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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Washington, D.C. 20549
Form 10-Q
(Mark One) | ||
þ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
For the quarterly period ended September 30, 2007 | ||
OR | ||
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
For the transition period from to |
Commission File Number: 001-33784
SANDRIDGE ENERGY, INC.
(Exact name of registrant as specified in its charter)
Delaware (State or other jurisdiction of incorporation or organization) | 20-8084793 (I.R.S. Employer Identification No.) | |
1601 N.W. Expressway, Suite 1600, Oklahoma City, Oklahoma (Address of principal executive offices) | 73118 (Zip Code) |
Registrant’s telephone number, including area code:
(405) 753-5500
Former name, former address and former fiscal year, if changed since last report: Not applicable
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes o No þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” inRule 12b-2 of the Exchange Act.
Large accelerated filer o Accelerated filer o Non-accelerated filer þ
Indicate by check mark whether the registrant is a shell company (as defined inRule 12b-2 of the Exchange Act). Yes o No þ
The number of shares outstanding of the registrant’s common stock, par value $0.001 per shares, as of the close of business on November 30, 2007, was 141,845,661.
SANDRIDGE ENERGY, INC.
FORM 10-Q
Quarter Ended September 30, 2007
FORM 10-Q
Quarter Ended September 30, 2007
INDEX
Financial Statements (Unaudited) | 4 | |||||||
Condensed Consolidated Balance Sheets | 4 | |||||||
Condensed Consolidated Statements of Operations | 5 | |||||||
Condensed Consolidated Statements of Stockholders’ Equity | 6 | |||||||
Condensed Consolidated Statements of Cash Flows | 7 | |||||||
Notes to Condensed Consolidated Financial Statements | 8 | |||||||
Management’s Discussion and Analysis of Financial Condition and Results of Operations | 22 | |||||||
Quantitative and Qualitative Disclosures About Market Risk | 39 | |||||||
Controls and Procedures | 41 | |||||||
Legal Proceedings | 41 | |||||||
Risk Factors | 42 | |||||||
Unregistered Sales of Equity Securities and Use of Proceeds | 42 | |||||||
Exhibits | 42 | |||||||
43 | ||||||||
44 | ||||||||
Certifications Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | ||||||||
Certifications Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | ||||||||
Certification of CEO Pursuant to Section 302 | ||||||||
Certification of CFO Pursuant to Section 302 | ||||||||
Certification of CEO & CFO Pursuant to Section 906 |
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DISCLOSURES REGARDING FORWARD-LOOKING STATEMENTS
This quarterly report onForm 10-Q (“Quarterly Report”) includes “forward-looking statements” within the meaning of various provisions of the Securities Act of 1933, as amended and the Securities Exchange Act of 1934, as amended. Various statements contained in this Quarterly Report, including those that express a belief, expectation, or intention, as well as those that are not statements of historical fact, are forward-looking statements. The forward-looking statements may include projections and estimates concerning the timing and success of specific projects and our future production, revenues, income and capital spending. Our forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes. We have based these forward-looking statements on our current expectations and assumptions about future events. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. However, whether actual results and developments will conform with our expectations and predictions is subject to a number of risks and uncertainties, including Risk Factors discussed in our Registration Statement onForm S-1 filed with the Securities and Exchange Commission on October 23, 2007 andItem 1A- Risk Factors contained herein, the opportunities that may be presented to and pursued by us, competitive actions by other companies, changes in laws or regulations, and other factors, many of which are beyond our control. Consequently, all of the forward-looking statements made in this document are qualified by these cautionary statements and there can be no assurance that the actual results or developments anticipated will be realized or, even if substantially realized, that they will have the expected consequences to or effects on our company or our business or operations. Such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in the forward-looking statements. We undertake no obligation to publicly update or revise any forward-looking statements.
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ITEM 1. | Financial Statements |
SandRidge Energy, Inc. and Subsidiaries
September 30, | December 31, | |||||||
2007 | 2006 | |||||||
(Unaudited) | ||||||||
(In thousands) | ||||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 32,013 | $ | 38,948 | ||||
Accounts receivable, net: | ||||||||
Trade | 71,957 | 89,774 | ||||||
Related parties | 16,727 | 5,731 | ||||||
Derivative contracts | 27,903 | — | ||||||
Inventories | 4,249 | 2,544 | ||||||
Deferred income taxes | — | 6,315 | ||||||
Other current assets | 20,548 | 31,494 | ||||||
Total current assets | 173,397 | 174,806 | ||||||
Oil and natural gas properties, using full cost method of accounting | ||||||||
Proved | 2,388,534 | 1,636,832 | ||||||
Unproved | 247,757 | 282,374 | ||||||
Less: accumulated depreciation and depletion | (174,552 | ) | (60,752 | ) | ||||
2,461,739 | 1,858,454 | |||||||
Other property, plant and equipment, net | 427,756 | 276,264 | ||||||
Derivative contracts | 4,139 | — | ||||||
Goodwill | 27,076 | 26,198 | ||||||
Investments | 6,983 | 3,584 | ||||||
Restricted deposits | 39,851 | 33,189 | ||||||
Other assets | 29,515 | 15,889 | ||||||
Total assets | $ | 3,170,456 | $ | 2,388,384 | ||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
Current liabilities: | ||||||||
Current maturities of long-term debt | $ | 14,293 | $ | 26,201 | ||||
Accounts payable and accrued expenses: | ||||||||
Trade | 181,227 | 129,799 | ||||||
Related parties | 3,182 | 1,834 | ||||||
Deferred income taxes | 6,740 | — | ||||||
Derivative contracts | — | 958 | ||||||
Total current liabilities | 205,442 | 158,792 | ||||||
Long-term debt | 1,437,211 | 1,040,630 | ||||||
Derivative contracts | — | 3,052 | ||||||
Other long-term obligations | 16,219 | 21,219 | ||||||
Asset retirement obligation | 57,508 | 45,216 | ||||||
Deferred income taxes | 32,992 | 24,922 | ||||||
Total liabilities | 1,749,372 | 1,293,831 | ||||||
Commitments and contingencies (Note 12) | ||||||||
Minority interest | 5,605 | 5,092 | ||||||
Redeemable convertible preferred stock, $0.001 par value, 2,650 shares authorized; 2,184 and 2,137 shares issued and outstanding at September 30, 2007 and December 31, 2006, respectively | 450,356 | 439,643 | ||||||
Stockholders’ equity: | ||||||||
Preferred stock, no par; 50,000 shares authorized; no shares issued and outstanding in 2007 and 2006 | — | — | ||||||
Common stock, $0.001 par value, 400,000 shares authorized; 109,272 issued and 107,820 outstanding at September 30, 2007 and 93,048 issued and 91,604 outstanding at December 31, 2006 | 108 | 92 | ||||||
Additional paid-in capital | 889,211 | 574,868 | ||||||
Treasury stock, at cost | (18,496 | ) | (17,835 | ) | ||||
Retained earnings | 94,300 | 92,693 | ||||||
Total stockholders’ equity | 965,123 | 649,818 | ||||||
Total liabilities and stockholders’ equity | $ | 3,170,456 | $ | 2,388,384 | ||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
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SandRidge Energy, Inc. and Subsidiaries
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2007 | 2006 | 2007 | 2006 | |||||||||||||
(Unaudited) | ||||||||||||||||
(In thousands except per share amounts) | ||||||||||||||||
Revenues: | ||||||||||||||||
Natural gas and crude oil | $ | 113,106 | $ | 18,150 | $ | 319,556 | $ | 46,419 | ||||||||
Drilling and services | 16,684 | 35,742 | 56,928 | 105,713 | ||||||||||||
Midstream and marketing | 19,030 | 29,326 | 71,131 | 91,218 | ||||||||||||
Other | 4,828 | 6,432 | 14,160 | 19,827 | ||||||||||||
Total revenues | 153,648 | 89,650 | 461,775 | 263,177 | ||||||||||||
Expenses: | ||||||||||||||||
Production | 28,689 | 7,960 | 77,707 | 21,625 | ||||||||||||
Production taxes | 4,402 | 1,050 | 12,328 | 2,579 | ||||||||||||
Drilling and services | 6,809 | 24,985 | 30,935 | 72,670 | ||||||||||||
Midstream and marketing | 14,444 | 27,139 | 61,191 | 85,525 | ||||||||||||
Depreciation, depletion and amortization — natural gas and crude oil | 45,177 | 6,064 | 115,876 | 13,932 | ||||||||||||
Depreciation, depletion and amortization — other | 14,282 | 8,298 | 36,545 | 22,106 | ||||||||||||
General and administrative | 20,421 | 11,721 | 45,781 | 32,024 | ||||||||||||
Gain on derivative contracts | (39,247 | ) | (5,304 | ) | (55,228 | ) | (16,176 | ) | ||||||||
Gain on sale of assets | (1,045 | ) | (839 | ) | (1,704 | ) | (849 | ) | ||||||||
Total expenses | 93,932 | 81,074 | 323,431 | 233,436 | ||||||||||||
Income from operations | 59,716 | 8,576 | 138,344 | 29,741 | ||||||||||||
Other income (expense): | ||||||||||||||||
Interest income | 575 | 51 | 4,201 | 448 | ||||||||||||
Interest expense | (28,522 | ) | (2,506 | ) | (88,630 | ) | (4,090 | ) | ||||||||
Minority interest | (164 | ) | (182 | ) | (321 | ) | (281 | ) | ||||||||
Income from equity investments | 1,235 | 737 | 3,399 | 40 | ||||||||||||
Total other income (expense) | (26,876 | ) | (1,900 | ) | (81,351 | ) | (3,883 | ) | ||||||||
Income before income tax expense | 32,840 | 6,676 | 56,993 | 25,858 | ||||||||||||
Income tax expense | 11,920 | 1,781 | 21,002 | 6,931 | ||||||||||||
Net income | 20,920 | 4,895 | 35,991 | 18,927 | ||||||||||||
Preferred stock dividends and accretion | 9,313 | — | 30,573 | — | ||||||||||||
Income available to common stockholders | $ | 11,607 | $ | 4,895 | $ | 5,418 | $ | 18,927 | ||||||||
Basic and diluted income per share available to common stockholders | $ | 0.11 | $ | 0.07 | $ | 0.05 | $ | 0.26 | ||||||||
Weighted average number of shares outstanding: | ||||||||||||||||
Basic | 107,554 | 71,870 | 102,562 | 71,692 | ||||||||||||
Diluted | 109,049 | 72,806 | 103,778 | 72,633 | ||||||||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
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Additional | ||||||||||||||||||||
Common | Paid-in | Treasury | Retained | |||||||||||||||||
Stock | Capital | Stock | Earnings | Total | ||||||||||||||||
(Unaudited) | ||||||||||||||||||||
(In thousands) | ||||||||||||||||||||
Balance, December 31, 2006 | $ | 92 | $ | 574,868 | $ | (17,835 | ) | $ | 92,693 | $ | 649,818 | |||||||||
Stock offering, net of $1.4 million in offering costs | 18 | 318,652 | — | — | 318,670 | |||||||||||||||
Conversion of common stock to redeemable convertible preferred stock | (1 | ) | (9,650 | ) | — | — | (9,651 | ) | ||||||||||||
Accretion on redeemable convertible preferred stock | — | — | — | (1,062 | ) | (1,062 | ) | |||||||||||||
Purchase of treasury stock | (1 | ) | — | (1,578 | ) | — | (1,579 | ) | ||||||||||||
Common stock issued under retirement plan | — | 379 | 917 | — | 1,296 | |||||||||||||||
Stock-based compensation | — | 4,962 | — | — | 4,962 | |||||||||||||||
Net income | — | — | — | 35,991 | 35,991 | |||||||||||||||
Redeemable convertible preferred stock dividend | — | — | — | (33,322 | ) | (33,322 | ) | |||||||||||||
Balance, September 30, 2007 | $ | 108 | $ | 889,211 | $ | (18,496 | ) | $ | 94,300 | $ | 965,123 | |||||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
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SandRidge Energy, Inc. and Subsidiaries
Nine Months Ended | ||||||||
September 30, | ||||||||
2007 | 2006 | |||||||
(Unaudited) | ||||||||
(In thousands) | ||||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||||
Net income | $ | 35,991 | $ | 18,927 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||
Provision for doubtful accounts | — | 2,458 | ||||||
Depreciation, depletion and amortization | 152,421 | 36,038 | ||||||
Debt issuance cost amortization | 14,903 | — | ||||||
Deferred income taxes | 20,004 | 2,662 | ||||||
Unrealized gain on derivatives | (36,052 | ) | (2,007 | ) | ||||
Gain on sale of assets | (1,704 | ) | (849 | ) | ||||
Interest income — restricted deposits | (1,024 | ) | — | |||||
Income from equity investments, net of distributions | (3,399 | ) | (28 | ) | ||||
Stock-based compensation | 4,962 | 8,156 | ||||||
Minority interest | 321 | 281 | ||||||
Changes in operating assets and liabilities | 53,133 | 1,862 | ||||||
Net cash provided by operating activities | 239,556 | 67,500 | ||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||
Capital expenditures for property, plant and equipment | (895,160 | ) | (181,231 | ) | ||||
Acquisition of assets | (3,001 | ) | (63,125 | ) | ||||
Proceeds from sale of assets | 6,458 | 19,742 | ||||||
Proceeds from sale of investment | — | 2,373 | ||||||
Contributions on equity investments | — | (3,388 | ) | |||||
Restricted deposits | (5,638 | ) | — | |||||
Restricted cash | — | 2,373 | ||||||
Net cash used in investing activities | (897,341 | ) | (223,256 | ) | ||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||
Proceeds from borrowings | 1,262,769 | 295,215 | ||||||
Repayments of borrowings | (879,592 | ) | (177,425 | ) | ||||
Dividends paid — preferred | (24,366 | ) | — | |||||
Minority interest contributions (distributions) | 192 | (390 | ) | |||||
Proceeds from issuance of common stock | 319,966 | 3,343 | ||||||
Purchase of treasury shares | (1,579 | ) | — | |||||
Debt issuance costs | (26,540 | ) | — | |||||
Net cash provided by financing activities | 650,850 | 120,743 | ||||||
NET DECREASE IN CASH AND CASH EQUIVALENTS | (6,935 | ) | (35,013 | ) | ||||
CASH AND CASH EQUIVALENTS, beginning of year | 38,948 | 45,731 | ||||||
CASH AND CASH EQUIVALENTS, end of period | $ | 32,013 | $ | 10,718 | ||||
Supplemental Disclosure of Noncash Investing and Financing Activities: | ||||||||
Insurance premiums financed | $ | 1,496 | $ | — | ||||
Accretion on redeemable convertible preferred stock | $ | 1,062 | $ | — | ||||
Common stock issued in connection with acquisitions | $ | — | $ | 5,128 | ||||
Redeemable convertible preferred stock dividends, net of dividends paid | $ | 8,956 | $ | — | ||||
Property, plant and equipment addition due to settlement | $ | 4,500 | $ | — |
The accompanying notes are an integral part of these condensed consolidated financial statements.
