of the transactions are properly reflected. However, actual results may differ materially from this pro forma financial information. The following table presents the actual results for the years ended December 31, 2006 and 2005 and the respective unaudited pro forma information to reflect the NEG acquisition (in thousands, except per share amounts):
Year Ended December 31, | ||||||||||||||||
2006 | 2005 | |||||||||||||||
Actual | Pro Forma | Actual | Pro Forma | |||||||||||||
(Unaudited) | ||||||||||||||||
Revenues | $ | 388,242 | $ | 565,256 | $ | 287,693 | $ | 560,235 | ||||||||
Income (loss) from continuing operations | 15,621 | 36,337 | 17,893 | (49,594 | ) | |||||||||||
Net income (loss) | 15,621 | 36,337 | 18,122 | (49,594 | ) | |||||||||||
Basic and diluted earnings per share available (applicable) to common stockholders: | ||||||||||||||||
Income (loss) from continuing operations | $ | 0.21 | $ | 0.40 | $ | 0.31 | $ | (0.96 | ) | |||||||
Net income (loss) available to common stockholders | $ | 0.16 | $ | 0.04 | $ | 0.32 | $ | (0.96 | ) |
2007 Acquisitions
The Company closed the following acquisitions in 2007:
• | On October 9, 2007, the Company purchased developed and undeveloped properties located in West Texas from an oil and gas company. The purchase price was approximately $73.8 million, comprised of $25.0 million in cash and a $48.8 million note payable. The $25 million cash consideration paid was funded through a draw on the Company’s senior credit facility. All principal and accrued interest (interest at 7% annually) due on the note payable were repaid on November 9, 2007 with proceeds from the Company’s initial public offering. For additional discussion of the Company’s initial public offering, refer to Note 18 herein. | ||
• | On November 28, 2007, the Company purchased a gas treatment plant and related gathering system located in Pecos County, Texas. The purchase price of approximately $10.0 million was paid in cash. | ||
• | On November 29, 2007, the Company purchased leasehold acreage and producing well interests located predominantly in the WTO from a group of entities controlled by a significant shareholder. The purchase price of approximately $32.0 million was paid in cash. |
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3. Discontinued Operations
On September 30, 2005, the Company exchanged substantially all of its land and agriculture operations with its majority shareholder. The majority shareholder exchanged 1,414,849 shares of the Company’s common stock for these operations. The shares were exchanged at their historical basis and the exchange was reflected as a treasury share transaction. The net book value of assets exchanged was $23.6 million. There was no gain (loss) recognized in this transaction. The land and agriculture operations are presented as discontinued operations, net of income taxes in the consolidated statements of operations.
The following table summarizes net revenue and net income from discontinued operations for the years ended December 31 (in thousands):
2007 | 2006 | 2005 | ||||||||||
Revenues | $ | — | $ | — | $ | 1,683 | ||||||
Operating expenses | — | — | (1,336 | ) | ||||||||
Income from discontinued operations | — | — | 347 | |||||||||
Income tax expense | — | — | (118 | ) | ||||||||
Net income from discontinued operations | $ | — | $ | — | $ | 229 | ||||||
No assets were classified as held for sale at December 31, 2007 or 2006.
4. Accounts Receivable
A summary of accounts receivable is as follows (in thousands):
December 31, | ||||||||
2007 | 2006 | |||||||
Oil and natural gas services | $ | 6,622 | $ | 8,489 | ||||
Oil and natural gas sales | 72,393 | 57,458 | ||||||
Joint interest billing | 17,874 | 26,553 | ||||||
Other | 90 | 299 | ||||||
96,979 | 92,799 | |||||||
Less allowance for doubtful accounts | (2,238 | ) | (3,025 | ) | ||||
Total accounts receivable, net | $ | 94,741 | $ | 89,774 | ||||
The following tables show the balance in the allowance for doubtful accounts and activity for the years ended December 31 (in thousands).
Additions | ||||||||||||||||
Balance at | Charged to | Balance at | ||||||||||||||
Beginning | Costs and | End of | ||||||||||||||
Allowance for Doubtful Accounts | of Period | Expenses | Deductions(1) | Period | ||||||||||||
Year ended December 31, 2005 | $ | 1,074 | $ | 33 | $ | (256 | ) | $ | 851 | |||||||
Year ended December 31, 2006 | $ | 851 | $ | 2,528 | $ | (354 | ) | $ | 3,025 | |||||||
Year ended December 31, 2007 | $ | 3,025 | $ | — | $ | (787 | ) | $ | 2,238 |
(1) | Deductions represent the write-off/recovery of receivables. |
5. Other Current Assets
Other current assets consist of the following (in thousands):
December 31, | ||||||||
2007 | 2006 | |||||||
Prepaid insurance | $ | 9,379 | $ | 7,604 | ||||
Prepaid drilling | 5,924 | 2,207 | ||||||
Materials and supplies | 4,751 | 6,244 | ||||||
Post closing receivable — NEG acquisition | — | 15,232 | ||||||
Other | 733 | 207 | ||||||
Total other current assets | $ | 20,787 | $ | 31,494 | ||||
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6. Property, Plant and Equipment
Property, plant and equipment consists of the following (in thousands):
December 31, | ||||||||
2007 | 2006 | |||||||
Oil and natural gas properties: | ||||||||
Proved | $ | 2,848,531 | $ | 1,636,832 | ||||
Unproved | 259,610 | 282,374 | ||||||
Total oil and natural gas properties | 3,108,141 | 1,919,206 | ||||||
Less accumulated depreciation and depletion | (230,974 | ) | (60,752 | ) | ||||
Net oil and natural gas properties capitalized costs | 2,877,167 | 1,858,454 | ||||||
Land | 1,149 | 738 | ||||||
Non oil and gas equipment | 539,893 | 337,294 | ||||||
Buildings and structures | 38,288 | 6,564 | ||||||
Total | 579,330 | 344,596 | ||||||
Less accumulated depreciation, depletion and amortization | (119,087 | ) | (68,332 | ) | ||||
Net capitalized costs | 460,243 | 276,264 | ||||||
Total property, plant and equipment | $ | 3,337,410 | $ | 2,134,718 | ||||
The amount of capitalized interest included in the above non oil and gas equipment balance at December 31, 2007 and 2006 was approximately $3.4 million and $1.4 million, respectively. The Company did not capitalize any interest in 2005.
On July 11, 2007, the Company purchased property to serve as its future corporate headquarters. The 3.51-acre site contains four buildings and is located in downtown Oklahoma City, Oklahoma. The purchase price was approximately $29.5 million in cash. Payment of the purchase price was funded through a draw on the Company’s senior credit facility.
Costs Excluded from Amortization
Costs associated with unproved properties related to continuing operations of $259.6 million as of December 31, 2007 are excluded from amounts subject to amortization. A summary of costs related to unproved properties which have been excluded from oil and natural gas properties being amortized at December 31, 2007 and the year in which they were incurred is as follows:
Excluded | ||||||||||||||||||||
Year Cost Incurred | Costs at | |||||||||||||||||||
Prior | December 31, | |||||||||||||||||||
Years | 2005 | 2006 | 2007 | 2007 | ||||||||||||||||
Property acquisition | $ | — | $ | — | $ | 259,610 | $ | — | $ | 259,610 | ||||||||||
Exploration | — | — | — | — | — | |||||||||||||||
Development | — | — | — | — | — | |||||||||||||||
Capitalized interest | — | — | — | — | — | |||||||||||||||
Total costs incurred | $ | — | $ | — | $ | 259,610 | $ | — | $ | 259,610 | ||||||||||
The majority of the evaluation activities are expected to be completed within a four-year period. In addition, the Company’s internal engineers evaluate all properties on an annual basis. The average composite rates used for depreciation, depletion and amortization were $2.64 per Mcfe in 2007, $1.68 per Mcfe in 2006 and $1.23 per Mcfe in 2005.
7. Investment in Affiliated Companies
The Company has certain investments that it accounts for under the equity method of accounting because it owns more than 20% and has significant influence but does not control. The equity method investments include the following:
Grey Ranch, L.P.Grey Ranch is primarily engaged in process and transportation of gas and natural gas liquids. The Company purchased its investment during 2003. At December 31, 2007 and 2006, the Company owned 50% of Grey Ranch, L.P. and had approximately $4,176,000 and $2,201,000, respectively, recorded in the consolidated balance sheets relating to this investment. The Company contributed a disproportionate amount of capital into the partnership, amounting to approximately $750,000, as of December 31, 2007 and 2006. The excess amount contributed is being amortized over the average life of the partnership’s long-lived assets.
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Larclay, L.P.The Company and Clayton Williams Energy, Inc. (“CWEI”) each own a 50% interest in Larclay, L.P., a limited partnership formed to acquire drilling rigs and provide land drilling services. The Company purchased its investment in 2006 and accounts for it under the equity method of accounting. The Company serves as the operations manager of the partnership. CWEI was responsible for securing the financing and purchasing the rigs. The partnership financed 100% of the acquisition cost of the rigs through a guarantee by CWEI. At December 31, 2007 and 2006, the Company had approximately $3,780,000 and $1,383,000, respectively, recorded in the consolidated balance sheets relating to this investment.
8. Restricted Deposits
Restricted deposits represent bank trust and escrow accounts required by the U.S. Department of Interior’s Minerals Management Service, surety bond underwriters, purchase agreements or other settlement agreements to satisfy the Company’s eventual responsibility to plug and abandon wells and remove structures when certain offshore fields are no longer in use. These restricted deposits were acquired as part of the NEG acquisition in November 2006 (See Note 2).
In connection with one of these agreements, the Company is required to make scheduled quarterly deposits of $0.8 million to an escrow account. Aggregate scheduled fundings under this agreement are as follows (in thousands):
Years ending December 31: | ||||
2008 | $ | 3,200 | ||
2009 | 3,200 | |||
2010 and none thereafter | 2,586 |
Additionally, two of the agreements require us to deposit additional funds in an escrow account equal to 10% of the net proceeds, as defined, from certain of our offshore properties. During 2007, we deposited approximately $5.8 million in these escrow accounts.
