SD Q2 10Q 6.30.12
Table of Contents

 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
__________________________
Form 10-Q
__________________________ 
(Mark One)
R
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2012
OR
£
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from              to             
Commission File Number: 001-33784
__________________________ 
SANDRIDGE ENERGY, INC.
(Exact name of registrant as specified in its charter)
__________________________
Delaware
 
20-8084793
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
 
 
 
123 Robert S. Kerr Avenue
Oklahoma City, Oklahoma
 
73102
(Address of principal executive offices)
 
(Zip Code)
Registrant’s telephone number, including area code:
(405) 429-5500
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 R No £

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes R    No £

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
R
 
Accelerated filer
£
Non-accelerated filer
£
(Do not check if a smaller reporting company)
Smaller reporting company
£

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes £    No R

The number of shares outstanding of the registrant’s common stock, par value $0.001 per share, as of the close of business on July 31, 2012, was 491,077,348.
 

Table of Contents

DISCLOSURES REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (“Quarterly Report”) of SandRidge Energy, Inc. (the "Company") includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements express a belief, expectation or intention and generally are accompanied by words that convey projected future events or outcomes. These forward-looking statements may include projections and estimates concerning capital expenditures, the Company’s liquidity and capital resources, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, elements of the Company’s business strategy, the effects of the acquisition of Dynamic Offshore Resources, LLC on the Company's financial condition and other statements concerning the Company’s operations, economic performance and financial condition. Forward-looking statements are generally accompanied by words such as “estimate,” “assume,” “target,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “goal,” “should,” “intend” or other words that convey the uncertainty of future events or outcomes. The Company has based these forward-looking statements on its current expectations and assumptions about future events. These statements are based on certain assumptions and analyses made by the Company in light of its experience and perception of historical trends, current conditions and expected future developments as well as other factors the Company believes are appropriate under the circumstances. The actual results or developments anticipated may not be realized or, even if substantially realized, they may not have the expected consequences to or effects on the Company’s business or operations. Such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in such forward-looking statements. The forward-looking statements in this respect speak only as of the date hereof. The Company disclaims any obligation to update or revise any forward-looking statements, unless required by law, and it cautions readers not to rely on them unduly. While the Company’s management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties relating to, among other matters, the risks discussed in “Risk Factors” in Item 1A of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2011 (the “2011 Form 10-K”).

Table of Contents

SANDRIDGE ENERGY, INC.
FORM 10-Q
Quarter Ended June 30, 2012

INDEX

 
 
 
ITEM 1.
 
 
 
 
 
ITEM 2.
ITEM 3.
ITEM 4.
 
 
 
 
 
 
ITEM 1.
ITEM 1A.
ITEM 2.
ITEM 6.

Table of Contents

PART I. Financial Information

ITEM 1. Financial Statements
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except per share data) 
 
June 30,
2012
 
December 31,
2011
 
(Unaudited)
 
 
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
421,073

 
$
207,681

Accounts receivable, net
288,332

 
206,336

Derivative contracts
204,202

 
4,066

Inventories
4,055

 
6,903

Costs in excess of billings
14,768

 
—

Prepaid expenses
33,648

 
14,099

Other current assets
14,707

 
2,755

Total current assets
980,785

 
441,840

Oil and natural gas properties, using full cost method of accounting
 
 
 
Proved
11,197,054

 
8,969,296

Unproved
948,369

 
689,393

Less: accumulated depreciation, depletion and impairment
(5,011,661
)
 
(4,791,534
)
 
7,133,762

 
4,867,155

Other property, plant and equipment, net
595,250

 
522,269

Restricted deposits
27,941

 
27,912

Derivative contracts
98,237

 
26,415

Goodwill
235,396

 
235,396

Other assets
107,164

 
98,622

Total assets
$
9,178,535

 
$
6,219,609

LIABILITIES AND EQUITY
 
 
 
Current liabilities
 
 
 
Current maturities of long-term debt
$
—

 
$
1,051

Accounts payable and accrued expenses
669,362

 
506,784

Billings and estimated contract loss in excess of costs incurred
6,321

 
43,320

Derivative contracts
6,962

 
115,435

Asset retirement obligation
140,789

 
32,906

Total current liabilities
823,434

 
699,496

Long-term debt
3,549,432

 
2,813,125

Derivative contracts
19,833

 
49,695

Asset retirement obligation
349,192

 
95,210

Other long-term obligations
14,566

 
13,133

Total liabilities
4,756,457

 
3,670,659

Commitments and contingencies (Note 11)

 

Equity
 
 
 
SandRidge Energy, Inc. stockholders’ equity
 
 
 
Preferred stock, $0.001 par value, 50,000 shares authorized
 
 
 
8.5% Convertible perpetual preferred stock; 2,650 shares issued and outstanding at June 30, 2012 and December 31, 2011; aggregate liquidation preference of $265,000
3

 
3

6.0% Convertible perpetual preferred stock; 2,000 shares issued and outstanding at June 30, 2012 and December 31, 2011; aggregate liquidation preference of $200,000
2

 
2

7.0% Convertible perpetual preferred stock; 3,000 shares issued and outstanding at June 30, 2012 and December 31, 2011; aggregate liquidation preference of $300,000
3

 
3

Common stock, $0.001 par value, 800,000 shares authorized; 490,161 issued and 489,191 outstanding at June 30, 2012 and 412,827 issued and 411,953 outstanding at December 31, 2011
475

 
399

Additional paid-in capital
5,202,119

 
4,568,856

Treasury stock, at cost
(6,925
)
 
(6,158
)
Accumulated deficit
(2,360,172
)
 
(2,937,094
)
Total SandRidge Energy, Inc. stockholders’ equity
2,835,505

 
1,626,011

Noncontrolling interest
1,586,573

 
922,939

Total equity
4,422,078

 
2,548,950

Total liabilities and equity
$
9,178,535

 
$
6,219,609

The accompanying notes are an integral part of these condensed consolidated financial statements.

4
Table of Contents

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)

 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
 
(Unaudited)
Revenues
 
 
 
 
 
 
 
Oil and natural gas
$
429,758

 
$
312,111

 
$
771,123

 
$
579,053

Drilling and services
33,632

 
28,537

 
62,941

 
49,571

Midstream and marketing
8,852

 
16,313

 
17,158

 
38,570

Other
6,192

 
7,813

 
8,847

 
10,427

Total revenues
478,434

 
364,774

 
860,069

 
677,621

Expenses
 
 
 
 
 
 
 
Production
122,481

 
81,834

 
205,791

 
155,791

Production taxes
11,001

 
12,666

 
23,255

 
23,242

Drilling and services
19,241

 
18,058

 
36,802

 
33,099

Midstream and marketing
8,559

 
15,873

 
16,513

 
38,156

Depreciation and depletion — oil and natural gas
139,260

 
73,826

 
226,326

 
145,286

Depreciation and amortization — other
15,348

 
13,275

 
29,860

 
26,368

Accretion of asset retirement obligation
7,965

 
2,360

 
10,572

 
4,786

General and administrative
61,716

 
37,678

 
112,017

 
72,091

(Gain) loss on derivative contracts
(669,850
)
 
(169,988
)
 
(415,204
)
 
107,640

Loss (gain) on sale of assets
300

 
(524
)
 
3,380

 
(725
)
Total expenses
(283,979
)
 
85,058

 
249,312

 
605,734

Income from operations
762,413

 
279,716

 
610,757

 
71,887

Other income (expense)
 
 
 
 
 
 
 
Interest expense
(68,569
)
 
(61,687
)
 
(135,534
)
 
(121,124
)
Bargain purchase gain
124,446

 
—

 
124,446

 
—

Loss on extinguishment of debt
—

 
(2,051
)
 
—

 
(38,232
)
Other (expense) income, net
(81
)
 
138

 
2,387

 
1,335

Total other income (expense)
55,796

 
(63,600
)
 
(8,701
)
 
(158,021
)
Income (loss) before income taxes
818,209

 
216,116

 
602,056

 
(86,134
)
Income tax benefit
(103,658
)
 
(7,054
)
 
(103,587
)
 
(6,967
)
Net income (loss)
921,867

 
223,170

 
705,643

 
(79,167
)
Less: net income attributable to noncontrolling interest
99,004

 
13,154

 
100,958

 
13,161

Net income (loss) attributable to SandRidge Energy, Inc.
822,863

 
210,016

 
604,685

 
(92,328
)
Preferred stock dividends
13,881

 
13,881

 
27,763

 
27,821

Income available (loss applicable) to SandRidge Energy, Inc. common stockholders
$
808,982

 
$
196,135

 
$
576,922

 
$
(120,149
)
Earnings (loss) per share
 
 
 
 
 
 
 
Basic
$
1.75

 
$
0.49

 
$
1.34

 
$
(0.30
)
Diluted
$
1.47

 
$
0.42

 
$
1.14

 
$
(0.30
)
Weighted average number of common shares outstanding
 
 
 
 
 
 
 
Basic
461,008

 
398,435

 
430,802

 
398,343

Diluted
560,640

 
495,982

 
530,378

 
398,343

The accompanying notes are an integral part of these condensed consolidated financial statements.

5
Table of Contents

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(In thousands) 
 
SandRidge Energy, Inc. Stockholders
 
 
 
 
 
Convertible Perpetual Preferred Stock
 
Common Stock
 
Additional Paid-In Capital
 
Treasury Stock
 
Accumulated Deficit
 
Non-controlling Interest
 
Total
 
Shares
 
Amount
 
Shares
 
Amount
 
 
 
 
 
 
(Unaudited)
Six Months Ended June 30, 2011
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance at December 31, 2010
7,650

 
$
8

 
406,360

 
$
398

 
$
4,528,912

 
$
(3,547
)
 
$
(2,989,576
)
 
$
11,288

 
$
1,547,483

Issuance of units by royalty trust
—

 
—

 
—

 
—

 
—

 
—

 
—

 
336,892

 
336,892

Distributions to noncontrolling interest owners
—

 
—

 
—

 
—

 
—

 
—

 
—

 
(1,501
)
 
(1,501
)
Stock issuance expense
—

 
—

 
—

 
—

 
(231
)
 
—

 
—

 
—

 
(231
)
Purchase of treasury stock
—

 
—

 
—

 
—

 
—

 
(4,984
)
 
—

 
—

 
(4,984
)
Retirement of treasury stock
—

 
—

 
—

 
—

 
(4,984
)
 
4,984

 
—

 
—

 
—

Stock purchases — retirement plans, net of distributions
—

 
—

 
(110
)
 
—

 
1,998

 
(978
)
 
—

 
—

 
1,020

Stock-based compensation
—

 
—

 
—

 
—

 
24,987

 
—

 
—

 
—

 
24,987

Stock-based compensation excess tax benefit
—

 
—

 
—

 
—

 
7

 
—

 
—

 
—

 
7

Issuance of restricted stock awards, net of cancellations
—

 
—

 
3,668

 
—

 
—

 
—

 
—

 
—

 
—

Net (loss) income
—

 
—

 
—

 
—

 
—

 
—

 
(92,328
)
 
13,161

 
(79,167
)
Convertible perpetual preferred stock dividends
—

 
—

 
—

 
—

 
—

 
—

 
(27,821
)
 
—

 
(27,821
)
Balance at June 30, 2011
7,650

 
$
8

 
409,918

 
$
398

 
$
4,550,689

 
$
(4,525
)
 
$
(3,109,725
)
 
$
359,840

 
$
1,796,685

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Six Months Ended June 30, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance at December 31, 2011
7,650

 
$
8

 
411,953

 
$
399

 
$
4,568,856

 
$
(6,158
)
 
$
(2,937,094
)
 
$
922,939

 
$
2,548,950

Issuance of common stock in acquisition
—

 
—

 
73,962

 
74

 
542,064

 
—

 
—

 
—

 
542,138

Issuance of units by royalty trust
—

 
—

 
—

 
—

 
—

 
—

 
—

 
587,086

 
587,086

Sale of royalty trust units
—

 
—

 
—

 
—

 
71,158

 
—

 
—

 
52,391

 
123,549

Distributions to royalty trust unitholders
—

 
—

 
—

 
—

 
—

 
—

 
—

 
(76,801
)
 
(76,801
)
Purchase of treasury stock
—

 
—

 
—

 
—

 
—

 
(6,704
)
 
—

 
—

 
(6,704
)
Retirement of treasury stock
—

 
—

 
—

 
—

 
(6,704
)
 
6,704

 
—

 
—

 
—

Stock purchases — retirement plans, net of distributions
—

 
—

 
(96
)
 
—

 
1,193

 
(767
)
 
—

 
—

 
426

Stock-based compensation
—

 
—

 
—

 
—

 
25,546

 
—

 
—

 
—

 
25,546

Stock-based compensation excess tax benefit
—

 
—

 
—

 
—

 
8

 
—

 
—

 
—

 
8

Issuance of restricted stock awards, net of cancellations
—

 
—

 
3,372

 
2

 
(2
)
 
—

 
—

 
—

 
—

Net income
—

 
—

 
—

 
—

 
—

 
—

 
604,685

 
100,958

 
705,643

Convertible perpetual preferred stock dividends
—

 
—

 
—

 
—

 
—

 
—

 
(27,763
)
 
—

 
(27,763
)
Balance at June 30, 2012
7,650

 
$
8

 
489,191

 
$
475

 
$
5,202,119

 
$
(6,925
)
 
$
(2,360,172
)
 
$
1,586,573

 
$
4,422,078


The accompanying notes are an integral part of these condensed consolidated financial statements.

6
Table of Contents

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
 
Six Months Ended June 30,
 
2012
 
2011
 
(Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
Net income (loss)
$
705,643

 
$
(79,167
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
 
 
 
Depreciation, depletion and amortization
256,186

 
171,654

Accretion of asset retirement obligation
10,572

 
4,786

Debt issuance costs amortization
5,401

 
5,748

Discount amortization on long-term debt
1,285

 
1,162

Bargain purchase gain
(124,446
)
 
—

Loss on extinguishment of debt
—

 
38,232

Deferred income taxes
(103,328
)
 
(6,986
)
Unrealized (gain) loss on derivative contracts
(455,138
)
 
79,350

Realized loss on amended derivative contracts
117,108

 
—

Realized (gain) loss on financing derivatives
(21,125
)
 
1,576

Loss (gain) on sale of assets
3,380

 
(725
)
Investment income
(97
)
 
(67
)
Stock-based compensation
23,277

 
18,301

Changes in operating assets and liabilities
(1,012
)
 
23,678

Net cash provided by operating activities
417,706

 
257,542

CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
Capital expenditures for property, plant and equipment
(1,123,040
)
 
(857,714
)
Acquisitions, net of cash received
(761,575
)
 
(9,149
)
Proceeds from sale of assets
420,859

 
369,251

Net cash used in investing activities
(1,463,756
)
 
(497,612
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
Proceeds from borrowings
750,000

 
1,725,000

Repayments of borrowings
(16,029
)
 
(1,741,795
)
Premium on debt redemption
—

 
(30,338
)
Debt issuance costs
(27,316
)
 
(19,640
)
Proceeds from issuance of royalty trust units
587,086

 
336,892

Proceeds from the sale of royalty trust units
123,549

 
—

Distributions to royalty trust unitholders
(76,801
)
 
—

Noncontrolling interest distributions
—

 
(1,501
)
Stock issuance expense
—

 
(231
)
Stock-based compensation excess tax benefit
8

 
7

Purchase of treasury stock
(7,980
)
 
(6,030
)
Dividends paid — preferred
(27,763
)
 
(28,980
)
Cash (paid) received on settlement of financing derivatives
(45,312
)
 
5,438

Net cash provided by financing activities
1,259,442

 
238,822

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
213,392

 
(1,248
)
CASH AND CASH EQUIVALENTS, beginning of year
207,681

 
5,863

CASH AND CASH EQUIVALENTS, end of period
$
421,073

 
$
4,615

Supplemental Disclosure of Noncash Investing and Financing Activities
 
 
 
Change in accrued capital expenditures
$
8,672

 
$
2,351

Convertible perpetual preferred stock dividends payable
$
16,572

 
$
16,572

Adjustment to oil and natural gas properties for estimated contract loss
$
10,000

 
$
19,000

Common stock issued in connection with acquisition
$
542,138

 
$
—


The accompanying notes are an integral part of these condensed consolidated financial statements.

7
Table of Contents

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

1. Basis of Presentation

Nature of Business. SandRidge Energy, Inc. (the “Company” or “SandRidge”) is an independent oil and natural gas company concentrating on development and production activities in the Mid-Continent, west Texas and Gulf of Mexico. The Company’s primary areas of focus are the Mississippian formation in the Mid-Continent area of Oklahoma and Kansas and the Permian Basin in west Texas. The Company owns and operates additional interests in the Mid-Continent, Gulf of Mexico, West Texas Overthrust (“WTO”) and Gulf Coast. The Company also operates businesses that are complementary to its primary development and production activities, including gas gathering and processing facilities, an oil and gas marketing business and an oil field services business, including a drilling rig business.

Interim Financial Statements. The accompanying condensed consolidated financial statements as of December 31, 2011 have been derived from the audited financial statements contained in the Company’s 2011 Form 10-K. The unaudited interim condensed consolidated financial statements have been prepared by the Company in accordance with the accounting policies stated in the audited consolidated financial statements contained in the 2011 Form 10-K. 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 the Company believes that the disclosures contained herein are adequate to make the information presented not misleading. In the opinion of management, all adjustments, which consist only of normal recurring adjustments, necessary to state fairly the information in the Company’s unaudited condensed consolidated financial statements have been included. These unaudited condensed consolidated financial statements should be read in conjunction with the financial statements and notes thereto included in the 2011 Form 10-K.

Significant Accounting Policies. For a description of the Company’s significant accounting policies, refer to Note 1 of the consolidated financial statements included in the 2011 Form 10-K.

Reclassifications. Certain reclassifications have been made to prior period financial statements to conform to the current period presentation. These reclassifications had no effect on the Company’s previously reported results of operations.

Use of Estimates. The preparation of the unaudited interim condensed consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

The more significant areas requiring the use of assumptions, judgments and estimates include: oil and natural gas reserves; cash flow estimates used in impairment tests of goodwill and other long-lived assets; depreciation, depletion and amortization; asset retirement obligations; assigning fair value and allocating purchase price in connection with business combinations; income taxes; valuation of derivative instruments; and accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ significantly from these estimates.

Risks and Uncertainties. The Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil and natural gas, each of which depends on numerous factors beyond the Company’s control such as overall oil and natural gas production and inventories in relevant markets, economic conditions, the global political environment, regulatory developments and competition from other energy sources. Oil and natural gas prices historically have been volatile, and may be subject to significant fluctuations in the future. The Company’s derivative arrangements serve to mitigate a portion of the effect of this price volatility on the Company’s cash flows. See Note 9 for the Company’s open oil and natural gas commodity derivative contracts.

The Company has incurred, and will have to continue to incur, capital expenditures to achieve production targets contained in certain gathering and treating agreements. Additionally, the Company has a drilling obligation to each of SandRidge Mississippian Trust I (the “Mississippian Trust I”), SandRidge Permian Trust (the “Permian Trust”) and SandRidge Mississippian Trust II (the "Mississippian Trust II"). See Note 3 for discussion of these drilling obligations. The Company depends on cash flows from operating activities, funding commitments for drilling carry, the sale of non-core assets and the availability of borrowings under its senior secured revolving credit facility (the “senior credit facility”) to fund its capital expenditures. Based on current cash balances, anticipated oil and natural gas prices and production, availability under the senior credit facility, potential access to capital markets, potential sales of royalty trust units and potential sales of working interests, including those with associated drilling carries, the Company expects to be able to fund its planned capital expenditures budget, debt service requirements and working

8
Table of Contents
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)


capital needs for 2012. However, a substantial or extended decline in oil or natural gas prices could have a material adverse effect on the Company’s financial position, results of operations, cash flows and quantities of oil and natural gas reserves that may be economically produced. A substantial or extended decline in oil or natural gas prices could also adversely impact the Company’s ability to comply with the financial covenants under its senior credit facility, which in turn would limit further borrowings to fund capital expenditures. See Note 8 for discussion of the financial covenants in the senior credit facility.

Recent Accounting Pronouncements. In May 2011, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS” (“ASU 2011-04”), which clarifies the FASB’s intent regarding the application of existing fair value measurements and requires additional disclosure of information regarding valuation processes and inputs used. The new disclosure requirements, which are effective for interim and annual reporting periods beginning after December 15, 2011, were implemented by the Company in the first quarter of 2012. The implementation of ASU 2011-04 had no impact on the Company’s financial position or results of operations. See Note 4 for discussion of the Company's fair value measurements.

In September 2011, the FASB issued Accounting Standards Update 2011-08, “Testing Goodwill for Impairment” (“ASU 2011-08”), which allows an entity the option of performing a qualitative assessment to determine whether it is necessary to perform the current two-step annual impairment test. If an entity determines, on the basis of qualitative factors, that the fair value of the reporting unit more-likely-than-not exceeds the carrying amount, the two-step impairment test is not required. ASU 2011-08 does not change how goodwill is calculated or assigned to reporting units, nor does it revise the requirement to test goodwill annually for impairment or amend the requirement to test goodwill for impairment between annual tests if events or circumstances warrant. ASU 2011-08 is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011, with early adoption permitted. The Company will implement ASU 2011-08 for its 2012 goodwill impairment test and does not expect this pronouncement to have any impact on the value of its goodwill.

2. Acquisitions and Divestitures

2011 Divestitures

The Company completed the following divestitures in 2011, all of which were accounted for as adjustments to the full cost pool with no gain or loss recognized:
•
In July 2011, the Company sold its Wolfberry assets in the Permian Basin for $151.6 million, net of fees and post-closing adjustments.
•
In August 2011, the Company sold certain oil and natural gas properties in Lea County and Eddy County, New Mexico, for $199.0 million, net of fees and post-closing adjustments.
•
In November 2011, the Company sold its east Texas natural gas properties in Gregg, Harrison, Rusk and Panola counties for $225.4 million, net of fees and post-closing adjustments.

2012 Acquisitions and Divestitures

Dynamic Acquisition. The Company acquired 100% of the equity interests of Dynamic Offshore Resources, LLC ("Dynamic") on April 17, 2012 for total consideration of approximately $1.2 billion, comprised of approximately $680.0 million in cash and approximately 74 million shares of the Company’s common stock (the “Dynamic Acquisition”). Dynamic is an oil and natural gas exploration, development and production company with operations in the Gulf of Mexico. The Dynamic Acquisition expanded the Company's presence in the Gulf of Mexico, adding oil and natural gas reserves and production to its existing asset base in this area. On April 18, 2012, the Company filed a registration statement with the Securities and Exchange Commission that registers under the Securities Act the resale of the shares of common stock issued as consideration in the Dynamic Acquisition.

9
Table of Contents
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)


The purchase price allocation presented below is preliminary and includes the use of estimates. This preliminary allocation is based on information that was available to management at the time these unaudited condensed consolidated financial statements were prepared. The Company believes the estimates used are reasonable and the significant effects of the Dynamic Acquisition are properly reflected. However, the estimates are subject to change as additional information becomes available and is assessed by the Company. The Company recorded a net deferred tax liability associated with the Dynamic Acquisition which resulted in the release of a portion of the previously recorded valuation allowance on the Company's net deferred tax asset. The Company will monitor the need to further adjust the Company's valuation allowance on its net deferred tax asset as the purchase price allocation is finalized and the full impact of the acquisition is determined. Changes to the purchase price allocation may result in a corresponding change to the bargain purchase gain in the period of change. The following table summarizes the estimated values of assets acquired and liabilities assumed in the accompanying unaudited condensed consolidated balance sheets and the resulting bargain purchase gain recognized in the accompanying unaudited condensed consolidated statements of operations (in thousands, except stock price):
Consideration(1)
 
Shares of SandRidge common stock issued
73,962

SandRidge common stock price
$
7.33

Fair value of common stock issued
542,138

Cash consideration(2)
680,000

Cash balance adjustment(3)
13,091

Total purchase price
$
1,235,229

Estimated Fair Value of Liabilities Assumed
 
Current liabilities
$
125,588

Asset retirement obligation(4)
315,922

Long-term deferred tax liability(5)
103,328

Other non-current liabilities
4,469

Amount attributable to liabilities assumed
549,307

Total purchase price plus liabilities assumed
1,784,536

Estimated Fair Value of Assets Acquired
 
Current assets
143,042

Oil and natural gas properties(6)
1,746,753

Other property, plant and equipment
1,296

Other non-current assets
17,891

Amount attributable to assets acquired
1,908,982

Bargain purchase gain(7)
$
(124,446
)
____________________
(1)
Consideration paid by SandRidge consisted of 73,961,554 shares of SandRidge common stock and cash of approximately $680.0 million. The value of the stock consideration is based upon the closing price of $7.33 per share of SandRidge common stock on April 17, 2012, which was the closing date of the Dynamic Acquisition. Under the acquisition method of accounting, the purchase price is determined based on the total cash paid and the fair value of SandRidge common stock issued on the acquisition date.
(2)
Cash consideration paid, including amounts paid to retire Dynamic’s long-term debt, was funded through a portion of the net proceeds from the Company’s issuance of $750.0 million of unsecured 8.125% Senior Notes due 2022 (the “8.125% Senior Notes”).
(3)
In accordance with the Equity Purchase Agreement dated February 1, 2012, the Company remitted to the seller a cash payment equal to Dynamic's average daily cash balance for the 30-day period ending on the second day prior to closing. This resulted in an additional cash payment by SandRidge of $13.1 million at closing.
(4)
The estimated fair value of the acquired asset retirement obligation was determined using SandRidge’s credit adjusted risk free rate.

10
Table of Contents
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)


(5)
The net deferred tax liability is primarily a result of the difference between the estimated fair value and the Company's expected tax basis in the assets acquired and liabilities assumed. The net deferred tax liability also includes the effects of deferred tax assets associated with net operating losses and other tax attributes acquired as a result of the Dynamic Acquisition.
(6)
The fair value of oil and natural gas properties acquired was estimated using a discounted cash flow model, with future cash flows estimated based upon projections of oil and natural gas reserve quantities and weighted average oil and natural gas prices of $113.62 per barrel of oil and $3.83 per Mcf of natural gas, after adjustment for transportation fees and regional price differentials. The commodity prices utilized were based upon commodity strip prices as of April 17, 2012 for the first four years and escalated for inflation at a rate of 2.0% annually beginning with the fifth year through the end of production. Future cash flows were discounted using an industry weighted average cost of capital rate.
(7)
The bargain purchase gain results from the excess of the fair value of net assets acquired over consideration paid and, as additional information becomes available, is subject to adjustment. The Company was able to acquire Dynamic for less than the estimated fair value of its net assets due to less competition to acquire Dynamic's properties due to their offshore location.

The market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates used by the Company to estimate the fair market value of the oil and natural gas properties acquired represent Level 3 inputs.