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SandRidge Energy, Inc. and Subsidiaries
1. | Basis of Presentation |
Nature of Business. SandRidge Energy, Inc. and its subsidiaries (collectively, the “Company”, “SandRidge”, “we”, “us”, or “our”) 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 CO2 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 and Gulf Coast area.
On November 21, 2006, the Company acquired all of the outstanding membership interests of NEG Oil & Gas LLC (“NEG”).
Interim Financial Statements. The accompanying condensed consolidated balance sheet as of December 31, 2006 has been derived from our audited financial statements contained in the Company’s Registration Statement onForm S-1/A filed October 23, 2007 (the “Registration Statement”). The unaudited interim condensed consolidated financial statements of SandRidge and its subsidiaries have been prepared by the Company in accordance with the accounting policies stated in the audited consolidated financial statements contained in the Company’sS-1/A filed October 23, 2007 pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted, although we believe that the disclosures contained herein are adequate to make the information presented not misleading. In the opinion of management, all adjustments (consisting only of normal recurring adjustments) necessary for a fair presentation in accordance with GAAP have been included in these unaudited interim condensed consolidated financial statements. These condensed financial statements should be read in conjunction with the financial statements and notes thereto included in the Registration Statement.
2. | Significant Accounting Policies |
For a description of the Company’s accounting policies, refer to Note 1 of the 2006 consolidated financial statements included in the Company’s Registration Statement, as well as Note 10 herein.
Reclassifications. Certain reclassifications have been made in prior period financial statements to conform with current period presentation.
Change in Method of Accounting for Oil and Gas Operations. In the fourth quarter of 2006, the Company changed from the successful efforts method to the full cost method of accounting for its oil and gas operations. Prior period financial statements presented herein have been restated to reflect the change.
SandRidge’s financial results have been retroactively restated to reflect the conversion to the full cost method. As prescribed by full cost accounting rules, all costs associated with property acquisition, exploration, and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities and other costs incurred for the purpose of finding oil and gas reserves.
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Notes to Condensed Consolidated Financial Statements — (Continued)
A comparison of the Company’s previously presented income tax expense, net income, and earnings per share under the successful efforts method of accounting to its results of operations disclosed herein are as follows (in thousands, except per share amounts):
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, 2006 | September 30, 2006 | |||||||||||||||
(As Originally | (As Originally | |||||||||||||||
Presented) | (As Restated) | Presented) | (As Restated) | |||||||||||||
Income tax expense | $ | 4,844 | $ | 1,781 | $ | 8,998 | $ | 6,931 | ||||||||
Net income | $ | 13,308 | $ | 4,895 | $ | 15,175 | $ | 18,927 | ||||||||
Basic earnings per share | $ | 0.18 | $ | 0.07 | $ | 0.21 | $ | 0.26 | ||||||||
Diluted earnings per share | $ | 0.18 | $ | 0.07 | $ | 0.21 | $ | 0.26 | ||||||||
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. These 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 by net equivalent proved reserves at the beginning of the quarter.
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 GAAP to be measured at fair value. SFAS No. 157 clarifies guidance in FASB Concepts Statement (“CON”) 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 is currently evaluating the impact of adopting SFAS No. 157 on the financial 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”(“SFAS No. 159”), 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. The Company has not yet evaluated the potential impact of this standard.
3. | Acquisitions and Dispositions |
On March 15, 2006, the Company acquired from an executive officer and director, an additional 12.5% interest in PetroSource Energy Company, a consolidated subsidiary. The acquisition consisted of the extinguishment 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
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Notes to Condensed Consolidated Financial Statements — (Continued)
SandRidge Energy, Inc. common stock (valued at $4.7 million). The cash and equity consideration was paid in July 2006.
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 SandRidge Energy, Inc. common stock (valued at $0.5 million). As a result of this acquisition, the Company became a 100% owner of PetroSource Energy Company.
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.
4. | Property, Plant and Equipment |
Property, plant and equipment consists of the following (in thousands):
September 30, | December 31, | |||||||
2007 | 2006 | |||||||
Oil and natural gas properties: | ||||||||
Proved | $ | 2,388,534 | $ | 1,636,832 | ||||
Unproved | 247,757 | 282,374 | ||||||
Total oil and natural gas properties | 2,636,291 | 1,919,206 | ||||||
Less accumulated depreciation and depletion | (174,552 | ) | (60,752 | ) | ||||
Net oil and natural gas properties capitalized costs | 2,461,739 | 1,858,454 | ||||||
Land | 1,344 | 738 | ||||||
Non oil and gas equipment | 491,000 | 337,294 | ||||||
Buildings and structures | 37,725 | 6,564 | ||||||
Total | 530,069 | 344,596 | ||||||
Less accumulated depreciation, depletion and amortization | (102,313 | ) | (68,332 | ) | ||||
Net capitalized costs | 427,756 | �� | 276,264 | |||||
Total property, plant and equipment | $ | 2,889,495 | $ | 2,134,718 | ||||
The amount of capitalized interest in the nine months ended September 30, 2007 and 2006 was approximately $1.5 million and $1.0 million, respectively, and is included in the above non oil and gas equipment balance.
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 of the property was approximately $25 million in cash plus the assumption of an obligation to indemnify the sellers in connection with pending litigation involving the property. Payment of the purchase price was funded through a draw on the Company’s senior credit facility. The related litigation was settled subsequent to September 30, 2007, resulting in an additional cost to the Company of $4.5 million which was treated as an adjustment to the purchase price of the property. For additional discussion of this settlement, refer to Note 17 herein.
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SandRidge Energy, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial Statements — (Continued)
5. | Goodwill |
The change in the carrying amount of goodwill from December 31, 2006 to September 30, 2007 was as follows (in thousands):
Balance at December 31, 2006 | $ | 26,198 | ||
Adjustments | 878 | |||
Balance at September 30, 2007 | $ | 27,076 | ||
The adjustments made in the nine months ended September 30, 2007 related to the preliminary purchase allocation in connection with the NEG acquisition in November 2006. The Company has assigned all of the NEG goodwill to the Exploration and Production segment.
6. | Asset Retirement Obligation |
A reconciliation of the beginning and ending aggregate carrying amounts of the asset retirement obligations for the period of December 31, 2006 to September 30, 2007 is as follows (in thousands):
Asset retirement obligation, December 31, 2006 | $ | 45,216 | ||
Liability incurred upon acquiring and drilling wells | 1,688 | |||
Revisions in estimated cash flows | 7,747 | |||
Liability settled in current period | (9 | ) | ||
Accretion of discount expense | 2,866 | |||
Asset retirement obligation, September 30, 2007 | $ | 57,508 | ||
7. | Long-Term Debt |
Long-term obligations consist of the following (in thousands):
September 30, | December 31, | |||||||
2007 | 2006 | |||||||
Senior credit facility | $ | 400,000 | $ | 140,000 | ||||
Senior bridge facility | — | 850,000 | ||||||
Senior term loan | 1,000,000 | — | ||||||
Other notes payable: | ||||||||
Drilling rig fleet and related oil field services equipment | 51,261 | 61,105 | ||||||
Sagebrush | — | 4,000 | ||||||
Insurance financing | 199 | 7,240 | ||||||
Other equipment and vehicles | 44 | 4,486 | ||||||
Total debt | 1,451,504 | 1,066,831 | ||||||
Less: Current maturities of long-term debt | 14,293 | 26,201 | ||||||
Long-term debt | $ | 1,437,211 | $ | 1,040,630 | ||||
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
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Notes to Condensed Consolidated Financial Statements — (Continued)
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 unsecured bridge facility (as discussed below) which was repaid in full during March 2007.
The senior credit facility also contains financial covenants, including maintenance of agreed upon levels for the ratio of (i) total funded debt to EBITDAX (as defined in the senior credit facility), (ii) 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 September 30, 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 proven oil and gas reserves representing at least 80% of the present discounted value (as defined in the senior credit facility) of proven oil and gas reserves reviewed in determining the borrowing base for the senior credit facility. Additionally, the obligations under the senior credit facility will be guaranteed by certain Company subsidiaries.
At the Company’s election, interest under the senior credit facility is determined by reference to (i) the British Bankers Association LIBOR rate, or LIBOR, 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 will be 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 will be paid at the end of each three-month period. The average interest rates paid on amounts outstanding under our senior credit facility for the three and nine month periods ended September 30, 2007 were 7.08% and 7.62%, respectively.
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 14, were used to repay outstanding borrowings under the Company’s senior credit facility.
The borrowing base was increased to $400 million on May 2, 2007, and to $700 million on September 14, 2007. At September 30, 2007, the Company had $400 million in outstanding indebtedness under this facility. The Company repaid all amounts outstanding under this facility subsequent to September 30, 2007. See Note 17 for further discussion.
Senior Bridge Facility. On November 21, 2006, the Company also entered into an $850.0 million senior unsecured bridge facility (the “senior bridge facility”), which was repaid in March 2007. The Company expensed 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
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Notes to Condensed Consolidated Financial Statements — (Continued)
placement of common equity as described in Note 14. 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 our variable term loans for the three and nine month periods ended September 30, 2007 were 8.99% and 8.98%, respectively.
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, 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 is unable or does not offer to exchange the senior term loans for senior unsecured notes with registration rights by April 30, 2008, the 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.
For the nine months ended September 30, interest payments, net of amounts capitalized were approximately $59.5 million in 2007 and $4.6 million in 2006.
8. | Other Long-Term Obligations |
The Company has recorded a long-term obligation for amounts to be paid under a settlement agreement with Conoco, Inc. (“Conoco”). During January 2007, the Company agreed to pay approximately $25.0 million plus interest to Conoco to settle outstanding litigation. Under this agreement, payments are to be made in $5.0 million increments on April 1, 2007, July 1, 2008, July 1, 2009, July 1, 2010, and July 1, 2011. On March 30, 2007, the Company made the first $5.0 million settlement payment plus accrued interest. The $5.0 million payment to be made on July 1, 2008 has been included in accounts payable-trade in the accompanying condensed consolidated balance sheets as of September 30, 2007. Unpaid settlement amounts of approximately $15.0 million and $20.0 million have been included in other long-term obligations in the accompanying condensed consolidated balance sheets as of September 30, 2007 and December 31, 2006, respectively.
9. | Derivatives |
The Company has entered into various derivative contracts including collars, fixed price swaps, and basis swaps with counterparties. The contracts expire on various dates through December 31, 2009.
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Notes to Condensed Consolidated Financial Statements — (Continued)
At September 30, 2007, the Company’s open commodity derivative contracts consisted of the following:
Weighted Avg. | ||||||||||||
Period | Commodity | Notional | Fix Price | |||||||||
Fixed price swaps: | ||||||||||||
April 2007 — October 2007 | Natural gas | 4,280,000 MmBtu | $ | 7.02 | ||||||||
April 2007 — October 2007 | Natural gas | 4,280,000 MmBtu | $ | 7.50 | ||||||||
September 2007 — December 2007 | Natural gas | 1,220,000 MmBtu | $ | 8.88 | ||||||||
October 2007 — December 2007 | Natural gas | 920,000 MmBtu | $ | 7.60 | ||||||||
October 2007 — December 2007 | Natural gas | 920,000 MmBtu | $ | 7.82 | ||||||||
October 2007 — December 2007 | Natural gas | 920,000 MmBtu | $ | 8.00 | ||||||||
October 2007 — December 2007 | Natural gas | 920,000 MmBtu | $ | 8.04 | ||||||||
October 2007 — December 2007 | Natural gas | 920,000 MmBtu | $ | 8.77 | ||||||||
October 2007 — December 2007 | Natural gas | 920,000 MmBtu | $ | 9.04 | ||||||||
November 2007 — June 2008 | Natural gas | 4,860,000 MmBtu | $ | 8.05 | ||||||||
November 2007 — June 2008 | Natural gas | 9,720,000 MmBtu | $ | 8.20 | ||||||||
November 2007 — March 2008 | Natural gas | 1,520,000 MmBtu | $ | 8.51 | ||||||||
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 | ||||||||
May 2008 — August 2008 | Natural gas | 2,460,000 MmBtu | $ | 8.38 | ||||||||
July 2008 — September 2008 | Natural gas | 920,000 MmBtu | $ | 8.23 | ||||||||
July 2008 — December 2008 | Natural gas | 1,840,000 MmBtu | $ | 8.31 | ||||||||
Collars: | ||||||||||||
January 2007 — December 2007 | Crude oil | 60,000 Bbls | $ | 50.00 − $84.50 | ||||||||
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 2007 — December 2007 | Natural gas | 7,300,000 MmBtu | $ | (0.5925 | ) | |||||||
January 2007 — December 2007 | Natural gas | 14,600,000 MmBtu | $ | (0.70 | ) | |||||||
April 2007 — October 2007 | Natural gas | 4,280,000 MmBtu | $ | (0.530 | ) | |||||||
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 | ) | |||||||
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 | ) |
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Notes to Condensed Consolidated Financial Statements — (Continued)
These derivatives have not been designated as hedges and 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 on derivative contracts in the condensed consolidated statements of operations. The following summarizes the cash settlements and valuation gains and losses for the three and nine month periods ended September 30, 2007 and 2006 (in thousands):
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2007 | 2006 | 2007 | 2006 | |||||||||||||
Realized gain | $ | (19,969 | ) | $ | (13,875 | ) | $ | (19,176 | ) | $ | (14,169 | ) | ||||
Unrealized loss (gain) | (19,278 | ) | 8,571 | (36,052 | ) | (2,007 | ) | |||||||||
Gain on derivative contracts | $ | (39,247 | ) | $ | (5,304 | ) | $ | (55,228 | ) | $ | (16,176 | ) | ||||
10. | Income Taxes |
In accordance with applicable generally accepted accounting principles, the Company estimates for each interim reporting period the effective tax rate expected for the full fiscal year and uses that estimated rate in providing income taxes on a current year-to-date basis.
