Seventy Seven Energy Inc. - FORM 10-K

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EX-31.2 - EXHIBIT 31.2 - Seventy Seven Energy Inc.	ex31220161231.htm
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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K



ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2016



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

FOR THE TRANSITION PERIOD FROM TO

Commission File No. 000-55669

Seventy Seven Energy Inc.

(Exact name of registrant as specified in its charter)



Delaware		45-3338422
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

777 N.W. 63rd Street Oklahoma City, Oklahoma		73116
(Address of principal executive offices)		(Zip Code)

(405) 608-7777

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

None

Securities registered pursuant to Section 12(g) of the Act:

Title of Class

Series B Warrants to purchase Common Stock, par value $0.01

Series C Warrants to purchase Common Stock, par value $0.01

Indicate by check mark whether the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¬ No ý

Indicate by check mark whether the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¬ No ý

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 ý No ¬

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¬

Indicate by check mark whether the registrant is a large accelerated filer, accelerated filer, non-accelerated filer, or smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ý No ¨

The aggregate market value of the common equity held by non-affiliates as of June 30, 2016 was approximately $5.2 million. At February 9, 2017, there were 22,932,522 shares of our $0.01 par value common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement relating to the 2017 Annual Meeting of Stockholders of Seventy Seven Energy Inc., which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2016, are incorporated by reference in Item 10, Item 11, Item 12, Item 13 and Item 14 of Part III of this Form 10-K.

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TABLE OF CONTENTS



		Page
PART I		1
Item 1.	Business	1
Item 1A.	Risk Factors	13
Item 1B.	Unresolved Staff Comments	28
Item 2.	Properties	28
Item 3.	Legal Proceedings	28
Item 4.	Mine Safety Disclosures	28

PART II		29
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	29
Item 6.	Selected Financial Data	30
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	60
Item 8.	Financial Statements and Supplementary Data	61
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	104
Item 9A.	Controls and Procedures	105
Item 9B.	Other Information	106

PART III		107
Item 10.	Directors, Executive Officers and Corporate Governance	107
Item 11.	Executive Compensation	107
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	107
Item 13.	Certain Relationships and Related Transactions, and Director Independence	107
Item 14.	Principal Accounting Fees and Services	107

PART IV		108
Item 15.	Exhibits, Financial Statement Schedules	108
Item 16.	Form 10-K Summary	111

SIGNATURES		111

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Forward-Looking Statements

All references in this report to “SSE”, the “Company”, “us”, “we”, and “our” are to Seventy Seven Energy Inc. and its consolidated subsidiaries. Certain statements contained in this report constitute forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Act of 1934. These statements relate to future events or our future performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as “seek,” “anticipate,” “plan,” “continue,” “estimate,” “expect,” “may,” “project,” “predict,” “potential,” “targeting,” “intend,” “could,” “might,” “should,” “believe” and similar expressions. These statements involve known and unknown risks and uncertainties and involve assumptions that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. Seventy Seven Energy Inc. believes the expectations reflected in these forward-looking statements are reasonable, but we cannot assure you that these expectations will prove to be correct. We caution you not to place undue reliance on the forward-looking statements contained in this report, which speak only as of the filing date.

Our actual results could differ materially from those anticipated in these forward-looking statements as a result of many factors, including the following factors:


•	the effects of the pending merger with Patterson-UTI Energy, Inc. (“Patterson-UTI”) on our business and operations;


•	potential adverse effects if the merger with Patterson-UTI is not completed;


•	potential adverse effects of our emergence from the Chapter 11 proceedings on our liquidity, results of operations, brand or business prospects and our ability to operate our business following such date;


•	the effects of the bankruptcy filing on our business and the interests of various creditors, equity holders and other constituents;


•	market prices for oil and natural gas;


•	our customers’ expenditures for oilfield services;


•	dependence on Chesapeake Energy Corporation (“CHK”) and its working interest partners for a majority of our revenues and our ability to secure new customers or provide additional services to existing customers;


•	the limitations that our level of indebtedness may have on our financial flexibility and restrictions in our debt agreements;


•	our ability to develop and maintain effective internal controls


•	the cyclical nature of the oil and natural gas industry;


•	changes in supply and demand of drilling rigs, hydraulic fracturing fleets and rental equipment;


•	our credit profile;


•	access to and cost of capital;


•	hazards and operational risks that may not be fully covered by insurance;


•	increased labor costs or the unavailability of skilled workers;


•	competitive conditions;


•	legislative or regulatory changes, including changes in environmental regulations, drilling regulations and liability under federal and state environmental laws and regulations; and


•	the factors generally described in Item 1A “Risk Factors” in this report.

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If one or more events related to these or other risks and uncertainties materialize, or if our underlying assumptions prove to be incorrect, our actual results may differ materially from what we anticipate. Except as may be required by law, we do not intend, and do not assume any obligation, to update any forward-looking statements.

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PART I



Item 1.	Business

We are a diversified oilfield services company that provides a wide range of wellsite services and equipment to U.S. land-based exploration and production (“E&P”) customers operating in unconventional resource plays. We offer services and equipment that are strategic to our customers’ oil and natural gas operations. Our services include drilling, hydraulic fracturing and oilfield rentals. Our operations are geographically diversified across many of the most active oil and natural gas plays in the onshore United States, including the Anadarko and Permian Basins and the Eagle Ford, Haynesville, Marcellus, Niobrara and Utica Shales.

Information About Us

We make available free of charge on our website at www.77nrg.com our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports as soon as reasonably practicable after we electronically file such material with or furnish it to the U.S. Securities and Exchange Commission (the “SEC”).

Patterson-UTI Merger Agreement

On December 12, 2016, SSE entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Patterson-UTI Energy, Inc., a Delaware corporation, and Pyramid Merger Sub, Inc., a Delaware corporation and a direct, wholly owned subsidiary of Patterson-UTI (“Merger Sub”), pursuant to which Patterson-UTI will acquire SSE in exchange for newly issued shares of Patterson-UTI common stock, par value $0.01 per share (“Patterson-UTI Common Stock”). The Merger Agreement provides that, upon the terms and subject to the conditions set forth therein, Merger Sub will be merged with and into SSE, with SSE continuing as the surviving entity and a wholly owned subsidiary of Patterson-UTI (the “Merger”). The transaction is subject to approvals from each company’s stockholders, regulatory approvals and customary closing conditions. The transaction is expected to close late in the first quarter or early in the second quarter of 2017. However, SSE cannot predict with certainty when, or if, the pending merger will be completed because completion of the transaction is subject to conditions beyond the control of the Company.

In connection with the execution of the Merger Agreement, certain affiliates of Axar Capital Management, LLC, BlueMountain Capital Management, LLC and Mudrick Capital Management, L.P. entered into voting and support agreements with Patterson-UTI, pursuant to which each such stockholder agreed to vote all of its shares of SSE common stock in favor of the adoption of the merger agreement and against, among other things, alternative transactions. As of February 9, 2017, those stockholders held and are entitled to vote in the aggregate approximately 59% of the issued and outstanding shares of SSE common stock entitled to vote at the SSE special meeting. In the event that SSE’s board of directors changes its recommendation that SSE stockholders adopt the merger agreement, such stockholders, taken together, will be required to vote shares that, in the aggregate, represent 39.99% of the issued and outstanding shares of SSE common stock on such proposal, with each such stockholder being able to vote the balance of its shares of SSE common stock on such proposal in such stockholder’s sole discretion.

For further information about the merger, see Note 2 “Patterson-UTI Merger Agreement” of the Notes to Consolidated Financial Statements in Item 8 herein.

Emergence from Voluntary Reorganization under Chapter 11 Proceedings

On June 7, 2016, SSE and its subsidiaries (collectively, the “Debtors”) filed voluntary petitions for relief (the “Bankruptcy Petitions”) under Chapter 11 of the United States Code (“Chapter 11” or the “Bankruptcy Code”) in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”), case number 16-11409. The Debtors continued to operate their business as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court. The subsidiary Debtors in these Chapter 11 cases were Seventy Seven Operating LLC (“SSO”), Seventy Seven Land Company LLC, Seventy Seven Finance Inc. (“SSF”), Performance Technologies, L.L.C., PTL Prop Solutions, L.L.C., Western Wisconsin Sand Company, LLC, Nomac Drilling, L.L.C., SSE Leasing LLC, Keystone Rock & Excavation, L.L.C. and Great Plains Oilfield Rental, L.L.C., which represent all subsidiaries of the Company. On July 14, 2016, the Bankruptcy Court issued an order (the “Confirmation Order”) confirming the Joint Pre-packaged Plan of Reorganization (as amended and supplemented, the “Plan”) of the Debtors. On

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August 1, 2016 (the “Effective Date”), the Plan became effective pursuant to its terms and the Debtors emerged from their Chapter 11 cases. For further information about the reorganization, see Note 3 “Emergence from Voluntary Reorganization under Chapter 11 Proceedings and Related Events” of the Notes to Consolidated Financial Statements in Item 8 herein.

Upon emergence from bankruptcy, the Company adopted fresh-start accounting and became a new entity for financial reporting purposes. As a result of the application of fresh-start accounting and the effects of the implementation of the Plan, the Company’s consolidated financial statements on or after August 1, 2016 are not comparable with the financial statements prior to the Effective Date. The discussion and analysis of our financial condition and results of operations contained herein relates to the five months ended December 31, 2016 (the “2016 Successor Period”), the seven months ended July 31, 2016 (the “2016 Predecessor Period”) and the years ended December 31, 2015 and 2014. For additional information about the application of fresh-start accounting, see Note 4 “Fresh-Start Accounting” of the Notes to Consolidated Financial Statements in Item 8 herein.

Spin-Off

On June 30, 2014, we separated from CHK in a series of transactions, which we refer to as the “spin-off.” Prior to the spin-off, we were an Oklahoma limited liability company operating under the name “Chesapeake Oilfield Operating, L.L.C.” (“COO”) and an indirect, wholly-owned subsidiary of CHK. As part of the spin-off, we converted to an Oklahoma corporation operating under the name “Seventy Seven Energy Inc.” All of the equity in our Company was distributed pro rata to CHK’s shareholders and we became an independent, publicly traded company. Please read “—The Spin-Off” for further discussion of the transactions in which SSE became an independent public company and the agreements we entered into with CHK in connection with the spin-off.

Our Operating Segments

We conduct our business through three operating segments: Drilling, Hydraulic Fracturing and Oilfield Rentals. For financial information pertaining to our operating segments, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 20 “Segment Information” of the Notes to Consolidated Financial Statements in Items 7 and 8, respectively, of this report.

Drilling

Our drilling segment is operated through our wholly-owned subsidiary, Nomac Drilling, L.L.C., and provides land-based drilling services.

Drilling rig fleet. Our all-electric rig fleet, one of the largest in the industry, is categorized into two operational “Tiers.” All of our rigs are equipped with top drives. Our AC powered Tier 1 and DC powered Tier 2 rigs are predominantly equipped with 1,600 horsepower mud pumps. Approximately 79% of our rigs are multi-well pad capable, equipped with skidding or walking systems.

As of December 31, 2016, our marketed rig fleet of 91 all-electric rigs consisted of 40 Tier 1 rigs, including 28 proprietary PeakeRigs™, and 51 Tier 2 rigs. Our PeakeRigs™ are designed for long lateral drilling of multiple wells from a single location, which makes them well-suited for unconventional resource development.

Drilling customers and contracts. Our customers, as operators of the wells that we service, engage us and pay our fees. These contracts provide for drilling services on a well-by-well basis or for a term of a certain number of days or a certain number of wells. As of December 31, 2016, all of our drilling contracts were daywork contracts. A daywork contract generally provides for a basic rate per day when drilling (the day rate for our providing a rig and crew) and for lower rates when the rig is moving, or when drilling operations are interrupted or restricted by equipment breakdowns, adverse weather conditions or other certain conditions beyond our control. In addition, daywork contracts may provide for a lump-sum fee for the mobilization and demobilization of the rig, which in most cases approximates our incurred costs. Many of our drilling contracts are also subject to termination by the customer. Under certain of these contracts, we have agreed to allow customers to pay the termination cost over the life of the contract in lieu of a lump sum, and we refer to a rig in this circumstance as “idle but contracted” or “IBC.” IBC payments are structured to preserve our anticipated operating margins for the affected rigs through the end of the contract terms.

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Hydraulic Fracturing

Our hydraulic fracturing segment is operated through our wholly-owned subsidiary, Performance Technologies, L.L.C. (“PTL”), and provides high-pressure hydraulic fracturing (or frac) services and other well stimulation services.

Hydraulic fracturing services. As of December 31, 2016, we own 13 hydraulic fracturing fleets with an aggregate of approximately 500,000 horsepower, and six of these fleets are contracted in the Anadarko Basin and the Eagle Ford Shale. Our equipment currently has an average age of approximately four and one-half years.

Hydraulic fracturing process. The fracturing process consists of pumping a fracturing fluid into a well at sufficient pressure to fracture the formation. The fracturing fluid is mainly water, which is mixed with specialty additives. Materials known as proppants, primarily sand or sand coated with resin, are suspended in the fracturing fluid and are pumped into the fracture to prop it open. The fracturing fluid is designed to “break,” or lose viscosity, and be forced out of the formation by its pressure, leaving the proppants suspended in the fractures.

Companies offering fracturing services typically own and operate fleets of mobile, high-pressure pumping systems and other heavy equipment. We refer to these pumping systems, each of which consists of a high-pressure reciprocating pump, diesel engine, transmission and various hoses, valves, tanks and other supporting equipment, all typically mounted to a flat-bed trailer, as “fracturing units.” The group of fracturing units, other equipment and vehicles necessary to perform a typical fracturing job is referred to as a “fleet.” Each fleet typically consists of eight to 20 fracturing units; two or more blenders (one used as a backup), which blend the proppant and chemicals into the fracturing fluid; sand bins, which are large containers used to store sand on location; various vehicles used to transport sand, chemicals, gels and other materials; and various service trucks and a monitoring van equipped with monitoring equipment and computers that control the fracturing process. The personnel assigned to each fleet are commonly referred to as a “crew.”

An important element of fracturing services is determining the proper fracturing fluid, proppants and injection program to maximize recovery from a given well. We employ field engineering personnel to provide technical evaluation and job design recommendations for customers as an integral element of our fracturing service. Technological developments in the industry over the past several years have focused on proppant density control, liquid gel concentrate capabilities, computer design and monitoring of jobs and cleanup properties for fracturing fluids.

We purchase the fracturing fluid additives used in our hydraulic fracturing activities from third-party suppliers. The suppliers are responsible for storage, handling and compatibility of the chemicals used in the fracturing fluid. In addition to performing internal vendor environmental and operational quality control at the well site, we also require our suppliers to adhere to strict environmental and quality standards and to maintain minimum inventory levels at regional hubs, thus ensuring adequate supply for our hydraulic fracturing operations.

Hydraulic fracturing customers and contracts. We contract with our customers pursuant to master services agreements that specify payment terms, audit rights and insurance requirements and allocate certain operational risks through indemnity and similar provisions. We supplement these agreements for each engagement with a bid proposal, subject to customer acceptance, containing terms such as the estimated number of fracturing stages to be performed, pricing, quantities of products required, and horsepower and pressure ratings of the hydraulic fracturing fleets to be used. We are generally compensated based on the number of fracturing stages we complete, and we recognize revenue upon the completion of each fracturing stage. We typically complete one or more fracturing stages per day during the course of a job. A stage is considered complete when the customer requests that pumping discontinue for that stage. Invoices typically include service charges that are determined by hydraulic horsepower requirements and achieved rate of barrels per minute along with product charges for sand, chemicals and other products actually consumed during the course of providing our services.

Oilfield Rentals

Our oilfield rentals segment is operated through our wholly-owned subsidiary, Great Plains Oilfield Rental, L.L.C., and provides premium rental tools and specialized services for land-based drilling, completion and workover activities. We offer an extensive line of rental tools, including a full line of tubular products specifically designed for horizontal drilling and completion, with high-torque, premium-connection drill pipe, drill collars and tubing. Additionally, we offer surface rental equipment including blowout preventers, frac tanks, mud tanks and environmental containment that encompass all phases of the hydrocarbon extraction and production process. Our air drilling equipment and services enable extraction in select basins where certain segments of formations preclude the use of drilling fluid, permitting operators to drill through problematic zones without the risk of fluid absorption and damage to the wellbore. We also provide frac-support services, including rental and rig-

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up/rig-down of wellhead pressure control equipment (“frac stacks”), delivery of on-site frac water through a water transfer operation using innovative lay-flat pipe, and monitoring and controlling of production returns. As of December 31, 2016, we offered oilfield rental services in the Mid-Continent region, Permian Basin and the Eagle Ford, Haynesville, Marcellus, Niobrara and Utica Shales. We price our rentals and services based on the type of equipment being rented and the services being performed. Substantially all rental revenue we earn is based upon a charge for the actual period of time the rental is provided to our customer on a market-based, fixed per-day or per-hour fee.

Former Oilfield Trucking

Our former oilfield trucking segment provided drilling rig relocation and logistics services as well as fluid handling services. During the second quarter of 2015, we sold Hodges Trucking Company, L.L.C., which provided drilling rig relocation and logistics services (please read Note 8 “Sale of Hodges Trucking Company, L.L.C.” of the Notes to Consolidated Financial Statements in Item 8 herein), and we also sold our water hauling assets. As part of the spin-off, we sold our crude hauling assets to a third party.

Customers and Competition

The markets in which we operate are highly competitive and we are dependent on CHK for the majority of our revenues. Our customers pay us market-based rates for the services we provide. To the extent that competitive conditions increase and prices for the services and products we provide decrease, the prices we are able to charge our customers for such products and services may decrease.

We are a party to a master services agreement (the “Master Services Agreement”) with CHK, pursuant to which we provide drilling and other services and supply materials and equipment to CHK. The Master Services Agreement contains general terms and provisions, specifies payment terms, audit rights and insurance requirements and allocates certain operational risks through indemnity and similar provisions. The agreement will remain in effect until we or CHK provide 30 days written notice of termination. The specific terms of each drilling services request are typically provided pursuant to drilling contracts on a well-by-well basis or for a term of a certain number of days or wells. The specific terms of each request for other services are typically set forth in a field ticket or purchase or work order. We believe that our drilling contracts, field tickets or purchase or work orders with CHK are substantially similar to those in prevailing industry contracts, specifically as they relate to pricing, liabilities and payment terms.

In connection with the spin-off, we supplemented the Master Service Agreement with certain new services agreements, including new drilling contracts and a services agreement for hydraulic fracturing services, among others. Please read “—The Spin-Off—Agreements Between Us and CHK” for further discussion of the new services agreements.

Competitors in each of our operating segments include:


•	Drilling - Helmerich & Payne, Inc., Patterson-UTI Energy, Inc., Trinidad Drilling Ltd., Nabors Industries Ltd., Pioneer Energy Services Corp., and Precision Drilling Corporation.


•	Hydraulic Fracturing - Halliburton Company, Schlumberger Limited, Baker Hughes Incorporated, Superior Energy Services, Inc., Weatherford International plc, RPC, Inc., Keane Group, FTS International, Inc., and C&J Energy Services, Inc.


•	Oilfield Rentals - Key Energy Services, Inc., RPC, Inc., Oil States International, Inc., Baker Oil Tools, Weatherford International plc, Basic Energy Services, Inc., Superior Energy Services, Inc., Quail Tools (owned by Parker Drilling Company), and Knight Oil Tools.

We also compete in each of our operating segments against a significant number of other companies with national, regional, or local operations.

Suppliers

We purchase a wide variety of raw materials, parts and components that are made by other manufacturers and suppliers for our use. We are not dependent on any single source of supply for those parts, supplies or materials.

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For our drilling rigs, we generally purchase individual components from reputable original equipment manufacturers and then assemble and commission the rigs ourselves at an internal facility, which we believe results in cost savings and higher quality.

We have purchased the majority of our hydraulic fracturing units from United Engines and FTS International. We purchase the raw materials we use in our hydraulic fracturing operations, such as sand, chemicals and diesel fuel, from a variety of suppliers throughout the U.S.

To date, we have generally been able to obtain on a timely basis the equipment, parts and supplies necessary to support our operations. Where we currently source materials from one supplier, we believe that we will be able to make satisfactory alternative arrangements in the event of interruption of supply. However, given the limited number of suppliers of certain of our raw materials, we may not always be able to make alternative arrangements should one of our suppliers fail to deliver or timely deliver our materials.

Employees

At every level of our operations, our employees are critical to our success and committed to operational excellence. Our senior management team has extensive experience building, acquiring and managing oilfield services and other assets. Their focus is on optimizing our business and expanding operations. On an operations level, our supervisory and field personnel are empowered with the training, tools and confidence required to succeed in their jobs. As of December 31, 2016, we employed approximately 1,700 people, none of whom were covered by collective bargaining agreements, and we consider our relationships with our employees to be good.

Risk Management and Insurance

The oilfield services business involves a variety of operating risks, including the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, natural gas leaks, ruptures or discharges of toxic gases. If any of these should occur, we could incur legal defense costs and suffer substantial losses due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations.