The following unaudited pro forma combined results of operations are provided for the three and six-month periods ended June 30, 2012 and June 30, 2011 as though the Dynamic Acquisition had been completed as of the beginning of the earliest period presented, or January 1, 2011. The pro forma combined results of operations for the three and six-month periods ended June 30, 2012 and 2011 have been prepared by adjusting the historical results of the Company to include the historical results of Dynamic, certain reclassifications to conform Dynamic’s presentation and accounting policies to the Company's and the impact of the bargain purchase gain resulting from the preliminary purchase price allocation. These supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the combined company for the periods presented or that may be achieved by the combined company in the future. The pro forma results of operations do not include any cost savings or other synergies that resulted, or may result, from the Dynamic Acquisition or any estimated costs that will be incurred to integrate Dynamic. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors.
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2012
(1)
 
2011
 
 
2012
(1)
 
2011
(2)
 
(In thousands, except per share data)
Revenues
$
508,198
 
 
$
493,445
 
 
$
1,038,003
 
 
$
906,399
 
Net income
$
712,007
 
 
$
285,245
 
 
$
493,282
 
 
$
160,426
 
Income available to SandRidge Energy, Inc. common stockholders
$
599,122
 
 
$
258,217
 
 
$
364,561
 
 
$
118,984
 
Pro forma net income per common share
 
 
 
 
 
 
 
Basic
$
1.26
 
 
$
0.55
 
 
$
0.77
 
 
$
0.25
 
Diluted
$
1.07
 
 
$
0.48
 
 
$
0.68
 
 
$
0.25
 
____________________
(1)
Pro forma net income, income available to SandRidge Energy, Inc. common stockholders and net income per common share exclude $9.9 million and $12.4 million of transaction costs incurred and included in general and administrative expenses for the three and six-month periods ended June 30, 2012, respectively, a $124.4 million bargain purchase gain and a $103.3 million partial valuation allowance release, included in income tax benefit, in the accompanying unaudited condensed consolidated statements of operations for both the three and six-month periods ended June 30, 2012. Pro forma net income, income available to SandRidge Energy, Inc. common stockholders and net income per common share exclude $10.9 million of fees to secure financing for the Dynamic Acquisition incurred and included in interest expense in the accompanying unaudited condensed consolidated statements of operations for the six-month period ended June 30, 2012.
(2)
Pro forma net income, income applicable to SandRidge Energy, Inc. common stockholders and net income per common share include a $124.4 million bargain purchase gain, $13.0 million of estimated transaction costs, $10.9 million of fees to secure financing for the Dynamic Acquisition and a partial valuation allowance release of $103.3 million.

11
Table of Contents
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)


Revenues of $108.0 million and income from operations of $28.5 million associated with Dynamic for the period from April 18, 2012 through June 30, 2012 have been included in the accompanying unaudited condensed consolidated statements of operations for the three and six-month periods ended June 30, 2012. Additionally, the Company has incurred $9.9 million and $12.4 million in acquisition-related costs for the Dynamic Acquisition, which have been included in general and administrative expenses in the accompanying unaudited condensed consolidated statements of operations for the three and six-month periods ended June 30, 2012, respectively.    

Sale of Tertiary Recovery Properties. In June 2012, the Company sold its tertiary recovery properties located in the Permian Basin area of west Texas for approximately $130.0 million, subject to post-closing adjustments. The sale of the acreage and working interests in wells was accounted for as an adjustment to the full cost pool with no gain or loss recognized. As a result of the sale, the Company was relieved of its commitment to purchase CO2 for use in these operations. The Company's obligation under this commitment was $22.8 million as of December 31, 2011.

Acquisition of Gulf of Mexico Properties. In June 2012, the Company acquired oil and natural gas properties in the Gulf of Mexico located on approximately 184,000 gross (103,000 net) acres for approximately $38.5 million, net of purchase price adjustments and subject to post-closing adjustments. This acquisition expanded the Company's presence in the Gulf of Mexico, adding oil and natural gas reserves and production to its existing asset base in this area.
This acquisition qualifies as a business combination for accounting purposes and, as such, the Company estimated the fair value of the acquired properties as of the June 20, 2012 acquisition date, which is the date on which the Company obtained control of the properties. The fair value was estimated using a discounted cash flow model based upon market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs.
The Company estimates the fair value of these properties approximates the fair value that would be paid by a typical market participant. As a result, no goodwill or bargain purchase gain has been recognized in conjunction with the purchase of these properties. Acquisition-related costs totaling $0.1 million have been expensed as incurred in general and administrative expenses in the accompanying unaudited condensed consolidated statements of operations for the three and six-month periods ended June 30, 2012. Revenues of $0.6 million and earnings of $0.2 million generated by the acquired properties from June 21, 2012 to June 30, 2012 have been included in the accompanying unaudited condensed consolidated statements of operations for the three and six-month periods ended June 30, 2012.
The following table summarizes the consideration paid to acquire the properties and the amounts of the assets acquired and liabilities assumed as of June 20, 2012. The purchase price allocation is preliminary and subject to adjustment upon the final closing settlement to be completed during 2012.
 
(in thousands)
Consideration paid
 
Cash, net of purchase price adjustment
$
38,458

Fair value of identifiable assets acquired and liabilities assumed
 
  Proved developed and undeveloped properties
93,901

  Asset retirement obligation
(55,443
)
Total identifiable net assets
$
38,458

 

12
Table of Contents
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)


The following unaudited pro forma combined results of operations are provided for the three and six-month periods ended June 30, 2012 and June 30, 2011 as though the Company acquired the Gulf of Mexico properties as of the beginning of the earliest period presented, or January 1, 2011. The pro forma combined results of operations for the three and six-month periods ended June 30, 2012 and 2011 have been prepared by adjusting the historical results of the Company to include the historical results of the acquired properties and estimates of the effect of the transaction on the combined results. These supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved had the transaction been in effect for the periods presented or that may be achieved by the Company in the future. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors.
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2012
 
 
2011
 
 
2012
 
 
2011
 
 
(In thousands, except per share data)
Revenues
$
492,233
 
 
$
388,248
 
 
$
888,485
 
 
$
722,247
 
Net income (loss)
$
923,010
 
 
$
233,710
 
 
$
707,923
 
 
$
(60,835
)
Income available (loss applicable) to SandRidge Energy, Inc. common stockholders
$
810,125
 
 
$
206,675
 
 
$
579,202
 
 
$
(101,817
)
Pro forma net income (loss) per common share
 
 
 
 
 
 
 
Basic
$
1.76
 
 
$
0.52
 
 
$
1.34
 
 
$
(0.26
)
Diluted
$
1.47
 
 
$
0.44
 
 
$
1.14
 
 
$
(0.26
)
Sale of Working Interests and Associated Drilling Carry Commitments

During 2011 and the first quarter of 2012, the Company entered into two transactions whereby the Company sold non-operated working interests in the Mississippian formation. In these transactions, the Company received aggregate cash proceeds of $500.0 million for the sale of working interests and received drilling carry commitments to fund a portion of its future drilling and completion costs totaling $1.0 billion. For accounting purposes, initial cash proceeds from these transactions were reflected as a reduction of oil and natural gas properties with no gain or loss recognized, and amounts received or billed during 2011 and 2012 attributable to the drilling carry reduced the Company’s capital expenditures. These transactions, as well as drilling carry amounts received or billed and remaining as of June 30, 2012, are as follows:
 
Partner
 
Closing Date
 
Proceeds Received At Closing(1)
 
Drilling Carry Recorded
 
Drilling Carry Remaining
 
 
 
 
(in millions)
Atinum MidCon I, LLC
 
September 2011
 
$
287.0

 
$
82.8

 
$
167.2

Repsol E&P USA, Inc.
 
January 2012
 
272.5

 
78.2

 
671.8

 
 
 
 
$
559.5

 
$
161.0

 
$
839.0

____________________
(1)    Includes amounts related to the drilling carry.
    
In September 2011, the Company sold to Atinum MidCon I, LLC (“Atinum”) non-operated working interests equal to approximately 113,000 net acres in the Mississippian formation in northern Oklahoma and southern Kansas for approximately $250.0 million. In addition, Atinum agreed to pay the development costs related to its working interest, as well as a portion of the Company’s development costs equal to Atinum’s working interest for wells within an area of mutual interest up to $250.0 million. The Company expects Atinum’s funding of the Company’s development cost for wells within the area of mutual interest to occur over a period not to exceed three years.

In January 2012, the Company sold (i) non-operated working interests equal to approximately 250,000 net acres, in the Mississippian formation in western Kansas and (ii) non-operated working interests equal to approximately 114,000 net acres, and a proportionate share of existing salt water disposal facilities in the Mississippian formation in northern Oklahoma and southern Kansas to Repsol E&P USA Inc. (“Repsol”) for approximately $250.0 million. In addition, Repsol agreed to pay the development costs related to its working interests, as well as a portion of the Company’s development costs equal to 200% of Repsol’s working

13
Table of Contents
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)


interests for wells within an area of mutual interest up to $750.0 million. The Company expects Repsol’s funding of the Company’s development cost for wells within the area of mutual interest to occur over a three-year period.

During the six-month period ended June 30, 2012, the Company recorded approximately $142.1 million of Atinum and Repsol's drilling carry, which reduced the Company’s capital expenditures for the period.

3. Variable Interest Entities

The Company consolidates the activities of variable interest entities (“VIEs”) of which it is the primary beneficiary. The primary beneficiary of a VIE is that variable interest holder possessing a controlling financial interest through (i) its power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (ii) its obligation to absorb losses or its right to receive benefits from the VIE that could potentially be significant to the VIE. In order to determine whether the Company owns a variable interest in a VIE, the Company performs a qualitative analysis of the entity’s design, organizational structure, primary decision makers and related financial agreements.

The Company’s significant associated VIEs, including those for which the Company has determined it is the primary beneficiary and those for which it has determined it is not, are described below.

Grey Ranch Plant, L.P. Primarily engaged in treating and transportation of natural gas, Grey Ranch Plant, L.P. (“GRLP”) is a limited partnership that operates the Company’s Grey Ranch plant (the “Plant”) located in Pecos County, Texas. The Company has long-term operating and gathering agreements with GRLP and also owns a 50% interest in GRLP, which represents a variable interest. Income or losses of GRLP are allocated to the partners based on ownership percentage and any operating or cash shortfalls require contributions from the partners. The Company has determined that GRLP qualifies as a VIE because certain equity holders lack the ability to participate in decisions impacting GRLP. Agreements related to the ownership and operation of GRLP provide for GRLP to pay management fees to the Company to operate the Plant and lease payments for the Plant. Under the operating agreements, lease payments are reduced if throughput volumes are below those expected. The Company determined that it is the primary beneficiary of GRLP as it has both (i) the power to direct the activities of GRLP that most significantly impact its economic performance as operator of the Plant and (ii) the obligation to absorb losses, as a result of the operating and gathering agreements, that could potentially be significant to GRLP and, therefore, consolidates the activity of GRLP in its consolidated financial statements. The 50% ownership interest not held by the Company is presented as noncontrolling interest in the consolidated financial statements.

GRLP’s assets can be used to settle only its own obligations and not other obligations of the Company. GRLP’s creditors have no recourse to the general credit of the Company. Although GRLP is included in the Company’s consolidated financial statements, the Company’s legal interest in GRLP’s assets is limited to its 50% ownership. At June 30, 2012 and December 31, 2011, $7.8 million and $8.2 million, respectively, of noncontrolling interest in the accompanying unaudited condensed consolidated balance sheets were related to GRLP. GRLP’s assets and liabilities, after considering the effects of intercompany eliminations, included in the accompanying unaudited condensed consolidated balance sheets at June 30, 2012 and December 31, 2011 consisted of the following (in thousands):
 
June 30,
2012
 
December 31,
2011
Cash and cash equivalents
$
1,052

 
$
1,702

Accounts receivable, net
21

 
24

Inventory
109

 
109

Prepaid expenses
59

 
176

Total current assets
1,241

 
2,011

Other property, plant and equipment, net
14,411

 
14,985

Total assets
$
15,652

 
$
16,996

Accounts payable and accrued expenses
$
152

 
$
280

Total liabilities
$
152

 
$
280

 

14
Table of Contents
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)


Grey Ranch Plant Genpar, LLC. The Company owns a 50% interest in Grey Ranch Plant Genpar, LLC (“Genpar”), the managing partner and 1% owner of GRLP. Additionally, the Company serves as Genpar’s administrative manager. Genpar’s ownership interest in GRLP is its only asset. As managing partner of GRLP, Genpar has the sole right to manage, control and conduct the business of GRLP. However, Genpar is restricted from making certain major decisions, including the decision to remove the Company as operator of the Plant. The rights afforded the Company under the Plant operating agreement and the restrictions on Genpar limit Genpar’s ability to make decisions on behalf of GRLP. Therefore, Genpar is considered a VIE. Although both the Company and Genpar’s other equity owner share equally in Genpar’s economic losses and benefits and also have agreements that may be considered variable interests, the Company determined it was the primary beneficiary of Genpar due to (i) its ability, as administrative manager and operator of the Plant, to direct the activities of Genpar that most significantly impact its economic performance and (ii) its obligation or right, as operator of the Plant, to absorb the losses of or receive benefits from Genpar that could potentially be significant to Genpar. As the primary beneficiary, the Company consolidates Genpar’s activity. However, its sole asset, the investment in GRLP, is eliminated in consolidation. Genpar has no liabilities.

Royalty Trusts. SandRidge owns beneficial interests in three Delaware statutory trusts. The Mississippian Trust I, the Permian Trust and the Mississippian Trust II (each individually, a “Royalty Trust” and collectively, the “Royalty Trusts”) completed initial public offerings of their common units in April 2011, August 2011 and April 2012, respectively. Concurrent with the closing of each offering, the Company conveyed certain royalty interests to each Royalty Trust in exchange for the net proceeds of the offering and common units representing beneficial interests in the Royalty Trust. Royalty interests conveyed to the Royalty Trusts are in certain existing wells and wells to be drilled on oil and natural gas properties leased by the Company in defined areas of mutual interest. Conveyance of the royalty interests was recorded at the Company's historical cost. The following table summarizes information about each Royalty Trust upon completion of its initial public offering:
 
 
Mississippian Trust I
 
Permian Trust
 
Mississippian Trust II
Net proceeds of offering (in millions)
 
$
336.9

 
$
580.6

 
$
587.1

Total outstanding common units
 
21,000,000

 
39,375,000

 
37,293,750

Total outstanding subordinated units
 
7,000,000

 
13,125,000

 
12,431,250

Beneficial interest owned by Company(1)
 
38.4
%
 
34.3
%
 
39.9
%
Liquidation date(2)
 
12/31/2030

 
3/31/2031

 
12/31/2031

 ____________________
(1)
The Company sold common units of the Mississippian Trust I and the Permian Trust in transactions exempt from registration under Rule 144 under the Securities Act subsequent to their initial public offerings during the three and six-month periods ended June 30, 2012. These transactions decreased the Company's beneficial interest in the Royalty Trusts. See further discussion of the unit sales below.
(2)
At the time each Royalty Trust terminates, 50% of the royalty interests conveyed to the Royalty Trust will automatically revert to the Company.
    
The Royalty Trusts make quarterly cash distributions to unitholders based on calculated distributable income. In order to provide support for cash distributions on the common units, the Company agreed to subordinate a portion of the units it owns in each Royalty Trust (the “subordinated units”), which constitute 25% of the total outstanding units of each Royalty Trust. The subordinated units are entitled to receive pro rata distributions from the Royalty Trusts each quarter if and to the extent there is sufficient cash to provide a cash distribution on the common units that is no less than the applicable quarterly subordination threshold. If there is not sufficient cash to fund such a distribution on all common units, the distribution to be made with respect to the subordinated units will be reduced or eliminated for such quarter in order to make a distribution, to the extent possible, of up to the subordination threshold amount on all common units, including common units held by the Company. In exchange for agreeing to subordinate a portion of its Royalty Trust units, SandRidge is entitled to receive incentive distributions equal to 50% of the amount by which the cash available for distribution on all of the Royalty Trust units exceeds the applicable quarterly incentive threshold. The Royalty Trusts declared and paid quarterly distributions during the three and six-month periods ended June 30, 2012 as follows (in millions):
 
 
Three Months Ended June 30, 2012
 
Six Months Ended June 30, 2012
Total distributions
 
$
65.9

 
$
118.0

Distributions to third-party unitholders
 
$
44.1

 
$
76.8



15
Table of Contents
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)


There were no quarterly distributions declared and paid during the three or six-month periods ended June 30, 2011. See Note 18 for discussion of the Royalty Trusts' distribution declarations in July 2012.

Pursuant to the trust agreements governing the Royalty Trusts, SandRidge has a loan commitment to each Royalty Trust, whereby SandRidge will loan funds to the Royalty Trust on an unsecured basis, with terms substantially the same as would be obtained in an arm's length transaction between SandRidge and an unaffiliated party, if at any time the Royalty Trust's cash is not sufficient to pay ordinary course administrative expenses as they become due. Any funds loaned may not be used to satisfy indebtedness of the Royalty Trust or to make distributions. There were no amounts outstanding under the loan commitments at June 30, 2012 or December 31, 2011.

The Company and one of its wholly owned subsidiaries entered into development agreements with the Royalty Trusts that obligate the Company to drill, or cause to be drilled, a specified number of wells within respective areas of mutual interest, which are also subject to the royalty interests granted to the Mississippian Trust I, Permian Trust and Mississippian Trust II, by December 31, 2014, March 31, 2015 and December 31, 2016, respectively. In the event of delays, the Company will have until December 31, 2015 and March 31, 2016 to fulfill its drilling obligations to the Mississippian Trust I and Permian Trust, respectively. At the end of the fourth full calendar quarter following satisfaction of the Company's drilling obligation (the “subordination period”), the subordinated units of each Royalty Trust will automatically convert into common units on a one-for-one basis and the Company's right to receive incentive distributions will terminate. One of the Company's wholly-owned subsidiaries also granted to each Royalty Trust a lien on the Company's interests in the properties where the development wells will be drilled in order to secure the estimated amount of drilling costs for the Royalty Trust's interests in the wells. As the Company fulfills its drilling obligation to each Royalty Trust, development wells that have been drilled and perforated for completion are released from the lien (subject to completion of an initial minimum number of wells for the Mississippian Trust II) and the total amount that may be recovered by each Royalty Trust is proportionately reduced. As of June 30, 2012, the total maximum amount recoverable by the Royalty Trusts under the liens was approximately $508.3 million. Additionally, the Company and each Royalty Trust entered into an administrative services agreement, pursuant to which the Company provides certain administrative services to the Royalty Trust, including hedge management services to the Permian Trust and the Mississippian Trust II. The Company also entered into derivatives agreements with each Royalty Trust, pursuant to which the Company provides to the Royalty Trust the economic effects of certain of the Company's derivative contracts. Substantially concurrent with the execution of the derivatives agreements with the Permian Trust and the Mississippian Trust II, the Company novated certain of the derivative contracts underlying the respective derivatives agreements to the Permian Trust and the Mississippian Trust II. In April 2012, the Company novated certain additional derivative contracts underlying the derivatives agreement to the Permian Trust. The tables below present the open oil and natural gas commodity derivative contracts at June 30, 2012 underlying the derivatives agreements, including the contracts novated to the Permian Trust and the Mississippian Trust II. The combined volume in the tables below reflects the total volume of the Royalty Trusts' open oil and natural gas commodity derivative contracts. See Note 9 for further discussion of the derivatives agreement between the Company and each Royalty Trust.

Oil Price Swaps Underlying the Derivatives Agreements
 
Notional (MBbl)
 
Weighted Avg. Fixed Price
July 2012 — December 2012
595

 
$
104.19

January 2013 — December 2013
1,814

 
$
103.03

January 2014 — December 2014
2,053

 
$
100.78

January 2015 — December 2015
667

 
$
101.02


Natural Gas Collars Underlying the Derivatives Agreements
 
Notional (MMBtu)
 
Collar Range
July 2012 — December 2012
402

 
$4.00 - 6.20
January 2013 — December 2013
858

 
$4.00 - 7.15
January 2014 — December 2014
937

 
$4.00 - 7.78
January 2015 — December 2015
1,010

 
$4.00 - 8.55


16
Table of Contents
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)


Oil Price Swaps Underlying the Derivatives Agreements and Novated to the Royalty Trusts
 
Notional (MBbl)
 
Weighted Avg. Fixed Price
July 2012 — December 2012
674

 
$
104.39

January 2013 — December 2013
1,021

 
$
103.35

January 2014 — December 2014
799

 
$
100.59

January 2015 — March 2015
104

 
$
100.90


The Company's ownership interest in each Royalty Trust and its loan commitment with each Royalty Trust constitute variable interests. The Royalty Trusts are considered VIEs due to the lack of voting or similar decision-making rights of the Royalty Trusts' equity holders regarding activities that have a significant effect on the economic success of the Royalty Trusts. The Company has determined it is the primary beneficiary of the Royalty Trusts as it has (a) the power to direct the activities that most significantly impact the economic performance of the Royalty Trusts through (i) its participation in the creation and structure of the Royalty Trusts, (ii) the manner in which it fulfills its drilling obligations to the Royalty Trusts and (iii) its operation of a majority of the oil and natural gas properties that are subject to the conveyed royalty interests and marketing of the associated production, and (b) the obligation to absorb losses and right to receive residual returns, through its ownership of the subordinated units and the loan commitments, that could potentially be significant to the Royalty Trusts. As a result, the Company began consolidating the activities of the Royalty Trusts into its results of operations upon conveyance of the royalty interests to each Royalty Trust. In consolidation, the common units of the Royalty Trusts owned by third parties are reflected as noncontrolling interest in the consolidated financial statements.

Each Royalty Trust's assets can be used to settle only that Royalty Trust's obligations and not other obligations of the Company or another Royalty Trust. The Royalty Trusts' creditors have no contractual recourse to the general credit of the Company. Although the Royalty Trusts are included in the Company's consolidated financial statements, the Company's legal interest in the Royalty Trusts' assets are limited to its ownership of the Royalty Trusts units. At June 30, 2012 and December 31, 2011, $1,578.8 million and $914.7 million, respectively, of noncontrolling interest in the accompanying unaudited condensed consolidated balance sheets were attributable to the Royalty Trusts. The Royalty Trusts' assets and liabilities, after considering the effects of intercompany eliminations, included in the accompanying unaudited condensed consolidated balance sheets at June 30, 2012 and December 31, 2011 consisted of the following (in thousands):    
 
June 30,
2012
 
December 31,
2011
Cash and cash equivalents(1)
$
3,844

 
$
3,151

Accounts receivable
26,199

 
18,357

Derivative contracts
19,538

 
1,499

Total current assets
49,581

 
23,007

Investment in royalty interests(2)
1,325,942

 
858,795

Less: accumulated depletion
(55,799
)
 
(24,404
)
 
1,270,143

 
834,391

Derivative contracts
18,312

 
5,668

Total assets
$
1,338,036

 
$
863,066

 
 
 
 
Accounts payable and accrued expenses
$
2,364

 
$
486

Total liabilities
$
2,364

 
$
486

 ____________________
(1)
Includes $3.0 million held by the trustee as reserves for future general and administrative expenses.
(2)
Investment in royalty interests is included in oil and natural gas properties in the accompanying unaudited condensed consolidated balance sheets, and was determined by allocating the historical net book value of the Company's full cost pool based on the fair value of each Royalty Trust's royalty interests relative to the fair value of the Company's full cost pool.

The Company sold Mississippian Trust I and Permian Trust common units in transactions exempt from registration pursuant to Rule 144 under the Securities Act during the three and six-month periods ended June 30, 2012 for total proceeds of $24.7 million and $123.5 million, respectively. The unit sales were accounted for as equity transactions with no gain or loss

17
Table of Contents
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)


recognized. The Company continues to be the primary beneficiary of the Mississippian Trust I and the Permian Trust, as discussed above, and continues to consolidate the activities of the Royalty Trusts. The Company's beneficial interests in the Royalty Trusts at June 30, 2012 and December 31, 2011 were as follows:
 
Beneficial Interest Owned by Company
 
June 30,
2012
 
December 31,
2011
Mississippian Trust I
29.3
%
 
38.4
%
Permian Trust
30.5
%
 
34.3
%
Mississippian Trust II
39.9
%
 
N/A


Piñon Gathering Company, LLC. The Company has a gas gathering and operations and maintenance agreement with Piñon Gathering Company, LLC (“PGC”) through June 30, 2029. Under the gas gathering agreement, the Company is required to compensate PGC for any throughput shortfalls below a required minimum volume. By guaranteeing a minimum throughput, the Company absorbs the risk that lower than projected volumes will be gathered by the gathering system. Therefore, PGC is a VIE. Other than as required under the gas gathering and operations and maintenance agreements, the Company has not provided any support to PGC. While the Company operates the assets of PGC as directed under the operations and management agreement, the member and managers of PGC have the authority to directly control PGC and make substantive decisions regarding PGC’s activities including terminating the Company as operator without cause. As the Company does not have the ability to control the activities of PGC that most significantly impact PGC’s economic performance, the Company is not the primary beneficiary of PGC. Therefore, the results of PGC’s activities are not consolidated into the Company’s financial statements. The amounts due from and due to PGC as of June 30, 2012 and December 31, 2011, respectively, included in the accompanying unaudited condensed consolidated balance sheets are as follows (in thousands):
 
June 30,
2012
 
December 31,
2011
Accounts receivable due from PGC
$
2,621

 
$
3,205

Accounts payable due to PGC
$
5,861

 
$
4,603


4. Fair Value Measurements

The Company measures and reports certain assets and liabilities on a fair value basis and has classified and disclosed its fair value measurements using the following levels of the fair value hierarchy:
 
Level 1
Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities.
 
 
Level 2
Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.
 
 
Level 3
Measurement based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable for objective sources (i.e., supported by little or no market activity).

Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values, stated below, considers the market for the Company’s financial assets and liabilities, the associated credit risk and other factors. The Company considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. The Company has assets and liabilities classified as Level 1, Level 2 and Level 3, as described below.


18
Table of Contents
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)


Level 1 Fair Value Measurements

Restricted deposits. The fair value of restricted deposits invested in mutual funds or municipal bonds is based on quoted market prices. For restricted deposits held in savings accounts, carrying value is deemed to approximate fair value.

Other assets. The fair value of other long-term assets, consisting of assets attributable to the Company’s deferred compensation plan, is based on quoted market prices.

Level 2 Fair Value Measurements

Derivative contracts. The fair values of the Company’s oil and natural gas fixed price swaps, natural gas collars and interest rate swap are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, interest rates and discount rates, or can be corroborated from active markets. Fair value is determined through the use of a discounted cash flow model using the applicable inputs, discussed above. The Company applies a weighted average credit default risk rating factor for its counterparties or gives effect to its credit default risk rating, as applicable, in determining the fair value of these derivative contracts. Credit default risk ratings are based on current published credit default swap rates.

