Washington, D.C. 20549
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 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.
The number of shares outstanding of the registrant’s common stock, par value $0.001 per share, as of the close of business on October 27, 2017,May 12, 2020, was 35,647,066.
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.
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)
Recent Accounting Pronouncements. The Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments” with the objective of reducing the existing diversity in practice of classification on certain cash receipts and payments in the statement of cash flows. The guidance requires adoption by application of a retrospective method to each period presented. The amendments are effective for the Company on January 1, 2018, with early adoption permitted. The Company adopted the ASU on April 1, 2017. The guidance had no impact on the consolidated financial statements and related disclosures.
The FASB Issued ASU 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business,” which provides a new framework for determining whether transactions should be accounted for as acquisitions (or disposals) of assets or as a business. The ASU is effective for the Company on January 1, 2018, and amendments should be applied prospectively on and after January 1, 2018. The Company early adopted this ASU for transactions effective after April 1, 2017. The guidance had no impact to the Company’s consolidated financial statements and related disclosures.
The FASB issued ASU 2017-09, “Compensation - Stock Compensation (Topic 718): Scope of Modification Accounting,” which provides guidance on determining which changes to the terms and conditions of share-based payment awards require an entity to apply modification accounting. The amendments in this ASU are effective for the Company on January 1, 2018, with early adoption permitted in any interim period. The ASU should be applied prospectively to an award modified on or after the adoption date. The Company early adopted this ASU on July 1, 2017. The guidance had no impact on the consolidated financial statements and related disclosures.
Recent Accounting Pronouncements Not Yet Adopted. The FASB issued ASU 2014-09, “Revenue from Contracts with Customers,” 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 defers the effective date of ASU 2014-09 to January 1, 2018, for the Company, with early adoption permitted in 2017. The ASU must be adopted using either the retrospective transition method, which requires restating previously reported results or the cumulative effect (modified retrospective) transition method, which utilizes 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 plans to adopt the ASU on January 1, 2018, using the modified retrospective transition method.
Subsequent to the issuance of ASU 2014-09, the FASB issued various clarifications and interpretive guidance to assist entities with implementation efforts, including guidance pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis. Under this guidance, an entity generally shall record revenue on a gross basis if it controls a specified good or service before transferring it to a customer, whereas an entity shall record revenue on a net basis if its role is to arrange for another entity to provide the goods or services to a customer. Significant judgment may be required in some circumstances to determine whether gross or net presentation is appropriate.
The Company is currently reviewing its contracts with customers and continues to evaluate the effect that the updated standard will have on its consolidated financial statements, accounting policies and related disclosures.
The FASB issued ASU 2016-02, “Leases (Topic 842),” which requires companies to recognize assets and liabilities for the rights and obligations created by long-term leases of assets on the balance sheet. Leases to explore for or use minerals, oil and natural gas are not impacted by this guidance. The guidance requires adoption by application of a modified retrospective transition approach for existing long-term leases and is effective for the Company on January 1, 2019. Early adoption is permitted. The Company plans to adopt the ASU on January 1, 2019 and continues to evaluate the effect that the guidance will have on its consolidated financial statements and related disclosures.
The FASB issued ASU 2016-16, “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other than Inventory” which removes 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 are effective for the Company on January 1, 2018, with early adoption permitted on January 1, 2017. The ASU should be applied 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 plans to adopt the ASU on January 1, 2018 and continues to evaluate the effect that the guidance will have on its consolidated financial statements.
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)
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 clarify 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 plans to adopt the ASU on January 1, 2018, using the modified retrospective transition method. The Company continues to evaluate the effect that the updated standard will have on its consolidated financial statements and related disclosures.
2. Recent Transactions
In the third quarter of 2017, the Company entered into a $200.0 million drilling participation agreement with a Counterparty to jointly develop new horizontal wells on a wellbore only basis within certain dedicated sections of its undeveloped leasehold acreage within the Meramec formation in Major and Woodward Counties in Oklahoma (the “NW STACK”). Under this agreement, the Counterparty is paying 90% of the net exploration and development costs, up to $100.0 million in the first tranche, in exchange for an initial 80% net working interest in each new well, subject to certain reversionary hurdles, as shown in the table below. As a result, the Company is receiving a 20% net working interest after funding 10% of the exploration and development costs related to the subject wells. This will allow the Company to spend minimal additional capital while accelerating the delineation of its position in the NW STACK, realizing further efficiencies and holding additional acreage by production, potentially adding reserves. The Company operates all of the wells developed under this agreement and will retain sole discretion as to the number, location and schedule of wells drilled. The Counterparty will also have the option to fund a second $100.0 million tranche, subject to mutual agreement.
Development Costs and Working Interest (“WI”) Structure
|
| | | | |
| | Counterparty | | SandRidge |
Development Costs | | 90% of Costs | | 10% of Costs |
Initial Working Interest | | 80% of WI | | 20% of WI |
Reversion If Counterparty Achieves 10% IRR | | 35% of WI | | 65% of WI |
Reversion If Counterparty Achieves 15% IRR | | 11% of WI | | 89% of WI |
3. Acquisitions and Divestitures
Acquisition of Properties. On February 10, 2017, the Company acquired assets consisting of approximately 13,000 net acres in Woodward County, Oklahoma for approximately $47.7 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. In 2017, the Company has 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.
Divestiture of West Texas Overthrust Properties and Release from Treating Agreement. On January 21, 2016, the Predecessor Company paid $11.0 million in cash and transferred ownership of substantially all of its oil and natural gas properties and midstream assets located in the Piñon field in West Texas Overthrust (the “WTO”) to Occidental Petroleum Corporation (“Occidental”) and was released from all past, current and future claims and obligations under an existing 30 year treating agreement between the companies. The Predecessor Company recognized a loss of approximately $89.1 million on the termination of the treating agreement and the cease-use of transportation agreements that supported production from the Piñon field.
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)
4. Fair Value Measurements
The Company measures and reports certain assets and liabilities on a fair value basis and has classified and disclosed its fair value measurements using the levels of the fair value hierarchy noted below. The carrying values of cash, restricted cash, accounts receivable, prepaid expenses, other current assets, accounts payable and accrued expenses and other current liabilities included in the unaudited condensed consolidated balance sheets approximated fair value at September 30, 2017, and December 31, 2016. As a result, these financial assets and liabilities are not discussed below. The fair values of property, plant and equipment and related impairments, which are calculated using Level 3 inputs, are discussed in Note 4.
|
| |
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 1 and Level 2 of the hierarchy as of September 30, 2017, and December 31, 2016, 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 $4.9 million and $2.8 million are included in other current assets at September 30, 2017, and December 31, 2016, respectively, and investments of $4.8 million are included in other assets at December 31, 2016, in the unaudited condensed consolidated balance sheets.
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.
Level 3 Fair Value Measurements
Debt Holder Conversion Feature. The Predecessor Company’s 8.125% Convertible Senior Notes due 2022 and 7.5% Convertible Senior Notes due 2023 (collectively, the “Convertible Senior Unsecured Notes”) each contained a conversion option whereby, prior to Chapter 11 filings, the Convertible Senior Unsecured Notes holders had the option to convert the notes into shares of Predecessor Company common stock. These conversion features were identified as embedded derivatives that met the criteria to be bifurcated from their host contracts and accounted for separately from the Convertible Senior Unsecured Notes.
The fair values of the holder conversion features were determined using a binomial lattice model based on certain assumptions including (i) the Predecessor Company’s stock price, (ii) risk-free rate, (iii) recovery rate, (iv) hazard rate and (v) expected volatility. The significant unobservable input used in the fair value measurement of the conversion features was the hazard rate, an estimate of default probability.
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)
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, 2017
|
| | | | | | | | | | | | | | | | | | | |
| | Fair Value Measurements | | Netting(1) | | Assets/Liabilities at Fair Value |
| | Level 1 | | Level 2 | | Level 3 |
| Assets | | | | | | | | | |
| Commodity derivative contracts | $ | — |
| | $ | 9,641 |
| | $ | — |
| | $ | (1,023 | ) | | $ | 8,618 |
|
| Investments | 4,918 |
| | — |
| | — |
| | — |
| | 4,918 |
|
| | $ | 4,918 |
| | $ | 9,641 |
| | $ | — |
| | $ | (1,023 | ) | | $ | 13,536 |
|
| Liabilities | | | | | | | | | |
| Commodity derivative contracts | $ | — |
| | $ | 1,031 |
| | $ | — |
| | $ | (1,023 | ) | | $ | 8 |
|
| | $ | — |
| | $ | 1,031 |
| | $ | — |
| | $ | (1,023 | ) | | $ | 8 |
|
December 31, 2016
|
| | | | | | | | | | | | | | | | | | | |
| | Fair Value Measurements | | Netting(1) | | Assets/Liabilities at Fair Value |
| | Level 1 | | Level 2 | | Level 3 |
| Assets | | | | | | | | | |
| Investments | $ | 7,541 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 7,541 |
|
| | $ | 7,541 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 7,541 |
|
| Liabilities | | | | | | | | | |
| Commodity derivative contracts | $ | — |
| | $ | 29,714 |
| | $ | — |
| | $ | — |
| | $ | 29,714 |
|
| | $ | — |
| | $ | 29,714 |
| | $ | — |
| | $ | — |
| | $ | 29,714 |
|
____________________
(1)Represents the effect of netting assets and liabilities for counterparties with which the right of offset exists.