On January 1, 2007, the Company adopted the provisions of FASB Interpretation No. 48 (“FIN 48”), “Accounting for Uncertainty in Income Taxes.” The Company has determined that no uncertain tax positions exist where the Company would be required to make additional tax payments. As a result, the Company has not recorded any additional liabilities for any unrecognized tax benefits as of September 30, 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 penalties and interest 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 September 30, 2007.
For the nine months ended September 30, income tax payments were approximately $2.7 million in 2007 and $1.9 million in 2006.
11. | Earnings Per Share |
Basic earnings per share are computed using the weighted average number of common shares outstanding during the period. 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 three and nine month periods ended September 30, 2007 and 2006 (in thousands):
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2007 | 2006 | 2007 | 2006 | |||||||||||||
Weighted average basic common shares outstanding | 107,554 | 71,870 | 102,562 | 71,692 | ||||||||||||
Effect of dilutive securities: | ||||||||||||||||
Restricted stock | 1,495 | 936 | 1,216 | 941 | ||||||||||||
Weighted average diluted common and potential common shares outstanding | 109,049 | 72,806 | 103,778 | 72,633 | ||||||||||||
In computing diluted earnings per share, the Company evaluated the if-converted method. Under this method, the Company assumes the conversion of the outstanding redeemable convertible 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
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Notes to Condensed Consolidated Financial Statements — (Continued)
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.
12. | Commitments and Contingencies |
The Company is a defendant in certain 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 other than those specifically identified below, which individually or in the aggregate, could have a material effect on the financial condition, operationsand/or cash flows of the Company.
Roosevelt Litigation. On May 18, 2004, the Company commenced a civil action seeking declaratory judgment against Elliot Roosevelt, Jr., E.R. Family Limited Partnership and Ceres Resource Partners, L.P. in the District Court of Dallas County, Texas, 101st Judicial District, SandRidge Energy, Inc. and Riata Energy Piceance, LLC v. Elliot Roosevelt, Jr. et al, CauseNo. 92.717-C. This suit sought a declaratory judgment relating to the rights of the parties in and to certain leases in a defined area of mutual interest in the Piceance Basin pursuant to an acquisition agreement entered into in 1989, including the Company’s 41,454 gross (16,193 net) acreage position. The Company tried the case to a jury in July 2006. Before the case was submitted to the jury, the trial court granted Roosevelt a directed verdict stating that he owned a 25% deferred interest in the Company’s acreage after project payout. The directed verdict is not likely to affect the Company’s proved reserves of 11.7 Bcfe, because of the requirement that project payout be achieved before the deferred interest shares in revenue. Other issues of fact were submitted to the jury. The trial court recently entered a judgment favorable to Roosevelt. The Company has filed a motion to modify the judgment and for a new trial. Depending on the outcome of this motion, the Company expects to appeal, at a minimum, from the entry of the directed verdict. If the Company does not ultimately prevail, the deferred interest will reduce the Company’s economic returns from the project, if project payout is achieved.
The Company is subject to other claims in the ordinary course of business. However, the Company believes that the ultimate resolution of the above mentioned claims and other current legal proceedings will not have a material adverse effect on its results of operations, financial condition, or cash flows.
13. | Redeemable Convertible Preferred Stock |
In November 2006, the Company sold 2,136,667 shares of redeemable convertible preferred stock as part 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. 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 is $210 per share as of September 30, 2007. Each share of convertible preferred stock is initially convertible into ten shares of common stock at the option of the holder, subject to certain anti-dilution adjustments.
On January 31, 2007, the Company’s Board of Directors declared a dividend on the outstanding shares of redeemable convertible preferred stock. The dividend of $3.21 per share was paid in cash on February 15, 2007. The dividend covered the time period from November 21, 2006, when the shares were issued, through February 1, 2007.
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 converted 526,316 shares of common stock into 47,619 shares of redeemable convertible preferred stock.
On May 8, 2007, the Company’s Board of Directors declared a dividend on the outstanding shares of redeemable convertible preferred stock. The dividend of $3.97 per share was paid in cash on May 15, 2007. The dividend covered the time period from February 2, 2007 through May 1, 2007.
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Notes to Condensed Consolidated Financial Statements — (Continued)
On June 8, 2007, the Company’s Board of Directors declared a dividend on the outstanding shares of redeemable convertible preferred stock. The dividend of $4.10 per share was paid in cash on August 15, 2007. The dividend covered the time period from May 2, 2007 through August 1, 2007.
On September 24, 2007, the Company’s Board of Directors declared a dividend on the outstanding shares of redeemable convertible preferred stock. The dividend of $4.10 per share was paid in cash on November 15, 2007. The dividend covers the time period from August 2, 2007 to November 1, 2007.
Approximately $9.0 million and $29.5 million in paid and unpaid dividends have been included in the Company’s earnings per share calculations for the three and nine month periods ended September 30, 2007, respectively, as presented in the accompanying condensed consolidated statements of operations.
14. | Stockholders’ Equity |
The following table presents information regarding SandRidge’s common stock (in thousands):
September 30, | December 31, | |||||||
2007 | 2006 | |||||||
Shares authorized | 400,000 | 400,000 | ||||||
Shares outstanding at end of period | 107,820 | 91,604 | ||||||
Shares held in treasury | 1,452 | 1,444 |
The Company is authorized to issue 50,000,000 shares of preferred stock, no par value, of which no shares were outstanding as of September 30, 2007 and December 31, 2006.
Common Stock Issuance. 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.
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 41,095 shares at a total value of $0.7 million during the nine month period ended September 30, 2007. 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 program 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 the Company’s 401k Plan brokerage account. 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 vest over periods of one, four, or seven years. All awards issued during and after 2006 have four year vesting periods. These shares of restricted common stock are subject to restriction on transfer and certain conditions to vesting.
For the three months ended September 30, the Company recognized stock-based compensation expense related to restricted stock of $2.7 million in 2007 and $3.7 million in 2006. For the nine months ended September 30, the Company recognized stock-based compensation expense related to restricted stock of approximately $5.0 million in 2007 and $8.2 million in 2006. Stock-based compensation expense is reflected in general and administrative expense in the condensed consolidated statements of operations.
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Notes to Condensed Consolidated Financial Statements — (Continued)
15. | 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 oilfield service supplies. Following is a summary of significant transactions with such related parties for the three and nine month periods ended September 30, 2007 and 2006 (in thousands):
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2007 | 2006 | 2007 | 2006 | |||||||||||||
Sales to and reimbursements from related parties | $ | 27,355 | $ | 4,449 | $ | 72,434 | $ | 12,070 | ||||||||
Purchases of services from related parties | $ | 32,093 | $ | 1,394 | $ | 42,544 | $ | 3,656 | ||||||||
On June 1, 2006, the Company purchased certain producing well interest from an executive officer and director. The purchase price was approximately $9.0 million in cash. The cash consideration was paid in July 2006.
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 condensed 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 $1.7 million and $0.1 million for the nine month periods ended September 30, 2007 and 2006, respectively. The lease extends to August 2009.
On May 2, 2007, the Company purchased certain leasehold acreage from a partnership controlled by a director. The purchase price was approximately $8.3 million in cash.
On June 11, 2007, the Company purchased certain producing well interests from a director. The purchase price was approximately $3.5 million in cash.
Larclay, L.P. Larclay is a joint venture between the Company and Clayton Williams Energy, Inc. (“CWEI”) and was formed to acquire drilling rigs and provide land drilling services. Larclay currently owns 12 rigs, one of which has not 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 joint venture. CWEI is responsible for financing and purchasing of the rigs. The Company had sales to and cost reimbursements from Larclay for the three and nine months ended September 30, 2007 of $20.0 million and $48.9 million, respectively. The Company had sales to and cost reimbursements from Larclay for the three and nine months ended September 30, 2006 of $0.7 million and $0.8 million, respectively. As of September 30, 2007 and December 31, 2006, the Company had accounts receivable — related party due from Larclay of $16.0 million and $3.0 million, respectively. Additionally, the Company had purchases from Larclay for the three and nine months ended September 30, 2007 of $10.0 million and $25.6 million, respectively. As of September 30, 2007, the Company had accounts payable — related party due to Larclay of $2.2 million. The Company made no purchases from Larclay in 2006.
16. | Industry Segment Information |
SandRidge has four business segments: Exploration and Production, Drilling and Oilfield Services, Midstream Gas 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 Oilfield 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
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Notes to Condensed Consolidated Financial Statements — (Continued)
natural gas. The Other segment transports CO2 to market for use by the Company and others in tertiary oil recovery operations and other miscellaneous operations.
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 our segments is shown in the following table (in thousands):
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2007 | 2006 | 2007 | 2006 | |||||||||||||
Revenues: | ||||||||||||||||
Exploration and production | $ | 113,105 | $ | 20,942 | $ | 320,984 | $ | 50,704 | ||||||||
Elimination of inter-segment revenue | — | (142 | ) | (574 | ) | (354 | ) | |||||||||
Exploration and production, net of inter-segment revenue | 113,105 | 20,800 | 320,410 | 50,350 | ||||||||||||
Drilling and oilfield services | 70,728 | 55,795 | 188,887 | 154,295 | ||||||||||||
Elimination of inter-segment revenue | (53,957 | ) | (19,864 | ) | (131,888 | ) | (48,040 | ) | ||||||||
Drilling and oilfield services, net of inter-segment revenue | 16,771 | 35,931 | 56,999 | 106,255 | ||||||||||||
Midstream gas services | 55,395 | 47,405 | 189,143 | 137,329 | ||||||||||||
Elimination of inter-segment revenue | (36,364 | ) | (18,081 | ) | (118,012 | ) | (46,115 | ) | ||||||||
Midstream gas services, net of inter-segment revenue | 19,031 | 29,324 | 71,131 | 91,214 | ||||||||||||
Other | 7,209 | 3,652 | 19,780 | 15,578 | ||||||||||||
Elimination of inter-segment revenue | (2,468 | ) | (57 | ) | (6,545 | ) | (220 | ) | ||||||||
Other, net of inter-segment revenue | 4,741 | 3,595 | 13,235 | 15,358 | ||||||||||||
Total revenues | $ | 153,648 | $ | 89,650 | $ | 461,775 | $ | 263,177 | ||||||||
Operating Income: | ||||||||||||||||
Exploration and production | $ | 61,843 | $ | 241 | $ | 138,306 | $ | 8,203 | ||||||||
Drilling and oilfield services | 5,376 | 10,153 | 14,252 | 27,178 | ||||||||||||
Midstream gas services | 3,657 | 1,361 | 5,958 | 3,138 | ||||||||||||
Other | (11,160 | ) | (3,179 | ) | (20,172 | ) | (8,778 | ) | ||||||||
Total operating income | 59,716 | 8,576 | 138,344 | 29,741 | ||||||||||||
Interest income | 575 | 51 | 4,201 | 448 | ||||||||||||
Interest expense | (28,522 | ) | (2,506 | ) | (88,630 | ) | (4,090 | ) | ||||||||
Other income (expense) | 1,071 | 555 | 3,078 | (241 | ) | |||||||||||
Income before income tax expense | $ | 32,840 | $ | 6,676 | $ | 56,993 | $ | 25,858 | ||||||||
Capital Expenditures: | ||||||||||||||||
Exploration and production | $ | 329,430 | $ | 37,127 | $ | 706,550 | $ | 88,861 | ||||||||
Drilling and oilfield services | 20,883 | 4,709 | 104,796 | 53,832 | ||||||||||||
Midstream gas services | 22,297 | 17,387 | 45,427 | 25,406 | ||||||||||||
Other | 30,406 | 7,508 | 38,387 | 13,132 | ||||||||||||
Total capital expenditures | $ | 403,016 | $ | 66,731 | $ | 895,160 | $ | 181,231 | ||||||||
Depreciation, Depletion and Amortization: | ||||||||||||||||
Exploration and production | $ | 45,643 | $ | 6,680 | $ | 117,329 | $ | 14,902 | ||||||||
Drilling and oilfield services | 10,092 | 5,206 | 25,962 | 14,070 | ||||||||||||
Midstream gas services | 1,688 | 845 | 4,182 | 2,238 | ||||||||||||
Other | 2,036 | 1,631 | 4,948 | 4,828 | ||||||||||||
Total depreciation, depletion and amortization | $ | 59,459 | $ | 14,362 | $ | 152,421 | $ | 36,038 | ||||||||
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SandRidge Energy, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial Statements — (Continued)
September 30, | December 31, | |||||||
2007 | 2006 | |||||||
Identifiable Asset(1): | ||||||||
Exploration and production | $ | 2,712,621 | $ | 2,091,459 | ||||
Drilling and oilfield services | 264,272 | 175,169 | ||||||
Midstream gas services | 108,031 | 75,606 | ||||||
Other | 85,532 | 46,150 | ||||||
Total | $ | 3,170,456 | $ | 2,388,384 | ||||
(1) | Identifiable assets are those used in SandRidge’s operations in each industry segment. |
17. | Subsequent Events |
Acquisitions. 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 $74 million, comprised of $25 million in cash and a $49 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.
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 predominately in the WTO from a group of entities. The purchase price of approximately $32.0 million was paid in cash.