Level 3 Fair Value Measurements

Derivative contracts. The fair values of the Company’s diesel fixed price swaps and oil and natural gas basis swaps are based upon quotes obtained from counterparties to the derivative contracts. These values are reviewed internally for reasonableness through the use of a discounted cash flow model using non-exchange traded regional pricing information. Additionally, the Company applies a weighted average credit default risk rating factor for its counterparties or gives effect to its credit risk, as applicable, in determining the fair value of these derivative contracts. The significant unobservable input used in the fair value measurement of the Company’s diesel fixed price swaps is the estimate of diesel prices. Significant (increases) decreases in diesel prices could result in a significantly (lower) higher fair value measurement. The significant unobservable inputs used in the fair value measurement of the Company’s oil and natural gas basis swaps is the estimate of future oil and natural gas basis differentials. Significant increases (decreases) in oil and natural gas basis differentials could result in a significantly higher (lower) fair value measurement. The significant unobservable inputs and the range and weighted average of these inputs used in the Company's level three fair value measurements at June 30, 2012 are included in the table below.
Derivative Type
 
Unobservable Input
 
Range
 
Weighted Average
 
Fair Value
 
 
 
 
 
 
 
 
 
 
 
 
(in thousands)
Diesel fixed price swaps
 
Diesel price forward curve inputs
 
$2.74
–
$2.83
per gallon
 
$2.78
per gallon
 
$
(113
)
Oil basis swaps
 
Oil basis differential forward curve inputs
 
$8.70
–
$12.57
per barrel
 
$10.64
per barrel
 
$
5,126



19
Table of Contents
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)


The following tables summarize the Company’s assets and liabilities measured at fair value on a recurring basis by the fair value hierarchy (in thousands):

June 30, 2012
 
Fair Value Measurements
 
Netting(1)
 
Assets/Liabilities at Fair Value
 
Level 1
 
Level 2
 
Level 3
 
 
Assets
 
 
 
 
 
 
 
 
 
Restricted deposits
$
27,941

 
$
—

 
$
—

 
$
—

 
$
27,941

Commodity derivative contracts
—

 
328,844

 
5,126

 
(31,531
)
 
302,439

Other assets
7,996

 
—

 
—

 
—

 
7,996

 
$
35,937

 
$
328,844

 
$
5,126

 
$
(31,531
)
 
$
338,376

Liabilities
 
 
 
 
 
 
 
 
 
Commodity derivative contracts
$
—

 
$
51,364

 
$
113

 
$
(31,531
)
 
$
19,946

Interest rate swap
—

 
6,849

 
—

 
—

 
6,849

 
$
—

 
$
58,213

 
$
113

 
$
(31,531
)
 
$
26,795


December 31, 2011
 
Fair Value Measurements
 
Netting(1)
 
Assets/Liabilities at Fair Value
 
Level 1
 
Level 2
 
Level 3
 
 
Assets
 
 
 
 
 
 
 
 
 
Restricted deposits
$
27,912

 
$
—

 
$
—

 
$
—

 
$
27,912

Commodity derivative contracts
—

 
62,746

 
397

 
(32,662
)
 
30,481

Other assets
7,138

 
—

 
—

 
—

 
7,138

 
$
35,050

 
$
62,746

 
$
397

 
$
(32,662
)
 
$
65,531

Liabilities
 
 
 
 
 
 
 
 
 
Commodity derivative contracts
$
—

 
$
182,694

 
$
4,650

 
$
(32,662
)
 
$
154,682

Interest rate swap
—

 
10,448

 
—

 
—

 
10,448

 
$
—

 
$
193,142

 
$
4,650

 
$
(32,662
)
 
$
165,130

____________________
(1)Represents the impact of netting assets and liabilities with counterparties with which the right of offset exists.

Fair values related to the Company’s oil and natural gas fixed price swaps, natural gas collars and interest rate swap were transferred from Level 3 to Level 2 in the fourth quarter of 2011 due to enhancements to the Company’s internal valuation process, including the use of observable inputs to assess the fair value. During the three and six-month periods ended June 30, 2012 and 2011, the Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements. The Company’s policy is to recognize transfers in and/or out of fair value hierarchy levels as of the end of the quarterly reporting period in which the event or change in circumstances causing the transfer occurred.


20
Table of Contents
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)


The tables below set forth a reconciliation of the Company’s financial assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the three and six-month periods ended June 30, 2012 and 2011 (in thousands): 
 
Three Months Ended June 30,
 
2012
 
2011
 
Commodity Derivative Contracts
 
Commodity Derivative Contracts
 
Interest Rate Swaps
 
Total
Balance of Level 3, March 31
$
(2,675
)
 
$
(478,541
)
 
$
(14,929
)
 
$
(493,470
)
Total gain or losses (realized/unrealized)
(1,643
)
 
169,988

 
(2,798
)
 
167,190

Purchases
5,697

 
—

 
—

 
—

Settlements
3,634

 
14,920

 
2,442

 
17,362

Balance of Level 3, June 30
$
5,013

 
$
(293,633
)
 
$
(15,285
)
 
$
(308,918
)
 
Six Months Ended June 30,
 
2012
 
2011
 
Commodity Derivative Contracts
 
Commodity Derivative Contracts
 
Interest Rate Swaps
 
Total
Balance of Level 3, December 31
$
(4,253
)
 
$
(205,860
)
 
$
(16,694
)
 
$
(222,554
)
Total gain or losses (realized/unrealized)
389

 
(107,640
)
 
(3,076
)
 
(110,716
)
Purchases
5,697

 
—

 
—

 
—

Settlements
3,180

 
19,867

 
4,485

 
24,352

Balance of Level 3, June 30
$
5,013

 
$
(293,633
)
 
$
(15,285
)
 
$
(308,918
)

Unrealized gains on the Company's Level 3 commodity derivative contracts of $2.1 million and $3.7 million for the three and six-month periods ended June 30, 2012, respectively, have been included in (gain) loss on derivative contracts in the accompanying unaudited condensed consolidated statements of operations.

See Note 9 for further discussion of the Company’s derivative contracts.

Fair Value of Debt

The Company measures the fair value of its senior notes using pricing for the Company's senior notes that is readily available in the public market. The Company classifies these inputs as Level 2 in the fair value hierarchy. The estimated fair values and carrying values of the Company’s senior notes at June 30, 2012 and December 31, 2011 were as follows (in thousands):
 
June 30, 2012
 
December 31, 2011
 
Fair Value
 
Carrying Value
 
Fair Value
 
Carrying Value
Senior Floating Rate Notes due 2014
$
346,833

 
$
350,000

 
$
339,381

 
$
350,000

9.875% Senior Notes due 2016(1)
400,223

 
355,591

 
396,568

 
354,579

8.0% Senior Notes due 2018
765,000

 
750,000

 
765,000

 
750,000

8.75% Senior Notes due 2020(2)
470,250

 
443,841

 
475,875

 
443,568

7.5% Senior Notes due 2021
893,250

 
900,000

 
909,000

 
900,000

8.125% Senior Notes due 2022
761,250

 
750,000

 
—

 
—

 ____________________
(1)Carrying value is net of $9,909 and $10,921 discount at June 30, 2012 and December 31, 2011, respectively.
(2)Carrying value is net of $6,159 and $6,432 discount at June 30, 2012 and December 31, 2011, respectively.


21
Table of Contents
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)


The carrying values of the Company’s senior credit facility and remaining fixed rate debt instruments approximate fair value based on current rates applicable to similar instruments. See Note 8 for discussion of the Company’s long-term debt.

5. Property, Plant and Equipment

Property, plant and equipment consists of the following (in thousands): 
 
June 30,
2012
 
December 31,
2011
Oil and natural gas properties
 
 
 
Proved
$
11,197,054

 
$
8,969,296

Unproved
948,369

 
689,393

Total oil and natural gas properties
12,145,423

 
9,658,689

Less accumulated depreciation, depletion and impairment
(5,011,661
)
 
(4,791,534
)
Net oil and natural gas properties capitalized costs
7,133,762

 
4,867,155

Land
15,723

 
14,196

Non-oil and natural gas equipment(1)
713,769

 
668,391

Buildings and structures
167,009

 
133,147

Total
896,501

 
815,734

Less accumulated depreciation and amortization
(301,251
)
 
(293,465
)
Other property, plant and equipment, net
595,250

 
522,269

Total property, plant and equipment, net
$
7,729,012

 
$
5,389,424

 ____________________
(1)
Includes cumulative capitalized interest of approximately $8.7 million and $6.7 million at June 30, 2012 and December 31, 2011, respectively.

There were no full cost ceiling impairments during the three or six-month periods ended June 30, 2012 or 2011. Cumulative full cost ceiling limitation impairment charges of $3,548.3 million at both June 30, 2012 and December 31, 2011 were included in accumulated depreciation, depletion and impairment for oil and natural gas properties in the table above.

6. Other Assets

Other assets consist of the following (in thousands):
 
June 30,
2012
 
December 31,
2011
Debt issuance costs, net of amortization
$
73,639

 
$
51,724

Notes receivable on asset retirement obligations
11,001

 
—

Investments
7,996

 
7,138

Production tax credit receivable
7,665

 
7,665

Lease broker advances
1,448

 
13,086

Development advance
—

 
16,777

Other
5,415

 
2,232

Total other assets
$
107,164

 
$
98,622


7. Construction Contracts

The Company accounts for its two construction contracts using the completed-contract method, under which contract revenues and costs are recognized when work under the contract is completed and assets have been transferred. In the interim, costs incurred on and billings related to contracts in process are accumulated on the balance sheet. Contract gains or losses will be recorded as development costs within the Company’s oil and natural gas properties as part of the full cost pool, when it is determined that a loss will be incurred. Contract gains, if any, are recorded at the end of the project.

22
Table of Contents
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)



Century Plant. The Company is constructing the Century Plant, a CO2 treatment plant in Pecos County, Texas (the “Century Plant”), and associated compression and pipeline facilities pursuant to an agreement with Occidental Petroleum Corporation (“Occidental”). Under the terms of the agreement, the Company is constructing the Century Plant and Occidental is paying the Company a minimum of 100% of the contract price, or $800.0 million, plus any subsequently agreed-upon revisions, through periodic cost reimbursements based upon the percentage of the project completed by the Company. The Company expects to complete the Century Plant in two phases. Upon completion of each phase of the Century Plant, Occidental will take ownership of the related assets and will operate the Century Plant for the purpose of separating and removing CO2 from delivered natural gas. Phase I is in the commissioning process with completion and transfer of title to Occidental expected in the third quarter of 2012, and Phase II is under construction and expected to be completed by the end of 2012. The Company has recorded additions of $140.0 million (including $10.0 million during the six-month period ended June 30, 2012) to its oil and natural gas properties for the estimated loss identified based on current projections of the costs to be incurred in excess of contract amounts. Billings and estimated contract loss in excess of costs incurred of $6.3 million and $43.3 million at June 30, 2012 and December 31, 2011, respectively, are reported as current liabilities in the accompanying unaudited condensed consolidated balance sheets.

Pursuant to a 30-year treating agreement executed simultaneously with the construction agreement, Occidental will remove CO2 from the Company’s delivered natural gas production volumes. Under this agreement, the Company will be required to deliver certain minimum CO2 volumes annually once Occidental takes title, and will have to compensate Occidental to the extent such requirements are not met. See Note 11 for additional discussion of this volume requirement. The Company will retain all methane gas from the natural gas it delivers to the Century Plant.

Transmission Expansion Projects. The Company entered into a construction services agreement in November 2011 to manage the design, engineering and construction of a series of transmission expansion and upgrade projects in northern Oklahoma. Under the terms of the agreement, the Company will be reimbursed for costs incurred on these projects up to approximately $22.0 million. Construction on these projects began in 2012 and is expected to be completed by the end of the year. Costs in excess of billings on these projects of $14.8 million at June 30, 2012 is reported as a current asset in the accompanying unaudited condensed consolidated balance sheets. There were no amounts related to these projects included in the accompanying unaudited condensed consolidated balance sheets at December 31, 2011.

8. Long-Term Debt

Long-term debt consists of the following (in thousands):

 
June 30,
2012
 
December 31,
2011
Senior Floating Rate Notes due 2014
$
350,000

 
$
350,000

Senior credit facility
—

 
—

9.875% Senior Notes due 2016, net of $9,909 and $10,921 discount, respectively
355,591

 
354,579

8.0% Senior Notes due 2018
750,000

 
750,000

8.75% Senior Notes due 2020, net of $6,159 and $6,432 discount, respectively
443,841

 
443,568

7.5% Senior Notes due 2021
900,000

 
900,000

8.125% Senior Notes due 2022
750,000

 
—

Mortgage
—

 
16,029

Total debt
3,549,432

 
2,814,176

Less: current maturities of long-term debt
—

 
1,051

Long-term debt
$
3,549,432

 
$
2,813,125


For the three and six-month periods ended June 30, 2012, interest payments, excluding amounts capitalized, were approximately $63.4 million and $120.6 million, respectively. Interest payments for the six-month period ended June 30, 2012 included $10.9 million of fees incurred to secure financing for the Dynamic Acquisition. For the three and six-month periods ended June 30, 2011, interest payments, excluding amounts capitalized, were approximately $56.3 million and $109.5 million, respectively. Interest payments for the three and six-months ended June 30, 2011 included $1.5 million and $25.7 million, respectively, of accrued interest paid in connection with the partial redemption of the 8.625% Senior Notes due 2015, discussed further below.

23
Table of Contents
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)



Senior Floating Rate Notes Due 2014. The Company’s Senior Floating Rate Notes due 2014 (the “Senior Floating Rate Notes”) were issued in May 2008. The Senior Floating Rate Notes are jointly and severally guaranteed unconditionally, in full, on an unsecured basis by certain of the Company’s wholly owned subsidiaries and are freely tradable. See Note 17 for condensed financial information of the subsidiary guarantors.

The Senior Floating Rate Notes bear interest at the London Interbank Offered Rate ("LIBOR") plus 3.625%. Interest is payable quarterly with the principal due on April 1, 2014. The average interest rate paid on the outstanding Senior Floating Rate Notes for the three-month periods ended June 30, 2012 and 2011 was 4.09% and 3.93%, respectively, without consideration of the interest rate swap discussed below. The average interest rate paid on the outstanding Senior Floating Rate Notes for the six-month periods ended June 30, 2012 and 2011 was 4.15% and 3.93%, respectively, without consideration of the interest rate swap discussed below. The Company may redeem, at specified redemption prices, some or all of the Senior Floating Rate Notes at any time.

The $9.4 million of debt issuance costs associated with the Senior Floating Rate Notes is included in other assets in the accompanying unaudited condensed consolidated balance sheets and is being amortized to interest expense over the term of the notes.

As of June 30, 2012, the Company had a $350.0 million notional interest rate swap agreement to effectively fix the variable interest rate on the Senior Floating Rate Notes to an annual rate of 6.69% through April 1, 2013. This swap has not been designated as a hedge.

Senior Credit Facility. The senior credit facility is available to be drawn on subject to limitations based on its terms and certain financial covenants, as described below. The senior credit facility matures on March 29, 2017, if the Company has repaid or refinanced the Senior Floating Rate Notes or the Company’s 9.875% Senior Notes due 2016 prior to September 30, 2015 with a source of funds other than the senior credit facility. If either series of notes is not repaid or refinanced prior to such date, the senior credit facility will mature on November 15, 2015.

On March 29, 2012, the senior credit facility was amended and restated to, among other things, (a) increase the borrowing base to $1.0 billion from $790.0 million, (b) allow for the incurrence or issuance of additional debt (including up to $750.0 million of unsecured debt to finance the cash portion of the Dynamic purchase price and related costs and expenses), (c) permit the Company to designate certain of its subsidiaries as unrestricted subsidiaries, and (d) effective on and after June 30, 2012, establish the financial covenants as maintaining agreed upon levels for (i) ratio of total funded debt to EBITDA, which may not exceed 4.5:1.0 at each quarter end, calculated using the last four completed fiscal quarters and (ii) ratio of current assets to current liabilities, which must be at least 1.0:1.0 at each quarter end. If no amounts are drawn under the senior credit facility when calculating the ratio of total funded debt to EBITDA, the Company’s debt is reduced by its cash balance in excess of $10.0 million. In the current ratio calculation, any amounts available to be drawn under the senior credit facility are included in current assets, and unrealized assets and liabilities resulting from mark-to-market adjustments on the Company’s derivative contracts are disregarded.

Additionally, the senior credit facility contains various covenants that limit the ability of the Company and certain of its subsidiaries 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 ability of the Company and certain of its subsidiaries to incur additional indebtedness with certain exceptions. As of and during the three and six-month periods ended June 30, 2012, the Company was in compliance with all applicable financial covenants under the senior credit facility.

The obligations under the senior credit facility are guaranteed by certain Company subsidiaries and are secured by first priority liens on all shares of capital stock of certain of the Company’s material present and future subsidiaries; certain intercompany debt of the Company; and substantially all of the Company’s assets, including proved oil and natural gas reserves representing at least 80.0% of the discounted present value (as defined in the senior credit facility) of proved oil and natural gas reserves considered by the lenders in determining the borrowing base for the senior credit facility.

At the Company’s election, interest under the senior credit facility is determined by reference to (a) LIBOR plus an applicable margin between 1.75% and 2.75% per annum or (b) the “base rate,” which is the highest of (i) the federal funds rate plus 0.5%, (ii) the prime rate published by Bank of America or (iii) the Eurodollar rate (as defined in the senior credit facility) plus 1.00% per annum, plus, in each case under scenario (b), an applicable margin between 0.75% and 1.75% per annum. Interest

24
Table of Contents
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)


is payable quarterly for base rate loans and at the applicable maturity date for LIBOR loans, except that if the interest period for a LIBOR loan is six months, interest is paid at the end of each three-month period. The Company made no interest payments during the three and six-month periods ended June 30, 2012 as there were no amounts outstanding under the senior credit facility during the period. The average annual interest rate paid on amounts outstanding under the senior credit facility was 2.51% and 2.70%, respectively, for the three and six-month periods ended June 30, 2011.

Borrowings under the senior credit facility may not exceed the lower of the borrowing base or the committed amount. The Company’s borrowing base is redetermined in April and October of each year. The next borrowing base redetermination will be in October 2012. With respect to each redetermination, the administrative agent and the lenders under the senior credit facility consider several factors, including the Company’s proved reserves and projected cash requirements, and make assumptions regarding, among other things, oil and natural gas prices and production. Because the value of the Company’s proved reserves is a key factor in determining the amount of the borrowing base, changing commodity prices and the Company’s success in developing reserves may affect the borrowing base. The Company at times incurs additional costs related to the senior credit facility as a result of amendments to the credit agreement and changes to the borrowing base. During the six-month period ended June 30, 2012, additional costs of approximately $7.4 million were incurred. These costs have been deferred, and are included in other assets in the accompanying unaudited condensed consolidated balance sheets and are being amortized to interest expense over the term of the senior credit facility.

At June 30, 2012, the Company had no amount outstanding under the senior credit facility and $29.5 million in outstanding letters of credit. Letters of credit, excluding a $1.5 million Dynamic letter of credit, reduce the availability under the senior credit facility on a dollar-for-dollar basis.

8.625% Senior Notes Due 2015. The Company’s 8.625% Senior Notes due 2015 (the “8.625% Senior Notes”) were issued in May 2008. In March 2011, the Company purchased approximately 94.5%, or $614.2 million, of the aggregate principal amount of its 8.625% Senior Notes pursuant to a tender offer, which expired on March 28, 2011. On April 1, 2011, the Company redeemed the remaining outstanding $35.8 million aggregate principal amount of its 8.625% Senior Notes. All holders whose notes were purchased or redeemed received accrued and unpaid interest from October 1, 2010. The premium paid to purchase these notes and the unamortized debt issuance costs associated with the notes, totaling $2.0 million and $38.2 million, respectively, were recorded as a loss on extinguishment of debt in the accompanying unaudited condensed consolidated statements of operations for the three and six-month periods ended June 30, 2011, respectively.

9.875% Senior Notes Due 2016. The Company’s unsecured 9.875% Senior Notes due 2016 (the “9.875% Senior Notes”) were issued in May 2009 and bear interest at a fixed rate of 9.875% per annum, payable semi-annually, with the principal due on May 15, 2016. The 9.875% Senior Notes were issued at a discount, which is amortized to interest expense over the term of the notes. The 9.875% Senior Notes are redeemable, in whole or in part, prior to their maturity at specified redemption prices and are jointly and severally guaranteed unconditionally, in full, on an unsecured basis by certain of the Company’s wholly owned subsidiaries and are freely tradable.

Debt issuance costs of $7.9 million incurred in connection with the offering of the 9.875% Senior Notes are included in other assets in the accompanying unaudited condensed consolidated balance sheets and are being amortized to interest expense over the term of the notes.

8.0% Senior Notes Due 2018. The Company’s unsecured 8.0% Senior Notes due 2018 (the “8.0% Senior Notes”) were issued in May 2008 and bear interest at a fixed rate of 8.0% per annum, payable semi-annually, with the principal due on June 1, 2018. The notes are redeemable, in whole or in part, prior to their maturity at specified redemption prices and are jointly and severally guaranteed unconditionally, in full, on an unsecured basis by certain of the Company’s wholly owned subsidiaries and are freely tradable.

The Company incurred $16.0 million of debt issuance costs in connection with the offering of the 8.0% Senior Notes. These costs are included in other assets in the accompanying unaudited condensed consolidated balance sheets and are being amortized to interest expense over the term of the notes.

8.75% Senior Notes Due 2020. The Company’s unsecured 8.75% Senior Notes due 2020 (the “8.75% Senior Notes”) were issued in December 2009 and bear interest at a fixed rate of 8.75% per annum, payable semi-annually, with the principal due on January 15, 2020. The 8.75% Senior Notes were issued at a discount, which is being amortized to interest expense over the term of the notes. The 8.75% Senior Notes are redeemable, in whole or in part, prior to their maturity at specified redemption

25
Table of Contents
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)


prices and are jointly and severally guaranteed unconditionally, in full, on an unsecured basis by certain of the Company’s wholly owned subsidiaries and are freely tradable. See Note 17 for condensed financial information of the subsidiary guarantors.

Debt issuance costs of $9.7 million incurred in connection with the offering and subsequent registered exchange of the 8.75% Senior Notes are included in other assets in the accompanying unaudited condensed consolidated balance sheets and are being amortized to interest expense over the term of the notes.

7.5% Senior Notes Due 2021. In March 2011, the Company issued $900.0 million of unsecured 7.5% Senior Notes due 2021 (the “7.5% Senior Notes”) to qualified institutional buyers eligible under Rule 144A of the Securities Act and to persons outside the United States under Regulation S under the Securities Act. Net proceeds from the offering were used to fund the tender offer for the 8.625% Senior Notes, including any accrued and unpaid interest, the redemption of the 8.625% Senior Notes that remained outstanding following the conclusion of the tender offer, including accrued and unpaid interest (each as described above) and to repay borrowings under the Company’s senior credit facility. The 7.5% Senior Notes bear interest at a fixed rate of 7.5% per annum, payable semi-annually, with the principal due on March 15, 2021. Prior to March 15, 2016, the 7.5% Senior Notes are redeemable, in whole or in part, at a specified redemption price plus accrued and unpaid interest. On or after March 15, 2016, the 7.5% Senior Notes are redeemable, in whole or in part, prior to their maturity at other various specified redemption prices. The notes are jointly and severally guaranteed unconditionally, in full, on an unsecured basis by certain of the Company’s wholly owned subsidiaries. See Note 17 for condensed financial information of the subsidiary guarantors.

In November 2011, pursuant to an exchange offer, the Company replaced a substantial majority of the 7.5% Senior Notes with 7.5% Senior Notes registered under the Securities Act. The exchange offer did not result in the incurrence of any additional indebtedness.

Debt issuance costs of $19.4 million incurred in connection with the offering and subsequent exchange of the 7.5% Senior Notes are included in other assets in the accompanying unaudited condensed consolidated balance sheets and are being amortized to interest expense over the term of the notes.

8.125% Senior Notes Due 2022. In April 2012, the Company issued $750.0 million of unsecured 8.125% Senior Notes to qualified institutional buyers eligible under Rule 144A of the Securities Act and to persons outside the United States under Regulation S under the Securities Act. Net proceeds from the offering were approximately $730.1 million after deducting offering expenses, and were used to finance the cash portion of the Dynamic Acquisition purchase price and to pay related fees and expenses, with any remaining amount being used for general corporate purposes. The 8.125% Senior Notes bear interest at a fixed rate of 8.125% per annum, payable semi-annually, with the principal due on October 15, 2022. Prior to 2017, the 8.125% Senior Notes are redeemable, in whole or in part, at a specified redemption price plus accrued and unpaid interest. The notes are jointly and severally guaranteed unconditionally, in full, on an unsecured basis by certain of the Company's wholly owned subsidiaries.

In conjunction with the issuance of the 8.125% Senior Notes, the Company entered into a registration rights agreement requiring the Company to commence a registered exchange offer for these notes no later than April 17, 2013. Under certain circumstances, in lieu of a registered exchange offer, the Company may be required to file a shelf registration statement relating to the resale of the 8.125% Senior Notes and to use its commercially reasonable best efforts to keep such registration statement effective until two years after its effective date (or such shorter period that will terminate when all of the 8.125% Senior Notes covered thereby have been resold pursuant thereto or in certain other circumstances). The Company would be required to pay additional interest as liquidated damages of 0.25%, increasing 0.25% each 90 days to a maximum of 0.50% if it fails to fulfill its obligations under the agreement within the specified time periods.

The Company incurred $19.9 million of debt issuance costs in connection with the offering of the 8.125% Senior Notes. These costs are included in other assets in the accompanying unaudited condensed consolidated balance sheets and are being amortized to interest expense over the term of the notes.

Indentures. The indentures governing the Company’s senior notes contain covenants which restrict the Company's ability to take a variety of actions, including limitations on the incurrence of indebtedness, payment of dividends, investments, asset sales, certain asset purchases, transactions with related parties and consolidations or mergers. As of and during the three and six-month periods ended June 30, 2012, the Company was in compliance with all of the covenants contained in the indentures governing its senior notes.


26
Table of Contents
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)


Other Notes Payable. The debt incurred to purchase the downtown Oklahoma City property that serves as the Company’s corporate headquarters was fully secured by a mortgage on one of the buildings located on the property. In May 2012, the Company paid the outstanding $15.8 million principal balance on the note underlying the mortgage.

9. Derivatives

The Company has not designated any of its derivative contracts as hedges for accounting purposes. The Company records all derivative contracts, which include commodity derivatives and an interest rate swap, at fair value. Changes in derivative contract fair values are recognized in earnings. Cash settlements and valuation gains and losses are included in (gain) loss on derivative contracts for commodity derivative contracts and in interest expense for interest rate swaps in the consolidated statements of operations. Commodity derivative contracts are settled on a monthly or quarterly basis. Settlements on interest rate swaps occur quarterly. Derivative assets and liabilities arising from the Company’s derivative contracts with the same counterparty that provide for net settlement are reported on a net basis in the consolidated balance sheets.

Commodity Derivatives. The Company is exposed to commodity price risk, which impacts the predictability of its cash flows from the sale of oil and natural gas. The Company seeks to manage this risk through the use of commodity derivative contracts. These derivative contracts allow the Company to limit its exposure to commodity price volatility on a portion of its forecasted oil and natural gas sales. Additionally, the Company uses derivative contracts to manage commodity price risk associated with diesel fuel used in its operations. None of the Company’s derivative contracts may be terminated early solely as a result of a downgrade in the credit rating of a party to the contract. At June 30, 2012, the Company’s commodity derivative contracts consisted of fixed price swaps, collars and basis swaps, which are described below:
Fixed price swaps
The Company receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.
 
 
Collars
Collars contain a fixed floor price (put) and a fixed ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, the Company receives the fixed price and pays the market price. If the market price is between the call and the put strike price, no payments are due from either party.
 
