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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
__________________________
Form 10-Q
__________________________
(Mark One)

þ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2018
OR

o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to
Commission File Number: 001-33784
__________________________
SANDRIDGE ENERGY, INC.
(Exact name of registrant as specified in its charter)
__________________________

Delaware |  | 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 þ No o
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer | o |  | Accelerated filer | þ
Non-accelerated filer | o |  | Smaller reporting company | o
|  |  | Emerging growth company | o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13, or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes þ No o
The number of shares outstanding of the registrant’s common stock, par value $0.001 per share, as of the close of business on November 2, 2018, was 35,693,515.

Table of Contents
References in this report to the “Company,” “SandRidge,” “we,” “our,” and “us” mean SandRidge Energy, Inc., including its consolidated subsidiaries and its proportionately consolidated share of each of SandRidge Mississippian Trust I, SandRidge Mississippian Trust II and SandRidge Permian Trust (collectively, the “Royalty Trusts”).
DISCLOSURES REGARDING FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q (“Quarterly Report”) of 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 the Company’s capital expenditures, liquidity, capital resources and debt profile, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, elements of the Company’s business strategy, compliance with governmental regulation of the oil and natural gas industry, including environmental regulations, acquisitions and divestitures and the effects thereof on the Company’s financial condition and other statements concerning the Company’s operations and financial performance and 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, may not have the expected consequences to or effects on the Company’s business or results. Such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in such forward-looking statements. These forward-looking statements speak only as of the date hereof. The Company disclaims any obligation to update or revise these 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 and uncertainties discussed in “Risk Factors” in Item 1A of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017 (the “2017 Form 10-K”) and in Item 1A of this Quarterly Report.

Table of Contents
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
FORM 10-Q
Quarter Ended September 30, 2018
INDEX

PART I. FINANCIAL INFORMATION |  |
ITEM 1. | Financial Statements (Unaudited): |
| Condensed Consolidated Balance Sheets | 4
| Condensed Consolidated Statements of Operations | 5
| Condensed Consolidated Statement of Changes in Stockholders’ Equit y | 6
| Condensed Consolidated Statements of Cash Flows | 7
| Notes to Condensed Consolidated Financial Statements | 8
ITEM 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 27
ITEM 3. | Quantitative and Qualitative Disclosures About Market Risk | 36
ITEM 4. | Controls and Procedures | 37
PART II. OTHER INFORMATION |  |
ITEM 1. | Legal Proceedings | 38
ITEM 1A. | Risk Factors | 38
ITEM 2. | Unregistered Sales of Equity Securities and Use of Proceeds | 39
ITEM 3. | Defaults upon Senior Securities | 39
ITEM 6. | Exhibits | 40
Signature |  |

Table of Contents
PART I. Financial Information
ITEM 1. Financial Statements
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)
(In thousands, except per share data)

| September 30, 2018 |  | December 31, 2017
ASSETS |  |  |
Current assets |  |  |
Cash and cash equivalents | $ | 32,562 |  | $ | 99,143
Restricted cash - other | 1,912 |  | 2,165
Accounts receivable, net | 54,493 |  | 71,277
Derivative contracts | 73 |  | 1,310
Prepaid expenses | 2,223 |  | 5,248
Other current assets | 350 |  | 15,954
Total current assets | 91,613 |  | 195,097
Oil and natural gas properties, using full cost method of accounting |  |  |
Proved | 1,206,363 |  | 1,056,806
Unproved | 68,737 |  | 100,884
Less: accumulated depreciation, depletion and impairment | (546,769) |  | (460,431)
| 728,331 |  | 697,259
Other property, plant and equipment, net | 211,198 |  | 225,981
Other assets | 1,181 |  | 1,290
Total assets | $ | 1,032,323 |  | $ | 1,119,627

LIABILITIES AND STOCKHOLDERS’ EQUITY |  |  |
Current liabilities |  |  |
Accounts payable and accrued expenses | $ | 112,980 |  | $ | 139,155
Derivative contracts | 36,905 |  | 10,627
Asset retirement obligation | 40,041 |  | 41,017
Other current liabilities | 7 |  | 8,115
Total current liabilities | 189,933 |  | 198,914
Long-term debt | — |  | 37,502
Derivative contracts | 6,791 |  | 3,568
Asset retirement obligation | 39,227 |  | 36,527
Other long-term obligations | 3,837 |  | 3,176
Total liabilities | 239,788 |  | 279,687
Commitments and contingencies (Note 11) |  |  |
Stockholders’ Equity |  |  |
Common stock, $0.001 par value; 250,000 shares authorized; 35,691 issued and outstanding at September 30, 2018 and 35,650 issued and outstanding at December 31, 2017 | 36 |  | 36
Warrants | 88,517 |  | 88,500
Additional paid-in capital | 1,054,155 |  | 1,038,324
Accumulated deficit | (350,173) |  | (286,920)
Total stockholders’ equity | 792,535 |  | 839,940
Total liabilities and stockholders’ equity | $ | 1,032,323 |  | $ | 1,119,627

The accompanying notes are an integral part of these condensed consolidated financial statements.
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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(In thousands, except per share data)

| Three Months Ended September 30, |  |  |  |  | Nine Months Ended September 30, |  |  |
| 2018 |  |  | 2017 |  | 2018 |  |  | 2017
Revenues |  |  |  |  |  |  |  |  |
Oil, natural gas and NGL | $ | 97,491 |  |  | $ | 80,540 |  | $ | 263,761 |  |  | $ | 263,235
Other | 169 |  |  | 352 |  | 489 |  |  | 858
Total revenues | 97,660 |  |  | 80,892 |  | 264,250 |  |  | 264,093
Expenses |  |  |  |  |  |  |  |  |
Production | 23,429 |  |  | 26,765 |  | 68,927 |  |  | 76,997
Production taxes | 5,636 |  |  | 3,606 |  | 14,725 |  |  | 9,435
Depreciation and depletion — oil and natural gas | 33,090 |  |  | 31,029 |  | 92,048 |  |  | 87,486
Depreciation and amortization — other | 3,036 |  |  | 3,399 |  | 9,229 |  |  | 10,729
Impairment | — |  |  | 498 |  | 4,170 |  |  | 3,475
General and administrative | 9,251 |  |  | 20,292 |  | 33,616 |  |  | 59,184
Accelerated vesting upon change in control | — |  |  | — |  | 6,545 |  |  | —
Proxy contest | (459) |  |  | — |  | 7,139 |  |  | —
Employee termination benefits | 23 |  |  | — |  | 32,653 |  |  | 4,815
Loss (gain) on derivative contracts | 11,329 |  |  | 11,702 |  | 59,763 |  |  | (46,024)
Other operating (income) expense | (105) |  |  | (132) |  | (1,343) |  |  | 135
Total expenses | 85,230 |  |  | 97,159 |  | 327,472 |  |  | 206,232
Income (loss) from operations | 12,430 |  |  | (16,267) |  | (63,222) |  |  | 57,861
Other (expense) income |  |  |  |  |  |  |  |  |
Interest expense, net | (627) |  |  | (872) |  | (2,226) |  |  | (2,757)
Gain on extinguishment of debt | — |  |  | — |  | 1,151 |  |  | —
Other (expense) income, net | (118) |  |  | 197 |  | 972 |  |  | 2,222
Total other expense | (745) |  |  | (675) |  | (103) |  |  | (535)
Income (loss) before income taxes | 11,685 |  |  | (16,942) |  | (63,325) |  |  | 57,326
Income tax benefit | (30) |  |  | (8,457) |  | (72) |  |  | (8,496)
Net income (loss) | $ | 11,715 |  |  | $ | (8,485) |  | $ | (63,253) |  |  | $ | 65,822
Earnings (loss) per share |  |  |  |  |  |  |  |  |
Basic | $ | 0.33 |  |  | $ | (0.25) |  | $ | (1.81) |  |  | $ | 2.07
Diluted | $ | 0.33 |  |  | $ | (0.25) |  | $ | (1.81) |  |  | $ | 2.06
Weighted average number of common shares outstanding |  |  |  |  |  |  |  |  |
Basic | 35,308 |  |  | 34,290 |  | 34,971 |  |  | 31,750
Diluted | 35,330 |  |  | 34,290 |  | 34,971 |  |  | 31,984

The accompanying notes are an integral part of these condensed consolidated financial statements.
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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY (Unaudited)
(In thousands)

|  | Common Stock |  |  |  | Warrants |  |  |  | Additional Paid-In Capital |  |  |  | Accumulated Deficit |  | Total
|  | Shares |  | Amount |  | Shares |  | Amount |  |  |  |  |  |  |  |
Nine Months Ended September 30, 2018 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Balance at December 31, 2017 |  | 35,650 |  | $ | 36 |  | 6,570 |  | $ | 88,500 |  | $ | 1,038,324 |  |  |  | $ | (286,920) |  | $ | 839,940
Issuance of stock awards, net of cancellations |  | 15 |  | — |  | — |  | — |  | — |  |  |  | — |  | —
Common stock issued for general unsecured claims |  | 26 |  | — |  | — |  | — |  | — |  |  |  | — |  | —
Stock-based compensation |  | — |  | — |  | — |  | — |  | 23,224 |  |  |  | — |  | 23,224
Issuance of warrants for general unsecured claims |  | — |  | — |  | 32 |  | 17 |  | (17) |  |  |  | — |  | —
Cash paid for tax withholdings on vested stock awards |  | — |  | — |  | — |  | — |  | (7,376) |  |  |  | — |  | (7,376)
Net loss |  | — |  | — |  | — |  | — |  | — |  |  |  | (63,253) |  | (63,253)
Balance at September 30, 2018 |  | 35,691 |  | $ | 36 |  | 6,602 |  | $ | 88,517 |  | $ | 1,054,155 |  |  |  | $ | (350,173) |  | $ | 792,535

The accompanying notes are an integral part of these condensed consolidated financial statements.
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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(In thousands)

| Nine Months Ended September 30, |  |
| 2018 |  | 2017
CASH FLOWS FROM OPERATING ACTIVITIES |  |  |
Net (loss) income | $ | (63,253) |  | $ | 65,822
Adjustments to reconcile net (loss) income to net cash provided by operating activities |  |  |
Provision for doubtful accounts | (6) |  | 133
Depreciation, depletion, and amortization | 101,277 |  | 98,215
Impairment | 4,170 |  | 3,475
Debt issuance costs amortization | 352 |  | 313
Amortization of premiums and discounts on debt | (47) |  | (231)
Gain on extinguishment of debt | (1,151) |  | —
Loss (gain) on derivative contracts | 59,763 |  | (46,024)
Cash (paid) received on settlement of derivative contracts | (29,025) |  | 7,700
Stock-based compensation | 22,415 |  | 12,616
Other | (1,734) |  | 188
Changes in operating assets and liabilities | 16,407 |  | 5,699
Net cash provided by operating activities | 109,168 |  | 147,906
CASH FLOWS FROM INVESTING ACTIVITIES |  |  |
Capital expenditures for property, plant and equipment | (146,819) |  | (152,743)
Acquisition of assets | — |  | (48,236)
Proceeds from sale of assets | 14,497 |  | 19,769
Net cash used in investing activities | (132,322) |  | (181,210)
CASH FLOWS FROM FINANCING ACTIVITIES |  |  |
Repayments of borrowings | (36,304) |  | —
Debt issuance costs | — |  | (1,488)
Cash paid for tax withholdings on vested stock awards | (7,376) |  | (3,766)
Net cash used in financing activities | (43,680) |  | (5,254)
NET DECREASE IN CASH, CASH EQUIVALENTS and RESTRICTED CASH | (66,834) |  | (38,558)
CASH, CASH EQUIVALENTS and RESTRICTED CASH, beginning of year | 101,308 |  | 174,071
CASH, CASH EQUIVALENTS and RESTRICTED CASH, end of period | $ | 34,474 |  | $ | 135,513
Supplemental Disclosure of Cash Flow Information |  |  |
Cash received for income taxes | $ | 4,381 |  | $ | —
Supplemental Disclosure of Noncash Investing and Financing Activities |  |  |
Change in accrued capital expenditures | $ | 29,141 |  | $ | (15,241)
Equity issued for debt | $ | — |  | $ | (268,779)