Litigation Settlement. On October 29, 2007, the Company entered into an agreement whereby it settled outstanding litigation related to certain property purchased by the Company during July 2007. Under the terms of the agreement, the Company paid $4.5 million to the counterparties on November 15, 2007 and the litigation was dismissed. The amount paid has been included in accounts payable and accrued expenses in the accompanying condensed consolidated balance sheet as of September 30, 2007.
Note Payable. 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 during July 2007 (see additional discussion in Note 4). 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 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 the next twelve months, the Company expects to make payments of principal and interest on this note totaling $1.0 million and $1.1 million, respectively.
Initial Public Offering. 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 4,170,000 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 $2.5 million, the Company received net proceeds of approximately $705.4 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
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SandRidge Energy, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial Statements — (Continued)
these additional shares. This offering generated total gross proceeds to the Company of $841.8 million and total net proceeds of approximately $795.3 million to us after deducting total underwriting discounts of approximately $44.0 million and other offering expenses estimated to be approximately $2.5 million. The aggregate net proceeds of approximately $795.3 million received by the Company at closing on November 9, 2007 were utilized as follows (in millions):
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 | 230.3 | |||
Total | $ | 795.3 | ||
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ITEM 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
The following discussion and analysis is intended to assist you in understanding our business and the results of operations together with our present financial condition. This section should be read in conjunction with our condensed consolidated financial statements and the accompanying notes included in this Quarterly Report, as well as our historical consolidated financial statements, and the notes included in registration statement onForm S-1/A filed with the Securities and Exchange Commission on October 23, 2007. Our operating results for the periods discussed may not be indicative of future performance. Statements concerning future results are forward-looking statements. In the text below, financial statement numbers have been rounded; however, the percentage changes are based on amounts that have not been rounded.
The financial information with respect to the three and nine month periods ended September 30, 2007 and 2006 that is discussed below is unaudited. In the opinion of management, this information contains all adjustments, consisting only of normal recurring accruals, necessary for a fair presentation of the results for such periods. The results of operations for the interim periods are not necessarily indicative of the results of operations for the full fiscal year.
Overview of Our Company
We are a rapidly expanding independent natural gas and oil company concentrating on exploration, development and production activities. We are focused on continuing the exploration and exploitation of our significant holdings in the West Texas Overthrust, which we refer to as the WTO, a natural gas prone geological region where we have operated since 1986 that includes the Piñon Field and our South Sabino and Big Canyon Prospects. We also own and operate drilling rigs and conduct related oil field services, and we own and operate interests in gas gathering, marketing and processing facilities and CO2 gathering and transportation facilities.
On November 21, 2006, we acquired all of the outstanding membership interests in NEG Oil & Gas, or NEG, for total consideration of approximately $1.5 billion, excluding cash acquired. 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. The NEG acquisition, coupled with numerous acquisitions of additional working interests completed during 2007, 2006 and late 2005, have significantly increased our holdings in the WTO. We also operate significant interests in the Cotton Valley Trend in East Texas and the Gulf Coast region.
During November 2007, we completed an initial public offering of our common stock, a portion of the proceeds from which were used to repay indebtedness outstanding under our senior credit facility as well as a note payable outstanding related to a recent acquisition. See further discussion of these transactions in Note 17 to the condensed consolidated financial statements contained in Part I, Item I of this Quarterly Report.
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Segment Overview
Operating income is computed as segment operating revenue less direct operating costs. These measurements provide important information to us about the activity and profitability of our lines of business. Set forth in the table below is financial information regarding each of our current segments.
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2007 | 2006 | 2007 | 2006 | |||||||||||||
(In thousands) | ||||||||||||||||
Segment revenue: | ||||||||||||||||
Exploration and production | $ | 113,105 | $ | 20,800 | $ | 320,410 | $ | 50,350 | ||||||||
Drilling and oil field services | 16,771 | 35,931 | 56,999 | 106,255 | ||||||||||||
Midstream gas services | 19,031 | 29,324 | 71,131 | 91,214 | ||||||||||||
Other | 4,741 | 3,595 | 13,235 | 15,358 | ||||||||||||
Total revenues | 153,648 | 89,650 | 461,775 | 263,177 | ||||||||||||
Segment operating income: | ||||||||||||||||
Exploration and production | 61,843 | 241 | 138,306 | 8,203 | ||||||||||||
Drilling and oil field services | 5,376 | 10,153 | 14,252 | 27,178 | ||||||||||||
Midstream gas services | 3,657 | 1,361 | 5,958 | 3,138 | ||||||||||||
Other | (11,160 | ) | (3,179 | ) | (20,172 | ) | (8,778 | ) | ||||||||
Total operating income | 59,716 | 8,576 | 138,344 | 29,741 | ||||||||||||
Interest income | 575 | 51 | 4,201 | 448 | ||||||||||||
Interest expense | (28,522 | ) | (2,506 | ) | (88,630 | ) | (4,090 | ) | ||||||||
Other income (expense) | 1,071 | 555 | 3,078 | (241 | ) | |||||||||||
Income before income taxes | $ | 32,840 | $ | 6,676 | $ | 56,993 | $ | 25,858 | ||||||||
Production data: | ||||||||||||||||
Gas (Mmcf) | 12,856 | 2,637 | 35,148 | 6,856 | ||||||||||||
Oil (MBbls) | 535 | 24 | 1,441 | 70 | ||||||||||||
Combined equivalent volumes (Mmcfe) | 16,067 | 2,780 | 43,793 | 7,275 | ||||||||||||
Daily combined equivalent volumes (Mmcfe/d) | 174.6 | 30.2 | 160.4 | 26.6 | ||||||||||||
Average prices — as reported(1): | ||||||||||||||||
Natural gas (per Mcf) | $ | 5.99 | $ | 6.23 | $ | 6.56 | $ | 6.14 | ||||||||
Oil (per Bbl) | $ | 67.57 | $ | 59.76 | $ | 61.67 | $ | 61.89 | ||||||||
Combined equivalent (per Mcfe) | $ | 7.04 | $ | 6.42 | $ | 7.30 | $ | 6.38 | ||||||||
Average prices — including impact of derivatives: | ||||||||||||||||
Natural gas (per Mcf) | $ | 7.54 | $ | 11.61 | $ | 7.11 | $ | 8.21 | ||||||||
Oil (per Bbl) | $ | 67.57 | $ | 59.76 | $ | 61.67 | $ | 61.89 | ||||||||
Combined equivalent (per Mcfe) | $ | 8.28 | $ | 11.52 | $ | 7.73 | $ | 8.33 | ||||||||
Drilling and oil field services: | ||||||||||||||||
Number of operational drilling rigs owned at end of period | 27.0 | (3) | 23.0 | 27.0 | (3) | 23.0 | ||||||||||
Average number of operational drilling rigs owned during the period | 27.0 | (3) | 22.3 | 26.0 | (3) | 21.0 | ||||||||||
Average total revenue per rig per day(2) | $ | 17,771 | $ | 17,121 | $ | 17,302 | $ | 17,089 |
(1) | Reported prices represent actual average prices for the periods presented and do not give effect to hedging transactions. |
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(2) | Does not include revenues for related rental equipment. | |
(3) | Does not include five rigs being retrofitted as of September 30, 2007. |
We report the results of our operations in the following segments:
Exploration and Production Segment
We explore for, develop and produce natural gas and oil reserves, with a focus on our proved reserves and extensive undeveloped acreage positions in the WTO. We operate substantially all of our wells in our core areas and employ our drilling rigs and other drilling services in the exploration and development of our operated wells and, to a lesser extent, on our non-operated wells.
The primary factors affecting the financial results of our exploration and production segment are the prices we receive for our natural gas and oil production, the quantity of our natural gas and oil production and changes in the fair value of derivative instruments we use to reduce the volatility of the prices we receive for our natural gas and oil production. Because we are vertically integrated, our exploration and production activities affect the results of our oil field service and midstream segments. The NEG acquisition substantially increased our revenues and operating income in our exploration and production segment. However, because our working interest in the Piñon Field increased to approximately 85%, there are greater intercompany eliminations that affect the consolidated financial results of our drilling and oil field service and midstream gas services segments.
Exploration and Production Segment — Three months ended September 30, 2007 compared to the three months ended September 30, 2006
Exploration and production segment revenues increased to $113.1 million in the three months ended September 30, 2007 from $20.8 million in the three months ended September 30, 2006, an increase of 443.8%, as a result of a 477.9% increase in combined production volumes and a 9.7% increase in the combined average price we received for the natural gas and oil we produced. In the three month period ended September 30, 2007 we increased natural gas production by 10.2 Bcf, to 12.9 Bcf and increased crude oil production by 511 MBbls to 535 MBbls from the comparable period in 2006. The total combined 13.3 Bcfe increase in production was due primarily to acquisitions and successful drilling in the WTO.
The average price we received for our natural gas production for the three month period ended September 30, 2007 decreased 3.9%, or $0.24 per Mcf, to $5.99 per Mcf from $6.23 per Mcf in the comparable period in 2006. The average price received for our crude oil production, however, increased 13.1%, or $7.81 per barrel, to $67.57 per barrel during the three months ended September 30, 2007 from $59.76 per barrel during the same period in 2006. Including the impact of derivative contract settlements, the effective price received for natural gas for the three month period ended September 30, 2007 was $7.54 per Mcf as compared to $11.61 per Mcf during the same period in 2006. Our derivatives contracts had no impact on effective oil prices during the three months ended September 30, 2007 or the comparable period in 2006. During late 2006 and continuing into 2007 we entered into derivatives contracts to mitigate the impact of commodity price fluctuations on our 2007 and 2008 production. Our derivatives contracts are not designated as accounting hedges and, as a result, gains or losses on derivatives contracts are recorded as an operating expense. Internally, management views the settlement of such derivatives contracts as adjustments to the price received for natural gas and oil production to determine “effective prices.”
For the three months ended September 30, 2007, we had $61.8 million in operating income in our exploration and production segment, compared to $0.2 million operating income for the same period in 2006. Our $92.3 million increase in exploration and production revenues was offset by a $20.7 million increase in production expenses, and a $39.1 million increase in depreciation, depletion and amortization, or DD&A, due to the step up in basis on the NEG properties. The increase in production expenses was attributable to the additional properties acquired in the NEG acquisition and operating expenses on our new wells. During the three month period ended September 30, 2007, the exploration and production segment reported a $39.2 million net gain on our derivatives positions ($19.9 million realized gains and $19.3 million unrealized gains) compared to a $5.3 million gain ($13.9 million realized gains and $8.6 million unrealized losses) in the comparable period in 2006. During 2007, we selectively entered into natural gas swaps and basis swaps by capitalizing on what we perceived as spikes in the price of natural gas or favorable basis differences between the NYMEX price and natural gas prices at our principal West Texas
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pricing point of Waha Hub. Unrealized gains or losses on derivative contracts represent the change in fair value of open derivative positions during the period. The change in fair value is principally measured based on period end prices as compared to the contract price. The unrealized gain recorded in the three month period ended September 30, 2007 was attributable to a decrease in average natural gas prices at September 30, 2007 as compared to the average natural gas prices at the various contract dates. Future volatility in natural gas and oil prices could have an adverse effect on the operating results of our exploration and production segment.
Exploration and Production Segment — Nine months ended September 30, 2007 compared to the nine months ended September 30, 2006
Exploration and production segment revenues increased to $320.4 million in the nine months ended September 30, 2007 from $50.4 million in the nine months ended September 30, 2006, an increase of 536.4%, as a result of a 502.0% increase in volumes and a 14.4% increase in the average price we received for the natural gas and oil we produced. In the nine month period ended September 30, 2007 we increased natural gas production by 28.3 Bcf, to 35.2 Bcf and increased crude oil production by 1,371 MBbls to 1,441 MBbls. The total combined 36.5 Bcfe increase in production was due primarily to acquisitions and successful drilling in the WTO.
The average price we received for our natural gas production for the nine month period ended September 30, 2007 increased 6.8%, or $0.42 per Mcf, to $6.56 per Mcf from $6.14 per Mcf in the comparable period in 2006. The average price received for our crude oil production decreased slightly, however, to $61.67 from $61.89 for the comparable period in 2006. Including the impact of derivative contract settlements, the effective price received for natural gas for the nine month period ended September 30, 2007 was $7.11 per Mcf as compared to $8.21 per Mcf during the comparable period in 2006. Our derivatives contracts had no impact on effective oil prices during the nine months ended September 30, 2007 or the comparable period in 2006.
For the nine months ended September 30, 2007, we had $138.3 million in operating income in our exploration and production segment, compared to $8.2 million operating income for the same period in 2006. Our $270.1 million increase in exploration and production revenues was offset by a $56.1 million increase in production expenses, and a $101.9 million increase in depreciation, depletion and amortization, or DD&A, due to the step up in basis on the NEG properties. The increase in production expenses was attributable to the additional properties acquired in the NEG acquisition and operating expenses on our new wells. During the nine month period ended September 30, 2007, the exploration and production segment reported a $55.2 million net gain on our derivatives positions ($19.2 million realized gains and $36.0 million in unrealized gains) compared to a $16.2 million gain ($14.2 realized gains and $2.0 unrealized gains) in the comparable period in 2006. During 2007, we selectively entered into natural gas swaps and basis swaps by capitalizing on what we perceived as spikes in the price of natural gas or favorable basis differences between the NYMEX price and natural gas prices at our principal West Texas pricing point of Waha Hub. Unrealized gains or losses on derivative contracts represent the change in fair value of open derivative positions during the period. The change in fair value is principally measured based on period end prices as compared to the contract price. The unrealized gain recorded in the nine month period ended September 30, 2007 was attributable to a decrease in average natural gas prices at September 30, 2007 as compared to the average natural gas prices at the various contract dates.
Drilling and Oil Field Services Segment
We drill for our own account primarily in the WTO through our drilling and oil field services subsidiary, Lariat Services. We also drill wells for other natural gas and oil companies, primarily located in the West Texas region. Our oil field services business conducts operations that complement our exploration and production operations. These services include providing pulling units, trucking, rental tools, location and road construction and roustabout services to ourselves and to third-parties. Additionally, we provide under-balanced drilling systems only for our own account.