We are covered under insurance policies that we believe are customary in the industry with customary deductibles or self-insured retentions. However, there are no assurances that this insurance will be adequate to cover all losses or exposure to liability. We carry $100.0 million in excess liability umbrella policies over our general liability, automobile liability, non-owned aviation liability and employer’s liability policies, as well as a $10.0 million contractor’s pollution liability policy. We provide workers’ compensation insurance coverage to employees in all states in which we operate. While we believe these policies are customary in the industry, they do not provide complete coverage against all operating risks. In addition, our insurance does not cover penalties or fines that may be assessed by a governmental authority. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows. The insurance coverage that we maintain may not be sufficient to cover every claim made against us and may not be available for purchase in the future on terms we consider commercially reasonable, or at all. Also, in the past, insurance rates have been subject to wide fluctuation, and changes in coverage could result in less coverage, increases in cost or higher deductibles and self-insured retentions.

Our master services agreements include certain indemnification provisions for losses resulting from operations. Generally, we take responsibility for our own people and property while our customers take responsibility for their own people, property and liabilities related to the well and subsurface operations, regardless of either party’s negligence or fault. For example, our Master Services Agreement with CHK provides that CHK assumes liability for (a) damage to the hole, including the cost to re-drill; (b) damages or claims arising from loss of control of a well or a blowout; (c) damage to the reservoir, geological formation or underground strata; (d) damages arising from the use of radioactive tools or any contamination resulting therefrom; (e) damages arising from pollution or contamination (other than surface spills attributable to our negligence); (f) liability arising from damage to, or escape of any substance from, any pipeline, vessel or storage or production facility; and (g) allegations of subsurface trespass.

In general, any material limitations on contractual indemnity obligations arise only by applicable state law or public policy. Many states place limitations on contractual indemnity agreements, particularly agreements that indemnify a party against the consequences of its own negligence. Furthermore, certain states, including Texas, Louisiana, New Mexico and Wyoming, have enacted statutes generally referred to as “oilfield anti-indemnity acts” expressly prohibiting certain indemnity agreements contained in or related to oilfield services agreements. Such oilfield anti-indemnity acts may restrict or void a

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party’s indemnification of us. Please read “Risk Factors—Risks Relating to Our Industry and Our Business” in Item 1A of this report.

Safety and Maintenance

Our business involves the operation of heavy and powerful equipment which can result in serious injuries to our employees and third parties and substantial damage to property and the environment. We have comprehensive health, safety and environmental (“HSE”) and training programs designed to reduce accidents in the workplace and improve the efficiency of our operations. In addition, our largest customers place great emphasis on HSE and the quality management programs of their contractors. We believe that these factors will gain further importance in the future. We have directed substantial resources toward employee HSE and quality management training programs as well as our employee review process and have benefited from steadily decreasing incident frequencies.

Regulation of Operations

We operate under the jurisdiction of a number of federal, state and local regulatory bodies that regulate worker safety, the handling of hazardous materials, the transportation of explosives, the protection of the environment and safe driving procedures. Regulations concerning equipment certification create an ongoing need for regular maintenance that is incorporated into our daily operating procedures. Please read “Risk Factors—Risks Relating to Our Industry and Our Business” in Item 1A of this report.

Among the services we provide and assets we utilize, we operate as a motor carrier and therefore are subject to regulation by the U.S. Department of Transportation and by various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations and regulatory safety, financial reporting and certain mergers, consolidations and acquisitions.

Interstate motor carrier operations are subject to safety requirements prescribed by the U.S. Department of Transportation. To a large degree, intrastate motor carrier operations are subject to safety regulations that mirror federal regulations. Such matters as weight and dimension of equipment are also subject to federal and state regulations, while the Department of Transportation mandates drug testing of drivers.

From time to time, various legislative proposals are introduced, such as proposals to increase federal, state, or local taxes, including taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes applicable to us will be enacted.

Environmental Matters

Our operations are subject to various federal, state and local environmental, health and safety laws and regulations pertaining to the release, emission or discharge of materials into the environment, the generation, storage, transportation, handling and disposal of materials (including solid and hazardous wastes) or the safety of employees, or otherwise relating to preservation or protection of human health and safety, pollution prevention or remediation, natural resources, wildlife or the environment. Federal environmental, health and safety requirements that govern our operations include the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), the Clean Water Act, the Safe Drinking Water Act (“SDWA”), the Clean Air Act (the “CAA”), the Resource Conservation and Recovery Act (“RCRA”), the Endangered Species Act, the Migratory Bird Treaty Act, the Occupational Safety and Health Act, and the regulations promulgated pursuant to such laws.

Some of these laws, including CERCLA and analogous state laws, may impose joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered responsible for releases of a hazardous substance or other pollutant into the environment. These persons may include the current or former owner or operator of the site where the release occurred and persons that generated, disposed of or arranged for the disposal of hazardous substances at the site.

Other federal and state laws, in particular RCRA, regulate hazardous wastes and non-hazardous solid wastes. In the course of our operations, we generate petroleum hydrocarbon wastes and other maintenance wastes. Some of our wastes are not currently classified as hazardous wastes, but may in the future be designated as hazardous wastes and may thus become subject to more rigorous and costly compliance and disposal requirements.

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We own or lease a number of properties that have been used as service yards in support of oil and natural gas exploration and production activities. Although we have utilized operating and disposal practices that we considered to be standard in the industry at the time, repair and maintenance activities on rigs and equipment stored in these service yards may have resulted in the disposal or release of hydrocarbons, wastes, or hazardous substances, including Naturally Occurring Radioactive Material (“NORM”) at or from these yards or at or from other locations where these wastes have been taken for treatment, storage or disposal. In addition, we own or lease properties that in the past were used by third parties whose operations were not under our control. These properties and any hydrocarbons or other materials handled thereon may be subject to CERCLA, RCRA or analogous state laws. Under these types of laws, we could be required to remove or remediate previously released hazardous substances, wastes or property contamination, or to pay for such cleanup activity.

Further, our operations are subject to the federal CAA and comparable state laws and regulations. These laws and regulations govern emissions of air pollutants from various industrial sources, including our non-road mobile engines, and impose various monitoring and reporting requirements. Compliance with increasingly stringent air emissions regulations may result in increased costs as we continue to grow. Beyond that, federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal CAA and associated state laws and regulations.

The Federal Water Pollution Control Act (commonly known as “the Clean Water Act”) and resulting regulations, which are primarily implemented through a system of permits, govern the discharge of certain contaminants into waters of the United States. Violation of the Clean Water Act requirements may result in a fine as well as an order to stop facility construction or operation or to stop hauling wastewaters to third party facilities. In addition, the Federal Oil Pollution Act of 1990 (“OPA”) and resulting regulations impose a variety of obligations on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills in waters of the United States.

The SDWA and comparable local and state provisions restrict the disposal, treatment or release of water produced or used during oil and gas development. Subsurface emplacement of fluids (including disposal wells or enhanced oil recovery) is governed by federal or state regulatory authorities that, in some cases, includes the state oil and gas regulatory authority or the state’s environmental authority. These regulations may increase the costs of compliance for some facilities.

We seek to manage environmental liability risks through provisions in our contracts with our customers that allocate risks relating to surface activities associated with the fracturing process to us and risks relating to “down-hole” liabilities to our customers. Our contracts generally require our customers to indemnify us against pollution and environmental damages originating below the surface of the ground or arising out of water disposal, or otherwise caused by the customer, other contractors or other third parties. In turn, our contracts generally require us to indemnify our customers for pollution and environmental damages originating at or above the surface caused solely by us. We seek to maintain consistent risk-allocation and indemnification provisions in our customer agreements to the greatest extent possible. Some of our contracts, however, may contain less explicit indemnification provisions, which would typically provide that each party will indemnify the other against liabilities to third parties resulting from the indemnifying party’s actions, except to the extent such liability results from the indemnified party’s gross negligence, willful misconduct or intentional act.

We have made and will continue to make expenditures to comply with health, safety and environmental regulations and requirements. These are necessary business costs in the oilfield services industry. Although we are not fully insured against all environmental, health and safety risks, and our insurance does not cover any penalties or fines that may be issued by a governmental authority, we maintain insurance coverage which we believe is customary in the industry. Moreover, it is possible that other developments, such as stricter and more comprehensive environmental, health and safety laws and regulations, as well as claims for damages to property or persons, resulting from company operations, could result in substantial costs and liabilities, including administrative, civil and criminal penalties, to us. We believe that we are in material compliance with applicable health, safety and environmental laws and regulations. We believe that the cost of maintaining compliance with these laws and regulations will not have a material adverse effect on our business, financial position and results of operations, but new or more stringent regulations could increase the cost of doing business and could have a material adverse effect on our business. Moreover, accidental releases or spills may occur in the course of our operations, causing us to incur significant costs and liabilities, including for third-party claims for damage to property and natural resources or personal injury. Please read “Risk Factors—Risks Relating to Our Industry and Our Business” in Item 1A of this report.

Hydraulic Fracturing. Vast quantities of oil, natural gas liquids and natural gas deposits exist in deep shale unconventional formations. It is customary in our industry to recover these resources from these deep formations through the use of hydraulic fracturing, combined with horizontal drilling.

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Hydraulic fracturing techniques have been used by the industry since 1947, and currently, more than 90% of all oil and natural gas wells drilled in the U.S. employ hydraulic fracturing. We strive to conduct our fracturing operations in accordance with best practices, industry standards, and all regulatory requirements. For example, we monitor rate and pressure to ensure that the services are performed as planned. We also perform fracturing for wells that have been constructed with multiple layers of protective steel casing surrounded by cement that are specifically designed to protect freshwater aquifers.

Legislative and regulatory efforts at the federal, state and local levels have been initiated that may impose additional requirements on our oilfield services, including hydraulic fracturing. In a few instances these have included bans on hydraulic fracturing. To date, these initiatives have not materially affected our operations, but they could spur further action towards federal, state, or local legislation and regulation of hydraulic fracturing activities. At this time, it is not possible to estimate the potential impact on our business of such additional federal, state, or local legislation or regulations affecting hydraulic fracturing. In addition, there is a growing trend among states to require us to provide information about the chemicals and products we maintain on location and use during hydraulic fracturing activities. Many of these laws and regulations require that we disclose information about these chemicals and products. In certain cases, these chemicals and products are manufactured and/or imported by third parties and we therefore must rely upon such third parties for such information. The consequences of any inaccurate disclosure, failure to disclose, or disclosure of confidential or proprietary information by us could have a material adverse effect on our business, financial condition and operational results. See “Risk Factors - Changes in laws or government regulations regarding hydraulic fracturing could increase our costs of doing business, limit the areas in which our customers can operate and reduce oil and natural gas production by our customers, which could adversely impact our business” in Item 1A of this report.

Greenhouse Gas Regulations. In June 2013, President Obama unveiled a Presidential climate action plan designed to reduce emissions in the U.S. of methane, carbon dioxide and other greenhouse gases (“GHG”). In furtherance of that plan, the Obama Administration launched a number of initiatives, including the development of standards restricting GHG emissions from light, medium and heavy-duty vehicles and of a Strategy to Reduce Methane Emissions from the oil and gas industry. The former Administration’s goal was to reduce methane emissions from the oil and gas industry by 40-45% by 2025 as compared to 2012 levels. Accordingly, the Environmental Protection Agency (“EPA”) adopted and implemented a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing provisions of the Clean Air Act (“CAA”). For instance, in May 2016, the EPA issued final new source performance standards governing methane emissions, imposing more stringent controls on methane and volatile organic compounds emissions at new and modified oil and natural gas production, processing, storage, and transmission facilities. The EPA has also announced that it intends to impose methane emission standards for existing sources and has issued information collection requests to companies with production, gathering and boosting, gas processing, storage, and transmission facilities. Similarly, the Bureau of Land Management issued final rules in November 2016 relating to the venting, flaring and leaking of natural gas by oil and natural gas producers who operate on federal and Indian lands. Furthermore, various state and local governments are considering enacting new legislation and promulgating new regulations governing or restricting GHG emissions from stationary sources such as our equipment and operations or promoting the use of renewable energy. Finally, in April 2016, the United States signed the Paris Agreement, which requires member countries to review and “represent a progression” in their nationally determined contributions, which set GHG emission reduction goals, every five years. See “Risk Factors - Our operations may incur substantial liabilities to comply with climate change legislation and regulatory initiatives.” in Item 1A of this report.

Emergence from Voluntary Reorganization under Chapter 11 Proceedings and Related Events

On May 12, 2016, the Company and all of its wholly owned subsidiaries entered into a Second Amended and Restated Restructuring Support Agreement (the “Restructuring Support Agreement”) with (i) certain noteholders of the 6.625% senior unsecured notes due 2019 of SSO and SSF (the “2019 Notes”), (ii) certain lenders under the Company’s Incremental Term Supplement (Tranche A) loan (the “Incremental Term Loan”), (iii) certain lenders under the Company’s $400.0 million Term Loan Credit Agreement dated June 25, 2014 (the “Term Loan”), and (iv) certain noteholders of the 6.50% senior unsecured notes due 2022 of the Company (the “2022 Notes”).

On June 7, 2016, the Debtors filed the Bankruptcy Petitions for reorganization under Chapter 11 in the Bankruptcy Court. The filings of the Bankruptcy Petitions constituted an event of default with respect to the 2019 Notes, the 2022 Notes, the Term Loan and the Incremental Term Loan (collectively, the “Outstanding Debt”) and constituted an event of default under our $275.0 million senior secured revolving credit facility (the “Pre-Petition Credit Facility”). See Note 11 “Debt” of the Notes to Consolidated Financial Statements in Item 8 herein. Pursuant to Chapter 11, the filing of the Bankruptcy Petitions automatically stayed most actions against the Debtors, including actions to collect indebtedness incurred prior to the filing of the Bankruptcy Petitions or to exercise control over the Debtor’s property. Accordingly, although the Bankruptcy Petitions triggered defaults under the Outstanding Debt, creditors were generally stayed from taking action as a result of these defaults. These defaults were

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deemed waived or cured upon the Effective Date of the Plan. The Debtors also filed the Plan and a related solicitation and disclosure statement on June 7, 2016.

On July 14, 2016, the Bankruptcy Court entered the Confirmation Order. The Debtors satisfied the remaining conditions to effectiveness contemplated under the Plan and emerged from Chapter 11 on August 1, 2016.

The Plan contemplated that we continue our day-to-day operations substantially as previously conducted and that all of our commercial and operational contracts remained in effect in accordance with their terms preserving the rights of all parties. The significant elements of the Plan included:


•	payment in full of all trade creditors and other general unsecured creditors in the ordinary course of business;


•	the exchange of the full $650.0 million of the 2019 Notes into 96.75% of new common stock issued in the reorganization (the “New Common Stock”);


•	the exchange of the full $450.0 million of the 2022 Notes for 3.25% of the New Common Stock as well as

warrants exercisable for 15% of the New Common Stock at predetermined equity values;


•	the issuance to our existing common stockholders of two series of warrants exercisable for an aggregate of 20% of the New Common Stock at predetermined equity values;

•

the maintenance of our $400.0 million existing secured Term Loan while the lenders holding Term Loans (i) received (a) payment of an amount equal to 2% of the Term Loans; and (b) as further security for the Term Loans, second-priority liens and security interests in the collateral securing the company’s New ABL Credit Facility (as defined herein), which collateral, together with the existing collateral securing the Term Loans and Tranche A Incremental Term Loans, is governed by an inter-creditor agreement among the applicable secured parties; and (ii) continued to hold Term Loans under the Term Loan Credit Agreement, as amended to reflect, among other modifications, the reduction of the maturity date of the Term Loans by one year and an affirmative covenant by the Company to use commercially reasonably efforts to maintain credit ratings for the Term Loans; and


•	the payment of a consent fee equal to 2% of the Incremental Term Loan plus $15.0 million of the outstanding Incremental Term Loan balance, together with the maintenance of the remaining $84.0 million balance of the Incremental Term Loan on identical terms, except for the suspension of any prepayment premium for a period of 18 months.

The Plan effectuated, among other things, a substantial reduction in our debt, including $1.1 billion in the aggregate of the face amount of the 2019 Notes and 2022 Notes.

In accordance with the Plan, on the Effective Date, we issued an aggregate of 22,000,000 shares of New Common Stock to the holders of the 2019 and 2022 Notes.

In accordance with the Plan, on the Effective Date, we entered into a warrant agreement with Computershare Inc. and Computershare Trust Company, N.A., as the warrant agent, (the “Warrant Agreement”) and issued three series of warrants to holders of 2022 Notes and to our existing common stockholders as follows:


•	We issued Series A Warrants (“Series A Warrants”), which are exercisable until August 1, 2021, to purchase up to an aggregate of 3,882,353 shares of New Common Stock, at an exercise price of $23.82 per share, to holders of the 2022 Notes.


•	We issued Series B Warrants (“Series B Warrants”), which are exercisable until August 1, 2021, to purchase up to an aggregate of 2,875,817 shares of New Common Stock, at an exercise price of $69.08 per share, to our existing common stockholders.


•	We issued Series C Warrants (“Series C Warrants,” and, together with the Series A Warrants and Series B Warrants, the “Warrants”), which are exercisable until August 1, 2023, to purchase up to an aggregate of 3,195,352 shares of New Common Stock at an exercise price of $86.93 per share, to our existing common stockholders.

All unexercised Warrants will expire and the rights of the holders of such warrants (the “Warrant Holders”) to purchase shares of New Common Stock will terminate on the first to occur of (i) the close of business on their respective expiration dates or (ii) the date of completion of (A) any Affiliated Asset Sale (as defined in the Warrant Agreement), or (B) a Change of Control (as defined in the Warrant Agreement). Following the Effective Date, there were 3,882,353 Series A Warrants, 2,875,817 Series B Warrants and 3,195,352 Series C Warrants outstanding.

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surviving entity) (a “Non-Affiliate Combination”), holders of Warrants shall be solely entitled to receive the consideration per Warrant that is payable per share of common stock of the Company, less the applicable exercise price of the Warrant, paid in the same form and in the same proportion as is payable to holders of common stock. If the consideration is any form other than cash, the holders of the Warrants shall have ten business days prior to the consummation of the Non-Affiliate Combination to exercise their respective Warrants, and any Warrants not exercised will terminate.

In accordance with the Plan, on September 20, 2016, the Company adopted the Seventy Seven Energy Inc. 2016 Omnibus Incentive Plan (the “2016 Omnibus Incentive Plan”). For additional information, see Note 14 “Share-Based Compensation” of the Notes to Consolidated Financial Statements in Item 8 herein.

Successor Issuer

Pursuant to Rule 12g-3(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), the Series B Warrants and Series C Warrants were deemed to be registered under Section 12(b) of the Exchange Act, and the Company was deemed to be the successor registrant to the Company in its state before the Effective Date. Such registration expired on September 6, 2016, and we filed a Registration Statement on Form 8-A to effect the registration of the Series B Warrants and Series C Warrants under Section 12(g) of the Exchange Act. As a result, the Company remained subject to the reporting requirements of the Exchange Act following the Effective Date.

Trading of New Common Stock

The New Common Stock is not traded on a national securities exchange. However, since August 17, 2016, SSE’s common stock has traded on the OTC Market Group Inc.’s Grey market (the “OTC Grey”) under the symbol “SVNT.” See Item 5 of this report. The Company can provide no assurance that the New Common Stock will trade on a nationally recognized market or an over-the-counter market, whether broker-dealers will provide public quotes of the reorganized Company’s common stock on an over-the-counter market, whether the trading volume on an over-the-counter market of the Company’s common stock will be sufficient to provide for an efficient trading market, or whether quotes for the Company’s common stock may be blocked by the OTC Markets Group in the future.

Registration Rights Agreement

On the Effective Date, by operation of the Plan, the Company entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with certain funds affiliated with and/or managed by each of BlueMountain Capital Management, LLC, Axar Capital Management, LLC and Mudrick Capital Management, L.P. (each a “Registration Rights Holder,” and collectively, the “Registration Rights Holders”).

The Registration Rights Agreement provides certain demand registration rights to the Registration Rights Holders at any time following the six-month anniversary of the Effective Date. The Company will not be required to effect more than (i) four demand registrations delivered by each Registration Rights Holder, or (ii) one demand registration delivered by any holder in any 180-day period.

If, following the six-month anniversary of the Effective date, the Company qualifies for the use of Form S-3, the Registration Rights Holders may require the Company, subject to restrictions set forth in the Registration Rights Agreement, to file a shelf registration statement on Form S-3 covering the resale of such holder’s registrable securities.

In addition, if the Company proposes to register shares of its New Common Stock in certain circumstances, the Registration Rights Holders will have certain “piggyback” registration rights, subject to restrictions set forth in the Registration Rights Agreement, to include their shares of New Common Stock in the registration statement.

Senior Secured Debtor-In-Possession Credit Agreement; New ABL Credit Facility

On June 8, 2016, in connection with the filings of the Bankruptcy Petitions, the Company, with certain of our subsidiaries as borrowers, entered into a senior secured debtor-in-possession credit facility (the “DIP Facility”) with total commitments of $100.0 million. For additional discussion related to the DIP Facility, see Note 11 “Debt” of the Notes to Consolidated Financial Statements in Item 8 herein.

On the Effective Date, by operation of the Plan, the DIP Facility was amended and restated, and the outstanding obligations pursuant thereto were converted to obligations under a senior secured revolving credit facility in an aggregate principal amount of up to $100.0 million (the “New ABL Credit Facility”).