During 2007, we were released from obligations under two of these escrow agreements. As a result, funds totaling $10.3 million were released from escrow accounts and returned to the Company.
9. Accounts Payable and Accrued Expenses
Accounts payable and accrued expenses consist of the following (in thousands):
December 31, | ||||||||
2007 | 2006 | |||||||
Accounts payable-trade | $ | 154,423 | $ | 103,683 | ||||
Redeemable convertible preferred stock dividends | 8,956 | — | ||||||
Payroll and benefits | 15,690 | 10,718 | ||||||
Drilling advances | 5,817 | 5,318 | ||||||
Legal (current) | 5,000 | 5,000 | ||||||
Accrued interest | 24,201 | 3,850 | ||||||
Other | 1,410 | 1,230 | ||||||
Total accounts payable and accrued expenses | $ | 215,497 | $ | 129,799 | ||||
10. Long-Term Debt
Long-term obligations consist of the following (in thousands):
December 31, | ||||||||
2007 | 2006 | |||||||
Senior term loans | $ | 1,000,000 | $ | — | ||||
Senior credit facility | — | 140,000 | ||||||
Senior bridge facility | — | 850,000 | ||||||
Other notes payable: | ||||||||
Drilling rig fleet and related oil field services equipment | 47,836 | 61,105 | ||||||
Mortgage | 19,651 | — | ||||||
Sagebrush | — | 4,000 | ||||||
Insurance financing | — | 7,240 | ||||||
Other equipment and vehicles | 162 | 4,486 | ||||||
Total debt | 1,067,649 | 1,066,831 | ||||||
Less: Current maturities of long-term debt | 15,350 | 26,201 | ||||||
Long-term debt | $ | 1,052,299 | $ | 1,040,630 | ||||
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Senior Credit Facility.On November 21, 2006, the Company entered into a $750 million senior secured revolving credit facility (the “senior credit facility”). The senior credit facility matures on November 21, 2011.
The proceeds of the senior credit facility were used to (i) partially finance the NEG acquisition, (ii) refinance the existing senior secured revolving credit facility and NEG’s existing credit facility,and (iii) pay fees and expenses related to the NEG acquisition and the existing credit facility. Future borrowings under the senior credit facility will be available for capital expenditures, working capital and general corporate purposes and to finance permitted acquisitions of oil and gas properties and other assets related to the exploration, production and development of oil and gas properties. The senior credit facility will be available to be drawn on and repaid without restriction so long as the Company is in compliance with its terms, including certain financial covenants.
The senior credit facility contains various covenants that limit the Company and certain of its subsidiaries’ ability to grant certain liens; make certain loans and investments; make distributions; redeem stock; redeem or prepay debt; merge or consolidate with or into a third party; or engage in certain asset dispositions, including a sale of all or substantially all of the Company’s assets. Additionally, the senior credit facility limits the Company and certain of its subsidiaries’ ability to incur additional indebtedness with certain exceptions, including under the senior term loans (as discussed below).
The senior credit facility also contains financial covenants, including maintenance of agreed upon levels for the (i) ratio of total funded debt to EBITDAX (as defined in the senior credit facility), (ii) ratio of EBITDAX to interest expense plus current maturities of long-term debt, and (iii) current ratio. The Company was in compliance with these financial covenants as of December 31, 2007.
The obligations under the senior credit facility are secured by first priority liens on all shares of capital stock of each of the Company’s present and future subsidiaries; all intercompany debt of the Company and its subsidiaries; and substantially all of the Company assets and the assets of its guarantor subsidiaries, including proved oil and natural gas reserves representing at least 80% of the present discounted value (as defined in the senior credit facility) of proved oil and natural gas reserves reviewed in determining the borrowing base for the senior credit facility. Additionally, the obligations under the senior credit facility are guaranteed by certain Company subsidiaries.
At the Company’s election, interest under the senior credit facility is determined by reference to (i) the LIBOR rate plus an applicable margin between 1.25% and 2.00% per annum or (ii) the higher of the federal funds rate plus 0.5% or the prime rate plus, in either case, an applicable margin between 0.25% and 1.00% per annum. Interest is payable quarterly for prime rate loans and at the applicable maturity date for LIBOR loans, except that if the interest period for a LIBOR loan is six months, interest is paid at the end of each three-month period. The average interest rate paid on amounts outstanding under our senior credit facility for the year ended December 31, 2007 was 7.34%.
The borrowing base of proved reserves was initially set at $300.0 million. As of December 31, 2006, the Company had $140.0 million of outstanding indebtedness on the senior credit facility. Proceeds from the Company’s sale of common stock on March 20, 2007, as described in Note 18, were used to pay outstanding borrowings under the Company’s senior credit facility.
The borrowing base was increased to $400.0 million on May 2, 2007, and to $700.0 million on September 14, 2007 where it remained at December 31, 2007. At December 31, 2007, the Company had no amounts outstanding under this facility. The Company repaid all amounts outstanding under this facility in November 2007. See Note 18 for further discussion.
If an event of default exists under the senior credit facility, the lenders may accelerate the maturity of the obligations outstanding under the senior credit facility and exercise other rights and remedies. Each of the following will be an event of default:
• | failure to pay any principal when due or any interest, fees or other amount within certain grace periods; | ||
• | failure to perform or otherwise comply with the covenants in the credit agreement or other loan documents, subject, in certain instances, to certain grace periods; | ||
• | bankruptcy or insolvency events involving the Company or its subsidiaries; | ||
• | a change of control (as defined in the senior credit facility). |
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Senior Bridge Facility.On November 21, 2006, the Company also entered into a $850.0 million senior unsecured bridge facility (the “senior bridge facility”), which was repaid in March 2007. The Company expensed the remaining unamortized debt issuance costs related to the senior bridge facility of approximately $12.5 million to interest expense in March 2007.
Together with borrowings under the senior credit facility, the proceeds from the senior bridge facility were used to (i) partially finance the NEG acquisition, (ii) refinance existing senior secured revolving credit facility and NEG’s existing credit facility,and (iii) pay fees and expenses related to the NEG acquisition and the existing credit facility.
Senior Term Loans.On March 22, 2007, the Company entered into $1.0 billion in senior unsecured term loans (the “senior term loans”). The closing of the senior term loans was generally contingent upon closing the private placement of common equity as described in Note 18. The senior term loans include both floating rate term loans and fixed rate term loans.
The Company issued $350.0 million at a variable rate with interest payable quarterly and principal due on April 1, 2014 (the “variable rate term loans”). The variable rate term loans bear interest, at the Company’s option, at the British Bankers Association LIBOR rate plus 3.625% or the higher of (i) the federal funds rate, as defined, plus 3.125% or (ii) a bank’s prime rate plus 2.625%. After April 1, 2009 the variable rate term loans may be prepaid in whole or in part with certain prepayment penalties. The average interest rates paid on amounts outstanding under the Company’s variable term loans for the year ended December 31, 2007 was 8.94%. Subsequent to year end, the Company entered into an interest rate swap to effectively fix the interest rate related to this portion of the term loan through April 1, 2011 (See Note 20).
The Company issued $650.0 million at a fixed rate of 8.625% with the principal due on April 1, 2015 (the “fixed rate term loans”). Under the terms of the fixed rate term loans, interest is payable quarterly and during the first four years interest may be paid, at the Company’s option, either entirely in cash or entirely with additional fixed rate term loans. If the Company elects to pay the interest due during any period in additional fixed rate term loans, the interest rate increases to 9.375% during such period. After April 1, 2011, the fixed rate term loans may be prepaid in whole or in part with certain prepayment penalties.
After March 22, 2008, but not later than April 30, 2008, the Company is required to offer to exchange the senior term loans for senior unsecured notes with registration rights and with identical terms and conditions as the term loans. If the Company does not complete the exchange of the senior term loans for senior unsecured notes with registration rights by May 31, 2008, the annual interest rate on the senior term loans will increase by 0.25% every 90 days up to a maximum of 0.50%.
Debt covenants under the senior term loans include financial covenants similar to those of the senior credit facility and include limitations on the incurrence of indebtedness, payment of dividends, asset sales, certain asset purchases, transactions with related parties, and consolidation or merger agreements. The Company incurred $26.1 million of debt issuance costs in connection with the senior term loans. These costs are included in other assets and amortized over the term of the senior term loans. A portion of the proceeds from the senior term loans was used to repay the Company’s $850.0 million senior bridge facility.
Other Indebtedness.The Company has financed a portion of its drilling rig fleet and related oil field services equipment through notes. At December 31, 2007, the aggregate outstanding balance of these notes was $47.8 million, with an annual fixed interest rate ranging from 7.64% to 8.87%. The notes have a final maturity date of December 1, 2011, require aggregate monthly installments for principal and interest in the amount of $1.2 million and are secured by the equipment. The notes have a prepayment penalty (currently 1-3%) in the event the Company repays the notes prior to maturity.
On November 15, 2007, the Company entered into a note payable in the amount of $20 million with a lending institution as a mortgage on the downtown Oklahoma City property purchased by the Company in July 2007 (see additional discussion in Note 6). This note is fully secured by one of the buildings and a parking garage located on the downtown property, bears interest at 6.08% annually, and matures on November 15, 2022. Payments of principal and interest in the amount of approximately $0.5 million are due on a quarterly basis through the maturity date. During 2008, the Company expects to make payments of principal and interest on this note totaling $0.8 million and $1.2 million, respectively.
Prior to 2007, the Company financed the purchase of various vehicles, oil field services equipment and other equipment through various notes payable. The aggregate outstanding balance of these notes as of December 31, 2006 was $4.5 million. Additionally, the Company financed its insurance payment made in 2007. These notes were substantially repaid during 2007 with borrowings under our senior credit facility. Also, in 2007 we repaid a $4.0 million loan incurred in 2005 for the purpose of completing a gas processing plant and pipeline in Colorado.