In October 2005, we entered into a joint venture, Larclay, with CWEI, pursuant to which Larclay acquired twelve sets of rig components and other related equipment to assemble into completed land drilling rigs. The drilling rigs were to be used for drilling on CWEI’s prospects, our prospects, or for contracting to third-parties on daywork drilling contracts. All of these rigs have been delivered, although one rig has not been assembled. CWEI
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was responsible for financing the purchase of the rigs by the terms of the joint venture and has financed 100% of the acquisition cost of the rigs. We operate the rigs owned by the joint venture. The joint venture and CWEI are responsible for all costs related to the initial construction and equipping of the drilling rigs. In the event of an operating shortfall within the joint venture, we along with CWEI are proportionately responsible to fund the shortfall through loans made to the joint venture. We have a 50% interest in Larclay, and we account for this joint venture as an equity investment.
The financial results of our drilling and oil field services segment depend on many factors, particularly the demand for and the price we can charge for our services. We provide drilling services for our own account and for others, generally on a daywork, footage or turnkey contract basis, although we record revenues and operating income only on wells drilled for or on behalf of third parties. The majority of our drilling contract revenues are derived from daywork drilling contracts. However, we generally assess the complexity and risk of operations, theon-site drilling conditions, the type of equipment to be used, the anticipated duration of the work to be performed and the prevailing market rates in determining the type of drilling contract into which we enter.
Daywork Contracts. Under a daywork drilling contract, we provide a drilling rig with required personnel to our customer who supervises the drilling of the well. We are paid based on a negotiated fixed rate per day while the rig is used. Daywork drilling contracts specify the equipment to be used, the size of the hole and the depth of the well. Under a daywork drilling contract, the customer bears a large portion of the out-of-pocket drilling costs, and we generally bear no part of the usual risks associated with drilling, such as time delays and unanticipated costs. As of September 30, 2007, 26 of our rigs were operating under daywork contracts and 20 of these were working for our account. Also as of September 30, 2007, the 11 operational rigs owned by Larclay were operating under daywork contracts and seven of these were working for our account. The remaining four operational Larclay rigs were working for CWEI as of September 30, 2007.
Footage Contracts. Under a footage contract, we are paid a fixed amount for each foot drilled, regardless of the time required or the problems encountered in drilling the well. As of September 30, 2007, none of our rigs were operating under footage contracts.
Turnkey Contracts. Under a typical turnkey contract, a customer will pay us to drill a well to a specified depth and under specified conditions for a fixed price, regardless of the time required or the problems encountered in drilling the well. We provide most of the equipment and drilling supplies required to drill the well. We subcontract for related services such as the provision of casing crews, cementing and well logging. Generally we do not receive progress payments and are paid only after the well is drilled. We routinely enter into turnkey contracts in areas where our experience and expertise permit us to drill wells more profitably than under a daywork contract. As of September 30, 2007, one of our rigs was operating under turnkey contracts.
Drilling and Oil Field Services Segment — Three months ended September 30, 2007 compared to the three months ended September 30, 2006
Drilling and oil field services segment revenue decreased to $16.8 million in the three month period ended September 30, 2007 from $35.9 million in the three month period ended September 30, 2006. Operating income decreased to $5.4 million in the three month period ended September 30, 2007 from $10.2 million in the same period in 2006. The decline in revenues and operating income is primarily attributable to an increase in the number of rigs operating on our properties and an increase in our ownership interest in our natural gas and oil properties. Our drilling and oil field services segment records revenues and operating income only on wells drilled for or on behalf of third parties. The portion of drilling costs incurred by our drilling and oil field services segment relating to our ownership interest are capitalized as part of our full-cost pool. With the NEG acquisition and other WTO property acquisitions, our average working interest has increased to approximately 85% in the wells we operate in the WTO, and the third party interest has declined to less than 20%. During the three month period ended September 30, 2007, approximately 76% ($54.0 million) of the drilling and oil field service revenues were generated by work performed on our own account and eliminated in consolidation as compared to approximately 36% ($19.9 million) for the comparable period in 2006. The number of drilling rigs we owned increased 21.1% to an average of 27.0 rigs during the three month period ended September 30, 2007 from an average of 22.3 rigs in the comparable period in 2006. The average daily rate we received per rig of approximately $17,000, excluding revenues for related rental
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equipment and before intercompany eliminations was essentially unchanged from the comparable period in 2006. Our rig utilization rate was 92.6%, representing 314 stacked rig days in 2007. The decline in operating income was principally attributable to the increase in the number and working interest ownership in wells drilled for our own account.
Drilling and Oil Field Services Segment — Nine months ended September 30, 2007 compared to the nine months ended September 30, 2006
Drilling and oil field services segment revenue decreased to $57.0 million in the nine month period ended September 30, 2007 from $106.3 million in the nine month period ended September 30, 2006. Operating income decreased to $14.3 million in the nine month period ended September 30, 2007 from $27.2 million in the same period in 2006. The decline in revenues and operating income is primarily attributable to an increase in the number of rigs operating on our properties and an increase in our ownership interest in our natural gas and oil properties. Our drilling and oil field services segment records revenues and operating income only on wells drilled for or on behalf of third parties. The portion of drilling costs incurred by our drilling and oil field services segment relating to our ownership interest are capitalized as part of our full-cost pool. With the NEG acquisition and other WTO property acquisitions, our average working interest has increased to approximately 85% in the wells we operate in the WTO, and the third party interest has declined to less than 20%. During the nine month period ended September 30, 2007, approximately 70% ($131.9 million) of the drilling and oil field service revenues were generated by work performed on our own account and eliminated in consolidation as compared to approximately 31% ($48.0 million) for the comparable period in 2006. The number of drilling rigs we owned increased 23.8% to an average of 26.0 rigs during the nine month period ended September 30, 2007 from an average of 21.0 rigs in the comparable period in 2006. The average daily rate we received per rig of approximately $17,000, excluding revenues for related rental equipment and before intercompany eliminations was essentially unchanged from the comparable period in 2006. Our rig utilization rate was 91.0%, representing 826 stacked rig days in 2007. The decline in operating income was principally attributable to the increase in the number and working interest ownership in wells drilled for our own account.
Midstream Gas Services Segment
We provide gathering, compression, processing and treating services of natural gas in West Texas and the Piceance Basin in northwestern Colorado, primarily through our wholly-owned subsidiary, ROC Gas. Through our gas marketing subsidiary, Integra Energy LLC (“Integra Energy”), we buy and sell natural gas produced from our operated wells as well as third-party operated wells located on or near our gathering systems. Gas marketing revenue is one of our largest revenue components; however, it is a very low margin business. Substantially all of our marketing fees are billed on a per unit basis. On a consolidated basis, gas purchases and other costs of sales includes the total value we receive from third-parties for the gas we sell and the amount we pay for gas, which are reported as midstream and marketing expense. The primary factors affecting our midstream gas services are the quantity of gas we gather, treat and market and the prices we pay and receive for natural gas.
Midstream gas services revenue for the three months ended September 30, 2007 was $19.0 million compared to $29.3 million in the comparable period of 2006. Midstream gas services revenue for the nine months ended September 30, 2007 was $71.1 million compared to $91.2 million in the comparable period in 2006. The quarterly and nine month decrease in midstream gas services revenues is attributable to the increase in our working interest in the WTO as a result of the NEG and other acquisitions.
Other Segment
Our other segment consists primarily of our CO2 gathering and sales operations and other investments. We conduct our CO2 gathering and sales operations through our wholly owned subsidiary, PetroSource. PetroSource gathers CO2 from natural gas treatment plants located in West Texas and transports and sells this CO2 for use in our and third-parties’ tertiary oil recovery operations.
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Results of Operations
Three months ended September 30, 2007 compared to the three months ended September 30, 2006
Revenue. Total revenue increased 71.4% to $153.6 million for the three months ended September 30, 2007 from $89.7 million in the same period in 2006. This increase was due to a $95.0 million increase in natural gas and oil sales and was partially offset by lower revenues in our drilling and oil field services, midstream gas services and other segments.
Three Months Ended | ||||||||||||||||
September 30, | ||||||||||||||||
2007 | 2006 | $ Change | % Change | |||||||||||||
(In thousands) | ||||||||||||||||
Revenue: | ||||||||||||||||
Natural gas and crude oil | $ | 113,106 | $ | 18,150 | $ | 94,956 | 523.2 | % | ||||||||
Drilling and services | 16,684 | 35,742 | (19,058 | ) | (53.3 | )% | ||||||||||
Midstream and marketing | 19,030 | 29,326 | (10,296 | ) | (35.1 | )% | ||||||||||
Other | 4,828 | 6,432 | (1,604 | ) | (24.9 | )% | ||||||||||
Total revenues | $ | 153,648 | $ | 89,650 | $ | 63,998 | 71.4 | % | ||||||||
Total natural gas and crude oil revenues increased $95.0 million to $113.1 million for the three months ended September 30, 2007 compared to $18.2 million for the same period in 2006, primarily as a result of an increase in natural gas and crude oil production volumes. Total natural gas production increased 387.5% to 12,856 Mmcf in 2007 compared to 2,637 Mmcf in 2006 while crude oil production increased 2,129.2% to 535 MBbls in 2007 from 24 MBbls in 2006. Of the 13,287 Mmcfe increase in total production, approximately 11,741 Mmcfe of the increase was attributable to the NEG acquisition. The remainder of the increase was due to our successful drilling in the WTO. The average price received for our natural gas and crude oil production increased 9.7% in the 2007 period to $7.04 per Mcfe compared to $6.42 per Mcfe in 2006, excluding the impact of derivative contracts.
Drilling and services revenue decreased 53.3% to $16.7 million for the three months ended September 30, 2007 compared to $35.7 million in the same period in 2006. The decline in revenues is primarily attributable to an increase in the number of rigs operating on our properties and an increase in our ownership interest in our natural gas and oil properties. The number of rigs we owned increased to 27.0 (average for the three months ended September 30, 2007) in 2007 compared to 22.3 (average for the three months ended September 30, 2006) in 2006, an increase of 21.1%, and the average daily revenue per rig, after considering the effect of the elimination of intercompany usage, was essentially unchanged at $17,771 per day.
Midstream and marketing revenue decreased $10.3 million, or 35.1%, with revenues of $19.0 million in the three month period ended September 30, 2007 as compared to $29.3 million in the three month period ended September 30, 2006. The NEG acquisition significantly decreased our midstream gas services revenues as more gas was transported for our own account. Prior to the acquisition, transportation, treating and processing of gas for NEG was recorded as midstream gas services revenue. We have the contractual right to periodically increase fees we receive for transportation and processing based on certain indexes.
Other revenue decreased to $4.8 million for the three months ended September 30, 2007 from $6.4 million for the same period in 2006. The decrease was primarily due to the effects of the sale of various non-energy related assets to our former President and Chief Operating Officer as described further in Note 15 to the condensed consolidated financial statements.. Revenues related to these assets are included in the 2006 period prior to their sale in August 2006. Other revenue is generated primarily by our CO2 gathering and sales operations.
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Operating Costs and Expenses. Total operating costs and expenses increased to $93.9 million for the three months ended September 30, 2007 compared to $81.1 million for the same period in 2006 due to increases in our production-related costs as well as an increase in corporate staff. These increases were partially offset by a decrease in costs attributable to our drilling and services and midstream and marketing operations as well as increased gains on derivative instruments.
Three Months Ended | ||||||||||||||||
September 30, | ||||||||||||||||
2007 | 2006 | $ Change | % Change | |||||||||||||
(In thousands) | ||||||||||||||||
Operating costs and expenses: | ||||||||||||||||
Production | $ | 28,689 | $ | 7,960 | $ | 20,729 | 260.4 | % | ||||||||
Production taxes | 4,402 | 1,050 | 3,352 | 319.2 | % | |||||||||||
Drilling and services | 6,809 | 24,985 | (18,176 | ) | (72.7 | )% | ||||||||||
Midstream and marketing | 14,444 | 27,139 | (12,695 | ) | (46.8 | )% | ||||||||||
Depreciation, depletion, and amortization — natural gas and crude oil | 45,177 | 6,064 | 39,113 | 645.0 | % | |||||||||||
Depreciation, depletion and amortization — other | 14,282 | 8,298 | 5,984 | 72.1 | % | |||||||||||
General and administrative | 20,421 | 11,721 | 8,700 | 74.2 | % | |||||||||||
Gain on derivative instruments | (39,247 | ) | (5,304 | ) | (33,943 | ) | (640.0 | )% | ||||||||
Gain on sale of assets | (1,045 | ) | (839 | ) | (206 | ) | (24.6 | )% | ||||||||
Total operating costs and expenses | $ | 93,932 | $ | 81,074 | $ | 12,858 | 15.9 | % | ||||||||
Production expense includes the costs associated with our exploration and production activities, including lease operating expense and processing costs. Production expenses increased $20.7 million primarily due to a $20.0 million increase related to the addition of the NEG properties in 2007. The remainder of the increase was due to an increase in lease operating expenses due to an increase in the number of wells we operate. Production taxes increased $3.4 million, or 319.2%, to $4.4 million primarily due to the addition of the NEG properties in 2007.
Drilling and services and midstream and marketing expenses decreased 72.7% and 46.8% respectively, for the three months ended September 30, 2007 as compared to the same period in 2006 primarily because of the increase in the number and working interest ownership of the wells we drilled for our own account.
Depreciation, depletion and amortization (“DD&A”) for our natural gas and crude oil properties increased to $45.2 million for the three months ended September 30, 2007 from $6.1 million in the same period in 2006. Our DD&A per Mcfe increased $0.63 to $2.81 from $2.18 in the comparable period in 2006. The increase is primarily attributable to the NEG acquisition, which increased our depreciable properties by the purchase price plus future development costs and increased production. Our production increased 477.9% to 16.1 Bcfe from 2.8 Bcfe in 2006.