Level 3 - Debt Holder Conversion Feature. The table below sets forth a reconciliation of the Predecessor Company’s Level 3 fair value measurements for debt holder conversion features (in thousands):
|
| | | | |
| | | Nine Months Ended September 30, 2016 |
| Beginning balance | | $ | 29,355 |
|
| Gain on derivative holder conversion feature | | (880 | ) |
| Conversions | | (21,194 | ) |
| Write off of derivative holder conversion feature to reorganization items | | (7,281 | ) |
| Ending balance | | $ | — |
|
Prior to commencement of the Chapter 11 Proceedings, the fair value of the conversion features was determined quarterly with changes in fair value recorded as interest expense.
Transfers. The Company recognizes transfers between fair value hierarchy levels as of the end of the reporting period in which the event or change in circumstances causing the transfer occurred. 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, 2017, and 2016.
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)
Fair Value of Financial Instruments - Long-Term Debt
The Successor Company measured the fair value of its previously outstanding non-interest bearing 0.00% Convertible Senior Subordinated Notes due 2020, (the “Convertible Notes”) using pricing that was readily available in the public market. The Successor Company measures the fair value of its $35.0 million initial principal note, as amended in February 2017, which is 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 estimated fair values and carrying values of the Company’s long-term debt are as follows (in thousands):
|
| | | | | | | | | | | | | | | |
| | September 30, 2017 | | December 31, 2016 |
| | Fair Value | | Carrying Value | | Fair Value | | Carrying Value |
| Convertible Notes | $ | — |
| | $ | — |
| | $ | 334,800 |
| | $ | 268,780 |
|
| Building Note | $ | 41,638 |
| | $ | 37,601 |
| | $ | 40,608 |
| | $ | 36,528 |
|
See Note 6 for additional discussion of the Company’s long-term debt.
5. Property, Plant and Equipment
Property, plant and equipment consists of the following (in thousands):
|
| | | | | | | |
| | September 30,
2017 | | December 31,
2016 |
| Oil and natural gas properties | | | |
| Proved | $ | 1,004,370 |
| | $ | 840,201 |
|
| Unproved | 103,533 |
| | 74,937 |
|
| Total oil and natural gas properties | 1,107,903 |
| | 915,138 |
|
| Less accumulated depreciation, depletion and impairment | (432,564 | ) | | (353,030 | ) |
| Net oil and natural gas properties capitalized costs | 675,339 |
| | 562,108 |
|
| | | | |
| Land | 5,200 |
| | 5,100 |
|
| Electrical infrastructure | 131,100 |
| | 130,242 |
|
| Other non-oil and natural gas equipment | 26,956 |
| | 35,768 |
|
| Buildings and structures | 88,503 |
| | 88,603 |
|
| Total | 251,759 |
| | 259,713 |
|
| Less accumulated depreciation and amortization | (13,339 | ) | | (3,889 | ) |
| Other property, plant and equipment, net | 238,420 |
| | 255,824 |
|
| Total property, plant and equipment, net | $ | 913,759 |
| | $ | 817,932 |
|
Impairments. The Predecessor Company recorded impairments on its oil and natural gas properties of $298.0 million and $657.4 million during the three and nine-month periods ended September 30, 2016 as a result of its quarterly full cost ceiling analysis. No full cost ceiling impairments have been recorded in the 2017 period.
In the first quarter of 2017, the Company classified its remaining drilling and oilfield services assets as held for sale in the other current assets line of the unaudited condensed consolidated balance sheet. The net realizable value of the assets was determined to be $4.4 million based on expected sales prices obtained from a third party. The carrying value of these assets exceeded the net realizable value, resulting in impairments of $0.5 million and $3.5 million for the three and nine-month periods ended September 30, 2017. The Company disposed of approximately $0.8 million of these assets during the nine-month period ended September 30, 2017, and expects to dispose of the majority of the remaining assets during the fourth quarter of 2017.
The Company reviews non-oil and natural gas equipment and buildings and structures for recoverability whenever events
or changes in circumstances indicate that carrying amounts may not be recoverable. The Company recognizes an impairment loss if the carrying amount of a long-lived asset is not recoverable and exceeds its fair value. During the third quarter of 2016,
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)
the electrical transmission system was reviewed and was determined to not be recoverable due to a decrease in projected Mid-Continent production volumes supporting the system’s usage. Further, the carrying value exceeded its fair value. The Company recorded an impairment of $55.6 million on its electrical transmission system during the three and nine-month periods ended September 30, 2016, and a $1.7 million impairment on compressors and various other midstream services equipment during the nine-month period ended September 30, 2016, due primarily to the determination that their future use was limited.
Fair value measurements for the electrical asset impairment discussed above were based on replacement cost. As the fair value was estimated using the cost approach, inputs were based on the cost to a market participant buyer to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence. These inputs were not observable in the market and were classified as Level 3 in the fair value hierarchy.
The Company disposed of certain drilling and oilfield services assets previously classified as held for sale during 2016
and recorded losses on the sale of those assets of $0.1 million and $1.7 million for the three and nine-month periods ended
September 30, 2016, which are included in other operating (income) expense in the accompanying unaudited condensed consolidated statements of operations.
Drilling Carry Commitments. Under the terms of an agreement with Repsol E&P USA, Inc. (“Repsol”), the Predecessor Company had agreed to carry Repsol’s drilling and completion costs totaling up to approximately $31.0 million for wells drilled in an area of mutual interest. Effective June 6, 2016, the Bankruptcy Court issued orders allowing the Company to reject certain long-term contracts, including this drilling carry commitment. Repsol filed a bankruptcy claim for this commitment, which was settled by the Company in the fourth quarter of 2016 for approximately $1.2 million.
6. 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 is $425.0 million. This borrowing base was reconfirmed during the October 2017 semi-annual redetermination. The next borrowing base redetermination is scheduled for April 1, 2018. 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).
Beginning with the quarter ended June 30, 2017, 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, 2017.
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 Company was in compliance with these covenants as of September 30, 2017.
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)
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 Company had no amounts outstanding under the Credit Facility at September 30, 2017, and $7.1 million in outstanding letters of credit, which reduce availability under the Credit Facility on a dollar-for-dollar basis.
First Lien Exit Facility. On the Emergence Date, the Company entered into the First Lien Exit Facility with the lenders party thereto and Royal Bank of Canada, as administrative agent and issuing lender.
The borrowing base under the First Lien Exit Facility was $425.0 million. The First Lien Exit Facility was set to mature on February 4, 2020. The outstanding borrowings under the First Lien Exit Facility bore interest at a rate equal to, at the option of the Company, either (a) a base rate plus an applicable rate of 3.75% per annum or (b) LIBOR plus 4.75% per annum, subject to a 1.00% LIBOR floor. Interest on base rate borrowings was payable quarterly in arrears and interest on LIBOR borrowings was payable every one, two, three or six months, at the election of the Company. Quarterly, the Company was committed to pay fees assessed at annual rates of 0.50% on any available portion of the First Lien Exit Facility. The Company had the right to prepay loans under the First Lien Exit Facility at any time without a prepayment penalty, other than customary “breakage” costs with respect to LIBOR loans.
The First Lien Exit Facility contained certain financial covenants and customary affirmative and negative covenants. The Company was in compliance with all applicable covenants through the date it was refinanced.
Convertible Notes. On the Emergence Date, pursuant to the terms of the Plan, the Company issued approximately $281.8 million principal amount of Convertible Notes, which did not bear regular interest and were set to mature and mandatorily convert into shares of common stock in the Successor Company (the “Common Stock”) on October 4, 2020, unless repurchased, redeemed or converted prior to that date. The Convertible Notes were recorded at their fair value of $445.7 million upon implementation of fresh start accounting. The resulting premium of $163.9 million was deemed significant to the principal amount of the Convertible Notes, and as such, was recorded in additional paid in capital in the condensed consolidated balance sheet at December 31, 2016. The Company’s obligations pursuant to the Convertible Notes were fully and unconditionally guaranteed, jointly and severally, by each of the guarantors of the First Lien Exit Facility.
The Convertible Notes were initially convertible at a rate of 0.05330841 shares of Common Stock per $1.00 principal amount of Convertible Notes, which represented in the aggregate, approximately 15.0 million shares of common stock. The conversion rate for the Convertible Notes was subject to customary anti-dilution adjustments.
The Convertible Notes were convertible at the option of the holders at any time up to, and including, the business day immediately preceding the maturity date. Between the Emergence Date and December 31, 2016, approximately $13.0 million in aggregate principal amount of the Convertible Notes was converted into approximately 0.7 million shares of Common Stock following delivery of voluntary conversion notices by the holders of those Convertible Notes. Additionally, during the period from January 1, 2017 to February 9, 2017, approximately $5.1 million in aggregate principal amount of the Convertible Notes was converted into approximately 0.3 million shares of Common Stock following delivery of voluntary conversion notices by the holders of those Convertible Notes. The remaining $263.7 million par value of outstanding Convertible Notes mandatorily converted into 14.1 million shares of Common Stock upon the refinancing of the First Lien Exit Facility on February 10, 2017, after the determination by the Successor Company’s board of directors in good faith that: (a) the refinancing provided for terms that were materially more favorable to the Company and (b) causing a conversion was not the primary purpose of the refinancing.
Building Note.On the Emergence Date, the Company entered into the Building Note, which had an initial principal amount of $35.0 million. The Building Note was recorded at a fair value of $36.6 million upon implementation of fresh start accounting. The resulting premium is being amortized to interest expense over the term of the Building Note. Interest is 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 paid in kind and added to the Building Note principal from the Emergence Date through May 11, 2017, which was 90 days after the refinancing of the First Lien Exit Facility. Interest became payable thereafter in cash. The Building Note matures on October 2, 2021 and became prepayable in whole or in part
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)
without premium or penalty upon the refinancing of the First Lien Exit Facility. Net proceeds of $26.8 million received from the sale of the Building Note were subsequently remitted to unsecured creditors on the Emergence Date in accordance with the Plan.