 
Basis swaps
The Company receives a payment from the counterparty if the settled price differential is greater than the stated terms of the contract and pays the counterparty if the settled price differential is less than the stated terms of the contract, which guarantees the Company a price differential for oil and natural gas from a specified delivery point.
Interest Rate Swaps. The Company is exposed to interest rate risk on its long-term fixed and variable interest rate borrowings. Fixed rate debt, where the interest rate is fixed over the life of the instrument, exposes the Company to (i) changes in market interest rates reflected in the fair value of the debt and (ii) the risk that the Company may need to refinance maturing debt with new debt at a higher rate. Variable rate debt, where the interest rate fluctuates, exposes the Company to short-term changes in market interest rates as the Company’s interest obligations on these instruments are periodically redetermined based on prevailing market interest rates, primarily LIBOR and the federal funds rate.

The Company has an interest rate swap agreement that effectively converts the variable interest rate on its Senior Floating Rate Notes to a fixed rate through April 1, 2013. See Note 8 for further discussion of the Company’s interest rate swap.

Derivatives Agreements with Royalty Trusts. Effective April 1, 2011, the Company entered into a derivatives agreement with the Mississippian Trust I. The agreement provides the Mississippian Trust I with the economic effect of certain oil and natural gas derivative contracts previously entered into by the Company with third parties. The underlying commodity derivative contracts cover volumes of oil and natural gas production through December 31, 2015. Under this arrangement, the Company will pay the Mississippian Trust I amounts it receives from its counterparties in accordance with the underlying contracts, and the Mississippian Trust I will pay the Company any amounts that the Company is required to pay its counterparties under such contracts.

Effective August 1, 2011, the Company entered into a derivatives agreement with the Permian Trust. The agreement provides the Permian Trust with the economic effect of certain oil derivative contracts previously entered into by the Company with third parties. The underlying commodity derivative contracts cover volumes of oil production through March 31, 2015. Under this arrangement, the Company will pay the Permian Trust amounts it receives from its counterparty in accordance with the underlying contracts, and the Permian Trust will pay the Company any amounts that the Company is required to pay its counterparty

27
Table of Contents
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)


under such contracts. Substantially concurrent with the execution of the derivatives agreement, the Company novated certain of the derivatives contracts underlying the derivatives agreement to the Permian Trust. As a party to these contracts, the Permian Trust will receive payment directly from the counterparty and pay any amounts owed directly to the counterparty. To secure the Permian Trust’s obligations under these novated contracts, the Permian Trust has given the counterparty a lien on its royalty interests. Under the derivatives agreement, as development wells are drilled for the benefit of the Permian Trust, the Company will have the right, under certain circumstances, to assign or novate to the Permian Trust additional derivative contracts. In April 2012, the Company novated to the Permian Trust certain additional derivative contracts underlying the derivatives agreement with the Permian Trust.

Effective April 1, 2012, the Company entered into a derivatives agreement with the Mississippian Trust II. The agreement provides the Mississippian Trust II with the economic effect of certain oil derivative contracts previously entered into by the Company with third parties. The underlying commodity derivative contracts cover volumes of oil production through December 31, 2014. Under this arrangement, the Company will pay the Mississippian Trust II amounts it receives from its counterparties in accordance with the underlying contracts, and the Mississippian Trust II will pay the Company any amounts that the Company is required to pay its counterparties under such contracts. Substantially concurrent with the execution of the derivatives agreement, the Company novated certain of the derivatives contracts underlying the derivatives agreement to the Mississippian Trust II. As a party to these contracts, the Mississippian Trust II will receive payment directly from the counterparty and pay any amounts owed directly to the counterparty. To secure the Mississippian Trust II’s obligations under these novated contracts, the Mississippian Trust II has given the counterparties a lien on its royalty interests. Under the derivatives agreement, as development wells are drilled for the benefit of the Mississippian Trust II, the Company will have the right, under certain circumstances, to assign or novate to the Mississippian Trust II additional derivative contracts.

All contracts underlying the derivatives agreements with the Royalty Trusts, including those novated to the Permian Trust and Mississippian Trust II, have been included in the Company’s consolidated derivative disclosures. See Note 3 for additional discussion of the Royalty Trusts.

Fair Value of Derivatives. The following table presents the fair value of the Company’s derivative contracts as of June 30, 2012 and December 31, 2011 on a gross basis without regard to same-counterparty netting (in thousands):
Type of Contract
Balance Sheet Classification
June 30,
2012
 
December 31,
2011
Derivative assets
 
 
 
 
Oil price swaps
Derivative contracts-current
$
191,637

 
$
6,095

Natural gas price swaps
Derivative contracts-current
4,248

 
6,585

Oil basis swaps
Derivative contracts-current
5,126

 
—

Oil collars
Derivative contracts-current
626

 
—

Natural gas collars
Derivative contracts-current
7,020

 
313

Diesel price swaps
Derivative contracts-current
—

 
397

Oil price swaps
Derivative contracts-noncurrent
122,165

 
48,718

Oil collars
Derivative contracts-noncurrent
178

 
—

Natural gas collars
Derivative contracts-noncurrent
2,970

 
1,035

Derivative liabilities
 
 
 
 
Oil price swaps
Derivative contracts-current
(777
)
 
(116,243
)
Natural gas price swaps
Derivative contracts-current
(3,677
)
 
—

Diesel price swaps
Derivative contracts-current
(113
)
 
(41
)
Interest rate swap
Derivative contracts-current
(6,849
)
 
(8,475
)
Oil price swaps
Derivative contracts-noncurrent
(46,910
)
 
(66,451
)
Natural gas basis swaps
Derivative contracts-noncurrent
—

 
(4,609
)
Interest rate swap
Derivative contracts-noncurrent
—

 
(1,973
)
Total net derivative contracts
 
$
275,644

 
$
(134,649
)

Refer to Note 4 for additional discussion of the fair value measurement of the Company’s derivative contracts.

28
Table of Contents
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)



The following table summarizes the effect of the Company’s derivative contracts on the accompanying unaudited condensed consolidated statements of operations for the three and six-month periods ended June 30, 2012 and 2011 (in thousands): 
Type of Contract
Location of (Gain) Loss Recognized in Income
Three Months Ended June 30,
 
Six Months Ended June 30,
2012
 
2011
 
2012
 
2011
Commodity derivatives
(Gain) loss on derivative contracts
$
(669,850
)
 
$
(169,988
)
 
$
(415,204
)
 
$
107,640

Interest rate swap
Interest expense
49

 
2,798

 
895

 
3,076

Total
 
$
(669,801
)
 
$
(167,190
)
 
$
(414,309
)
 
$
110,716


The following tables summarize the cash settlements and valuation gains and losses on the Company’s commodity derivative contracts and interest rate swaps for the three and six-month periods ended June 30, 2012 and 2011 (in thousands):
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
Commodity Derivatives
 
 
 
 
 
 
 
Realized (gain) loss(1)
$
(89,120
)
 
$
18,273

 
$
36,336

 
$
26,881

Unrealized (gain) loss
(580,730
)
 
(188,261
)
 
(451,540
)
 
80,759

(Gain) loss on commodity derivative contracts
$
(669,850
)
 
$
(169,988
)
 
$
(415,204
)
 
$
107,640

Interest Rate Swap
 
 
 
 
 
 
 
Realized loss
$
2,294

 
$
2,442

 
$
4,494

 
$
4,485

Unrealized (gain) loss
(2,245
)
 
356

 
(3,599
)
 
(1,409
)
Loss on interest rate swap
$
49

 
$
2,798

 
$
895

 
$
3,076

____________________
(1)
The three and six-month periods ended June 30, 2012 included $57.3 million of realized gains related to settlements of commodity derivative contracts with contractual maturities after the quarterly period in which they were settled ("early settlements"). The six-month period ended June 30, 2012 also included $117.1 million non-cash realized losses on derivative contracts amended in January 2012. The three and six-month periods ended June 30, 2011 included $25.8 million and $38.2 million, respectively, of realized gains from early settlements.

At June 30, 2012, the Company’s open commodity derivative contracts consisted of the following:

Oil Price Swaps 
 
Notional (MBbl)
 
Weighted Avg. Fixed Price
July 2012 — December 2012
8,253

 
$
100.59

January 2013 — December 2013
17,420

 
$
96.40

January 2014 — December 2014
6,781

 
$
92.15

January 2015 — December 2015
5,076

 
$
83.69


Oil Basis Swaps
 
Notional (MBbl)
 
Weighted Avg. Fixed Price
July 2012 — December 2012
745

 
$
17.49



29
Table of Contents
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)


Oil Collars
 
Notional (MBbl)
 
Collar Range
July 2012 — December 2012
108

 
$85.00 - $114.00
January 2013 — December 2013
168

 
$80.00 - $102.50

Natural Gas Price Swaps
 
Notional (MMBtu)
 
Weighted Avg. Fixed Price
July 2012 — December 2012
42,897

 
$
2.98


Natural Gas Collars
 
Notional (MMBtu)
 
Collar Range
July 2012 — December 2012
4,432

 
$4.06 - $6.58
January 2013 — December 2013
6,858

 
$3.78 - $6.71
January 2014 — December 2014
937

 
$4.00 - $7.78
January 2015 — December 2015
1,010

 
$4.00 - $8.55

Diesel Price Swaps
 
Notional (Thousands of Gallons)
 
Weighted Avg. Fixed Price
July 2012 — December 2012
3,024

 
$
2.82


10. Asset Retirement Obligation

A reconciliation of the beginning and ending aggregate carrying amounts of the asset retirement obligation for the period from December 31, 2011 to June 30, 2012 is as follows (in thousands):

Asset retirement obligation, December 31, 2011
$
128,116

Liability incurred upon acquiring and drilling wells
3,232

     Liability assumed in acquisitions(1)
371,365

Revisions in estimated cash flows
1,308

Liability settled or disposed in current period
(24,612
)
Accretion of discount expense
10,572

Asset retirement obligation, June 30, 2012
489,981

Less: current portion
140,789

Asset retirement obligation, net of current
$
349,192

____________________
(1)
Includes amounts assumed in the Dynamic Acquisition in April 2012 and in the acquisition of Gulf of Mexico properties in June 2012.

11. Commitments and Contingencies

Legal Proceedings

On or about June 27, 2008 and November 6, 2008, there were fires at the Company’s Grey Ranch Plant and a nearby compressor station. The Company, as owner of the Plant and compressor station, recovered approximately $24.5 million from its

30
Table of Contents
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)


insurance carriers for damages caused by the fires. At the time of the Plant fire, the Plant was operated by Southern Union Gas Services, Ltd. (“Southern Union Gas”). On June 4, 2010, November 10, 2010, and March 15, 2011, the Company’s insurance carriers filed lawsuits against Southern Union Gas and its parent, Southern Union Company (together with Southern Union Gas, “Southern Union”) seeking recovery for amounts paid under the Company’s insurance policies. Southern Union, in turn, has tendered indemnity requests to GRLP, of which the Company is a 50% owner. GRLP has not accepted or acknowledged any responsibility to indemnify Southern Union. To the extent the Company, as a 50% owner of GRLP, is required to fund any indemnification of Southern Union, it will pursue coverage for such liability under its general liability insurance policy. An estimate of reasonably possible losses associated with these claims is approximately $12.3 million. As the loss is not probable, the Company has not established any reserves relating to these claims.

On February 14, 2011, Aspen Pipeline, II, L.P. (“Aspen”) filed a complaint in the District Court of Harris County, Texas, against Arena Resources, Inc. ("Arena") and SandRidge Energy, Inc. claiming damages based upon alleged representations by Arena in connection with Aspen’s construction of a natural gas pipeline in west Texas. On October 14, 2011, the complaint was amended to add Odessa Fuels, LLC, Odessa Fuels Marketing, LLC and Odessa Field Services and Compression, LLC as plaintiffs. The plaintiffs’ amended claims seek damages relating to the construction of the pipeline and performance under a related gas purchase agreement, which damages are alleged to approach $100.0 million. The Company intends to defend this lawsuit vigorously. This case is in the discovery stage and, accordingly, an estimate of reasonably possible losses associated with this claim, if any, cannot be made until the facts, circumstances and legal theories relating to the plaintiffs’ claims and the Company’s defenses are fully disclosed and analyzed. The Company has not established any reserves relating to this claim.

On April 5, 2011, Wesley West Minerals, Ltd. and Longfellow Ranch Partners, LP filed suit against SandRidge Energy, Inc. and SandRidge Exploration and Production, LLC (collectively, the “SandRidge Entities”) in the 83rd District Court of Pecos County, Texas. The plaintiffs, who have leased mineral rights to the SandRidge Entities in Pecos County, allege that the SandRidge Entities have not properly paid royalties on all volumes of natural gas (including carbon dioxide, or “CO2”) produced from the acreage leased from the plaintiffs. The plaintiffs also allege that the SandRidge Entities have inappropriately failed to pay royalties on CO2 produced from the plaintiffs’ acreage that results from the treatment of natural gas at the Century Plant. The plaintiffs seek unspecified actual damages, punitive damages and a declaration that the SandRidge Entities must pay royalties on CO2 produced from plaintiffs’ acreage that results from treatment of natural gas at the Century Plant. The Commissioner of the General Land Office of the State of Texas (“GLO”) is named as an additional defendant in the lawsuit as some of the affected oil and natural gas leases described in the plaintiffs’ allegations cover mineral classified lands in which the GLO is entitled to one-half of the royalties attributable to such leases. The GLO has filed a cross-claim against the SandRidge Entities asserting the same claims as the plaintiffs with respect to the leases covering mineral classified lands. The Company intends to defend this lawsuit vigorously. This case is in the discovery stage and, accordingly, an estimate of reasonably possible losses associated with these claims, if any, cannot be made until the facts, circumstances and legal theories relating to the plaintiffs’ claims and the Company’s defenses are fully disclosed and analyzed. The Company has not established any reserves relating to these claims.

On August 4, 2011, Patriot Exploration, LLC, Jonathan Feldman, Redwing Drilling Partners, Mapleleaf Drilling Partners, Avalanche Drilling Partners, Penguin Drilling Partners and Gramax Insurance Company Ltd. filed a lawsuit against SandRidge Energy, Inc., SandRidge Exploration and Production, LLC (“SandRidge E&P”) and certain directors and senior executive officers of SandRidge Energy, Inc. (collectively, the “defendants”) in the U.S. District Court for the District of Connecticut. The plaintiffs allege that the defendants made false and misleading statements to U.S. Drilling Capital Management LLC and the plaintiffs prior to the entry into a participation agreement among Patriot Exploration, LLC, U.S. Drilling Capital Management LLC and SandRidge E&P, which provided for the investment by the plaintiffs in certain of SandRidge E&P’s oil and natural gas properties. To date, the plaintiffs have invested approximately $15.0 million under the participation agreement. The plaintiffs seek compensatory and punitive damages and rescission of the participation agreement. The Company intends to defend this lawsuit vigorously and believes the plaintiffs’ claims are without merit. This case is in the early stages and, accordingly, an estimate of reasonably possible losses associated with this claim, if any, cannot be made until the facts, circumstances and legal theories relating to the plaintiffs’ claims and the Company’s defenses are fully disclosed and analyzed. The Company has not established any reserves relating to this claim.

In addition, the Company is a defendant in lawsuits from time to time in the normal course of business. While the results of litigation and claims cannot be predicted with certainty, the Company believes the reasonably possible losses of such matters, individually and in the aggregate, are not material. Additionally, the Company believes the probable final outcome of such matters will not have a material adverse effect on the Company’s consolidated results of operations, financial position, cash flows or liquidity.


31
Table of Contents
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)


Treating Agreement Commitment

In conjunction with the Century Plant construction agreement, the Company entered into a 30-year treating agreement with Occidental for CO2 to be removed from the Company’s delivered production volumes. The Company is required to deliver a total of approximately 3,200 Bcf of CO2 volumes during the agreement period. If the Company does not meet the CO2 volume requirements, the Company will have to pay a fee for any volume shortfalls. Based upon current natural gas production levels, the Company expects to incur between approximately $11.5 million and $14.5 million at December 31, 2012 for amounts related to the Company’s shortfall in meeting its annual delivery obligations based on the projected completion date of Phase I. Due to the sensitivity of natural gas production to prevailing market prices, the Company is unable to estimate additional amounts it may be required to pay under this agreement in subsequent periods.
  
12. Equity

Preferred Stock. The following table presents information regarding the Company’s preferred stock (in thousands):
 
June 30,
2012
 
December 31,
2011
Shares authorized
50,000

 
50,000

Shares outstanding at end of period
 
 
 
8.5% Convertible perpetual preferred stock
2,650

 
2,650

6.0% Convertible perpetual preferred stock
2,000

 
2,000

7.0% Convertible perpetual preferred stock
3,000

 
3,000


The Company is authorized to issue 50,000,000 shares of preferred stock, $0.001 par value, of which 7,650,000 shares are designated as convertible perpetual preferred stock at June 30, 2012. All of the outstanding shares of the Company’s convertible perpetual preferred stock were issued in private transactions and none of these shares is listed on a stock exchange. However, all of the outstanding shares of convertible perpetual preferred stock are freely tradable.

8.5% Convertible perpetual preferred stock. The Company’s 8.5% convertible perpetual preferred stock was issued in January 2009. Each share of 8.5% convertible perpetual preferred stock has a liquidation preference of $100.00 and is convertible at the holder’s option at any time initially into approximately 12.4805 shares of the Company’s common stock, subject to customary adjustments in certain circumstances. Each holder of the convertible perpetual preferred stock is entitled to an annual dividend of $8.50 per share to be paid semi-annually in cash, common stock or a combination thereof, at the Company’s election. The 8.5% convertible perpetual preferred stock is not redeemable by the Company at any time. After February 20, 2014, the Company may cause all outstanding shares of the convertible perpetual preferred stock to convert automatically into common stock at the then-prevailing conversion rate if certain conditions are met.

6.0% Convertible perpetual preferred stock. The Company’s 6.0% convertible perpetual preferred stock was issued in December 2009. Each share of the 6.0% convertible perpetual preferred stock has a liquidation preference of $100.00 and is entitled to an annual dividend of $6.00 payable semi-annually in cash, common stock or any combination thereof, at the Company’s election. The 6.0% convertible perpetual preferred stock is not redeemable by the Company at any time. Each share is initially convertible into approximately 9.2115 shares of the Company’s common stock, at the holder’s option, subject to customary adjustments in certain circumstances. On December 21, 2014, all outstanding shares of the 6.0% convertible preferred stock will be converted automatically into shares of the Company’s common stock at the then-prevailing conversion price as long as all dividends accrued at that time have been paid.

7.0% Convertible perpetual preferred stock. The Company’s 7.0% convertible perpetual preferred stock was issued in November 2010. Each share of the 7.0% convertible preferred stock has a liquidation preference of $100.00 per share and became convertible at the holder’s option on February 15, 2011, initially into approximately 12.8791 shares of the Company’s common stock, subject to customary adjustments in certain circumstances. The annual dividend on each share of the 7.0% convertible preferred stock is $7.00 payable semi-annually, in cash, common stock or a combination thereof, at the Company’s election. The 7.0% convertible perpetual preferred stock is not redeemable by the Company at any time. After November 20, 2015, the Company may cause all outstanding shares of the 7.0% convertible perpetual preferred stock to convert automatically into common stock at the then-prevailing conversion rate if certain conditions are met.


32
Table of Contents
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)


Preferred stock dividends. All dividend payments to date on the Company's 8.5%, 6.0% and 7.0% convertible perpetual preferred stock have been paid in cash. Paid and unpaid dividends included in the calculation of income available (loss applicable) to the Company’s common stockholders and the Company’s basic earnings per share calculation for the three and six-month periods ended June 30, 2012 and 2011 as presented in the accompanying unaudited condensed consolidated statements of operations, are included in tables below (in thousands):
 
Three Months Ended June 30,
 
2012
 
2011
 
Dividends Paid
 
Dividends Unpaid
 
Total
 
Dividends Paid
 
Dividends Unpaid
 
Total
8.5% Convertible Perpetual Preferred Stock
$
—

 
$
5,631

 
$
5,631

 
$
—

 
$
5,631

 
$
5,631

6.0% Convertible Perpetual Preferred Stock
—

 
3,000

 
3,000

 
—

 
3,000

 
3,000

7.0% Convertible Perpetual Preferred Stock
2,625

 
2,625

 
5,250

 
2,625

 
2,625

 
5,250

  Total
$
2,625

 
$
11,256

 
$
13,881

 
$
2,625

 
$
11,256

 
$
13,881

 
Six Months Ended June 30,
 
2012
 
2011
 
Dividends Paid
 
Dividends Unpaid
 
Total
 
Dividends Paid
 
Dividends Unpaid
 
Total
8.5% Convertible Perpetual Preferred Stock
$
2,816

 
$
8,447

 
$
11,263

 
$
2,816

 
$
8,447

 
$
11,263

6.0% Convertible Perpetual Preferred Stock
500

 
5,500

 
6,000

 
500

 
5,500

 
6,000

7.0% Convertible Perpetual Preferred Stock
7,875

 
2,625

 
10,500

 
7,933

 
2,625

 
10,558

  Total
$
11,191

 
$
16,572

 
$
27,763

 
$
11,249

 
$
16,572

 
$
27,821


Common Stock. The following table presents information regarding the Company’s common stock (in thousands): 
 
June 30,
2012
 
December 31,
2011
Shares authorized
800,000

 
800,000

Shares outstanding at end of period
489,191

 
411,953

Shares held in treasury
970

 
874


On April 17, 2012, the Company issued approximately 74 million shares of SandRidge common stock to satisfy the stock portion of the consideration paid in the Dynamic Acquisition. See Note 2 for further discussion of the Dynamic Acquisition.
    
Treasury Stock. The Company makes required statutory tax payments on behalf of employees when their restricted stock awards vest and then withholds a number of vested shares of common stock having a value on the date of vesting equal to the tax obligation. As a result of such transactions, the Company withheld approximately 825,000 shares having a total value of $6.7 million and approximately 617,000 shares having a total value of $5.0 million during the six-month periods ended June 30, 2012 and 2011, respectively. These shares were accounted for as treasury stock when withheld, and subsequently retired.

Shares of Company common stock held as assets in a trust for the Company’s non-qualified deferred compensation plan are accounted for as treasury shares. These shares are not included as outstanding shares of common stock in this report. For corporate purposes, including for the purpose of voting at Company stockholder meetings, these shares are considered outstanding and have voting rights, which are exercised by the Company.

Equity Compensation. The Company awards restricted common stock under incentive compensation plans that vest over specified periods of time, subject to certain conditions and are valued based upon the market value of common stock on the date of grant. Awards issued prior to 2006 had vesting periods of one, four or seven years. Awards issued during and after 2006 generally have four-year vesting periods. Shares of restricted common stock are subject to restriction on transfer. Unvested restricted stock awards are included in the Company’s outstanding shares of common stock.


33
Table of Contents
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)


Equity compensation provided to employees directly involved in oil and natural gas exploration and development activities is capitalized to the Company’s oil and natural gas properties. Equity compensation not capitalized is reflected in general and administrative expenses, production expenses, midstream and marketing expenses and drilling and services expenses in the consolidated statements of operations. For the three and six-month periods ended June 30, 2012, the Company recognized equity compensation expense of $11.1 million and $21.6 million, net of $2.1 million and $4.0 million capitalized, respectively, related to restricted common stock. For the three and six-month periods ended June 30, 2011, the Company recognized equity compensation expense of $8.9 million and $17.1 million, net of $1.9 million and $3.7 million capitalized, respectively, related to restricted common stock.

Noncontrolling Interest. Noncontrolling interests in the Company’s subsidiaries and VIEs of which the Company was the primary beneficiary as of and for the three and six-month periods ended June 30, 2012 (see Note 3), represent third-party ownership interests in the consolidated entity and are included as a component of equity in the accompanying unaudited condensed consolidated balance sheets and accompanying unaudited condensed consolidated statements of changes in equity.


13. Income Taxes

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 for income taxes on a current year-to-date basis. The (benefit) provision for income taxes consisted of the following components for the three and six-month periods ended June 30, 2012 and 2011 (in thousands):
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
Current
 
 
 
 
 
 
 
Federal
$
11

 
$
(137
)
 
$
(72
)
 
$
(116
)
State
(341
)
 
69

 
(187
)
 
135

 
(330
)
 
(68
)
 
(259
)
 
19

Deferred
 
 
 
 
 
 
 
Federal
(100,385
)
 
(6,385
)
 
(100,385
)
 
(6,385
)
State
(2,943
)
 
(601
)
 
(2,943
)
 
(601
)
 
(103,328
)
 
(6,986
)
 
(103,328
)
 
(6,986
)
Total benefit
(103,658
)
 
(7,054
)
 
(103,587
)
 
(6,967
)
Less: income tax provision attributable to noncontrolling interest
67

 
—

 
157

 
2

Total benefit attributable to SandRidge Energy, Inc.
$
(103,725
)
 
$
(7,054
)
 
$
(103,744
)
 
$
(6,969
)

Deferred income taxes are provided to reflect the future tax consequences of temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements. Deferred tax assets are reduced by a valuation allowance when a determination is made that it is more likely than not that some or all of the deferred assets will not be realized based on the weight of all available evidence. As of December 31, 2008, the Company determined it was appropriate to record a full valuation allowance against its net deferred tax asset. During the three-month period ended June 30, 2012, the Company recorded a net deferred tax liability associated with the Dynamic Acquisition which resulted in the Company releasing a portion of the previously recorded valuation allowance. The partial release of the valuation allowance was based on management's assessment that it is more likely than not that the Company will realize a benefit from more of its existing deferred tax assets as the Dynamic deferred tax liabilities are available to offset the reversal of the Company's deferred tax assets. Although the Company continued to have a full valuation allowance against its net deferred tax asset at June 30, 2012, the release of a portion of the valuation allowance resulted in an income tax benefit of $103.3 million for the three and six-month periods ended June 30, 2012. The Company continues to closely monitor all available evidence in making its determination for the need to maintain a valuation allowance against its net deferred tax asset.

Internal Revenue Code (“IRC”) Section 382 addresses company ownership changes and specifically limits the utilization of certain deductions and other tax attributes on an annual basis following an ownership change. The Company experienced an ownership change within the meaning of IRC Section 382 on December 31, 2008. The ownership change subjected certain of the

34
Table of Contents
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)


Company’s tax attributes, including $298.4 million of federal net operating loss carryforwards, to the IRC Section 382 limitation. The Company experienced a subsequent ownership change within the meaning of IRC Section 382 on July 16, 2010 as a result of the acquisition of Arena. The subsequent ownership change resulted in a more restrictive limitation on certain of the Company’s tax attributes than with the December 31, 2008 ownership change. The more restrictive limitation applies not only to the $298.4 million of federal net operating loss carryforwards and certain other tax attributes existing at December 31, 2008, but also to net operating losses of approximately $554.3 million and certain other tax attributes generated in periods following the December 31, 2008 ownership change. The subsequent limitation could result in a material amount of existing loss carryforwards expiring unused. Arena also experienced an ownership change on July 16, 2010 as a result of its acquisition by the Company. This ownership change resulted in a limitation on Arena’s net operating loss carryforwards of $119.9 million available to the Company. None of the limitations discussed above resulted in a current federal tax liability at June 30, 2012 or December 31, 2011.

At June 30, 2012, the Company had a liability of approximately $1.3 million for unrecognized tax benefits, compared to a liability of approximately $1.8 million at December 31, 2011. If recognized, approximately $0.9 million, net of federal tax expense, would be recorded as a reduction of income tax expense and would affect the effective tax rate.