The accompanying notes are an integral part of these condensed consolidated financial statements.
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. Basis of Presentation
Nature of Business. SandRidge Energy, Inc. is an oil and natural gas exploration and production company headquartered in Oklahoma City, Oklahoma with its principal focus on developing high-return, growth-oriented projects in the U.S. Mid-Continent and North Park Basin of Colorado.
Principles of Consolidation. The consolidated financial statements include the accounts of the Company and its wholly owned or majority owned subsidiaries, including its proportionate share of the Royalty Trusts. All significant intercompany accounts and transactions have been eliminated in consolidation.
Interim Financial Statements. The accompanying unaudited condensed consolidated financial statements and notes have been derived from the Company's 2017 Form 10-K and should be read in conjunction with the audited financial statements and notes contained in the Company’s 2017 Form 10-K. Certain information and 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, the financial statements include all adjustments, which consist of normal recurring adjustments unless otherwise disclosed, necessary to fairly state the Company’s unaudited condensed consolidated financial statements.
Significant Accounting Policies. The unaudited condensed consolidated financial statements were prepared in accordance with the accounting policies stated in the 2017 Form 10-K as well as the items noted below.
Reclassifications. Certain reclassifications have been made to the prior period financial statements to conform to the current period presentation. These reclassifications have no effect on the Company’s previously reported results of operations.
Use of Estimates. The preparation of the unaudited 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, natural gas and natural gas liquids (“NGL”) reserves; impairment tests of long-lived assets; depreciation, depletion and amortization; income taxes; valuation of derivative instruments; contingencies; and accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ significantly.
Recent Accounting Pronouncements. The Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, “Revenue from Contracts with Customers (Topic 606),” which outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers. Its objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. In August 2015, the FASB issued ASU 2015-14, "Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date," which deferred the effective date of ASU 2014-09 to January 1, 2018, for the Company. The ASU required adoption using either the retrospective transition method, which required restating previously reported results or the cumulative effect (modified retrospective) transition method, which utilized a cumulative-effect adjustment to retained earnings in the period of adoption to account for prior period effects rather than restating previously reported results. The Company adopted Topic 606 and all the related amendments (the “new revenue standard”) on January 1, 2018, using the modified retrospective transition method. See Note 2 for further discussion of the adoption of the new revenue standard.
The FASB issued ASU 2016-16, “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other than Inventory,” which removed the prohibition in Accounting Standards Codification (“ASC”) 740 against the immediate recognition of current and deferred income tax effects of intra-entity transfers of assets other than inventory. The amendments in this ASU were effective for the Company on January 1, 2018, with early adoption permitted on January 1, 2017. The ASU required application on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. The Company adopted the ASU on January 1, 2018. There was no impact to the Company’s consolidated financial statements and related disclosures upon adoption.
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The FASB issued ASU 2017-05, “Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic: 610-20): Clarifying the Scope of Asset Derecognition Guidance and the Accounting for Partial Sales of Nonfinancial
Assets,” which helps filers determine the guidance applicable for gain/loss recognition subsequent to the adoption of ASU 2014-09, Revenue from Contracts with Customers. The amendments also clarified that the derecognition of all businesses except those related to conveyances of oil and gas rights or contracts with customers should be accounted for in accordance with the derecognition and deconsolidation guidance in Topic 810, Consolidation. The Company adopted the ASU on January 1, 2018, using the modified retrospective transition method. Under this transition method the Company could have elected to apply this guidance retrospectively either to all contracts at the date of initial application or only to contracts that are not completed contracts at the date of initial application. The Company elected to evaluate only contracts that are not completed contracts. As there were no uncompleted contracts at January 1, 2018, there was no impact to the Company’s consolidated financial statements and related disclosures upon adoption.
The FASB issued ASU 2018-13, "Fair Value Measurement (Topic 820) - Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement," which removes, modifies or adds disclosure requirements regarding fair value measurements. The amendments in this ASU are effective for all entities beginning after December 15, 2019, with amendments on changes in unrealized gains and losses, the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements, and the narrative description of measurement uncertainty requiring prospective adoption and all other amendments requiring retrospective adoption. Early adoption is permitted and the Company elected to adopt this ASU during the third quarter of 2018, which resulted in a change to the Company's fair value measurement disclosures on a prospective basis, but had no impact on its consolidated financial statements.
Recent Accounting Pronouncements Not Yet Adopted. The FASB issued ASU 2016-02, “Leases (Topic 842),” which requires lessees to recognize the assets and liabilities for the rights and obligations of all leases with a term greater than 12 months (long-term) on the balance sheet. Leases will be classified as financing or operating expenses, with the classification affecting the pattern and classification of expense recognition in the income statement. Leases to explore for or use oil and natural gas are not impacted by this guidance. In January 2018, the FASB issued ASU 2018-01, “Leases (Topic 842), Land Easement Practical Expedient for Transition to Topic 842.” This ASU permits an entity to continue to apply its current accounting policy for land easements that existed before the effective date of Topic 842. Once an entity adopts Topic 842, it would apply that Topic prospectively to all new (or modified) land easements to determine whether the arrangement contains a lease. ASU 2016-02 required adoption by application of a modified retrospective transition approach. In July 2018, the FASB issued ASU 2018-11, "Leases (Topic 842)." The amendments in this update provide another transition method whereby entities are allowed to initially apply the new lease standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. The amendments further provide lessors with a practical expedient, by class of underlying asset, to not separate nonlease components from the associated lease component, similar to the expedient provided for lessees. The lessor practical expedient is limited to circumstances in which the nonlease component or components otherwise would be accounted for under the new revenue guidance and both (1) the timing and pattern of transfer are the same for the nonlease component(s) and associated lease component and (2) the lease component, if accounted for separately, would be classified as an operating lease. The amendments also clarify whether Topic 842 or Topic 606 applies for combined components. This topic is effective for the Company on January 1, 2019. Early adoption is permitted.
Topic 842 provides a number of optional practical expedients in transition. The Company plans to elect the ‘package of practical expedients,’ which means the Company will not have to reassess under the new lease standard its prior conclusions about lease identification, lease classification and initial indirect costs. The Company also plans to elect the land easement practical expedient. The Company does not expect to elect the use-of-hindsight. Upon adoption, the Company anticipates recognizing assets and liabilities for the rights and obligations of its existing long-term operating leases on its consolidated balance sheets and utilizing new systems, processes and internal controls to properly identify, classify, measure and recognize new (or modified) leases after the date of adoption. While the effects of adoption are continuing to be assessed, the Company believes the primary impact of the lease standard relates to (1) recognizing assets and liabilities for the rights and obligations of the Company’s vehicle, drilling rig and equipment leases and, (2) providing new disclosures about the Company’s leasing activities. The Company will complete its evaluation during 2018 and will adopt Topic 842 on January 1, 2019. The Company expects to adopt this Topic using a modified retrospective approach by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption.
The new leasing standard also provides practical expedients for an entity’s ongoing accounting. The Company currently plans to elect the short-term lease recognition exemption for leases that qualify, which means the Company will not recognize assets and liabilities for the rights and obligations of qualifying leases, including existing short-term leases of those assets in
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transition. The Company is also currently evaluating applicability of the practical expedient to avoid separating lease and nonlease components for its leases.
2. Revenues
The Company adopted the new revenue standard on January 1, 2018, using the modified retrospective method for all contracts outstanding on that date. Adoption of the new revenue standard had no impact on the Company’s consolidated balance sheet, results of operations, equity or cash flows as of the adoption date, and the Company does not expect any further material impact to its consolidated financial statements on an ongoing basis as a result of adopting the new revenue standard. The Company has included the disclosures required by the new revenue standard below.
The following table disaggregates the Company’s revenue by source for the three and nine-month periods ended September 30, 2018 and 2017:

| Three Months Ended September 30, |  |  |  | Nine Months Ended September 30, |  |  |  |  |  |  |  |
| 2018 |  | 2017 |  | 2018 |  | 2017 |  |  |  |  |  |
| (In thousands) |  |  |  |  |  |  |  |  |  |  |  |
Oil | $ | 63,994 |  | $ | 44,032 |  | $ | 166,548 |  | $ | 147,792 |  |  |  |  |  |
NGL | 18,776 |  | 15,391 |  | 52,111 |  | 42,962 |  |  |  |  |  |
Natural gas | 14,721 |  | 21,117 |  | 45,102 |  | 72,481 |  |  |  |  |  |
Other | 169 |  | 352 |  | 489 |  | 858 |  |  |  |  |  |
Total revenues | $ | 97,660 |  | $ | 80,892 |  | $ | 264,250 |  | $ | 264,093 |  |  |  |  |  |

Oil, natural gas and NGL revenues. A majority of the Company’s revenues come from sales of oil, natural gas and NGLs and are recorded at a point in time when control of the oil, natural gas and NGL production passes to the customer at the inlet of the processing plant or pipeline, or the delivery point for onloading to a delivery truck. As the Company’s customers obtain control of the production prior to selling it to other end customers, the Company presents its revenues on a net basis, rather than on a gross basis.
Pricing for the Company’s oil, natural gas and NGL contracts is variable and is based on volumes sold multiplied by either an index price, net of deductions, or a percentage of the sales price obtained by the customer, which is also based on index prices. The transaction price is allocated on a pro-rata basis to each unit of oil, natural gas or NGL sold based on the terms of the contract. Oil, natural gas and NGL revenues are also recorded net of royalties, discounts and allowances, and transportation costs, as applicable. Taxes assessed by governmental authorities on oil, natural gas and NGL sales are presented separately from revenues and are included in production tax expense in the consolidated statements of operations.
Revenues Receivable. The Company records an asset in accounts receivable, net on its consolidated balance sheet for revenues receivable from contracts with customers at the end of each period. Pricing for revenues receivable is estimated using current month crude oil, natural gas and NGL prices, net of deductions. Revenues receivable are typically collected the month after the Company delivers the related production to its customers. As of September 30, 2018, and December 31, 2017, the Company had revenues receivable of $33.7 million and $34.6 million, respectively, and did not record any bad debt expense on revenues receivable during the three and nine-month periods ended September 30, 2018.
Practical expedients and exemptions. The Company elected not to retrospectively restate contracts that were modified prior to January 1, 2017, and assumed that the contract terms in place at January 1, 2018 were in place from the inception of the contract.
Most of the Company's contracts are short-term in nature with a contract term of one year or less. The Company generally expenses certain insignificant costs when incurred rather than recognizing them as an asset because the amortization period would have been one year or less. Additionally, the Company does not disclose the value of unsatisfied performance obligations for (i) contracts with an original expected length of one year or less, and (ii) contracts for which revenue is recognized at the amount to which the Company has the right to invoice for services performed. Payment terms are typically within 30 days of control being transferred.
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(Unaudited)
Currently, the Company’s existing contracts do not contain financing components, but the Company has elected the practical expedient that allows financing components to be ignored if the difference between the performance and payment is less than one year for any future contracts that may contain financing components.
3. Proxy Contest
In the second quarter of 2018, the Company received notification from Carl C. Icahn and certain affiliated entities (together, "Icahn"), that they intended to nominate a full slate of five candidates for election to the Board at the 2018 Annual Meeting of Stockholders (the "2018 annual meeting") that was held on June 19, 2018 (the "proxy contest"). The Company and Icahn, together with certain of their Board nominees, each entered into a settlement agreement pursuant to which the size of the Board was expanded to eight directors. The Board now consists of previously incumbent directors Sylvia K. Barnes, David J. Kornder and William M. Griffin, and newly elected members Bob G. Alexander, Jonathan Christodoro, Jonathan Frates, John J. "Jack" Lipinski and Randolph C. Read following the certification of the voting results, which occurred on June 22, 2018. As confirmed by external counsel, the election of a majority of non-incumbent directors nominated in connection with the proxy contest resulted in the accelerated vesting of certain share and incentive-based compensation awards granted to the Company's employees and directors as discussed further in Note 15.
The Company incurred legal, consulting and advisory fees related to shareholder activism and the proxy contest, as well as the review of strategic alternatives of $7.1 million for the nine-month period ended September 30, 2018, which is net of $(0.5) million in fees which were reimbursed to the Company during the three-month period ended September 30, 2018.
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4. Employee Termination Benefits
The following table presents a summary of employee termination benefits for the three and nine-month periods ended September 30, 2018 and 2017 (in thousands):

|  | Cash |  | Share-Based Compensation (4) |  | Number of Shares |  | Total Employee Termination Benefits
Three Months Ended September 30, 2018 |  |  |  |  |  |  |  |
Executive Employee Termination Benefits |  | $ | — |  | $ | — |  | — |  | $ | —
Other Employee Termination Benefits |  | 23 |  | — |  | — |  | 23
|  | $ | 23 |  | $ | — |  | — |  | $ | 23
Three Months Ended September 30, 2017 |  |  |  |  |  |  |  |
Executive Employee Termination Benefits |  | $ | — |  | $ | — |  | — |  | $ | —
Other Employee Termination Benefits |  | — |  | — |  | — |  | —
|  | $ | — |  | $ | — |  | — |  | $ | —
Nine Months Ended September 30, 2018 |  |  |  |  |  |  |  |
Executive Employee Termination Benefits (1) |  | $ | 11,945 |  | $ | 9,196 |  | 554 |  | $ | 21,141
Other Employee Termination Benefits (2) |  | 7,577 |  | 3,935 |  | 209 |  | 11,512
|  | $ | 19,522 |  | $ | 13,131 |  | 763 |  | $ | 32,653
Nine Months Ended September 30, 2017 |  |  |  |  |  |  |  |
Executive Employee Termination Benefits (3) |  | $ | 2,500 |  | $ | 1,825 |  | 96 |  | $ | 4,325
Other Employee Termination Benefits |  | 490 |  | — |  | — |  | 490
|  | $ | 2,990 |  | $ | 1,825 |  | 96 |  | $ | 4,815

____________________
1. On February 8, 2018, the Company’s then current CEO, James Bennett, separated employment from the Company, and on February 22, 2018, the Company’s then current CFO, Julian Bott, also separated employment from the Company. In accordance with the terms of their respective employment agreements, the Company incurred cash severance costs and share-based compensation costs associated with the accelerated vesting of awards during the first quarter of 2018.
2. As a result of a reduction in workforce in the first quarter of 2018, certain employees received termination benefits including cash severance and accelerated share-based and incentive compensation vesting upon separation of service from the Company.
3. Includes cash severance costs and share-based compensation costs associated with the accelerated vesting of awards related to the departure of the Company's former Executive Vice President of Investor Relations and Strategy, Duane Grubert.
4. Share-based compensation recognized in connection with the accelerated vesting of restricted stock awards and performance share units upon the departure of certain executives and the reduction in workforce in the first quarter of 2018 reflects the remaining unrecognized compensation expense associated with these awards at the date of termination. The unrecognized compensation expense was calculated using the grant date fair value for restricted stock awards and performance share units. One share of the Company’s common stock was issued per performance share unit.
See Note 15 for additional discussion of the Company’s share-based compensation awards.
5. Acquisitions and Divestitures
Acquisition of Properties. In February 2017, the Company acquired assets consisting of approximately 13,000 net acres in Woodward County, Oklahoma for approximately $47.8 million in cash, net of post-closing adjustments. Also included in the acquisition were working interests in four wells previously drilled on the acreage.
2017 Property Divestitures. During the nine-month period ended September 30, 2017, the Company divested various non-core oil and natural gas properties for approximately $16.0 million in cash. All of these divestitures were accounted for as adjustments to the full cost pool with no gain or loss recognized.
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(Unaudited)
See Note 7 for discussion of significant fixed asset divestitures and Note 16 for discussion of acquisitions and divestitures subsequent to the balance sheet date.
6. 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 levels of the fair value hierarchy noted below. The carrying values of cash, restricted cash, accounts receivable, prepaid expenses, certain other current assets and other assets, accounts payable and accrued expenses, other current liabilities and other long-term obligations included in the unaudited condensed consolidated balance sheets approximated fair value at September 30, 2018, and December 31, 2017. As a result, these financial assets and liabilities are not discussed below. The fair values of property, plant and equipment classified as assets held for sale and related impairments, which are calculated using Level 3 inputs, are discussed in Note 7.