7. 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 seeks 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 in loss (gain) 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, 2017, 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 loss (gain) on commodity derivative contracts of $11.7 million and $(0.3) million for the three-month periods ended September 30, 2017, and 2016, respectively, which include net cash receipts upon settlement of $5.0 million and $14.6 million, respectively. The Company recorded (gain) loss on commodity derivative contracts of $(46.0) million and $4.8 million for the nine-month periods ended September 30, 2017, and 2016, respectively, which include net cash receipts upon settlement of $7.7 million and $72.6 million, respectively. Included in the net cash receipts for the nine-month period ended September 30, 2016, is $17.9 million of cash receipts related to certain commodity derivative contracts settled prior to their contractual maturities (“early settlements”).
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 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, 2017, the counterparties to the Company’s open commodity derivative contracts consisted of seven 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.
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, 2017, and the First Lien Exit Facility as of December 31, 2016 (in thousands):
September 30, 2017
|
| | | | | | | | | | | | | | | | | | | | |
| | | Gross Amounts | | Gross Amounts Offset | | Amounts Net of Offset | | Financial Collateral | | Net Amount |
| Assets | | | | | | | | | | |
| Derivative contracts - current | | $ | 7,632 |
| | $ | (1,024 | ) | | $ | 6,608 |
| | $ | — |
| | $ | 6,608 |
|
| Derivative contracts - noncurrent | | 2,009 |
| | 1 |
| | 2,010 |
| | — |
| | 2,010 |
|
| Total | | $ | 9,641 |
| | $ | (1,023 | ) | | $ | 8,618 |
| | $ | — |
| | $ | 8,618 |
|
| Liabilities | | | | | | | | | | |
| Derivative contracts - current | | $ | 1,031 |
| | $ | (1,023 | ) | | $ | 8 |
| | $ | (8 | ) | | $ | — |
|
| Total | | $ | 1,031 |
| | $ | (1,023 | ) | | $ | 8 |
| | $ | (8 | ) | | $ | — |
|
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)
December 31, 2016 |
| | | | | | | | | | | | | | | | | | | | |
| | | Gross Amounts | | Gross Amounts Offset | | Amounts Net of Offset | | Financial Collateral | | Net Amount |
| Liabilities | | | | | | | | | | |
| Derivative contracts - current | | $ | 27,538 |
| | $ | — |
| | $ | 27,538 |
| | $ | (27,538 | ) | | $ | — |
|
| Derivative contracts - noncurrent | | 2,176 |
| | — |
| | 2,176 |
| | (2,176 | ) | | — |
|
| Total | | $ | 29,714 |
| | $ | — |
| | $ | 29,714 |
| | $ | (29,714 | ) | | $ | — |
|
At September 30, 2017, the Company’s open commodity derivative contracts consisted of the following:
Oil Price Swaps
|
| | | | | | |
| | Notional (MBbls) | | Weighted Average Fixed Price |
| October 2017 - December 2017 | 828 |
| | $ | 52.24 |
|
| January 2018 - December 2018 | 2,006 |
| | $ | 54.87 |
|
Natural Gas Price Swaps
|
| | | | | | |
| | Notional (MMcf) | | Weighted Average Fixed Price |
| October 2017 - December 2017 | 8,280 |
| | $ | 3.20 |
|
| January 2018 - December 2018 | 17,300 |
| | $ | 3.16 |
|
Fair Value of Derivatives
The following table presents the fair value of the Company’s derivative contracts as of September 30, 2017, and December 31, 2016, on a gross basis without regard to same-counterparty netting (in thousands):
|
| | | | | | | | | | |
| Type of Contract | | Balance Sheet Classification | | September 30,
2017 | | December 31,
2016 |
| Derivative assets | | | | | | |
| Oil price swaps | | Derivative contracts-current | | $ | 5,417 |
| | $ | — |
|
| Natural gas price swaps | | Derivative contracts-current | | 2,214 |
| | — |
|
| Oil price swaps | | Derivative contracts-noncurrent | | 1,739 |
| | — |
|
| Natural gas price swaps | | Derivative contracts-noncurrent | | 271 |
| | — |
|
| Derivative liabilities | | | | | | |
| Oil price swaps | | Derivative contracts-current | | (1,031 | ) | | (13,395 | ) |
| Natural gas price swaps | | Derivative contracts-current | | — |
| | (14,143 | ) |
| Oil price swaps | | Derivative contracts-noncurrent | | — |
| | (2,105 | ) |
| Natural gas price swaps | | Derivative contracts-noncurrent | | — |
| | (71 | ) |
| Total net derivative contracts | | $ | 8,610 |
| | $ | (29,714 | ) |
See Note 4 for additional discussion of the fair value measurement of the Company’s derivative contracts.
8. 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
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)
complaint making allegations substantially similar to those contained in the amended complaint that was previously dismissed. An estimate of reasonably possible losses associated with this action can not be made at this time. The Company has not established any reserves relating to this action.
In addition to the matter 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.
Restricted Cash. Restricted cash - other included on the unaudited condensed consolidated balance sheets at September 30, 2017, and December 31, 2016 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 enters into commodity derivative arrangements in order to mitigate a portion of the effect of this price volatility on the Company’s cash flows. See Note 7 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, debt service requirements and working capital needs 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.
9. Equity
Common Stock. On the Emergence Date, the previously issued Predecessor Company common stock was canceled and an aggregate of approximately 18.9 million shares of Common Stock, par value $0.001 per share, was issued to the holders of allowed claims, as defined in the Plan. Approximately 0.4 million shares of Common Stock were reserved for future distributions under the Plan and approximately 0.1 million of the reserved shares were issued during the three-month period ended September 30, 2017. Additionally, from the Emergence Date through February 9, 2017, voluntary conversions of Convertible Notes resulted in the issuance of approximately 1.0 million shares of Common Stock. The remaining balance of Convertible Notes converted to 14.1 million shares of Common Stock upon refinancing the First Lien Exit Facility. See Note 6 for further discussion of the Convertible Notes.
Warrants. On the Emergence Date, the Company issued approximately 4.9 million Series A Warrants, 4.5 million of which were issued immediately upon emergence, and 2.1 million Series B Warrants, 1.9 million of which were issued immediately upon emergence (the “Warrants”). The Warrants were initially exercisable 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. Approximately 0.1 million Series A Warrants and an insignificant amount of Series B Warrants were issued under the Plan during the three-month period ended September 30, 2017. The Warrants are exercisable from the Emergence Date until October 4, 2022, and contain customary anti-dilution adjustments in the event of any stock split, reverse stock split, reclassification, stock dividend or other distributions.
Predecessor Company Preferred Stock Dividends. In the first quarter of 2016, prior to the February semi-annual dividend payment date, the Predecessor Company announced the suspension of the semi-annual dividend on its 8.5% convertible perpetual preferred stock. At September 30, 2016, the Company had dividends in arrears of $11.3 million and $21.0 million on its 8.5% and 7.0% convertible perpetual preferred stock, respectively. The Predecessor Company ceased accruing dividends on its 8.5% and 7.0% convertible perpetual preferred stock as of May 16, 2016, in conjunction with the Chapter 11 petition filings.
Paid and unpaid dividends included in the calculation of loss applicable to the Predecessor Company’s common stockholders and the Predecessor Company’s basic loss per share calculation for the nine-month period ended September 30, 2016 are presented in the unaudited condensed consolidated statement of operations. All outstanding shares of the Predecessor Company's
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)
8.5% and 7.0% convertible perpetual preferred stock were canceled upon Emergence from Chapter 11. See Note 11 for discussion of the Company’s loss (earnings) per share calculation.
10. 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, |
| | Successor | | | Predecessor | | Successor | | | Predecessor |
| | 2017 | | | 2016 | | 2017 | | | 2016 |
| Current | | | | | | | | | |
| Federal | $ | (8,460 | ) | | | $ | — |
| | $ | (8,460 | ) | | | $ | — |
|
| State | 3 |
| | | 4 |
| | (36 | ) | | | 11 |
|
| Total provision | $ | (8,457 | ) | | | $ | 4 |
| | $ | (8,496 | ) | | | $ | 11 |
|
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. During the three-month period ended September 30, 2017, the Company reduced the valuation allowance associated with deferred tax assets related to alternative minimum tax (AMT) credits that became realizable as a result of a special tax election. Accordingly, the Company recorded an income tax benefit of $8.5 million in the three-month period ended September 30, 2017. 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 remaining net deferred tax asset at September 30, 2017.
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. The Company analyzed alternatives available within the IRC to taxpayers in Chapter 11 bankruptcy proceedings in order to minimize the impact of the October 4, 2016 ownership change on its tax attributes. Previously, the Company planned to elect an available alternative upon filing its 2016 U.S. Federal income tax return that would not subject existing tax attributes to an immediate IRC Section 382 limitation but would have resulted in a full limitation should a subsequent ownership change occur within two years of the emergent date ownership change. Alternatively, upon filing its 2016 U.S. Federal income tax return, the Company elected a method that did subject tax attributes including net operating losses (“NOLs”) existing at October 4, 2016, to an annual limitation but provided more certainty with respect to the future availability of the Company’s existing NOLs. This limitation is expected to result in a significant portion of our NOL carryforwards expiring unused. As such, the Company’s deferred tax asset associated with NOLs and corresponding valuation allowance are expected to be materially less at December 31, 2017, compared to December 31, 2016. The election and resulting limitation did not result in an income tax expense as the Company’s net deferred tax asset had previously been reduced by a valuation allowance. Additionally, the limitation did not result in a tax liability for the tax year ended December 31, 2016 and is not expected to result in a tax liability for the tax year ending December 31, 2017.