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New Directors

On the Effective Date, in accordance with the Plan and pursuant to the Stockholders Agreement that we entered into with certain stockholders on the Effective Date, Jerry Winchester and Edward J. DiPaolo, who were existing directors of the Company, and Andrew Axelrod, Victor Danh, Steven Hinchman, David King and Doug Wall became members of the Board until the first annual meeting of the Company’s stockholders to be held in 2017, and their respective successors are duly elected and qualified or until their earlier death, resignation or removal.

Conversion to Delaware Corporation

Effective July 22, 2016, in accordance with the Plan and with the laws of the State of Delaware and the State of Oklahoma, we converted our form of organization from an Oklahoma corporation (the “Oklahoma Predecessor Corporation”) to a Delaware limited liability company and, immediately thereafter, to a Delaware corporation (the “Delaware Successor Corporation”). As a result of the conversions, the equity holders of the Oklahoma Predecessor Corporation became the equity holders of the Delaware Successor Corporation. The name of the Company remained “Seventy Seven Energy Inc.”

For purposes of Delaware law, the Delaware Successor Corporation is deemed to be the same entity as the Company before the conversions, and its existence is deemed to have commenced on the date of original incorporation of the Company. Furthermore, under Delaware law, the rights, assets, operations, liabilities and obligations that comprised the going business of the Company before the conversions remain the rights, assets, operations, liabilities and obligations of the Company after the conversions.

The Spin-Off

The transactions in which SSE became an independent, publicly traded company, including the cash distribution to CHK referenced below, are referred to collectively as the “spin-off”. Prior to the spin-off, we conducted our business as COO. As part of the spin-off, we completed the following transactions, among others:


•	the entrance into our Pre-Petition Credit Facility and Term Loan. We used the proceeds from borrowings under these new facilities to repay in full and terminate our existing $500.0 million senior secured revolving credit facility (the “Old Credit Facility”);


•	the issuance of our 2022 Notes. We used the net proceeds of approximately $493.8 million to make a cash distribution of approximately $391.0 million to CHK, to repay a portion of outstanding indebtedness under the Pre-Petition Credit Facility, and for general corporate purposes.


•	we distributed our compression unit manufacturing and geosteering businesses to CHK. Please read “Results of Operations” in Item 7 of this report for further discussion of the financial impact of these businesses to our historical financial results.


•	we sold our crude hauling assets to a third party and used a portion of the net proceeds received to make a $30.9 million cash distribution to CHK.

•

CHK transferred to us buildings and real estate used in our business, including property and equipment, at cost of approximately $212.5 million and accumulated depreciation of $22.2 million as of the spin-off date. Prior to the spin-off, we leased these buildings and real estate from CHK pursuant to a facilities lease agreement and incurred lease expense of $8.2 million for the year ended December 31, 2014. In connection with the spin-off, the facilities lease agreement was terminated.


•	COO transferred all of its existing assets, operations and liabilities, including our 2019 Notes, to SSO. SSO is an Oklahoma limited liability company, our direct wholly-owned subsidiary and the direct owner of all our operating subsidiaries.


•	COO was renamed SSE and converted from a limited liability company to a corporation.

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Agreements Between Us and CHK

In connection with the spin-off, we supplemented the Master Services Agreement with the new agreements described below.

New Services Agreements

Under the new services agreement governing our provision of hydraulic fracturing services for CHK (the “New Services Agreement”), CHK is required to utilize the lesser of (i) seven, five and three of our hydraulic fracturing crews in years one, two and three of the agreement, respectively, or (ii) fifty percent (50%) of the total number of all hydraulic fracturing crews working for CHK in all its operating regions during the respective year. CHK is also required to utilize our hydraulic fracturing services for a minimum number of stages as set forth in the agreement. CHK is entitled to terminate the agreement in certain situations, including in the event we fail to materially comply with the overall quality of service provided by similar service providers. Additionally, CHK’s requirement to utilize our services may be suspended under certain circumstances, such as when we are unable to timely accept and supply services ordered by CHK or as a result of a force majeure event. Our hydraulic fracturing backlog under the New Services Agreement as of December 31, 2016 was approximately $44.9 million.

In connection with the spin-off, we entered into rig-specific daywork drilling contracts with CHK for the provision of drilling services having terms similar to those we currently use for other customers (the “Drilling Contracts”). The Drilling Contracts had a commencement date of July 1, 2014 and terms ranging from three months to three years. CHK has the right to terminate a drilling contract in certain circumstances. Our drilling backlog under the Drilling Contracts as of December 31, 2016 was approximately $142.5 million and our early contract termination value related to the Drilling Contracts was $79.9 million. For additional information about our contractual backlog please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Backlog” in Item 7 of this report.

Master Separation Agreement

The master separation agreement entered into between us and CHK governs the separation of our businesses from CHK, the distribution of our shares to CHK shareholders and other matters related to CHK’s relationship with us, including cross-indemnities between us and CHK. In general, CHK agreed to indemnify us for any liabilities relating the CHK’s business and we agreed to indemnify CHK for any liabilities relating to our business.

Tax Sharing Agreement

In connection with the spin-off, we and CHK entered into a tax sharing agreement that governs our respective rights, responsibilities and obligations with respect to tax liabilities and benefits, tax attributes, the preparation and filing of tax returns, the control of audits and other tax proceedings and certain other matters regarding taxes. References in this summary description of the tax sharing agreement to the terms “tax” or “taxes” mean taxes as well as any interest, penalties, additions to tax or additional amounts in respect of such taxes.

Under the tax sharing agreement, we generally are liable for and will indemnify CHK against all taxes attributable to our business and will be allocated all tax benefits attributable to such business. CHK generally is liable for and will indemnify us against all taxes attributable to its other businesses and will be allocated all tax benefits attributable to such businesses.

Finally, the tax sharing agreement will require that neither we nor any of our affiliates take or fail to take any action after the effective date of the tax sharing agreement that (i) would be reasonably likely to be inconsistent with or cause to be untrue any material statement, covenant or representation in any representation letters, tax opinions or Internal Revenue Service (“IRS”) private letter ruling obtained by CHK or (ii) would be inconsistent with the spin-off generally qualifying as a tax-free transaction described under Sections 355 and 368(a)(1)(D) of the Code.

Moreover, CHK generally will be liable for and indemnify us for any taxes arising from the spin-off or certain related transactions that are imposed on us, CHK or its other subsidiaries. However, we would be liable for and indemnify CHK for any such taxes to the extent they result from certain actions or failures to act by us that occur after the effective date of the tax sharing agreement.

Employee Matters Agreement

In connection with the spin-off, we and CHK entered into an employee matters agreement, which provides that each of CHK and SSE has responsibility for its own employees and compensation plans. The agreement also contains provisions

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concerning benefit protection for both SSE and CHK employees, treatment of holders of CHK stock options, restricted stock, restricted stock units and performance share units, and cooperation between us and CHK in the sharing of employee information and maintenance of confidentiality.

Transition Services Agreement

Prior to the spin-off, we had an administrative services agreement (the “Administrative Services Agreement”) with CHK pursuant to which CHK allocated certain expenses to us. Under the Administrative Services Agreement, in return for the general and administrative services provided by CHK, we reimbursed CHK on a monthly basis for the overhead expenses incurred by CHK on our behalf in accordance with its allocation policy, which included actual out-of-pocket fees, costs and expenses incurred in connection with the provision of any of the services under the agreement, including the wages and benefits of CHK employees who performed services on our behalf. In connection with the spin-off, we terminated the Administrative Services Agreement and entered into a transition services agreement (the “Transition Services Agreement”). These charges from CHK were $8.3 million and $18.0 million for the years ended December 31, 2015 and 2014, respectively, and we terminated the Transition Services Agreement during the second quarter of 2015.



Item 1A.	Risk Factors

Risks Relating to Our Industry and Our Business

We are dependent on CHK for a majority of our revenues. Therefore, we are indirectly subject to the business and financial risks of CHK. We have no control over CHK’s business decisions and operations, and CHK is under no obligation to adopt a business strategy that is favorable to us.

We currently provide a significant percentage of our oilfield services and equipment to CHK and its working interest partners. For the 2016 Successor Period, the 2016 Predecessor Period and the years ended December 31, 2015 and 2014, CHK and its working interest partners accounted for approximately 51%, 65%, 70% and 81% of our total revenues, respectively. If CHK ceases to engage us on terms that are attractive to us during any period, our business, financial condition and results of operations would be materially adversely affected during such period. Accordingly, we are indirectly subject to the business and financial risks of CHK, some of which are the following:


•	the volatility of oil and natural gas prices, which could have a negative effect on the value of CHK’s oil and natural gas properties, its drilling program, its ability to finance its operations and its willingness to allocate capital toward exploration and development activities;


•	the availability of capital on favorable terms to fund its exploration and development activities;


•	its discovery rate of new oil and natural gas reserves and the speed at which it develops such reserves;


•	uncertainties inherent in estimating quantities of natural gas and oil reserves and projecting future rates of production;


•	its drilling and operating risks, including potential environmental liabilities;


•	pipeline, storage and other transportation capacity constraints and interruptions;


•	adverse effects of governmental and environmental regulation; and


•	losses from pending or future litigation.

In particular, CHK has generally made capital expenditures in excess of its operating cash flows. To fund these expenditures, CHK obtained capital from its revolving credit facility, the debt capital markets, oil and natural gas asset sales and other sources. If CHK is unable to generate cash flow from operations sufficient to fund its capital expenditures, CHK may be required to reduce its drilling and completion activities, which could have a material adverse impact on our business, financial condition and results of operations.

We serve customers who are involved in drilling for and producing oil and natural gas. Adverse developments affecting the oil and natural gas industry or drilling and completions activity, including sustained low oil, natural gas, or natural gas liquids prices, reduced demand for oil and natural gas products and increased regulation of drilling and production, could have a material adverse effect on our business, financial condition and results of operations.

Our revenues are generated from customers who are engaged in drilling for and producing oil and natural gas. Developments that adversely affect oil and natural gas drilling and production services could adversely affect our customers’ demand for our products and services, resulting in a material adverse effect on our business, financial condition and results of operations.

The predominant factor that would reduce demand for our products and services is reduced land-based drilling and completions activity in the continental United States. Commodity prices, and market expectations of potential changes in these prices, may significantly affect this level of activity, as well as the rates paid for our services. Oil and natural gas prices are volatile and have fluctuated dramatically in recent years. We negotiate the rates payable under our contracts based on prevailing market prices for the services we provide. Declines in the prices of oil, natural gas, or natural gas liquids have had an adverse impact on the level of drilling, exploration and production activity since the end of the fourth quarter of 2014, and sustained low levels of drilling, exploration and production activity or further declines could materially and adversely affect the demand for our products and services and our results of operations. However, higher commodity prices do not necessarily translate into increased drilling and completions activity because our customers’ expectations of future prices also influences their activity. Additionally, we have incurred costs and had downtime in the past as we redeployed equipment and personnel from one unconventional resource play to another to meet our customers’ needs, and in the future we may incur redeployment costs and have downtime any time our customers’ activities are refocused towards different drilling regions.

Another factor that would reduce demand for our products and services is a decline in the level of drilling and production activity as a result of increased government regulation of that activity. Our customers’ drilling and production operations are subject to extensive federal, state, local and foreign laws and government regulations concerning emissions of pollutants and greenhouse gases; hydraulic fracturing; the handling of oil and natural gas and byproducts thereof and other materials and substances used in connection with oil and natural gas operations, including drilling fluids and wastewater; well siting and spacing; production limitations; plugging and abandonment of wells; unitization and pooling of properties; and taxation. More stringent legislation or regulation, a moratorium on drilling or hydraulic fracturing, or increased taxation of oil and natural gas drilling and completions activity could directly curtail such activity or increase the cost of drilling, resulting in reduced levels of drilling and completions activity and therefore reduced demand for our products and services.

Demand for services in our industry is cyclical and depends on drilling and completion spending by CHK and other E&P companies in the U.S., and the level of such activity is cyclical.

Demand for services in our industry is cyclical, and we depend on CHK’s and our other customers’ willingness to make capital and operating expenditures to explore for, develop and produce oil and natural gas in the U.S. Our customers’ willingness to undertake these activities depends largely upon prevailing industry conditions that are influenced by numerous factors over which we have no control, including:


•	prices, and expectations about future prices, of oil and natural gas;


•	domestic and foreign supply of and demand for oil and natural gas;


•	the availability, pricing and perceived safety of pipeline, trucking, train storage and other transportation capacity;


•	lead times associated with acquiring equipment and availability of qualified personnel;


•	the expected rates of decline in production from existing and prospective wells;


•	the discovery rates of new oil and natural gas reserves;


•	laws and regulations relating to environmental matters;


•	federal, state and local regulation of hydraulic fracturing and other oilfield activities, including public pressure on governmental bodies and regulatory agencies to regulate our industry;


•	adverse weather conditions, including hurricanes that can affect oil and natural gas operations over a wide area;


•	oil refining capacity;


•	merger and divestiture activity among oil and gas producers;


•	tax laws, regulation and policies;


•	the availability of water resources and suitable proppants in sufficient quantities and on acceptable terms for use in hydraulic fracturing operations;


•	the availability, capacity and cost of disposal and recycling services for used hydraulic fracturing fluids;


•	the political environment in oil and natural gas producing regions, including uncertainty or instability resulting from civil disorder, terrorism or war;


•	advances in exploration, development and production technologies or in technologies affecting energy consumption;


•	the price and availability of alternative fuels and energy sources;


•	uncertainty in capital and commodities markets; and


•	the ability of oil and natural gas producers to raise capital on favorable terms.

Anticipated future prices for crude oil and natural gas are a primary factor affecting spending and drilling and completions activity by E&P companies, including CHK. Actual or anticipated lower prices or volatility in prices for oil and natural gas typically decrease spending and drilling and completions activity, which can cause rapid and material declines in demand for our services and in the prices we are able to charge for our services. Worldwide political, economic and military events as well as natural disasters and other factors beyond our control contribute to oil and natural gas price levels and volatility and are likely to continue to do so in the future.

We negotiate the rates payable under our contracts based on prevailing market prices, and, consequently, the prices we are able to charge will fluctuate with market conditions. A material decline in oil and natural gas prices or drilling and completions activity levels or sustained lower prices or activity levels could have a material adverse effect on our business, financial condition, results of operations and cash flows. For example, beginning at the end of the fourth quarter of 2014 and continuing throughout the majority of 2015 and 2016, we have experienced reductions in both the demand for our services and the prices we are able to charge as the sharp decline in oil prices has led our customers to reduce spending and cut costs. Industry activity is beginning to increase as the U.S. domestic rig count was 589 during the fourth quarter of 2016, which, while down 22% compared to the fourth quarter of 2015, was up 22% compared to the third quarter of 2016. Additionally, the average price of oil during the fourth quarter of 2016 was $49.25 per barrel, which represented a 17% increase compared to the fourth quarter of 2015 and a 10% increase compared to the third quarter of 2016. These average oil prices remain well below the average prices in 2014. The average price of natural gas during the fourth quarter of 2016 was $3.04 per McF, an increase of 47% compared to the fourth quarter of 2015 and a 6% increase compared to the third quarter of 2016. Future price declines or prolonged levels of low prices would further negatively affect the demand for our services and the prices we are able to charge to our customers. Additionally, we may incur costs and have downtime during periods when our customers’ activities are refocused towards different drilling regions.

Spending by E&P companies can also be impacted by conditions in the capital markets. Limitations on the availability of capital, or higher costs of capital, for financing expenditures may cause CHK and other E&P companies to make additional reductions to capital budgets in the future, even if oil or natural gas prices increase from current levels. Any such cuts in spending will curtail drilling and completion programs as well as discretionary spending on wellsite services, which may result in a reduction in the demand for our services, the rates we can charge, and the utilization of our services. Moreover, reduced discovery rates of new oil and natural gas reserves, or a decrease in the development rate of reserves in our market areas, whether due to increased governmental or environmental regulation, limitations on exploration and drilling and completions activity or other factors, could also have an impact on our business, even in a stronger oil and natural gas price environment. An adverse development in any of these areas could have an adverse impact on our customers’ operations or financial condition, which could in turn result in reduced demand for our products and services.

Our current backlog of contract drilling and hydraulic fracturing revenue may not be fully realized.

As of December 31, 2016, the contract backlog associated with our drilling and hydraulic fracturing services was approximately $253.0 million, of which approximately 74% was with CHK. We calculate our drilling backlog by adding together (i) the day rate under our active rig contracts multiplied by the number of days remaining under the contracts and (ii) the implied daily margin rate on our IBC rigs multiplied by the number of days remaining on those contracts. We calculate our hydraulic fracturing backlog by multiplying the (i) rate per stage, which varies by operating region and is, therefore, estimated based on current customer activity levels by region and current contract pricing, by (ii) the number of stages remaining under the contract, which we estimate based on current and anticipated utilization of our crews. With respect to our hydraulic fracturing backlog, our contracts provide for periodic adjustments of the rates we may charge for our services, which will be negotiated based on then-prevailing market pricing and in the future may be higher or lower than the current rates we charge and utilize in calculating our backlog. Our drilling backlog calculation does not include any reduction in revenues related to mobilization or demobilization, nor does it include potential reductions in rates for unscheduled standby or during periods in which the rig is moving, on standby or incurring maintenance and repair time in excess of what is permitted under the drilling contract. The contractual rate may be higher than the actual rate we receive because of a number of factors, including downtime or suspension of operations. Several factors could cause downtime or a suspension of operations, many of which are beyond our control, including:


•	breakdowns of equipment;


•	work stoppages, including labor strikes;


•	shortages or material and skilled labor;


•	severe weather or harsh operating conditions; and


•	force majeure events.

In addition, many of our drilling contracts are subject to termination by the customer on short notice and provide for an early termination payment to us in the event that the contract is terminated by the customer. We calculate our contract drilling early termination value assuming each rig remains stacked for the remainder of the term of the terminated contract. As a result of the foregoing, revenues could differ materially from the backlog and early termination amounts presented. Moreover, we can provide no assurance that our customers will be able or willing to fulfill their contractual commitments to us. Liquidity issues could lead our customers to go into bankruptcy or could encourage our customers to seek to repudiate, cancel or renegotiate our contracts for various reasons. Many of our contracts permit early termination of the contracts by the customer for convenience (without cause), generally exercisable upon advance notice to us and in some cases without making an early termination payment to us. Our inability to realize the full amount of our contract backlog amounts and early termination amounts may have a material adverse effect on our business, financial position and results of operations.

We recently emerged from bankruptcy, which could adversely affect our business and relationships.

It is possible that our having filed for bankruptcy and our recent emergence from the Chapter 11 bankruptcy proceedings could adversely affect our business and relationships with customers, employees and suppliers. Due to uncertainties, many risks exist, including the following:


•	key suppliers could terminate their relationship or require financial assurances or enhanced performance;


•	the ability to renew existing contracts and compete for new business may be adversely affected;


•	the ability to attract, motivate and/or retain key executives and employees may be adversely affected;


•	employees may be distracted from performance of their duties or more easily attracted to other employment opportunities; and


•	competitors may take business away from us, and our ability to attract and retain customers may be negatively impacted.

The occurrence of one or more of these events could have a material and adverse effect on our operations, financial condition and reputation. We cannot assure you that having been subject to bankruptcy protection will not adversely affect our operations in the future.

Our actual financial results after emergence from bankruptcy may not be comparable to our historical financial information as a result of the implementation of the plan of reorganization, the transactions contemplated thereby and our adoption of fresh-start accounting.

In connection with the disclosure statement we filed with the bankruptcy court, and the hearing to consider confirmation of the plan of reorganization, we prepared projected financial information to demonstrate to the bankruptcy court the feasibility of the plan of reorganization and our ability to continue operations upon our emergence from bankruptcy. Those projections were prepared solely for the purpose of the bankruptcy proceedings and have not been, and will not be, updated on an ongoing basis and should not be relied upon by investors. At the time they were prepared, the projections reflected numerous assumptions concerning our anticipated future performance, with respect to prevailing and anticipated market and economic conditions that were and remain beyond our control and may not materialize. Projections are inherently subject to substantial and numerous uncertainties and to a wide variety of significant business, economic and competitive risks, and the assumptions underlying the projections and/or valuation estimates may prove to be wrong in material respects. Actual results will likely vary significantly from those contemplated by the projections. As a result, investors should not rely on these projections.

In addition, upon our emergence from bankruptcy, we adopted fresh-start accounting. Accordingly, our financial conditions and results of operations following our emergence from bankruptcy are not comparable to the financial condition or results of operations reflected in our historical financial statement. Our financial results for future periods following the application of fresh-start accounting will be different from historical trends and such differences may be material.

There is a limited trading market for our securities and the market price of our securities is subject to volatility.