DD&A for our other assets consists primarily of depreciation of our drilling rigs and other equipment. The increase in DD&A for our drilling and oil field services equipment was due primarily to the increase in the number of rigs we own. We calculate depreciation of property and equipment using the straight-line method over the estimated useful lives of the assets, which range from three to 25 years. Our drilling rigs and related oil field services equipment are depreciated over an average seven-year useful life
General and administrative expenses increased $8.7 million to $20.4 million for the three months ended September 30, 2007 from $11.7 million for the comparable period in 2006. The increase was principally attributable to a $10.2 million increase in corporate salaries and wages due to a significant increase in corporate and support staff. As of September 30, 2007, we had 2,205 employees as compared to 1,319 at September 30, 2006. The increase in salaries and wages was partially offset by a $1.0 million decrease in stock compensation expense. As part of a severance package for certain executive officers, the Board of Directors approved the acceleration of vesting of certain stock awards resulting in increased compensation expense recognized during the three month period ended September 30, 2006.
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For the three month period ended September 30, 2007, we recorded a gain of $39.2 million ($19.3 million unrealized gain and $19.9 million realized gain) on our derivatives instruments compared to a $5.3 million gain ($8.6 million unrealized loss and $13.9 realized gain) for the comparable period in 2006. During 2007, we selectively entered into natural gas swaps and basis swaps by capitalizing on what we perceived as spikes in the price of natural gas or favorable basis differences between the NYMEX price and natural gas prices at our principal West Texas pricing point of Waha Hub. Unrealized gains or losses on derivatives contracts represent the change in fair value of open derivatives positions during the period. The change in fair value is principally measured based on period end prices as compared to the contract price. The unrealized gain recorded in the three month period ended September 30, 2007 was attributable to a decrease in average natural gas prices at September 30, 2007 as compared to the average natural gas prices at the various contract dates.
Other Income (Expense). Total other expense increased to $26.9 million in the three month period ended September 30, 2007 from $1.9 million in the three month period ended September 30, 2006. The increase is reflected in the table below.
Three Months Ended | ||||||||||||||||
September 30, | ||||||||||||||||
2007 | 2006 | $ Change | % Change | |||||||||||||
(In thousands) | ||||||||||||||||
Other income (expenses): | ||||||||||||||||
Interest income | $ | 575 | $ | 51 | $ | 524 | 1027.5 | % | ||||||||
Interest expense | (28,522 | ) | (2,506 | ) | (26,016 | ) | (1038.1 | )% | ||||||||
Minority interest | (164 | ) | (182 | ) | 18 | 9.9 | % | |||||||||
Income (loss) from equity investments | 1,235 | 737 | 498 | 67.6 | % | |||||||||||
Total other expense | (26,876 | ) | (1,900 | ) | (24,976 | ) | (1314.5 | )% | ||||||||
Income before income taxes | 32,840 | 6,676 | 26,164 | 391.9 | % | |||||||||||
Income tax expense | 11,920 | 1,781 | 10,139 | 569.3 | % | |||||||||||
Net income | $ | 20,920 | $ | 4,895 | $ | 16,025 | 327.4 | % | ||||||||
Interest income increased to $0.6 million for the three months ended September 30, 2007 from $0.1 million for the same period in 2006. This increase was due to interest income from the investment of excess cash after the repayment of debt.
Interest expense increased to $28.5 million for the three months ended September 30, 2007 from $2.5 million for the same period in 2006. This increase was attributable to increased average debt balances. To finance the NEG acquisition, we entered into a $750 million senior credit facility, which has an initial borrowing base of $300 million, and an $850 million senior bridge facility. In March 2007, we entered into a $1.0 billion term loan and sold 17.8 million shares of common stock in a private placement. A portion of the proceeds from the senior unsecured term loan were used to repay the bridge loan. The balance of proceeds were used to fund current year capital expenditures. Please read “— Liquidity and Capital Resources.”
During the three months ended September 30, 2007, we reported income from equity investments of $1.2 million as compared to $0.7 million in the comparable period in 2006. This increase was attributable to income from Larclay as all of Larclay’s rigs have now been delivered and all but one is operational.
We reported an income tax expense of $11.9 million for the three months ended September 30, 2007, as compared to an expense of $1.8 million for the same period in 2006. The current period income tax expense represents an effective income tax rate of 36.3% as compared to 26.7% in the comparable period in 2006. The lower effective income tax rate in 2006 was attributable to favorable percentage depletion deductions during that period.
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Nine months ended September 30, 2007 compared to the nine months ended September 30, 2006
Revenue. Total revenue increased 75.5% to $461.8 million for the nine months ended September 30, 2007 from $263.2 million in the same period in 2006. This increase was due to a $273.1 million increase in natural gas and oil sales and was partially offset by lower revenues in our other segments.
Nine Months Ended | ||||||||||||||||
September 30, | ||||||||||||||||
2007 | 2006 | $ Change | % Change | |||||||||||||
(In thousands) | ||||||||||||||||
Revenue: | ||||||||||||||||
Natural gas and crude oil | $ | 319,556 | $ | 46,419 | $ | 273,137 | 588.4 | % | ||||||||
Drilling and services | 56,928 | 105,713 | (48,785 | ) | (46.1 | )% | ||||||||||
Midstream and marketing | 71,131 | 91,218 | (20,087 | ) | (22.0 | )% | ||||||||||
Other | 14,160 | 19,827 | (5,667 | ) | (28.6 | )% | ||||||||||
Total revenues | $ | 461,775 | $ | 263,177 | $ | 198,598 | 75.5 | % | ||||||||
Total natural gas and crude oil revenues increased $273.1 million to $319.5 million for the nine months ended September 30, 2007, compared to $46.4 million for the same period in 2006, primarily as a result of an increase in natural gas and crude oil production volumes. Total natural gas production increased 412.7% to 35,148 Mmcf in 2007 compared to 6,856 Mmcf in 2006, while crude oil production increased 1,958.6% to 1,441 MBbls in 2007 from 70 MBbls in 2006. Approximately 32,964 Mmcfe of the 36,518 Mmcfe increase in production was attributable to the NEG acquisition. Average price received for our natural gas and crude oil production increased 14.4% in the 2007 period to $7.30 per Mcfe compared to $6.38 per Mcfe in 2006, excluding the impact of derivative contracts.
Drilling and services revenue decreased 46.1% to $56.9 million for the nine months ended September 30, 2007, compared to $105.7 million in the same period in 2006. The decline in revenues is primarily attributable to an increase in the number of rigs operating on our properties and an increase in our ownership interest in our natural gas and oil properties as a result of the NEG acquisition. The number of rigs we owned increased to 26.0 (average for the nine months ended September 30, 2007) in 2007 compared to 21.0 (average for the nine months ended September 30, 2006) in 2006, an increase of 23.8%, and the average daily revenue per rig, after considering the effect of the elimination of intercompany usage, was essentially unchanged at $17,302 per day.
Midstream and marketing revenue decreased $20.1 million, or 22.0%, with revenues of $71.1 million in the nine month period ended September 30, 2007, as compared to $91.2 million in the nine month period ended September 30, 2006. The NEG acquisition significantly decreased our midstream gas services revenues as more gas was transported for our own account. Prior to the acquisition, transportation, treating and processing of gas for NEG was recorded as midstream gas services revenue. We have the contractual right to periodically increase fees we receive for transportation and processing based on certain indexes.
Other revenue decreased to $14.2 million for the nine months ended September 30, 2007 from $19.8 million for the same period in 2006. The decrease was primarily due to the sale of various non-energy related assets to our former President and Chief Operating Officer. Revenues related to these assets are included in the 2006 period prior to their sale in August 2006. This decrease was slightly offset by an increase in revenues generated by the sale of CO2. Other revenue is generated primarily by our CO2 gathering and sales operations.
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Operating Costs and Expenses. Total operating costs and expenses increased to $323.4 million for the nine months ended September 30, 2007, compared to $233.4 million for the same period in 2006, primarily due to increases in our production-related costs as well as an increase in corporate staff. These increases were partially offset by decreases in costs attributable to our drilling and services and midstream and marketing operations as well as increased gains on derivative instruments.
Nine Months Ended | ||||||||||||||||
September 30, | ||||||||||||||||
2007 | 2006 | $ Change | % Change | |||||||||||||
(In thousands) | ||||||||||||||||
Operating costs and expenses: | ||||||||||||||||
Production | $ | 77,707 | $ | 21,625 | $ | 56,082 | 259.3 | % | ||||||||
Production taxes | 12,328 | 2,579 | 9,749 | 378.0 | % | |||||||||||
Drilling and services | 30,935 | 72,670 | (41,735 | ) | (57.4 | )% | ||||||||||
Midstream and marketing | 61,191 | 85,525 | (24,334 | ) | (28.5 | )% | ||||||||||
Depreciation, depletion, and amortization — natural gas and crude oil | 115,876 | 13,932 | 101,944 | 731.7 | % | |||||||||||
Depreciation, depletion and amortization — other | 36,545 | 22,106 | 14,439 | 65.3 | % | |||||||||||
General and administrative | 45,781 | 32,024 | 13,757 | 43.0 | % | |||||||||||
Gain on derivative instruments | (55,228 | ) | (16,176 | ) | (39,052 | ) | (241.4 | )% | ||||||||
Gain on sale of assets | (1,704 | ) | (849 | ) | (855 | ) | (100.7 | )% | ||||||||
Total operating costs and expenses | $ | 323,431 | $ | 233,436 | $ | 89,995 | 38.6 | % | ||||||||
Production expense includes the costs associated with our exploration and production activities, including, but not limited to, lease operating expense and processing costs. Production expenses increased $56.1 million primarily due to a $53.6 million increase because of the addition of the NEG properties in 2007. The remainder of the increase was due to an increase in lease operating expenses due to an increase in the number of wells we operate. Production taxes increased $9.7 million, or 378.0%, to $12.3 million primarily due to the addition of the NEG properties in 2007.
Drilling and services and midstream and marketing expenses decreased 57.4% and 28.5% respectively, for the nine months ended September 30, 2007, as compared to the same period in 2006 primarily because of the increase in the number and working interest ownership of the wells we drilled for our own account.
DD&A for our natural gas and crude oil properties increased to $115.9 million for the nine months ended September 30, 2007, from $13.9 million in the same period in 2006. Our DD&A per Mcfe increased $0.73 to $2.65 from $1.92 in the comparable period in 2006. The increase is primarily attributable to the NEG acquisition, which increased our depreciable properties by the purchase price plus future development costs and increased production. Our production increased 502.0% to 43.8 Bcfe from 7.3 Bcfe in 2006.
DD&A for our other assets consists primarily of depreciation of our drilling rigs and other equipment. The increase in DD&A for our drilling and oil field services equipment was due primarily to the increase in the number of rigs we own. We calculate depreciation of property and equipment using the straight-line method over the estimated useful lives of the assets, which range from three to 25 years. Our drilling rigs and related oil field services equipment are depreciated over an average seven-year useful life
General and administrative expenses increased $13.8 million to $45.8 million for the nine months ended September 30, 2007, from $32.0 million for the comparable period in 2006. The increase was principally attributable to a $21.7 million increase in corporate salaries and wages which was due to a significant increase in corporate and support staff. As of September 30, 2007, we had 2,205 employees as compared to 1,319 at September 30, 2006. The increase in salaries and wages was partially offset by a $3.2 million decrease in stock compensation expense. As part of a severance package for certain executive officers, the Board of Directors
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approved the acceleration of vesting of certain stock awards resulting in increased compensation expense recognized during the nine months ended September 30, 2006.
For the nine month period ended September 30, 2007, we recorded a gain of $55.2 million ($36.1 million unrealized gain and $19.1 million realized gain) on our derivatives instruments compared to a $16.2 million gain ($2.0 million unrealized gain and $14.2 million realized gain) for the comparable period in 2006. During 2007, we selectively entered into natural gas swaps and basis swaps by capitalizing on what we perceived as spikes in the price of natural gas or favorable basis differences between the NYMEX price and natural gas prices at our principal West Texas pricing point of Waha Hub. Unrealized gains or losses on derivatives contracts represent the change in fair value of open derivatives positions during the period. The change in fair value is principally measured based on period end prices as compared to the contract price. The unrealized gain recorded in the nine month period ended September 30, 2007 was attributable to a decrease in average natural gas prices at September 30, 2007 as compared to the average natural gas prices at the various contract dates.
Other Income (Expense). Total other expense increased to $81.4 million in the nine month period ended September 30, 2007, from $3.9 million in the nine month period ended September 30, 2006. The increase is reflected in the table below.
Nine Months Ended | ||||||||||||||||
September 30, | ||||||||||||||||
2007 | 2006 | $ Change | % Change | |||||||||||||
(In thousands) | ||||||||||||||||
Other income (expense): | ||||||||||||||||
Interest income | $ | 4,201 | $ | 448 | $ | 3,753 | 837.7 | % | ||||||||
Interest expense | (88,630 | ) | (4,090 | ) | (84,540 | ) | (2067.0 | )% | ||||||||
Minority interest | (321 | ) | (281 | ) | (40 | ) | (14.2 | )% | ||||||||
Income (loss) from equity investments | 3,399 | 40 | 3,359 | 8397.5 | % | |||||||||||
Total other expense | (81,351 | ) | (3,883 | ) | (77,468 | ) | (1995.1 | )% | ||||||||
Income before income taxes | 56,993 | 25,858 | 31,135 | 120.4 | % | |||||||||||
Income tax expense | 21,002 | 6,931 | 14,071 | 203.0 | % | |||||||||||
Net income | $ | 35,991 | $ | 18,927 | $ | 17,064 | 90.2 | % | ||||||||
Interest income increased to $4.2 million for the nine months ended September 30, 2007, from $0.4 million for the same period in 2006. This increase was due to interest income from investment of excess cash after the repayment of debt.