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Prior Senior Credit Facility.On November 21, 2006, we replaced a $130 million revolving credit facility with our existing senior credit facility. The prior senior credit facility bore interest at the Company’s option at either LIBOR plus 2.15% or the Bank of America, N.A. prime rate. The Company paid a commitment fee on the unused portion of the borrowing base amount equal to 1/8% per annum. The prior senior credit facility was collateralized by natural gas and oil properties representing at least 80% of the present discounted value of the Company’s proved reserves and by a negative pledge on any of the Company’s non-mortgaged properties.
Maturities of Long-Term Debt.Aggregate maturities of long-term debt during the next five years are as follows (in thousands):
Years ending December 31: | ||||
2008 | $ | 15,350 | ||
2009 | 16,580 | |||
2010 | 12,476 | |||
2011 | 7,222 | |||
2012 | 1,052 | |||
Thereafter | 1,014,969 | |||
Total debt | $ | 1,067,649 | ||
11. Other Long-Term Obligations
The Company has recorded a long-term obligation for amounts to be paid under a litigation settlement agreement with Conoco, Inc. entered into in January 2007. The Company agreed to pay approximately $25.0 million plus interest, payable in $5.0 million increments on April 1, 2007, July 1, 2008, July 1, 2009, July 1, 2010, and July 1, 2011. The $5.0 million payment made in 2007 has been included in accounts payable-trade in the accompanying consolidated balance sheet as of December 31, 2006, and the $5.0 million payment to be made in 2008 has been included in accounts payable-trade in the accompanying consolidated balance sheet as of December 31, 2007. Unpaid settlement amounts of approximately $15.0 million and $20.0 million have been included in other long-term obligations in the accompanying consolidated balance sheets as of December 31, 2007 and 2006, respectively.
12. Derivatives
The Company has entered into various derivative contracts including fixed price swaps, collars and basis swaps with counterparties. The contracts expire on various dates through December 31, 2009.
At December 31, 2007, the Company’s open commodity derivative contracts consisted of the following:
Weighted Avg. | ||||||||
Period | Commodity | Notional | Fixed Price | |||||
Fixed price swaps: | ||||||||
November 2007 — March 2008 | Natural gas | 1,520,000 MmBtu | $ | 8.51 | ||||
November 2007 — June 2008 | Natural gas | 4,860,000 MmBtu | $ | 8.05 | ||||
November 2007 — June 2008 | Natural gas | 9,720,000 MmBtu | $ | 8.20 | ||||
January 2008 | Natural gas | 310,000 MmBtu | $ | 8.24 | ||||
January 2008 — June 2008 | Natural gas | 3,640,000 MmBtu | $ | 7.99 | ||||
January 2008 — June 2008 | Natural gas | 3,640,000 MmBtu | $ | 7.99 | ||||
January 2008 — December 2008 | Natural gas | 3,660,000 MmBtu | $ | 8.23 | ||||
January 2008 — December 2008 | Natural gas | 3,660,000 MmBtu | $ | 8.48 | ||||
January 2008 — December 2008 | Natural gas | 3,660,000 MmBtu | $ | 9.00 | ||||
April 2008 — June 2008 | Natural gas | 910,000 MmBtu | $ | 7.17 | ||||
May 2008 — August 2008 | Natural gas | 2,460,000 MmBtu | $ | 8.38 | ||||
July 2008 | Natural gas | 310,000 MmBtu | $ | 8.00 | ||||
July 2008 | Natural gas | 310,000 MmBtu | $ | 8.02 | ||||
July 2008 — September 2008 | Natural gas | 920,000 MmBtu | $ | 7.43 | ||||
July 2008 — September 2008 | Natural gas | 920,000 MmBtu | $ | 7.49 | ||||
July 2008 — September 2008 | Natural gas | 920,000 MmBtu | $ | 8.06 | ||||
July 2008 — September 2008 | Natural gas | 920,000 MmBtu | $ | 8.07 | ||||
July 2008 — September 2008 | Natural gas | 920,000 MmBtu | $ | 8.23 | ||||
July 2008 — September 2008 | Natural gas | 920,000 MmBtu | $ | 8.36 | ||||
July 2008 — December 2008 | Natural gas | 1,840,000 MmBtu | $ | 8.31 | ||||
July 2008 — December 2008 | Natural gas | 1,840,000 MmBtu | $ | 8.59 | ||||
August 2008 | Natural gas | 310,000 MmBtu | $ | 8.00 | ||||
August 2008 | Natural gas | 310,000 MmBtu | $ | 8.07 |
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Weighted Avg. | ||||||||
Period | Commodity | Notional | Fixed Price | |||||
September 2008 | Natural gas | 300,000 MmBtu | $ | 8.05 | ||||
September 2008 | Natural gas | 300,000 MmBtu | $ | 8.10 | ||||
October 2008 — December 2008 | Natural gas | 920,000 MmBtu | $ | 7.96 | ||||
October 2008 — December 2008 | Natural gas | 1,840,000 MmBtu | $ | 8.00 | ||||
October 2008 — December 2008 | Natural gas | 920,000 MmBtu | $ | 8.07 | ||||
October 2008 — December 2008 | Natural gas | 920,000 MmBtu | $ | 8.11 | ||||
October 2008 — December 2008 | Natural gas | 920,000 MmBtu | $ | 8.16 | ||||
October 2008 — December 2008 | Natural gas | 920,000 MmBtu | $ | 8.32 | ||||
October 2008 — December 2008 | Natural gas | 920,000 MmBtu | $ | 8.83 | ||||
January 2009 — March 2009 | Natural gas | 900,000 MmBtu | $ | 8.56 | ||||
January 2009 — March 2009 | Natural gas | 900,000 MmBtu | $ | 8.60 | ||||
January 2009 — March 2009 | Natural gas | 900,000 MmBtu | $ | 8.65 | ||||
January 2009 — March 2009 | Natural gas | 900,000 MmBtu | $ | 8.91 | ||||
Collars: | ||||||||
January 2008 — June 2008 | Crude oil | 42,000 Bbls | $ | 50.00 — $83.35 | ||||
July 2008 — December 2008 | Crude oil | 54,000 Bbls | $ | 50.00 — $82.60 | ||||
Waha basis swaps: | ||||||||
January 2008 — December 2008 | Natural gas | 10,980,000 MmBtu | $ | (0.57 | ) | |||
January 2008 — December 2008 | Natural gas | 7,320,000 MmBtu | $ | (0.585 | ) | |||
January 2008 — December 2008 | Natural gas | 7,320,000 MmBtu | $ | (0.59 | ) | |||
January 2008 — December 2008 | Natural gas | 3,660,000 MmBtu | $ | (0.595 | ) | |||
January 2008 — December 2008 | Natural gas | 3,660,000 MmBtu | $ | (0.625 | ) | |||
January 2008 — December 2008 | Natural gas | 7,320,000 MmBtu | $ | (0.635 | ) | |||
January 2008 — December 2008 | Natural gas | 7,320,000 MmBtu | $ | (0.6525 | ) | |||
May 2008 — August 2008 | Natural gas | 2,460,000 MmBtu | $ | (0.45 | ) | |||
June 2008 — August 2008 | Natural gas | 920,000 MmBtu | $ | (0.4808 | ) | |||
September 2008 — December 2008 | Natural gas | 2,440,000 MmBtu | $ | (0.7930 | ) | |||
January 2009 — December 2009 | Natural gas | 3,650,000 MmBtu | $ | (0.47 | ) | |||
January 2009 — December 2009 | Natural gas | 3,650,000 MmBtu | $ | (0.49 | ) | |||
January 2009 — December 2009 | Natural gas | 3,650,000 MmBtu | $ | (0.4975 | ) |
These derivatives have not been designated as hedges. The Company records all derivatives on the balance sheet at fair value. Changes in derivative fair values are recognized in earnings. Cash settlements and valuation gains and losses are included in (gain) loss on derivative contracts in the consolidated statements of operations. The following summarizes the cash settlements and valuation gains and losses for the years ended December 31 (in thousands):
2007 | 2006 | 2005 | ||||||||||
Realized (gain) loss | $ | (34,494 | ) | $ | (14,169 | ) | $ | 2,836 | ||||
Unrealized (gain) loss | (26,238 | ) | 1,878 | 1,296 | ||||||||
(Gain) loss on derivative contracts | $ | (60,732 | ) | $ | (12,291 | ) | $ | 4,132 | ||||
13. Retirement and Deferred Compensation Plans
Retirement Plan.The Company maintains a 401(k) retirement plan for its employees. Under the plan, eligible employees may elect to defer a portion of their earnings up to the maximum allowed by regulations promulgated by the Internal Revenue Service. Prior to August 2006, the Company made matching contributions equal to 50% on the first 6% of employee deferred wages (maximum 3% matching). The Company modified the 401(k) retirement plan in August 2006 to change the matching contributions to equal a match of 100% on the first 15% of employee deferred wages (maximum 15% matching). The plan was also modified to make the matching contributions payable in Company common stock. Accrued payables in the amounts of $5.2 million and $1.3 million are reflected in the consolidated balance sheets as of December 31, 2007 and 2006, respectively, related to the matching contributions. During June 2007, the Company satisfied its matching obligation related to employees’ contributions made in 2006 through a transfer of treasury stock (See Note 18). For 2007, 2006 and 2005, retirement plan expense was approximately $4.9 million, $1.5 million and $0.3 million, respectively.
Deferred Compensation Plan.Effective February 1, 2007 the Company established a non-qualified deferred compensation plan in order to provide our employees with flexibility in meeting their future income needs and assisting them in their retirement planning. Pursuant to the terms of the deferred compensation plan, eligible highly compensated employees are provided the opportunity to defer income in excess of the IRA annual limitations on qualified 401(k) retirement plans. The 2007 annual 401(k) deferral limit for employees under age 50 was $15,500. Employees turning age 50 or over in 2007 could defer up to $20,500.
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14. Income Taxes
On January 1, 2007, the Company adopted the provisions of FIN 48. The Company has determined that no uncertain tax positions exist and therefore no reserves have been recorded for purposes of FIN 48 as of December 31, 2007. As a result, the Company has not recorded any additional liabilities for any unrecognized tax benefits as of December 31, 2007. The Company and its subsidiaries file income tax returns in the U.S. federal and various state jurisdictions. Tax years 1994 to present remain open for the majority of taxing authorities. The Company’s accounting policy is to recognize interest and penalties, if any, related to unrecognized tax benefits as income tax expense. The Company does not have an accrued liability for the payment of penalties and interest at December 31, 2007.