Upon our emergence from bankruptcy, our old common stock was cancelled and we issued New Common Stock. Our New Common Stock is not listed on any national or regional securities exchange or quoted on any over-the-counter market. Our New Common Stock is eligible to trade in the OTC Grey market. OTC Grey market securities do not have bid or ask quotations in the OTC Link system or the OTC Bulletin Board (“OTCBB”). Broker-dealers must report OTC Grey market trades to the Financial Industry Regulatory Authority (“FINRA”), therefore trade data is available on http://www.otcmarkets.com and other public sources. Generally, trading in the OTC Grey market is much more limited than trading on any national securities exchange. The market price of our common stock could be subject to wide fluctuations in response to, and the level of trading that develops with our common stock may be affected by, numerous factors, many of which are beyond our control. These factors include, among other things, our new capital structure as a result of the transactions contemplated by the plan of reorganization, our limited trading history subsequent to our emergence from bankruptcy, our limited trading volume, the concentration of holdings of our common stock, the lack of comparable historical financial information due to our adoption of fresh-start accounting, actual or anticipated variations in our operating results and cash flow, the nature and content of our earnings releases, announcements or events that impact our products, customers, competitors or markets, business conditions in our markets and the general state of the securities markets and the market for energy-related stocks, as well as general economic and market conditions and other factors that may affect our future results, including those other risk factors described in this section. No assurance can be given that an active market will develop for the common stock or as to the liquidity of the trading market for the common stock. The common stock may be traded only infrequently in transactions arranged through brokers or otherwise, and reliable market quotations may not be available. Holders of our common stock may experience difficulty in reselling, or an inability to sell, their shares. In addition, if an active trading market does not develop or is not maintained, significant sales of our common stock, or the expectation of these sales, could materially and adversely affect the market price of our common stock. No assurances can be given regarding the Company’s ability to be quoted on one of the over-the-counter markets or a national exchange in a timely manner or at all.

Our industry is highly competitive. If we are unable to compete successfully, our profitability may be reduced.

The market for oilfield services in which we operate is highly competitive. Price competition, rig or fleet availability, location and suitability, experience of the workforce, safety records, financial strength, reputation, operating integrity and condition of the equipment are all factors used by customers in awarding contracts. Our future success and profitability will partly depend upon our ability to keep pace with our customers’ demands with respect to these factors. Our competitors are numerous, ranging from global diversified services companies to other independent marketers and distributors of varying sizes, financial resources and experience. Some of our competitors may have greater financial, technical and personnel resources than us. Contracts are traditionally awarded on the basis of competitive bids or direct negotiations with customers. The competitive

environment could intensify if there is consolidation among E&P companies because such consolidation would reduce the number of available customers. The fact that drilling rigs and other oilfield services equipment are mobile and can be moved from one market to another in response to market conditions heightens the competition in the industry. In addition, any increase in the supply of land drilling rigs and hydraulic fracturing fleets could have a material adverse impact on market prices under our contracts and utilization rates of our services. This increased supply could also require higher capital investment to keep our services competitive.

Our business involves many hazards and operational risks, and we are not insured against all the risks we face.

Our operations are subject to many hazards and risks, including the following:


•	accidents resulting in serious bodily injury and the loss of life or property;


•	liabilities from accidents or damage by our fleet of trucks, rigs and other equipment;


•	pollution and other damage to the environment;


•	exposure to toxic gases or other hazardous substances;


•	well blow-outs, the uncontrolled flow of oil, natural gas or other well fluids into or through the environment, including onto the ground or into the atmosphere, surface waters or an underground formation;


•	fires and explosions;


•	mechanical or technological failures;


•	spillage handling and disposing of materials;


•	adverse weather conditions; and


•	failure of our employees to comply with our internal environmental health and safety guidelines.

If any of these hazards occur, they could result in suspension of operations, termination of contracts without compensation, damage to or destruction of our equipment and the property of others, or injury or death to our personnel or third parties and could expose us to substantial liability or losses. The frequency and severity of such incidents will affect operating costs, insurability and relationships with customers, employees and regulators. In addition, these risks may be greater for us upon the acquisition of another company that has not allocated significant resources and management focus to safety and has a poor safety record.

We are not fully insured against all risks inherent in our business. For example, we do not have any business interruption/loss of income insurance that would provide coverage in the event of damage to any of our equipment or facilities. Although we are insured for environmental pollution resulting from environmental accidents that occur on a sudden and accidental basis, we may not be insured against all environmental accidents that might occur, some of which may result in toxic tort claims. If a significant accident or event occurs for which we are not adequately insured, it could adversely affect our business, financial condition and results of operations. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Please read “Business—Risk Management and Insurance” in Item 1 of this report.

Our business may be adversely affected by a deterioration in general economic conditions or the further weakening of the broader energy industry.

A prolonged economic slowdown, another recession in the United States, adverse events relating to the energy industry and local, regional and national economic conditions and factors, particularly a worsening of the continuing downturn in the E&P sector, could negatively impact our operations and therefore adversely affect our results. The risks associated with our business are more acute during periods of economic slowdown or recession because such periods may be accompanied by decreased spending by our customers.

Restrictions in the agreements governing our outstanding indebtedness could adversely affect our business, financial condition and results of operations.

The operating and financial restrictions in our credit facility and term loans and any future financing agreements could restrict our ability to finance future operations or capital needs, or otherwise pursue our business activities. For example, our credit facility limits our and our subsidiaries’ ability to, among other things:


•	incur additional debt or issue guarantees;


•	incur or permit certain liens to exist;


•	make certain investments, acquisitions or other restricted payments;


•	dispose of assets;


•	engage in certain types of transactions with affiliates;


•	merge, consolidate or transfer all or substantially all of our assets; and


•	prepay certain indebtedness.

Furthermore, our credit facility contains a covenant requiring us to maintain a fixed charge coverage ratio of 1.0 to 1.0 based on the ratio of consolidated EBITDA to fixed charges when availability under the facility is less than 12.5%.

A failure to comply with the covenants in the agreements governing our indebtedness could result in an event of default, which, if not cured or waived, would permit the exercise of remedies against us that would be likely to have a material adverse effect on our business, financial condition and results of operations. Remedies under our credit facility and term loan include foreclosure on the collateral securing the indebtedness, which includes operating assets and accounts receivable. Moreover, the existence of these covenants may also prevent or delay us from pursuing business opportunities that we believe would otherwise benefit us.

Our assets may require significant amounts of capital for maintenance, upgrades and refurbishment.

Our drilling rigs and hydraulic fracturing fleets may require significant capital investment in maintenance, upgrades and refurbishment to maintain the competitiveness of our assets. Our rigs and fleets typically do not generate revenue while they are undergoing maintenance, refurbishment or upgrades. Any maintenance, upgrade or refurbishment project for our assets could increase our indebtedness or reduce cash available for other opportunities. Further, such projects may require proportionally greater capital investments as a percentage of total asset value, which may make such projects difficult to finance on acceptable terms. To the extent we are unable to fund such projects, we may have fewer rigs and fleets available for service or our rigs and fleets may not be attractive to potential or current customers. Such demands on our capital or reductions in demand for our rigs and fleets could have a material adverse effect on our business, financial condition and results of operations.

We participate in a capital intensive industry and we may not be able to finance our capital needs.

We intend to rely primarily on cash on hand, cash flows from operating activities and borrowings under our credit facility to fund our future capital expenditures. If our cash on hand, cash flows from operating activities and borrowings under our credit facility are not sufficient to fund our capital expenditures, we would be required to fund these expenditures through the issuance of debt or equity or alternative financing plans, such as:


•	refinancing or restructuring our debt;


•	selling assets; or


•	reducing or delaying acquisitions or capital investments, such as planned upgrades or acquisitions of equipment and refurbishments of our rigs and related equipment, even if previously publicly announced.

The terms of existing or future debt instruments and the terms of the Merger Agreement may restrict us from adopting some of these alternatives. If debt and equity capital or alternative financing plans are not available on favorable terms or at all,

we would be required to curtail our capital spending, and our ability to sustain or improve our profits may be adversely affected. Our ability to refinance or restructure our debt will depend on the condition of the capital markets and our financial condition at such time, among other things. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations.

Shortages or increases in the costs of the equipment we use in our operations could adversely affect our operations in the future.

We generally do not have long-term contracts in place that provide for the delivery of equipment, including, but not limited to, drill pipe, replacement parts and other equipment. We could experience delays in the delivery of the equipment that we have ordered and its placement into service due to factors that are beyond our control. New federal regulations regarding diesel engines, demand by other oilfield services companies and numerous other factors beyond our control could adversely affect our ability to procure equipment that we have not yet ordered or cause the prices of such equipment to increase. Price increases, delays in delivery and interruptions in supply may require us to increase capital and repair expenditures and incur higher operating costs. In certain instances, we may have the ability to cancel purchases of equipment that may no longer be needed. Each of these could have a material adverse effect on our business, financial condition and results of operations.

We are dependent on a small number of suppliers for key raw materials and finished products.

We do not have long-term contracts with third party suppliers for many of the raw materials and finished products that we use in large volumes in our operations, including, in the case of our hydraulic fracturing operations, proppants, acid, gels, including guar gum, chemicals and water, and fuels used in our equipment and vehicles. Especially during periods in which oilfield services are in high demand, the availability of raw materials and finished products used in our industry decreases and the price of such raw materials and finished products increases. We are dependent on a small number of suppliers for key raw materials and finished products. Our reliance on such suppliers could increase the difficulty of obtaining such raw materials and finished products in the event of shortage in our industry or cause us to pay higher prices to obtain such raw materials and finished products. Price increases, delays in delivery and interruptions in supply may require us to incur higher operating costs. Each of these could have a material adverse effect on our business, financial condition and results of operations.

The loss of key executives could adversely affect our ability to effectively operate and manage our business.

We are dependent upon the efforts and skills of our executives to operate and manage our business. We cannot assure you that we will be able to retain these employees, and the loss of the services of one or more of our key executives could increase our exposure to the other risks described in this “Risk Factors” section. We do not maintain key man insurance on any of our personnel.

We may record losses or impairment charges related to idle assets or assets that we sell.

Prolonged periods of low utilization, changes in technology or the sale of assets below their carrying value may cause us to experience losses. These events could result in the recognition of impairment charges that reduce our net income. Please read Note 9 “Asset Sales and Impairments and Other” of the Notes to Consolidated Financial Statements in Item 8 herein for more information, including a summary of impairment charges we have recognized previously. Significant impairment charges as a result of adverse market conditions or otherwise could have a material adverse effect on our financial condition.

The unavailability of skilled workers could hurt our operations.

We are dependent upon the available pool of skilled employees to conduct our business safely, reliably and efficiently. We compete with other oilfield services businesses and other employers to attract and retain qualified personnel with the technical skills and experience required to provide the highest quality service. Historically, our industry has experienced high employee turnover rates as a result of both the physically demanding nature of the work and the volatile and cyclical nature of the oilfield services industry. For example, there have been significant reductions in employee headcount throughout the oilfield services industry due to low oil and natural gas prices since mid-2014. Particularly if the current downturn is prolonged, many of these workers may retire or pursue employment opportunities in other industries, many of which may offer a more desirable work environment at wage rates that are competitive with ours. We cannot assure you that we will be able to recruit, train and retain an adequate number of workers to replace departing workers or that might be needed to take advantage of opportunities once the current business environment begins to improve. The inability to maintain an adequate workforce could have a material adverse effect on our business, financial condition, cash flows and results of operations.

During periods of high drilling and completions activities levels, the demand for skilled workers is high and the supply is limited, and a shortage in the labor pool of skilled workers or other general inflationary pressures or changes in applicable laws and regulations have in the past, and could in the future, make it more difficult for us to attract and retain personnel and require us to enhance our wage and benefits packages thereby increasing our operating costs.

Although our employees are not covered by a collective bargaining agreement, union organizational efforts could occur and, if successful, could increase our labor costs. A significant increase in the wages paid by competing employers or the unionization of groups of our employees could result in increases in the wage rates that we must pay. Likewise, laws and regulations to which we are subject, such as the Fair Labor Standards Act, which governs such matters as minimum wage, overtime and other working conditions, can increase our labor costs or subject us to liabilities to our employees. We cannot assure you that labor costs will not increase. Increases in our labor costs or unavailability of skilled workers could impair our capacity and diminish our profitability, having a material adverse effect on our business, financial condition and results of operations.

Our inability to obtain or implement new technology may cause us to become less competitive.

The oilfield services industry is subject to the introduction of new drilling and completion techniques and services using new technologies, some of which may be subject to patent protection or costly to obtain. As competitors and others use or develop new technologies in the future, we may be placed at a competitive disadvantage. Furthermore, we may face competitive pressure to implement or acquire certain new technologies at a substantial cost. Some of our competitors have greater financial, technical and personnel resources that may allow them to enjoy technological advantages and implement new technologies before we can. We cannot be certain that we will be able to implement new technologies or products on a timely basis or at an acceptable cost. Thus, limits on our ability to effectively use and implement new and emerging technologies may have a material adverse effect on our business, financial condition and results of operations.

Oilfield anti-indemnity provisions enacted by many states may restrict or prohibit a party’s indemnification of us.

We typically enter into agreements with our customers governing the provision of our services, which usually include certain indemnification provisions for losses resulting from operations. Such agreements may require each party to indemnify the other against certain claims regardless of the negligence or other fault of the indemnified party; however, many states place limitations on contractual indemnity agreements, particularly agreements that indemnify a party against the consequences of its own negligence. Furthermore, certain states, including Louisiana, New Mexico, Texas and Wyoming, have enacted statutes generally referred to as “oilfield anti-indemnity acts” expressly prohibiting certain indemnity agreements contained in or related to oilfield services agreements. Such oilfield anti-indemnity acts may restrict or void a party’s indemnification of us, which could have a material adverse effect on our business, financial condition and results of operations.

Delays in obtaining permits by our customers for their operations could impair our business.

Our customers are required to obtain permits from one or more governmental agencies in order to perform drilling and/or completion activities. Such permits are typically required by state agencies but can also be required by federal and local governmental agencies. The requirements for such permits vary depending on the location where such drilling and completion activities will be conducted. As with all governmental permitting processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit to be issued and the conditions which may be imposed in connection with the granting of the permit. Certain regulatory authorities have delayed or suspended the issuance of permits while the potential environmental impacts associated with issuing such permits can be studied and appropriate mitigation measures evaluated. Permitting delays, an inability to obtain new permits or revocation of our or our customers’ current permits could cause a loss of revenue and could materially and adversely affect our business, financial condition and results of operations.

We and our customers are subject to federal, state and local laws and regulations regarding issues of health, safety, climate change and protection of the environment. Under these laws and regulations, we may become liable for penalties, damages or costs of remediation or other corrective measures. Any changes in laws or government regulations could increase our costs of doing business.

Our and our customers’ operations are subject to stringent federal, state and local laws and regulations relating to, among other things, protection of natural resources, wetlands, endangered species, the environment, health and safety, waste management, waste disposal and transportation of waste and other materials. Our operations pose risks of environmental liability, including leakage or spills from our operations to surface or subsurface soils, surface water or groundwater. Environmental laws and regulations often impose strict liability and may impose joint and several liability. Therefore, in some

situations, we could be exposed to liability as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, third parties without regard to whether we caused or contributed to the conditions. Actions arising under these laws and regulations could result in the shutdown of our operations, fines and penalties, expenditures for remediation or other corrective measures, and claims for liability for property damage, exposure to hazardous materials, exposure to hazardous waste or personal injuries. Sanctions for noncompliance with applicable environmental laws and regulations also may include the assessment of administrative, civil or criminal penalties, revocation of permits, temporary or permanent cessation of operations in a particular location, and issuance of corrective action orders. Such claims or sanctions and related costs could cause us to incur substantial costs or losses and could have a material adverse effect on our business, financial condition and results of operations. Additionally, an increase in regulatory requirements on oil and natural gas exploration and completion activities could significantly delay or interrupt our operations.

For instance, in May 2016, the EPA issued final new source performance standards governing methane emissions, imposing more stringent controls on methane and volatile organic compounds emissions at new and modified oil and natural gas production, processing, storage, and transmission facilities. The EPA has also announced that it intends to impose methane emission standards for existing sources and has issued information collection requests to companies with production, gathering and boosting, gas processing, storage, and transmission facilities. In November 2016, the Department of the Interior issued final rules relating to the venting, flaring and leaking of natural gas by oil and natural gas producers who operate on federal and Indian lands. The rules limit routine flaring of natural gas, require the payment of royalties on avoidable gas losses and require plans or programs relating to gas capture and leak detection and repair. In addition, several states are pursuing similar measures to regulate emissions of methane from new and existing sources within the oil and natural gas source category. As a result of this continued regulatory focus, future federal and state regulations of the oil and natural gas industry remain a possibility and could result in increased compliance costs on our operations.

Changes in Federal and/or State Motor Carrier regulations may increase our costs and negatively impact our results of operations.

For several facets of our operations, we operate trucks and other heavy equipment that are required to comply with Federal and/or State Motor Carrier regulations. The U.S. Department of Transportation and various state agencies exercise broad powers over our motor carrier operations, generally governing such matters as the authorization to engage in various activities, safety, equipment testing and specifications and insurance requirements. The trucking industry is subject to possible regulatory and legislative changes that may impact our operations, such as changes in fuel emissions limits, the hours of service regulations that govern the amount of time a driver may drive or work in any specific period, limits on vehicle weight and size and other matters. In 2011, the National Highway Traffic Safety Administration (“NHTSA”) and the EPA published regulations governing fuel efficiency and GHG emissions from medium- and heavy-duty trucks, beginning with vehicles built for model year 2014. In October 2016, those agencies finalized a second phase of fuel efficiency and GHG standards for medium-and heavy-duty trucks as well as trailers used in combination with tractors. The EPA also regulates air emissions from certain off-road diesel engines that are used by us to power equipment in the field. Under these Tier IV regulations, we are required to retrofit or retire certain engines, and we are limited in the number of non-compliant off-road diesel engines we can purchase. Tier IV engines are costlier and are not always available. Until Tier IV-compliant engines that meet our needs are available, these regulations could limit our ability to acquire a sufficient number of engines to expand our fleet and to replace existing engines as they are taken out of service. As a result of these regulations, we may experience an increase in costs related to truck purchases and maintenance, an impairment of equipment productivity, a decrease in the residual value of these vehicles and an increase in operating expenses. Proposals to increase federal, state or local taxes, including taxes on motor fuels, are also made from time to time, and any such increase would increase our operating costs. We cannot predict whether, or in what form, any legislative or regulatory changes applicable to our trucking operations will be enacted and to what extent any such legislation or regulations could increase our costs or otherwise adversely affect our business, financial condition and results of operations.

Changes in laws or government regulations regarding hydraulic fracturing could increase our costs of doing business, limit the areas in which our customers can operate and reduce oil and natural gas production by our customers, which could adversely impact our business.

The hydraulic fracturing process is water-intensive and there has been increased public concern regarding the usage of water supplies for hydraulic fracturing, an alleged potential for hydraulic fracturing to adversely affect drinking water, and the suitability of disposal outlets for fracturing fluids. Hydraulic fracturing typically is regulated by state oil and natural gas commissions. In addition, certain federal agencies have proposed additional laws and regulations to more closely regulate the hydraulic fracturing process. For example, the EPA’s recent finalization of new source performance standard (“NSPS”) requirements for methane and volatile organic compounds emissions from oil and gas development and production operations includes hydraulic fracturing and other well completion activity. The EPA also released the final results of its comprehensive

research study on the potential adverse impacts that hydraulic fracturing may have on drinking water resources in December 2016. The EPA concluded that hydraulic fracturing activities can impact drinking water resources under some circumstances, including large volume spills and inadequate mechanical integrity of wells. The results of the EPA’s study could spur action towards federal legislation and regulation of hydraulic fracturing or similar production operations. For example, Congress has in recent legislative sessions considered legislation to amend the SDWA, including legislation that would repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process. The U.S. Congress may consider similar SDWA legislation in the future. Several states where we conduct our water and environmental services business, such as Texas and Pennsylvania, have also either adopted or proposed laws and/or regulations to require oil and natural gas operators to disclose chemical ingredients and water volumes used to hydraulically fracture wells. The chemical ingredient information is generally available to the public via online databases, and this may bring more public scrutiny to hydraulic fracturing operations. Apart from disclosure obligations, states have been imposing more stringent well construction and monitoring requirements. Local governments likewise have been enacting restrictions on fracturing.

Federal agencies have been pursuing a variety of initiatives relating to hydraulic fracturing beyond the recent NSPS requirements. For example, the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance on February 11, 2014, addressing the performance of such activities in those states where the EPA is the permitting authority. Also, in 2014, the EPA issued an advance notice of proposed rulemaking under the Toxic Substances Control Act to solicit public input on the information that should be reported or disclosed for hydraulic fracturing chemical substances and mixtures. Further, the EPA proposed federal Clean Water Act regulations in 2015 that would govern wastewater discharges to publicly owned treatment works from hydraulic fracturing and certain other natural gas operations. In addition, the U.S. Department of the Interior has promulgated a final rule for hydraulic fracturing activities on federal lands in March 2015; however, these rules were struck down by a federal court in Wyoming in June 2016. An appeal of the decision is pending. Moreover, in June 2012, the Occupational Safety and Health Administration (“OSHA”) and the National Institute of Occupational Safety and Health (“NIOSH”) issued a joint hazard alert for workers who use silica (commonly referred to as “sand”) in hydraulic fracturing activities. OSHA formally proposed to lower the permissible exposure limit for airborne silica in 2013, and it has prepared guidance identifying other workplace hazards resulting from hydraulic fracturing along with ways to reduce exposure to those hazards.