The Company’s only taxing jurisdiction is the United States (federal and state). The Company’s tax years 2014 to present remain open for federal examination. Additionally, tax years 2005 through 2013 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.
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)
11. (Loss) Earnings per Share
As discussed in Note 9, on the Emergence Date, the Predecessor Company’s then-authorized common stock was canceled and the new Common Stock and Warrants were issued.
The following table summarizes the calculation of weighted average common shares outstanding used in the computation of diluted (loss) earnings per share:
|
| | | | | | | | | | |
| | Net (Loss) Income | | Weighted Average Shares | | (Loss) Earnings Per Share |
| | (In thousands, except per share amounts) |
| Three Months Ended September 30, 2017 (Successor) | | | | | |
| Basic loss per share | $ | (8,485 | ) | | 34,290 |
| | $ | (0.25 | ) |
| Effect of dilutive securities | | | | | |
| Restricted stock awards(1) | — |
| | — |
| | |
| Performance share units(1) | — |
| | — |
| | |
| Diluted loss per share | $ | (8,485 | ) | | 34,290 |
| | $ | (0.25 | ) |
| | | | | | |
| | | | | | |
| Three Months Ended September 30, 2016 (Predecessor) | | | | | |
| Basic loss per share | $ | (404,337 | ) | | 718,373 |
| | $ | (0.56 | ) |
| Effect of dilutive securities | | | | | |
| Restricted stock and units(2) | — |
| | — |
| | |
| Diluted loss per share | $ | (404,337 | ) | | 718,373 |
| | $ | (0.56 | ) |
| | | | | | |
| | | | | | |
| Nine Months Ended September 30, 2017 (Successor) | | | | | |
| Basic earnings per share | $ | 65,822 |
| | 31,750 |
| | $ | 2.07 |
|
| Effect of dilutive securities | | | | | |
| Restricted stock awards | — |
| | 234 |
| | |
| Performance share units(3) | — |
| | — |
| | |
| Diluted earnings per share | $ | 65,822 |
| | 31,984 |
| | $ | 2.06 |
|
| | | | | | |
| | | | | | |
| Nine Months Ended September 30, 2016 (Predecessor) | | | | | |
| Basic loss per share | $ | (1,249,795 | ) | | 708,788 |
| | $ | (1.76 | ) |
| Effect of dilutive securities | | | | | |
| Restricted stock and units(2) | — |
| | — |
| | |
| Diluted loss per share | $ | (1,249,795 | ) | | 708,788 |
| | $ | (1.76 | ) |
____________________
| |
(1) | 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. See Note 12 for discussion of the Company’s share and incentive-based compensation awards. |
| |
(2) | No incremental shares of potentially dilutive restricted stock awards or units were included for the three and nine-month periods ended September 30, 2016, as their effect was antidilutive under the treasury stock method. See Note 12 for discussion of the Company’s share and incentive-based compensation awards. |
| |
(3) | No incremental shares of potentially dilutive performance share units were included for the nine-month period ended September 30, 2017, as their effect was antidilutive under the treasury stock method. See Note 12 for discussion of the Company’s share and incentive-based compensation awards. |
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)
12. Share and Incentive-Based Compensation
Successor Share-Based Compensation
Omnibus Incentive Plan.Upon the Company’s emergence from bankruptcy, the Predecessor's share-based compensation awards were canceled and pursuant to terms of the Plan, the SandRidge Energy, Inc. 2016 Omnibus Incentive Plan (the “Omnibus Incentive Plan”) became effective.
Persons eligible to receive awards under the Omnibus Incentive Plan include non-employee directors of the Company, employees of the Company or any of its affiliates, and certain consultants and advisors 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 Common Stock, as well as certain cash-based awards. At September 30, 2017, the Company had restricted stock awards, performance share units and performance units outstanding under the Omnibus Incentive Plan.
Restricted Stock Awards. The Successor Company’s restricted stock awards are valued based upon the market value of the Company’s Common Stock on the date of grant. During October 2016, awards for approximately 1.4 million shares of restricted stock were granted under the Omnibus Incentive Plan. These restricted shares will vest over a three-year period. In 2017, awards for approximately 0.6 million shares were granted, which will vest over a period of approximately 2.5 years. The Successor Company recognized total share-based compensation expense related to its restricted stock awards of $3.1 million and $13.5 million, of which $0.5 million and $1.8 million were capitalized, for the three and nine-month periods ended September 30, 2017, respectively. Share-based compensation expense for the nine-month period ended September 30, 2017, includes $1.8 million for the accelerated vesting of 0.1 million restricted common stock awards. The following table presents a summary of the Successor Company’s unvested restricted stock awards.
|
| | | | | | |
| | Number of Shares | | Weighted Average Grant Date Fair Value |
| | (In thousands) | | |
| Unvested restricted shares outstanding at December 31, 2016 | 1,407 |
| | $ | 24.32 |
|
| Granted | 640 |
| | $ | 20.04 |
|
| Vested | (464 | ) | | $ | 22.41 |
|
| Forfeited / Canceled | (96 | ) | | $ | 23.52 |
|
| Unvested restricted shares outstanding at September 30, 2017 | 1,487 |
| | $ | 23.13 |
|
As of September 30, 2017, the Successor Company’s unrecognized compensation cost related to unvested restricted stock awards was $25.0 million. The remaining weighted-average contractual period over which this compensation cost may be recognized is 2.0 years. The Successor Company’s restricted stock awards are equity-classified awards.
Performance Share Units. In February 2017, the Company granted performance share units which vest upon completion of the performance period, which is January 1, 2017 through June 30, 2019. The performance share units will be settled in Common Stock, up to a maximum of approximately 0.4 million shares of Common Stock, provided the required performance measures are met. The shares are valued based on one share of the Company Common Stock per performance share unit as awarded based on the Company’s performance relative to certain performance and market conditions. The Company’s performance share units are equity-classified awards. The Successor Company recognized total share-based compensation expense related to its performance share units of $0.4 million and $1.0 million, of which $0.1 million and $0.2 million were capitalized, for the three and nine-month periods ended September 30, 2017, respectively.
Successor Incentive-Based Compensation
Performance Units. In October 2016, the Company granted performance units which will vest over a three-year period and will be settled in cash, provided the required performance measures are met. The performance units were issued at a value of $100 each and the value at vesting will be determined by annual scorecard results. The Company’s performance units are liability-classified awards. The Successor Company recognized total incentive-based compensation expense related to its performance units of $0.5 million and $2.1 million, of which $0.1 million and $0.3 million were capitalized, for the three and nine-month periods ended September 30, 2017, respectively. At September 30, 2017, the liability related to performance units was $2.5 million.
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
(Unaudited)
Predecessor Share-Based Compensation
Restricted Common Stock Awards. Prior to the cancellation of the Predecessor Company’s share-based compensation awards on the Emergence Date, the then-existing restricted common stock awards generally vested over a four-year period, subject to certain conditions, and were valued based upon the market value of the Company’s common stock on the date of grant. For the three and nine-month periods ended September 30, 2016, the Company recognized total share-based compensation expense related to its restricted stock awards of $1.8 million and $11.2 million, of which $0.5 million and $1.7 million were capitalized, respectively. Share-based compensation expense for the nine-month period ended September 30, 2016, included $5.4 million for the accelerated vesting of 1.3 million restricted common stock awards related to the Predecessor Company’s reduction in workforce during the first quarter of 2016. There was no significant activity related to the Predecessor Company’s then-outstanding restricted stock units, performance units and performance share units during the three and nine-month periods ended September 30, 2016. The following table presents a summary of the Predecessor Company’s unvested restricted stock awards.
|
| | | | | | |
| | Number of Shares | | Weighted-Average Grant Date Fair Value |
| | (In thousands) | | |
| Unvested restricted shares outstanding at December 31, 2015 | 5,626 |
| | $ | 4.85 |
|
| Granted | — |
| | $ | — |
|
| Vested | (3,034 | ) | | $ | 5.34 |
|
| Forfeited / Canceled | (158 | ) | | $ | 6.25 |
|
| Unvested restricted shares outstanding at September 30, 2016 | 2,434 |
| | $ | 4.15 |
|
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 2016 Form 10-K. Our discussion and analysis includes the following subjects:
Overview;
Consolidated Results of Operations;
Liquidity and Capital Resources;
Critical Accounting Policies and Estimates; and
Valuation Allowance.
The financial information with respect to the three and nine-month periods ended September 30, 2017, and 2016, 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.
Voluntary Reorganization Under Chapter 11
On May 16, 2016, the Debtors filed the Bankruptcy Petitions for reorganization under Chapter 11 of the Bankruptcy Code with the Bankruptcy Court. The Debtors’ Chapter 11 Cases were consolidated for procedural purposes only and are jointly administered under the caption In re: SandRidge Energy Inc., et al. The Bankruptcy Court confirmed the Debtors’ joint plan of reorganization on September 9, 2016, and we subsequently emerged from bankruptcy on October 4, 2016.