Consistent with the Company’s policy to record interest and penalties on income taxes as a component of the income tax provision, the Company has included $0.01 million and $0.03 million of accrued gross interest with respect to unrecognized tax benefits in the accompanying unaudited condensed consolidated statements of operations during the three and six-month periods ended June 30, 2012, respectively. The Company included $0.02 million and $0.07 million of accrued gross interest with respect to unrecognized tax benefits in the accompanying unaudited condensed consolidated statements of operations during the three and six-month periods ended June 30, 2011, respectively. The Company had a corresponding accrued liability of $0.2 million for interest and penalties relating to uncertain tax positions at June 30, 2012 and December 31, 2011.

The Company’s only taxing jurisdiction is the United States (federal and state). The Company’s tax years 2008 to present remain open for federal examination. Additionally, various tax years remain open beginning with tax year 2003 due to federal net operating loss carryforwards. The number of years open for state tax audits varies, depending on the state, but are generally from three to five years. Currently, several examinations are in progress. The Company does not anticipate that any federal or state audits will have a significant impact on the Company’s results of operations or financial position. As a result of ongoing negotiations pertaining to the Company’s current state audits, it is reasonably possible that the Company’s gross unrecognized tax benefits balance may decrease within the next twelve months by approximately $1.1 million.

For the three and six-month periods ended June 30, 2012, income tax payments, net of refunds, were approximately $1.4 million and $1.3 million, respectively. For the three-month period ended June 30, 2011, income tax refunds, net of payments, were approximately $0.04 million. For the six-month period ended June 30, 2011, income tax payments, net of refunds, were $0.9 million.

14. 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 period, but also include the dilutive effect of awards of restricted stock, using the treasury stock method, and outstanding convertible preferred stock. Under the treasury stock method, the amount of unrecognized compensation expense related to unvested stock-based compensation grants are assumed to be used to repurchase common shares. 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 six-month periods ended June 30, 2012 and 2011 (in thousands):
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
Weighted average basic common shares outstanding
461,008

 
398,435

 
430,802

 
398,343

Effect of dilutive securities
 
 
 
 
 
 
 
Restricted stock
9,499

 
7,414

 
9,443

 
—

Convertible preferred stock
90,133

 
90,133

 
90,133

 
—

Weighted average diluted common and potential common shares outstanding
560,640

 
495,982

 
530,378

 
398,343



35
Table of Contents
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)


For the six-month period ended June 30, 2011, restricted stock awards covering 7.3 million shares were excluded from the computation of loss per share because their effect would have been antidilutive.

In computing diluted earnings per share, the Company evaluated the if-converted method with respect to its outstanding 8.5% convertible perpetual preferred stock, 6.0% convertible perpetual preferred stock and 7.0% convertible perpetual preferred stock for the three and six-month periods ended June 30, 2012 and 2011. Under the if-converted method, the Company assumes the conversion of the preferred stock to common stock and determines if this is more dilutive than including the preferred stock dividends (paid and unpaid) in the computation of income available (loss applicable) to common stockholders. For the three-month periods ended June 30, 2012 and 2011, and the six-month period ended June 30, 2012, the Company determined the if-converted method was more dilutive and did not include the 8.5%, 6.0% and 7.0% preferred stock dividends in the determination of income available to common stockholders. For the six-month period ended June 30, 2011, the Company determined the if-converted method was not more dilutive and included the 8.5%, 6.0% and 7.0% preferred stock dividends in the determination of loss applicable to common stockholders.

15. Related Party Transactions

The Company enters into transactions in the ordinary course of business with certain related parties. These transactions primarily consist of purchases related to drilling and completion activities, gas treating services and drilling equipment and sales of oil field services, equipment and natural gas. During the three-month periods ended June 30, 2012 and 2011, sales by the Company to related parties were $3.2 million and $6.9 million, respectively. During the six-month periods ended June 30, 2012 and 2011, sales by the Company to related parties were $7.0 million and $11.7 million, respectively. Accounts receivable due from related parties totaled $1.2 million and $1.6 million at June 30, 2012 and December 31, 2011, respectively. These amounts primarily relate to sales of natural gas to Southern Union, the Company’s partner in GRLP.

Oklahoma City Thunder Agreements. The Company’s Chairman and Chief Executive Officer and one of its independent directors own minority interests in a limited liability company that owns and operates the Oklahoma City Thunder basketball team. The Company is party to a sponsorship agreement, through the 2013 season, whereby it pays approximately $3.3 million per year for advertising and promotional activities related to the Oklahoma City Thunder. Additionally, the Company entered into an agreement to license a suite at the arena where the Oklahoma City Thunder plays its home games. Under this four-year agreement, the Company pays an annual license fee of $0.2 million through 2013. At June 30, 2012, the Company had $0.6 million due under these agreements. At December 31, 2011, the Company had no amounts due under these agreements.

16. Business Segment Information

The Company has three business segments: exploration and production, drilling and oil field services and midstream gas services. These segments represent the Company’s three main business units, each offering different products and services. The exploration and production segment is engaged in the acquisition, development and production of oil and natural gas properties and includes the activities of the Mississippian Trust I, the Permian Trust and the Mississippian Trust II. The drilling and oil field services segment is engaged in the contract drilling of oil and natural gas wells. The midstream gas services segment is engaged in the purchasing, gathering, treating and selling of natural gas. The All Other column in the tables below includes items not related to the Company’s reportable segments, including CO2 gathering and sales and corporate operations.


36
Table of Contents
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)


Management evaluates the performance of the Company’s business segments based on income (loss) from operations, which is defined as segment operating revenues less operating expenses and depreciation, depletion, amortization and accretion. Summarized financial information concerning the Company’s segments is shown in the following table (in thousands):
 
Exploration and Production
 
Drilling and Oil Field Services
 
Midstream Gas Services
 
All Other
 
Consolidated Total
Three Months Ended June 30, 2012
 
 
 
 
 
 
 
 
 
Revenues
$
434,834

 
$
104,076

 
$
24,798

 
$
1,543

 
$
565,251

Inter-segment revenue
(77
)
 
(70,444
)
 
(16,296
)
 
—

 
(86,817
)
Total revenues
$
434,757

 
$
33,632

 
$
8,502

 
$
1,543

 
$
478,434

 
 
 
 
 
 
 
 
 
 
Income (loss) from operations(1)
$
786,335

 
$
4,678

 
$
(3,631
)
 
$
(24,969
)
 
$
762,413

Interest income (expense)
416

 
—

 
(137
)
 
(68,848
)
 
(68,569
)
Bargain purchase gain
124,446

 
—

 
—

 
—

 
124,446

Other income (expense), net
242

 
—

 
—

 
(323
)
 
(81
)
Income (loss) before income taxes
$
911,439

 
$
4,678

 
$
(3,768
)
 
$
(94,140
)
 
$
818,209

Capital expenditures(2)
$
518,343

 
$
5,836

 
$
17,754

 
$
20,121

 
$
562,054

Depreciation, depletion, amortization and accretion
$
147,479

 
$
8,624

 
$
1,717

 
$
4,753

 
$
162,573

Three Months Ended June 30, 2011
 
 
 
 
 
 
 
 
 
Revenues
$
317,768

 
$
96,443

 
$
48,278

 
$
2,886

 
$
465,375

Inter-segment revenue
(66
)
 
(67,906
)
 
(32,473
)
 
(156
)
 
(100,601
)
Total revenues
$
317,702

 
$
28,537

 
$
15,805

 
$
2,730

 
$
364,774

 
 
 
 
 
 
 
 
 
 
Income (loss) from operations(1)
$
301,197

 
$
4,098

 
$
(2,570
)
 
$
(23,009
)
 
$
279,716

Interest income (expense)
15

 
4

 
(141
)
 
(61,565
)
 
(61,687
)
Loss on extinguishment of debt
—

 
—

 
—

 
(2,051
)
 
(2,051
)
Other income (expense), net
3

 
—

 
216

 
(81
)
 
138

Income (loss) before income taxes
$
301,215

 
$
4,102

 
$
(2,495
)
 
$
(86,706
)
 
$
216,116

Capital expenditures(2)
$
413,529

 
$
8,030

 
$
4,462

 
$
17,875

 
$
443,896

Depreciation, depletion, amortization and accretion
$
76,734

 
$
7,998

 
$
1,291

 
$
3,438

 
$
89,461

Six Months Ended June 30, 2012
 
 
 
 
 
 
 
 
 
Revenues
$
777,955

 
$
202,408

 
$
50,960

 
$
2,949

 
$
1,034,272

Inter-segment revenue
(155
)
 
(139,467
)
 
(34,591
)
 
10

 
(174,203
)
Total revenues
$
777,800

 
$
62,941

 
$
16,369

 
$
2,959

 
$
860,069

 
 
 
 
 
 
 
 
 
 
Income (loss) from operations(3)
$
662,499

 
$
8,157

 
$
(6,358
)
 
$
(53,541
)
 
$
610,757

Interest income (expense)
559

 
—

 
(293
)
 
(135,800
)
 
(135,534
)
Bargain purchase gain
124,446

 
—

 
—

 
—

 
124,446

Other income, net
2,010

 
—

 
—

 
377

 
2,387

Income (loss) before income taxes
$
789,514

 
$
8,157

 
$
(6,651
)
 
$
(188,964
)
 
$
602,056

Capital expenditures(2)
$
1,010,248

 
$
13,752

 
$
41,729

 
$
65,983

 
$
1,131,712

Depreciation, depletion, amortization and accretion
$
237,531

 
$
17,174

 
$
3,128

 
$
8,925

 
$
266,758

At June 30, 2012
 
 
 
 
 
 
 
 
 
Total assets
$
8,003,601

 
$
214,471

 
$
180,193

 
$
780,270

 
$
9,178,535


37
Table of Contents
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)


 
Exploration and Production
 
Drilling and Oil Field Services
 
Midstream Gas Services
 
All Other
 
Consolidated Total
Six Months Ended June 30, 2011
 
 
 
 
 
 
 
 
 
Revenues
$
585,004

 
$
163,992

 
$
104,256

 
$
6,106

 
$
859,358

Inter-segment revenue
(133
)
 
(114,421
)
 
(66,511
)
 
(672
)
 
(181,737
)
Total revenues
$
584,871

 
$
49,571

 
$
37,745

 
$
5,434

 
$
677,621

 
 
 
 
 
 
 
 
 
 
Income (loss) from operations(3)
$
116,990

 
$
3,990

 
$
(5,098
)
 
$
(43,995
)
 
$
71,887

Interest income (expense)
120

 
(101
)
 
(313
)
 
(120,830
)
 
(121,124
)
Loss on extinguishment of debt
—

 
—

 
—

 
(38,232
)
 
(38,232
)
Other income (expense), net
1,679

 
—

 
(485
)
 
141

 
1,335

Income (loss) before income taxes
$
118,789

 
$
3,889

 
$
(5,896
)
 
$
(202,916
)
 
$
(86,134
)
Capital expenditures(2)
$
812,626

 
$
14,793

 
$
8,635

 
$
24,011

 
$
860,065

Depreciation, depletion, amortization and accretion
$
151,206

 
$
15,727

 
$
2,388

 
$
7,119

 
$
176,440

At December 31, 2011
 
 
 
 
 
 
 
 
 
Total assets
$
5,345,527

 
$
219,101

 
$
138,844

 
$
516,137

 
$
6,219,609

____________________
(1)
Exploration and production segment income from operations includes net gains of $669.8 million and $170.0 million on commodity derivative contracts for the three-month periods ended June 30, 2012 and 2011, respectively.
(2)
On an accrual basis.
(3)
Exploration and production segment income from operations includes a net gain of $415.2 million and a net loss of $107.6 million on commodity derivative contracts for the six-month periods ended June 30, 2012 and 2011, respectively.

17. Condensed Consolidating Financial Information

The Company provides condensed consolidating financial information for its subsidiaries that are guarantors of its registered debt. The subsidiary guarantors are wholly owned and have jointly and severally guaranteed, on a full, unconditional and unsecured basis, the Company’s Senior Floating Rate Notes, 8.75% Senior Notes and 7.5% Senior Notes. Prior to their purchase and redemption in 2011, the 8.625% Senior Notes were also jointly and severally guaranteed, on a full, unconditional and unsecured basis by the wholly owned subsidiary guarantors. The subsidiary guarantees (i) rank equally in right of payment with all of the existing and future senior debt of the subsidiary guarantors; (ii) rank senior to all of the existing and future subordinated debt of the subsidiary guarantors; (iii) are effectively subordinated in right of payment to any existing or future secured obligations of the subsidiary guarantors to the extent of the value of the assets securing such obligations; (iv) are structurally subordinated to all debt and other obligations of the subsidiaries of the guarantors who are not themselves guarantors; and (v) are only released under certain customary circumstances. The Company’s subsidiary guarantors guarantee payments of principal and interest under the Company’s registered notes.

The following unaudited condensed consolidating financial information represents the financial information of SandRidge Energy, Inc., its wholly owned subsidiary guarantors and its non-guarantor subsidiaries, prepared on the equity basis of accounting. The non-guarantor subsidiaries, including consolidated VIEs, are included in the non-guarantors column in the tables below. The financial information may not necessarily be indicative of the financial position, results of operations or cash flows had the subsidiary guarantors operated as independent entities.


38
Table of Contents
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)


Condensed Consolidating Balance Sheets
 
 
June 30, 2012
 
Parent
 
Guarantors
 
Non-Guarantors
 
Eliminations
 
Consolidated
 
(In thousands)
ASSETS
 
 
 
 
 
 
 
 
 
Current assets
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
410,870

 
$
5,219

 
$
4,984

 
$
—

 
$
421,073

Accounts receivable, net
1,485,828

 
711,971

 
676,005

 
(2,585,472
)
 
288,332

Derivative contracts
—

 
184,664

 
43,443

 
(23,905
)
 
204,202

Prepaid expenses
—

 
33,390

 
258

 
—

 
33,648

Other current assets
—

 
28,060

 
5,470

 
—

 
33,530

Total current assets
1,896,698

 
963,304

 
730,160

 
(2,609,377
)
 
980,785

Property, plant and equipment, net
—

 
6,401,818

 
1,382,779

 
(55,585
)
 
7,729,012

Investment in subsidiaries
5,707,575

 
(45,077
)
 
—

 
(5,662,498
)
 
—

Derivative contracts
—

 
79,925

 
67,759

 
(49,447
)
 
98,237

Goodwill
—

 
235,396

 
—

 
—

 
235,396

Other assets
73,638

 
61,368

 
99

 
—

 
135,105

Total assets
$
7,677,911

 
$
7,696,734

 
$
2,180,797

 
$
(8,376,907
)
 
$
9,178,535

LIABILITIES AND EQUITY
 
 
 
 
 
 
 
 
 
Current liabilities
 
 
 
 
 
 
 
 
 
Accounts payable and accrued expenses
$
1,220,476

 
$
1,386,515

 
$
639,112

 
$
(2,576,741
)
 
$
669,362

Derivative contracts
6,849

 
24,018

 
—

 
(23,905
)
 
6,962

Asset retirement obligation
—

 
140,789

 
—

 
—

 
140,789

Other current liabilities
—

 
6,321

 
—

 
—

 
6,321

Total current liabilities
1,227,325

 
1,557,643

 
639,112

 
(2,600,646
)
 
823,434

Long-term debt
3,555,334

 
—

 
—

 
(5,902
)
 
3,549,432

Derivative contracts
—

 
69,280

 
—

 
(49,447
)
 
19,833

Asset retirement obligation
—

 
349,003

 
189

 
—

 
349,192

Other long-term obligations
1,333

 
13,233

 
—

 
—

 
14,566

Total liabilities
4,783,992

 
1,989,159

 
639,301

 
(2,655,995
)
 
4,756,457

Equity
 
 
 
 
 
 
 
 
 
SandRidge Energy, Inc. stockholders’ equity
2,893,919

 
5,707,575

 
1,541,496

 
(7,307,485
)
 
2,835,505

Noncontrolling interest
—

 
—

 
—

 
1,586,573

 
1,586,573

Total equity
2,893,919

 
5,707,575

 
1,541,496

 
(5,720,912
)
 
4,422,078

Total liabilities and equity
$
7,677,911

 
$
7,696,734

 
$
2,180,797

 
$
(8,376,907
)
 
$
9,178,535


39
Table of Contents
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)


 
December 31, 2011
 
Parent
 
Guarantors
 
Non-Guarantors
 
Eliminations
 
Consolidated
 
(In thousands)
ASSETS
 
 
 
 
 
 
 
 
 
Current assets
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
204,015

 
$
437

 
$
3,229

 
—

 
$
207,681

Accounts receivable, net
1,217,096

 
247,824

 
602,541

 
(1,861,125
)
 
206,336

Derivative contracts
—

 
2,567

 
10,368

 
(8,869
)
 
4,066

Prepaid expenses
—

 
13,442

 
657

 
—

 
14,099

Other current assets
—

 
2,621

 
7,037

 
—

 
9,658

Total current assets
1,421,111

 
266,891

 
623,832

 
(1,869,994
)
 
441,840

Property, plant and equipment, net
—

 
4,462,846

 
926,578

 
—

 
5,389,424

Investment in subsidiaries
3,609,244

 
90,920

 
—

 
(3,700,164
)
 
—

Derivative contracts
—

 
20,746

 
35,774

 
(30,105
)
 
26,415

Goodwill
—

 
235,396

 
—

 
—

 
235,396

Other assets
51,724

 
74,760

 
50

 
—

 
126,534

Total assets
$
5,082,079

 
$
5,151,559

 
$
1,586,234

 
$
(5,600,263
)
 
$
6,219,609

LIABILITIES AND EQUITY
 
 
 
 
 
 
 
 
 
Current liabilities
 
 
 
 
 
 
 
 
 
Accounts payable and accrued expenses
$
643,376

 
$
1,166,029

 
$
556,165

 
$
(1,858,786
)
 
$
506,784

Derivative contracts
8,475

 
115,829

 
—

 
(8,869
)
 
115,435

Asset retirement obligation
—

 
32,906

 
—

 
—

 
32,906

Other current liabilities
—

 
43,320

 
1,051

 
—

 
44,371

Total current liabilities
651,851

 
1,358,084

 
557,216

 
(1,867,655
)
 
699,496

Long-term debt
2,798,147

 
—

 
14,978

 
—

 
2,813,125

Derivative contracts
1,973

 
77,827

 
—

 
(30,105
)
 
49,695

Asset retirement obligation
—

 
95,029

 
181

 
—

 
95,210

Other long-term obligations
1,758

 
11,375

 
—

 
—

 
13,133

Total liabilities
3,453,729

 
1,542,315

 
572,375

 
(1,897,760
)
 
3,670,659

Equity
 
 
 
 
 
 
 
 
 
SandRidge Energy, Inc. stockholders’ equity
1,628,350

 
3,609,244

 
1,013,859

 
(4,625,442
)
 
1,626,011

Noncontrolling interest
—

 
—

 
—

 
922,939

 
922,939

Total equity
1,628,350

 
3,609,244

 
1,013,859

 
(3,702,503
)
 
2,548,950

Total liabilities and equity
$
5,082,079

 
$
5,151,559

 
$
1,586,234

 
$
(5,600,263
)
 
$
6,219,609


40
Table of Contents
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)


Condensed Consolidating Statements of Operations
 
Parent
 
Guarantors
 
Non-Guarantors
 
Eliminations
 
Consolidated
 
(In thousands)
Three Months Ended June 30, 2012
 
 
 
 
 
 
 
 
 
Total revenues
$
—

 
$
402,589

 
$
110,240

 
$
(34,395
)
 
$
478,434

Expenses
 
 
 
 
 
 
 
 
 
Direct operating expenses
—

 
149,540

 
45,391

 
(33,349
)
 
161,582

General and administrative
99

 
59,951

 
2,014

 
(348
)
 
61,716

Depreciation, depletion, amortization and accretion
—

 
140,339

 
22,234

 
—

 
162,573

Gain on derivative contracts
—

 
(562,081
)
 
(107,769
)
 
—

 
(669,850
)
Total expenses
99

 
(212,251
)
 
(38,130
)
 
(33,697
)
 
(283,979
)
(Loss) income from operations
(99
)
 
614,840

 
148,370

 
(698
)
 
762,413

Equity earnings from subsidiaries
802,457

 
48,942

 
—

 
(851,399
)
 
—

Interest (expense) income
(68,527
)
 
278

 
(320
)
 
—

 
(68,569
)
Gain on sale of investment in subsidiary
55,585

 
—

 
—

 
(55,585
)
 
—

Bargain purchase gain
—

 
124,446

 
—

 
—

 
124,446

Other income, net
—

 
13,951

 
—

 
(14,032
)
 
(81
)
Income before income taxes
789,416

 
802,457

 
148,050

 
(921,714
)
 
818,209

Income tax (benefit) expense
(103,762
)
 
—

 
104

 
—

 
(103,658
)
Net income
893,178

 
802,457

 
147,946

 
(921,714
)
 
921,867

Less: net income attributable to noncontrolling interest
—

 
—

 
—

 
99,004

 
99,004

Net income attributable to SandRidge Energy, Inc.
$
893,178

 
$
802,457

 
$
147,946

 
$
(1,020,718
)
 
$
822,863

 
 
 
 
 
 
 
 
 
 
Three Months Ended June 30, 2011
 
 
 
 
 
 
 
 
 
Total revenues
$
—

 
$
341,481

 
$
56,289

 
$
(32,996
)
 
$
364,774

Expenses
 
 
 
 
 
 
 
 
 
Direct operating expenses
—

 
122,389

 
38,260

 
(32,742
)
 
127,907

General and administrative
104

 
36,608

 
1,220

 
(254
)
 
37,678

Depreciation, depletion, amortization and accretion
—

 
83,413

 
6,048

 
—

 
89,461

Gain on derivative contracts
—

 
(160,387
)
 
(9,601
)
 
—

 
(169,988
)
Total expenses
104

 
82,023

 
35,927

 
(32,996
)
 
85,058

(Loss) income from operations
(104
)
 
259,458

 
20,362

 
—

 
279,716

Equity earnings from subsidiaries
266,425

 
20,104

 
—

 
(286,529
)
 
—

Interest expense
(61,308
)
 
(121
)
 
(258
)
 
—

 
(61,687
)
Loss on extinguishment of debt
(2,051
)
 
—

 
—

 
—

 
(2,051
)
Other income, net
—

 
138

 
—

 
—

 
138

Income before income taxes
202,962

 
279,579

 
20,104

 
(286,529
)
 
216,116

Income tax benefit
(7,054
)
 
—

 
—

 
—

 
(7,054
)
Net income
210,016

 
279,579

 
20,104

 
(286,529
)
 
223,170

Less: net income attributable to noncontrolling interest
—

 
—

 
—

 
13,154

 
13,154

Net income attributable to SandRidge Energy, Inc.
$
210,016

 
$
279,579

 
$
20,104

 
$
(299,683
)
 
$
210,016

 
 
 
 
 
 
 
 
 
 

41
Table of Contents
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)


 
Parent
 
Guarantors
 
Non-Guarantors
 
Eliminations
 
Consolidated
 
(In thousands)
Six Months Ended June 30, 2012
 
 
 
 
 
 
 
 
 
Total revenues
$
—

 
$
724,815

 
$
201,371

 
$
(66,117
)
 
$
860,069

Expenses
 
 
 
 
 
 
 
 
 
Direct operating expenses
—

 
263,607

 
87,081

 
(64,947
)
 
285,741

General and administrative
185

 
108,065

 
4,447

 
(680
)
 
112,017

Depreciation, depletion, amortization and accretion
—

 
231,255

 
35,503

 
—

 
266,758

Gain on derivative contracts
—

 
(341,146
)
 
(74,058
)
 
—

 
(415,204
)
Total expenses
185

 
261,781

 
52,973

 
(65,627
)
 
249,312

(Loss) income from operations
(185
)
 
463,034

 
148,398

 
(490
)
 
610,757

Equity earnings from subsidiaries
707,930

 
46,640

 
—

 
(754,570
)
 
—

Interest (expense) income
(135,233
)
 
265

 
(566
)
 
—

 
(135,534
)
Gain on sale of investment in subsidiary
55,585

 
—

 
—

 
(55,585
)
 
—

Bargain purchase gain
—

 
124,446

 
—

 
—

 
124,446

Other income, net
—

 
73,545

 
—

 
(71,158
)
 
2,387

Income before income taxes
628,097

 
707,930

 
147,832

 
(881,803
)
 
602,056

Income tax (benefit) expense
(103,821
)
 
—

 
234

 
—

 
(103,587
)
Net income
731,918

 
707,930

 
147,598

 
(881,803
)
 
705,643

Less: net income attributable to noncontrolling interest
—

 
—

 
—

 
100,958

 
100,958

Net income attributable to SandRidge Energy, Inc.
$
731,918

 
$
707,930

 
$
147,598

 
$
(982,761
)
 
$
604,685

Six Months Ended June 30, 2011
 
 
 
 
 
 
 
 
 
Total revenues
$
—

 
$
650,777

 
$
70,770

 
$
(43,926
)
 
$
677,621

Expenses
 
 
 
 
 
 
 
 
 
Direct operating expenses
—

 
241,617

 
51,472

 
(43,526
)
 
249,563

General and administrative
189

 
70,342

 
1,960

 
(400
)
 
72,091

Depreciation, depletion, amortization and accretion
—

 
168,652

 
7,788

 
—

 
176,440

Loss (gain) on derivative contracts
—

 
117,241

 
(9,601
)
 
—

 
107,640

Total expenses
189

 
597,852

 
51,619

 
(43,926
)
 
605,734

(Loss) income from operations
(189
)
 
52,925

 
19,151

 
—

 
71,887

Equity earnings from subsidiaries
59,437

 
18,873

 
—

 
(78,310
)
 
—

Interest expense
(120,315
)
 
(293
)
 
(516
)
 
—

 
(121,124
)
Loss on extinguishment of debt
(38,232
)
 
—

 
—

 
—

 
(38,232
)
Other income, net
—

 
1,093

 
242

 
—

 
1,335

(Loss) income before income taxes
(99,299
)
 
72,598

 
18,877

 
(78,310
)
 
(86,134
)
Income tax (benefit) expense
(6,971
)
 
—

 
4

 
—

 
(6,967
)
Net (loss) income
(92,328
)
 
72,598

 
18,873

 
(78,310
)
 
(79,167
)
Less: net income attributable to noncontrolling interest
—

 
—

 
—

 
13,161

 
13,161

Net (loss) income attributable to SandRidge Energy, Inc.
$
(92,328
)
 
$
72,598

 
$
18,873

 
$
(91,471
)
 
$
(92,328
)


42
Table of Contents
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)


Condensed Consolidating Statements of Cash Flows

 
Parent
 
Guarantors
 
Non-Guarantors
 
Eliminations
 
Consolidated
 
(In thousands)
Six Months Ended June 30, 2012
 
 
 
 
 
 
 
 
 
Net cash provided by operating activities
$
144,654

 
$
59,362

 
$
153,748

 
$
59,942

 
$
417,706

Net cash used in investing activities
(624,748
)
 
(127,286
)
 
(617,051
)
 
(94,671
)
 
(1,463,756
)
Net cash provided by financing activities
686,949

 
72,706

 
465,058

 
34,729

 
1,259,442

Net increase in cash and cash equivalents
206,855

 
4,782

 
1,755

 
—

 
213,392

Cash and cash equivalents at beginning of year
204,015

 
437

 
3,229

 
—

 
207,681

Cash and cash equivalents at end of period
$
410,870

 
$
5,219

 
$
4,984

 
$
—

 
$
421,073

Six Months Ended June 30, 2011
 
 
 
 
 
 
 
 
 
Net cash provided by operating activities
$
94,579

 
$
159,264

 
$
3,699

 
$
—

 
$
257,542

Net cash used in investing activities
—

 
(158,747
)
 
(340,366
)
 
1,501

 
(497,612
)
Net cash (used in) provided by financing activities
(95,214
)
 
(864
)
 
336,401

 
(1,501
)
 
238,822

Net decrease in cash and cash equivalents
(635
)
 
(347
)
 
(266
)
 
—

 
(1,248
)
Cash and cash equivalents at beginning of year
1,441

 
564

 
3,858

 
—

 
5,863

Cash and cash equivalents at end of period
$
806

 
$
217

 
$
3,592

 
$
—

 
$
4,615


18. Subsequent Events

Events occurring after June 30, 2012 were evaluated to ensure that any subsequent events that met the criteria for recognition and/or disclosure in this Quarterly Report have been included.