Significant components of the Company’s deferred tax assets (liabilities) are as follows (in thousands):
December 31, | ||||||||
2007 | 2006 | |||||||
Deferred tax assets (liabilities): | ||||||||
Current: | ||||||||
Accrued liabilities | $ | 1,820 | $ | 4,451 | ||||
Other | — | 1,864 | ||||||
Total current deferred tax assets | $ | 1,820 | $ | 6,315 | ||||
Noncurrent: | ||||||||
Property, plant and equipment | $ | (45,537 | ) | $ | (25,692 | ) | ||
Net operating loss carryforwards | 2,397 | — | ||||||
Other | (6,210 | ) | 770 | |||||
Total noncurrent deferred tax liabilities | $ | (49,350 | ) | $ | (24,922 | ) | ||
The provisions for income taxes for continuing operations consisted of the following components for the years ended December 31 (in thousands):
2007 | 2006 | 2005 | ||||||||||
Current: | ||||||||||||
Federal | $ | — | $ | 3,235 | $ | 508 | ||||||
State | 601 | 2,653 | — | |||||||||
601 | 5,888 | 508 | ||||||||||
Deferred: | ||||||||||||
Federal | 28,121 | 345 | 9,460 | |||||||||
State | 802 | 3 | — | |||||||||
28,923 | 348 | 9,460 | ||||||||||
Total provision for income taxes | $ | 29,524 | $ | 6,236 | $ | 9,968 | ||||||
A reconciliation of the provision for income taxes from continuing operations at the statutory federal tax rates to the Company’s actual provision for income taxes is as follows for the years ended December 31 (in thousands):
2007 | 2006 | 2005 | ||||||||||
Computed at federal statutory rates | $ | 27,911 | $ | 7,650 | $ | 9,543 | ||||||
State taxes, net of federal benefit | 912 | 1,724 | 390 | |||||||||
Nondeductible expenses | 312 | 84 | 35 | |||||||||
Percentage depletion deduction | — | (3,488 | ) | — | ||||||||
Change in rate | — | 326 | — | |||||||||
Other | 389 | (60 | ) | — | ||||||||
Total provision for income taxes | $ | 29,524 | $ | 6,236 | $ | 9,968 | ||||||
As of December 31, 2007, the Company had $6.8 million of net operating loss carryforwards that will begin to expire in 2023. The Company, as of December 31, 2007, had approximately $0.5 million of alternative minimum tax credits that do not expire.
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15. Earnings Per Share
Basic earnings per share are computed using the weighted average number of common shares outstanding during the year. Diluted earnings per share are computed using the weighted average shares outstanding during the year, but also include the dilutive effect of awards of restricted stock. The following table summarizes the calculation of weighted average common shares outstanding used in the computation of diluted earnings per share for the years ended December 31 (in thousands).
2007 | 2006 | 2005 | ||||||||||
Weighted average basic common shares outstanding | 108,828 | 73,727 | 56,559 | |||||||||
Effect of dilutive securities: | ||||||||||||
Restricted stock | 1,213 | 937 | 178 | |||||||||
Weighted average diluted common and potential common shares outstanding | 110,041 | 74,664 | 56,737 | |||||||||
In computing diluted earnings per share, the Company evaluated the if-converted method with respect to its outstanding redeemable convertible preferred stock. Under this method, the Company assumes the conversion of the preferred stock to common stock and determines if this is more dilutive than including the preferred stock dividends (paid and unpaid) in the computation of income available to common stockholders. The Company determined the if-converted method is not more dilutive and has included preferred stock dividends in the determination of income available to common stockholders.
16. Commitments and Contingencies
Operating Leases.The Company has obligations under noncancelable operating leases, primarily for the use of office space and equipment. Total rental expense under operating leases for the years ended December 31, 2007, 2006 and 2005 was approximately $2.3 million, $1.1 million and $1.1 million, respectively.
Future minimum lease payments under noncancelable operating leases (with initial lease terms in excess of one year) as of December 31, 2007 are as follows (in thousands):
Years ending December 31: | ||||
2008 | $ | 2,139 | ||
2009 | 1,102 | |||
2010 | 110 | |||
2011 | 110 | |||
2012 | 45 | |||
Thereafter | — | |||
$ | 3,506 | |||
Litigation.The Company is a defendant in lawsuits from time to time in the normal course of business. In management’s opinion, the Company is not currently involved in any legal proceedings which, individually or in the aggregate, could have a material effect on the financial condition, operations and/or cash flows of the Company.
17. Redeemable Convertible Preferred Stock
In November 2006, the Company sold 2,136,667 shares of redeemable convertible preferred stock in order to finance a portion of the NEG acquisition and received net proceeds from this sale of approximately $439.5 million after deducting offering expenses of approximately $9.3 million (See Note 2). Each holder of the redeemable convertible preferred stock is entitled to quarterly cash dividends at the annual rate of 7.75% of the accreted value of its redeemable convertible preferred stock. The accreted value was $210 per share as of December 31, 2007 and 2006. Each share of convertible preferred stock was initially convertible into ten (10.2 currently) shares of common stock at the option of the holder, subject to certain anti-dilution adjustments. A summary of dividends declared and paid on the redeemable convertible preferred stock is as follows (in thousands, except per share data):
Dividends | ||||||||||||
Declared | Dividend Period | per Share | Total | Date Paid | ||||||||
January 31, 2007 | November 21, 2006 — February 1, 2007 | $ | 3.21 | $ | 6,859 | February 15, 2007 | ||||||
May 8, 2007 | February 2, 2008 — May 1, 2007 | 3.97 | 8,550 | May 15, 2007 | ||||||||
June 8, 2007 | May 2, 2007 — August 1, 2007 | 4.10 | 8,956 | August 15, 2007 | ||||||||
September 24, 2007 | August 2, 2007 — November 1, 2007 | 4.10 | 8,956 | November 15, 2007 | ||||||||
December 16, 2007 | November 2, 2007 — February 1, 2008 | 4.10 | 8,956 | February 15, 2008 |
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On March 30, 2007, certain holders of the Company’s common units (consisting of shares of common stock and a warrant to purchase redeemable convertible preferred stock upon the surrender of common stock) exercised warrants to purchase redeemable convertible preferred stock. The holders exchanged 526,316 shares of common stock for 47,619 shares of redeemable convertible preferred stock.
Approximately $38.5 million and $3.8 million in paid and unpaid dividends have been included in the Company’s earnings per share calculations for the years ended December 31, 2007 and 2006, respectively, as presented in the accompanying consolidated statements of operations.
18. Stockholders’ Equity
The following table presents information regarding SandRidge’s common stock (in thousands):
December 31, | ||||||||
2007 | 2006 | |||||||
Shares authorized | 400,000 | 400,000 | ||||||
Shares outstanding at end of period | 140,391 | 91,604 | ||||||
Shares held in treasury | 1,456 | 1,444 |
The Company is authorized to issue 50,000,000 shares of preferred stock, $0.001 par value, of which 2,625,000 shares are designated as redeemable convertible preferred. As of December 31, 2007 and 2006 there were 2,184,286 and 2,136,667 shares, respectively, of redeemable convertible preferred stock outstanding (See Note 17). There were no undesignated preferred shares outstanding as of December 31, 2007 and 2006.
Stock Split.On December 19, 2005, the Company effected a 281.562 for 1 stock split. All references in the accompanying financial statements have been restated to reflect this stock split. The Company also authorized 400,000,000 shares of common stock with a par value of $0.001 per share.
Common Stock Issuance.In December 2005, the Company sold 12.5 million shares of common stock in a private placement and received net proceeds from this sale of approximately $173.1 million after deducting the initial purchasers’ discount of $16.8 million and offering expenses of approximately $1.2 million. Approximately $105.5 million of the proceeds of the offering were used to repay outstanding bank debt and finance the Company’s December 2005 acquisitions (See Note 2).
In January 2006, the Company issued an additional 239,630 shares of common stock upon exercise of an over-allotment option. The Company issued these shares at a price of $15.00 per share after deducting the purchasers’ fee of $0.3 million. The Company received net proceeds from the sale of approximately $3.3 million.
In November 2006, the Company sold 5.3 million common units (consisting of shares of common stock ($18.00 per share) and a warrant ($1.00 per share) to purchase convertible preferred stock upon the surrender of the common stock) as part of the NEG acquisition and received net proceeds from this sale of approximately $97.4 million after deducting the offering expenses of approximately $3.9 million (See Note 2).
In March 2007, the Company sold approximately 17.8 million shares of common stock for net proceeds of $318.7 million after deducting offering expenses of approximately $1.4 million. The stock was sold in private sales to various investors including Tom L. Ward, the Company’s Chairman of the Board of Directors and Chief Executive Officer, who invested $61.4 million in exchange for approximately 3.4 million shares of common stock.
On November 9, 2007, the Company completed an initial public offering (the “IPO”) of its common stock. The Company sold 28,700,000 shares of SandRidge common stock, including 4,710,000 shares sold directly to an entity controlled by Tom L. Ward. The shares were sold at a price of $26 per share. After deducting underwriting discounts of approximately $38.3 million and estimated offering expenses of approximately $3.1 million, the Company received net proceeds of approximately $704.8 million. This transaction priced after market close on November 5, 2007. In conjunction with the IPO, the underwriters were granted an option to purchase 3,679,500 additional shares of the Company’s common stock. The underwriters fully exercised this option and purchased the additional shares on November 6, 2007. After deducting underwriting discounts of approximately $5.7 million, the Company received net proceeds of approximately $89.9 million from these additional shares. This offering generated total gross proceeds to the Company of $841.8 million and total net proceeds of approximately $794.7 million to the Company after deducting total underwriting discounts of approximately $44.0 million and other offering expenses of approximately $3.1 million. The aggregate net proceeds of approximately $794.7 million received by the Company at closing on November 9, 2007 were utilized as follows (in millions):
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Repayment of outstanding balance and accrued interest on senior credit facility | $ | 515.9 | ||
Repayment of note payable and accrued interest incurred in connection with recent acquisition | 49.1 | |||
Excess cash to fund future capital expenditures | 229.7 | |||
Total | $ | 794.7 | ||
Treasury Stock.The Company makes required tax payments on behalf of employees as their stock awards vest and then withholds a number of vested shares having a value on the date of vesting equal to the tax obligation. As a result of such transactions, the Company withheld 44,649 shares at a total value of $0.8 million and 29,000 shares at a total value of $0.5 million during the years ended December 31, 2007 and 2006, respectively. These shares were accounted for as treasury stock.