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 in Level 2 of the hierarchy as of September 30, 2018, and Level 1 and Level 2 as of December 31, 2017, as described below.
Level 1 Fair Value Measurements
Investments. The fair value of investments, consisting of assets attributable to the Company’s non-qualified deferred compensation plan, is based on quoted market prices. Investments of $5.1 million are included in other current assets in the accompanying unaudited condensed consolidated balance sheet at December 31, 2017. The Company’s non-qualified deferred compensation plan was terminated and all remaining investment balances were distributed to participants in January 2018.
Level 2 Fair Value Measurements
Commodity Derivative Contracts. The fair values of the Company’s oil and natural gas fixed price swaps are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors and discount rates, or can be corroborated from active markets. Fair value is determined through the use of a discounted cash flow model or option pricing 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.
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Fair Value - Recurring Measurement Basis
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):
September 30, 2018

| Fair Value Measurements |  |  |  |  |  | Netting(1) |  | Assets/Liabilities at Fair Value
| Level 1 |  | Level 2 |  | Level 3 |  |  |  |
Assets |  |  |  |  |  |  |  |  |
Commodity derivative contracts | $ | — |  | $ | 224 |  | $ | — |  | $ | (151) |  | $ | 73
| $ | — |  | $ | 224 |  | $ | — |  | $ | (151) |  | $ | 73
Liabilities |  |  |  |  |  |  |  |  |
Commodity derivative contracts | $ | — |  | $ | 43,847 |  | $ | — |  | $ | (151) |  | $ | 43,696
| $ | — |  | $ | 43,847 |  | $ | — |  | $ | (151) |  | $ | 43,696

December 31, 2017

| Fair Value Measurements |  |  |  |  |  | Netting(1) |  | Assets/Liabilities at Fair Value
| Level 1 |  | Level 2 |  | Level 3 |  |  |  |
Assets |  |  |  |  |  |  |  |  |
Commodity derivative contracts | $ | — |  | $ | 5,582 |  | $ | — |  | $ | (4,272) |  | $ | 1,310
Investments | 5,072 |  | — |  | — |  | — |  | 5,072
| $ | 5,072 |  | $ | 5,582 |  | $ | — |  | $ | (4,272) |  | $ | 6,382
Liabilities |  |  |  |  |  |  |  |  |
Commodity derivative contracts | $ | — |  | $ | 18,467 |  | $ | — |  | $ | (4,272) |  | $ | 14,195
| $ | — |  | $ | 18,467 |  | $ | — |  | $ | (4,272) |  | $ | 14,195

____________________
1. Represents the effect of netting assets and liabilities for counterparties with which the right of offset exists.
Transfers. The Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements during the three and nine-month periods ended September 30, 2018 and 2017.
Fair Value of Financial Instruments - Long-Term Debt
The Company measured the fair value of its $35.0 million initial principal note, as amended in February 2017, which was secured by first priority mortgages on the Company’s real estate in Oklahoma City, Oklahoma (the “Building Note”) using a discounted cash flow analysis, which is classified as a Level 2 input in the fair value hierarchy. The Company repaid the Building Note in full during the first quarter of 2018. The estimated fair values and carrying values of the Company’s long-term debt are as follows (in thousands):

| September 30, 2018 |  |  |  | December 31, 2017 |  |
| Fair Value |  | Carrying Value |  | Fair Value |  | Carrying Value
Building Note | $ | — |  | $ | — |  | $ | 42,526 |  | $ | 37,502

See Note 9 for additional discussion of the Company’s long-term debt.
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7. Property, Plant and Equipment
Property, plant and equipment consists of the following (in thousands):

| September 30, 2018 |  | December 31, 2017
Oil and natural gas properties |  |  |
Proved | $ | 1,206,363 |  | $ | 1,056,806
Unproved | 68,737 |  | 100,884
Total oil and natural gas properties | 1,275,100 |  | 1,157,690
Less accumulated depreciation, depletion and impairment | (546,769) |  | (460,431)
Net oil and natural gas properties capitalized costs | 728,331 |  | 697,259
Land | 4,500 |  | 4,500
Electrical infrastructure | 131,010 |  | 131,010
Other non-oil and natural gas equipment | 19,671 |  | 26,809
Buildings and structures | 79,548 |  | 79,548
Total | 234,729 |  | 241,867
Less accumulated depreciation and amortization | (23,531) |  | (15,886)
Other property, plant and equipment, net | 211,198 |  | 225,981
Total property, plant and equipment, net | $ | 939,529 |  | $ | 923,240

The Company had approximately $10.6 million in assets classified as held for sale in the other current assets line of the accompanying consolidated balance sheet at December 31, 2017. Approximately $9.3 million of the total at December 31, 2017 was related to one of the Company’s properties located in downtown Oklahoma City, OK, which was classified as held for sale in the fourth quarter of 2017 and sold during the second quarter of 2018 for approximately $10.4 million, net of transaction fees. The resulting gain of $1.1 million was recorded in other operating expense on the accompanying condensed consolidated statements of operations for the nine-month period ended September 30, 2018.
Additionally, during the first quarter of 2018, the Company classified its remaining midstream generator assets as held for sale. These assets had a carrying value of $5.7 million which exceeded the estimated net realizable value of $1.6 million based on expected sales prices obtained from third parties. As a result, the Company recorded an impairment of $4.1 million for the nine-month period ended September 30, 2018. The midstream generator assets were sold during the second quarter of 2018 with no gain or loss recognized on the sale.
8. Accounts Payable and Accrued Expenses
Accounts payable and accrued expenses consist of the following (in thousands):

| September 30, 2018 |  |  | December 31, 2017
Accounts payable and other accrued expenses | $ | 54,957 |  |  | $ | 75,191
Accrued interest | 65 |  |  | 1,385
Revenues and royalties payable | 42,075 |  |  | 37,274
Payroll and benefits | 15,719 |  |  | 21,475
Drilling advances | 164 |  |  | 3,830
Total accounts payable and accrued expenses | $ | 112,980 |  |  | $ | 139,155

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9. Long-Term Debt
Credit Facility. On February 10, 2017, the $425.0 million reserve-based revolving credit facility (the “First Lien Exit Facility”) was refinanced and replaced by a new $600.0 million credit facility (the “credit facility”). The borrowing base under the credit facility was reduced from $425.0 million to $350.0 million during the October 2018 semi-annual redetermination. The next borrowing base redetermination is scheduled for April 1, 2019. The credit facility matures on March 31, 2020. The outstanding borrowings under the credit facility bear interest based on a pricing grid tied to borrowing base utilization of (a) LIBOR plus an applicable margin that varies from 3.00% to 4.00% per annum, or (b) the base rate plus an applicable margin that varies from 2.00% to 3.00% per annum. Interest on base rate borrowings is payable quarterly in arrears and interest on LIBOR borrowings is payable every one, two, three or six months, at the election of the Company. Quarterly, the Company pays commitment fees assessed at annual rates of 0.50% on any available portion of the credit facility. The Company has the right to prepay loans under the credit facility at any time without a prepayment penalty, other than customary “breakage” costs with respect to LIBOR loans. Upon refinancing of the First Lien Exit Facility, $50.0 million maintained in a restricted cash collateral account, as required by the terms of the First Lien Exit Facility, was released to the Company.
The credit facility is secured by (i) first-priority mortgages on at least 95% of the PV-9 valuation of all proved reserves included in the most recently delivered reserve report of the Company, (ii) a first-priority perfected pledge of substantially all of the capital stock owned by each credit party and equity interests in the Royalty Trusts that are owned by a credit party and (iii) a first-priority perfected security interest in substantially all the cash, cash equivalents, deposits, securities and other similar accounts, and other tangible and intangible assets of the credit parties (including but not limited to as-extracted collateral, accounts receivable, inventory, equipment, general intangibles, investment property, intellectual property, real property and the proceeds of the foregoing).
The credit facility requires the Company to maintain (i) a maximum consolidated total net leverage ratio, measured as of the end of any fiscal quarter, of no greater than 3.50 to 1.00 and (ii) a minimum consolidated interest coverage ratio, measured as of the end of any fiscal quarter, of no less than 2.25 to 1.00. These financial covenants are subject to customary cure rights. The Company was in compliance with all applicable financial covenants under the credit facility as of September 30, 2018.
The credit facility contains customary affirmative and negative covenants, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements, oil and gas engineering reports, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens, indebtedness, asset dispositions, fundamental changes, restricted payments including dividends and other customary covenants. The Company was in compliance with these covenants as of September 30, 2018.
The credit facility includes events of default relating to customary matters, including, among other things, nonpayment of principal, interest or other amounts; violation of covenants; incorrectness of representations and warranties in any material respect; cross-payment default and cross acceleration with respect to indebtedness in an aggregate principal amount of $25.0 million or more; bankruptcy; judgments involving a liability of $25.0 million or more that are not paid; and ERISA events. Many events of default are subject to customary notice and cure periods.
The credit facility also provides that a change in control, as defined therein, constitutes an event of default. In connection with the change in the majority of the members of the Company’s Board that occurred as a result of the 2018 annual meeting in June 2018, the Company entered into a consent and waiver agreement with the administrative agent and certain lenders constituting the majority lenders under the credit facility. The consent and waiver agreement waived any event of default which might have occurred as a result of the change in the majority of the members of the Company’s Board and recognized the new members of the Board as existing members of the Board under the definition of change in control in the credit agreement.
The Company had no amounts outstanding under the credit facility at September 30, 2018, and $6.2 million in outstanding letters of credit, which reduce availability under the credit facility on a dollar-for-dollar basis.
Building Note. On October 4, 2016 (the “Emergence Date”), in accordance with the joint plan of organization (the "Plan") of the Company and certain of its direct and indirect subsidiaries (collectively, the “Debtors"), the Company entered into the Building Note, which had an initial principal amount of $35.0 million. Net proceeds of $26.8 million received from the sale of the Building Note were remitted to unsecured creditors on the Emergence Date. The Company repaid the Building Note in full in February 2018. Interest was payable on the Building Note at 6% per annum for the first year following the Emergence Date, 8% per annum for the second year following the Emergence Date, and 10% thereafter through maturity. Interest costs were
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payable in-kind until 90 days after the refinancing of the First Lien Exit Facility, which was May 11, 2017, and approximately $1.3 million in in-kind interest costs were added to the Building Note principal from the Emergence Date. Interest became payable thereafter in cash. The Building Note was set to mature on October 2, 2021 and became prepayable in whole or in part without premium or penalty upon the refinancing of the First Lien Exit Facility. The Building Note was initially recorded at a fair value of $36.6 million upon implementation of fresh start accounting. Prior to repayment, the resulting premium was being amortized to interest expense over the term of the Building Note. Upon repayment, the remaining unamortized premium of $1.2 million was recognized as a gain on extinguishment of debt in the unaudited condensed consolidated statement of operations for the nine-month period ended September 30, 2018.
10. Derivatives
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, on occasion, has sought to manage this risk through the use of commodity derivative contracts, which allow the Company to limit its exposure to commodity price volatility on a portion of its forecasted oil and natural gas sales. The Company has not designated any of its derivative contracts as hedges for accounting purposes and records all derivative contracts at fair value with changes in derivative contract fair values recognized as gain or loss on derivative contracts in the unaudited condensed consolidated statements of operations. None of the Company’s commodity derivative contracts may be terminated prior to contractual maturity solely as a result of a downgrade in the credit rating of a party to the contract. Commodity derivative contracts are settled on a monthly basis. On a quarterly basis, the commodity derivative contract valuations are adjusted to the mark-to-market valuation. At September 30, 2018, the Company’s commodity derivative contracts consisted of fixed price swaps under which 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.
The Company recorded losses on commodity derivative contracts of $11.3 million and $11.7 million for the three-month periods ended September 30, 2018, and 2017, respectively, which include net cash payments (receipts) upon settlement of $11.6 million and $(5.0) million, respectively. The Company recorded loss (gain) on commodity derivative contracts of $59.8 million and $(46.0) million for the nine-month periods ended September 30, 2018, and 2017, respectively, which include net cash payments (receipts) upon settlement of $29.0 million and $(7.7) million, respectively.
On June 26, 2018, the Board suspended the Company's ability to enter into new commodity derivative contracts pending review. In November 2018, the Board concluded this comprehensive evaluation of its commodity derivatives program and determined that no action should be taken with respect to outstanding derivatives contracts at this time. Future derivative transactions will require Board approval.
Master Netting Agreements and the Right of Offset. The Company has master netting agreements with all of its commodity derivative counterparties and has presented its derivative assets and liabilities with the same counterparty on a net basis in the unaudited condensed consolidated balance sheets. As a result of the netting provisions, the Company's maximum amount of loss under commodity derivative transactions due to credit risk is limited to the net amounts due from its counterparties. As of September 30, 2018, the counterparties to the Company’s open commodity derivative contracts consisted of five financial institutions, all of which are also lenders under the Company’s credit facility. The Company is not required to post additional collateral under its commodity derivative contracts as all of the counterparties to the Company’s commodity derivative contracts share in the collateral supporting the Company’s credit facility.
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The following tables summarize (i) the Company's commodity derivative contracts on a gross basis, (ii) the effects of netting assets and liabilities for which the right of offset exists based on master netting arrangements and (iii) for the Company’s net derivative liability positions, the applicable portion of shared collateral under the credit facility as of September 30, 2018, and December 31, 2017 (in thousands):
September 30, 2018