Royalty Trust Distributions. On July 26, 2012, the Royalty Trusts announced quarterly distributions for the three-month period ended June 30, 2012. The following distributions are expected to be paid on August 29, 2012 to holders of record as of the close of business on August 14, 2012 (in thousands):
Royalty Trust
 
Total Distribution
 
Amount to be Distributed to Third-Party Unitholders
Mississippian Trust I
 
$
20,375

 
$
14,397

Mississippian Trust II
 
24,723

 
14,866

Permian Trust
 
30,147

 
20,959

  Total
 
$
75,245

 
$
50,222



43
Table of Contents

ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Introduction

The following discussion and analysis is intended to help the reader understand the Company’s business, financial condition, results of operations, liquidity and capital resources. This discussion and analysis should be read in conjunction with the Company’s unaudited condensed consolidated financial statements and the accompanying notes included in this Quarterly Report, as well as the Company’s audited consolidated financial statements and the accompanying notes included in the 2011 Form 10-K. The Company’s discussion and analysis includes the following subjects:
•
Overview of the Company;
•
Recent Developments;
•
Recent Accounting Pronouncements;
•
Results by Segment;
•
Consolidated Results of Operations; and
•
Liquidity and Capital Resources.

The financial information with respect to the three and six-month periods ended June 30, 2012 and 2011, discussed below, is unaudited. In the opinion of management, this information contains all adjustments, which consist only of normal recurring adjustments, necessary to state fairly the unaudited condensed consolidated financial statements. The results of operations for the interim periods are not necessarily indicative of the results of operations for the full fiscal year.

Overview of the Company

SandRidge is an independent oil and natural gas company concentrating on development and production activities in the Mid-Continent, west Texas and Gulf of Mexico. The Company’s primary areas of focus are the Mississippian formation in the Mid-Continent area of Oklahoma and Kansas and the Permian Basin in west Texas. The Company owns and operates additional interests in the Mid-Continent, Gulf of Mexico, WTO and Gulf Coast.

The Company also operates businesses that are complementary to its primary development and production activities, including gas gathering and processing facilities, an oil and gas marketing business and an oil field services business, including a drilling rig business. These complementary businesses provide the Company with operational flexibility and an advantageous cost structure by reducing the Company’s dependence on third parties for these services. The extent to which each of these supplemental businesses contributes to the Company’s consolidated results of operations largely is determined by the amount of work each performs for third parties. Revenues and costs related to work performed by these businesses for the Company’s own account are eliminated in consolidation and, therefore, do not directly contribute to the Company’s consolidated results of operations.

Recent Developments

Dynamic Acquisition. In April 2012, the Company completed the Dynamic Acquisition for approximately $1.2 billion, comprised of approximately $680.0 million in cash and approximately 74 million shares of the Company’s common stock. Dynamic is an oil and natural gas exploration, development and production company with operations in the Gulf of Mexico. The Dynamic Acquisition expanded the Company's holdings in state and federal waters of the Gulf of Mexico and added 1,807 MBoe to the Company's production in the second quarter of 2012.

Issuance of 8.125% Senior Notes due 2022. In April 2012, concurrent with the closing of the Dynamic Acquisition, the Company issued $750.0 million of unsecured 8.125% Senior Notes. Net proceeds from the offering were approximately $730.1 million after deducting offering expenses, and were used to finance the cash portion of the Dynamic Acquisition purchase price and to pay related fees and expenses, with any remaining amount being used for general corporate purposes.

SandRidge Mississippian Trust II. In April 2012, the Mississippian Trust II completed its initial public offering of 29,900,000 common units representing beneficial interests in the Mississippian Trust II. Net proceeds to the Mississippian Trust II, after underwriting discounts and commissions, were approximately $587.1 million. Concurrent with the closing, the Company conveyed certain royalty interests to the Mississippian Trust II in exchange for the net proceeds of the Mississippian Trust II’s initial public offering and 19,825,000 units of beneficial interest, representing approximately 39.9% of the beneficial interest in the Mississippian Trust II. The royalty interests conveyed to the Mississippian Trust II are in certain existing wells and wells to be drilled on certain oil and natural gas properties leased by the Company in the Mississippian formation in northern Oklahoma

44
Table of Contents

and southern Kansas. The Company intends to use the net proceeds from the offering for general corporate purposes, including to partially fund its 2012 capital expenditure program.

The Company and one of its wholly owned subsidiaries entered into a development agreement with the Mississippian Trust II that obligates the Company to drill, or cause to be drilled, a specified number of development wells, which are also subject to the royalty interest, by December 31, 2016. One of the Company’s wholly owned subsidiaries also granted to the Mississippian Trust II a lien on the Company’s interests in the properties where the development wells will be drilled, in order to secure the estimated amount of the drilling costs for the wells. Additionally, the Company and the Mississippian Trust II entered into an administrative services agreement and a derivatives agreement. The Mississippian Trust II is a VIE of which the Company has determined it is the primary beneficiary. As such, its activities were consolidated with those of the Company beginning in April 2012.

Sale of Tertiary Recovery Properties. In June 2012, the Company sold its tertiary recovery properties located in the Permian Basin area of west Texas for approximately $130.0 million, subject to post-closing adjustments. Approximately 1.3% of the Company's combined production volumes for the year ended December 31, 2011 was produced from the tertiary properties.

Acquisition of Gulf of Mexico Properties. In June 2012, the Company acquired oil and natural gas properties in the Gulf of Mexico located on approximately 184,000 gross (103,000 net) acres for approximately $38.5 million, net of purchase price adjustments and subject to post-closing adjustments.

Recent Accounting Pronouncements

For a discussion of recent accounting pronouncements, see Note 1 to the Company’s unaudited interim condensed consolidated financial statements included in Item 1 of this Quarterly Report.

Results by Segment

The Company operates in three business segments: exploration and production, drilling and oil field services and midstream gas services. These segments represent the Company's three main business units, each offering different products and services. The exploration and production segment is engaged in the acquisition, development and production of oil and natural gas properties and includes the activities of the Mississippian Trust I, the Permian Trust and the Mississippian Trust II. The drilling and oil field services segment is engaged in the contract drilling of oil and natural gas wells. The midstream gas services segment is engaged in the purchasing, gathering, treating and selling of natural gas. The All Other column in the tables below includes items not related to the Company’s reportable segments, including its CO2 gathering and sales and corporate operations.

Management evaluates the performance of the Company’s business segments based on income (loss) from operations, which is defined as segment operating revenues less operating expenses and depreciation, depletion, amortization and accretion. Results of these measurements provide important information to the Company about the activity and profitability of the Company’s lines of business.

45
Table of Contents

The following table sets forth financial information regarding each of the Company’s business segments for the three and six-month periods ended June 30, 2012 and 2011 (in thousands).
 
Exploration and Production
 
Drilling and Oil Field Services
 
Midstream Gas Services
 
All Other
 
Consolidated Total
Three Months Ended June 30, 2012
 
 
 
 
 
 
 
 
 
Revenues
$
434,834

 
$
104,076

 
$
24,798

 
$
1,543

 
$
565,251

Inter-segment revenue
(77
)
 
(70,444
)
 
(16,296
)
 
—

 
(86,817
)
Total revenues
$
434,757

 
$
33,632

 
$
8,502

 
$
1,543

 
$
478,434

Income (loss) from operations(1)
$
786,335

 
$
4,678

 
$
(3,631
)
 
$
(24,969
)
 
$
762,413

Interest income (expense)
416

 
—

 
(137
)
 
(68,848
)
 
(68,569
)
Bargain purchase gain
124,446

 
—

 
—

 
—

 
124,446

Other income (expense), net
242

 
—

 
—

 
(323
)
 
(81
)
Income (loss) before income taxes
$
911,439

 
$
4,678

 
$
(3,768
)
 
$
(94,140
)
 
$
818,209

Three Months Ended June 30, 2011
 
 
 
 
 
 
 
 
 
Revenues
$
317,768

 
$
96,443

 
$
48,278

 
$
2,886

 
$
465,375

Inter-segment revenue
(66
)
 
(67,906
)
 
(32,473
)
 
(156
)
 
(100,601
)
Total revenues
$
317,702

 
$
28,537

 
$
15,805

 
$
2,730

 
$
364,774

Income (loss) from operations(1)
$
301,197

 
$
4,098

 
$
(2,570
)
 
$
(23,009
)
 
$
279,716

Interest income (expense)
15

 
4

 
(141
)
 
(61,565
)
 
(61,687
)
Loss on extinguishment of debt
—

 
—

 
—

 
(2,051
)
 
(2,051
)
Other income (expense), net
3

 
—

 
216

 
(81
)
 
138

Income (loss) before income taxes
$
301,215

 
$
4,102

 
$
(2,495
)
 
$
(86,706
)
 
$
216,116

 
 
Exploration and Production
 
Drilling and Oil Field Services
 
Midstream Gas Services
 
All Other
 
Consolidated Total
Six Months Ended June 30, 2012
 
 
 
 
 
 
 
 
 
Revenues
$
777,955

 
$
202,408

 
$
50,960

 
$
2,949

 
$
1,034,272

Inter-segment revenue
(155
)
 
(139,467
)
 
(34,591
)
 
10

 
(174,203
)
Total revenues
$
777,800

 
$
62,941

 
$
16,369

 
$
2,959

 
$
860,069

Income (loss) from operations(2)
$
662,499

 
$
8,157

 
$
(6,358
)
 
$
(53,541
)
 
$
610,757

Interest income (expense)
559

 
—

 
(293
)
 
(135,800
)
 
(135,534
)
Bargain purchase gain
124,446

 
—

 
—

 
—

 
124,446

Other income, net
2,010

 
—

 
—

 
377

 
2,387

Income (loss) before income taxes
$
789,514

 
$
8,157

 
$
(6,651
)
 
$
(188,964
)
 
$
602,056

Six Months Ended June 30, 2011
 
 
 
 
 
 
 
 
 
Revenues
$
585,004

 
$
163,992

 
$
104,256

 
$
6,106

 
$
859,358

Inter-segment revenue
(133
)
 
(114,421
)
 
(66,511
)
 
(672
)
 
(181,737
)
Total revenues
$
584,871

 
$
49,571

 
$
37,745

 
$
5,434

 
$
677,621

Income (loss) from operations(2)
$
116,990

 
$
3,990

 
$
(5,098
)
 
$
(43,995
)
 
$
71,887

Interest income (expense)
120

 
(101
)
 
(313
)
 
(120,830
)
 
(121,124
)
Loss on extinguishment of debt
—

 
—

 
—

 
(38,232
)
 
(38,232
)
Other income (expense), net
1,679

 
—

 
(485
)
 
141

 
1,335

Income (loss) before income taxes
$
118,789

 
$
3,889

 
$
(5,896
)
 
$
(202,916
)
 
$
(86,134
)
___________________
(1)
Exploration and production segment income from operations includes net gains of $669.8 million and $170.0 million on commodity derivative contracts for the three-month periods ended June 30, 2012 and 2011, respectively.
(2)
Exploration and production segment income from operations includes a net gain of $415.2 million and a net loss of $107.6 million on commodity derivative contracts for the six-month periods ended June 30, 2012 and 2011, respectively.


46
Table of Contents

Exploration and Production Segment

The Company currently generates the majority of its consolidated revenues and cash flow from the production and sale of oil and natural gas. The Company’s revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas and on the Company’s ability to find and economically develop and produce oil and natural gas reserves. Prices for oil and natural gas fluctuate widely. In order to reduce the Company’s exposure to these fluctuations, the Company enters into commodity derivative contracts for a portion of its anticipated future oil and natural gas production. Reducing the Company’s exposure to price volatility helps ensure that it has adequate funds available for its capital expenditure programs.

The primary factors affecting the financial results of the Company’s exploration and production segment are the prices the Company receives for its oil and natural gas production, the quantity of oil and natural gas it produces and changes in the fair value of commodity derivative contracts. Quarterly comparisons of production and price data are presented in the tables below. Changes in the Company’s results from the 2011 periods to the 2012 periods are the result of increased oil production throughout 2011 and continuing in 2012 due to the Company’s focus on the development of its oil properties located in the Mid-Continent and Permian Basin and the purchase of oil and natural gas properties through the Dynamic Acquisition in April 2012.
 
Three Months Ended June 30,
 
Change
 
2012
 
2011
 
Amount
 
Percent
Production data
 
 
 
 
 
 
 
Oil (MBbls)(1)
4,556

 
2,767

 
1,789

 
64.7
 %
Natural gas (MMcf)
21,903

 
17,239

 
4,664

 
27.1
 %
Total volumes (MBoe)
8,206

 
5,640

 
2,566

 
45.5
 %
Average daily total volumes (MBoe/d)
90

 
62

 
28

 
45.2
 %
Average prices — as reported(2)
 
 
 
 
 
 
 
Oil (per Bbl)(1)
$
85.35

 
$
89.09

 
$
(3.74
)
 
(4.2
)%
Natural gas (per Mcf)
$
1.87

 
$
3.81

 
$
(1.94
)
 
(50.9
)%
Total (per Boe)
$
52.37

 
$
55.34

 
$
(2.97
)
 
(5.4
)%
Average prices — including impact of derivative contract settlements
 
 
 
 
 
 
 
Oil (per Bbl)(1)
$
89.76

 
$
76.26

 
$
13.50

 
17.7
 %
Natural gas (per Mcf)
$
2.39

 
$
3.31

 
$
(0.92
)
 
(27.8
)%
Total (per Boe)
$
56.21

 
$
47.52

 
$
8.69

 
18.3
 %
 
Six Months Ended June 30,
 
Change
 
2012
 
2011
 
Amount
 
Percent
Production data
 
 
 
 
 
 
 
Oil (MBbls)(1)
7,982

 
5,348

 
2,634

 
49.3
 %
Natural gas (MMcf)
37,648

 
34,505

 
3,143

 
9.1
 %
Total volumes (MBoe)
14,257

 
11,099

 
3,158

 
28.5
 %
Average daily total volumes (MBoe/d)
78

 
61

 
17

 
27.9
 %
Average prices — as reported(2)
 
 
 
 
 
 
 
Oil (per Bbl)(1)
$
87.34

 
$
84.59

 
$
2.75

 
3.3
 %
Natural gas (per Mcf)
$
1.96

 
$
3.67

 
$
(1.71
)
 
(46.6
)%
Total (per Boe)
$
54.09

 
$
52.17

 
$
1.92

 
3.7
 %
Average prices — including impact of derivative contract settlements
 
 
 
 
 
 
 
Oil (per Bbl)(1)
$
88.26

 
$
74.33

 
$
13.93

 
18.7
 %
Natural gas (per Mcf)
$
2.37

 
$
3.46

 
$
(1.09
)
 
(31.5
)%
Total (per Boe)
$
55.68

 
$
46.58

 
$
9.10

 
19.5
 %
__________________
(1)
Includes natural gas liquids.
(2)
Prices represent actual average prices for the periods presented and do not include effects of derivative transactions.

47
Table of Contents


Exploration and Production Segment — Three months ended June 30, 2012 compared to the three months ended June 30, 2011

Exploration and production segment revenues increased $117.1 million, or 36.8%, to $434.8 million in the three-month period ended June 30, 2012 from the same period in 2011, as a result of a 1,789 MBbl, or 64.7%, increase in oil production, and a 4,664 MMcf, or 27.1%, increase in natural gas production. These increases were slightly offset by a $3.74 per Bbl, or 4.2%, decrease in the average price received for oil production and a $1.94 per Mcf, or 50.9%, decrease in the average price received for natural gas production. The increase in oil production was due to the continued focus on increased oil drilling throughout 2011 and continuing in 2012 in the Mid-Continent and Permian Basin areas. Additionally, the acquisition of oil and natural gas properties through the Dynamic Acquisition in April 2012 resulted in higher oil production during the three-month period ended June 30, 2012. The increase in natural gas production was primarily a result of the acquisition of oil and natural gas properties through the Dynamic Acquisition in April 2012.

Due to the long-term nature of the Company's investment in the development of its properties, the Company enters into oil and natural gas swaps and collars for a portion of its production in order to stabilize future cash inflows for planning purposes. The Company's derivative contracts are not designated as accounting hedges and, as a result, realized and unrealized gains or losses on commodity derivative contracts are recorded as a component of operating expenses. Internally, management views the settlement of such derivative contracts as adjustments to the price received for oil and natural gas production to determine “effective prices.” Realized gains or losses related to settlements of derivative contracts prior to their respective contractual maturities ("early settlements") are not considered in the calculation of effective prices. The effective price received for oil for the three-month period ended June 30, 2012 was $89.76 per Bbl compared to $76.26 per Bbl during the same period in 2011. The effective price received for natural gas for the three-month period ended June 30, 2012 was $2.39 per Mcf compared to $3.31 per Mcf during the same period in 2011.

During the three-month period ended June 30, 2012, the exploration and production segment reported a $669.8 million net gain on its commodity derivative positions ($89.1 million realized gain and $580.7 million unrealized gain) compared to a $170.0 million net gain on its commodity derivative positions ($18.3 million realized loss and $188.3 million unrealized gain) in the same period in 2011. The realized gain for the three-month period ended June 30, 2012 was due to lower oil prices at the time of settlement compared to the contract price for the Company's oil price swaps. The realized loss for the three-month period ended June 30, 2011 was due to higher oil prices at the time of settlement compared to the contract price for the Company's oil price swaps. Realized gains of $57.3 million resulting from early settlements were included in the realized gain for the three-month period ended June 30, 2012. Realized gains totaling $25.8 million resulting from early settlements were included in the net realized loss for the three-month period ended June 30, 2011. Unrealized gains or losses on derivative contracts represent the change in fair value of open derivative contracts during the period. The unrealized gain on the Company's commodity contracts recorded during the three-month period ended June 30, 2012 was attributable to a decrease in average oil prices at June 30, 2012 compared to the average oil prices at March 31, 2012 or the contract price for contracts entered into during the second quarter of 2012. The unrealized gain on the Company's commodity contracts recorded during the three months ended June 30, 2011 was attributable to a decrease in average oil prices at June 30, 2011 compared to the average oil prices at March 31, 2011 or the contract price for contracts entered into during the second quarter of 2011.

For the three-month period ended June 30, 2012, the Company had income from operations of $786.3 million in its exploration and production segment compared to income from operations of $301.2 million in the same period in 2011. Increases of $117.6 million in oil and natural gas revenues and $499.9 million in gain on derivative contracts were partially offset by increases of $40.6 million in production expense and $65.4 million in depreciation and depletion on oil and natural gas properties along with $9.9 million of acquisition costs related to the Dynamic Acquisition included in general and administrative expenses during the three-month period ended June 30, 2012. See further discussion of these changes under “Consolidated Results of Operations” below.

Exploration and Production Segment — Six months ended June 30, 2012 compared to the six months ended June 30, 2011

Exploration and production segment revenues increased $192.9 million, or 33.0%, to $777.8 million in the six-month period ended June 30, 2012 from the same period in 2011, as a result of a 2,634 MBbl, or 49.3%, increase in oil production, a $2.75 per Bbl, or 3.3%, increase in the average price received for oil production and a 3,143 MMcf, or 9.1%, increase in natural gas production. These increases were slightly offset by a $1.71 per Mcf, or 46.6%, decrease in the average price received for natural gas production. The increase in oil production was due to the continued focus on increased oil drilling throughout 2011 and continuing in 2012 in the Mid-Continent and Permian Basin areas. Additionally, the acquisition of oil and natural gas properties through the Dynamic Acquisition in April 2012 resulted in higher oil production during the six-month period ended June 30, 2012. The increase in natural gas production was primarily a result of the acquisition of oil and natural gas properties through the Dynamic

48
Table of Contents

Acquisition in April 2012.

The effective price received for oil for the six-month period ended June 30, 2012 was $88.26 per Bbl compared to $74.33 per Bbl during the same period in 2011. The effective price received for natural gas for the six-month period ended June 30, 2012 was $2.37 per Mcf compared to $3.46 per Mcf during the same period in 2011.

During the six-month period ended June 30, 2012, the exploration and production segment reported a $415.2 million net gain on its commodity derivative positions ($36.3 million realized loss and $451.5 million unrealized gain) compared to a $107.6 million net loss on its commodity derivative positions ($26.9 million realized loss and $80.7 million unrealized loss) in the same period in 2011. The realized loss for the six-month periods ended June 30, 2012 and 2011 was due to higher oil prices at the time of settlement compared to the contract price for the Company's oil price swaps. Realized gains of $57.3 million resulting from early settlements were included in the net realized loss for the six-month period ended June 30, 2012. Additionally, non-cash realized losses of $117.1 million resulting from the amendment of certain 2012 derivative contracts to contracts maturing in 2014 and 2015 were included in the net realized loss for the six-month period ended June 30, 2012. Realized gains totaling $38.2 million resulting from early settlements were included in the net realized loss for the six-month period ended June 30, 2011. The unrealized gain on the Company's commodity contracts recorded during the six-month period ended June 31, 2012 was attributable to a decrease in average oil prices at June 30, 2012 compared to the average oil prices at December 31, 2011, or the contract price for contracts entered into during the first six months of 2012. The unrealized loss on the Company's commodity contracts recorded during the six-month period ended June 31, 2011 was attributable to an increase in average oil prices at June 30, 2011 compared to the average oil prices at December 31, 2010, or the contract price for contracts entered into during the first six months of 2011.

For the six-month period ended June 30, 2012, the Company had income from operations of $662.5 million in its exploration and production segment compared to income from operations of $117.0 million in the same period in 2011. An increase of $192.1 million in oil and natural gas revenues was partially offset by increases of $50.0 million in production expense and $81.0 million in depreciation and depletion on oil and natural gas properties along with increased general and administrative expenses as a result of the Dynamic Acquisition during the six-month period ended June 30, 2012. See further discussion of these changes under “Consolidated Results of Operations” below. Additionally, the Company recorded a $415.2 million net gain on its commodity derivative contracts for the six months ended June 30, 2012 compared to a $107.6 million net loss for the same period in 2011.

Drilling and Oil Field Services Segment

The financial results of the Company’s drilling and oil field services segment depend primarily on demand and prices that can be charged for its services. On a consolidated basis, drilling and oil field service revenues earned and expenses incurred in performing services for third parties, including third-party working interests in wells the Company operates, are included in drilling and services revenues and expenses. Drilling and oil field service revenues earned and expenses incurred in performing services for the Company’s own account are eliminated in consolidation.

As of June 30, 2012, the Company owned 31 drilling rigs. The table below presents a summary of the Company’s rigs as of June 30, 2012 and 2011:
 
June 30,
 
2012
 
2011
Rigs
 
 
 
Working for SandRidge
21

 
20

Working for third parties
8

 
11

Total operational
29

 
31

Non-operational(1)
2

 
—

Total rigs
31

 
31

____________________
(1)
Includes one rig stacked and one rig that was non-operational at June 30, 2012.

Drilling and Oil Field Services Segment — Three months ended June 30, 2012 compared to the three months ended June 30, 2011

Drilling and oil field services segment revenues increased $5.1 million to $33.6 million in the three-month period ended June 30, 2012 from the same period in 2011 and drilling and oil field services segment expenses increased $4.5 million during the same period to $29.0 million. The increase in revenues and expenses was primarily attributable to an increase in supplies sold

49
Table of Contents

and oil field services work performed for third parties during the three-month period ended June 30, 2012, due to the continued development of the Company's oil properties located in the Mid-Continent and Permian Basin. These increases resulted in income from operations of $4.7 million in the three-month period ended June 30, 2012 compared to income from operations of $4.1 million in the 2011 period.

Drilling and Oil Field Services Segment — Six months ended June 30, 2012 compared to the six months ended June 30, 2011

Drilling and oil field services segment revenues increased $13.4 million to $62.9 million in the six-month period ended June 30, 2012 from the same period in 2011 and drilling and oil field services segment expenses increased $9.2 million during the same period to $54.7 million. The increase in revenues and expenses was primarily attributable to an increase in supplies sold and oil field services work performed for third parties during the six-month period ended June 30, 2012, due to the continued development of the Company's oil properties located in the Mid-Continent and Permian Basin. These increases resulted in income from operations of $8.2 million in the six-month period ended June 30, 2012 compared to income from operations of $4.0 million in the 2011 period.

Midstream Gas Services Segment

Midstream gas services segment revenues consist mostly of revenue from gas marketing, which is a very low-margin business. Midstream gas services are primarily undertaken to realize incremental margins on natural gas purchased at the wellhead, and provide value-added services to customers. On a consolidated basis, midstream and marketing revenues represent natural gas sold on behalf of third parties and the fees the Company charges to gather, compress and treat this natural gas. Gas marketing operating costs represent payments made to third parties for the proceeds from the sale of natural gas owned by such parties, net of any applicable margin and actual costs the Company charges to gather, compress and treat the natural gas. In general, natural gas purchased and sold by the Company’s midstream gas business is priced at a published daily or monthly index price. The primary factors affecting the results of the Company’s midstream gas services segment are the quantity of natural gas the Company gathers, treats and markets and the prices it pays and receives for natural gas.

The Company owns and operates two gas treating plants in west Texas, which remove CO2 from natural gas production and deliver residue gas to nearby pipelines. During 2012, the Company continued with the operational assessment phase of the Century Plant, in Pecos County, Texas, including diverting some of the Company’s natural gas from the Company’s two existing gas treating plants and processing it at the Century Plant during this time. As a result of this assessment, the Century Plant has been taken off line from time to time to resolve certain operational issues. The Company is currently in the process of diverting its high CO2 natural gas production back through the Century Plant and conducting performance testing for Phase I of the Century Plant. Upon successful completion of the performance testing, the use of the Company’s two gas treating plants in west Texas may be limited, the extent of which will depend on certain variables, including natural gas prices and the expected need for such plants to supplement treating capacity at the Century Plant in the future. During the second quarter of 2011, the Company evaluated its gas treating plants for impairment in connection with the operational phase of Phase I of the Century Plant and concluded no impairment was necessary. The Company continued to monitor the status of the Century Plant, the related impact on its gas treating plants and CO2 compression facilities and natural gas prices during the second half of 2011 and first six months of 2012. As of June 30, 2012, no impairment of these plants or facilities was deemed necessary.