On June 28, 2007, the Company purchased 39,844 shares of its common stock into treasury through an open market repurchase transaction in order to fund a portion of its 401(k) matching obligation as described below. Cash consideration for these shares of approximately $0.8 million was paid in July 2007.
On June 29, 2007, the Company transferred 72,044 shares of its treasury stock to an account established for the benefit of the Company’s 401(k) Plan. The transfer was made in order to satisfy the Company’s $1.3 million accrued payable to match employee contributions made to the plan during 2006. Historical cost of the shares transferred totaled approximately $0.9 million, resulting in an increase to the Company’s additional paid-in capital of approximately $0.4 million.
Restricted Stock.The Company issues restricted stock awards under incentive compensation plans which vest over specified periods of time. Awards issued prior to 2006 had vesting periods of one, four or seven years. All awards issued during and after 2006 have four year vesting periods. Shares of restricted common stock are subject to restriction on transfer and certain conditions to vesting.
The Company granted restricted stock awards of approximately 1.6 million shares in December 2005. The stock awards included (i) 153,667 shares scheduled to vest on December 31, 2006, (ii) 904,833 shares scheduled to vest on June 30, 2010, and (iii) 493,667 shares scheduled to vest on June 30, 2013. In June 2006, the Company modified the vesting periods of the one year period and four year period restricted stock awards. One year restricted stock awards were modified to vest on October 1, 2006, rather than December 31, 2006, and four year restricted stock awards were modified to vest 25% each January 1, for four years, beginning January 1, 2007, rather than all vesting on June 30, 2010. The Company recognized compensation cost related to these modifications of $17,250 in June 2006.
Additionally, the Company modified the vesting period related to restricted shares awarded to certain executive officers who resigned in June 2006 and August 2006 as a component of their separations from the Company. The Board of Directors agreed to immediately vest all of the executive officers’ restricted stock, a total of 222,000 shares, including 20,334 shares which would have vested in 2006, 150,000 shares which would have vested in 2010, and 51,666 shares which would have vested in 2013. The Company recognized compensation cost related to these modifications of $2.3 million in the year ended December 31, 2006.
In December 2006, the Company accelerated the vesting of 39,960 restricted shares on behalf of certain employees who resigned from the Company in late December 2006. These shares had been scheduled to vest on January 1, 2007. The Company recognized additional compensation cost in December 2006 for these shares of approximately $0.1 million due to the modification. Other restricted shares held by these employees were forfeited.
Restricted stock activity for the year ended December 31, 2007 was as follows (shares in thousands):
Weighted- | ||||||||
Number of | Average Grant | |||||||
Shares | Date Fair Value | |||||||
Unvested restricted shares outstanding at December 31, 2006 | 937 | $ | 15.88 | |||||
Granted | 1,600 | 19.79 | ||||||
Vested | (466 | ) | 15.62 | |||||
Canceled | (144 | ) | 15.15 | |||||
Unvested restricted shares outstanding at December 31, 2007 | 1,927 | $ | 19.25 | |||||
For the year ended December 31, the Company recognized stock-based compensation expense related to restricted stock of approximately $7.2 million in 2007, $8.8 million in 2006, and $0.5 million in 2005. Stock-based compensation expense is reflected in general and administrative expense in the consolidated statements of operations.
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As of December 31, 2007, there was approximately $30.5 million of unrecognized compensation cost related to unvested restricted stock awards which is expected to be recognized over a weighted average period of 2.21 years.
19. Related Party Transactions
During the ordinary course of business, the Company has transactions with certain shareholders and other related parties. These transactions primarily consist of purchases of drilling equipment and sales of oil field service supplies. Following is a summary of significant transactions with such related parties for the years ended December 31 (in thousands):
2007 | 2006 | 2005 | ||||||||||
Sales to and reimbursements from related parties | $ | 118,631 | $ | 14,102 | $ | 12,673 | ||||||
Purchases of services from related parties | $ | 77,555 | $ | 4,811 | $ | 37 | ||||||
In August 2006, the Company sold various non-energy related assets to the Company’s former President and Chief Operating Officer, N. Malone Mitchell, 3rd, for approximately $6.1 million in cash. The sale transaction resulted in a $0.8 million gain recognized in earnings by the Company in August 2006. The gain is included in gain on sale of assets in the consolidated statements of operations.
In September 2006, the Company entered into a facilities lease with a member of its Board of Directors. The Company believes that the payments to be made under this lease are at fair market rates. Rent expense related to the lease totaled $1.3 million and $0.3 million for the years ended December 31, 2007 and 2006, respectively. The lease extends to August 2009.
In May 2007, the Company purchased leasehold acreage from a partnership controlled by a director. The purchase price was approximately $8.3 million in cash.
In June 2007, the Company purchased certain producing well interests from a director. The purchase price was approximately $3.5 million in cash.
Larclay, L.P.The Company and CWEI each own a 50% interest in Larclay, L.P., a limited partnership formed to acquire drilling rigs and provide land drilling services. Larclay currently owns 12 rigs, one of which has not yet been assembled. The Company purchased its investment in 2006 and accounts for it under the equity method of accounting. The Company serves as the operations manager of the partnership. CWEI is responsible for financing and purchasing the rigs. The Company had sales to and cost reimbursements from Larclay for the years ended December 31, 2007 and 2006 of $53.3 million and $1.6 million, respectively. As of December 31, 2007 and 2006, the Company had accounts receivable — related party due from Larclay of $16.6 million and $3.0 million, respectively. Additionally, the Company contracted with Larclay to utilize rigs for drilling. For the year ended December 31, 2007 the amount we were billed for these services was $33.3 million. As of December 31, 2007, the Company had accounts payable — related party due to Larclay of $0.3 million. The Company made no purchases from Larclay in 2006.
See Note 2 for a discussion of additional related party transactions.
20. Subsequent Events
In January 2008, the Company entered into an interest rate swap to fix the variable LIBOR interest rate on the $350.0 million floating rate portion of its term loan at 6.26% for the period from April 1, 2008 to April 1, 2011. This swap has not been designated as a hedge.
21. Industry Segment Information
SandRidge has four business segments: Exploration and Production, Drilling and Oil Field Services, Midstream Services, and Other representing its four main business units offering different products and services. The Exploration and Production segment is engaged in the development, acquisition and production of oil and natural gas properties. The Drilling and Oil Field Services segment is engaged in the land contract drilling of oil and natural gas wells. The Midstream Gas Services segment is engaged in the purchasing, gathering, processing and treating of natural gas. The Other segment transports CO(2) to market for use by the Company and others in tertiary oil recovery operations and other miscellaneous operations.
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The accounting policies of the segments are the same as those described in the Summary of Significant Accounting Policies (Note 1). Management evaluates the performance of SandRidge’s operating segments based on operating income, which is defined as operating revenues less operating expenses and depreciation, depletion and amortization. Summarized financial information concerning the Company’s segments is shown in the following table (in thousands):
2007 | 2006 | 2005 | ||||||||||
Revenues: | ||||||||||||
Exploration and production | $ | 479,321 | $ | 106,990 | $ | 54,425 | ||||||
Elimination of inter-segment revenue | 574 | 577 | 374 | |||||||||
Exploration and production, net of inter-segment revenue | 478,747 | 106,413 | 54,051 | |||||||||
Drilling and oil field services | 261,818 | 211,055 | 109,766 | |||||||||
Elimination of inter-segment revenue | 188,616 | 72,398 | 29,615 | |||||||||
Drilling and oil field services, net of inter-segment revenue | 73,202 | 138,657 | 80,151 | |||||||||
Midstream services | 285,065 | 192,960 | 192,503 | |||||||||
Elimination of inter-segment revenue | 177,487 | 70,068 | 45,004 | |||||||||
Midstream services, net of inter-segment revenues | 107,578 | 122,892 | 147,499 | |||||||||
Other | 29,286 | 21,411 | 6,164 | |||||||||
Elimination of inter-segment revenue | 11,361 | 1,131 | 172 | |||||||||
Other, net of inter-segment revenue | 17,925 | 20,280 | 5,992 | |||||||||
Total revenues | $ | 677,452 | $ | 388,242 | $ | 287,693 | ||||||
Operating Income: | ||||||||||||
Exploration and production | $ | 198,913 | $ | 17,069 | $ | 14,886 | ||||||
Drilling and oil field services | 10,473 | 32,946 | 18,295 | |||||||||
Midstream services | 6,783 | 3,528 | 4,096 | |||||||||
Other | (29,310 | ) | (16,562 | ) | (3,224 | ) | ||||||
Total operating income | 186,859 | 36,981 | 34,053 | |||||||||
Interest expense, net | (111,762 | ) | (15,795 | ) | (5,071 | ) | ||||||
Other income (expense), net | 4,648 | 671 | (1,121 | ) | ||||||||
Income before income taxes | $ | 79,745 | $ | 21,857 | $ | 27,861 | ||||||
Identifiable Assets(1): | ||||||||||||
Exploration and production | $ | 3,143,137 | $ | 2,091,459 | $ | 243,612 | ||||||
Drilling and oil field services | 271,563 | 175,169 | 100,995 | |||||||||
Midstream services | 127,822 | 75,606 | 33,845 | |||||||||
Other | 88,044 | 46,150 | 80,231 | |||||||||
Total assets | $ | 3,630,566 | $ | 2,388,384 | $ | 458,683 | ||||||
Capital Expenditures: | ||||||||||||
Exploration and production | $ | 1,046,552 | $ | 170,872 | $ | 61,227 | ||||||
Drilling and oil field services | 123,232 | 89,810 | 43,730 | |||||||||
Midstream services | 63,828 | 16,975 | 25,904 | |||||||||
Other | 47,236 | 28,884 | 3,735 | |||||||||
Total capital expenditures | $ | 1,280,848 | $ | 306,541 | $ | 134,596 | ||||||
Depreciation, Depletion and Amortization | ||||||||||||
Exploration and production | $ | 175,565 | $ | 28,104 | $ | 8,796 | ||||||
Drilling and oil field services | 37,792 | 20,268 | 11,851 | |||||||||
Midstream services | 6,641 | 3,180 | 1,652 | |||||||||
Other | 7,110 | 4,074 | 1,907 | |||||||||
Total depreciation, depletion and amortization | $ | 227,108 | $ | 55,626 | $ | 24,206 | ||||||
(1) | Identifiable assets are those used in SandRidge’s operations in each industry segment. |
Major Customer.During 2007, the Company had sales in excess of 10% of total revenues to an oil and gas purchaser ($76.1 million or 11.2% of total revenues). There were no customers that accounted for 10% or more of our total revenues in 2006 or 2005.