|  | Gross Amounts |  | Gross Amounts Offset |  | Amounts Net of Offset |  | Financial Collateral |  | Net Amount
Assets |  |  |  |  |  |  |  |  |  |
Derivative contracts - current |  | $ | 224 |  | $ | (151) |  | $ | 73 |  | $ | — |  | $ | 73
Derivative contracts - noncurrent |  | — |  | — |  | — |  | — |  | —
Total |  | $ | 224 |  | $ | (151) |  | $ | 73 |  | $ | — |  | $ | 73
Liabilities |  |  |  |  |  |  |  |  |  |
Derivative contracts - current |  | $ | 37,056 |  | $ | (151) |  | $ | 36,905 |  | $ | (36,905) |  | $ | —
Derivative contracts - noncurrent |  | 6,791 |  | — |  | 6,791 |  | (6,791) |  | —
Total |  | $ | 43,847 |  | $ | (151) |  | $ | 43,696 |  | $ | (43,696) |  | $ | —

December 31, 2017

|  | Gross Amounts |  | Gross Amounts Offset |  | Amounts Net of Offset |  | Financial Collateral |  | Net Amount
Assets |  |  |  |  |  |  |  |  |  |
Derivative contracts - current |  | $ | 5,582 |  | $ | (4,272) |  | $ | 1,310 |  | $ | — |  | $ | 1,310
Derivative contracts - noncurrent |  | — |  | — |  | — |  | — |  | —
Total |  | $ | 5,582 |  | $ | (4,272) |  | $ | 1,310 |  | $ | — |  | $ | 1,310
Liabilities |  |  |  |  |  |  |  |  |  |
Derivative contracts - current |  | $ | 14,899 |  | $ | (4,272) |  | $ | 10,627 |  | $ | (10,627) |  | $ | —
Derivative contracts - noncurrent |  | 3,568 |  | — |  | 3,568 |  | (3,568) |  | —
Total |  | $ | 18,467 |  | $ | (4,272) |  | $ | 14,195 |  | $ | (14,195) |  | $ | —

At September 30, 2018, the Company’s open commodity derivative contracts consisted of the following:
Oil Price Swaps

| Notional (MBbls) |  | Weighted Average Fixed Price
October 2018 - December 2018 | 828 |  | $ | 56.12
January 2019 - December 2019 | 1,825 |  | $ | 54.29

Natural Gas Price Swaps

| Notional (MMcf) |  | Weighted Average Fixed Price
October 2018 - December 2018 | 3,680 |  | $ | 3.11

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Fair Value of Derivatives
The following table presents the fair value of the Company’s derivative contracts as of September 30, 2018, and December 31, 2017, on a gross basis without regard to same-counterparty netting (in thousands):

Type of Contract |  | Balance Sheet Classification |  | September 30, 2018 |  | December 31, 2017
Derivative assets |  |  |  |  |  |
Natural gas price swaps |  | Derivative contracts-current |  | $ | 224 |  | $ | 5,582
Derivative liabilities |  |  |  |  |  |
Oil price swaps |  | Derivative contracts-current |  | (37,056) |  | (14,899)
Oil price swaps |  | Derivative contracts-noncurrent |  | (6,791) |  | (3,568)
Total net derivative contracts |  |  |  | $ | (43,623) |  | $ | (12,885)

See Note 6 for additional discussion of the fair value measurement of the Company’s derivative contracts.
11. Commitments and Contingencies
Legal Proceedings. On October 14, 2016, Lisa West and Stormy Hopson filed an amended class action complaint in the United States District Court for the Western District of Oklahoma against SandRidge Exploration and Production, LLC, among other defendants. In their amended complaint, plaintiffs asserted various tort claims seeking relief for damages, including the reimbursement of past and future earthquake insurance premiums, resulting from seismic activity allegedly caused by the defendants’ operation of wastewater disposal wells. The court dismissed the plaintiffs’ amended complaint on May 12, 2017, but permitted the plaintiffs to file a second amended complaint. On July 18, 2017, the plaintiffs filed a second amended class action complaint making allegations substantially similar to those contained in the amended complaint that was previously dismissed. On August 13, 2018, the court granted the Company’s motion to dismiss, thereby dismissing the Company from the lawsuit.
As previously disclosed, on May 16, 2016, the Debtors filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). The Bankruptcy Court confirmed the Plan on September 9, 2016, and the Debtors subsequently emerged from bankruptcy on October 4, 2016.
Pursuant to the Plan, claims against the Company were discharged without recovery in each of the following consolidated cases (the “Cases”):
• In re SandRidge Energy, Inc. Securities Litigation, Case No. 5:12-cv-01341-LRW, USDC, Western District of Oklahoma
• Ivan Nibur, Lawrence Ross, Jase Luna, Matthew Willenbucher, and the Duane & Virginia Lanier Trust v. SandRidge Mississippian Trust I, et al., Case No. 5:15-cv-00634-SLP, USDC, Western District of Oklahoma
• Barton W. Gernandt Jr., et al. v. SandRidge Energy, Inc., Case No. 5:15-cv-00834-D, USDC, Western District of Oklahoma
Although the Cases have not been dismissed against certain former officers and directors who remain defendants in the Cases, the Company remains as a nominal defendant in each of the Cases so that any of the respective plaintiffs may seek to recover proceeds from any applicable insurance policies or proceeds. In each of the Cases, to the extent liability exceeds the amount of available insurance proceeds, the Company may owe indemnity obligations to its former officers and/or directors who remain as defendants in such action. An estimate of reasonably probable losses associated with any of the Cases cannot be made at this time, however the Company believes that any potential liability with respect to the Cases will not be material. The Company has not established any reserves relating to any of the Cases.
In addition to the matters described above, the Company is involved in various lawsuits, claims and proceedings which are being handled and defended by the Company in the ordinary course of business. Pursuant to the terms of the SandRidge Mississippian Trust I and SandRidge Mississippian Trust II, the Company is obligated to indemnify each Royalty Trust against losses, claims, damages, liabilities and expenses, including reasonable costs of investigation and attorney’s fees and expenses arising out of certain legal matters as stipulated in the respective agreements with each Royalty Trust.
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Restricted Cash. Restricted cash - other included on the unaudited condensed consolidated balance sheets at September 30, 2018, and December 31, 2017 is the cash portion of consideration set aside for future settlement of general unsecured claims related to the Chapter 11 proceedings in accordance with the Plan. The corresponding liability for future cash settlements of general unsecured claims is included in accounts payable and accrued expenses on the unaudited condensed consolidated balance sheets.
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, which depend 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 has historically entered into commodity derivative arrangements in order to mitigate a portion of the effect of this price volatility on the Company’s cash flows. The Company may not fully benefit from increases in the market price of oil and natural gas during periods where the strike prices for the Company's commodity derivative contracts are below market prices at the time of settlement. See Note 10 for the Company’s open oil and natural gas derivative contracts.
The Company historically has depended on cash flows from operating activities and, as necessary, borrowings under its credit facility to fund its capital expenditures. Based on its cash balances, cash flows from operating activities and net borrowing availability under the credit facility, the Company expects to be able to fund its planned capital expenditures budget, working capital needs, and any potential debt service requirements for the next year; however, if oil or natural gas prices decline from current levels, they could have a material adverse effect on the Company’s financial position, results of operations, cash flows and quantities of oil, natural gas and NGL reserves that may be economically produced. Potential decreases in the Company's cash flows from operating activities during periods of declining market prices of oil and natural gas may be offset to the extent the Company has commodity derivative contracts in place that have strike prices above market prices at the time of settlement.
12. Equity
Common Stock and Performance Share Units. At September 30, 2018, the Company had 35.7 million shares of common stock, par value $0.001 per share, issued and outstanding, including 0.4 million shares of unvested restricted stock awards, and 250.0 million shares of common stock authorized. In accordance with normal practices, the Company granted additional restricted stock awards and an immaterial amount of performance share units in the third quarter of 2018.
Accelerated Vesting upon Change in Control. As a result of the election of a majority of non-incumbent directors nominated in connection with the proxy contest in the second quarter of 2018, and on the advice of outside counsel, vesting was accelerated for the majority of the Company's then-outstanding unvested restricted stock awards and all of the Company's then-outstanding unvested performance share units. See Note 3 and Note 15 for additional discussion of this event.
Warrants. The Company has issued approximately 4.6 million Series A warrants and 2.0 million Series B warrants that are exercisable until October 4, 2022 for one share of common stock per warrant at initial exercise prices of $41.34 and $42.03 per share, respectively, subject to adjustments pursuant to the terms of the warrants, to certain holders of general unsecured claims as defined in the Plan. The warrants contain customary anti-dilution adjustments in the event of any stock split, reverse stock split, reclassification, stock dividend or other distributions.
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13. Income Taxes
For each interim reporting period, the Company estimates 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 provision for income taxes consisted of the following components (in thousands):

| Three Months Ended September 30, |  |  |  |  | Nine Months Ended September 30, |  |
| 2018 |  |  | 2017 |  | 2018 |  | 2017
Current |  |  |  |  |  |  |  |
Federal | $ | (33) |  |  | $ | (8,460) |  | $ | (33) |  | $ | (8,460)
State | 3 |  |  | 3 |  | (39) |  | (36)
Total provision | $ | (30) |  |  | $ | (8,457) |  | $ | (72) |  | $ | (8,496)

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. The Company’s deferred tax assets have been reduced by a valuation allowance due to a determination 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. The Company continues to closely monitor and weigh all available evidence, including both positive and negative, in making its determination whether to maintain a valuation allowance. As a result of the significant weight placed on the Company's cumulative negative earnings position, the Company continued to maintain a full valuation allowance against its net deferred tax asset at September 30, 2018. Thus, the Company’s effective tax rate and expense for the three and nine-month periods ended September 30, 2018 continue to be low.
The “Tax Cuts and Jobs Act” (the “TCJA”) enacted in December 2017 includes significant changes to the taxation of business entities, most of which are effective for taxable years beginning after December 31, 2017. These changes include, among others, a permanent reduction to the corporate income tax rate from a maximum 35% to a flat 21% rate, expansion of expensing capital expenditures for a period of time, new limitations on the utilization of net operating losses (“NOLs”), and limitations on the deduction of interest expense and executive compensation. We continue to evaluate the impact of the TCJA as new guidance and accounting interpretations become available and while adjustments to certain deferred tax assets may occur in 2018, we do not expect a material adjustment to the provisional amounts recorded for the year ended December 31, 2017 or the nine-month period ended September 30, 2018.
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. As a result of the Chapter 11 reorganization and related transactions, the Company experienced an ownership change within the meaning of IRC Section 382 on October 4, 2016 that subjected certain of the Company’s tax attributes, including $1.9 billion of federal NOL carryforwards, to the IRC Section 382 limitation. This limitation is expected to result in $1.6 billion of the $1.9 billion of federal NOL carryforwards expiring unused. As such, the Company’s deferred tax asset associated with NOLs and corresponding valuation allowance were reduced in the period ended December 31, 2017. The limitation did not result in a current tax liability for the tax year ended December 31, 2017 or the nine-month period ended September 30, 2018. Since the October 4, 2016 ownership change the Company has generated additional NOLs that are not currently subject to an IRC Section 382 limitation. See "Note 19 - Income Taxes" in the 2017 Form 10-K for additional discussion with respect to the impact of income tax elections associated with the Chapter 11 reorganization.
The Company’s only taxing jurisdiction is the United States (federal and state). The Company’s tax years 2015 to present remain open for federal examination. Additionally, tax years 2005 through 2014 remain subject to examination for the purpose of determining the amount of remaining federal NOL and other carryforwards. The number of years open for state tax audits varies, depending on the state, but are generally from three to five years.
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14. Earnings (Loss) per Share
The following table summarizes the calculation of weighted average common shares outstanding used in the computation of diluted earnings (loss) per share:

| Net Income (Loss) |  | Weighted Average Shares |  | Earnings (Loss) Per Share
| (In thousands, except per share amounts) |  |  |  |
Three Months Ended September 30, 2018 |  |  |  |  |
Basic earnings per share | $ | 11,715 |  | 35,308 |  | $ | 0.33
Effect of dilutive securities |  |  |  |  |
Restricted stock awards | — |  | 22 |  |
Performance share units(1) | — |  | — |  |
Warrants(2) | — |  | — |  |
Diluted earnings per share | $ | 11,715 |  | 35,330 |  | $ | 0.33
Three Months Ended September 30, 2017 |  |  |  |  |
Basic loss per share | $ | (8,485) |  | 34,290 |  | $ | (0.25)
Effect of dilutive securities |  |  |  |  |
Restricted stock awards(3) | — |  | — |  |
Performance share units(3) | — |  | — |  |
Warrants(2) | — |  | — |  |
Diluted loss per share | $ | (8,485) |  | 34,290 |  | $ | (0.25)
Nine Months Ended September 30, 2018 |  |  |  |  |
Basic loss per share | $ | (63,253) |  | 34,971 |  | $ | (1.81)
Effect of dilutive securities |  |  |  |  |
Restricted stock awards(4) | — |  | — |  |
Performance share units(1) | — |  | — |  |
Warrants(2) | — |  | — |  |
Diluted loss per share | $ | (63,253) |  | 34,971 |  | $ | (1.81)
Nine Months Ended September 30, 2017 |  |  |  |  |
Basic earnings per share | $ | 65,822 |  | 31,750 |  | $ | 2.07
Effect of dilutive securities |  |  |  |  |
Restricted stock awards | — |  | 234 |  |
Performance share units(1) | — |  | — |  |
Warrants(2) | — |  | — |  |
Diluted earnings per share | $ | 65,822 |  | 31,984 |  | $ | 2.06