Emergence from Voluntary Reorganization Under Chapter 11
The following significant transactions occurred upon our emergence from Chapter 11:
| |
• | First Lien Credit Agreement.All outstanding obligations under the senior secured revolving credit facility (the “senior credit facility”) were canceled, and the $425.0 million First Lien Exit Facility was established. The First Lien Exit Facility was refinanced in February 2017 as discussed in “Liquidity and Capital Resources.”
|
| |
• | Cash Collateral Account. We deposited $50.0 million of cash collateral in an account controlled by the administrative agent to the First Lien Exit Facility. This deposit was released to us in February 2017 in conjunction with the refinancing of the First Lien Exit Facility as discussed in “Liquidity and Capital Resources.”
|
| |
• | Senior Secured Notes. All outstanding obligations under the 8.75% Senior Secured Notes due 2020 issued in June 2015 and the $78.0 million principal 8.75% Senior Secured Notes due 2020 issued to Piñon Gathering Company, LLC in October 2015, (collectively, the “Senior Secured Notes”) were canceled and exchanged for approximately 13.7 million of the 18.9 million shares of the Successor Company’s Common Stock, issued at emergence. Additionally, claims under the Senior Secured Notes received approximately $281.8 million principal value of Convertible Notes. The remaining principal outstanding on the Convertible Notes mandatorily converted into shares of Common Stock upon the refinancing of the First Lien Exit Facility in February 2017, as discussed in “Liquidity and Capital Resources.”
|
| |
• | General Unsecured Claims.The Predecessor Company’s general unsecured claims, including the Senior Unsecured Notes and the Convertible Senior Unsecured Notes, became entitled to receive their proportionate share of (a) approximately $36.7 million in cash, (b) approximately 5.7 million shares of Common Stock, 5.2 million of which was issued immediately
|
upon emergence, and (c) 4.9 million Series A Warrants and 2.1 million Series B Warrants. Approximately 4.5 million Series A Warrants and 1.9 million Series B Warrants were issued immediately upon emergence.
| |
• | Building Note. The Building Note with a principal amount of $35.0 million ($36.6 million fair value on the Emergence
|
Date), was issued and purchased on the Emergence Date for $26.8 million in cash, net of certain fees and expenses, by
certain holders of the Senior Unsecured Notes. Proceeds received from the Building Note were subsequently remitted to unsecured creditors on the Emergence Date in accordance with the Plan.
| |
• | Preferred and Common Stock. The Predecessor Company’s 7.0% and 8.5% convertible perpetual preferred stock and common stock were canceled and released under the Plan.
|
See “Note 6 - Long-Term Debt” and “Note 9 - Equity” to the accompanying unaudited condensed consolidated financial statements for additional information on the transactions noted above.
Fresh Start Accounting. We elected to apply fresh start accounting effective October 1, 2016, to coincide with the timing of our normal fourth quarter reporting period, which resulted in SandRidge becoming a new entity for financial reporting purposes. In accordance with ASC 852, the reorganization value of the Successor Company was allocated to its individual assets based on their estimated fair values as of the Emergence Date.
As a result of the application of fresh start accounting and the effects of the implementation of the Plan, the statement of operations after October 1, 2016 (the “Successor 2016 Period”) may not be comparable with the statement of operations for the period from January 1, 2016 through October 1, 2016 (the “Predecessor 2016 Period”). However, our reorganization under Chapter 11 did not result in the divestiture of any of our oil and natural gas properties. As a result, certain operating results and key operating performance measures, including those related to production, average oil and natural gas selling prices, revenues and lease operating expenses, were not significantly impacted by the reorganization, and certain of the operating results in the Predecessor Period and the Successor Period are still comparable. For items that are not comparable, we have included additional analysis to supplement the discussion.
Operational Activities
Operational activities for the three and nine-month periods ended September 30, 2017, and 2016 include the following:
Total production for the three-month period ended September 30, 2017, was comprised of approximately 26.7% oil, 50.7% natural gas and 22.6% NGLs compared to 28.1% oil, 47.8% natural gas and 24.1% NGLs in the same period of 2016. Total production for the nine-month period ended September 30, 2017, was comprised of approximately 27.5% oil, 49.6% natural gas and 22.9% NGLs compared to 28.7% oil, 48.9% natural gas and 22.4% NGLs in the same period of 2016.
Increased total rigs drilling to three at September 30, 2017, from one at September 30, 2016.
Drilled nine and 14 wells, respectively, in the Mid-Continent during the three and nine-month periods ended September 30, 2017, compared to three and 13 wells drilled during the same periods in 2016, respectively. Drilled four and six wells, respectively, in the North Park Basin during the three and nine-month periods ended September 30, 2017, compared to drilling two and 12 wells during the same periods in 2016, respectively.
In the third quarter of 2017, we entered into a $200.0 million drilling participation agreement with a Counterparty to jointly develop new horizontal wells on a wellbore only basis within certain dedicated sections of our undeveloped leasehold acreage within the NW STACK. See “Note 2 - Recent Transactions” to the accompanying unaudited condensed consolidated financial statements for additional discussion of the drilling participation agreement.
Discontinued all remaining drilling and oilfield services operations in 2016, and as a result, our drilling and oilfield services operations no longer constituted a reportable segment in 2017.
Transferred substantially all oil and natural gas properties and midstream assets located in the Piñon field in the WTO and $11.0 million in cash to Occidental in January 2016 in exchange for the release from all past, current and future claims and obligations under an existing 30-year treating agreement with Occidental. Our midstream and marketing operations no longer constitute a reportable segment in 2017.
On February 10, 2017, we acquired approximately 13,000 net acres in Woodward County, Oklahoma for approximately $47.7 million in cash. Also included in the acquisition were working interests in four wells previously drilled on the acreage.
Outlook
Based on the successful results of our drilling program in the North Park Basin and NW STACK during the first half of 2017, we increased our 2017 capital expenditures budget to a range between $250.0 million and $260.0 million in the second quarter of 2017 from the original range of $210.0 million to $220.0 million. The increase in capital expenditures is allowing for continued development of these assets in the fourth quarter of 2017 by funding (i) the establishment of two federal units and additional infrastructure in our North Park acreage, and (ii) the acquisition of 3D seismic and core analysis to support our NW STACK drilling program.
Although no impairment was indicated for our oil and natural gas properties during the third quarter of 2017, the commodity price environment in 2015 and 2016 resulted in the impairment of a significant portion of our oil and natural gas properties over recent reporting periods. The historical twelve-month unweighted average prices at September 30, 2017 were $49.81 per barrel of oil and $3.00 per Mcf of natural gas. Applying the actual October 1, 2017 and November 1, 2017 benchmark commodities prices, the twelve-month unweighted average prices would be $50.73 per barrel of oil and $3.01 per Mcf of natural gas through November 2017.
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 New York Mercantile Exchange (“NYMEX”) prices for oil and natural gas during the three and nine-month periods ended September 30, 2017, and 2016 are shown in the table below:
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | | 2017 | | 2016 | | 2017 | | 2016 |
| Oil (per Bbl) | | $ | 48.20 |
| | $ | 44.94 |
| | $ | 49.36 |
| | $ | 41.53 |
|
| Natural gas (per Mcf) | | $ | 2.95 |
| | $ | 2.79 |
| | $ | 3.05 |
| | $ | 2.35 |
|
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.
Oil, Natural Gas and NGL Production and Pricing
Set forth in the table below is production and pricing information for the Successor Company and the Predecessor Company for the three and nine-month periods ended September 30, 2017, and 2016.
|
| | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | Successor | | | Predecessor | | Successor | | | Predecessor |
| | 2017 | | | 2016 | | 2017 | | | 2016 |
| Production data (in thousands) | | | | | | | | | |
| Oil (MBbls) | 954 |
| | | 1,282 |
| | 3,130 |
| | | 4,315 |
|
| NGL (MBbls) | 807 |
| | | 1,103 |
| | 2,601 |
| | | 3,358 |
|
| Natural gas (MMcf) | 10,850 |
| | | 13,079 |
| | 33,883 |
| | | 44,124 |
|
| Total volumes (MBoe) | 3,569 |
| | | 4,565 |
| | 11,378 |
| | | 15,027 |
|
| Average daily total volumes (MBoe/d) | 38.8 |
| | | 49.6 |
| | 41.7 |
| | | 54.8 |
|
| Average prices—as reported(1) | | | | | | | | | |
| Oil (per Bbl) | $ | 46.16 |
| | | $ | 42.82 |
| | $ | 47.22 |
| | | $ | 36.85 |
|
| NGL (per Bbl) | $ | 19.07 |
| | | $ | 13.90 |
| | $ | 16.52 |
| | | $ | 12.67 |
|
| Natural gas (per Mcf) | $ | 1.95 |
| | | $ | 2.27 |
| | $ | 2.14 |
| | | $ | 1.78 |
|
| Total (per Boe) | $ | 22.57 |
| | | $ | 21.89 |
| | $ | 23.14 |
| | | $ | 18.63 |
|
| Average prices—including impact of derivative contract settlements(2) | | | | | | | | | |
| Oil (per Bbl) | $ | 49.67 |
| | | $ | 53.75 |
| | $ | 49.42 |
| | | $ | 51.05 |
|
| NGL (per Bbl) | $ | 19.07 |
| | | $ | 13.90 |
| | $ | 16.52 |
| | | $ | 12.67 |
|
| Natural gas (per Mcf) | $ | 2.10 |
| | | $ | 2.32 |
| | $ | 2.16 |
| | | $ | 1.77 |
|
| Total (per Boe) | $ | 23.97 |
| | | $ | 25.10 |
| | $ | 23.81 |
| | | $ | 22.70 |
|
__________________
| |
(1) | Prices represent actual average sales prices for the periods presented and do not include effects of derivative transactions. |
| |
(2) | Excludes settlements of commodity derivative contracts prior to their contractual maturity. |
The table below presents production by area of operation for the three and nine-month periods ended September 30, 2017, and 2016.