22. Supplemental Information on Oil and Gas Producing Activities (Unaudited)
The Supplementary Information on Oil and Gas Producing Activities is presented as required by SFAS No. 69, “Disclosures about Oil and Gas Producing Activities.” The supplemental information includes capitalized costs related to oil and gas producing activities; costs incurred for the acquisition of oil and gas producing activities, exploration and development activities; and the results of
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operations from oil and gas producing activities. Supplemental information is also provided for per unit production costs; oil and gas production and average sales prices; the estimated quantities of proved oil and gas reserves; the standardized measure of discounted future net cash flows associated with proved oil and gas reserves; and a summary of the changes in the standardized measure of discounted future net cash flows associated with proved oil and gas reserves.
The Company’s capitalized costs consisted of the following (in thousands):
Capitalized Costs Related to Oil and Gas Producing Activities
December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Oil and natural gas properties: | ||||||||||||
Proved | $ | 2,848,531 | $ | 1,636,832 | $ | 160,789 | ||||||
Unproved | 259,610 | 282,374 | 33,974 | |||||||||
Total oil and natural gas properties | 3,108,141 | 1,919,206 | 194,763 | |||||||||
Less accumulated depreciation and depletion | (230,974 | ) | (60,752 | ) | (35,029 | ) | ||||||
Net oil and natural gas properties capitalized costs | $ | 2,877,167 | $ | 1,858,454 | $ | 159,734 | ||||||
Costs Incurred in Property Acquisition, Exploration and Development Activities
2007 | 2006 | 2005 | ||||||||||
Acquisitions of properties | ||||||||||||
Proved | $ | 303,282 | $ | 1,311,029 | $ | 14,554 | ||||||
Unproved | — | 268,839 | 21,085 | |||||||||
Exploration(1) | 361,973 | 18,612 | 2,527 | |||||||||
Development | 485,348 | 115,153 | 60,364 | |||||||||
Total cost incurred | $ | 1,150,603 | $ | 1,713,633 | $ | 98,530 | ||||||
(1) | 2007 amount includes seismic costs of $38.6 million. |
The Company’s results of operations from oil and gas producing activities for each of the years 2007, 2006 and 2005 are shown in the following table (in thousands):
Results of Operations for Oil and Gas Producing Activities
For the Year Ended December 31, 2005 | ||||
Revenues | $ | 48,405 | ||
Expenses: | ||||
Production costs | 19,353 | |||
Depreciation, depletion and amortization expenses | 8,995 | |||
Total expenses | 28,348 | |||
Income before income taxes | 20,057 | |||
Provision for income taxes | 7,020 | |||
Results of operations for oil and gas producing activities | $ | 13,037 | ||
For the Year Ended December 31, 2006 | ||||
Revenues | $ | 101,252 | ||
Expenses: | ||||
Production costs | 39,803 | |||
Depreciation, depletion and amortization expenses | 25,723 | |||
Total expenses | 65,526 | |||
Income before income taxes | 35,726 | |||
Provision for income taxes | 10,718 | |||
Results of operations for oil and gas producing activities | $ | 25,008 | ||
For the Year Ended December 31, 2007 | ||||
Revenues | $ | 477,612 | ||
Expenses: | ||||
Production costs | 125,749 | |||
Depreciation, depletion and amortization expenses | 169,392 | |||
Total expenses | 295,141 | |||
Income before income taxes | 182,471 | |||
Provision for income taxes | 65,690 | |||
Results of operations for oil and gas producing activities | $ | 116,781 | ||
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The table below represents the Company’s estimate of proved crude oil and natural gas reserves attributable to the Company’s net interest in oil and gas properties based upon the evaluation by the Company and its independent petroleum engineers of pertinent geological and engineering data in accordance with United States Securities and Exchange Commission regulations. Estimates of substantially all of the Company’s proved reserves have been prepared by the team of independent reservoir engineers and geoscience professionals and are reviewed by members of the Company’s senior management with professional training in petroleum engineering to ensure that the Company consistently applies rigorous professional standards and the reserve definitions prescribed by the United States Securities and Exchange Commission.
Netherland, Sewell & Associates, Inc. and DeGolyer and MacNaughton, independent oil and gas consultants, have prepared the estimates of proved reserves of natural gas and crude oil attributable to several portions of the Company’s net interest in oil and gas properties as of the end of one or more of 2007, 2006 and 2005. Netherland, Sewell & Associates, Inc. and DeGolyer and MacNaughton are independent petroleum engineers, geologists, geophysicists and petrophysicists and do not own an interest in us or our properties and are not employed on a contingent basis. Netherland, Sewell & Associates, Inc. prepared the estimates of proved reserves for all of our properties other than those held by PetroSource, which constitute approximately 89% of our total proved reserves as of December 31, 2007. DeGolyer and MacNaughton prepared the estimates of proved reserves for PetroSource, which constitute approximately 8% of our total proved reserves as of December 31, 2007. The small remaining portion of estimates of proved reserves were based on Company estimates.
The Company believes the geologic and engineering data examined provides reasonable assurance that the proved reserves are recoverable in future years from known reservoirs under existing economic and operating conditions. Estimates of proved reserves are subject to change, either positively or negatively, as additional information is available and contractual and economic conditions change.
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, that is, prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. Proved developed reserves are the quantities of crude oil, natural gas liquids and natural gas expected to be recovered through existing investments in wells and field infrastructure under current operating conditions. Proved undeveloped reserves require additional investments in wells and related infrastructure in order to recover the production.
During 2007, the Company recognized additional reserves attributable to extensions and discoveries as a result of successful drilling in the Piñon Field. Drilling expenditures of $97.1 resulted in the addition of 44.7 Bcfe of net proved developed reserves by extending the field boundaries as well as proving the producing capabilities of formations not previously captured as proved reserves. The remaining 55.1 Bcfe of net proved reserves for 2007 are proved undeveloped reserves associated with direct offsets to the 2007 drilling program extending the boundaries of the Piñon Field and zone identification. Changes in reserves associated with the development drilling have been accounted for in revisions of previous reserve estimates.
During 2006, the Company recognized additional reserves attributable to extensions and discoveries as a result of successful drilling in the Piñon Field. Drilling expenditures of $18.6 million resulted in the addition of 10.9 Bcfe of net proved developed reserves by extending the field boundaries as well as proving the producing capabilities of formations not previously captured as proved reserves. The remaining 83.1 Bcfe of net proved reserves for 2006 are proved undeveloped reserves associated with direct offsets to the 2006 drilling program extending the boundaries of the Piñon Field and zone identification. Changes in reserves associated with the development drilling have been accounted for in revisions of previous reserve estimates.