____________________
1. No incremental shares of potentially dilutive performance share units were included for the three-month period ended September 30, 2018, or the nine-month periods ended September 30, 2018, or 2017, as their effect was antidilutive under the treasury stock method.
2. No incremental shares of potentially dilutive warrants were included for the three and nine-month periods ended September 30, 2018, or 2017, as their effect was antidilutive.
3. Restricted stock awards covering 0.1 million shares and performance share units covering an insignificant amount of shares for the three-month period ended September 30, 2017, were excluded from the computation of loss per share because their effect would have been antidilutive.
4. No incremental shares of potentially dilutive restricted stock awards were included for the nine-month period ended September 30, 2018, as their effect was antidilutive under the treasury stock method.
See Note 15 for discussion of the Company’s share-based compensation awards.
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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)
15. Share and Incentive-Based Compensation
Share-Based Compensation
Omnibus Incentive Plan. The Company's Omnibus Incentive Plan became effective in October 2016. The Omnibus Incentive Plan authorizes the issuance of up to 4.6 million shares of SandRidge common stock to eligible persons including non-employee directors of the Company, employees of the Company or any of its affiliates, and certain consultants and advisers to the Company or any of its affiliates. The types of awards that may be granted under the Omnibus Incentive Plan include stock options, restricted stock, performance awards and other forms of awards granted or denominated in shares of the Company’s common stock, as well as certain cash-settled awards. At September 30, 2018, the Company had restricted stock awards and an immaterial amount of performance share units outstanding under the Omnibus Incentive Plan.
Restricted Stock Awards. The Company’s restricted stock awards are equity-classified awards and are valued based upon the market value of the Company’s common stock on the date of grant. Vesting for certain restricted stock awards was accelerated in connection with executive terminations and a reduction in force in the first quarter of 2018 with the majority of the remaining restricted stock awards vesting in June 2018 as a result of the accelerated vesting upon change in control event discussed in Note 3. In August 2018, the Company granted additional restricted stock awards. Outstanding restricted shares will generally vest over either a one-year period or three-year period. The following table presents a summary of the Company’s unvested restricted stock awards:

| Number of Shares |  | Weighted Average Grant Date Fair Value
| (In thousands) |  |
Unvested restricted shares outstanding at December 31, 2017 | 1,105 |  | $ | 22.62
Granted | 366 |  | $ | 16.06
Vested | (1,049) |  | $ | 22.71
Forfeited / Canceled | (39) |  | $ | 21.61
Unvested restricted shares outstanding at September 30, 2018 | 383 |  | $ | 16.22

As of September 30, 2018, the Company's unrecognized compensation cost related to unvested restricted stock awards totaled $5.6 million. The remaining weighted average contractual period over which this compensation cost may be recognized is 2.4 years. The aggregate intrinsic value of restricted stock that vested during the nine-month period ended September 30, 2018 was approximately $15.9 million based on the stock price at the time of vesting.
Performance Share Units. In February 2017, the Company granted equity-classified awards in the form of performance share units. The vesting for certain performance share units was accelerated in connection with executive terminations and a reduction in force in the first quarter of 2018 with all remaining units vesting in June 2018 as a result of the accelerated vesting upon change in control event discussed in Note 3. All performance share units for which vesting was accelerated were settled in shares of the Company’s common stock with one share of common stock being issued per performance share unit. In September 2018, the Company granted an immaterial amount of additional performance share units. The following table presents a summary of the Company’s performance share units:

| Number of Units |  | Fair Value per Unit at September 30, 2018
| (In thousands) |  |
Unvested performance share units outstanding at December 31, 2017 | 183 |  |
Granted | 111 |  |
Vested | (177) |  |
Forfeited / Canceled | (6) |  |
Unvested performance share units outstanding at September 30, 2018 | 111 |  | $ | 20.41

The aggregate intrinsic value of performance share units that vested during the nine-month period ended September 30, 2018 was approximately $2.7 million based on the stock price at the time of vesting.
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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)
Incentive-Based Compensation
Performance Units. In October 2016, the Company granted liability-classified awards in the form of performance units. The vesting for certain performance units was accelerated in connection with executive terminations and a reduction in force in the first quarter of 2018 with all remaining units vesting in June 2018 as a result of the accelerated vesting upon change in control acceleration event discussed in Note 3. The accelerated performance units were paid at the issuance value of $100 each. The value for previous vestings was determined by annual scorecard results. The following table presents a summary of the Company’s performance units:

| Number of Units |  | Fair Value per Unit at September 30, 2018
| (In thousands) |  |
Unvested performance units outstanding at December 31, 2017 | 49 |  |
Granted | — |  |
Vested | (48) |  |
Forfeited / Canceled | (1) |  |
Unvested performance units outstanding at September 30, 2018 | — |  | —

The aggregate intrinsic value of performance units that vested during the nine-month period ended September 30, 2018 was approximately $4.8 million.
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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)
The following tables summarize share and incentive-based compensation for the three and nine-month periods ended September 30, 2018, and 2017 (in thousands):

|  | Recurring Compensation Expense(1) |  | Executive Terminations(2) |  | Reduction in Force(2) |  | Change in Control(3) |  | Total
Three Months Ended September 30, 2018 |  |  |  |  |  |  |  |  |  |
Equity-classified awards: |  |  |  |  |  |  |  |  |  |
Restricted stock awards |  | $ | 523 |  | $ | — |  | $ | — |  | $ | — |  | $ | 523
Performance share units |  | 41 |  | — |  | — |  | — |  | 41
Total share-based compensation expense |  | 564 |  | — |  | — |  | — |  | 564
Less: Capitalized compensation expense |  | (58) |  | — |  | — |  | — |  | (58)
Share-based compensation expense, net |  | $ | 506 |  | $ | — |  | $ | — |  | $ | — |  | $ | 506
Three Months Ended September 30, 2017 |  |  |  |  |  |  |  |  |  |
Equity-classified awards: |  |  |  |  |  |  |  |  |  |
Restricted stock awards |  | $ | 3,084 |  | $ | — |  | $ | — |  | $ | — |  | $ | 3,084
Performance share units |  | 397 |  | — |  | — |  | — |  | 397
Total share-based compensation expense |  | 3,481 |  | — |  | — |  | — |  | 3,481
Liability-classified awards: |  |  |  |  |  |  |  |  |  |
Performance units |  | 489 |  | — |  | — |  | — |  | 489
Total share and incentive-based compensation expense |  | 3,970 |  | — |  | — |  | — |  | 3,970
Less: Capitalized compensation expense |  | (593) |  | — |  | — |  | — |  | (593)
Share and incentive-based compensation expense, net |  | $ | 3,377 |  | $ | — |  | $ | — |  | $ | — |  | $ | 3,377

Nine Months Ended September 30, 2018 |  |  |  |  |  |  |  |  |  |
Equity-classified awards: |  |  |  |  |  |  |  |  |  |
Restricted stock awards |  | $ | 3,902 |  | $ | 8,140 |  | $ | 3,777 |  | $ | 5,181 |  | $ | 21,000
Performance share units |  | 400 |  | 1,056 |  | 158 |  | 610 |  | 2,224
Total share-based compensation expense |  | 4,302 |  | 9,196 |  | 3,935 |  | 5,791 |  | 23,224
Liability-classified awards: |  |  |  |  |  |  |  |  |  |
Performance units |  | 776 |  | 2,151 |  | 558 |  | 1,309 |  | 4,794
Total share and incentive-based compensation expense |  | 5,078 |  | 11,347 |  | 4,493 |  | 7,100 |  | 28,018
Less: Capitalized compensation expense |  | (392) |  | — |  | — |  | (555) |  | (947)
Share and incentive-based compensation expense, net |  | $ | 4,686 |  | $ | 11,347 |  | $ | 4,493 |  | $ | 6,545 |  | $ | 27,071
Nine Months Ended September 30, 2017 |  |  |  |  |  |  |  |  |  |
Equity-classified awards: |  |  |  |  |  |  |  |  |  |
Restricted stock awards |  | $ | 11,698 |  | $ | 1,825 |  | $ | — |  | $ | — |  | $ | 13,523
Performance share units |  | 1,007 |  | — |  | — |  | — |  | 1,007
Total share-based compensation expense |  | 12,705 |  | 1,825 |  | — |  | — |  | 14,530
Liability-classified awards: |  |  |  |  |  |  |  |  |  |
Performance units |  | 2,051 |  | — |  | — |  | — |  | 2,051
Total share and incentive-based compensation expense |  | 14,756 |  | 1,825 |  | — |  | — |  | 16,581
Less: Capitalized compensation expense |  | (2,221) |  | — |  | — |  | — |  | (2,221)
Share and incentive-based compensation expense, net |  | $ | 12,535 |  | $ | 1,825 |  | $ | — |  | $ | — |  | $ | 14,360

____________________
1. Recorded in general and administrative expense in the accompanying consolidated statements of operations.
2. Recorded in employee termination benefits in the accompanying consolidated statements of operations.
3. Recorded in accelerated vesting upon change in control in the accompanying consolidated statements of operations.
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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)
16. Subsequent Events
Divestiture of Permian Basin Properties. On November 1, 2018, the Company sold substantially all of its oil and natural gas properties, rights and related assets in the Central Basin Platform ("CBP") region of the Permian Basin, primarily located in Andrews County, TX, along with 13,125,000 common units representing a 25% equity interest in the SandRidge Permian Trust (the "Permian Trust"), to an independent third party for $14.5 million in cash, subject to certain remaining post-closing adjustments. The CBP assets and interest in the Permian Trust include 1,066 producing wells within the Permian Trust's area of mutual interest, certain wells not associated with the Permian Trust, a field office, and all equipment, inventory and yards associated with the Company's CBP operations. As a result of this divestiture, the Company will no longer have any obligations associated with the Permian Trust. This transaction did not result in a significant alteration of the relationship between the Company’s capitalized costs and proved reserves and, accordingly, the divestiture will be accounted for as an adjustment to the full cost pool with no gain or loss recognized on the sale.
Acquisition of Oil and Natural Gas Interests. On November 2, 2018, the Company acquired certain oil and natural gas properties, rights and related assets in the Mississippian Lime and NW STACK areas of Oklahoma and Kansas for approximately $25.1 million, subject to certain remaining post-closing adjustments. The acquired assets primarily consist of interests in 1,962 wells, approximately 80% of which are operated by the Company, an additional 13.2% working interest in approximately 410,000 gross (54,000 net) acres across the Mid-Continent, and an additional 13.2% working interest ownership in the Company's saltwater gathering and disposal system in the Mississippian Lime.
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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 our business, financial condition, results of operations, liquidity and capital resources. This discussion and analysis should be read in conjunction with the accompanying unaudited condensed consolidated financial statements and the accompanying notes included in this Quarterly Report, as well as our audited consolidated financial statements and the accompanying notes included in the 2017 Form 10-K. Our discussion and analysis includes the following subjects:
• Overview;
• Consolidated Results of Operations;
• Liquidity and Capital Resources; and
• Critical Accounting Policies and Estimates
The financial information with respect to the three and nine-month periods ended September 30, 2018, and 2017, discussed below, is unaudited. In the opinion of management, this information contains all adjustments, which consist only of normal recurring adjustments unless otherwise disclosed, necessary to state fairly the accompanying 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
We are an oil and natural gas company with a principal focus on exploration and production activities in the U.S. Mid-Continent and North Park Basin of Colorado.
Operational Activities
Operational activities for the three and nine-month periods ended September 30, 2018, and 2017 include the following:

| Three Months Ended September 30, |  |  |  |  |  |  |  |  |  |
| 2018 |  |  |  |  |  | 2017 |  |  |  |
| Gross Wells Drilled |  | Net Wells Drilled |  | Average Rigs Drilling |  | Gross Wells Drilled |  | Net Wells Drilled |  | Average Rigs Drilling
Area |  |  |  |  |  |  |  |  |  |  |
Mid-Continent (1) | 5 |  | 2.1 |  | 1.9 |  | 9 |  | 6.4 |  | 2.9
North Park Basin | — |  | — |  | 0.3 |  | 3 |  | 3.0 |  | 1.0
Total | 5 |  | 2.1 |  | 2.2 |  | 12 |  | 9.4 |  | 3.9

| Nine Months Ended September 30, |  |  |  |  |  |  |  |  |  |
| 2018 |  |  |  |  |  | 2017 |  |  |  |
| Gross Wells Drilled |  | Net Wells Drilled |  | Average Rigs Drilling |  | Gross Wells Drilled |  | Net Wells Drilled |  | Average Rigs Drilling
Area |  |  |  |  |  |  |  |  |  |  |
Mid-Continent (1) | 15 |  | 4.3 |  | 1.5 |  | 15 |  | 11.3 |  | 2.3
North Park Basin | 8 |  | 8.0 |  | 0.6 |  | 4 |  | 4.0 |  | 0.5
Total | 23 |  | 12.3 |  | 2.1 |  | 19 |  | 15.3 |  | 2.8