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | Successor | | | Predecessor | | Successor | | | Predecessor |
| | 2017 | | | 2016 | | 2017 | | | 2016 |
| | Production (MBoe) | | % of Total | | | Production (MBoe) | | % of Total | | Production (MBoe) | | % of Total | | | Production (MBoe) | | % of Total |
| Mid-Continent | 3,314 |
| | 92.9 | % | | | 4,250 |
| | 93.1 | % | | 10,511 |
| | 92.4 | % | | | 14,119 |
| | 94.0 | % |
| North Park Basin | 128 |
| | 3.6 | % | | | 161 |
| | 3.5 | % | | 473 |
| | 4.2 | % | | | 320 |
| | 2.1 | % |
| Permian Basin | 127 |
| | 3.5 | % | | | 153 |
| | 3.4 | % | | 394 |
| | 3.4 | % | | | 489 |
| | 3.3 | % |
| Other | — |
| | — | % | | | 1 |
| | — | % | | — |
| | — | % | | | 99 |
| | 0.6 | % |
| Total | 3,569 |
| | 100.0 | % | | | 4,565 |
| | 100.0 | % | | 11,378 |
| | 100.0 | % | | | 15,027 |
| | 100.0 | % |
Revenues
Consolidated revenues for the Successor Period and Predecessor Period are presented in the table below (in thousands):
|
| | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | Successor | | | Predecessor | | Successor | | | Predecessor |
| | 2017 | | | 2016 | | 2017 | | | 2016 |
| Oil | $ | 44,032 |
| | | $ | 54,898 |
| | $ | 147,792 |
| | | $ | 159,023 |
|
| NGL | 15,391 |
| | | 15,336 |
| | 42,962 |
| | | 42,541 |
|
| Natural gas | 21,117 |
| | | 29,700 |
| | 72,481 |
| | | 78,407 |
|
| Other | 352 |
| | | 4,122 |
| | 858 |
| | | 13,838 |
|
| Total revenues | $ | 80,892 |
| | | $ | 104,056 |
| | $ | 264,093 |
| | | $ | 293,809 |
|
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, 2017, and 2016 are shown in the tables below (in thousands):
|
| | | | | | | |
| | Three Months Ended September 30 | | Nine Months Ended September 30 |
| 2016 oil, natural gas and NGL revenues | $ | 99,934 |
| | $ | 279,971 |
|
| Change due to production volumes | (23,280 | ) | | (71,406 | ) |
| Change due to average prices | 3,886 |
| | 54,670 |
|
| 2017 oil, natural gas and NGL revenues | $ | 80,540 |
| | $ | 263,235 |
|
Revenues from oil, natural gas and NGL sales decreased $19.4 million, or 19.4% for the three-month period ended September 30, 2017, compared to the same period in 2016, largely due to a 1.0 MMBoe decrease in total production, primarily due to natural declines in existing producing wells and fewer wells brought on production. This decrease was slightly offset by an increase in average prices received for our oil and NGL production. Revenues from oil, natural gas and NGL sales decreased by $16.7 million, or 6.0%, for the nine-month period ended September 30, 2017, compared to the same period in 2016, primarily due to the declines in production as noted above, which were largely offset by an increase in the average prices received for our oil, natural gas, and NGL production. Additionally, the average prices received for production in the 2017 periods include the effects of the Successor Company’s election to include transportation deductions in revenues for the Successor Periods as discussed below.
Other revenues in the 2016 periods primarily include drilling and oilfield services and marketing and midstream sales, which largely decreased due to discontinuing all remaining drilling and oilfield services operations in 2016, and transferring substantially all oil and natural gas properties and midstream assets located in the Piñon field in the WTO to Occidental in January 2016.
Expenses
Expenses for the three and nine-month periods ended September 30, 2017, and 2016 consisted of the following (in thousands): |
| | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | Successor | | | Predecessor | | Successor | | | Predecessor |
| | 2017 | | | 2016 | | 2017 | | | 2016 |
| Production | $ | 26,765 |
| | | $ | 39,640 |
| | $ | 76,997 |
| | | $ | 129,608 |
|
| Production taxes | 3,606 |
| | | 2,278 |
| | 9,435 |
| | | 6,107 |
|
| Depreciation and depletion—oil and natural gas | 31,029 |
| | | 27,725 |
| | 87,486 |
| | | 90,978 |
|
| Depreciation and amortization—other | 3,399 |
| | | 7,514 |
| | 10,729 |
| | | 21,323 |
|
| Impairment | 498 |
| | | 354,451 |
| | 3,475 |
| | | 718,194 |
|
| General and administrative | 20,292 |
| | | 29,145 |
| | 63,999 |
| | | 134,447 |
|
| Loss (gain) on derivative contracts | 11,702 |
| | | (338 | ) | | (46,024 | ) | | | 4,823 |
|
| Loss on settlement of contract | — |
| | | — |
| | — |
| | | 90,184 |
|
| Other operating (income) expense | (132 | ) | | | 979 |
| | 135 |
| | | 4,348 |
|
| Total expenses | $ | 97,159 |
| | | $ | 461,394 |
| | $ | 206,232 |
| | | $ | 1,200,012 |
|
Production expense includes costs associated with our exploration and production activities, including, but not limited to, lease operating expense and treating costs. Production costs per Boe decreased to $7.50 and $6.77 for the three and nine-month periods ended September 30, 2017, from $8.68 per Boe and $8.63 per Boe for the same 2016 periods, respectively, primarily due to (i) the Successor Company’s presentation of transportation costs totaling $7.8 million and $21.5 million as a reduction from revenues for the three and nine-month periods ended September 30, 2017, compared to the Predecessor Company’s presentation of transportation costs totaling $8.0 million and $26.2 million as production expenses for the same 2016 periods, respectively, and (ii) controlled reductions in expenditures for electricity, chemicals and various other costs.
Depreciation and depletion for our oil and natural gas properties increased by $3.3 million for the three-month period ended September 30, 2017, compared to the same period in 2016, primarily due to an increase in the average depletion rate to $8.69 per Boe compared to $6.07 per Boe for the 2016 period. The increase in the average depletion rate primarily resulted from (i) incurring higher actual drilling and completion costs per Boe during the 2017 period compared to the rate per Boe calculated at December 31, 2016 following the significant ceiling test write-down incurred in the fourth quarter of 2016, and (ii) a shift of more capital to develop our North Park Basin oil asset where the anticipated future development costs likewise are expected to be higher than the $6.07 per Boe rate following the significant ceiling test write-down.
Depreciation and depletion for our oil and natural gas properties decreased by $3.5 million for the nine-month period ended September 30, 2017, compared to the same period in 2016, primarily due to the decrease in production. This decrease was partially offset by an increase in the average depletion rate to $7.69 per Boe for the nine-month period ended September 30, 2017, compared to $6.05 per Boe for the same 2016 period, as noted above. Also contributing to the higher rate was a $2.9 million increase in accretion for the nine-month period ended September 30, 2017, compared to the same period in 2016, primarily due to the Successor Company recording a higher fresh start valuation for asset retirement obligations on the Emergence Date.
Depreciation and amortization - other decreased primarily due to the transfer of substantially all midstream assets to Occidental in January 2016, as well as the sale of various corporate assets during 2016 and 2017.
Impairment consists of the following (in thousands):
|
| | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | Successor | | | Predecessor | | Successor | | | Predecessor |
| | 2017 | | | 2016 | | 2017 | | | 2016 |
| Full cost pool ceiling limitation(1) | $ | — |
| | | $ | 297,995 |
| | $ | — |
| | | $ | 657,392 |
|
| Drilling assets(2)(3) | 498 |
| | | 856 |
| | 3,475 |
| | | 3,511 |
|
| Electrical transmission assets(4) | — |
| | | 55,600 |
| | — |
| | | 55,600 |
|
| Midstream assets(5) | — |
| | | — |
| | — |
| | | 1,691 |
|
| | $ | 498 |
| | | $ | 354,451 |
| | $ | 3,475 |
| | | $ | 718,194 |
|
____________________
| |
(1) | Impairment recorded for the three and nine-month periods ended September 30, 2016, largely resulted from a decrease in the twelve-month weighted average oil and natural gas prices in the first half of 2016 and downward revisions to forecasted reserves due to a decrease in projected Mid-Continent production volumes in the third quarter of 2016. |
| |
(2) | Impairment for the three and nine-month periods ended September 30, 2017, reflects the write-down of remaining drilling and oilfield services assets classified as held for sale to net realizable value. |
| |
(3) | Impairment for the three and nine-month periods ended September 30, 2016, reflects the write-down of certain drilling assets after determining their future use was limited due to the Predecessor Company’s discontinued operations in the Permian region. |
| |
(4) | Impairment in the three and nine-month periods ended September 30, 2016, resulted from a decrease in projected Mid-Continent production volumes supporting the system’s usage. |
| |
(5) | Impairment in the nine-month period ended September 30, 2016, was recorded on compressors and various other midstream services equipment after determining that their future use was limited. |
General and administrative expenses decreased $8.9 million, or 30.4% for the three-month period ended September 30, 2017, from the same period in 2016 due primarily to a $13.0 million decrease in net salary costs largely resulting from a reduction in force during the fourth quarter of 2016 and recording an adjustment to the 2016 retention incentive accrual in the third quarter of 2016. This decrease was partially offset by (i) an increase of $2.7 million in professional services costs due to transaction fees and (ii) an increase of $1.4 million in other miscellaneous costs.
General and administrative expenses decreased $70.4 million, or 52.4% for the nine-month period ended September 30, 2017, from the same period in 2016 due primarily to (i) a $21.6 million decrease in net salary costs largely resulting from reductions in force during the first and fourth quarters of 2016, (ii) a decrease of $20.9 million in professional services costs due to incurring significant consultant and legal fees in the 2016 period in contemplation of the Company’s restructuring, (iii) the 2016 period including the write-off of a $16.7 million joint interest account receivable due to the determination that its collection was doubtful at March 31, 2016, and (iv) a decrease of $13.5 million in severance costs incurred due primarily to a reduction in force that occurred during the first quarter of 2016. These decreases were partially offset by an increase of $2.3 million in other miscellaneous costs.