Midstream Gas Services Segment — Three months ended June 30, 2012 compared to the three months ended June 30, 2011

Midstream gas services segment revenues for the three-month period ended June 30, 2012 were $8.5 million compared to $15.8 million in the same period in 2011. The decrease in revenue was due to a decrease in third-party volumes the Company marketed of approximately 1.0 Bcf and a decrease in natural gas prices. The decrease in revenue resulted in a loss from operations of $3.6 million for the three-month period ended June 30, 2012 compared to a loss from operations of $2.6 million in the same period in 2011.

Midstream Gas Services Segment — Six months ended June 30, 2012 compared to the six months ended June 30, 2011

Midstream gas services segment revenues for the six-month period ended June 30, 2012 were $16.4 million compared to $37.7 million in the same period in 2011. The decrease in revenue was due to a decrease in third-party volumes the Company marketed of approximately 3.7 Bcf and a decrease in natural gas prices. The decrease in revenue resulted in a loss from operations of $6.4 million for the six-month period ended June 30, 2012 compared to a loss from operations of $5.1 million in the same period in 2011.



50
Table of Contents

Consolidated Results of Operations

Three months ended June 30, 2012 compared to the three months ended June 30, 2011

Revenues. Total revenues increased 31.2% for the three months ended June 30, 2012 from the same period in 2011. This increase was primarily due to the increase in oil and natural gas sales.
 
Three Months Ended June 30,
 
 
 
 
 
2012
 
2011
 
$ Change
 
% Change
 
(In thousands)
Revenues
 
 
 
 
 
 
 
Oil and natural gas
$
429,758

 
$
312,111

 
$
117,647

 
37.7
 %
Drilling and services
33,632

 
28,537

 
5,095

 
17.9
 %
Midstream and marketing
8,852

 
16,313

 
(7,461
)
 
(45.7
)%
Other
6,192

 
7,813

 
(1,621
)
 
(20.7
)%
Total revenues
$
478,434

 
$
364,774

 
$
113,660

 
31.2
 %

Total oil and natural gas revenues increased $117.6 million for the three-month period ended June 30, 2012 compared to the same period in 2011, as a result of an increase in the amount of oil and natural gas produced. This increase was slightly offset by a decrease in the average prices received for oil and natural gas production. See further discussion of oil and natural gas production and prices received during the three-month period ended June 30, 2012 under "Results by Segment - Exploration and Production Segment."

Drilling and services revenues increased $5.1 million for the three-month period ended June 30, 2012 compared to the same period in 2011 due to an increase in supplies sold and oil field services work performed for third parties.

Midstream and marketing revenues decreased $7.5 million, or 45.7%, in the three-month period ended June 30, 2012 compared to the same period in 2011. The decrease was attributable to a decrease in third-party volumes the Company marketed, a decrease in natural gas prices and a decrease in natural gas volumes processed at the Company's gas treating plants for the three-month period ended June 30, 2012 compared to the same period in 2011.

Expenses. Total expenses decreased to ($284.0) million for the three months ended June 30, 2012 compared to $85.1 million for the same period in 2011. The decrease was primarily due to the increase in gain on derivative contracts, partially offset by increases in production expense, depreciation and depletion on oil and natural gas properties and general and administrative expense.
 
Three Months Ended June 30,
 
 
 
 
 
2012
 
2011
 
$ Change
 
% Change
 
(In thousands)
Expenses
 
 
 
 
 
 
 
Production
$
122,481

 
$
81,834

 
$
40,647

 
49.7
 %
Production taxes
11,001

 
12,666

 
(1,665
)
 
(13.1
)%
Drilling and services
19,241

 
18,058

 
1,183

 
6.6
 %
Midstream and marketing
8,559

 
15,873

 
(7,314
)
 
(46.1
)%
Depreciation and depletion — oil and natural gas
139,260

 
73,826

 
65,434

 
88.6
 %
Depreciation and amortization — other
15,348

 
13,275

 
2,073

 
15.6
 %
Accretion on asset retirement obligation
7,965

 
2,360

 
5,605

 
237.5
 %
General and administrative
61,716

 
37,678

 
24,038

 
63.8
 %
Gain on derivative contracts
(669,850
)
 
(169,988
)
 
(499,862
)
 
294.1
 %
Loss (gain) on sale of assets
300

 
(524
)
 
824

 
(157.3
)%
Total expenses
$
(283,979
)
 
$
85,058

 
$
(369,037
)
 
(433.9
)%


51
Table of Contents

Production expense includes the costs associated with the Company’s exploration and production activities, including, but not limited to, lease operating expense and treating costs. Production expenses increased $40.6 million primarily due to operating expenses associated with additional oil wells that began producing during 2011 and 2012, and from oil and natural gas properties acquired through the Dynamic Acquisition. Total production increased 45.5%, with oil production increasing 64.7% and natural gas production increasing 27.1% for the three-month period ended June 30, 2012 compared to the same period in 2011.

Production taxes decreased slightly for the three-month period ended June 30, 2012 compared to the same period in 2011. Production taxes are typically calculated based upon oil and natural gas revenue; however, a significant portion of the increase in the Company's oil and natural gas production for the three-month period ended June 30, 2012 compared to the same period in 2011 was from production in the Gulf of Mexico, as a result of the Dynamic Acquisition, which is not subject to production tax.

Midstream and marketing expenses decreased $7.3 million, or 46.1%, due to decreased natural gas volumes purchased from third parties as a result of decreased natural gas production and a decrease in natural gas volumes processed at the Company's gas treating plants during the three-month period ended June 30, 2012.

Depreciation and depletion for the Company’s oil and natural gas properties increased $65.4 million for the three-month period ended June 30, 2012 from the same period in 2011. The increase was due to an increase of 45.5% in the Company’s combined production volume as well as an increase in the depreciation and depletion per Boe to $16.97 in the three-month period ended June 30, 2012 from $13.09 per Boe in the same period in 2011 primarily as a result of oil and natural gas properties acquired through the Dynamic Acquisition.

Accretion on asset retirement obligation increased $5.6 million as a result of the future plugging and abandonment obligations associated with the oil and natural gas properties acquired through the Dynamic Acquisition.

General and administrative expenses increased $24.0 million, or 63.8%, to $61.7 million for the three-month period ended June 30, 2012 from the same period in 2011. This increase is due primarily to $10.0 million in costs associated with the Dynamic Acquisition in April 2012 and the acquisition of Gulf of Mexico properties in June 2012 and a $7.3 million increase in compensation costs as a result of an increase in the number of employees.

The Company recorded a net gain of $669.8 million ($89.1 million realized gain and $580.7 million unrealized gain) on its commodity derivative contracts for the three-month period ended June 30, 2012 compared to a net gain of $170.0 million ($18.3 million realized loss and $188.3 million unrealized gain) in the same period in 2011. See further discussion of gains and losses on commodity derivative contracts under “Results by Segment—Exploration and Production Segment.”

Other Income (Expense), Taxes and Net Income Attributable to Noncontrolling Interest. Changes in other income (expense), taxes and net income attributable to noncontrolling interest are presented in the table below. 
 
Three Months Ended June 30,
 
 
 
 
 
2012
 
2011
 
$ Change
 
% Change
 
(In thousands)
Other income (expense)
 
 
 
 
 
 
 
Interest expense
$
(68,569
)
 
$
(61,687
)
 
$
(6,882
)
 
11.2
 %
Bargain purchase gain
124,446

 
—

 
124,446

 
100.0
 %
Loss on extinguishment of debt
—

 
(2,051
)
 
2,051

 
(100.0
)%
Other (expense) income, net
(81
)
 
138

 
(219
)
 
(158.7
)%
Total other expense
55,796

 
(63,600
)
 
119,396

 
(187.7
)%
Income before income taxes
818,209

 
216,116

 
602,093

 
278.6
 %
Income tax benefit
(103,658
)
 
(7,054
)
 
(96,604
)
 
1,369.5
 %
Net income
921,867

 
223,170

 
698,697

 
313.1
 %
Less: net income attributable to noncontrolling interest
99,004

 
13,154

 
85,850

 
652.7
 %
Net income attributable to SandRidge Energy, Inc.
$
822,863

 
$
210,016

 
$
612,847

 
291.8
 %

Interest expense increased $6.9 million for the three-month period ended June 30, 2012 compared to the same period in 2011, due primarily to interest on the 8.125% Senior Notes issued in April 2012. This was partially offset by a $2.6 million increase in the unrealized gain recorded on the Company's interest rate swap during the three-month period ended June 30, 2012 compared

52
Table of Contents

to the same period in 2011.

The bargain purchase gain recorded during the three-month period ended June 30, 2012 resulted from the excess of net assets acquired over consideration paid in the Dynamic Acquisition. The Company was able to acquire Dynamic for less than the estimated fair value of its net assets due to less competition to acquire Dynamic's properties due to their offshore location.

In connection with the redemption of the 8.625% Senior Notes that remained outstanding following the completion of the Company's March 2011 tender offer, the Company recognized a loss on extinguishment of debt of $2.0 million in the second quarter of 2011. The loss represents the premium paid to purchase and redeem these notes and the unamortized debt issuance costs associated with the remaining notes.

The Company reported an income tax benefit of $103.7 million for the three-month period ended June 30, 2012. The benefit was primarily attributable to the release of a portion of the Company's valuation allowance against its net deferred tax asset during the period. Net deferred tax liabilities recorded as a result of the Dynamic Acquisition reduced the Company's existing net deferred tax asset position, allowing a corresponding reduction in the valuation allowance against the net deferred tax asset. In the second quarter of 2011, the Company completed its valuation of assets acquired and liabilities assumed related to the acquisition of Arena in order to finalize the purchase price allocation. In connection therewith, the Company recorded an additional net deferred tax liability of $7.0 million. The tax benefit of $7.1 million for the three-month period ended June 30, 2011 is primarily comprised of the partial release of the Company's previously recorded valuation allowance against its net deferred tax asset.

Net income attributable to noncontrolling interest increased to $99.0 million for the three-month period ended June 30, 2012 from $13.2 million during the same period in 2011 due to the completion of the Permian Trust's initial public offering in August 2011 and the Mississippian Trust II's initial public offering in April 2012, as it reflects the portion of net income attributable to beneficial interests of the trusts held by third parties.

Six months ended June 30, 2012 compared to the six months ended June 30, 2011

Revenues. Total revenues increased 26.9% for the six months ended June 30, 2012 from the same period in 2011. This increase was primarily due to the increase in oil and natural gas sales.
 
Six Months Ended June 30,
 
 
 
 
 
2012
 
2011
 
$ Change
 
% Change
 
(In thousands)
Revenues
 
 
 
 
 
 
 
Oil and natural gas
$
771,123

 
$
579,053

 
$
192,070

 
33.2
 %
Drilling and services
62,941

 
49,571

 
13,370

 
27.0
 %
Midstream and marketing
17,158

 
38,570

 
(21,412
)
 
(55.5
)%
Other
8,847

 
10,427

 
(1,580
)
 
(15.2
)%
Total revenues
$
860,069

 
$
677,621

 
$
182,448

 
26.9
 %

Total oil and natural gas revenues increased $192.1 million for the six-month period ended June 30, 2012 compared to the same period in 2011, as a result of an increase in the amount of oil and natural gas produced and an increase in the average price received for oil production. These increases were slightly offset by a decrease in the average price received for natural gas production. See further discussion of oil and natural gas production and prices received during the six-month period ended June 30, 2012 under "Results by Segment - Exploration and Production Segment."

Drilling and services revenues increased $13.4 million for the six-month period ended June 30, 2012 compared to the same period in 2011 due to an increase in supplies sold and oil field services work performed for third parties.

Midstream and marketing revenues decreased $21.4 million, or 55.5%, in the six-month period ended June 30, 2012 compared to the same period in 2011. The decrease was attributable to a decrease in third-party volumes the Company marketed due to decreased natural gas production, a decrease in natural gas prices and a decrease in natural gas volumes processed at the Company's gas treating plants during the six-month period ended June 30, 2012 compared to the same period in 2011.


53
Table of Contents

Expenses. Total expenses decreased to $249.3 million for the six months ended June 30, 2012 compared to $605.7 million for the same period in 2011. The decrease was due to the significant increase in gain on derivative contracts, partially offset by increases in production expense, depreciation and depletion on oil and natural gas properties and general and administrative expense.
 
Six Months Ended June 30,
 
 
 
 
 
2012
 
2011
 
$ Change
 
% Change
 
(In thousands)
Expenses
 
 
 
 
 
 
 
Production
$
205,791

 
$
155,791

 
$
50,000

 
32.1
 %
Production taxes
23,255

 
23,242

 
13

 
0.1
 %
Drilling and services
36,802

 
33,099

 
3,703

 
11.2
 %
Midstream and marketing
16,513

 
38,156

 
(21,643
)
 
(56.7
)%
Depreciation and depletion — oil and natural gas
226,326

 
145,286

 
81,040

 
55.8
 %
Depreciation and amortization — other
29,860

 
26,368

 
3,492

 
13.2
 %
Accretion on asset retirement obligation
10,572

 
4,786

 
5,786

 
120.9
 %
General and administrative
112,017

 
72,091

 
39,926

 
55.4
 %
(Gain) loss on derivative contracts
(415,204
)
 
107,640

 
(522,844
)
 
(485.7
)%
Loss (gain) on sale of assets
3,380

 
(725
)
 
4,105

 
(566.2
)%
Total expenses
$
249,312

 
$
605,734

 
$
(356,422
)
 
(58.8
)%

Production expenses increased $50.0 million primarily due to operating expenses associated with additional oil wells that began producing during 2011 and the first six months of 2012, and from oil and natural gas properties acquired through the Dynamic Acquisition. Total production increased 28.5% with oil production increasing 49.3% for the six-month period ended June 30, 2012 compared to the same period in 2011.

Production taxes remained unchanged for the six-month period ended June 30, 2012 compared to the 2011 period. A significant portion of the increase in the Company's oil and natural gas production for the six-month period ended June 30, 2012 compared to the same period in 2011 was from production in the Gulf of Mexico, as a result of the Dynamic Acquisition, which is not subject to production tax.

Midstream and marketing expenses decreased $21.6 million, or 56.7%, due to decreased natural gas volumes purchased from third parties as a result of decreased natural gas production and a decrease in natural gas volumes processed at the Company's gas treating plants during the six-month period ended June 30, 2012.

Depreciation and depletion for the Company’s oil and natural gas properties increased $81.0 million for the six-month period ended June 30, 2012 from the same period in 2011. The increase was due to an increase of 28.5% in the Company’s combined production volume as well as an increase in the depreciation and depletion per Boe to $15.87 in the six-month period ended June 30, 2012 from $13.09 per Boe in the same period in 2011 primarily as a result of oil and natural gas properties acquired through the Dynamic Acquisition.

Accretion on asset retirement obligation increased $5.8 million as a result of the future plugging and abandonment obligations associated with the oil and natural gas properties the Company acquired through the Dynamic Acquisition.

General and administrative expenses increased $39.9 million, or 55.4%, to $112.0 million for the six-month period ended June 30, 2012 from the same period in 2011. This increase is due primarily to $12.5 million in costs associated with the Dynamic Acquisition in April 2012 and the acquisition of Gulf of Mexico properties in June 2012, a $14.0 million increase in compensation costs as a result of an increase in number of employees, a $4.7 million increase in legal and consulting fees and a $3.6 million increase in advertising expense.

The Company recorded a net gain of $415.2 million ($36.3 million realized loss and $451.5 million unrealized gain) on its commodity derivative contracts for the six-month period ended June 30, 2012 compared to a net loss of $107.6 million ($26.9 million realized loss and $80.7 million unrealized loss) in the same period in 2011. See further discussion of gains and losses on commodity derivative contracts under “Results by Segment—Exploration and Production Segment.”


54
Table of Contents

Other Income (Expense), Taxes and Net Income Attributable to Noncontrolling Interest. Changes in other income (expense), taxes and net income attributable to noncontrolling interest are presented in the table below. 
 
Six Months Ended June 30,
 
 
 
 
 
2012
 
2011
 
$ Change
 
% Change
 
(In thousands)
Other income (expense)
 
 
 
 
 
 
 
Interest expense
$
(135,534
)
 
$
(121,124
)
 
$
(14,410
)
 
11.9
 %
Bargain purchase gain
124,446

 
—

 
124,446

 
100.0
 %
Loss on extinguishment of debt
—

 
(38,232
)
 
38,232

 
(100.0
)%
Other income, net
2,387

 
1,335

 
1,052

 
78.8
 %
Total other expense
(8,701
)
 
(158,021
)
 
149,320

 
(94.5
)%
Income (loss) before income taxes
602,056

 
(86,134
)
 
688,190

 
(799.0
)%
Income tax benefit
(103,587
)
 
(6,967
)
 
(96,620
)
 
1,386.8
 %
Net income (loss)
705,643

 
(79,167
)
 
784,810

 
(991.3
)%
Less: net income attributable to noncontrolling interest
100,958

 
13,161

 
87,797

 
667.1
 %
Net income (loss) attributable to SandRidge Energy, Inc.
$
604,685

 
$
(92,328
)
 
$
697,013

 
(754.9
)%

Interest expense increased $14.4 million for the six-month period ended June 30, 2012 compared to the same period in 2011 due to interest on the 8.125% Senior Notes issued in April 2012 and fees incurred to secure committed financing for the Dynamic Acquisition. The Company elected to issue senior notes to fund the cash portion of the Dynamic Acquisition rather than utilize the committed financing. As a result, the fees associated with the committed financing of $10.9 million were fully expensed during the six-month period ended June 30, 2012. The fees and interest on the 8.125% Senior Notes were partially offset by a decrease in interest expense related to the senior credit facility as no amounts were outstanding during the six-month period ended June 30, 2012.
    
The bargain purchase gain recorded during the six-month period ended June 30, 2012 resulted from the excess of net assets acquired over consideration paid in the Dynamic Acquisition.

In connection with the tender offer to repurchase and the redemption of the 8.625% Senior Notes, the Company recognized a loss on extinguishment of debt of $38.2 million for the six-month period ended June 30, 2011. The loss represents the premium paid to purchase these notes and the unamortized debt issuance costs associated with the notes.

The Company reported an income tax benefit of $103.6 million for the six-month period ended June 30, 2012. The benefit was primarily attributable to the release of a portion of the Company's valuation allowance against its net deferred tax asset during the period. Net deferred tax liabilities recorded as a result of the Dynamic Acquisition reduced the Company's existing net deferred tax asset position, allowing a corresponding reduction in the valuation allowance against the net deferred tax asset. In the second quarter of 2011, the Company completed its valuation of assets acquired and liabilities assumed related to the acquisition of Arena in order to finalize the purchase price allocation. In connection therewith, the Company recorded an additional net deferred tax liability of $7.0 million. The tax benefit of $7.0 million for the six-month period ended June 30, 2011 is primarily comprised of the partial release of the Company's previously recorded valuation allowance against its net deferred tax asset.

Net income attributable to noncontrolling interest increased to $101.0 million for the six-month period ended June 30, 2012 from $13.2 million during the same period in 2011 due to the completion of the Mississippian Trust I initial public offering in April 2011, the Permian Trust's initial public offering in August 2011 and the Mississippian Trust II initial public offering in April 2012, as it reflects the portion of net income attributable to beneficial interests of the trusts held by third parties.

Liquidity and Capital Resources

The Company’s primary sources of liquidity and capital resources are cash flow from operations, borrowings under the Company’s senior credit facility, the issuance of equity and debt securities and proceeds from sales or other monetizations of assets. The Company received approximately $272.5 million in January 2012 from the sale of working interests in the Mississippian formation and related drilling carry, and, as described in "Recent Developments" above, the Company received net proceeds of approximately $587.1 million in April 2012 as partial consideration for the conveyance of royalty interests in certain of the Company’s oil and natural gas properties to the Mississippian Trust II, and approximately $130.0 million in June 2012 for the sale

55
Table of Contents

of its tertiary recovery properties.

The Company’s primary uses of capital are expenditures related to its oil and natural gas properties, such as costs related to drilling and completion of wells, including to fulfill its drilling commitments to the Royalty Trusts, and other fixed assets, the acquisition of oil and natural gas properties, the repayment of amounts outstanding under its senior credit facility, the payment of dividends on its outstanding convertible perpetual preferred stock and interest payments on its outstanding debt. The Company maintains access to funds that may be needed to meet capital funding requirements through its senior credit facility.

Working Capital

The Company’s working capital balance fluctuates as a result of the timing and amount of borrowings or repayments under its senior credit facility and changes in the fair value of its outstanding commodity derivative instruments. Absent any significant effects from its commodity derivative instruments, the Company historically maintains a working capital deficit or a relatively small amount of positive working capital because the Company’s capital spending generally has exceeded the Company’s cash flows from operations and it historically has used excess cash to pay down borrowings outstanding, if any, under its credit arrangements.

At June 30, 2012, the Company had a working capital surplus of $157.4 million compared to a deficit of $257.7 million at December 31, 2011. Current assets increased $538.9 million at June 30, 2012, compared to current assets at December 31, 2011, primarily due to a $213.4 million increase in cash and cash equivalents and a $200.1 million increase in asset positions on the Company's current derivative contracts. The increase in cash and cash equivalents is primarily due to net proceeds received as partial consideration for the conveyance of royalty interests in certain of the Company’s oil and natural gas properties to the Mississippian Trust II in April 2012 and the sale of the Company's tertiary recovery properties in June 2012. The increase in the Company's asset positions on its current derivative contracts is due to a decrease in oil prices from December 31, 2011. Current liabilities increased $123.9 million, primarily due to a $162.6 million increase in accounts payable and accrued expenses as a result of increased drilling activity and payables assumed in the Dynamic Acquisition and a $107.9 million increase in the Company's current asset retirement obligation due to future plugging and abandonment obligations assumed from Dynamic. These increases were partially offset by a $108.5 million decrease in the Company’s current liability positions on derivative contracts as a result of decreased oil prices.

The Company expects to fund its planned capital expenditures budget, debt service requirements and working capital needs for the remainder of 2012 with cash flows from operating activities, its existing cash balances, availability under the senior credit facility, potential access to capital markets, potential sales of royalty trust units and potential sales of working interests, including those with associated drilling carries. However, a significant portion of the Company’s 2012 capital expenditures budget is discretionary and can be curtailed, if necessary, based on oil and natural gas prices and the availability of the sources of funds described above.

Cash Flows

The Company’s cash flows for the six-month periods ended June 30, 2012 and 2011 are presented in the following table and discussed below:
 
Six Months Ended
June 30,
 
2012
 
2011
 
(In thousands)
Cash flows provided by operating activities
$
417,706

 
$
257,542

Cash flows used in investing activities
(1,463,756
)
 
(497,612
)
Cash flows provided by financing activities
1,259,442

 
238,822

Net increase (decrease) in cash and cash equivalents
$
213,392

 
$
(1,248
)

Cash Flows from Operating Activities

The Company’s operating cash flow is mainly influenced by the prices the Company receives for its oil and natural gas production; the quantity of oil and natural gas it produces; settlements on derivative contracts; third-party demand for its drilling rigs and oil field services and the rates it is able to charge for these services; and the margins it obtains from its natural gas and CO2 gathering and treating contracts.


56
Table of Contents

Net cash provided by operating activities for the six-month periods ended June 30, 2012 and 2011 was $417.7 million and $257.5 million, respectively. The increase in cash provided by operating activities in the 2012 period compared to the 2011 period was primarily due to an increase in oil and natural gas sales as a result of increased oil and natural gas production and prices received for oil production during the six-month period ended June 30, 2012 compared to the same period in 2011.

Cash Flows from Investing Activities

The Company dedicates and expects to continue to dedicate a substantial portion of its capital expenditure program toward the development, production and acquisition of oil and natural gas reserves. These capital expenditures are necessary to offset inherent declines in production and proven reserves, which is typical in the capital-intensive oil and natural gas industry.

Cash flows used in investing activities increased to $1,463.8 million in the six-month period ended June 30, 2012 from $497.6 million in the same period in 2011 due to an increase in capital expenditures, primarily for the continued development of the Company’s oil properties, and an increase in acquisitions, primarily related to the Dynamic Acquisition in April 2012. These amounts were partially offset by increased proceeds from the sale of assets, including the sale of working interests to Repsol, and the sale of the Company's tertiary recovery properties during the six-month period ended June 30, 2012. Proceeds from the sale of assets totaled $420.9 million in the six-month period ended June 30, 2012 compared to $369.3 million in the same period in 2011.

Capital Expenditures. The Company’s capital expenditures, on an accrual basis, by segment for the six-month periods ended June 30, 2012 and 2011 are summarized below:
 
Six Months Ended
June 30,
 
2012
 
2011
 
(In thousands)
Capital Expenditures
 
 
 
Exploration and production
$
1,010,248

 
$
812,626

Drilling and oil field services
13,752

 
14,793

Midstream gas services
41,729

 
8,635

Other
65,983

 
24,011

Capital expenditures, excluding acquisitions
1,131,712

 
860,065

Acquisitions
761,575

 
9,149

Total
$
1,893,287

 
$
869,214


Cash Flows from Financing Activities

The Company’s financing activities provided $1,259.4 million in cash for the six-month period ended June 30, 2012 compared to $238.8 million in the same period in 2011. Cash provided by financing activities during the 2012 period was primarily comprised of $750.0 million from the issuance of the 8.125% Senior Notes, $587.1 million from the issuance of Mississippian Trust II common units, and $123.5 million of proceeds from the sale of Mississippian Trust I and Permian Trust common units. These proceeds were offset by $76.8 million in distributions to royalty trust unitholders, $45.3 million in cash paid to settle financing derivatives, $27.8 million in dividends paid on the Company’s 8.5%, 6.0% and 7.0% convertible perpetual preferred stock and $27.3 million in debt issuance costs.

Cash provided by financing activities during the six months ended June 30, 2011 was primarily comprised of $880.7 million of net proceeds from the issuance of the 7.5% Senior Notes and $336.9 million of net proceeds from the issuance of common units by the Mississippian Trust I, offset by the purchase and redemption of $650.0 million aggregate principal amount of the 8.625% Senior Notes, the premium of $30.3 million paid in connection with the purchase and redemption of the 8.625% Senior Notes, $260.0 million of net repayments under the senior credit facility and $29.0 million of dividends paid on the Company’s 8.5%, 6.0% and 7.0% convertible perpetual preferred stock.


57
Table of Contents

Indebtedness

Long-term obligations under the senior credit facility, senior notes and other long-term debt consist of the following at June 30, 2012 (in thousands): 
Senior Floating Rate Notes due 2014
$
350,000

Senior credit facility
—

9.875% Senior Notes due 2016, net of $9,909 discount
355,591

8.0% Senior Notes due 2018
750,000

8.75% Senior Notes due 2020, net of $6,159 discount
443,841

7.5% Senior Notes due 2021
900,000

8.125% Senior Notes due 2022
750,000

Total debt
$
3,549,432


The indentures governing the senior notes referred to above contain covenants imposing certain restrictions on the Company’s activities, including, but not limited to, limitations on the incurrence of indebtedness, payment of dividends, investments, asset sales, certain asset purchases, transactions with related parties and consolidations or mergers.