The process of hydraulic fracturing produces large quantities of wastewater that must be disposed of, leading to a significant increase in the number of disposal wells drilled in recent years. Unlike enhanced recovery wells and hydraulic fracturing, wastewater disposal wells are not accompanied by any withdrawal of fluids and, thus, have greater potential for pressure buildup, potentially increasing the likelihood of induced seismic activity. In March 2016, the United States Geological Survey identified six states with the most significant hazards from induced seismicity, including Texas, Colorado, Oklahoma, Kansas, New Mexico and Arkansas. In addition, a number of lawsuits have been filed, most recently in Oklahoma, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells and hydraulic fracturing.

If new federal, state or local laws or regulations that significantly restrict hydraulic fracturing activities are adopted, such legal requirements could result in delays, eliminate certain drilling and completions activities and make it more difficult or costly for us to perform fracturing. Any such regulations limiting or prohibiting hydraulic fracturing could reduce oil and natural gas exploration and production activities by our customers and, therefore, adversely affect our business. Such laws or regulations could also materially increase our costs of compliance and doing business by more strictly regulating how hydraulic fracturing wastes are handled or disposed. The impact of such requirements could be materially adverse to our business, financial condition and results of operations.

Our operations may incur substantial costs to comply with climate change legislation and regulatory initiatives, which may also reduce the demand for fossil fuels and our services.

In response to certain scientific studies suggesting that emissions of GHGs, including carbon dioxide and methane, are contributing to the warming of the Earth’s atmosphere and other climatic conditions, the U.S. Congress has considered adopting comprehensive legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through measures to promote the use of renewable energy and/or regional GHG cap-and-trade programs. In addition, in December 2009, the EPA determined that emissions of carbon dioxide, methane and certain other GHGs endanger public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. Accordingly, the EPA has begun adopting rules

under the CAA that, among other things, cover reductions in GHG emissions from motor vehicles, permits for certain large stationary sources of GHGs, monitoring and annual reporting of GHG emissions from specified GHG emission sources, including oil and natural gas exploration and production operations. For instance, the EPA has adopted rules under the CAA for the permitting of greenhouse gas emissions from stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. In October 2015, the EPA finalized rules that added new sources to the scope of the GHG monitoring and reporting requirements. These new sources include gathering and boosting facilities as well as completions and workovers from hydraulically fractured oil wells. The revisions also include the addition of well identification reporting requirements for certain facilities.

Finally, efforts have also been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. In 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. In April 2016, the United States signed the Paris Agreement, which requires member countries to review and “represent a progression” in their nationally determined contributions, which set GHG emission reduction goals, every five years.

Although it is not possible at this time to estimate how potential future laws or regulations addressing GHG emissions would impact our business, either directly or indirectly, any future federal, state or local laws or implementing regulations that may be adopted to address GHG emissions in areas where we operate could require us or our customers to incur increased compliance and operating costs. Regulation of GHGs could also result in a reduction in demand for and production of oil and natural gas, which would result in a decrease in demand for our services. Additionally, to the extent that unfavorable weather conditions are exacerbated by global climate change or otherwise, our operations may be adversely affected to a greater degree than we have previously experienced, including an increase in delays and costs. We cannot predict with any certainty at this time how these possibilities may affect our operations, but such effects could be materially adverse. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states likewise could adversely affect the oil and natural gas industry. Moreover, incentives to conserve energy or use alternative energy sources could reduce demand for oil and natural gas and thereby reduce demand for our services.

Severe weather could have a material adverse effect on our business.

Adverse weather can directly impede our operations. Repercussions of severe weather conditions may include:


•	curtailment of services;


•	weather-related damage to facilities and equipment, resulting in suspension of operations;


•	inability to deliver equipment and personnel to job sites in accordance with contract schedules; and


•	loss of productivity.

These constraints could delay our operations and materially increase our operating and capital costs. Unusually warm winters or cool summers may also adversely affect the demand for our services by decreasing the demand for natural gas. Our operations in semi-arid regions can be affected by droughts and other lack of access to water used in our operations, especially with respect to our hydraulic fracturing operations.

Cybersecurity risks and threats could affect our business.

We rely heavily on information systems to conduct our business. There can be no assurance that the systems we have designed to prevent or limit the effects of cyber incidents or attacks will be sufficient to prevent or detect such incidents or attacks, or to avoid a material impact on our systems when such incidents or attacks do occur. If our systems for protecting against cybersecurity risks are circumvented or breached, it could result in the loss of our intellectual property or other proprietary information, including customer data, as well as disrupt our normal business operations and result in significant costs to remedy the effects of such incidents.

A sustained failure of our enterprise resource planning systems could adversely affect our business.

We use enterprise resource planning systems to operate our business. A sustained failure of these systems could adversely affect our business by preventing us from:


•	closing our financials and preparing financial statements;


•	tracking our repair and maintenance, payroll and other expenses;


•	tracking fixed assets or purchase orders and receipts for supply chain purchases;


•	gaining visibility of the financial performance at each of lines of business; and


•	being able to properly manage the needs of our customers.

We are subject to continuing contingent tax liabilities of CHK following the spin-off.

Under the Internal Revenue Code (the “Code”) and the related rules and regulations, each corporation that was a member of CHK’s consolidated tax reporting group during any taxable period or portion of any taxable period ending on or before the effective time of the spin-off is jointly and severally liable for the federal income tax liability of the entire consolidated tax reporting group for that taxable period. We have entered into a tax sharing agreement with CHK that allocates the responsibility for prior year taxes of CHK’s consolidated tax reporting group between us and CHK and its subsidiaries. Please read “Business—The Spin-Off—Agreements Between Us and CHK” in Item 1 of this report. However, if CHK were unable to pay, we nevertheless could be required to pay the entire amount of such taxes.

Potential indemnification liabilities to CHK pursuant to the master separation agreement could materially adversely affect our company.

The master separation agreement with CHK provides for, among other things, provisions governing the relationship between our company and CHK resulting from the spin-off. For a description of the terms of the master separation agreement, please read “Business—The Spin-Off—Agreements Between Us and CHK” in Item 1 of this report. Among other things, the master separation agreement provides for indemnification obligations designed to make our company financially responsible for substantially all liabilities that may exist relating to our business activities incurred after the spin-off. If we are required to indemnify CHK under the circumstances set forth in the master separation agreement, we may be subject to substantial liabilities. Additionally, in certain circumstances, we will be prohibited from making an indemnity claim until we first seek an insurance recovery.

In connection with our separation from CHK, CHK indemnified us for certain liabilities. However, there can be no assurance that the indemnities will be sufficient to insure us against the full amount of such liabilities, or that CHK’s ability to satisfy its indemnification obligation will not be impaired in the future.

Pursuant to the master separation agreement and tax sharing agreement, CHK has agreed to indemnify us for certain liabilities. However, third parties could seek to hold us responsible for any of the liabilities that CHK has agreed to retain, and there can be no assurance that the indemnity from CHK will be sufficient to protect us against the full amount of such liabilities, or that CHK will be able to fully satisfy its indemnification obligations. Moreover, even if we ultimately succeed in recovering from CHK any amounts for which we are held liable, we may be temporarily required to bear these losses. If CHK is unable to satisfy its indemnification obligations, the underlying liabilities could have a material adverse effect on our business, financial condition and results of operations.

As a result of our spin-off from CHK, our historical financial information with respect to periods prior to June 30, 2014 is not necessarily indicative of our future financial condition or future results of operations nor does it reflect what our financial condition or results of operations would have been as an independent public company during the periods presented.

The historical financial information prior to June 30, 2014 that we have included in this Form 10-K does not reflect what our financial condition or results of operations would have been as an independent public company during the periods presented and is not necessarily indicative of our future financial condition or future results of operations. This is primarily a result of the following factors:


•	our historical financial results prior to June 30, 2014 reflect allocations of expenses for services historically provided by CHK, and those allocations may be significantly lower than the comparable expenses we would have incurred as an independent company;


•	our historical financial results prior to June 30, 2014 reflect CHK’s guarantee of utilization levels for our drilling rigs and following the spin-off such guarantee was terminated;


•	our historical financial results prior to June 30, 2014 do not reflect various transactions that were effected in connection with the spin-off;


•	contracts with customers may be at less favorable rates than those in place under our arrangement with CHK prior to the spin-off;


•	our cost of debt and other capitalization is different from that reflected in our historical financial statements; and


•	the historical financial information may not fully reflect the increased costs associated with being an independent public company, including significant changes in our cost structure, management, financing arrangements, cash tax payment obligations and business operations as a result of our spin-off from CHK, including all the costs related to being an independent public company.

We historically have had material weaknesses in our internal control over financial reporting. If we do not maintain an effective system of internal control over financial reporting, we may not be able to accurately report our financial results.

A material weakness is a deficiency or a combination of deficiencies in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. In prior periods we identified a control deficiency that constituted a material weakness. We did not design and maintain effective controls related to the recoverability of the carrying value of property and equipment. Specifically, we did not design a review precise enough to determine the accuracy and support of certain assumptions related to the property and equipment impairment assessments.

Deficiencies in internal control over financial reporting are matters that may require an extended period to remediate. We will continue to evaluate, design and implement policies and procedures to address deficiencies to maintain adequate internal control over financial reporting as a public company. Internal control over financial reporting, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the control objectives will be met. These inherent limitations include system errors, the potential for human error and unauthorized actions of employees or contractors, inadequacy of controls, temporary lapses in controls due to shortfalls in transition planning and oversight or resources, and other factors. Consequently, such controls may not prevent or detect misstatements in our reported financial results as required under SEC and any exchange rules, which could increase our operating costs or impair our ability to operate our business. Controls may also become inadequate due to changes in circumstances, and it is necessary to replace, upgrade or modify our internal information systems from time to time.

If management is not successful in maintaining a strong internal control environment, material weaknesses could occur, causing investors to lose confidence in our reported financial information. This could lead to a decline in our stock price, limit our ability to access the capital markets in the future, and require us to incur additional costs to improve our internal control systems and procedures.

There may be circumstances in which the interests of our significant stockholders could be in conflict with the interests of our other stockholders.

Funds associated with BlueMountain Capital Management, LLC, Axar Capital Management, LLC and Mudrick Capital Management, L.P. currently own approximately 35.0%, 15.6% and 8.6%, respectively, of our outstanding common stock. Circumstances may arise in which these stockholders may have an interest in pursuing or preventing acquisitions, divestitures or other transactions, including the issuance of additional shares or debt, that, in their judgment, could enhance their investment in us or another company in which they invest. Such transactions might adversely affect us or other holders of our common stock. Furthermore, we have entered into a Stockholders Agreement with the Registration Rights Holders that provides for certain director nomination rights subject to conditions on share ownership. Certain significant actions by the Company require the consent of one or more of the Holders. These actions include, but are not limited to, the issuance of equity securities of the Company representing more than 10% of the shares of New Common Stock issued pursuant to the Plan, the incurrence of indebtedness under the New ABL Credit Facility in excess of $275 million in the aggregate and other indebtedness in excess of $550 million in the aggregate, and the consummation of acquisitions greater than $100 million. In addition, our significant concentration of share ownership may adversely affect the trading price of our common shares because investors may perceive disadvantages in owning shares in companies with significant stockholders.

Members of our management may have conflicts of interest because of their ownership of shares of common stock of CHK.

Members of our management own shares of common stock of CHK. This ownership could create, or appear to create, potential conflicts of interest when our directors and executive officers are faced with decisions that could have different implications for our company and CHK.

Risks Relating to our Pending Merger with Patterson-UTI

The pendency of the merger with Patterson-UTI could adversely affect our business and operations.

In connection with the pending merger with Patterson-UTI, some of our customers or vendors may delay or defer decisions, which could negatively affect our revenues, earnings, cash flows and expenses, regardless of whether the merger is completed. Similarly, our current and prospective employees may experience uncertainty about their future roles with the combined company following the merger, which may materially adversely affect our ability to attract, retain and motivate key personnel during the pendency of the merger and which may materially adversely divert attention from the daily activities of our existing employees.

In addition, due to operating covenants in the merger agreement, we may be unable, during the pendency of the merger, to pursue strategic transactions, undertake significant capital projects, undertake certain significant financing transactions and otherwise pursue other actions that are not in the ordinary course of business, even if such actions would prove beneficial to us. Further, the process of seeking to accomplish the merger could also divert the focus of our management from pursuing other opportunities that could be beneficial to it, without realizing any of the benefits which might have resulted had the merger been completed.

Failure to complete the merger with Patterson-UTI could negatively impact our future business and financial results.

We cannot make any assurances that we will be able to satisfy all of the conditions to the merger or succeed in any litigation brought in connection with the merger. If the merger is not completed, the financial results of SSE may be adversely affected and we will be subject to several risks, including but not limited to:


•	the requirement that we pay Patterson-UTI a termination fee of $40,000,000 in each case under certain circumstances provided in the merger agreement;


•	the payment of costs relating to the merger, such as legal, accounting, financial advisor and printing fees, regardless of whether the merger is completed;


•	the focus of our management team on the merger instead of the pursuit of other opportunities that could have been beneficial to each company; and


•	the potential occurrence of litigation related to any failure to complete the merger.

In addition, if the merger is not completed, we may experience negative reactions from the financial markets and from our customers and employees. If the merger is not completed, we cannot assure you that these risks will not materialize and will not materially and adversely affect our business, financial results and stock price.

The merger agreement contains provisions that limit each party’s ability to pursue alternatives to the merger, could discourage a potential competing acquiror from making a favorable alternative transaction proposal for us and, in specified circumstances, could require us to pay a termination fee to Patterson-UTI.

The merger agreement contains “non-solicitation” provisions that, subject to limited exceptions, restrict our ability to, among other things, directly or indirectly solicit, initiate, facilitate, knowingly encourage or induce or take any action that could be reasonably expected to lead to the making, submission or announcement of a proposal competing with the transactions contemplated by the merger agreement. In addition, while our board of directors has the ability, in certain circumstances, to change its recommendation of the transaction to their respective stockholders, we cannot terminate the merger agreement to accept an alternative proposal, and Patterson-UTI generally has an opportunity to modify the terms of the merger and the merger agreement in response to any alternative proposals that may be made before such board of directors may withdraw or

modify its recommendation. Moreover, in certain circumstances, we may be required to pay up to $7,500,000 of Patterson-UTI’s expenses and we may be required to pay Patterson-UTI a termination fee of $40,000,000.

These provisions could discourage a potential third party that might have an interest in acquiring all or a significant portion of us from considering or proposing that acquisition, even if it were prepared to pay consideration with a higher per share cash or market value than the market value proposed to be received or realized in the merger with Patterson-UTI. In addition, these provisions might result in a potential third party acquirer proposing to pay a lower price to our stockholders than it might otherwise have proposed to pay because of the added expense of the termination fee that may become payable in certain circumstances.

If the merger agreement is terminated and we determine to seek another business combination, we may not be able to negotiate a transaction with another party on terms comparable to, or better than, the terms of the merger with Patterson-UTI.



Item 1B.	Unresolved Staff Comments

None.



Item 2.	Properties

We conduct our operations out of a number of field offices, yards, shops, terminals and other facilities principally located in Ohio, Oklahoma, Pennsylvania, Texas, West Virginia and Wyoming. Most of these facilities were transferred to us from CHK at the time of the spin-off. We do not believe that any one of these facilities is individually material to our operations.



Item 3.	Legal Proceedings

While the filing of the Bankruptcy Petitions automatically stayed certain actions against the Company, including actions to collect pre-petition indebtedness or to exercise control over the property of its bankruptcy estates, the Company received an order from the Bankruptcy Court allowing it to pay all general claims, including claims of litigation counterparties, in the ordinary course of business in accordance with applicable non-bankruptcy laws notwithstanding the commencement of the Chapter 11 cases. The Plan confirmed in the Chapter 11 cases provides for the treatment of claims against the Company’s bankruptcy estates, including pre-petition liabilities that have not otherwise been satisfied or addressed during the Chapter 11 cases.

On the Effective Date, by operation of the Plan, the Company, on its behalf and on behalf of its subsidiaries, entered into a Litigation Trust Agreement (the “Litigation Trust Agreement”) with Alan Carr (the “Trustee”), pursuant to which the Litigation Trust (the “Trust”) was established for the benefit of specified holders of allowed claims. Pursuant to the Plan and the Confirmation Order, the Company transferred specified claims and causes of action to the Trust with title to such claims and causes of action being free and clear of all liens, claims, encumbrances, and interests. In addition, pursuant to the Plan and Confirmation Order, the Company transferred $50,000 in cash to the Trust to pay the reasonable costs and expenses associated with the administration of the Trust. The Trustee may prosecute the transferred claims and causes of action and conduct such other action as described in and authorized by the Plan, make timely and appropriate distributions to the beneficiaries of the Trust, and otherwise carry out the provisions of the Litigation Trust Agreement. The Company is not a beneficiary of the Trust.

We are subject to various legal proceedings and claims arising in the ordinary course of our business. Our management does not expect the outcome of any of these known legal proceedings, individually or collectively, to have a material adverse effect on our financial condition or results of operations.



Item 4.	Mine Safety Disclosures

Not applicable.

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PART II. OTHER INFORMATION



Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Market Information

Prior to May 17, 2016, the Company’s common stock was traded on the NYSE under the symbol “SSE.” On May 17, 2016, SSE was notified by the NYSE that due to “abnormally low” trading price levels, pursuant to Section 802.01D of the NYSE’s Listed Company Manual, the NYSE had determined to commence proceedings to delist the Company’s common stock. Trading in the Company’s common stock was suspended immediately prior to the opening of trading on May 17, 2016. SSE common stock was traded on the OTC Market Group Inc.’s OTC Pink market under “SSEI” from May 18, 2016 until June 8, 2016, and under “SSEIQ” from June 8, 2016 until August 2, 2016.

Upon emergence from bankruptcy on August 1, 2016, the Company’s then outstanding common stock was cancelled and the Company issued an aggregate of 22,000,000 shares of New Common Stock. The New Common Stock is not traded on a national securities exchange. The New Common Stock began trading on the OTC Grey market under “SVNT” on August 17, 2016. Broker-dealers are not willing or able to publicly quote OTC Grey market securities because of a lack of investor interest, company information availability or regulatory compliance. OTC Grey market securities do not have bid or ask quotations in the OTC Link system or the OTCBB. Broker-dealers must report OTC Grey market trades to FINRA, therefore trade data is available on http://www.otcmarkets.com and other public sources.

As of February 9, 2017, there were 71 registered holders of our issued and outstanding common stock.

Dividends

No dividends were paid during the years ended December 31, 2016, 2015 and 2014.

Our debt arrangements restrict our ability to distribute dividends.

Issuer Purchases of Equity Securities

The following table presents information about repurchases of our common stock during the quarter ended December 31, 2016:



Period	Total Number of Shares Purchased^(a)	Average Price Paid per Share^(a)		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased under the Plans or Program
October 1, 2016 - October 31, 2016	—	$	—	—	—
November 1, 2016 - November 30, 2016	—	$	—	—	—
December 1, 2016 - December 31, 2016	59,178	$	45.00	—	—
Total	59,178			—	—


(a)	Reflects shares surrendered as payment for statutory withholding taxes upon the vesting of restricted stock issued pursuant to the Seventy Seven Energy Inc. 2016 Omnibus Incentive Plan.

Equity Compensation Plan Information

Information required by this item with respect to compensation plans under which our equity securities are authorized for issuance is incorporated by reference to Part III, Item 12 of this report.

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Item 6.	Selected Financial Data

The following table sets forth certain consolidated financial data for the periods presented, which has been derived from our audited consolidated financial statements and the audited consolidated financial statements of our predecessor, COO.

The selected historical financial data is not necessarily indicative of results to be expected in future periods and does not necessarily reflect what our financial position and results of operations would have been had we operated as an independent public company during periods prior to our spin-off from CHK. The selected historical financial data should be read in conjunction with Item 7 and Item 8 of this report.

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	Successor			Predecessor
	Five Months Ended			Seven Months Ended			Years Ended December 31,
	December 31, 2016			July 31, 2016			2015			2014			2013			2012
				(in thousands, except per share data)
Income Statement Data:
Revenues	$	222,378		$	333,919		$	1,131,244		$	2,080,892		$	2,188,205		$	1,920,022
Operating Expenses:
Operating costs^(a)	166,726			237,014			855,870			1,580,353			1,717,709			1,390,786
Depreciation and amortization	73,898			162,425			295,421			292,912			289,591			231,322
General and administrative	31,808			66,667			112,141			108,139			80,354			66,360
Loss on sale of a business	—			—			35,027			—			—			—
(Gains) losses on sales of property and equipment, net	(1,748		)	848			14,656			(6,272		)	(2,629		)	2,025
Impairment of goodwill	—			—			27,434			—			—			—
Impairments and other^(b)	—			6,116			18,632			30,764			74,762			60,710
Total Operating Expenses	270,684			473,070			1,359,181			2,005,896			2,159,787			1,751,203
Operating (Loss) Income	(48,306		)	(139,151		)	(227,937		)	74,996			28,418			168,819
Other (Expense) Income:
Interest expense	(15,497		)	(48,116		)	(99,267		)	(79,734		)	(56,786		)	(53,548		)
Gains on early extinguishment of debt	—			—			18,061			—			—			—
Loss and impairment from equity investees	—			—			(7,928		)	(6,094		)	(958		)	(361		)
Other income	2,112			2,318			3,052			664			1,758			1,543
Reorganization items, net	(1,868		)	(29,892		)	—			—			—			—
Total Other Expense	(15,253		)	(75,690		)	(86,082		)	(85,164		)	(55,986		)	(52,366		)
(Loss) Income Before Income Taxes	(63,559		)	(214,841		)	(314,019		)	(10,168		)	(27,568		)	116,453
Income Tax (Benefit) Expense	—			(59,131		)	(92,628		)	(2,189		)	(7,833		)	46,877
Net (Loss) Income	$	(63,559	)	$	(155,710	)	$	(221,391	)	$	(7,979	)	$	(19,735	)	$	69,576
(Loss) Earnings Per Common Share^(c):
Basic	$	(2.86	)	$	(2.84	)	$	(4.42	)	$	(0.17	)	$	(0.42	)	$	1.48
Diluted	$	(2.86	)	$	(2.84	)	$	(4.42	)	$	(0.17	)	$	(0.42	)	$	1.48
Cash Flow Data:
Cash flows provided by operations	$	21,890		$	6,469		$	284,106		$	265,296		$	337,071		$	211,151
Cash flows used in investing activities	$	(2,482	)	$	(80,126	)	$	(159,667	)	$	(367,646	)	$	(296,817	)	$	(577,324	)
Cash flows (used in) provided by financing activities	$	(8,504	)	$	(19,241	)	$	5,318		$	101,563		$	(39,803	)	$	366,870
Other Financial Data:
Capital expenditures	$	12,502		$	82,787		$	205,706		$	457,618		$	349,806		$	622,825


(a)	Historical operating costs include the effect of $18.9 million, $76.9 million and $100.8 million of rig rent expense associated with our lease of drilling rigs for the years December 31, 2014, 2013 and 2012, respectively. As of December 31, 2014, we had purchased all rigs that were subject to these lease arrangements.