We recorded loss (gain) on commodity derivative contracts of $11.7 million and $(0.3) million for the three-month periods ended September 30, 2017, and 2016, respectively, which include net cash receipts upon settlement of $5.0 million and $14.6 million, respectively. We recorded (gain) loss on commodity derivative contracts of $(46.0) million and $4.8 million for the nine-month periods ended September 30, 2017, and 2016, respectively, which include net cash receipts upon settlement of $7.7 million and $72.6 million, respectively. Included in the net cash receipts for the nine-month period ended September 30, 2016, are $17.9 million of cash receipts related to early settlements.
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 gas production to determine “effective prices.” Gains or losses on early settlements and losses related to amendments of contracts, if any, are not considered in the calculation of 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.
Loss on settlement of contracts for the nine-month period ended September 30, 2016, includes a $78.9 million loss resulting from the termination of a gas treating and CO2 delivery agreement with Occidental as well as a loss of $11.2 million recorded for the cease-use of transportation agreements that supported production from the Piñon field.
Other operating (income) expense primarily include drilling and oilfield services costs which largely decreased due to discontinuing all remaining drilling and oilfield services operations in 2016.
Other (Expense) Income
The Company’s other (expense) income for the three and nine-month periods ended September 30, 2017, and 2016 are presented in the table below (in thousands).
|
| | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | Successor | | | Predecessor | | Successor | | | Predecessor |
| | 2017 | | | 2016 | | 2017 | | | 2016 |
| Other (expense) income | | | | | | | | | |
| Interest expense | $ | (872 | ) | | | $ | (3,343 | ) | | $ | (2,757 | ) | | | $ | (126,099 | ) |
| Gain on extinguishment of debt | — |
| | | — |
| | — |
| | | 41,179 |
|
| Reorganization items | — |
| | | (42,754 | ) | | — |
| | | (243,672 | ) |
| Other income (expense), net | 197 |
| | | (898 | ) | | 2,222 |
| | | 1,332 |
|
| Total other expense | $ | (675 | ) | | | $ | (46,995 | ) | | $ | (535 | ) | | | $ | (327,260 | ) |
Interest expense for the three and nine-month periods ended September 30, 2017, and 2016 consisted of the following (in thousands):
|
| | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | Successor | | | Predecessor | | Successor | | | Predecessor |
| | 2017 | | | 2016 | | 2017 | | | 2016 |
| Interest expense, net | | | | | | | | | |
| Interest expense on debt | $ | 1,255 |
| | | $ | 3,796 |
| | $ | 3,740 |
| | | $ | 123,350 |
|
| Amortization of debt issuance costs, discounts and premium | (78 | ) | | | — |
| | (231 | ) | | | 7,730 |
|
| Gain on long-term debt holder conversion feature | — |
| | | — |
| | — |
| | | (1,324 | ) |
| Capitalized interest | — |
| | | (207 | ) | | — |
| | | (2,240 | ) |
| Total | 1,177 |
| | | 3,589 |
| | 3,509 |
| | | 127,516 |
|
| Less: interest income | (305 | ) | | | (246 | ) | | (752 | ) | | | (1,417 | ) |
| Total interest expense, net | $ | 872 |
| | | $ | 3,343 |
| | $ | 2,757 |
| | | $ | 126,099 |
|
Interest expense decreased $2.5 million and $123.3 million for the three and nine-month periods ended September 30, 2017, respectively, compared to the same periods in 2016, primarily due to the elimination of our Senior Secured Notes, Senior Unsecured Notes, and senior credit facility as part of the reorganization in 2016. The senior notes were canceled upon our emergence from Chapter 11 in the fourth quarter of 2016 and amounts outstanding under the First Lien Exit Facility were also repaid in full in the fourth quarter of 2016. There were no new borrowings on either the First Lien Exit Facility or the Credit Facility during 2017.
We recognized a gain on extinguishment of debt of $41.2 million for the nine-month period ended September 30, 2016, in connection with the exchange of certain of our Convertible Senior Unsecured Notes, including outstanding accrued interest on these notes, for shares of the Predecessor Company’s common stock.
See “Note 6 - Long-Term Debt” to the accompanying unaudited condensed consolidated financial statements included in this Quarterly Report for additional discussion of our long-term debt transactions in 2017 and 2016.
Reorganization items for the three-month period ended September 30, 2016, primarily consist of professional and legal
fees incurred as a result of the Chapter 11 proceedings. Reorganization items for the nine-month period ended September 30, 2016 primarily consist of (i) the write-off of $148.8 million in net unamortized debt premiums and discounts, unamortized debt
issuance costs and the remaining value of derivatives associated with the Convertible Senior Unsecured Notes and the 8.75% Senior Secured Notes due 2020 issued to Piñon Gathering Company, LLC in October 2015 that were written-off when the Bankruptcy Petitions were filed, (ii) $55.9 million in professional and legal fees incurred as a result of the Chapter 11 proceedings, (iii) an adjustment of $20.5 million for estimated allowable claims related to the Company’s legal proceedings, and (iv) $21.3 million in amounts related to the rejection or cure of certain long-term contracts as approved by the Bankruptcy Court. These items were slightly offset by approximately $6.3 million in discounts negotiated on pre-petition liabilities.
Liquidity and Capital Resources
As of September 30, 2017, our cash and cash equivalents, excluding restricted cash, were $133.2 million. Additionally, we had approximately $37.6 million in total debt outstanding and $7.1 million in outstanding letters of credit. As of October 27, 2017, the Company had approximately $97.8 million in cash and cash equivalents, excluding restricted cash, an undrawn Credit Facility, and $7.9 million in outstanding letters of credit, which reduce the amount available under the Credit Facility.
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 surplus decreased to $24.2 million at September 30, 2017, compared to $43.5 million at December 31, 2016, largely due to the acquisition of oil and natural gas properties for approximately $47.7 million in cash in the first quarter of 2017. This decrease is partially offset by fluctuations in the timing and amount of collections of receivables and payments of accounts payable and accrued expenses as well as changes in derivative assets and liabilities due to quarterly mark-to-market adjustments.
As noted in “— Outlook,” in the second quarter of 2017, we increased our 2017 capital expenditures budget to a range between $250.0 million and $260.0 million. The increase in budgeted capital expenditures is offset by asset sales, continued declining production costs, and increased 2017 production expectations, lessening the impact to future liquidity. Management intends to fund remaining 2017 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, and therefore 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 2015 through September 2017, the month-end NYMEX settled price for oil fluctuated between a high of $60.30 per Bbl in May 2015 and a low of $33.62 per Bbl in January 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.
Our cash flows for the nine-month periods ended September 30, 2017, and 2016 are presented in the following table and discussed below (in thousands):
|
| | | | | | | | |
| | Nine Months Ended September 30, |
| | Successor | | | Predecessor |
| | 2017 | | | 2016 |
| Cash flows provided by (used in) operating activities | $ | 147,906 |
| | | $ | (64,039 | ) |
| Cash flows used in investing activities | (181,210 | ) | | | (167,690 | ) |
| Cash flows (used in) provided by financing activities | (5,254 | ) | | | 448,821 |
|
| Net (decrease) increase in cash and cash equivalents | $ | (38,558 | ) | | | $ | 217,092 |
|
Cash Flows from Operating Activities
The $211.9 million increase in operating cash flows for the nine-month period ended September 30, 2017, compared to the same period in 2016, is primarily due to (i) a reduction in cash paid for interest expense, (ii) a reduction in general and administrative expenses, (iii) a reduction in production expenses, and (iv) cash payments made in the 2016 period to certain holders of the Convertible Notes who elected to convert their notes into shares of the Predecessor Company’s stock. These increases were partially offset by a decrease in cash received for the settlement of derivatives. See “—Consolidated Results of Operations” for further analysis of the changes in operating expenses.
Cash Flows from Investing Activities
The Company dedicates and expects to continue to dedicate a substantial portion of its capital expenditure program toward the exploration for and production of oil and natural gas. 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, 2017, cash flows used in investing activities included the acquisition of 13,000 net acres in Woodward County, Oklahoma for approximately $47.7 million in cash and capital expenditures for exploration and production, which were partially offset by proceeds from the sale of various non-core oil and natural gas properties and certain drilling equipment previously classified as held for sale. During the nine-month period ended September 30, 2016, cash flows used in investing activities primarily consisted of capital expenditures for exploration and production activities, which were slightly offset by proceeds from the sale of various non-core oil and natural gas properties. Capital expenditures on an accrual basis for the nine-month periods ended September 30, 2017, and 2016 are summarized on an accrual basis below (in thousands):
|
| | | | | | | | |
| | Nine Months Ended September 30, |
| | Successor | | | Predecessor |
| | 2017 | | | 2016 |
| Capital Expenditures (on an accrual basis) | | | | |
| Exploration and production | $ | 166,296 |
| | | $ | 155,627 |
|
| Other - operating | 282 |
| | | 3,108 |
|
| Other - corporate | 1,406 |
| | | 2,672 |
|
| Capital expenditures, excluding acquisitions | 167,984 |
| | | 161,407 |
|
| Acquisitions | 48,236 |
| | | 1,328 |
|
| Total | $ | 216,220 |
| | | $ | 162,735 |
|
Capital expenditures, excluding acquisitions, for exploration and production activities increased in the 2017 period compared to the 2016 period due primarily to an increase in drilling activity in the third quarter of 2017.