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Reserve Quantity Information
Crude Oil | Nat. Gas | |||||||
(MBbls) | (MMcf)(a) | |||||||
Proved developed and undeveloped reserves: | ||||||||
As of December 31, 2004 | 682 | 144,452 | ||||||
Revisions of previous estimates | 108 | 11,679 | ||||||
Acquisitions of new reserves | 9,518 | 32,022 | ||||||
Extensions and discoveries | 200 | 56,133 | ||||||
Production | (72 | ) | (6,873 | ) | ||||
As of December 31, 2005 | 10,436 | 237,413 | ||||||
Revisions of previous estimates | 1,250 | 19,139 | ||||||
Acquisitions of new reserves | 13,753 | 514,170 | ||||||
Extensions and discoveries | 58 | 93,396 | ||||||
Production | (322 | ) | (13,410 | ) | ||||
As of December 31, 2006 | 25,175 | 850,708 | ||||||
Revisions of previous estimates | 5,492 | 318,639 | ||||||
Acquisitions of new reserves | 53 | 75,139 | ||||||
Extensions and discoveries | 7,849 | 104,501 | ||||||
Production | (2,042 | ) | (51,958 | ) | ||||
As of December 31, 2007 | 36,527 | 1,297,029 | ||||||
Proved developed reserves: | ||||||||
As of December 31, 2004 | 231 | 50,981 | ||||||
As of December 31, 2005 | 899 | 69,377 | ||||||
As of December 31, 2006 | 10,994 | 308,296 | ||||||
As of December 31, 2007 | 12,532 | 590,358 |
(a) | Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit. |
The standardized measure of discounted cash flows and summary of the changes in the standardized measure computation from year to year are prepared in accordance with SFAS No. 69. The assumptions that underlie the computation of the standardized measure of discounted cash flows may be summarized as follows:
• | the standardized measure includes the Company’s estimate of proved crude oil, natural gas liquids and natural gas reserves and projected future production volumes based upon year-end economic conditions; | ||
• | pricing is applied based upon year-end market prices adjusted for fixed or determinable contracts that are in existence at year-end. The calculated weighted average per unit prices for the Company’s proved reserves and future net revenues were as follows: |
At December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Natural gas (per Mcf) | $ | 6.46 | $ | 5.32 | $ | 8.40 | ||||||
Crude oil (per barrel) | $ | 87.47 | $ | 54.62 | $ | 54.02 |
• | future development and production costs are determined based upon actual cost at year-end; | ||
• | the standardized measure includes projections of future abandonment costs based upon actual costs at year-end; and | ||
• | a discount factor of 10% per year is applied annually to the future net cash flows. |
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Standardized Measure of Discounted Future Net Cash Flows Related to
Proved Oil and Gas Reserves
Proved Oil and Gas Reserves
(In thousands) | ||||
As of December 31, 2005 | ||||
Future cash inflows from production | $ | 2,558,668 | ||
Future production costs | (653,748 | ) | ||
Future development costs(a) | (296,489 | ) | ||
Future income tax expenses | (546,867 | ) | ||
Undiscounted future net cash flows | 1,061,564 | |||
10% annual discount | (562,410 | ) | ||
Standardized measure of discounted future net cash flows | $ | 499,154 | ||
As of December 31, 2006 | ||||
Future cash inflows from production | $ | 5,901,660 | ||
Future production costs | (1,623,216 | ) | ||
Future development costs(a) | (931,947 | ) | ||
Future income tax expenses | (638,599 | ) | ||
Undiscounted future net cash flows | 2,707,898 | |||
10% annual discount | (1,267,752 | ) | ||
Standardized measure of discounted future net cash flows | $ | 1,440,146 | ||
As of December 31, 2007 | ||||
Future cash inflows from production | $ | 11,578,381 | ||
Future production costs | (2,706,208 | ) | ||
Future development costs(a) | (1,640,500 | ) | ||
Future income tax expenses | (1,782,909 | ) | ||
Undiscounted future net cash flows | 5,448,764 | |||
10% annual discount | (2,730,227 | ) | ||
Standardized measure of discounted future net cash flows | $ | 2,718,537 | ||
(a) | Includes abandonment costs. |
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The following table represents the Company’s estimate of changes in the standardized measure of discounted future net cash flows from proved reserves (in thousands):
Changes in the Standardized Measure of Discounted Future Net Cash Flows
From Proved Oil and Gas Reserves
From Proved Oil and Gas Reserves
Present value as of December 31, 2004 | $ | 198,962 | ||
Changes during the year: | ||||
Revenues less production and other costs | (29,052 | ) | ||
Net changes in prices, production and other costs | 225,227 | |||
Development costs incurred | 56,368 | |||
Net changes in future development costs | (86,828 | ) | ||
Extensions and discoveries | 96,514 | |||
Revisions of previous quantity estimates | 47,501 | |||
Accretion of discount | 28,981 | |||
Net change in income taxes | (155,250 | ) | ||
Purchases of reserves in-place | 196,206 | |||
Timing differences and other(a) | (79,475 | ) | ||
Net change for the year | 300,192 | |||
Present value as of December 31, 2005 | $ | 499,154 | ||
Revenues less production and other costs | (61,449 | ) | ||
Net changes in prices, production and other costs | (294,437 | ) | ||
Development costs incurred | 75,323 | |||
Net changes in future development costs | (75,466 | ) | ||
Extensions and discoveries | 126,061 | |||
Revisions of previous quantity estimates | 54,313 | |||
Accretion of discount | 73,643 | |||
Net change in income taxes | (36,962 | ) | ||
Purchases of reserves in-place | 1,135,062 | |||
Timing differences and other(a) | (55,096 | ) | ||
Net change for the year | 940,992 | |||
Present value as of December 31, 2006 | $ | 1,440,146 | ||
Changes during the year: | ||||
Revenues less production and other costs | (351,863 | ) | ||
Net changes in prices, production and other costs | 800,630 | |||
Development costs incurred | 485,348 | |||
Net changes in future development costs | (723,943 | ) | ||
Extensions and discoveries | 328,094 | |||
Revisions of previous quantity estimates | 998,729 | |||
Accretion of discount | 88,596 | |||
Net change in income taxes | (537,835 | ) | ||
Purchases of reserves in-place | 155,051 | |||
Timing differences and other(a) | 35,584 | |||
Net change for the year | 1,278,391 | |||
Present value as of December 31, 2007 | $ | 2,718,537 | ||
(a) | The change in timing differences and other are related to revisions in the Company’s estimated time of production and development. |
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23. Quarterly Financial Results (Unaudited)
Our operating results for each quarter of 2007 and 2006 are summarized below (in thousands, except per share data).
First | Second | Third | Fourth | |||||||||||||
Quarter | Quarter | Quarter | Quarter | |||||||||||||
2007: | ||||||||||||||||
Total revenues | $ | 149,064 | $ | 159,063 | $ | 153,648 | $ | 215,677 | ||||||||
Income from operations | $ | 14,408 | $ | 75,160 | $ | 59,716 | $ | 37,575 | ||||||||
Net income (loss) | $ | (19,493 | ) | $ | 34,564 | $ | 20,920 | $ | 14,230 | |||||||
Income (loss) available (applicable) to common stockholders | $ | (28,459 | ) | $ | 22,270 | $ | 11,607 | $ | 4,915 | |||||||
Basic and diluted: | ||||||||||||||||
Net income (loss) available (applicable) to common stockholders(1) | $ | (0.31 | ) | $ | 0.21 | $ | 0.11 | $ | 0.04 | |||||||
2006: | ||||||||||||||||
Total revenues | $ | 85,915 | $ | 87,915 | $ | 89,650 | $ | 124,762 | ||||||||
Income from operations | $ | 3,468 | $ | 6,757 | $ | 8,576 | $ | 18,180 | ||||||||
Net income (loss) | $ | 8,383 | $ | 5,649 | $ | 4,895 | $ | (3,306 | ) | |||||||
Income (loss) available (applicable) to common stockholders | $ | 8,383 | $ | 5,649 | $ | 4,895 | $ | (7,273 | ) | |||||||
Basic and diluted: | ||||||||||||||||
Net income (loss) available (applicable) to common stockholders(1) | $ | 0.12 | $ | 0.08 | $ | 0.07 | $ | (0.10 | ) | |||||||
(1) | Income (loss) available (applicable) to common stockholders for each quarter is computed using the weighted-average number of shares outstanding during the quarter, while earnings per share for the fiscal year is computed using the weighted-average number of shares outstanding during the year. Thus, the sum of income (loss) available (applicable) to common stockholders for each of the four quarters may not equal the fiscal year amount. |
24. Condensed Consolidating Financial Information
The Company is providing condensed consolidating financial information for its subsidiaries that are guarantors of its public debt registered in October 2008. Subsidiary guarantors are wholly owned and have, jointly and severally, unconditionally guaranteed on an unsecured basis the Company’s 8.625% Senior Notes due 2015 and Senior Floating Rate Notes due 2014. The subsidiary guarantees (i) rank equally in right of payment with all of the existing and future senior debt of the subsidiary guarantors; (ii) rank senior to all of the existing and future subordinated debt of the subsidiary guarantors; (iii) are effectively subordinated in right of payment to any existing or future secured obligations of the subsidiary guarantors to the extent of the value of the assets securing such obligations; and (iv) are structurally subordinated to all debt and other obligations of the subsidiaries of the guarantors who are not themselves guarantors.
The Company has not presented separate financial and narrative information for each of the subsidiary guarantors because it believes that such financial and narrative information would not provide any additional information that would be material in evaluating the sufficiency of the guarantees.
The following condensed consolidating financial information represents the financial information of SandRidge Energy, Inc. and its wholly-owned subsidiary guarantors, prepared on the equity basis of accounting. The non-guarantor subsidiaries are minor and, therefore, not presented separately. The information is presented in accordance with the requirements of Rule 3-10 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had the subsidiary guarantors operated as independent entities.