(b)	Historical impairments and other include the effect of $9.7 million, $22.4 million and $24.9 million of lease terminations costs associated with repurchases of leased drilling rigs for the years ended December 31, 2014, 2013 and 2012, respectively.


(c)	On June 30, 2014 we distributed 46,932,433 shares of our common stock to CHK shareholders in conjunction with the spin-off. For comparative purposes, and to provide a more meaningful calculation for weighted average shares, we have assumed this amount to be outstanding for periods prior to the spin-off.

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	Successor		Predecessor
	December 31,		December 31,
	2016		2015		2014		2013		2012
			(in thousands)
Balance Sheet Data:
Cash	$	48,654	$	130,648	$	891	$	1,678	$	1,227
Property and equipment, net	$	749,540	$	1,530,420	$	1,767,053	$	1,497,476	$	1,581,519
Total assets	$	948,550	$	1,902,618	$	2,290,293	$	2,015,845	$	2,106,870
Long-term debt, less current maturities	$	425,212	$	1,564,592	$	1,572,241	$	1,043,952	$	1,055,559
Total equity	$	451,248	$	118,840	$	291,023	$	547,192	$	596,817

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Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations relates to the five months ended December 31, 2016 (the “2016 Successor Period”), the seven months ended July 31, 2016 (the “2016 Predecessor Period”) and the years ended December 31, 2015 and 2014.

Comparability of Historical Results

Upon emergence from bankruptcy, the Company adopted fresh-start accounting and became a new entity for financial reporting purposes. As a result of the application of fresh-start accounting and the effects of the implementation of the Plan, the Company’s consolidated financial statements on or after August 1, 2016 are not comparable with the financial statements prior to the Effective Date. The discussion and analysis of our financial condition and results of operations contained herein relates to the five months ended December 31, 2016, the seven months ended July 31, 2016, the year ended December 31, 2015, and the year ended December 31, 2014. For additional information about the application of fresh-start accounting, see Note 4 “Fresh-Start Accounting” of the Notes to Consolidated Financial Statements in Item 8 herein.

The historical results discussed in this section prior to June 30, 2014 are those of COO, which is our predecessor. The transactions in which we became an independent, publicly traded company, including the distribution of our common stock on June 30, 2014, are referred to collectively as the “spin-off”. The historical results discussed in this section prior to the spin-off do not purport to reflect what the results of operations, financial position, or cash flows would have been had we operated as an independent public company prior to June 30, 2014 and do not give effect to certain spin-off transactions on our consolidated statements of operations. For a detailed description of the basis of presentation of the historical financial statements, please read Note 1 “Basis of Presentation” of the Notes to Consolidated Financial Statements in Item 8 herein.

Overview

We are a diversified oilfield services company providing a wide range of wellsite services to U.S. land-based E&P customers. We offer services and equipment that are strategic to our customers’ oil and natural gas operations. We conduct our business through three operating segments: Drilling, Hydraulic Fracturing and Oilfield Rentals. Our operations are geographically diversified across many of the most active oil and natural gas plays in the onshore United States, including the Anadarko and Permian Basins and the Eagle Ford, Haynesville, Marcellus, Niobrara and Utica Shales.

Since we commenced operations in 2001, we have actively grown our business and modernized our asset base. As of December 31, 2016, our marketed rig fleet of 91 all-electric rigs consisted of 40 Tier 1 rigs, including 28 proprietary PeakeRigs™, and 51 Tier 2 rigs. As of December 31, 2016, we also owned 13 hydraulic fracturing fleets with an aggregate of approximately 500,000 horsepower and a diversified oilfield rentals business. For additional information regarding our business and strategies, please read “Business” in Item 1 of this report.

Cyclical Nature of Industry

We operate in a highly cyclical industry. The main factor influencing demand for oilfield services is the level of drilling and completions activity by E&P companies, which in turn depends largely on current and anticipated future crude oil and natural gas prices and production depletion rates. Demand for oil and natural gas is cyclical and is subject to large and rapid fluctuations. When oil and natural gas prices increase, producers increase their capital expenditures, which generally results in greater revenues and profits for oilfield service companies. The increased capital expenditures also ultimately result in greater production, which historically has resulted in increased oil and gas supplies and reduced prices that, in turn, tend to reduce demand for oilfield services. For these reasons, our results of operations may fluctuate from quarter-to-quarter and from year-to-year.

Industry activity is beginning to increase as the U.S. domestic rig count was 589 during the fourth quarter of 2016, which, while down 22% compared to the fourth quarter of 2015, was up 22% compared to the third quarter of 2016. Additionally, the average price of oil during the fourth quarter of 2016 was $49.25 per barrel, which represented a 17% increase compared to the fourth quarter of 2015 and a 10% increase compared to the third quarter of 2016. These average oil prices remain well below the average prices in 2014. The average price of natural gas during the fourth quarter of 2016 was $3.04 per McF, an increase of 47% compared to the fourth quarter of 2015 and a 6% increase compared to the third quarter of 2016. Future price declines or prolonged levels of low prices would further negatively affect the demand for our services and the prices we are able to charge

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to our customers. Additionally, we may incur costs and have downtime during periods when our customers’ activities are refocused towards different drilling regions.

Although the environment in which we are operating today is challenging, we continue to be focused on maximizing value for the company. We expect to achieve this objective through execution of the following strategies:

Diversify our customer base and geographic footprint. We intend to utilize our modern, high-quality assets and our deep understanding of the needs of unconventional resource developers to continue to diversify our customer base and geographic footprint. We provide extensive end-to-end complementary services aimed at reducing time spent on drilling and completion and total wellhead cost. In addition, the experience we gained as an integrated part of CHK, historically one of the most active developers of unconventional resources in the United States, makes us unique and allows us to achieve significant cost and cycle time advantages. We believe this gives us a strategic advantage and positions us well to attract new customers. It also gives us the ability to bundle our service offerings and create solutions that will allow us to move from transactional supplier to strategic partner for a number of our customers. We believe this strategy will reduce our customer concentration risk over time and create greater opportunities to benefit from the eventual recovery in oil and/or natural gas prices.

Continue our industry leading safety performance. We are committed to maintaining and continually improving the safety, reliability and efficiency of our operations, which we believe is critical to attracting new customers and maintaining relationships with our current customers, regulators and the communities in which we operate. We believe we have one of the lowest Total Recordable Incidence Rate (“TRIR”) as compared to our industry peers. In addition, our business goals include safety metrics, which drives continuous improvement regarding quality and safety. We have adopted and developed a management system that requires rigorous processes and procedures to facilitate our compliance with environmental regulations and policies. We also conduct internal and external assessments to verify compliance and identify areas for improvement. We work diligently to meet or exceed applicable safety and environmental regulations and we intend to continue to incorporate safety, environmental and quality principals into our operating procedures as our business grows and operating conditions change.

Continue to improve flexibility in our balance sheet and enhance our liquidity. We are committed to continually improving our balance sheet and liquidity, which will allow us to take advantage of our operational strengths and grow our business. Additionally, we believe this strategy will better position us to take advantage of opportunistic growth opportunities.

Patterson-UTI Merger Agreement

On December 12, 2016, SSE entered into an Agreement and Plan of Merger with Patterson-UTI Energy, Inc., a Delaware corporation, and Pyramid Merger Sub, Inc., a Delaware corporation and a direct, wholly owned subsidiary of Patterson-UTI , pursuant to which Patterson-UTI will acquire SSE in exchange for newly issued shares of Patterson-UTI common stock, par value $0.01 per share. The Merger Agreement provides that, upon the terms and subject to the conditions set forth therein, Merger Sub will be merged with and into SSE, with SSE continuing as the surviving entity and a wholly owned subsidiary of Patterson-UTI. The transaction is subject to approvals from each company’s stockholders, regulatory approvals and customary closing conditions. The transaction is expected to close late in the first quarter or early in the second quarter of 2017. However, SSE cannot predict with certainty when, or if, the pending merger will be completed because completion of the transaction is subject to conditions beyond the control of the Company.

For further information about the merger, see Note 2 “Patterson-UTI Merger Agreement” of the Notes to Consolidated Financial Statements in Item 8 herein.

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Emergence from Voluntary Reorganization under Chapter 11 Proceedings and Related Events

On June 7, 2016, the Debtors filed the Bankruptcy Petitions for reorganization under Chapter 11 in the Bankruptcy Court. On July 14, 2016, the Bankruptcy Court entered the Confirmation Order. The Debtors satisfied the remaining conditions to effectiveness contemplated under the Plan and emerged from Chapter 11 on August 1, 2016. For additional information about our bankruptcy proceedings, see Note 3 “Emergence from Voluntary Reorganization under Chapter 11 Proceedings and Related Events” of the Notes to Consolidated Financial Statements in Item 8 herein.

Upon our emergence from Chapter 11 bankruptcy, we adopted fresh-start accounting in accordance with the provisions of FASB ASC 852, “Reorganizations” which resulted in us becoming a new entity for financial reporting purposes. References to Successor relate to us on and subsequent to the Effective Date and references to Predecessor refer to us prior to the Effective Date. Upon adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the Effective Date. The Effective Date fair values of our assets and liabilities differed materially from the recorded values of our assets and liabilities as reflected in our historical condensed consolidated balance sheet. The effects of the Plan and application of fresh-start accounting are reflected in our condensed consolidated financial statements as of July 31, 2016, and the related adjustments thereto are recorded in our condensed consolidated statements of operations as reorganization items for the period ended July 31, 2016 (Predecessor Company).

As a result, our condensed consolidated balance sheets and condensed consolidated statement of operations subsequent to the Effective Date will not be comparable to our condensed consolidated balance sheets and statements of operations prior to the Effective Date. Our condensed consolidated financial statements and related footnotes are presented with a black line division which delineates the lack of comparability between amounts presented on or after August 1, 2016 and dates prior thereto. Our financial results for future periods following the application of fresh-start accounting will be different from historical trends, and such differences may be material. For additional information about our application of fresh-start accounting, see Note 4 “Fresh-Start Accounting” of the Notes to Consolidated Financial Statements in Item 8 herein.

Backlog

We maintain a backlog of contract revenues under our contracts for the provision of drilling and hydraulic fracturing services. Our drilling and hydraulic fracturing backlogs as of December 31, 2016 were approximately $208.1 million and $44.9 million, respectively. We calculate our drilling backlog by adding together (i) the day rate under our active rig contracts multiplied by the number of days remaining under the contracts and (ii) the implied daily margin rate on our IBC rigs multiplied by the number of days remaining on those contracts. We calculate our hydraulic fracturing backlog by multiplying the (i) rate per stage, which varies by operating region and is, therefore, estimated based on current customer activity levels by region and current contract pricing, by (ii) the number of stages remaining under the contract, which we estimate based on current and anticipated utilization of our crews. With respect to our hydraulic fracturing backlog, our contracts provide for periodic adjustments of the rates we may charge for our services, which will be negotiated based on then-prevailing market pricing and in the future may be higher or lower than the current rates we charge and utilize in calculating our backlog. Our drilling backlog calculation does not include any reduction in revenues related to mobilization or demobilization, nor does it include potential reductions in rates for unscheduled standby or during periods in which the rig is moving, on standby or incurring maintenance and repair time in excess of what is permitted under the drilling contract. In addition, many of our drilling contracts are subject to termination by the customer on short notice and provide for an early termination payment to us in the event that the contract is terminated by the customer. We calculate our contract drilling early termination value assuming each rig remains stacked for the remainder of the term of the terminated contract. As a result of the foregoing, revenues could differ materially from the backlog and early termination amounts presented.

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Following are details of our drilling and hydraulic fracturing backlogs as of December 31, 2016 (in millions):



Drilling Backlog	2017		2018
Rig-years^(a)	29.6		3.5
Revenues	$	184.1	$	24.0
Early termination value	$	115.5	$	11.8


(a)	Rig-years represents the number of equivalent rigs under contract during the given year. We calculate rig-years for our drilling backlog by dividing the total number of months that our rigs are contracted by 12.



Hydraulic Fracturing Backlog	2017		2018
Revenues	$	44.9	$	—

As of December 31, 2016, our hydraulic fracturing backlog had an average duration of six months.

How We Evaluate Our Operations

Our management team uses a variety of tools to monitor and manage our operations in the following eight areas: (a) segment gross margin, (b) equipment maintenance performance, (c) customer satisfaction, (d) asset utilization, (e) safety performance, (f) Adjusted EBITDA, (g) Adjusted Revenues and (h) Adjusted Operating Costs.

Segment Gross Margin. We define segment gross margin as segment revenues less segment operating costs. We view segment gross margin as one of our key management tools for managing costs at the segment level and evaluating segment performance. Our chief operating decision-maker tracks segment gross margin both as an absolute amount and as a percentage of revenues compared to prior periods.

Equipment Maintenance Performance. Equipment reliability (“uptime”) is an important factor to the success of our business. Uptime is beneficially impacted through preventive maintenance on our equipment. We have formal preventive maintenance procedures which are regularly monitored for compliance. Further, management monitors maintenance expenses as a percentage of revenue. This metric provides a leading indicator with respect to the execution of preventive maintenance and ensures that equipment reliability issues do not negatively impact operational uptime.

Customer Satisfaction. Upon completion of many of our services, we encourage our customers to provide feedback on the services provided. The evaluation of our performance is based on various criteria and our customer comments are indicative of their overall satisfaction level. This feedback provides us with the necessary information to reinforce positive performance and remedy negative issues and trends.

Asset Utilization. By consistently monitoring our operations’ activity levels, pricing and relative performance of each of our rigs and fleets, we can more efficiently allocate our personnel and equipment to maximize revenue generation. We measure our activity levels by the total number of jobs completed by each of our drilling rigs and hydraulic fracturing fleets on a periodic basis. We also monitor the utilization rates of our drilling rigs. We define utilization of our drilling rigs as the number of rigs that are operating divided by our marketed rig count.

Safety Performance. Maintaining a safe and incident-free workplace is a critical component of our operational success. Our management team uses both lagging and leading indicators to measure and manage safety performance. Total Recordable Incident Rate (“TRIR”), Lost Time Incident Rate (“LTIR”) and Motor Vehicle Crash Rate (“MVCR”) are key lagging indicators reviewed by management. We also review leading indicators such as safety observations, training completion, and action item completion to enhance our view of safety performance. Safety performance data is reported, tracked, and trended in a centralized database, which allows us to efficiently focus our incident prevention efforts.

Adjusted EBITDA. The primary financial and operating measurement that our management uses to analyze and monitor the operating performance of our business is Adjusted EBITDA, which we define as net income before interest expense, income tax expense, depreciation and amortization, as further adjusted to add back gains on extinguishment of debt, gains or losses on sale of a business and exit costs, gains or losses on sale of property and equipment, impairments and other, non-cash stock

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compensation, severance-related costs, restructuring charges, reorganization items, interest income, and certain non-recurring items, such as the sale of our drilling rig relocation and logistics business and the sale of our water hauling assets.

The tables below show our Net (Loss) Income and Adjusted EBITDA for the 2016 Successor Period, the 2016 Predecessor Period and the years ended December 31, 2015 and 2014. Please see “Non-GAAP Financial Measures” below for a reconciliation of Adjusted EBITDA to the GAAP financial measures of, on a consolidated basis, net loss and cash provided by operating activities, and for each of our operating segments, net (loss) income.



	Successor			Predecessor
	Five Months Ended			Seven Months Ended			Years Ended December 31,
	December 31, 2016			July 31, 2016			2015			2014
				(In thousands)
Net (Loss) Income:
Consolidated	$	(63,559	)	$	(155,710	)	$	(221,391	)	$	(7,979	)
Drilling	$	37,934		$	(366,593	)	$	(30,454	)	$	49,528
Hydraulic Fracturing	$	(45,385	)	$	(66,216	)	$	(15,990	)	$	38,985
Oilfield Rentals	$	(5,140	)	$	(28,539	)	$	(28,353	)	$	(1,705	)



	Successor			Predecessor
	Five Months Ended			Seven Months Ended			Years Ended December 31,
	December 31, 2016			July 31, 2016			2015		2014
				(In thousands)
Adjusted EBITDA:
Consolidated	$	37,942		$	72,451		$	235,019	$	432,178
Drilling^(a)	$	64,727		$	99,558		$	216,416	$	301,291
Hydraulic Fracturing^(b)	$	(10,566	)	$	3,221		$	86,399	$	144,720
Oilfield Rentals^(c)	$	3,496		$	(1,482	)	$	10,254	$	53,028

(a)

During 2015, general and administrative expenses were allocated to the Drilling segment in the amount of $31.9 million for corporate functions provided by the Other Operations segment on behalf of the Drilling segment. No allocations were made during the 2016 Successor Period, the 2016 Predecessor Period or the year ended December 31, 2014. The allocations for 2015 have been retroactively revised in the table above. See Note 20 “Segment Information” of the Notes to Consolidated Financial Statements in Item 8 herein.

(b)

During 2015, general and administrative expenses were allocated to the Hydraulic Fracturing segment in the amount of $25.6 million for corporate functions provided by the Other Operations segment on behalf of the Hydraulic Fracturing segment. No allocations were made during the 2016 Successor Period, the 2016 Predecessor Period or the year ended December 31, 2014. The allocations for 2015 have been retroactively revised in the table above. See Note 20 “Segment Information” of the Notes to Consolidated Financial Statements in Item 8 herein.

(c)

During 2015, general and administrative expenses were allocated to the Oilfield Rentals segment in the amount of $9.1 million for corporate functions provided by the Other Operations segment on behalf of the Oilfield Rentals segment. No allocations were made during the 2016 Successor Period, the 2016 Predecessor Period or the year ended December 31, 2014. The allocations for 2015 have been retroactively revised in the table above. See Note 20 “Segment Information” of the Notes to Consolidated Financial Statements in Item 8 herein.

Adjusted Revenues and Adjusted Operating Costs. “Adjusted Revenues” and “Adjusted Operating Costs” are financial and operating measurements that our management uses to analyze and monitor our period-over-period operating performance, which we define as revenues and operating costs before revenues and operating costs associated with our rig relocation and logistics business and water hauling assets that were sold in the second quarter of 2015, our compression unit manufacturing and geosteering businesses that were distributed to CHK as part of the spin-off, and our crude hauling assets that were sold to a third party as part of the spin-off. In addition, Adjusted Operating Costs is further adjusted to subtract rig rent expense.

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Non-GAAP Financial Measures

“Adjusted EBITDA”, “Adjusted Revenues” and “Adjusted Operating Costs” are non-GAAP financial measures. Adjusted EBITDA, Adjusted Revenues and Adjusted Operating Costs, as used and defined by us, may not be comparable to similarly titled measures employed by other companies and are not measures of performance calculated in accordance with generally accepted accounting principles (“GAAP”).

Adjusted Revenues and Adjusted Operating Costs should not be considered in isolation or as a substitute for revenues and operating costs, respectively, prepared in accordance with GAAP. However, our management uses Adjusted Revenues and Adjusted Operating Costs to evaluate our period-over-period operating performance because our management believes these measures improve the comparability of our continuing business, and for the same reasons believes these measures may be useful to an investor in evaluating our operating performance. A reconciliation of Adjusted Revenues and Adjusted Operating Costs to the GAAP measures of revenues and operating costs, respectively, is provided below in “—Results of Operations” for each period discussed.

Adjusted EBITDA should not be considered in isolation or as a substitute for operating income, net income or loss, cash flows provided by operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. However, our management uses Adjusted EBITDA to evaluate our performance and liquidity and believes Adjusted EBITDA may be useful to an investor in evaluating our operating performance and liquidity because this measure:


•	is widely used by investors in the oilfield services industry to measure a company’s operating performance without regard to items excluded from the calculation of such measure, which can vary substantially from company to company depending upon accounting methods, book value of assets, capital structure and the method by which assets were acquired, among other factors;


•	is a liquidity measure that is used by rating agencies, lenders and other parties to evaluate our creditworthiness; and


•	is used by our management for various purposes, including as a measure of performance for our operating entities and as a basis for strategic planning and forecasting.