Cash Flows from Financing Activities
Our financing activities used $5.3 million of cash for the nine-month period ended September 30, 2017, which consisted of the purchase of common stock upon the vesting of employee share-based compensation awards and deferred financing costs incurred on the Credit Facility. Our financing activities provided approximately $448.8 million during the nine-month period ended September 30, 2016, primarily due to net borrowings under the senior credit facility in the first quarter of 2016.
Indebtedness
Long-termdebt consists of the following at September 30, 2017 (in thousands):
|
| | | |
| Credit Facility | $ | — |
|
| Building Note | 37,601 |
|
| Total Debt | $ | 37,601 |
|
Credit Facility
On February 10, 2017, the First Lien Exit Facility was refinanced into a new $600.0 million Credit Facility with a $425.0 million borrowing base. The Credit Facility agreement had the following impacts:
increased the principal amount of commitments to $600.0 million from $425.0 million;
extended the maturity date to March 31, 2020, from February 4, 2020;
borrowing base determinations now include our proportionately consolidated share of proved reserves held by the Royalty Trusts;
reduced the interest rate from a flat base rate of LIBOR plus 4.75% per annum to 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;
reduced the LIBOR floor from 1% to 0%;
eliminated the minimum proved developing producing reserves asset coverage ratio;
removed the requirement to maintain $50.0 million in a cash collateral account controlled by the administrative agent;
eliminated the holiday from borrowing base determinations and the maximum consolidated total net leverage ratio and the minimum consolidated interest coverage ratio covenants; and
eliminated certain negative covenants, such as the $20.0 million liquidity requirement and the limitation on capital expenditures.
The initial borrowing base under the Credit Facility was $425.0 million, which was reconfirmed in the October 2017 borrowing base redetermination. The next semi-annual borrowing base redetermination is scheduled for April 1, 2018. 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). As described above, the Credit Facility refinanced and thereby replaced the First Lien Exit Facility.
Beginning with the quarter ended June 30, 2017, 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, 2017.
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, the Company entered into the Building Note, which had an initial principal amount of $35.0 million and is secured by first priority mortgages on the Company’s real estate in Oklahoma City, Oklahoma. The Building Note was recorded at fair value ($36.6 million) upon implementation of fresh start accounting. Interest is 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 on the Building Note was initially payable in kind. Approximately $1.3 million in in-kind interest costs were added to the Building Note principal from the Emergence Date through May 11, 2017, which was 90 days after the refinancing of the First Lien Exit Facility. Interest became payable thereafter in cash. The Building Note matures 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.
See “Note 6 - 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, 2016, 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 conversion of the Convertible Notes discussed in “—Overview,” and the drilling participation agreement discussed in “—Overview” and “Note 2 - Recent Transactions” to the accompanying unaudited condensed consolidated financial statements, there were no other significant changes in contractual obligations and off-balance sheet arrangements from those reported in the 2016 10-K.
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 2016 Form 10-K. For a discussion of 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 2017.
Valuation Allowance
Upon emergence from bankruptcy and the application of fresh start accounting, our tax basis in property, plant, and equipment exceeded the book carrying value of our assets. Additionally, we had a significant U.S. Federal NOL carryforward remaining after the attribute reduction caused by the restructuring transactions. As such, the Successor Company had significant deferred tax assets to consume upon emergence. We considered all available evidence and concluded that it was more likely than not that some or all of the deferred tax assets would not be realized and established a valuation allowance against our net deferred tax asset upon emergence and maintained the valuation allowance for the subsequent periods through September 30, 2017.
We continue to closely monitor all available evidence in considering whether to maintain a valuation allowance on our net deferred tax asset. Factors considered are, but not limited to, the reversal periods of existing deferred tax liabilities and deferred tax assets, our historical earnings and the prospects of future earnings. For purposes of the valuation allowance analysis, “earnings” is defined as pre-tax earnings as adjusted for permanent tax adjustments.
In determining whether to maintain the valuation allowance at September 30, 2017, we concluded that the objectively verifiable negative evidence of the presumption of cumulative negative earnings upon emergence and actual cumulative negative earnings for the Successor Company period ended September 30, 2017, is difficult to overcome with any forms of positive evidence that may exist. Accordingly, we have not changed our judgment regarding the need for a full valuation allowance against our net deferred tax asset for the period ended September 30, 2017.
See “Note 10 - Income Taxes” to the accompanying unaudited condensed consolidated financial statements for additional discussion of income tax related matters.
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.
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, 2017, 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.
At September 30, 2017, our open commodity derivative contracts consisted of the following:
Oil Price Swaps
|
| | | | | | |
| | Notional (MBbls) | | Weighted Average Fixed Price |
| October 2017 - December 2017 | 828 |
| | $ | 52.24 |
|
| January 2018 - December 2018 | 2,006 |
| | $ | 54.87 |
|
Natural Gas Price Swaps
|
| | | | | | |
| | Notional (MMcf) | | Weighted Average Fixed Price |
| October 2017 - December 2017 | 8,280 |
| | $ | 3.20 |
|
| January 2018 - December 2018 | 17,300 |
| | $ | 3.16 |
|
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.
We recorded loss (gain) on commodity derivative contracts of $11.7 million and $(0.3) million for the three-month periods ended September 30, 2017, and 2016, respectively, which include net cash receipts upon settlement of $5.0 million and $14.6 million, respectively. We recorded (gain) loss on commodity derivative contracts of $(46.0) million and $4.8 million for the nine-month periods ended September 30, 2017, and 2016, respectively, which include net cash receipts upon settlement of $7.7 million and $72.6 million, respectively. Included in the net cash receipts for the nine-month period ended September 30, 2016, are $17.9 million of cash receipts related to early settlements.
See “Note 7 - 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, 2017, the counterparties to our open commodity derivative contracts consisted of seven 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, 2017.
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, 2017, 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, 2017, that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.
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. An estimate of reasonably possible losses associated with this action cannot be made at this time. The Company has not established any reserves relating to this action.
In addition to the matter 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.
ITEM 1A.Risk Factors
There have been no material changes to the risk factors previously discussed in Item 1A—Risk Factors in the Company’s 2016 Form 10-K.
ITEM 2.Unregistered Sales of Equity Securities and Use of Proceeds
The following table presents a summary of share repurchases made by the Company during the three-month period ended September 30, 2017.
|
| | | | | | | | | | | |
| Period | Total Number of Shares Purchased(1) | | Average Price Paid per Share | | Total Number of Shares Purchased as Part of Publicly Announced Program | | Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Program (in Millions) |
| July 1, 2017 — July 31, 2017 | 44,999 |
| | $ | 19.44 |
| | N/A |
| | N/A |
| August 1, 2017 — August 31, 2017 | — |
| | $ | — |
| | N/A |
| | N/A |
| September 1, 2017 — September 30, 2017 | — |
| | $ | — |
| | N/A |
| | N/A |
| Total | 44,999 |
| | | | — |
| | |
____________________
| |
(1) | Includes shares of common stock tendered by employees in order to satisfy tax withholding requirements upon vesting of their stock awards. Shares withheld are initially recorded as treasury shares, then immediately retired. |
ITEM 3.Defaults upon Senior Securities
None.
ITEM 6. Exhibits
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Incorporated by Reference | | | | | | | | |
Exhibit No. | Exhibit Description | Form | | SEC File No. | | Exhibit | | Filing Date | | Filed Herewith |
| 2.1 |
| 8-A | | 001-33784 | | 2.1 | | 10/4/2016 | | |
| 3.1 |
| 8-A | | 001-33784 | | 3.1 | | 10/4/2016 | | |
| 3.2 |
| 8-A | | 001-33784 | | 3.2 | | 10/4/2016 | | |
| 10.1 | | 8-K | | 001-33784 | | 10.1 | | 4/7/2020 | | |
| 10.2 | | 10-K | | 001-33784 | | 10.11 | | 2/27/2020 | | |
| 31.1 | | 10-Q | | 001-33784 | | 31.1 | | 5/19/2020 | | |
| 31.2 | | 10-Q | | 001-33784 | | 31.2 | | 5/19/2020 | | |
| 31.3 | | | | | | | | | | * |
| 32.4 | | | | | | | | | | * |
| 32.1 | | 10-Q | | 001-33784 | | 32.1 | | 5/19/2020 | | |
| 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 | | | | | | | | | * |
| 104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) | | | | | | | | | * |
See the Exhibit Index accompanying this Quarterly Report.
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. | |
| | |
| Date: June 2, 2020 | SandRidge Energy, Inc.By: | /s/ Michael A. Johnson |
| | |
| By: | /s/ Julian Bott |
| | Julian BottMichael A. Johnson
ExecutiveSenior Vice President and Chief Financial Officer
|
Date: November 3, 2017
EXHIBIT INDEX
|
| | | | | | | | | | |
| | | Incorporated by Reference | | |
Exhibit No. | Exhibit Description | Form | | SEC File No. | | Exhibit | | Filing Date | | Filed Herewith |
| 2.1 |
| 8-A | | 001-33784 | | 2.1 | | 10/4/2016 | | |
| 3.1 |
| 8-A | | 001-33784 | | 3.1 | | 10/4/2016 | | |
| 3.2 |
| 8-A | | 001-33784 | | 3.2 | | 10/4/2016 | | |
10.1.1.1†
| | | | | | | | | | *
|
10.1.2.1†
|
| | | | | | | | | *
|
10.1.4.1†
|
| | | | | | | | | *
|
| 10.1.6.1† |
| | | | | | | | | * |
| 31.1 | | | | | | | | | | * |
| 31.2 | | | | | | | | | | * |
| 32.1 | | | | | | | | | | * |
| 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 | | | | | | | | | * |