Maturities of Long-Term Debt. As of June 30, 2012, aggregate maturities of long-term debt, excluding discounts, for the next five fiscal years are as follows (in thousands):
 
2012
$
—

2013
—

2014
350,000

2015
—

2016
365,500

Thereafter
2,850,000

Total debt
$
3,565,500


Senior Credit Facility. The amount the Company may borrow under its senior credit facility is limited to a borrowing base, and is subject to periodic redeterminations. The Company pays a 0.5% commitment fee on any available portion of the senior credit facility. Effective March 29, 2012, the borrowing base was increased to $1.0 billion from $790.0 million as further discussed below. The borrowing base is determined based upon the discounted present value of future cash flows attributable to the Company’s proved reserves. Because the value of the Company’s proved reserves is a key factor in determining the amount of the borrowing base, changing commodity prices and the Company’s success in developing reserves may affect the borrowing base.

At June 30, 2012, the Company had no amount outstanding under the senior credit facility and $29.5 million in outstanding letters of credit, which reduced the availability under the senior credit facility to $972.0 million at June 30, 2012. The senior credit facility matures on March 29, 2017, unless neither the Company’s Senior Floating Rate Notes nor the Company’s 9.875% Senior Notes have been repaid or refinanced by September 30, 2015 with a source of funds other than the senior credit facility, in which case the senior credit facility will mature on November 15, 2015.

On March 29, 2012, the senior credit facility was amended and restated to, among other things, (a) increase the borrowing base to $1.0 billion from $790.0 million, (b) allow for the incurrence or issuance of additional debt (including up to $750.0 million of unsecured debt to finance the cash portion of the Dynamic purchase price and the related costs and expenses), (c) permit the Company to designate certain of its subsidiaries as unrestricted subsidiaries, and (d) effective on and after June 30, 2012, establish the financial covenants as maintaining agreed upon levels for (i) ratio of total funded debt to EBITDA, which may not exceed 4.5:1.0 at each quarter end, calculated using the last four completed fiscal quarters and (ii) ratio of current assets to current liabilities, which must be at least 1.0:1.0 at each quarter end. If no amounts are drawn under the senior credit facility when calculating the ratio of total funded debt to EBITDA, the Company’s debt is reduced by its cash balance in excess of $10.0 million. In the current ratio calculation, any amounts available to be drawn under the senior credit facility are included in current assets, and unrealized assets and liabilities resulting from mark-to-market adjustments on the Company’s derivative contracts are disregarded. As of and during the three and six-month period ended June 30, 2012, the Company was in compliance with all applicable financial covenants under the senior credit facility.

58
Table of Contents


Issuance of 8.125% Senior Notes due 2022. As discussed in "Recent Developments," the Company issued $750.0 million of unsecured 8.125% Senior Notes in April 2012, concurrent with the closing of the Dynamic Acquisition to finance the cash portion of the consideration paid in the Dynamic Acquisition. The 8.125% Senior Notes bear interest at a fixed rate of 8.125% per annum, payable semi-annually, with the principal due on October 15, 2022. Prior to 2017, the 8.125% Senior Notes are redeemable, in whole or in part, at a specified redemption price plus accrued and unpaid interest. The notes are jointly and severally guaranteed unconditionally, in full, on an unsecured basis by certain of the Company’s wholly owned subsidiaries.

For more information about the senior credit facility and the senior notes, see Note 8 to the unaudited condensed consolidated financial statements included in this Quarterly Report.

Outlook

The Company’s 2012 budget for capital expenditures, including expenditures related to Dynamic and the Company's drilling programs for the Mississippian Trust I, the Permian Trust and the Mississippian Trust II, is approximately $2.1 billion. The majority of the Company’s capital expenditures are discretionary and could be curtailed if the Company’s cash flows decline from expected levels or if the Company is unable to obtain capital on attractive terms. The Company and one of its wholly owned subsidiaries have entered into development agreements with the Mississippian Trust I, the Permian Trust and the Mississippian Trust II that obligate the Company to drill, or cause to be drilled, a specified number of wells within specific areas of mutual interest for each trust by December 31, 2015, March 31, 2016 and December 31, 2016, respectively. Additionally, the Company has incurred, and will have to continue to incur, capital expenditures to achieve production targets contained in certain gathering and treating arrangements.

The Company is dependent on the availability of borrowings under its senior credit facility, along with cash flows from operating activities, to fund its capital expenditures. Based on current cash balances, anticipated oil and natural gas prices and production, availability under the senior credit facility, potential access to capital markets, potential sales of royalty trust units and potential sales of working interests, including those with associated drilling carries, the Company expects to be able to fund its planned capital expenditures budget, debt service requirements and working capital needs for the remainder of 2012. The Company plans to fund the remainder of its 2012 budget for capital expenditures with cash flows from operations, its existing cash balances, availability under its senior credit facility and potential access to capital markets. However, a substantial or extended decline in oil or natural gas prices could have a material adverse effect on the Company’s financial position, results of operations, cash flows and quantities of oil and natural gas reserves that may be economically produced, which could adversely impact the Company’s ability to comply with the financial covenants under its senior credit facility, which in turn would limit further borrowings to fund capital expenditures.

The Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil and natural gas, each of which depend on numerous factors beyond the Company’s control such as economic conditions, regulatory developments and competition from other energy sources. Oil and natural gas prices historically have been volatile and may be subject to significant fluctuations in the future. The Company’s derivative arrangements serve to mitigate a portion of the effect of this price volatility on its cash flows, and while fixed price swap contracts are in place for the majority of expected oil production for 2012 and 2013, fixed price swap contracts are in place for only a portion of expected oil production for 2014 and 2015. No fixed price swap contracts are in place for the Company’s natural gas production beyond 2012 or oil production beyond 2015. The Company may increase or decrease planned capital expenditures depending on oil and natural gas prices, the availability of capital through asset sales and the issuance of additional equity or long-term debt.

As an alternative to borrowing under its senior credit facility, the Company may choose to issue long-term debt or equity in the public or private markets, or both. In addition, the Company may from time to time seek to retire or purchase its outstanding securities through cash purchases and/or exchanges in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, the Company’s liquidity requirements, contractual restrictions and other factors.

As of June 30, 2012, the Company’s cash and cash equivalents were $421.1 million, including $4.9 million attributable to the Company’s consolidated VIEs which is available to satisfy only obligations of the VIEs. The Company had approximately $3.5 billion in total debt outstanding and $29.5 million in outstanding letters of credit with no amount outstanding under its senior credit facility at June 30, 2012. As of and for the three and six-month periods ended June 30, 2012, the Company was in compliance with applicable covenants under all of its senior notes and senior credit facility. As of July 31, 2012, the Company’s cash and cash equivalents were approximately $304.6 million, including $4.5 million attributable to the Company’s consolidated VIEs. Additionally, there was no amount outstanding under the Company’s senior credit facility and $29.5 million outstanding in letters of credit.

59
Table of Contents


Contractual Obligations

From time to time, the Company enters into transactions that can give rise to significant contractual obligations. Since December 31, 2011 the Company has completed the Dynamic Acquisition and the Mississippian Trust II public offering in April 2012 and the acquisition of Gulf of Mexico properties in June 2012. These transactions resulted in the following contractual obligations, which are in addition to contractual obligations of the Company that were presented in the 2011 Form 10-K:

•
Asset Retirement Obligation Resulting from Dynamic Acquisition and Acquisition of Gulf of Mexico Properties. As of June 30, 2012, amounts associated with acquired properties are approximately $38.2 million, $69.7 million, $42.1 million, $29.3 million, $42.1 million and $135.5 million due in 2012, 2013, 2014, 2015, 2016 and thereafter, respectively.

•
Drilling Contracts with Third-Parties Resulting from Dynamic Acquisition. As of June 30, 2012, future commitments to third-party rig operators are approximately $26.8 million and $20.0 million in 2012 and 2013, respectively.

•
8.125% Senior Notes Issued in Conjunction with Dynamic Acquisition. The principal amount due of $750.0 million in October 2022 is included in the maturities of long term debt table above. Interest payments due on the 8.125% Senior Notes as of June 30, 2012 are $30.5 million for 2012, $60.9 million per year for 2013 through 2016 and $353.3 million thereafter.

•
Development Agreement with Royalty Trusts. The estimated cost at June 30, 2012 to fulfill the drilling obligations to the Royalty Trusts was approximately $622.0 million. See Note 3 to the unaudited condensed consolidated financial statements included in this Quarterly Report for discussion of the drilling obligations.

Valuation Allowance

In 2008 and 2009, the Company recorded full cost ceiling impairments totaling $3.5 billion on its oil and natural gas assets, resulting in the Company being in a net deferred tax asset position. Management considered all available evidence and concluded that it was more likely than not that some or all of the deferred tax assets would not be realized and established a valuation allowance against the Company's net deferred tax asset in the period ending December 31, 2008. The valuation allowance has been maintained since 2008. See Note 13 to the unaudited condensed consolidated financial statements included in this Quarterly Report for more discussion on the establishment of the valuation allowance.
Management continues to closely monitor all available evidence in considering whether to maintain a valuation allowance on its net deferred tax asset. Factors considered are, but not limited to, the reversal periods of existing deferred tax liabilities and deferred tax assets, the historical earnings of the Company and the prospects of future earnings. While the Company's earnings are trending upward and prospects of future earnings may exist, the Company's 36-month cumulative earnings at June 30, 2012 remained at a loss. For purposes of the valuation allowance analysis, “earnings” is defined as pre-tax earnings as adjusted for permanent tax adjustments.
The current year marks the sixth anniversary of the Company. In its relatively short history the Company has experienced significant earnings volatility due to substantial changes in the market price of natural gas. In 2008, the Company's earnings were primarily derived from natural gas sales and during 2008 and 2009 the market price of natural gas declined substantially. Since 2009, natural gas prices have remained relatively low. In 2008, the Company engaged in a strategy to change its focus from the exploration and production of natural gas to that of oil based on the view that natural gas prices would remain under long-term pressure due to the continued drilling in gas focused plays and that oil would provide a more stable revenue stream for the Company over the long-term. As a result of this strategy, the Company's revenues are now primarily derived from oil sales and the Company continues to take additional steps to further ensure shareholder value and future profitability.
The Company's revenue, profitability and future growth are substantially dependent upon prevailing and future prices for oil and natural gas. The markets for these commodities continue to be volatile. Relatively modest drops in prices can significantly affect the Company's financial results and impede its growth. Changes in oil and natural gas prices have a significant impact on the value of the Company's reserves and on its cash flow. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas and a variety of additional factors that are beyond the Company's control. Due to these factors, management has placed a lower weight on the prospects of future earnings in its overall analysis of the valuation allowance.

60
Table of Contents

In evaluating whether to release all or a portion of the valuation allowance, the Company concluded that the objectively verifiable negative evidence of cumulative losses in the recent years outweighs the subjective positive evidence of the upward trend in recent earnings continuing through the prospects of future earnings. Accordingly, the Company has not changed its judgment regarding the need for a full valuation allowance against its net deferred tax asset. However, a continued and sustained increase in the Company's profitability resulting from its shift in focus from natural gas production to oil production could lead to the reversal of its valuation allowance in the near future. The valuation allowance at December 31, 2011 was $725.9 million and has been reduced during the three-month period ended June 30, 2012 by $103.3 million as a result of the net deferred tax liability recorded as part of the Dynamic Acquisition. See Note 2 to the unaudited condensed consolidated financial statements included in this Quarterly Report for further information on the Dynamic Acquisition. The amount of the potential release of the valuation allowance and corresponding income tax benefit depend on many factors including, but not limited to, purchase accounting entries related to the Dynamic Acquisition, future potential acquisitions and divestitures, the results of current year operations, and the prospects of future earnings.

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

General

This discussion provides information about the financial instruments the Company uses to manage commodity prices and interest rate volatility, including instruments used to manage commodity prices for production attributable to the Royalty Trusts. All contracts are settled in cash and do not require the actual delivery of a commodity at settlement.

Commodity Price Risk. The Company’s most significant market risk relates to the prices it receives for its oil and natural gas production. Due to the historical price volatility of these commodities, the Company periodically has entered into, and expects in the future to enter into, derivative arrangements for the purpose of reducing the variability of oil and natural gas prices the Company receives for its production. From time to time, the Company enters into commodity pricing derivative contracts for a portion of its anticipated production volumes depending upon management’s view of opportunities under the then-prevailing current market conditions. The Company’s senior credit facility limits its ability to enter into derivative transactions to 85% of expected production volumes from estimated proved reserves.

The Company uses, and may continue to use, a variety of commodity-based derivative contracts, including fixed price swaps, collars and basis swaps. The Company’s oil and diesel fixed price swap transactions are settled based upon the average daily prices for the calendar month or quarter of the contract period. The Company’s natural gas fixed price swap transactions are settled based upon New York Mercantile Exchange ("NYMEX") prices, and the Company’s natural gas basis swap transactions are settled based upon the index price of natural gas at the Waha hub, a west Texas gas marketing and delivery center, and the Houston Ship Channel. The Company's oil basis swap transactions are settled based upon the spread between the NYMEX or Argus West Texas Intermediate price and the Argus Louisiana Light Sweet price. The Company’s natural gas collars are settled based upon the NYMEX prices on the penultimate commodity business day for the relevant contract. Natural gas collars only result in a cash settlement when the settlement price exceeds the fixed-price ceiling or falls below the fixed-price floor. Settlement for oil and diesel derivative contracts occurs in the succeeding month or quarter and natural gas derivative contracts are settled in the production month.

The Company has not designated any of its derivative contracts as hedges for accounting purposes. The Company records all derivative contracts at fair value, which reflects changes in commodity prices. Changes in fair values of the Company’s derivative contracts are recognized as unrealized gains and losses in current period earnings. As a result, the Company’s current period earnings may be significantly affected by changes in the fair value of its commodity derivative contracts. Changes in fair value are principally measured based on period-end prices compared to the contract price.

See Note 9 to the Company’s unaudited condensed consolidated financial statements included in this Quarterly Report for a summary of the Company’s open commodity derivative contracts.


61
Table of Contents

The following table summarizes the cash settlements and valuation gains and losses on the Company’s commodity derivative contracts for the three and six-month periods ended June 30, 2012 and 2011(in thousands):
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
Realized (gain) loss(1)
$
(89,120
)
 
$
18,273

 
$
36,336

 
$
26,881

Unrealized (gain) loss
(580,730
)
 
(188,261
)
 
(451,540
)
 
80,759

(Gain) loss on commodity derivative contracts
$
(669,850
)
 
$
(169,988
)
 
$
(415,204
)
 
$
107,640

____________________
(1)
The three and six-month periods ended June 30, 2012 included $57.3 million of realized gains on early settlements. The six-month period ended June 30, 2012 also included $117.1 million non-cash realized losses on derivative contracts amended in January 2012. The three and six-month periods ended June 30, 2011 included $25.8 million and $38.2 million of realized gains on early settlements, respectively.

Credit Risk. All of the Company’s hedging transactions have been carried out in the over-the-counter market. The use of hedging transactions involves the risk that the counterparties may be unable to meet the financial terms of the transactions. The counterparties for all of the Company’s hedging transactions have an “investment grade” credit rating. The Company monitors on an ongoing basis the credit ratings of its hedging counterparties and considers its counterparties’ credit default risk ratings in determining the fair value of its derivative contracts. The Company’s derivative contracts are with multiple counterparties to minimize its exposure to any individual counterparty. Additionally, the majority of the Company’s counterparties are lenders under its senior credit facility.

Under certain circumstances, a default by the Company under its senior credit facility constitutes a default under its derivative contracts. The Company does not require collateral or other security from counterparties to support derivative instruments. The Company has master netting agreements with all of its derivative contract counterparties, which allows the Company to net its derivative assets and liabilities with the same counterparty. As a result of the netting provisions, the Company’s maximum amount of loss under derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the derivatives. The Company’s loss is further limited as any amounts due from a defaulting counterparty can be offset against amounts owed to such counterparty under the Company’s senior credit facility under certain circumstances. As of June 30, 2012, the counterparties to the Company’s open derivative contracts consisted of 18 financial institutions, 15 of which are also lenders under the Company’s senior credit facility. As a result, the Company is not required to post additional collateral under derivative contracts as the majority of the counterparties to the Company’s derivative contracts share in the collateral supporting the Company’s senior credit facility. To secure their obligations under the derivative contracts novated by the Company, the Permian Trust and the Mississippian Trust II have each given the counterparties to such contracts a lien on their royalty interest. See Note 9 to the unaudited condensed consolidated financial statements included in this Quarterly Report for additional information on the Permian Trust and the Mississippian Trust II's derivative contracts.

The Company’s ability to fund its capital expenditure budget is partially dependent upon the availability of funds under its senior credit facility. In order to mitigate the credit risk associated with individual financial institutions committed to participate in the senior credit facility, the Company’s bank group currently consists of 23 financial institutions with commitments ranging from 1.00% to 6.00%.

Interest Rate Risk. The Company is subject to interest rate risk on its long-term fixed and variable interest rate borrowings. Fixed rate debt, where the interest rate is fixed over the life of the instrument, exposes the Company to (i) changes in market interest rates reflected in the fair value of the debt and (ii) the risk that the Company may need to refinance maturing debt with new debt at a higher rate. Variable rate debt, where the interest rate fluctuates, exposes the Company to short-term changes in market interest rates as its interest obligations on these instruments are periodically redetermined based on prevailing market interest rates, primarily the LIBOR and the federal funds rate.

The Company may enter into derivative transactions to fix the interest rate on its variable rate debt. At June 30, 2012, the Company had a $350.0 million notional interest rate swap agreement, which effectively fixes the rate on the Senior Floating Rate Notes at an annual rate of 6.69% through April 1, 2013. This swap has not been designated as a hedge.

The Company’s interest rate swap reduces its market risk on its Senior Floating Rate Notes. The Company uses sensitivity analyses to determine the impact that market risk exposures could have on the Company’s variable interest rate borrowings in the absence of its interest rate swap. Based on the $350.0 million outstanding balance of the Company’s Senior Floating Rate Notes at June 30, 2012, a one percent change in the applicable rates, with all other variables held constant, would have resulted in a

62
Table of Contents

change in the Company’s interest expense of approximately $0.9 million and $1.8 million for the three and six-month periods ended June 30, 2012, respectively.

The following table summarizes the cash settlements and valuation gains and losses, which are included in interest expense in the Company’s accompanying unaudited condensed consolidated statements of operations, on the Company’s interest rate swap for the three and six-month periods ended June 30, 2012 and 2011 (in thousands):
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
Realized loss
$
2,294

 
$
2,442

 
$
4,494

 
$
4,485

Unrealized (gain) loss
(2,245
)
 
356

 
(3,599
)
 
(1,409
)
Loss on interest rate swap
$
49

 
$
2,798

 
$
895

 
$
3,076


ITEM 4. Controls and Procedures

Under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, the Company performed an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures pursuant to Exchange Act Rules 13a-15 and 15d-15 as of the end of the period covered by this Quarterly Report. Based on that evaluation, the Company’s Chief Executive Officer and the Company’s Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of June 30, 2012 to provide reasonable assurance that the information required to be disclosed by the Company in its reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission, and such information is accumulated and communicated to management, as appropriate to allow timely decisions regarding required disclosure.

There was no change in the Company’s internal control over financial reporting during the quarter ended June 30, 2012 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.


63
Table of Contents

PART II. Other Information

ITEM 1. Legal Proceedings

On February 14, 2011, Aspen Pipeline, II, L.P. (“Aspen”), filed a complaint in the District Court of Harris County, Texas, against Arena and SandRidge claiming damages based upon alleged representations by Arena in connection with Aspen’s construction of a natural gas pipeline in west Texas. On October 14, 2011, the complaint was amended to add Odessa Fuels, LLC, Odessa Fuels Marketing, LLC and Odessa Field Services and Compression, LLC as plaintiffs. The plaintiffs’ amended claims seek damages relating to the construction of the pipeline and performance under a related gas purchase agreement, which damages are alleged to approach $100.0 million. The Company intends to defend this lawsuit vigorously. This case is in the discovery stage.

On April 5, 2011, Wesley West Minerals, Ltd. and Longfellow Ranch Partners, LP filed suit against SandRidge Energy, Inc. and SandRidge Exploration and Production, LLC (collectively, the “SandRidge Entities”) in the 83rd District Court of Pecos County, Texas. The plaintiffs, who have leased mineral rights to the SandRidge Entities in Pecos County, allege that the SandRidge Entities have not properly paid royalties on all volumes of natural gas (including CO2) produced from the acreage leased from the plaintiffs. The plaintiffs also allege that the SandRidge Entities have inappropriately failed to pay royalties on CO2 produced from plaintiffs’ acreage that results from the treatment of natural gas at the Century Plant. The plaintiffs seek unspecified actual damages, punitive damages and a declaration that the SandRidge Entities must pay royalties on CO2 produced from plaintiffs’ acreage that results from treatment of natural gas at the Century Plant. The Commissioner of the General Land Office of the State of Texas (“GLO”) is named as an additional defendant in the lawsuit as some of the affected oil and natural gas leases described in the plaintiffs’ allegations cover mineral classified lands in which the GLO is entitled to one-half of the royalties attributable to such leases. The GLO has filed a cross-claim against the SandRidge Entities asserting the same claims as the plaintiffs with respect to the leases covering mineral classified lands. The Company intends to defend this lawsuit vigorously. This case is in the discovery stage.

On August 4, 2011, Patriot Exploration, LLC, Jonathan Feldman, Redwing Drilling Partners, Mapleleaf Drilling Partners, Avalanche Drilling Partners, Penguin Drilling Partners and Gramax Insurance Company Ltd. filed a lawsuit against SandRidge Energy, Inc., SandRidge Exploration and Production, LLC (“SandRidge E&P”) and certain directors and senior executive officers of SandRidge Energy, Inc. (collectively, the “defendants”), in the U.S. District Court for the District of Connecticut. The plaintiffs allege that the defendants made false and misleading statements to U.S. Drilling Capital Management LLC and the plaintiffs prior to the entry into a participation agreement among Patriot Exploration LLC, U.S. Drilling Capital Management LLC and SandRidge E&P, which provided for the investment by the plaintiffs in certain of SandRidge E&P’s oil and natural gas properties. To date, the plaintiffs have invested approximately $15.0 million under the participation agreement. The plaintiffs seek compensatory and punitive damages and rescission of the participation agreement. The Company intends to defend this lawsuit vigorously and believes the plaintiffs’ claims are without merit. This case remains in its early stages pending the Court's ruling on the Company's motion to dismiss all of the plaintiffs' claims.

In addition, SandRidge is a defendant in lawsuits from time to time in the normal course of business. While the results of litigation and claims cannot be predicted with certainty, the Company believes the reasonably possible losses of such matters, individually and in the aggregate, are not material. Additionally, the Company believes the probable final outcome of such matters will not have a material adverse effect on the Company’s consolidated results of operations, financial position, cash flows or liquidity.

ITEM 1A. Risk Factors

There has been no material change to the risk factors previously discussed in Item 1A – Risk Factors in the Company’s 2011 Form 10-K.


64
Table of Contents

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds

As part of the Company’s restricted stock program, the Company makes required tax payments on behalf of employees when their stock awards vest and then withholds a number of vested shares of common stock having a value on the date of vesting equal to the tax obligation. The shares withheld are initially recorded as treasury shares, then immediately retired. During the quarter ended June 30, 2012, the following shares were withheld in satisfaction of tax withholding obligations arising from the vesting of restricted stock:
Period
Total Number of Shares Purchased
 
Average Price Paid per Share
 
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
 
Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
April 1, 2012 — April 30, 2012
885

 
$
7.79

 
N/A
 
N/A
May 1, 2012 — May 31, 2012
1,572

 
$
7.14

 
N/A
 
N/A
June 1, 2012 — June 30, 2012
45,588

 
$
6.49

 
N/A
 
N/A

ITEM 6. Exhibits

See the Exhibit Index accompanying this Quarterly Report.


65
Table of Contents

SIGNATURE

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/    JAMES D. BENNETT
 
 
James D. Bennett
Executive Vice President and
Chief Financial Officer
Date: August 6, 2012

66
Table of Contents

EXHIBIT INDEX

 
 
Incorporated by Reference
 
 
Exhibit
No.
Exhibit Description
Form
 
SEC
File No.
 
Exhibit
 
Filing Date
 
Filed
Herewith
3.1
Certificate of Incorporation of SandRidge Energy, Inc.
S-1
 
333-148956
 
3.1

 
1/30/2008
 
 
3.2
Certificate of Amendment to the Certificate of Incorporation of SandRidge Energy, Inc., dated July 16, 2010
10-Q
 
001-33784
 
3.2

 
8/9/2010
 
 
3.3
Amended and Restated Bylaws of SandRidge Energy, Inc.
8-K
 
001-33784
 
3.1

 
3/9/2009
 
 
4.1
Indenture, dated as of April 17, 2012, among the Company, certain subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee
8-K
 
001-33784
 
4.1

 
4/17/2012
 
 
4.2
Supplemental Indenture, dated April 17, 2012, among the Company, certain subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee
8-K
 
001-33784
 
4.3

 
4/17/2012
 
 
4.3
Supplemental Indenture, dated June 1, 2012, among the Company, certain subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee
 
 
 
 
 
 
 
 
*
10.1
Second Amended and Restated Credit Agreement, dated as of March 29, 2012, among SandRidge Energy, Inc., Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer, and the other lenders party thereto
8-K
 
001-33784
 
10.1

 
4/2/2012
 
 
10.2
Purchase Agreement, dated April 2, 2012, by and among the Company, certain subsidiary guarantors named therein, and Merrill Lynch, Pierce, Fenner & Smith Incorporated, SunTrust Robinson Humphrey, Inc. and RBS Securities Inc., as representatives of the several initial purchasers
8-K
 
001-33784
 
10.1

 
4/4/2012
 
 
10.3
Registration Rights Agreement, dated April 17, 2012, by and among SandRidge Energy, Inc., certain subsidiary guarantors named therein, and Merrill Lynch, Pierce, Fenner & Smith Incorporated, SunTrust Robinson Humphrey, Inc. and RBS Securities Inc., as representatives of the several initial purchasers
8-K
 
001-33784
 
4.2

 
4/17/2012
 
 
10.4
Development Agreement, by and between SandRidge Energy, Inc., SandRidge Exploration and Production, LLC and SandRidge Mississippian Trust II
8-K
 
001-33784
 
10.1

 
4/24/2012
 
 
31.1
Section 302 Certification — Chief Executive Officer
 
 
 
 
 
 
 
 
*
31.2
Section 302 Certification — Chief Financial Officer
 
 
 
 
 
 
 
 
*
32.1
Section 906 Certifications of Chief Executive Officer and Chief Financial Officer
 
 
 
 
 
 
 
 
*
101.INS
XBRL Instance Document
 
 
 
 
 
 
 
 
*
101.SCH
XBRL Taxonomy Extension Schema Document
 
 
 
 
 
 
 
 
*
101.CAL
XBRL Taxonomy Extension Calculation Linkbase Document
 
  
 
  
 
  
 
  
*
101.DEF
XBRL Taxonomy Extension Definition Document
 
  
 
  
 
  
 
  
*
101.LAB
XBRL Taxonomy Extension Label Linkbase Document
 
  
 
  
 
  
 
  
*
101.PRE
XBRL Taxonomy Extension Presentation Linkbase Document
 
  
 
  
 
  
 
  
*

67