There are significant limitations to using Adjusted EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss. Additionally, because Adjusted EBITDA excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies.

On a consolidated basis, the following tables present a reconciliation of Adjusted EBITDA to the GAAP financial measures of net loss and cash provided by operating activities. The following tables also present a reconciliation of Adjusted EBITDA to the GAAP financial measure of net (loss) income for each of our operating segments.

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Consolidated



	Successor			Predecessor
	Five Months Ended			Seven Months Ended			Years Ended December 31,
	December 31, 2016			July 31, 2016			2015			2014
				(In thousands)
Net loss	$	(63,559	)	$	(155,710	)	$	(221,391	)	$	(7,979	)
Add:
Interest expense	15,497			48,116			99,267			79,734
Gains on early extinguishment of debt	—			—			(18,061		)	—
Income tax benefit	—			(59,131		)	(92,628		)	(2,189		)
Depreciation and amortization	73,898			162,425			295,421			292,912
Impairment of goodwill	—			—			27,434			—
Impairments and other	—			6,116			18,632			30,764
(Gains) losses on sale of a business and exit costs	(106		)	135			35,018			—
Losses (gains) on sales of property and equipment, net	(1,748		)	848			14,656			(6,272		)
Non-cash compensation	10,577			12,637			48,509			47,184
Severance-related costs	215			643			6,433			2,017
Restructuring charges	3,026			27,918			—			—
Reorganization items, net	1,868			29,892			—			—
Impairment of equity method investment	—			—			8,806			4,500
Rent expense on buildings and real estate transferred from CHK^(a)	—			—			—			8,187
Rig rent expense^(b)	—			—			—			18,900
Interest income	(1,726		)	(1,438		)	(1,353		)	—
Less:
Drilling rig relocation and logistics Adjusted EBITDA	—			—			(9,745		)	17,450
Water hauling Adjusted EBITDA	—			—			(4,531		)	(1,364		)
Compression unit manufacturing Adjusted EBITDA	—			—			—			13,073
Geosteering Adjusted EBITDA	—			—			—			957
Crude hauling Adjusted EBITDA	—			—			—			(5,066		)
Non-recurring credit to stock compensation expense	—			—			—			10,530
Adjusted EBITDA	$	37,942		$	72,451		$	235,019		$	432,178

(a)

Rent expense on buildings and real estate transferred from CHK as part of the spin-off is included in operating costs and general and administrative expenses on the consolidated statement of operations included in Item 8 of this report. Our operating costs and general and administrative expenses include $8.0 million and $0.2 million, respectively, of rent expense associated with our lease of these facilities for the year ended December 31, 2014.


(b)	Rig rent expense associated with our lease of drilling rigs is included in operating costs on the consolidated statement of operations included in Item 8 of this report. As of December 31, 2014, we had repurchased all of our leased drilling rigs.

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	Successor			Predecessor
	Five Months Ended			Seven Months Ended			Years Ended December 31,
	December 31, 2016			July 31, 2016			2015			2014
				(In thousands)
Cash provided by operating activities	$	21,890		$	6,469		$	284,106		$	265,296
Add:
Changes in assets and liabilities	1,963			(26,243		)	(163,356		)	88,588
Interest expense	15,497			48,116			99,267			79,734
Lease termination costs	—			—			—			9,701
Amortization of sale/leaseback gains	—			—			—			5,414
Amortization of deferred financing costs	(103		)	(2,455		)	(4,623		)	(6,122		)
Accretion of discount on Term Loans	(5,192		)	—			—			—
Accretion of discount on Note Receivable	694			—			—			—
(Gains) losses on sale of a business and exit costs	(106		)	135			(9		)	—
Income (loss) from equity investees	—			—			878			(1,594		)
Provision for doubtful accounts	(16		)	(1,406		)	(1,375		)	(2,887		)
Current tax expense	—			(8		)	58			674
Severance-related costs	215			643			6,433			2,017
Restructuring charges	3,026			27,918			—			—
Cash reorganization items, net	1,868			20,710			—			—
Rent expense on buildings and real estate transferred from CHK^(a)	—			—			—			8,187
Rig rent expense^(b)	—			—			—			18,900
Interest Income	(1,726		)	(1,438		)	(1,353		)	—
Other	(68		)	10			717			(150		)
Less:
Drilling rig relocation and logistics Adjusted EBITDA	—			—			(9,745		)	17,450
Water hauling Adjusted EBITDA	—			—			(4,531		)	(1,364		)
Compression unit manufacturing Adjusted EBITDA	—			—			—			13,073
Geosteering Adjusted EBITDA	—			—			—			957
Crude hauling Adjusted EBITDA	—			—			—			(5,066		)
Non-recurring credit to stock compensation expense	—			—			—			10,530
Adjusted EBITDA	$	37,942		$	72,451		$	235,019		$	432,178

(a)


(b)	Rig rent expense associated with our lease of drilling rigs is included in operating costs on the consolidated statement of operations included in Item 8 of this report. As of December 31, 2014, we had repurchased all of our leased drilling rigs.

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Drilling



	Successor			Predecessor
	Five Months Ended			Seven Months Ended			Years Ended December 31,
	December 31, 2016			July 31, 2016			2015			2014
				(In thousands)
Net income (loss)	$	37,934		$	(366,593	)	$	(30,454	)	$	49,528
Add:
Income tax (benefit) expense	—			(142,564		)	(12,741		)	30,471
Depreciation and amortization	26,979			87,160			163,380			140,884
Impairment of goodwill	—			—			27,434			—
Impairments and other	—			3,205			14,329			29,602
(Gains) losses on sales of property and equipment, net	(984		)	1,211			10,566			17,931
Non-cash compensation	467			1,973			10,745			17,188
Severance-related costs	—			259			1,263			374
Corporate overhead allocation^(a)	—			—			31,894			—
Restructuring charges	288			280			—			—
Reorganization items, net	43			514,627			—			—
Rent expense on buildings and real estate transferred from CHK	—			—			—			1,688
Rig rent expense	—			—			—			18,900
Less:
Geosteering Adjusted EBITDA	—			—			—			957
Non-recurring credit to stock compensation expense	—			—			—			4,318
Adjusted EBITDA	$	64,727		$	99,558		$	216,416		$	301,291

(a)

In 2015, the information that was regularly reviewed by our chief operating decision-maker included general and administrative expenses that were allocated to each of our reportable segments for corporate overhead functions provided by the Other Operations segment, on behalf of our reportable segments. Effective January 1, 2016, we no longer allocate general and administrative expenses to our reportable segments from the Other Operations segment in the information that is reviewed by our chief operating decision-maker.

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Hydraulic Fracturing



	Successor			Predecessor
	Five Months Ended			Seven Months Ended			Years Ended December 31,
	December 31, 2016			July 31, 2016			2015			2014
				(In thousands)
Net (loss) income	$	(45,385	)	$	(66,216	)	$	(15,990	)	$	38,985
Add:
Income tax (benefit) expense	—			(25,750		)	(6,690		)	24,563
Depreciation and amortization	34,079			49,124			70,605			72,105
Impairments and other	—			—			—			207
Losses (gains) on sales of property and equipment, net	31			66			230			(17		)
Non-cash compensation	278			718			3,440			3,369
Severance-related charges	215			55			351			226
Corporate overhead allocation^(a)	—			—			25,647			—
Restructuring charges	184			178			—			—
Reorganization items, net	32			45,046			—			—
Impairment of equity method investment	—			—			8,806			4,500
Rent expense on buildings and real estate transferred from CHK	—						—			1,259
Less:				—
Non-recurring credit to stock compensation expense	—			—			—			477
Adjusted EBITDA	$	(10,566	)	$	3,221		$	86,399		$	144,720

(a)

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Oilfield Rentals



	Successor			Predecessor
	Five Months Ended			Seven Months Ended			Years Ended December 31,
	December 31, 2016			July 31, 2016			2015			2014
				(In thousands)
Net loss	$	(5,140	)	$	(28,539	)	$	(28,353	)	$	(1,705	)
Add:
Income tax benefit	—			(11,099		)	(11,863		)	(754		)
Depreciation and amortization	9,032			18,773			41,049			52,680
Impairments and other	—			287			—			955
Gains on sales of property and equipment, net	(590		)	(425		)	(1,780		)	(2,355		)
Non-cash compensation	94			285			1,917			2,691
Severance-related costs	—			173			175			702
Corporate overhead allocation^(a)	—			—			9,109			—
Restructuring charges	87			97			—			—
Reorganization items, net	13			18,966			—			—
Rent expense on buildings and real estate transferred from CHK	—			—			—			1,415
Less:
Non-recurring credit to stock compensation expense	—			—			—			601
Adjusted EBITDA	$	3,496		$	(1,482	)	$	10,254		$	53,028

(a)

Liquidity and Capital Resources

We require capital to fund ongoing operations, including operating expenses, organic growth initiatives, investments, acquisitions and debt service. We expect our future capital needs will be funded by cash flows from operations, borrowings under our credit facility, access to the capital markets and other financing transactions. We believe we will have adequate liquidity over the next twelve months to operate our business and meet our cash requirements.

As of December 31, 2016, we had cash of $48.7 million and working capital of $105.2 million. We had no outstanding borrowings under our revolving bank credit facility, letters of credit of $15.9 million and availability of $58.6 million as of December 31, 2016.

As of February 9, 2017, we had cash of $44.9 million and our credit facility remained undrawn. We expect that our primary sources of liquidity will be from cash on hand, cash from operations and availability under our credit facility.

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Long-Term Debt

The following table presents our long-term debt outstanding as of December 31, 2016 and 2015 (in thousands):



	Successor		Predecessor
	December 31, 2016		December 31, 2015
6.625% Senior Notes due 2019	$	—	$	650,000
6.50% Senior Notes due 2022	—		450,000
Term Loans	473,250		493,250
Total principal amount of debt	473,250		1,593,250
Less:
Discount on Term Loans	43,038		—
Current portion of long-term debt	5,000		5,000
Unamortized deferred financing costs	—		23,658
Total long-term debt	$	425,212	$	1,564,592

For further information on our long-term debt, please read Note 11 “Debt” of the Notes to Consolidated Financial Statements in Item 8 herein.

Capital Expenditures

Our business is capital-intensive, requiring significant investment to maintain, upgrade and purchase equipment to meet our customers’ needs and industry demand. Our capital requirements consist primarily of:


•	growth capital expenditures, which are defined as capital expenditures made to acquire additional equipment and other assets, increase our service lines, expand geographically or advance other strategic initiatives for the purpose of growing our business; and


•	maintenance capital expenditures, which are defined as capital expenditures that are necessary to maintain and upgrade the service capability of our existing assets and include the replacement of components and equipment which are worn or obsolete.

Total capital expenditures were $12.5 million, $82.8 million, $205.7 million and $457.6 million for the 2016 Successor Period, the 2016 Predecessor Period and the years ended December 31, 2015 and 2014, respectively. We may increase, decrease or reallocate our anticipated capital expenditures during any period based on industry conditions, the availability of capital or other factors, and a significant component of our anticipated capital spending is discretionary. In addition, from time to time we may use cash on hand in excess of our budgeted capital expenditures to repurchase our outstanding long-term debt.

Cash Flow

Our cash flow depends in large part on the level of spending by our customers on exploration, development and production activities. Sustained increases or decreases in the price of oil or natural gas could have a material impact on these activities, thus materially affecting our cash flows. The following is a discussion of our cash flow for the 2016 Successor Period, the 2016 Predecessor Period and the years ended December 31, 2015 and 2014.

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	Successor			Predecessor
	Five Months Ended			Seven Months Ended			Years Ended December 31,
	December 31, 2016			July 31, 2016			2015			2014
Cash Flow Statement Data:				(In thousands)
Net cash provided by operating activities	$	21,890		$	6,469		$	284,106		$	265,296
Net cash used in investing activities	$	(2,482	)	$	(80,126	)	$	(159,667	)	$	(367,646	)
Net cash (used in) provided by financing activities	$	(8,504	)	$	(19,241	)	$	5,318		$	101,563
Cash, beginning of period	$	37,750		$	130,648		$	891		$	1,678
Cash, end of period	$	48,654		$	37,750		$	130,648		$	891

Operating Activities. Cash provided by operating activities was $21.9 million, $6.5 million, $284.1 million and $265.3 million for the 2016 Successor Period, the 2016 Predecessor Period and the years ended December 31, 2015 and 2014, respectively. Changes in working capital items (decreased) increased cash provided by operating activities by ($2.0) million, $26.2 million, $163.4 million and ($88.6) million for the 2016 Successor Period, the 2016 Predecessor Period and the years ended December 31, 2015 and 2014, respectively. The change in cash provided by operating activities in the Successor and Predecessor periods was primarily due to lower income levels resulting from the industry downturn. Please read “Results of Operations” below for further detail. Included in operating activities for the 2016 Predecessor Period are DIP Facility financing costs of $0.5 million.

Investing Activities. Cash used in investing activities was $2.5 million, $80.1 million, $159.7 million and $367.6 million for the 2016 Successor Period, the 2016 Predecessor Period and the years ended December 31, 2015 and 2014, respectively. Capital expenditures are the main component of our investing activities. The majority of our capital expenditures for the 2016 Successor Period, the 2016 Predecessor Period and the years ended December 31, 2015 and 2014 related to our investment in new PeakeRigs™ and the purchase of certain leased drilling rigs. Additionally, during the 2016 Predecessor Period we purchased hydraulic fracturing equipment with an aggregate of 60,000 horsepower at auction for $10.6 million. We purchased 45 leased drilling rigs for approximately $158.4 million during 2014. Cash used in investing activities was partially offset by proceeds from the sale of Hodges of $15.0 million during 2015 and proceeds from asset sales in the amounts of $10.0 million, $2.6 million, $27.7 million and $88.6 million for the 2016 Successor Period, the 2016 Predecessor Period and the years ended December 31, 2015 and 2014, respectively.

Financing Activities. Net cash (used in) provided by financing activities was ($8.5) million, ($19.2) million, $5.3 million and $101.6 million for the 2016 Successor Period, the 2016 Predecessor Period and the years ended December 31, 2015 and 2014, respectively. We had borrowings and repayments under our credit facility of $160.1 million and $210.6 million, respectively, during 2015. We had borrowings and repayments under our credit facility of $1.201 billion and $1.556 billion, respectively, during 2014. During 2015, we borrowed $100.0 million under the Incremental Term Loan and received net proceeds of $94.5 million. We also repurchased and cancelled $50.0 million in aggregate principal amount of the 2022 Notes in multiple transactions for $31.3 million during 2015. During 2014, we (i) issued $500.0 million in aggregate principal amount of 6.50% Senior Notes due 2022 and used the net proceeds of $493.8 million from the 2022 Notes issuance to make a distribution of approximately $391.0 million to CHK and for general corporate purposes, and (ii) we entered into a $400.0 million seven-year term loan credit agreement and used the net proceeds of $393.9 million to repay and terminate the Old Credit Facility. We paid deferred borrowing costs of $1.2 million, $0.8 million and $3.6 million during the 2016 Predecessor Period and the years ended December 31, 2015 and 2014, respectively. We made term loan repayments of $2.5 million, $17.5 million, $4.8 million and $2.0 million during the 2016 Successor Period, the 2016 Predecessor Period and the years ended December 31, 2015 and 2014, respectively. During 2014, our distributions to CHK were $422.8 million. We withheld employee tax payments on restricted stock vestings totaling $6.0 million, $0.5 million, $1.8 million and $3.2 million during the 2016 Successor Period, the 2016 Predecessor Period and the years ended December 31, 2015 and 2014, respectively.

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Results of Operations

The following table sets forth financial information by operating segment and other selected information for the periods indicated. The 2016 Successor Period, the 2016 Predecessor Period and the years ended December 31, 2015 and 2014 are distinct reporting periods as a result of our emergence from bankruptcy on August 1, 2016. References in this results of operations discussion to “the change” and “the percentage change” combine the Successor Company and Predecessor Company results for the 2016 Successor Period and the 2016 Predecessor Period in order to provide comparability of such 2016 information to our results for the years ended December 31, 2015 and 2014. While this combined presentation is a non-GAAP presentation for which there is no comparable GAAP measure, management believes that providing this financial information is the most relevant and useful method for making comparisons across the periods indicated.

Comparison of Years Ended December 31, 2016 and 2015



	Successor			Predecessor
	(a)			(b)			(c)			(a) + (b) - (c)
	Five Months Ended December 31, 2016			Seven Months Ended July 31, 2016			Year Ended December 31, 2015			Change			% Change
							(In thousands)
Drilling:
Revenue	$	116,731		$	154,794		$	436,404		$	(164,879	)	(38	)%
Operating costs	52,571			57,573			231,544			(121,400		)	(52	)%
Depreciation and amortization	26,979			87,160			163,380			(49,241		)	(30	)%
General and administrative	288			539			33,157			(32,330		)	(98	)%
(Gains) losses on sales of property and equipment, net	(984		)	1,211			10,566			(10,339		)	(98	)%
Impairment of goodwill	—			—			27,434			(27,434		)	(100	)%
Impairments and other	—			3,205			14,329			(11,124		)	(78	)%
Operating Income (Loss)	$	37,877		$	5,106		$	(44,006	)	$	86,989		(198	)%

Hydraulic Fracturing:
Revenue	$	89,493		$	160,723		$	575,495		$	(325,279	)	(57	)%
Operating costs	100,401			158,569			494,554			(235,584		)	(48	)%
Depreciation and amortization	34,079			49,124			70,605			12,598			18	%
General and administrative	399			233			26,057			(25,425		)	(98	)%
Losses on sales of property and equipment, net	31			66			230			(133		)	(58	)%
Operating Loss	$	(45,417	)	$	(47,269	)	$	(15,951	)	$	(76,735	)	481	%

Oilfield Rentals:
Revenue	$	16,154		$	18,402		$	76,587		$	(42,031	)	(55	)%
Operating costs	12,827			20,172			68,317			(35,318		)	(52	)%
Depreciation and amortization	9,032			18,773			41,049			(13,244		)	(32	)%
General and administrative	87			270			9,284			(8,927		)	(96	)%
Gains on sales of property and equipment, net	(590		)	(425		)	(1,780		)	765			(43	)%
Impairments and other	—			287			—			287			n/m
Operating Loss	$	(5,202	)	$	(20,675	)	$	(40,283	)	$	14,406		(36	)%

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	Successor			Predecessor
	(a)			(b)			(c)			(a) + (b) - (c)
	Five Months Ended December 31, 2016			Seven Months Ended July 31, 2016			Year Ended December 31, 2015			Change			% Change
							(In thousands)
Former Oilfield Trucking:
Revenue	$	—		$	—		$	42,739		$	(42,739	)	n/m
Operating costs	—			—			54,674			(54,674		)	n/m
Depreciation and amortization	—			—			8,787			(8,787		)	n/m
General and administrative	—			—			9,249			(9,249		)	n/m
Losses on sales of property and equipment, net	—			—			5,728			(5,728		)	n/m
Impairments and other	—			—			2,737			(2,737		)	n/m
Operating Loss	$	—		$	—		$	(38,436	)	$	38,436		n/m

Consolidated:
Revenue	$	222,378		$	333,919		$	1,131,244		$	(574,947	)	(51	)%
Operating costs	166,726			237,014			855,870			(452,130		)	(53	)%
Depreciation and amortization	73,898			162,425			295,421			(59,098		)	(20	)%
General and administrative	31,808			66,667			112,141			(13,666		)	(12	)%
Loss on sale of a business	—			—			35,027			(35,027		)	(100	)%
(Gains) losses on sales of property and equipment, net	(1,748		)	848			14,656			(15,556		)	(106	)%
Impairment of goodwill	—			—			27,434			—			—	%
Impairments and other	—			6,116			18,632			(12,516		)	(67	)%
Operating Loss	(48,306		)	(139,151		)	(227,937		)	40,480			(18	)%
Interest expense	(15,497		)	(48,116		)	(99,267		)	35,654			(36	)%
Gains on early extinguishment of debt	—			—			18,061			(18,061		)	(100	)%
Loss and impairment from equity investee	—			—			(7,928		)	7,928			(100	)%
Other income	2,112			2,318			3,052			1,378			45	%
Reorganization items, net	(1,868		)	(29,892		)	—			(31,760		)	n/m
Loss Before Income Taxes	(63,559		)	(214,841		)	(314,019		)	35,619			(11	)%
Income Tax Benefit	—			(59,131		)	(92,628		)	33,497			(36	)%
Net Loss	$	(63,559	)	$	(155,710	)	$	(221,391	)	$	2,122		(1	)%
“n/m” means not meaningful.

Revenues

Revenues for 2016, including the Successor Period and the Predecessor Period, decreased $574.9 million, or 51%, from the year ended December 31, 2015 primarily due to decreased utilization and pricing pressure. The percentage of our revenues derived from CHK was 51%, 65% and 70% for the 2016 Successor Period, the 2016 Predecessor Period and the year ended December 31, 2015, respectively. Included in total revenue are amounts related to IBC payments of $38.9 million, $80.7 million and $87.9 million for the 2016 Successor Period, the 2016 Predecessor Period and the year ended December 31, 2015, respectively. Excluding the IBC revenues, the Company has diversified its customer base and increased non-CHK revenue from 32% in 2015 to 58% and 42% in the 2016 Successor Period and the 2016 Predecessor Period, respectively.