____________________
1. Three and 12 wells, respectively, were drilled under the drilling participation agreement during the three and nine-month periods ended September 30, 2018. One well was drilled under the drilling participation agreement during the three and nine-month periods ended September 30, 2017. Under this agreement, we are receiving a 20% net working interest after funding 10% of the drilling and completion costs related to the subject wells. The counterparty to the drilling participation agreement has been billed costs totaling $49.4 million for drilling and completion activity through September 30, 2018, under the initial $100.0 million tranche of the agreement.
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Total production for the three-month period ended September 30, 2018, was comprised of approximately 30.6% oil, 46.7% natural gas and 22.7% NGLs compared to 26.7% oil, 50.7% natural gas and 22.6% NGLs in the same period of 2017. Total production for the nine-month period ended September 30, 2018, was comprised of approximately 28.4% oil, 48.9% natural gas and 22.7% NGLs compared to 27.5% oil, 49.6% natural gas and 22.9% NGLs in the same period of 2017.
Recent Events
Divestiture of Permian Basin Properties. On November 1, 2018, we sold substantially all of our oil and natural gas properties, rights and related assets in the CBP region of the Permian Basin, together with 13,125,000 common units of the Trust, to an independent third party for $14.5 million in cash, subject to certain remaining post-closing adjustments. This transaction did not result in a significant alteration of the relationship between our capitalized costs and proved reserves and, accordingly, the proceeds were recorded as a reduction of our full cost pool with no gain or loss recognized on the sale. We believe that exiting the CBP will simplify our portfolio and operations, and allow us to increase our focus on our core asset development strategy. See "Note 16 - Subsequent Events" for further discussion of this divestiture.
Acquisition of Oil and Gas Interests. On November 2, 2018, we acquired certain oil and natural gas properties, rights and related assets in the Mississippian Lime and NW STACK areas of Oklahoma and Kansas for approximately $25.1 million, subject to certain remaining post-closing adjustments. As of September 2018, these oil and gas properties had monthly net production of 3,775 barrels of oil per day. This transaction compliments and consolidates working interests in wells we currently operate, and therefore requires little effort to integrate into our operations. See "Note 16 - Subsequent Events" for further discussion of this acquisition.
CEO Search. On September 17, 2018, William M. Griffin, Jr., Interim President and CEO, informed the Board that he would not be a candidate to serve as the ongoing President and CEO. Mr. Griffin will continue serving as Interim President and CEO until a successor is appointed and will continue as a non-employee member of the Board thereafter. The Board has formed a search committee to evaluate and recommend to the Board candidates to serve as President and CEO following the departure of Mr. Griffin.
Terminated Poison Pill. On November 26, 2017, we entered into an agreement with American Stock Transfer & Trust Company, LLC (as amended by the First Amendment to the Stockholder Rights Agreement dated January 22, 2018, the "Poison Pill"). At our 2018 annual meeting in June 2018, the Poison Pill was terminated.
Proxy Contest. Prior to our 2018 annual meeting, Icahn proposed a slate of candidates for the Board, and our shareholders voted a majority of non-incumbent directors onto the Board. Subsequent to the shareholder vote, by agreement of all the request parties, the size of the Board was expanded to eight directors.
Executive terminations and reduction in force. On February 8, 2018, our then-current CEO, James Bennett, separated employment from the Company, and on February 22, 2018, our then-current CFO, Julian Bott, also separated employment from the Company. In accordance with the terms of their respective employment agreements, we incurred cash severance costs of $11.9 million and accelerated share-based compensation costs of $9.2 million associated with these executive terminations during the nine-month period ended September 30, 2018 as discussed in "Note 4 - Employee Termination Benefits."
Additionally, as a result of a 26% reduction in workforce in February 2018, we incurred cash severance costs of $7.6 million and accelerated share-based compensation costs of $3.9 million during the nine-month period ended September 30, 2018 as discussed in "Note 4 - Employee Termination Benefits."
Outlook
On June 29, 2018, the Board announced an expanded pursuit of the strategic options process with RBC Capital Markets which could have included a possible sale of the Company or significant assets of the Company. The Board also announced the beginning of a complete and thorough review of assets and operating strategies, including capital expenditures and drilling programs, and expenses. On September 10, 2018, the Board announced that it had concluded its formal strategic review process following the thorough evaluation of multiple potential transactions, all of which the Board believed significantly undervalued either the Company or its resources. The Board concluded that the optimal course is to develop our extensive inventory base in the NW STACK and the North Park Basin and pursue value enhancement opportunities in the Mississippian Lime. We will also continue to pursue opportunistic acquisitions of strategic assets that provide complimentary, high quality production and development upside in a capital disciplined manner such as the acquisition described in "—Recent Events" above. We will
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continue to focus on cost reductions, margin improvements and opportunistic divestment of core and non-core properties, while moving forward with a profitable plan for organic growth.
Consolidated Results of Operations
The majority of our consolidated revenues and cash flow are generated from the production and sale of oil, natural gas and NGLs. Our revenues, profitability and future growth depend substantially on prevailing prices received for our production, the quantity of oil, natural gas and NGLs we produce, our ability to find and economically develop and produce our reserves, and changes in the fair value of our commodity derivative contracts. Prices for oil, natural gas and NGLs fluctuate widely and are difficult to predict.
To provide information on the general trend in pricing, the average NYMEX prices for oil and natural gas during the three and nine-month periods ended September 30, 2018, and 2017 are shown in the table below:

|  | Three Months Ended September 30, |  |  |  | Nine Months Ended September 30, |  |
|  | 2018 |  | 2017 |  | 2018 |  | 2017
Oil (per Bbl) |  | $ | 69.43 |  | $ | 48.20 |  | $ | 66.79 |  | $ | 49.36
Natural gas (per MMBtu) |  | $ | 2.86 |  | $ | 2.95 |  | $ | 2.85 |  | $ | 3.05

In order to reduce our exposure to price fluctuations, we have historically entered into commodity derivative contracts for a portion of our anticipated future oil and natural gas production depending on management's view of opportunities under then-prevailing market conditions as discussed in “Item 3. Quantitative and Qualitative Disclosures About Market Risk.” Reducing our exposure to price volatility helps mitigate the risk that we will not have adequate funds available for our capital expenditure programs. During periods where the strike prices for our commodity derivative contracts are below market prices at the time of settlement, we may not fully benefit from increases in the market price of oil and natural gas. Conversely, during periods of declining market prices of oil and natural gas, our commodity derivative contracts may partially offset declining revenues and cash flow to the extent strike prices for our contracts are above market prices at the time of settlement.
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Oil, Natural Gas and NGL Production and Pricing
Set forth in the table below is production and pricing information for the Company for the three and nine-month periods ended September 30, 2018, and 2017:

| Three Months Ended September 30, |  |  |  |  |  |  | Nine Months Ended September 30, |  |
| 2018 |  | 2017 |  |  |  |  | 2018 |  | 2017
Production data |  |  |  |  |  |  |  |  |  |
Oil (MBbls) | 956 |  | 954 |  |  |  |  | 2,637 |  | 3,130
NGL (MBbls) | 710 |  | 807 |  |  |  |  | 2,110 |  | 2,601
Natural gas (MMcf) | 8,757 |  | 10,850 |  |  |  |  | 27,221 |  | 33,883
Total volumes (MBoe) | 3,126 |  | 3,569 |  |  |  |  | 9,284 |  | 11,378
Average daily total volumes (MBoe/d) | 34.0 |  | 38.8 |  |  |  |  | 34.0 |  | 41.7
Average prices—as reported(1) |  |  |  |  |  |  |  |  |  |
Oil (per Bbl) | $ | 66.94 |  | $ | 46.16 |  |  |  |  | $ | 63.16 |  | $ | 47.22
NGL (per Bbl) | $ | 26.45 |  | $ | 19.07 |  |  |  |  | $ | 24.70 |  | $ | 16.52
Natural gas (per Mcf) | $ | 1.68 |  | $ | 1.95 |  |  |  |  | $ | 1.66 |  | $ | 2.14
Total (per Boe) | $ | 31.19 |  | $ | 22.57 |  |  |  |  | $ | 28.41 |  | $ | 23.14
Average prices—including impact of derivative contract settlements |  |  |  |  |  |  |  |  |  |
Oil (per Bbl) | $ | 53.99 |  | $ | 49.67 |  |  |  |  | $ | 50.81 |  | $ | 49.42
NGL (per Bbl) | $ | 26.45 |  | $ | 19.07 |  |  |  |  | $ | 24.70 |  | $ | 16.52
Natural gas (per Mcf) | $ | 1.77 |  | $ | 2.10 |  |  |  |  | $ | 1.79 |  | $ | 2.16
Total (per Boe) | $ | 27.47 |  | $ | 23.97 |  |  |  |  | $ | 25.28 |  | $ | 23.81

__________________
1. Prices represent actual average sales prices for the periods presented and do not include effects of derivatives.
The table below presents production by area of operation for the three and nine-month periods ended September 30, 2018, and 2017:

| Three Months Ended September 30, |  |  |  |  |  |  |  | Nine Months Ended September 30, |  |  |  |  |  |  |
| 2018 |  |  |  | 2017 |  |  |  | 2018 |  |  |  |  | 2017 |  |
| Production (MBoe) |  | % of Total |  | Production (MBoe) |  | % of Total |  | Production (MBoe) |  | % of Total |  |  | Production (MBoe) |  | % of Total
Mississippian Lime | 2,414 |  | 77.2 | % |  | 3,072 |  | 86.1 | % |  | 7,482 |  | 80.5 | % |  |  | 9,974 |  | 87.7 | %
NW STACK | 221 |  | 7.1 | % |  | 242 |  | 6.8 | % |  | 743 |  | 8.0 | % |  |  | 537 |  | 4.7 | %
North Park Basin | 379 |  | 12.1 | % |  | 128 |  | 3.6 | % |  | 720 |  | 7.8 | % |  |  | 473 |  | 4.2 | %
Permian Basin | 112 |  | 3.6 | % |  | 127 |  | 3.5 | % |  | 339 |  | 3.7 | % |  |  | 394 |  | 3.4 | %
Total | 3,126 |  | 100.0 | % |  | 3,569 |  | 100.0 | % |  | 9,284 |  | 100.0 | % |  |  | 11,378 |  | 100.0 | %

Revenues
Consolidated revenues for the three and nine-month periods ended September 30, 2018, and 2017 are presented in the table below (in thousands):

| Three Months Ended September 30, |  |  |  | Nine Months Ended September 30, |  |
| 2018 |  | 2017 |  | 2018 |  | 2017
Oil | $ | 63,994 |  | $ | 44,032 |  | $ | 166,548 |  | $ | 147,792
NGL | 18,776 |  | 15,391 |  | 52,111 |  | 42,962
Natural gas | 14,721 |  | 21,117 |  | 45,102 |  | 72,481
Other | 169 |  | 352 |  | 489 |  | 858
Total revenues | $ | 97,660 |  | $ | 80,892 |  | $ | 264,250 |  | $ | 264,093

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Variances in oil, natural gas and NGL revenues attributable to changes in the average prices received for our production and total production volumes sold for the three and nine-month periods ended September 30, 2018, and 2017 are shown in the tables below (in thousands):

| Three Months Ended September 30 |  | Nine Months Ended September 30
2017 oil, natural gas and NGL revenues | $ | 80,540 |  | $ | 263,235
Change due to production volumes | (5,831) |  | (45,640)
Change due to average prices | 22,782 |  | 46,166
2018 oil, natural gas and NGL revenues | $ | 97,491 |  | $ | 263,761

Revenues from oil, natural gas and NGL sales increased $17.0 million, or 21.0% and $0.5 million, or 0.2% for the three and nine-month periods ended September 30, 2018, compared to the same periods in 2017, respectively, due primarily to an increase in average prices received for our oil and NGL production during the 2018 periods. These increases were partially offset by a decrease in total production, resulting largely from natural declines in existing producing wells.
Expenses
Expenses for the three and nine-month periods ended September 30, 2018, and 2017 consisted of the following (in thousands):

| Three Months Ended September 30, |  |  |  |  | Nine Months Ended September 30, |  |
| 2018 |  |  | 2017 |  | 2018 |  | 2017
Production | $ | 23,429 |  |  | $ | 26,765 |  | $ | 68,927 |  | $ | 76,997
Production taxes | 5,636 |  |  | 3,606 |  | 14,725 |  | 9,435
Depreciation and depletion—oil and natural gas | 33,090 |  |  | 31,029 |  | 92,048 |  | 87,486
Depreciation and amortization—other | 3,036 |  |  | 3,399 |  | 9,229 |  | 10,729
Impairment | — |  |  | 498 |  | 4,170 |  | 3,475
General and administrative | 9,251 |  |  | 20,292 |  | 33,616 |  | 59,184
Accelerated vesting upon change in control | — |  |  | — |  | 6,545 |  | —
Proxy contest | (459) |  |  | — |  | 7,139 |  | —
Employee termination benefits | 23 |  |  | — |  | 32,653 |  | 4,815
Loss (gain) on derivative contracts | 11,329 |  |  | 11,702 |  | 59,763 |  | (46,024)
Other operating (income) expense | (105) |  |  | (132) |  | (1,343) |  | 135
Total expenses | $ | 85,230 |  |  | $ | 97,159 |  | $ | 327,472 |  | $ | 206,232