33
Condensed Consolidating Balance Sheet
(In Thousands)
(In Thousands)
December 31, 2007 | December 31, 2006 | |||||||||||||||||||||||||||||||
Parent | Guarantor | Parent | Guarantor | |||||||||||||||||||||||||||||
Company | Subsidiaries | Eliminations | Consolidated | Company | Subsidiaries | Eliminations | Consolidated | |||||||||||||||||||||||||
ASSETS | ||||||||||||||||||||||||||||||||
Current assets: | ||||||||||||||||||||||||||||||||
Cash and cash equivalents | $ | 62,967 | $ | 168 | $ | — | $ | 63,135 | $ | 31,447 | $ | 7,501 | $ | — | $ | 38,948 | ||||||||||||||||
Accounts and notes receivable, net | 557,527 | 85,947 | (528,715 | ) | 114,759 | 139,959 | 112,044 | (156,498 | ) | 95,505 | ||||||||||||||||||||||
Derivative contracts | 21,958 | — | — | 21,958 | — | — | — | — | ||||||||||||||||||||||||
Other current assets | 5,936 | 20,664 | — | 26,600 | 23,894 | 16,459 | — | 40,353 | ||||||||||||||||||||||||
Total current assets | 648,388 | 106,779 | (528,715 | ) | 226,452 | 195,300 | 136,004 | (156,498 | ) | 174,806 | ||||||||||||||||||||||
Property, plant and equipment, net | 967,259 | 2,370,151 | — | 3,337,410 | 278,637 | 1,856,081 | — | 2,134,718 | ||||||||||||||||||||||||
Investment in subsidiaries | 1,817,330 | — | (1,817,330 | ) | — | 1,642,482 | 3,584 | (1,642,482 | ) | 3,584 | ||||||||||||||||||||||
Other assets | 77,614 | 40,474 | (51,384 | ) | 66,704 | 76,052 | 59,592 | (60,368 | ) | 75,276 | ||||||||||||||||||||||
Total assets | $ | 3,510,591 | $ | 2,517,404 | $ | (2,397,429 | ) | $ | 3,630,566 | $ | 2,192,471 | $ | 2,055,261 | $ | (1,859,348 | ) | $ | 2,388,384 | ||||||||||||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||||||||||||||||||||||||||
Current liabilities: | ||||||||||||||||||||||||||||||||
Accounts payable and accrued expenses | $ | 224,015 | $ | 520,592 | $ | (528,715 | ) | $ | 215,892 | $ | 70,419 | $ | 217,712 | $ | (156,498 | ) | $ | 131,633 | ||||||||||||||
Other current liabilities | — | 16,214 | — | 16,214 | 1,020 | 26,139 | — | 27,159 | ||||||||||||||||||||||||
Total current liabilities | 224,015 | 536,806 | (528,715 | ) | 232,106 | 71,439 | 243,851 | (156,498 | ) | 158,792 | ||||||||||||||||||||||
Long-term debt | 1,000,000 | 103,683 | (51,384 | ) | 1,052,299 | 990,137 | 110,861 | (60,368 | ) | 1,040,630 | ||||||||||||||||||||||
Asset retirement obligation | 4,620 | 53,096 | — | 57,716 | 1,438 | 43,778 | — | 45,216 | ||||||||||||||||||||||||
Other liabilities | 15,000 | 1,817 | — | 16,817 | 23,015 | 1,256 | — | 24,271 | ||||||||||||||||||||||||
Deferred income taxes | 49,350 | — | — | 49,350 | 16,981 | 7,941 | — | 24,922 | ||||||||||||||||||||||||
Total liabilities | 1,292,985 | 695,402 | (580,099 | ) | 1,408,288 | 1,103,010 | 407,687 | (216,866 | ) | 1,293,831 | ||||||||||||||||||||||
Minority interest | — | 4,672 | — | 4,672 | — | 5,092 | — | 5,092 | ||||||||||||||||||||||||
Redeemable convertible preferred stock | 450,715 | — | — | 450,715 | 439,643 | — | — | 439,643 | ||||||||||||||||||||||||
Stockholders’ equity | 1,766,891 | 1,817,330 | (1,817,330 | ) | 1,766,891 | 649,818 | 1,642,482 | (1,642,482 | ) | 649,818 | ||||||||||||||||||||||
Total liabilities and stockholders’ equity | $ | 3,510,591 | $ | 2,517,404 | $ | (2,397,429 | ) | $ | 3,630,566 | $ | 2,192,471 | $ | 2,055,261 | $ | (1,859,348 | ) | $ | 2,388,384 | ||||||||||||||
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Condensed Consolidating Statements of Operations
(In Thousands)
(In Thousands)
Year Ended December 31 | ||||||||||||||||
2007 | ||||||||||||||||
Parent | Guarantor | |||||||||||||||
Company | Subsidiaries | Eliminations | Consolidated | |||||||||||||
Revenues | $ | 139,281 | $ | 538,171 | $ | — | $ | 677,452 | ||||||||
Expenses: | ||||||||||||||||
Direct operating expenses | 33,643 | 228,793 | — | 262,436 | ||||||||||||
General and administrative | 32,446 | 29,334 | — | 61,780 | ||||||||||||
Depreciation, depletion, and amortization | 43,257 | 183,852 | — | 227,109 | ||||||||||||
(Gain) loss on derivative contracts | (26,183 | ) | (34,549 | ) | — | (60,732 | ) | |||||||||
Total operating expenses | 83,163 | 407,430 | — | 490,593 | ||||||||||||
Income from operations | 56,118 | 130,741 | — | 186,859 | ||||||||||||
Equity earnings from subsidiaries | 137,515 | (137,515 | ) | — | ||||||||||||
Interest expense | (113,838 | ) | (3,347 | ) | — | (117,185 | ) | |||||||||
Other income (expense), net | (81 | ) | 10,152 | — | 10,071 | |||||||||||
Income (loss) before income taxes | 79,714 | 137,546 | (137,515 | ) | 79,745 | |||||||||||
Income tax expense | 29,493 | 31 | — | 29,524 | ||||||||||||
Net income (loss) | $ | 50,221 | $ | 137,515 | $ | (137,515 | ) | $ | 50,221 | |||||||
Year Ended December 31 | ||||||||||||||||
2006 | ||||||||||||||||
Parent | Guarantor | |||||||||||||||
Company | Subsidiaries | Eliminations | Consolidated | |||||||||||||
Revenues | $ | 63,041 | $ | 325,201 | $ | — | $ | 388,242 | ||||||||
Expenses: | ||||||||||||||||
Direct operating expenses | 25,773 | 226,519 | — | 252,292 | ||||||||||||
General and administrative | 31,904 | 23,730 | — | 55,634 | ||||||||||||
Depreciation, depletion, and amortization | 24,500 | 31,126 | — | 55,626 | ||||||||||||
(Gain) loss on derivative contracts | (12,327 | ) | 36 | — | (12,291 | ) | ||||||||||
Total operating expenses | 69,850 | 281,411 | — | 351,261 | ||||||||||||
Income from operations | (6,809 | ) | 43,790 | — | 36,981 | |||||||||||
Equity earnings from subsidiaries | 36,470 | — | (36,470 | ) | — | |||||||||||
Interest expense | (14,222 | ) | (2,682 | ) | — | (16,904 | ) | |||||||||
Other income (expense), net | 425 | 1,355 | — | 1,780 | ||||||||||||
Income (loss) before income taxes | 15,864 | 42,463 | (36,470 | ) | 21,857 | |||||||||||
Income tax expense | 243 | 5,993 | — | 6,236 | ||||||||||||
Net income (loss) | $ | 15,621 | $ | 36,470 | $ | (36,470 | ) | $ | 15,621 | |||||||
35
Year Ended December 31 | ||||||||||||||||
2005 | ||||||||||||||||
Parent | Guarantor | |||||||||||||||
Company | Subsidiaries | Eliminations | Consolidated | |||||||||||||
Revenues | $ | 52,916 | $ | 234,777 | $ | — | $ | 287,693 | ||||||||
Expenses: | ||||||||||||||||
Direct operating expenses | 17,238 | 196,156 | — | 213,394 | ||||||||||||
General and administrative | 7,627 | 4,281 | — | 11,908 | ||||||||||||
Depreciation, depletion, and amortization | 8,708 | 15,498 | — | 24,206 | ||||||||||||
(Gain) loss on derivative contracts | 4,132 | — | — | 4,132 | ||||||||||||
Total operating expenses | 37,705 | 215,935 | — | 253,640 | ||||||||||||
Income from operations | 15,211 | 18,842 | — | 34,053 | ||||||||||||
Equity earnings from subsidiaries | 9,284 | — | (9,284 | ) | — | |||||||||||
Interest expense | (610 | ) | (4,667 | ) | — | (5,277 | ) | |||||||||
Other income (expense), net | 358 | (1,273 | ) | — | (915 | ) | ||||||||||
Income (loss) before income taxes | 24,243 | 12,902 | (9,284 | ) | 27,861 | |||||||||||
Income tax expense | 7,641 | 2,327 | — | 9,968 | ||||||||||||
Income from continuing operations | 16,602 | 10,575 | (9,284 | ) | 17,893 | |||||||||||
Income from discontinued operations | 1,520 | (1,291 | ) | — | 229 | |||||||||||
Net income (loss) | $ | 18,122 | $ | 9,284 | $ | (9,284 | ) | $ | 18,122 | |||||||
Condensed Consolidating Statements of Cash Flows
(In Thousands)
(In Thousands)
Year Ended December 31 | ||||||||||||||||
2007 | ||||||||||||||||
Parent | Guarantor | |||||||||||||||
Company | Subsidiaries | Eliminations | Consolidated | |||||||||||||
Net cash (used in) provided by operating activities | $ | (301,288 | ) | $ | 667,724 | $ | (8,984 | ) | $ | 357,452 | ||||||
Net cash used in investing activities | (728,697 | ) | (656,884 | ) | — | (1,385,581 | ) | |||||||||
Net cash provided by (used in) financing activities | 1,061,505 | (18,173 | ) | 8,984 | 1,052,316 | |||||||||||
Net increase (decrease) in cash and cash equivalents | 31,520 | (7,333 | ) | — | 24,187 | |||||||||||
Cash and cash equivalents at beginning of year | 31,447 | 7,501 | — | 38,948 | ||||||||||||
Cash and cash equivalents at end of year | $ | 62,967 | $ | 168 | $ | — | $ | 63,135 | ||||||||
36
Year Ended December 31 | ||||||||||||||||
2006 | ||||||||||||||||
Parent | Guarantor | |||||||||||||||
Company | Subsidiaries | Eliminations | Consolidated | |||||||||||||
Net cash (used in) provided by operating activities | $ | (33,775 | ) | $ | 94,570 | $ | 6,554 | $ | 67,349 | |||||||
Net cash used in investing activities | (1,212,910 | ) | (127,657 | ) | — | (1,340,567 | ) | |||||||||
Net cash provided by (used in) financing activities | 1,233,555 | 39,434 | (6,554 | ) | 1,266,435 | |||||||||||
Net increase (decrease) in cash and cash equivalents | (13,130 | ) | 6,347 | — | (6,783 | ) | ||||||||||
Cash and cash equivalents at beginning of year | 44,577 | 1,154 | — | 45,731 | ||||||||||||
Cash and cash equivalents at end of year | $ | 31,447 | $ | 7,501 | $ | — | $ | 38,948 | ||||||||
Year Ended December 31 | ||||||||||||||||
2005 | ||||||||||||||||
Parent | Guarantor | |||||||||||||||
Company | Subsidiaries | Eliminations | Consolidated | |||||||||||||
Net cash (used in) provided by operating activities | $ | (11,525 | ) | $ | 38,560 | $ | 36,609 | $ | 63,644 | |||||||
Net cash used in investing activities | (84,577 | ) | (72,722 | ) | — | (157,299 | ) | |||||||||
Net cash provided by (used in) financing activities | 127,706 | 35,316 | (36,609 | ) | 126,413 | |||||||||||
Net increase in cash and cash equivalents | 31,604 | 1,154 | — | 32,758 | ||||||||||||
Cash and cash equivalents at beginning of year | 12,973 | — | — | 12,973 | ||||||||||||
Cash and cash equivalents at end of year | $ | 44,577 | $ | 1,154 | $ | — | $ | 45,731 | ||||||||
37