Interest expense increased to $88.6 million for the nine months ended September 30, 2007, from $4.1 million for the same period in 2006. This increase was attributable to increased average debt balances. To finance the NEG acquisition, we entered into a $750 million senior credit facility, which has an initial borrowing base of $300 million, and an $850 million senior bridge facility. In March 2007, we entered into a $1.0 billion term loan and sold 17.8 million shares of common stock in a private placement. A portion of the proceeds from the senior unsecured term loan was used to repay the bridge loan. Please read “— Liquidity and Capital Resources.”
During the nine months ended September 30, 2007, we reported income from equity investments of $3.4 million as compared to $40,000 in the comparable period in 2006. Approximately $1.6 million of the increase was attributable to income from our interest in the Grey Ranch processing plant which has experienced increased profitability due to higher levels of utilization during the nine months ended September 30, 2007 as compared to the same period in 2006. Approximately $1.8 million of the increase was attributable to income from Larclay as all of Larclay’s rigs have now been delivered and all but one rig are operational.
We reported an income tax expense of $21.0 million for the nine months ended September 30, 2007, as compared to an expense of $6.9 million for the same period in 2006. The current period income tax expense represents an effective income tax rate of 36.9% as compared to 26.8% in the comparable period in 2006. The lower effective income tax rate in 2006 was attributable to favorable percentage depletion deductions during that period.
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Liquidity and Capital Resources
Summary
Our operating cash flow is influenced mainly by the prices that we receive for our natural gas and oil production; the quantity of natural gas we produce; and, to a lesser extent, the quantity of oil we produce; the success of our development and exploration activities; the demand for our drilling rigs and oil field services and the rates we receive therefore; and, the margins we obtain from our natural gas and CO2 gathering and processing contracts.
During 2006 and the first quarter of 2007, we entered into various debt and equity transactions to fund the acquisition of NEG and our 2007 capital expenditure program. As of September 30, 2007, our cash and cash equivalents were $32.0 million, and we had approximately $300.0 million available under our senior credit facility. The significant cash balance at September 30, 2007 was the result of borrowings under our senior credit facility in anticipation of an acquisition that closed subsequent to quarter-end. On November 9, 2007, we repaid amounts outstanding under our senior credit facility with a portion of the proceeds from our initial public offering. There are currently no amounts outstanding under our senior credit facility. As of September 30, 2007, we had $1,452 million in total debt outstanding.
Our capital expenditures for the three and nine month periods ended September 30, 2007 totaled $403.0 million and $895.2 million, respectively. Please see Note 16 to the condensed consolidated financial statements contained in Part I, Item I of this Quarterly Report for a breakdown of capital expenditures by segment.
Cash Flows from Operations
Our cash flows for the nine months ended September 30, 2007 and 2006 are as follows:
Nine Months Ended | ||||||||
September 30, | ||||||||
2007 | 2006 | |||||||
(In thousands) | ||||||||
Cash flows provided by operating activities | $ | 239,556 | $ | 67,500 | ||||
Cash flows used in investing activities | (897,341 | ) | (223,256 | ) | ||||
Cash flows provided by financing activities | 650,850 | 120,743 | ||||||
Net decrease in cash and cash equivalents | $ | (6,935 | ) | $ | (35,013 | ) | ||
Operating Activities. Net cash provided by operating activities for the nine months ended September 30, 2007 and 2006 were $239.6 million and $67.5 million, respectively. The increase in cash provided by operating activities from 2006 to 2007 was primarily due to our 502.0% increase in production volumes as a result of the NEG and various other acquisitions as well as our drilling success. Also, contributing to this increase was a 241.4% increase in realized and unrealized gains on our derivative contracts. These increases were partially offset by increases in general and administrative costs such as salaries and wages.
Investing Activities. Cash flows used in investing activities increased to $897.3 million in the nine month period ended September 30, 2007 from $223.3 million in the 2006 period as we continued to ramp up our capital expenditure program. For the nine month period ended September 30, 2007, our capital expenditures were $706.6 million in our exploration and production segment, $104.8 million for drilling and oil field services, $45.4 million for midstream gas services and $38.4 million for other capital expenditures. During the same period in 2006, capital expenditures were $88.9 million in our exploration and production segment, $53.8 million for drilling and oil field services, $25.4 million for midstream gas services and $13.1 million for other capital expenditures.
Financing Activities. Since December 2005, we have used equity issuances, borrowings and, to a lesser extent, our cash flows from operations to fund our rapid growth. Proceeds from borrowings increased to $1,262.8 million for the nine months ended September 30, 2007, and we repaid approximately $879.6 million leaving net borrowings during the period of approximately $383.2 million. We also received net proceeds of approximately $318.7 million from a private placement of our common stock. We used the net proceeds from the term loan and the common stock issuance to repay the senior bridge facility and to repay all of our outstanding
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borrowings under our senior credit facility. Our financing activities provided $650.9 million in cash for the nine month period ended September 30, 2007 compared to $120.7 million in the comparable period in 2006.
Credit Facilities and Other Indebtedness
Senior Credit Facility. On November 21, 2006, we entered into a new $750 million senior secured revolving credit facility (the “senior credit facility”) with Bank of America, N.A., as Administrative Agent and Banc of America Securities LLC as Lead Arranger and Book Running Manager. 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 our existing senior secured revolving credit facility and NEG’s existing credit facility, and (iii) pay fees and expenses related to the NEG acquisition and our 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 natural gas and oil properties and other assets related to the exploration, production and development of natural gas and oil properties. The senior credit facility will be available to be drawn on and repaid without restriction so long as we are in compliance with its terms, including certain financial covenants.
The senior credit facility contains various covenants that limit our and certain of our 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 our assets. Additionally, the senior credit facility limits our and certain of our subsidiaries’ ability to incur additional indebtedness with certain exceptions, including under the senior unsecured bridge facility (as discussed below), which was repaid in full during March 2007.
The senior credit facility also contains financial covenants, including maintenance of agreed upon levels for the ratio of (i) our total funded debt to EBITDAX (as defined in the senior credit facility), which may not exceed 4.5:1.0 calculated using the last fiscal quarter on an annualized basis as of the end of fiscal quarters ending on or before September 30, 2008 and calculated using the last four completed fiscal quarters thereafter, (ii) our ratio of EBITDAX to interest expense plus current maturities of long-term debt, which must be at least 2.5:1.0 calculated using the last fiscal quarter on an annualized basis as of the end of fiscal quarters ending on or before September 30, 2008 and calculated using the last four completed fiscal quarters thereafter, and (iii) our current ratio, which must be at least 1.0:1.0. As of the end of the third quarter 2007 we were in compliance with these financial covenants.
The obligations under the senior credit facility are secured by first priority liens on all shares of capital stock of each of our present and future subsidiaries; all intercompany debt of us and our subsidiaries; and substantially all of our assets and the assets of our guarantor subsidiaries, including proven natural gas and oil reserves representing at least 80% of the present discounted value (as defined in the senior credit facility) of our proven natural gas and oil reserves reviewed in determining the borrowing base for the senior credit facility (as determined by the Administrative Agent). Additionally, the obligations under the senior credit facility will be guaranteed by certain of our subsidiaries.
The borrowing base for the senior credit facility is determined by the administrative agent in its sole discretion in accordance with its normal and customary natural gas and oil lending practices and approved by lenders. The reaffirmation of an existing borrowing base amount or an increase in the borrowing base will require approval by Required Lenders (as defined in the senior credit facility). The borrowing base is subject to review semi-annually; however, Required Lenders reserve the right to have (a) one additional redetermination within the first twelve months from the closing date and (b) one additional redetermination of the borrowing base per calendar year thereafter. Unscheduled redeterminations may be made at our request, but are limited to two such requests during the twelve months following the closing date and one request per twelve months thereafter.
The borrowing base includes proved developed producing reserves, proved developed non-producing reserves and proved undeveloped reserves and was $700.0 million as of September 2007. As of September 30, 2007, we had outstanding indebtedness of $400 million on our senior credit facility. We repaid all outstanding borrowings under this facility on November 9, 2007, and there are currently no amounts outstanding under the senior credit facility.
At our election, interest under the senior credit facility is determined by reference to (i) the British Bankers Association LIBOR rate, or LIBOR, plus an applicable margin between 1.25% and 2.00% per annum or (ii) the
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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 will be 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 will be paid at the end of each three-month period. The average interest rates paid on amounts outstanding under our senior credit facility for the three and nine month periods ended September 30, 2007 were 7.08% and 7.62%, respectively.
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 us or our subsidiaries; | |
• | a change of control (as defined in the senior credit facility). |
March 2007 Term Loan. On March 22, 2007, we entered into a $1 billion senior unsecured term loan. The proceeds of the term loan were used to partially repay the senior bridge facility described below. The term loan includes both a floating rate tranche and fixed rate tranche.
We issued $350 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 our option, at LIBOR 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 a prepayment penalty. The average interest rates paid on amounts outstanding under our variable rate term loans for the three and nine month periods ended September 30, 2007 were 8.99% and 8.98%, respectively.
We issued $650 million at a fixed rate of 8.625% with 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 our option, either entirely in cash or entirely with additional Fixed Rate Term Loans. If we elect 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 prepayment penalties.
After March 22, 2008, we are required to offer to exchange the term loan for senior unsecured notes with registration rights. The senior unsecured notes will have substantially similar terms and conditions as the term loan. If we are unable to or do not offer to exchange the term loan for senior unsecured notes with registration rights by April 30, 2008, the interest rate on the term loan will increase by 0.25% every 90 days up to a maximum of 0.50%. The term loan contains other covenants which are ordinary and customary including limitations on the incurrence of indebtedness, payment of dividends, asset sales, certain asset purchases, transactions with related parties and consolidation or merger agreements.
Other Indebtedness. We have financed a portion of our drilling rig fleet and related oil field services equipment through notes with Merrill Lynch Capital Corporation. At September 30, 2007, the aggregate outstanding balance of these credit agreements was $51.3 million, with a fixed interest rate ranging from 7.64% to 8.87%. The notes have a final maturity date of November 1, 2010, 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 we repay the notes prior to maturity.
We have financed the purchase of various vehicles, oil field services equipment and other equipment used in our business. The aggregate outstanding balance of these notes as of December 31, 2006 was $4.5 million. These notes were repaid during the three months ended September 30, 2007 with borrowings under our senior credit facility.
On October 14, 2005, Sagebrush Pipeline, LLC borrowed $4.0 million from Bank of America, N.A. for the purpose of completing the gas processing plant and pipeline in Colorado. This loan was repaid in full in July 2007.
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Senior Bridge Facility. On November 21, 2006, we also entered into an $850 million senior unsecured bridge facility (the “senior bridge facility”) with Banc of America Bridge LLC, as the Initial Bridge Lender and Banc of America Securities LLC, Credit Suisse Securities, Goldman Sachs Credit Partners L.P., and Lehman Brothers Inc., as joint lead arrangers and bookrunners. This facility was repaid in full during March 2007 with proceeds from our senior unsecured term loan.
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 our existing senior secured revolving credit facility and NEG’s existing credit facility, and (iii) pay fees and expenses related to the NEG acquisition and our existing credit facility. The obligations under the senior bridge facility are general unsecured obligations of our company and certain of our subsidiaries. The senior bridge facility was paid in full in March 2007 with the proceeds from the term loan and the common stock issuance described above.
The senior bridge facility contained customary restrictive covenants pertaining to management and operations of our company and our subsidiaries similar to those contained in the senior credit facility. Generally, amounts outstanding under the senior bridge facility bore interest at a base rate equal to the greater of (i) three-month LIBOR plus an applicable margin initially equal to 4.50% per annum or (ii) 9.0% per annum plus an applicable margin initially equal to 0% per annum; provided that the applicable margin for the senior bridge facility will increase by 0.5% at the end of the period that is six months after the closing date for the senior bridge facility and an additional 0.25% per quarter thereafter for as long as the senior bridge facility, Rollover Loans or Exchange Notes remain outstanding subject to a cap of 11% (subject to certain additional interest rate increases in certain circumstances). In addition, the senior bridge facility included a covenant that obligated us to use commercially reasonable efforts to refinance the senior bridge facility as promptly as practicable.
Prior Senior Credit Facility. Prior to its termination on November 21, 2006, we had a $130 million revolving credit facility in place with Bank of America, N.A. (the “prior senior credit facility”). The prior senior credit facility included a $20 million sub-limit for letters of credit. The prior senior credit facility was replaced by the senior credit facility as of November 21, 2006. Advances under the prior senior credit facility were subject to a borrowing base based on our proved developed producing reserves, our proved developed non-producing reserves and proved undeveloped reserves. The borrowing base was subject to re-determination semi-annually at the sole discretion of the lender based on the reports of independent petroleum engineers in accordance with normal and customary natural gas and oil lending practices.
The prior senior credit facility bore interest at our option at either LIBOR plus 2.15% or the Bank of America, N.A. prime rate. We 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 our proved reserves and by a negative pledge on any of our non-mortgaged properties.
Building Mortgage. On November 15, we entered into a note payable in the amount of $20 million with a lending institution which is fully secured by our downtown property. The mortgage bears interest at 6.08% ,and matures 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. We expect to make payments of principal and interest on this note totaling $1.0 million and $1.1 million, respectively, over the next twelve months.
Convertible Preferred Stock
We have 2,184,286 shares of convertible preferred stock issued and outstanding. Each holder of our convertible preferred stock is entitled to quarterly cash dividends at the annual rate of 7.75% of the accreted value of its convertible preferred stock. At our option, we may choose to increase the accreted value of the convertible preferred stock in lieu of paying any quarterly cash dividend. The accreted value is $210 per share as of September 30, 2007. Each share of convertible preferred stock is currently convertible into approximately 10.2 shares of common stock at the option of the holder, subject to certain anti-dilution adjustments. In addition, beginning in the second quarter of 2008, we may convert all outstanding shares of convertible preferred stock at the same conversion rate if we have satisfied certain conditions.