Production expense includes, but is not limited to, lease operating expense and treating costs. Production costs per Boe were relatively consistent at $7.49 for the three-month period ended September 30, 2018, compared to $7.50 for the same 2017 period. Production costs per Boe increased to $7.42 for the nine-month period ended September 30, 2018, from $6.77 per Boe for the same 2017 period, primarily due to the decrease in total production noted above.
Production taxes as a percentage of oil, natural gas and NGL revenue increased to approximately 5.8% and 5.6% for the three and nine-month periods ended September 30, 2018, compared to approximately 4.5% and 3.6%, respectively, for the same periods in 2017. These increases were primarily due to fewer wells having the benefit of tax credits in 2018 compared to 2017 due to the loss of certain horizontal tax credits, which caused previous rates to increase back to statutory rates for certain wells.
Depreciation and depletion for our oil and natural gas properties increased by $2.1 million and $4.6 million for the three and nine-month periods ended September 30, 2018, compared to the same periods in 2017, respectively, primarily due to an increase in the average depletion rates to $10.59 per Boe and $9.91 per Boe compared to $8.69 per Boe and $7.69 per Boe for the same 2017 periods, respectively. The increases in the average depletion rates resulted primarily from increases in future development costs associated with proved undeveloped reserves in the North Park Basin, and to a lesser extent, in our Mid-Continent NW STACK play, as well as an increase in future capital for improved recovery systems in the Mid-Continent, and to a lesser extent, the North Park Basin. As a substantial number of our maturing wells in the Mississippian Lime are converted or are expected to convert from submersible pump to rod pump, we anticipate an increase in capital related to rod pump production over the remaining life of such wells. As we continue to shift more capital to develop our North Park Basin oil asset
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where the anticipated future development costs are expected to be higher than in prior periods, average depletion rates may continue to increase.
Impairment for the nine-month period ended September 30, 2018, primarily reflects the write-down of midstream generator assets classified as held for sale to estimated net realizable value. Impairment for the three and nine-month periods ended September 30, 2017, reflects the write-down of the remaining drilling and services assets classified as held for sale to estimated net realizable value.
General and administrative expenses decreased $11.0 million, or 54.4% for the three-month period ended September 30, 2018, from the same period in 2017 due primarily to (i) a $5.6 million decrease in compensation-related costs largely resulting from a reduction in force during the first quarter of 2018, (ii) a decrease of $4.2 million in professional services costs due primarily to incurring significant consultant fees in the 2017 period after the Company’s restructuring, and (iii) a decrease of $1.2 million in other miscellaneous general and administrative items.
General and administrative expenses decreased $25.6 million, or 43.2% for the nine-month period ended September 30, 2018, from the same period in 2017 due primarily to (i) an $18.8 million decrease in compensation-related costs largely resulting from a reduction in force during the first quarter of 2018 as well as additional declines in headcount throughout 2018, (ii) a decrease of $6.0 million in professional services costs due primarily to incurring significant consultant fees in the 2017 period after the Company’s restructuring and (iii) a decrease of $0.8 million in other miscellaneous general and administrative items.
Accelerated vesting upon change in control costs incurred during the nine-month period ended September 30, 2018 include compensation costs recognized for the accelerated vesting of certain share and incentive-based awards granted to our employees and directors as discussed in "Note 3 - Proxy Contest" in the accompanying unaudited condensed consolidated financial statements.
Proxy contest costs for the nine-month period ended September 30, 2018 include legal, consulting and advisory fees incurred in the proxy contest and strategic alternatives review which were initiated in response to shareholder actions in 2018, which were offset by a $0.5 million reimbursement of costs received in the third quarter of 2018. See "Note 3 - Proxy Contest" in the accompanying unaudited condensed consolidated financial statements for additional discussion of proxy contest costs.
Employee termination benefits for the nine-month period ended September 30, 2018, include cash and share-based severance costs incurred primarily as a result of (i) the reduction in force in the first quarter of 2018 and (ii) severance costs associated with the departure of executive officers and other senior officers. See "Note 4 - Employee Termination Benefits" in the accompanying unaudited condensed consolidated financial statements and "—Recent Events" above for additional discussion of these expenses.
Employee termination benefits for the nine-month period ended September 30, 2017, include cash and share-based compensation costs incurred upon the departure of our former Executive Vice President of Investor Relations and Strategy, Duane Grubert as well as severance costs incurred due to the reduction in workforce in the fourth quarter of 2016. See "Note 4 - Employee Termination Benefits" in the accompanying unaudited condensed consolidated financial statements for additional discussion of these expenses.
We recorded losses on commodity derivative contracts of $11.3 million and $11.7 million for the three-month periods ended September 30, 2018, and 2017, respectively, which include net cash payments (receipts) upon settlement of $11.6 million and $(5.0) million, respectively. We recorded loss (gain) on commodity derivative contracts of $59.8 million and $(46.0) million for the nine-month periods ended September 30, 2018, and 2017, respectively, which include net cash payments (receipts) upon settlement of $29.0 million and $(7.7) million, respectively.
On November 14, 2017, we entered into an Agreement and Plan of Merger (the "merger") with Bonanza Creek Energy, Inc. ("Bonanza Creek"). In contemplation of the proposed merger with Bonanza Creek, which would have been partially financed with debt, we entered into several oil derivative contracts in November 2017. We recorded losses on such oil derivatives of $6.5 million and $22.9 million for the three and nine-month periods ended September 30, 2018, which include net cash payments upon settlement of $2.4 million and $5.8 million, respectively.
Our derivative contracts are not designated as accounting hedges and, as a result, changes in the fair value of our commodity derivative contracts are recorded each quarter as a component of operating expenses. Internally, management views the settlement of commodity derivative contracts at contractual maturity as adjustments to the price received for oil and natural
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gas production to determine “effective prices.” In general, cash is received on settlement of contracts due to lower oil and natural gas prices at the time of settlement compared to the contract price for our commodity derivative contracts, and cash is paid on settlement of contracts due to higher oil and natural gas prices at the time of settlement compared to the contract price for our commodity derivative contracts.
Other operating expense in the nine-month period ended September 30, 2018 primarily reflects the gain on the sale of one of the Company’s properties located in downtown Oklahoma City, OK.
Other (Expense) Income
The Company’s other (expense) income for the three and nine-month periods ended September 30, 2018, and 2017 are presented in the table below (in thousands).

| Three Months Ended September 30, |  |  |  | Nine Months Ended September 30, |  |
| 2018 |  | 2017 |  | 2018 |  | 2017
Other (expense) income |  |  |  |  |  |  |
Interest expense, net | $ | (627) |  | $ | (872) |  | $ | (2,226) |  | $ | (2,757)
Gain on extinguishment of debt | — |  | — |  | 1,151 |  | —
Other (expense) income, net | (118) |  | 197 |  | 972 |  | 2,222
Total other expense | $ | (745) |  | $ | (675) |  | $ | (103) |  | $ | (535)

Gain on extinguishment of debt was recognized for the nine-month period ended September 30, 2018, as a result of writing off the unamortized premium in conjunction with the repayment of the Building Note during the first quarter of 2018.
Liquidity and Capital Resources
As of September 30, 2018, our cash and cash equivalents, excluding restricted cash, were $32.6 million. Additionally, we had no debt outstanding under our $425.0 million credit facility and $6.2 million in outstanding letters of credit, which reduce the amount available under the credit facility. As of November 2, 2018, the Company had approximately $19.6 million in cash and cash equivalents, excluding restricted cash, an undrawn $350.0 million credit facility after the October 2018 redetermination, and $6.2 million in outstanding letters of credit.
Working Capital and Sources and Uses of Cash
Our principal sources of liquidity for the next year include cash flow from operations, cash on hand and amounts available under our credit facility, as discussed in “—Credit Facility” below.
Our working capital deficit increased to $98.3 million at September 30, 2018, compared to $3.8 million at December 31, 2017, largely due to the repayment of the building note in the first quarter of 2018, employee termination benefits paid during the first quarter of 2018 and changes in derivative assets and liabilities due to quarterly mark-to-market adjustments. This decrease is partially offset by fluctuations in the timing and amount of payments of accounts payable and accrued expenses.
We have established a range for our 2018 capital expenditures budget between $180.0 million and $190.0 million, with the substantial majority of the budgeted expenditures being designated for drilling and completion activities. Management intends to fund remaining 2018 capital expenditures using cash flow from operations, cash on hand and, if necessary, borrowings under the credit facility discussed below.
Cash Flows
Our cash flows from operations, which impact our ability to fund our capital expenditures, are substantially dependent on current and future prices for oil and natural gas, which historically have been, and may continue to be, volatile. For example, during the period from January 2016 through September 2018, the NYMEX settled price for oil fluctuated between a high of $74.15 per Bbl in June 2018 and a low of $26.21 per Bbl in February 2016, and the month-end NYMEX settled price for gas fluctuated between a high of $3.93 per MMBtu in January 2017 and a low of $1.71 per MMBtu in March 2016.
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Our cash flows for the nine-month periods ended September 30, 2018, and 2017 are presented in the following table and discussed below (in thousands):

| Nine Months Ended September 30, |  |
| 2018 |  | 2017
Cash flows provided by operating activities | $ | 109,168 |  | $ | 147,906
Cash flows used in investing activities | (132,322) |  | (181,210)
Cash flows used in financing activities | (43,680) |  | (5,254)
Net decrease in cash and cash equivalents | $ | (66,834) |  | $ | (38,558)

Cash Flows from Operating Activities
The $38.7 million decrease in operating cash flows for the nine-month period ended September 30, 2018, compared to the same period in 2017, is primarily due to (i) cash paid for employee termination benefits, (ii) cash paid on settlement of derivative contracts in the 2018 period compared to receiving cash in the 2017 period, and (iii) other changes in working capital, partially offset by lower general and administrative costs. See “—Consolidated Results of Operations” for further analysis of the changes in operating expenses.
Cash Flows from Investing Activities
We dedicate and expect to continue to dedicate a substantial portion of our capital expenditure program toward the exploration for and development of our oil and natural gas properties. These capital expenditures are necessary to offset inherent declines in production and proved reserves, which is typical in the capital-intensive oil and natural gas industry. During the nine-month period ended September 30, 2018, cash flows used in investing activities primarily consisted of capital expenditures for drilling and completion activities, which were partially offset by proceeds received from the sale of one of the Company's properties located in downtown Oklahoma City and various other midstream equipment. During the nine-month period ended September 30, 2017, cash flows used in investing activities included the acquisition of 13,000 net acres in Woodward County, Oklahoma for approximately $47.8 million in cash and capital expenditures for drilling and completion activities, which were partially offset by proceeds of $19.8 million from the sale of various non-core oil and natural gas properties and certain drilling equipment previously classified as held for sale.
Capital expenditures for the nine-month periods ended September 30, 2018, and 2017 are summarized on an accrual basis below (in thousands):

| Nine Months Ended September 30, |  |
| 2018 |  | 2017
Capital Expenditures (on an accrual basis) |  |  |
Drilling and completion | $ | 107,382 |  | $ | 122,438
Leasehold and geophysical | 9,842 |  | 43,858
Other - operating | 410 |  | 282
Other - corporate | 44 |  | 1,406
Capital expenditures, excluding acquisitions | 117,678 |  | 167,984
Acquisitions | — |  | 48,236
Total | $ | 117,678 |  | $ | 216,220