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Initial Public Offering
On November 9, 2007, we completed an initial public offering (the “IPO”) of its common stock. We sold 28,700,000 shares of SandRidge common stock, including 4,170,000 shares sold directly to an entity controlled by Tom L. Ward, at a price of $26 per share. We received net proceeds of approximately $705.4 million after deducting underwriting discounts of approximately $38.3 million and estimated offering expenses of approximately $2.5 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 our 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, we received net proceeds of approximately $89.9 million from these additional shares. This offering generated total gross proceeds to us of approximately $841.8 million and total net proceeds of approximately $795.3 million to us after deducting total underwriting discounts of $44.0 million and other offering expenses estimated to be approximately $2.5 million. After the payment of offering expenses, we used a portion of the aggregate net proceeds to repay outstanding indebtedness under our senior credit facility as well as a note payable related to a recent acquisition. Funds remaining after these repayments will be used to fund future capital expenditures.
Contractual Obligations
A summary of our contractual obligations as of September 30, 2007 is provided in the following table:
Remainder | Payments Due by Year | |||||||||||||||||||||||||||
of 2007 | 2008 | 2009 | 2010 | 2011 | After 2011 | Total | ||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||
Long-term debt | $ | 3,629 | $ | 14,450 | $ | 15,664 | $ | 11,541 | $ | 406,220 | $ | 1,000,000 | $ | 1,451,504 | ||||||||||||||
Interest on term loan(1) | 35,502 | 85,944 | 85,944 | 85,944 | 85,944 | 249,436 | 628,714 | |||||||||||||||||||||
Firm transportation(2) | 237 | 949 | 949 | 949 | 949 | 4,592 | 8,625 | |||||||||||||||||||||
Operating leases | 1,209 | 4,525 | 2,707 | 110 | 46 | — | 8,597 | |||||||||||||||||||||
Third party drilling rig commitments(3) | 5,946 | 8,325 | — | — | — | — | 14,271 | |||||||||||||||||||||
Dispute settlement payments(4) | — | 5,000 | 5,000 | 5,000 | 5,000 | — | 20,000 | |||||||||||||||||||||
Asset retirement obligations | — | 846 | 150 | 199 | 8,582 | 47,731 | 57,508 | |||||||||||||||||||||
Total | $ | 46,523 | $ | 120,039 | $ | 110,414 | $ | 103,743 | $ | 506,741 | $ | 1,301,759 | $ | 2,189,219 | ||||||||||||||
(1) | Based on interest rates as of November 14, 2007. | |
(2) | We entered into a firm transportation agreement with Questar Pipeline Company giving us guaranteed capacity on their pipeline for 10 MmBtu per day at an estimated charge of $0.9 million per year, with a total commitment of $9.1 million. In December 2006 we assigned our rights and obligations to a third party. | |
(3) | Drilling contracts with third party drilling rig operators at specified day rates. All of our drilling rig contracts contain operator performance conditions that allow for pricing adjustments or early termination for operator nonperformance. Subsequent to September 30, 2007, the Company signed short-term contracts (approximately 100 days) for two additional rigs for total commitments of approximately $3.8 million. | |
(4) | In January 2007, we settled a royalty interest dispute and agreed to pay five installments of $5 million each, plus interest commencing April 1, 2007. The remaining installments are due on July 1 of each year commencing July 1, 2008. |
In connection with the NEG acquisition, we acquired restricted deposits aggregating $31.9 million. The restricted deposits represent bank trust and escrow accounts required to be set up by surety bond underwriters and certain former owners of a subsidiary on NEG’s offshore properties. In accordance with requirements of MMS, the NEG subsidiary was required to put in place surety bonds or escrow agreements to provide satisfaction of its eventual responsibility to plug and abandon wells and remove structures when certain offshore fields are no longer in use. As part of the agreement with the surety bond underwriter or the former owners of the particular fields, bank
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trust and escrow accounts were set up and funded based on the terms of the escrow agreements. Certain amounts are required to be paid upon receipt of proceeds from production.
In connection with one of the escrow accounts, we are required to make quarterly deposits to the escrow accounts of $0.8 million. Additionally, for some of the offshore properties, we will be required to deposit additional funds in an escrow account, representing the difference between the required escrow deposit under the surety bond and actual escrow deposit balance at various points in time in the future. Aggregate payments to the escrow accounts are estimated as follows (in thousands):
Remainder of 2007 | $ | 800 | ||
2008 | 3,200 | |||
2009 | 3,200 | |||
2010 | 5,000 | |||
Thereafter | 4,000 | |||
$ | 16,200 | |||
ITEM 3. | Quantitative and Qualitative Disclosures About Market Risk |
General
We are exposed to a variety of market risks, commodity price risk and interest rate risk. We address these risks through a program of risk management which may include the use of derivative instruments.
Commodity Price Risk. Our most significant market risk is the prices we receive for our gas and oil production, which can be highly volatile. In light of this historical volatility, we periodically have entered into, and expect in the future to enter into, derivative arrangements aimed at reducing the variability of gas and oil prices we receive for our production. We will from time to time enter into commodities pricing derivative instruments for a portion of our anticipated production volumes depending upon our management’s view of opportunities under the then current market conditions. We do not intend to enter into derivative instruments that would exceed our expected production volumes for the period covered by the derivative arrangement. Our current credit agreement limits our ability to enter into derivatives transactions to 85% of expected production volumes from estimated proved reserves. Future credit agreements could require a minimum level of commodity price hedging.
We use, or may use, a variety of derivative instruments including collars and fixed-price swaps. These transactions generally require no cash payment upfront and are settled in cash at maturity. While this strategy may result in lower operating profits than if we were not party to these derivative instruments in times of high natural gas prices, we believe that the stabilization of prices and protection afforded us by providing a revenue floor for our production is very beneficial.
For natural gas derivatives, transactions are settled based upon the New York Mercantile Exchange price of natural gas at the Waha hub, a West Texas gas marketing and delivery center, on the final trading day of the month. Settlement for natural gas derivative contracts occurs in the month following the production month. We currently do not enter into derivative arrangements with respect to our oil production, but we may do so in the future if our oil production increases as a result of the initiation of our CO2 tertiary oil recovery operations. Generally, our trade counterparties are affiliates of the financial institution that is a party to our credit agreement, although we do have transactions with counterparties that are not affiliated with this institution.
While we believe that the gas and oil price derivative arrangements we enter into are important to our program to manage price variability for our production, we have not designated any of our derivative contracts as hedges for accounting purposes. We record all derivative contracts on the balance sheet at fair value, which will be significantly affected by changes in gas and oil prices. We establish fair value of our derivative contracts by market price quotations of the derivative contract or, if not available, market price quotations of derivative contracts with similar terms and characteristics. When market quotations are not available, we will estimate the fair value of derivative contracts using option pricing models that management believes represent its best estimate. Changes in fair values of our derivative contracts that are not designated as hedges for accounting purposes are recognized as unrealized gains and losses in current period earnings. As a result, our current period earnings may be significantly
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affected by changes in fair value of our commodities derivative arrangements. The gain recognized in earnings, included in operating costs and expenses, for the nine months ended September 30, 2007 and 2006 was a gain of $55.2 million and $16.2 million, respectively.
At September 30, 2007, our open commodity derivative contracts consisted of the following:
Period | Commodity | Notional | Fix Price | ||||||||
Fixed price swaps: | |||||||||||
April 2007 — October 2007 | Natural gas | 4,280,000 MmBtu | $ | 7.02 | |||||||
April 2007 — October 2007 | Natural gas | 4,280,000 MmBtu | $ | 7.50 | |||||||
September 2007 — December 2007 | Natural gas | 1,220,000 MmBtu | $ | 8.88 | |||||||
October 2007 — December 2007 | Natural gas | 920,000 MmBtu | $ | 7.60 | |||||||
October 2007 — December 2007 | Natural gas | 920,000 MmBtu | $ | 7.82 | |||||||
October 2007 — December 2007 | Natural gas | 920,000 MmBtu | $ | 8.00 | |||||||
October 2007 — December 2007 | Natural gas | 920,000 MmBtu | $ | 8.04 | |||||||
October 2007 — December 2007 | Natural gas | 920,000 MmBtu | $ | 8.77 | |||||||
October 2007 — December 2007 | Natural gas | 920,000 MmBtu | $ | 9.04 | |||||||
November 2007 — June 2008 | Natural gas | 4,860,000 MmBtu | $ | 8.05 | |||||||
November 2007 — June 2008 | Natural gas | 9,720,000 MmBtu | $ | 8.20 | |||||||
November 2007 — March 2008 | Natural gas | 1,520,000 MmBtu | $ | 8.51 | |||||||
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 | |||||||
May 2008 — August 2008 | Natural gas | 2,460,000 MmBtu | $ | 8.38 | |||||||
July 2008 — September 2008 | Natural gas | 920,000 MmBtu | $ | 8.23 | |||||||
July 2008 — December 2008 | Natural gas | 1,840,000 MmBtu | $ | 8.31 | |||||||
Collars: | |||||||||||
January 2007 — December 2007 | Crude oil | 60,000 Bbls | $ | 50.00 − $84.50 | |||||||
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 2007 — December 2007 | Natural gas | 7,300,000 MmBtu | $ | (0.5925 | ) | ||||||
January 2007 — December 2007 | Natural gas | 14,600,000 MmBtu | $ | (0.70 | ) | ||||||
April 2007 — October 2007 | Natural gas | 4,280,000 MmBtu | $ | (0.530 | ) | ||||||
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 | ) | ||||||
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 | ) |
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These derivative instruments have not been designated as hedges.
Interest Rate Risk. We are subject to interest rate risk on our long-term fixed and variable interest rate borrowings. Fixed rate debt, where the interest rate is fixed over the life of the instrument, exposes us (i) to changes in market interest rates reflected in the fair value of the debt and (ii) to the risk that we may need to refinance maturing debt with new debt at a higher rate. Variable rate debt, where the interest rate fluctuates, exposes us to short-term changes in market interest rates as our interest obligations on these instruments are periodically redetermined based on prevailing market interest rates, primarily LIBOR and the federal funds rate.
The indebtedness evidenced by our other notes payable related to our drilling rig fleet and related oil field services equipment, Sagebrush Pipeline, insurance financing, and other equipment and vehicles and a portion of our term loan is a fixed-rate debt, which exposes us to cash-flow risk from market interest rate changes on these notes. The fair value of that debt will vary as interest rates change.
Borrowings under our senior credit facility and a portion of our term loan expose us to certain market risks. We use sensitivity analysis to determine the impact that market risk exposures may have on our variable interest rate borrowings. At September 30, 2007, borrowings outstanding under our senior credit facility totaled $400 million. Based on the approximately $350.0 million outstanding balance of the variable rate portion of our term loan at September 30, 2007, a one percent change in the applicable rate, with all other variables held constant, would result in a change in our interest expense of approximately $2.6 million for the nine months ended September 30, 2007.
In addition to commodity price derivative arrangements, we may enter into derivative transactions to fix the interest we pay on a portion of the money we borrow under our credit agreements. At September 30, 2007, we are not party to any interest rate swap instruments. Future interest rate derivative instruments, if any, are expected to be with affiliates of the financial institution that are party to our credit agreements.
ITEM 4. | Controls and Procedures |
In accordance with Rules 13a-15 and 15d-15 under the Securities and Exchange Act of 1934, as amended (the “Exchange Act”), we carried out an evaluation, under the supervision of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules13a-15(e) and15d-15(e) under the Exchange Act) as of September 30, 2007. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer have concluded that our current disclosure controls and procedures were effective as of September 30, 2007 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (ii) accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. During the three months ended September 30, 2007, there were no changes in our internal control over financial reporting or in other factors that have materially affected or are reasonably likely to materially effect our internal control over financial reporting.
ITEM 1. | Legal Proceedings |
We are involved in various disputes from time to time in the normal course of business. See further discussion of current litigation in Note 12 to the condensed consolidated financial statements. We believe that the ultimate resolution of currently pending litigation will not have a material adverse effect on its results of operations, financial condition or cash flows.
ITEM 1A. | Risk Factors |
There have been no material changes to the risk factors previously disclosed in our Registration Statement onForm S-1/A dated October 23, 2007 and filed with the SEC on October 23, 2007 relating to our initial public
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offering of common stock (the “Registration Statement”). The risk factors listed on pages 13 through 24 under the heading “Risk Factors” in the Registration Statement are incorporated herein by reference.
ITEM 2. | Unregistered Sales of Equity Securities and Use of Proceeds |
(b) The following use of proceeds information is being provided with respect to the Registration Statement, which was declared effective by the SEC on November 5, 2007.
The initial public offering of our common stock, par value $0.001 per share, commenced on November 5, 2007 following the effectiveness of our registration statement onForm S-1 (FileNo. 333-144004). Lehman Brothers, Goldman, Sachs & Co. and Banc of America Securities LLC acted as joint book-running managers and representatives of the underwriters in the offering. We issued and sold 28,700,000 shares of our common stock at $26 per share, including 4,170,000 shares sold directly to an entity controlled by Tom L. Ward, our Chairman, Chief Executive Officer and President. The offering generated gross proceeds of $746.2 million to us and net proceeds of approximately $705.4 million to us after deducting underwriters’ discounts of approximately $38.3 million and other expenses estimated to be approximately $2.5 million. This transaction priced after market close on November 5, 2007. In conjunction with this offering, the underwriters were granted an option to purchase 3,679,500 additional shares of our common stock. The underwriters fully exercised this option and purchased the additional shares on November 6, 2007. After deducting discounts of approximately $5.7 million, we received net proceeds of approximately $89.9 million from these additional shares. After the payment of offering expenses we used a portion of the aggregate net proceeds to repay the outstanding indebtedness under our senior credit facility as well as a note payable outstanding related to a recent acquisition. None of the offering expenses or net proceeds of the offering to us were direct or indirect payments to our directors, officers, affiliates, or to a person owning 10% or more of our common stock.
ITEM 6. | Exhibits |
See the Exhibit Index accompanying this report.
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Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
SandRidge Energy, Inc.
By: | /s/ Dirk M. Van Doren |
Dirk M. Van Doren
Executive Vice President and
Chief Financial Officer
Date: December 3, 2007
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31 | .1 | — | Certification of the Company’s Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241) | |||
31 | .2 | — | Certification of the Company’s Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241) | |||
32 | — | Certification of the Company’s Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350) |
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