Cash Flows from Financing Activities
Our cash used in financing activities was approximately $43.7 million for the nine-month period ended September 30, 2018, which consisted of the repayment of the building note and cash paid for employee tax obligations in connection with the withholding of common shares upon vesting of employee share-based compensation awards. Our cash used in financing activities was approximately $5.3 million during the nine-month period ended September 30, 2017, which consisted of cash paid for employee tax obligations in connection with the withholding of common shares upon vesting of employee share-based compensation awards and deferred financing costs incurred on the credit facility.
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Indebtedness
Credit Facility
We had no debt outstanding under our credit facility at September 30, 2018. The borrowing base under the credit facility is $350.0 million, which was reduced from $425.0 million during the October 2018 borrowing base redetermination. The next semi-annual borrowing base redetermination is scheduled for April 1, 2019. The credit facility is secured by (i) first-priority mortgages on at least 95% of the PV-9 valuation of all proved reserves included in our most recently delivered reserve report, (ii) a first-priority perfected pledge of substantially all of the capital stock owned by each credit party and equity interests in the Royalty Trusts that are owned by a credit party and (iii) a first-priority perfected security interest in substantially all the cash, cash equivalents, deposits, securities and other similar accounts, and other tangible and intangible assets of the credit parties (including but not limited to as-extracted collateral, accounts receivable, inventory, equipment, general intangibles, investment property, intellectual property, real property and the proceeds of the foregoing).
The credit facility requires us to maintain (i) a maximum consolidated total net leverage ratio, measured as of the end of any fiscal quarter, of no greater than 3.50 to 1.00 and (ii) a minimum consolidated interest coverage ratio, measured as of the end of any fiscal quarter, of no less than 2.25 to 1.00. These financial covenants are subject to customary cure rights. We were in compliance with all applicable financial covenants under the credit facility as of September 30, 2018.
The credit facility contains customary affirmative and negative covenants, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements, oil and gas engineering reports, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens, indebtedness, asset dispositions, fundamental changes, restricted payments and other customary covenants.
The credit facility includes events of default relating to customary matters, including, among other things, nonpayment of principal, interest or other amounts; violation of covenants; incorrectness of representations and warranties in any material respect; cross-payment default and cross acceleration with respect to indebtedness in an aggregate principal amount of $25.0 million or more; bankruptcy; judgments involving liability of $25.0 million or more that are not paid; and ERISA events. Many events of default are subject to customary notice and cure periods.
Building Note
On the Emergence Date, we entered into the Building Note, which had an initial principal amount of $35.0 million and was secured by first priority mortgages on our real estate in Oklahoma City, Oklahoma. We repaid the Building Note in full during February 2018. The Building Note was recorded at fair value ($36.6 million) upon implementation of fresh start accounting, and approximately $1.3 million in in-kind interest costs were added to the principal prior to interest becoming payable in cash after the refinancing of the First Lien Exit Facility. The Building Note was set to mature on October 2, 2021, and was prepayable in whole or in part without premium or penalty.
See “Note 9 - Long-Term Debt” to the accompanying unaudited condensed consolidated financial statements for additional discussion of the Company’s debt.
Contractual Obligations and Off-Balance Sheet Arrangements
At December 31, 2017, the Company’s contractual obligations included long-term debt obligations, third-party drilling rig agreements, asset retirement obligations, operating leases and other individually insignificant obligations. Additionally, we have certain financial instruments representing potential commitments that were incurred in the normal course of business to support our operations, including standby letters of credit and surety bonds. The underlying liabilities insured by these instruments are reflected in our balance sheets, where applicable. Therefore, no additional liability is reflected for the letters of credit and surety bonds.
Other than the repayment of the Building Note discussed above, there were no other significant changes in contractual obligations and off-balance sheet arrangements from those reported in the 2017 Form 10-K.
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Critical Accounting Policies and Estimates
For a description of our critical accounting policies and estimates, refer to Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2017 Form 10-K. For a discussion of recent accounting pronouncements, newly adopted and recent accounting pronouncements not yet adopted, see “Note 1 - Basis of Presentation” to the accompanying unaudited condensed consolidated financial statements included in Item 1 of this Quarterly Report. We did not have any material changes in critical accounting policies, estimates, judgments and assumptions during the first nine months of 2018.
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk
General
This discussion provides information about the financial instruments we use to manage commodity prices. All contracts are settled in cash and do not require the actual delivery of a commodity at settlement. Additionally, our exposure to credit risk and interest rate risk is also discussed.
Commodity Price Risk. Our most significant market risk relates to the prices we receive for our oil, natural gas and NGLs. Due to the historical price volatility of these commodities, from time to time, depending upon our view of opportunities under the then-prevailing current market conditions, we enter into commodity price derivative contracts for a portion of our anticipated production volumes for the purpose of reducing variability of oil and natural gas prices we receive. Our credit facility limits our ability to enter into derivative transactions to 90% of expected production volumes from estimated proved reserves over the period covered by the transactions.
We use, and may continue to use, a variety of commodity-based derivative contracts, including fixed price swaps, basis swaps and collars. At September 30, 2018, our commodity derivative contracts consisted of fixed price swaps under which we receive a fixed price for the contract and pay a floating market price to the counterparty over a specified period for a contracted volume.
Our oil fixed price swap transactions are settled based upon the average daily prices for the calendar month of the contract period and our natural gas fixed price swap transactions are settled based upon the last day settlement of the first nearby month futures contract of the contract period. Settlement for oil derivative contracts occurs in the succeeding month and natural gas derivative contracts are settled in the production month.
On June 26, 2018, the Board suspended the Company's ability to enter into new commodity derivative contracts pending review. In November 2018, the Board concluded this comprehensive evaluation of its commodity derivatives program and determined that no action should be taken with respect to outstanding derivatives contracts at this time. Future derivative transactions will require Board approval.
At September 30, 2018, our open commodity derivative contracts consisted of the following:
Oil Price Swaps

| Notional (MBbls) |  | Weighted Average Fixed Price
October 2018 - December 2018 | 828 |  | $ | 56.12
January 2019 - December 2019 | 1,825 |  | $ | 54.29

Natural Gas Price Swaps

| Notional (MMcf) |  | Weighted Average Fixed Price
October 2018 - December 2018 | 3,680 |  | $ | 3.11

Because we have not designated any of our derivative contracts as hedges for accounting purposes, changes in fair values of our derivative contracts are recognized as gains and losses in current period earnings. As a result, our current period earnings may be significantly affected by changes in the fair value of our commodity derivative contracts. Changes in fair value are principally measured based on a comparison of future prices as of period-end to the contract price.
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The Company recorded losses on commodity derivative contracts of $11.3 million and $11.7 million for the three-month periods ended September 30, 2018, and 2017, respectively, which include net cash payments (receipts) upon settlement of $11.6 million and $(5.0) million, respectively. We recorded loss (gain) on commodity derivative contracts of $59.8 million and $(46.0) million for the nine-month periods ended September 30, 2018, and 2017, respectively, which include net cash payments (receipts) upon settlement of $29.0 million and $(7.7) million, respectively.
See “Note 10 - Derivatives” to the accompanying unaudited condensed consolidated financial statements included in this Quarterly Report for additional information regarding our commodity derivatives.
Credit Risk. All of our derivative transactions have been carried out in the over-the-counter market. The use of derivative transactions in over-the-counter markets involves the risk that the counterparties may be unable to meet the financial terms of the transactions. The counterparties for all of our derivative transactions have an “investment grade” credit rating. We monitor the credit ratings of our derivative counterparties and consider our counterparties’ credit default risk ratings in determining the fair value of our derivative contracts. Our derivative contracts are with multiple counterparties to minimize exposure to any individual counterparty.
We do not require collateral or other security from counterparties to support derivative instruments. We have master netting agreements with each of our derivative contract counterparties, which allow us to net our derivative assets and liabilities by commodity type with the same counterparty. As a result of the netting provisions, our maximum amount of loss under derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the commodity derivative contracts. Our loss is further limited as any amounts due from a defaulting counterparty that is a lender under the credit facility can be offset against amounts owed, if any, to such counterparty. As of September 30, 2018, the counterparties to our open commodity derivative contracts consisted of five financial institutions, all of which are also lenders under our credit facility. As a result, we are not required to post additional collateral under our commodity derivative contracts.
Interest Rate Risk. We are exposed to interest rate risk on our credit facility. This variable interest rate on our credit facility fluctuates, and exposes us to short-term changes in market interest rates as our interest obligations on this instrument is periodically redetermined based on prevailing market interest rates, primarily LIBOR and the federal funds rate. We had no outstanding variable rate debt as of September 30, 2018.
ITEM 4. Controls and Procedures
Disclosure 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 Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of September 30, 2018, 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.
Changes in Internal Control Over Financial Reporting
There was no change in the Company’s internal control over financial reporting during the quarter ended September 30, 2018 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.
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PART II. Other Information
ITEM 1. Legal Proceedings
On October 14, 2016, Lisa West and Stormy Hopson filed an amended class action complaint in the United States District Court for the Western District of Oklahoma against SandRidge Exploration and Production, LLC, among other defendants. In their amended complaint, plaintiffs asserted various tort claims seeking relief for damages, including the reimbursement of past and future earthquake insurance premiums, resulting from seismic activity allegedly caused by the defendants’ operation of wastewater disposal wells. The court dismissed the plaintiffs’ amended complaint on May 12, 2017, but permitted the plaintiffs to file a second amended complaint. On July 18, 2017, the plaintiffs filed a second amended class action complaint making allegations substantially similar to those contained in the amended complaint that was previously dismissed. On August 13, 2018, the court granted the Company’s motion to dismiss, thereby dismissing the Company from the lawsuit.
As previously disclosed, on May 16, 2016, the Debtors filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code in the Bankruptcy Court. The Bankruptcy Court confirmed the Plan on September 9, 2016, and the Debtors subsequently emerged from bankruptcy on October 4, 2016.
Pursuant to the Plan, claims against the Company were discharged without recovery in each of the following consolidated Cases:
• In re SandRidge Energy, Inc. Securities Litigation, Case No. 5:12-cv-01341-LRW, USDC, Western District of Oklahoma
• Ivan Nibur, Lawrence Ross, Jase Luna, Matthew Willenbucher, and the Duane & Virginia Lanier Trust v. SandRidge Mississippian Trust I, et al., Case No. 5:15-cv-00634-SLP, USDC, Western District of Oklahoma
• Barton W. Gernandt Jr., et al. v. SandRidge Energy, Inc., Case No. 5:15-cv-00834-D, USDC, Western District of Oklahoma
Although the Cases have not been dismissed against certain former officers and directors who remain defendants in the Cases, the Company remains as a nominal defendant in each of the Cases so that any of the respective plaintiffs may seek to recover proceeds from any applicable insurance policies or proceeds. In each of the Cases, to the extent liability exceeds the amount of available insurance proceeds, the Company may owe indemnity obligations to its former officers and/or directors who remain as defendants in such action. An estimate of reasonably probable losses associated with any of the Cases cannot be made at this time, however the Company believes that any potential liability with respect to the Cases will not be material. The Company has not established any reserves relating to any of the Cases.
In addition to the matters described above, the Company is involved in various lawsuits, claims and proceedings which are being handled and defended by the Company in the ordinary course of business. Pursuant to the terms of the SandRidge Mississippian Trust I and SandRidge Mississippian Trust II, the Company is obligated to indemnify each Royalty Trust against losses, claims, damages, liabilities and expenses, including reasonable costs of investigation and attorney’s fees and expenses arising out of certain legal matters as stipulated in the respective agreements with each Royalty Trust.
ITEM 1A. Risk Factors
Except as set forth below, there have been no material changes to the risk factors previously discussed in Item 1A—Risk Factors in the Company's 2017 Form 10-K.
Risks and uncertainties related to the adoption and implementation of regulations restricting oil and gas development in Colorado.
The Company has substantial undeveloped reserves and unproved acreage in the North Park Basin area of Jackson County, Colorado. Recently, various initiatives have been promoted by interest groups in Colorado to increase regulations restricting oil and gas development. For example, on November 6, 2018, Coloradans considered Proposition 112, a ballot initiative that would have established a new statewide minimum distance requirement for new oil and gas development far in excess of existing Colorado Oil and Gas Conservation Commission (“COGCC”) setback regulations. Although Coloradans did not approve Proposition 112, future similar initiatives, if implemented, could pose operational challenges, substantially limit our development activity and require higher levels of capital expenditures than we currently anticipate, and therefore have a significant adverse effect on our ability to develop proved undeveloped reserves in the North Park Basin. Even if we are able to develop these assets, delayed development of our reserves or increases in costs to drill and develop such reserves will reduce
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the present value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves. Such restrictions, additional costs and delays could adversely impact our financial condition, results of operations and/or cash flows.
Risks and uncertainties related to the potential sale or lease of our corporate headquarters.
The Company's corporate headquarters building in downtown Oklahoma City, OK, is substantially underutilized. The Company has entered into a brokerage agreement to seek to lease the unutilized portion of the building. The Company is also currently considering offers to purchase the entire building. Any alternative we pursue is subject to certain risks and uncertainties, including, among other things, the possibility that any alternative we select will not be completed on terms that are advantageous to us and the possibility that an outright sale of our corporate headquarters will be at a sales price significantly below its current carrying value on our books.
ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds
There were no share repurchases made by the Company during the three-month period ended September 30, 2018.
ITEM 3. Defaults upon Senior Securities
None.
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ITEM 6. Exhibits

|  | Incorporated by Reference |  |  |  |  |  |  |  |
Exhibit No. | Exhibit Description | Form |  | SEC File No. |  | Exhibit |  | Filing Date |  | Filed Herewith
2.1 | Amended Joint Chapter 11 Plan of Reorganization of SandRidge Energy, Inc., et al., dated September 19, 2016 | 8-A |  | 001-33784 |  | 2.1 |  | 10/4/2016 |  |
3.1 | Amended and Restated Certificate of Incorporation of SandRidge Energy, Inc. | 8-A |  | 001-33784 |  | 3.1 |  | 10/4/2016 |  |
3.2 | Amended and Restated Bylaws of SandRidge Energy, Inc. | 8-A |  | 001-33784 |  | 3.2 |  | 10/4/2016 |  |
10.1† | Amended and Restated SandRidge Energy, Inc. 2016 Omnibus Incentive Plan, dated August 8, 2018 |  |  |  |  |  |  |  |  | *
10.1.1† | Form of Non-employee Director Restricted Stock Award Agreement for SandRidge Energy, Inc. 2016 Omnibus Incentive Plan, dated July 17, 2018 |  |  |  |  |  |  |  |  | *
10.1.2† | Form of Executive Restricted Stock Award Agreement for Amended and Restated SandRidge Energy, Inc. 2016 Omnibus Incentive Plan, dated August 9, 2018 |  |  |  |  |  |  |  |  | *
10.1.3† | Form of Performance Share Unit Award Agreement for Amended and Restated SandRidge Energy, Inc. 2016 Omnibus Incentive Plan, dated September 5, 2018 |  |  |  |  |  |  |  |  | *
31.1 | S ection 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 - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL 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 |  |  |  |  |  |  |  |  | *
† Management contract or compensatory plan or arrangement |  |  |  |  |  |  |  |  |  |

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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/ Michael A. Johnson
|  | Michael A. Johnson Senior Vice President and Chief Financial Officer

Date: November 8, 2018
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