Table of Contents

Drilling revenues for 2016, including the Successor Period and the Predecessor Period, decreased $164.9 million, or 38%, from the year ended December 31, 2015, which was primarily due to a 48% decline in revenue days as our average active rig count dropped from 41 in 2015 to 27 in the 2016 Successor Period and 17 in the 2016 Predecessor Period. As of February 9, 2017, our active rig count was 41. Average revenue per revenue day for 2016, including the Successor Period and the Predecessor Period, decreased 15% from 2015. Revenues from non-CHK customers were 46% and 38% of total segment revenues in the 2016 Successor Period and the 2016 Predecessor Period, respectively, compared to 39% for 2015. Excluding IBC revenues, non-CHK drilling revenue increased from 46% in 2015 to 66% and 67% in the 2016 Successor Period and the 2016 Predecessor Period, respectively.

Hydraulic fracturing revenues for 2016, including the Successor Period and the Predecessor Period, decreased $325.3 million, or 57%, from the year ended December 31, 2015, which was primarily due to a 34% decrease in stages completed in addition to a 34% decrease in revenue per stage due to pricing pressure. Revenues from non-CHK customers improved to 49% and 28% of total segment revenues in the 2016 Successor Period and the 2016 Predecessor Period, respectively, compared to 17% for 2015.

Oilfield rental revenues for 2016, including the Successor Period and the Predecessor Period, decreased $42.0 million, or 55%, from the year ended December 31, 2015, which was primarily due to a decline in utilization by CHK and pricing pressure. Revenues from non-CHK customers improved to 68% and 60% of total segment revenues in the 2016 Successor Period and the 2016 Predecessor Period, respectively, compared to 59% for 2015.

Operating Costs

As a percentage of revenues, operating costs were 75% and 71% for the 2016 Successor Period and the 2016 Predecessor Period, respectively, compared to 76% for 2015. Operating costs for 2016, including the Successor Period and Predecessor Period, decreased $452.1 million, or 53%, compared to 2015 primarily due to declines in utilization in each of our segments.

As a percentage of drilling revenues, drilling operating costs were 45%, 37% and 53% for the 2016 Successor Period, the 2016 Predecessor Period and the year ended December 31, 2015, respectively. The decrease from 2015 was primarily due to a higher proportion of IBC rigs, which generate revenue with little associated cost. Drilling operating costs for the 2016 Successor Period and 2016 Predecessor Period decreased $121.4 million, or 52%, from 2015 primarily due to a decrease in labor-related costs and lower fleet utilization.

As a percentage of hydraulic fracturing revenues, hydraulic fracturing operating costs were 112%, 99% and 86% for the 2016 Successor Period, the 2016 Predecessor Period and the year ended December 31, 2015, respectively. The increase from 2015 was due to revenue reductions from pricing pressure outpacing cost reductions, which resulted in a 34% decrease in revenue per stage and a 20% decrease in operating costs per stage in the 2016 Successor Period and 2016 Predecessor Period as compared to 2015. Hydraulic fracturing operating costs for the 2016 Successor Period and the 2016 Predecessor Period decreased $235.6 million, or 48%, from 2015, which was primarily due to a 46% decrease in product costs.

As a percentage of oilfield rental revenues, oilfield rental operating costs were 79%, 110% and 89% for the 2016 Successor Period, the 2016 Predecessor Period and the year ended December 31, 2015, respectively. The change was due to significant declines in fleet utilization, which resulted in revenue reductions from pricing pressure outpacing cost reductions. Oilfield rental operating costs for the 2016 Successor Period and the 2016 Predecessor Period decreased $35.3 million, or 52%, from 2015, which was primarily due to lower utilization and a decrease in labor-related costs.

During 2015, we sold our drilling rig relocation and logistics business and water hauling assets. As of June 30, 2015, there were no remaining assets or operations in the oilfield trucking segment.

Other Financial Statement Items

Depreciation and Amortization. Depreciation and amortization for the 2016 Successor Period, the 2016 Predecessor Period and the year ended December 31, 2015 was $73.9 million, $162.4 million and $295.4 million, respectively. The decrease was due to the revaluation of our assets associated with the adoption of fresh-start accounting. In addition, we also had a change in accounting estimate for estimated useful lives of certain components of drilling rigs and certain drilling rigs in 2015. For further details, see Note 6 “Significant Accounting Policies” of the Notes to Consolidated Financial Statements in Item 8 herein. As a percentage of revenues, depreciation and amortization expense was 33%, 49% and 26% for the 2016 Successor Period, the 2016 Predecessor Period and the year ended December 31, 2015, respectively.

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General and Administrative Expenses. General and administrative expenses for the 2016 Successor Period, the 2016 Predecessor Period and the year ended December 31, 2015 were $31.8 million, $66.7 million and $112.1 million, respectively. General and administrative expenses for corporate functions settled in cash decreased $28.2 million, or 37%, from $75.5 million in 2015 to $18.9 million and $28.3 million in the 2016 Successor Period and the 2016 Predecessor Period, respectively, primarily due to a decline in labor-related costs. As a percentage of revenues, general and administrative expenses settled in cash were 9%, 8% and 7% for the 2016 Successor Period, the 2016 Predecessor Period and the year ended December 31, 2015, respectively. The increase from 2015 was primarily due to a lower revenue base in the 2016 Successor Period and the 2016 Predecessor Period.

Additionally, during the 2016 Successor Period, the 2016 Predecessor Period and the year ended December 31, 2015, we recognized restructuring charges of $2.9 million, $28.1 million and a nominal amount, respectively, primarily related to professional fees incurred prior to the Chapter 11 filing (see Note 3 “Emergence from Voluntary Reorganization under Chapter 11 Proceedings and Related Events” of the Notes to Consolidated Financial Statements in Item 8 herein) and charges incurred related to the former oilfield trucking segment. We incurred non-cash compensation expenses of $9.7 million, $9.7 million and $30.2 million and severance-related costs of $0.2 million, $0.6 million and $6.4 million during the 2016 Successor Period, the 2016 Predecessor Period and year ended December 31, 2015, respectively. Included in the non-cash compensation expenses and severance-related costs for 2015 are $2.1 million and $0.6 million, respectively, related to the sale of Hodges, our previously wholly-owned subsidiary that provided drilling rig relocation and logistic services.

Below is a breakout of general and administrative expenses incurred in the 2016 Successor Period, the 2016 Predecessor Period and year ended December 31, 2015.



	Successor		Predecessor
	Five Months Ended December 31, 2016		Seven Months Ended July 31, 2016		Twelve Months Ended December 31, 2015
			(In thousands)
G&A expenses settled in cash	$	18,936	$	28,310	$	75,474
Restructuring charges	2,920		28,054		(9		)
Non-cash compensation expenses	9,737		9,660		30,244
Severance-related costs	215		643		6,432
Total General and Administrative Expenses	$	31,808	$	66,667	$	112,141

Loss on Sale of a Business. On June 14, 2015, we sold Hodges for aggregate consideration of $42.0 million. We recognized a loss of $35.0 million on the sale during the year ended December 31, 2015.

(Gains) Losses on Sales of Property and Equipment, Net. We recorded (gains) losses on sales of property and equipment of ($1.7) million, $0.8 million and $14.7 million during the 2016 Successor Period, the 2016 Predecessor Period and the year ended December 31, 2015, respectively. During 2015, we sold our water hauling assets for $6.5 million and recognized a loss on the sale of $5.8 million.

Impairment of Goodwill. During the fourth quarter of 2015, we recognized an impairment loss of $27.4 million on goodwill. For further discussion, see Note 6 “Significant Accounting Policies” of the Notes to Consolidated Financial Statements in Item 8 herein.

Impairments and Other. During the 2016 Predecessor Period and the year ended December 31, 2015 we recognized impairments of $6.1 million and $18.6 million, respectively, including impairment charges of $0.3 million and $5.2 million, respectively, for certain drilling rigs that we impaired based on future cash flow of these rigs. Additionally, during the 2016 Predecessor Period and the year ended December 31, 2015 we recognized impairment charges of $2.9 million and $8.7 million, respectively, for drilling-related services equipment that we deemed to be impaired based on the expected future cash flows of this equipment. We also recognized impairment charges of $2.7 million during 2015 for certain trucking and water disposal equipment that we deemed to be impaired based on expected future cash flows of this equipment.

We identified certain other property and equipment during the 2016 Predecessor Period and the year ended December 31, 2015 that we deemed to be impaired based on our assessment of the market value and expected future cash flows of the long-lived asset. We recorded impairment charges of $2.9 million and $2.0 million during the 2016 Predecessor Period and year ended December 31, 2015, respectively, related to these other assets.

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Interest Expense. Interest expense for the 2016 Successor Period, the 2016 Predecessor Period and the year ended December 31, 2015 was $15.5 million, $48.1 million and $99.3 million, respectively, related to borrowings under our senior notes, term loans and credit facility during the 2016 Predecessor and 2015 periods, and related to our term loans and credit facility during the 2016 Successor Period. Subsequent to June 7, 2016, we did not record interest expense on the unsecured debt due to the Chapter 11 cases. Contractual interest expense for the 2016 Predecessor Period was $59.0 million. As a direct result of the reorganization, interest expense decreased $41.0 million during the 2016 Successor Period and the 2016 Predecessor Period compared to the year ended December 31, 2015.

Gains on Extinguishment of Debt. During the year ended December 31, 2015, we repurchased and cancelled $50.0 million in aggregate principal amount of the 2022 Notes in multiple transactions for $31.3 million. We recognized gains on extinguishment of debt of $18.1 million, which included accelerated amortization of deferred financing costs of $0.6 million.

Loss and Impairment from Equity Investees. Loss and impairment from equity investees was $7.9 million for the year ended December 31, 2015, which was a direct result of our 49% membership interest in Maalt Specialized Bulk, L.L.C. (“Maalt”). We recorded a non-cash impairment charge of $8.8 million for the year ended December 31, 2015, which resulted from an excess of carrying value over the estimated fair value for this investment.

Other Income. Other income was $2.1 million, $2.3 million and $3.1 million for the 2016 Successor Period, the 2016 Predecessor Period and year ended December 31, 2015, respectively.

Reorganization items, net. Reorganization items for the 2016 Successor Period and the 2016 Predecessor Period totaled $1.9 million and $29.9 million, respectively. Below is a breakout of charges for each period (in thousands):



	Successor		Predecessor
	Five Months Ended December 31, 2016		Seven Months Ended July 31, 2016
Net gain on settlement of liabilities subject to compromise	$	—	$	(632,059	)
Net loss on fresh-start adjustments	—		596,044
Stock-based compensation acceleration expense	—		25,086
Professional fees	1,868		20,228
Write-off of debt issuance costs	—		13,318
Fair value of warrants issued to Predecessor stockholders	—		6,797
DIP credit agreement financing costs	—		478
Total Reorganization Items, net	$	1,868	$	29,892

Income Tax Benefit. We recorded income tax benefit of $59.1 million and $92.6 million for the 2016 Predecessor Period and the year ended December 31, 2015, respectively. The $33.5 million decrease in income tax benefit is primarily the result of a $99.2 million reduction in pre-tax loss. No corresponding income tax benefit was recorded for the 2016 Successor Period because a full valuation allowance was required to offset the tax benefit calculated at expected rates, given the uncertainty of realization.

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Comparison of Years Ended December 31, 2015 and 2014



	Years Ended December 31,
	2015			2014			Change			% Change
	(In thousands)
Drilling:
Revenue	$	436,404		$	774,530		$	(338,126	)	(44	)%
Operating costs	231,544			499,059			(267,515		)	(54	)%
Depreciation and amortization	163,380			140,884			22,496			16	%
General and administrative	33,157			9,795			23,362			239	%
Losses on sales of property and equipment, net	10,566			17,931			(7,365		)	(41	)%
Impairment of goodwill	27,434			—			27,434			n/m
Impairments and other	14,329			29,602			(15,273		)	(52	)%
Operating (Loss) Income	$	(44,006	)	$	77,259		$	(121,265	)	(157	)%

Hydraulic Fracturing:
Revenue	$	575,495		$	885,907		$	(310,412	)	(35	)%
Operating costs	494,554			735,967			(241,413		)	(33	)%
Depreciation and amortization	70,605			72,105			(1,500		)	(2	)%
General and administrative	26,057			10,965			15,092			138	%
Losses (gains) on sales of property and equipment, net	230			(17		)	247			(1,453	)%
Impairments and other	—			207			(207		)	(100	)%
Operating (Loss) Income	$	(15,951	)	$	66,680		$	(82,631	)	(124	)%

Oilfield Rentals:
Revenue	$	76,587		$	153,120		$	(76,533	)	(50	)%
Operating costs	68,317			102,025			(33,708		)	(33	)%
Depreciation and amortization	41,049			52,680			(11,631		)	(22	)%
General and administrative	9,284			2,565			6,719			262	%
Gains on sales of property and equipment, net	(1,780		)	(2,355		)	575			(24	)%
Impairments and other	—			955			(955		)	(100	)%
Operating Loss	$	(40,283	)	$	(2,750	)	$	(37,533	)	1,365	%

Former Oilfield Trucking:
Revenue	$	42,739		$	190,479		$	(147,740	)	(78	)%
Operating costs	54,674			180,084			(125,410		)	(70	)%
Depreciation and amortization	8,787			21,817			(13,030		)	(60	)%
General and administrative	9,249			4,515			4,734			105	%
Losses (gains) on sales of property and equipment, net	5,728			(21,853		)	27,581			(126	)%
Impairments and other	2,737			—			2,737			n/m
Operating (Loss) Income	$	(38,436	)	$	5,916		$	(44,352	)	(750	)%

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	Years Ended December 31,
	2015			2014			Change			% Change
	(In thousands)
Consolidated:
Revenue	$	1,131,244		$	2,080,892		$	(949,648	)	(46	)%
Operating costs	855,870			1,580,353			(724,483		)	(46	)%
Depreciation and amortization	295,421			292,912			2,509			1	%
General and administrative	112,141			108,139			4,002			4	%
Loss on sale of a business	35,027			—			35,027			n/m
Losses (gains) on sales of property and equipment, net	14,656			(6,272		)	20,928			(334	)%
Impairment of goodwill	27,434			—			27,434			n/m
Impairments and other	18,632			30,764			(12,132		)	(39	)%
Operating (Loss) Income	(227,937		)	74,996			(302,933		)	(404	)%
Interest expense	(99,267		)	(79,734		)	(19,533		)	24	%
Gains on early extinguishment of debt	18,061			—			18,061			n/m
Loss and impairment from equity investee	(7,928		)	(6,094		)	(1,834		)	30	%
Other income	3,052			664			2,388			360	%
Loss Before Income Taxes	(314,019		)	(10,168		)	(303,851		)	2,988	%
Income Tax Benefit	(92,628		)	(2,189		)	(90,439		)	4,132	%
Net Loss	$	(221,391	)	$	(7,979	)	$	(213,412	)	2,675	%
“n/m” means not meaningful.

Revenues

Revenues and Adjusted Revenues for 2015 decreased $949.6 million and $723.3 million, respectively, compared to 2014, primarily due to decreased utilization and increased pricing pressure. The percentage of our revenues derived from CHK was 70% and 81% for 2015 and 2014, respectively.

Below is a reconciliation of Revenues to Adjusted Revenues for 2015 and 2014.



	Years Ended December 31,
	2015		2014
	(in thousands)
Adjusted Revenues^(a):
Revenue	$	1,131,244	$	2,080,892
Less:
Rig relocation and logistics revenues	34,408		120,311
Water hauling revenues	8,331		46,339
Compression unit manufacturing revenues	—		74,650
Geosteering revenues	—		3,940
Crude hauling revenues	—		23,829
Adjusted Revenues	$	1,088,505	$	1,811,823

(a)

“Adjusted Revenues” is a non-GAAP financial measure that we define as revenues before revenues associated with our drilling rig relocation and logistics business and water hauling assets that were sold in the second quarter of 2015, our compression unit manufacturing and geosteering businesses that were distributed to CHK as part of the spin-off and our crude hauling assets that were sold to a third party as part of the spin-off. For a description of our calculation of Adjusted Revenues and the reasons our management uses this measure to evaluate our business, please read “—How We Evaluate Our Operations” and “—Non-GAAP Financial Measures.”

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Drilling revenues for 2015 decreased $338.1 million, or 44%, compared to 2014, due to a 51% decrease in revenue days as our average active rig count dropped from 83 in 2014 to 41 in 2015. Revenues from non-CHK customers were 39% of total segment revenues in 2015, compared to 34% in 2014.

Hydraulic fracturing revenues for 2015 decreased $310.4 million, or 35%, compared to 2014, which was primarily due to a 40% decrease in our revenue per stage from 2014 to 2015, partially offset by an 8% increase in completed stages from 2014 to 2015. The decrease in revenue per stage was primarily due to market pricing pressure. Revenues from non-CHK customers increased to 17% of total segment revenues in 2015, compared to 3% in 2014.

Oilfield rental revenues for 2015 decreased $76.5 million, or 50%, compared to 2014, due to a decline in utilization and pricing pressure. Revenues from non-CHK customers increased to 59% of total segment revenues in 2015, compared to 19% in 2014.

Operating Costs

Operating costs and Adjusted Operating Costs for 2015 decreased $724.5 million and $516.7 million, respectively, compared to 2014. The decrease was primarily due to a decrease in labor-related costs, reduced utilization in our drilling and rental segments, and a decrease in product costs in our hydraulic fracturing segment. As a percentage of Adjusted Revenues, Adjusted Operating Costs were 74% and 73% for 2015 and 2014, respectively. The percentage increase was due to declines in utilization.

Below is a reconciliation of Operating costs to Adjusted Operating Costs for 2015 and 2014.



	Years Ended December 31,
	2015		2014
	(in thousands)
Adjusted Operating Costs^(a):
Operating costs	$	855,870	$	1,580,353
Less:
Rig relocation and logistics operating costs	42,577		104,729
Water hauling operating costs	12,097		48,101
Rig rent expense	—		18,900
Compression unit manufacturing operating costs	—		60,616
Geosteering operating costs	—		2,895
Crude hauling operating costs	—		27,254
Adjusted Operating Costs	$	801,196	$	1,317,858

(a)

“Adjusted Operating Costs” is a non-GAAP financial measure that we define as operating costs before operating costs associated with our drilling rig relocation and logistics business and water hauling assets that were sold in the second quarter of 2015, our compression unit manufacturing and geosteering businesses that were distributed to CHK as part of the spin-off and our crude hauling assets that were sold to a third party as part of the spin-off, further adjusted to subtract rig rent expense. For a description of our calculation of Adjusted Operating Costs and the reasons why our management uses this measure to evaluate our business, please read “—How We Evaluate Our Operations” and “—Non-GAAP Financial Measures.”

As a percentage of drilling revenues, drilling operating costs were 53% and 64% for 2015 and 2014, respectively. The percentage decrease was due to declines in labor-related costs. Drilling operating costs for 2015 decreased $267.5 million, or 54%, from 2014, primarily as result of a decrease in labor-related costs, lower repairs and maintenance expense and the elimination of rig rent expense.

As a percentage of hydraulic fracturing revenues, hydraulic fracturing operating costs increased from 83% in 2014 to 86% in 2015 primarily due to an increase in transportation costs and increased pricing pressure. Hydraulic fracturing operating costs for 2015 decreased $241.4 million, or 33% compared to 2014, primarily due to a decrease in product costs partially offset by higher transportation costs.

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As a percentage of oilfield rental revenues, oilfield rental operating costs were 89% and 67% for 2015 and 2014, respectively. The percentage increase was due to one-time labor-related costs in 2015 and significant declines in fleet utilization without corresponding decreases in operating costs. Oilfield rental operating costs for 2015 decreased $33.7 million, or 33% compared to 2014. The decrease was primarily due to a decrease in repairs and maintenance expense due to lower utilization and a decrease in labor-related costs.

During the second quarter of 2015, we sold our drilling rig relocation and logistics business and water hauling assets. As of June 30, 2015, there were no remaining assets or operations in this former segment.

Other Financial Statement Items

Depreciation and Amortization. Depreciation and amortization for the years ended December 31, 2015 and 2014 was $295.4 million and $292.9 million, respectively. The increase is primarily due to a change in the estimated useful lives of certain components of drilling rigs and certain drilling rigs. For further details, see Note 6 “Significant Accounting Policies” of the Notes to Consolidated Financial Statements in Item 8 herein. As a percentage of revenues, depreciation and amortization expense was 26% and 14% for 2015 and 2014, respectively.

General and Administrative Expenses. General and administrative expenses for the years ended December 31, 2015 and 2014 were $112.1 million and $108.1 million, respectively. General and administrative expenses for corporate functions settled in cash decreased $11.2 million, or 13%, from $86.7 million in 2014 to $75.5 million in 2015, primarily due to a decline in CHK transition services costs. Included in general and administrative expenses settled in cash are corporate overhead charges from CHK for the first half of 2014 totaling $26.8 million, and charges of $8.3 million and $18.0 million, respectively, for services provided by CHK pursuant to the transition services agreement during 2015 and 2014. As a percentage of revenues, general and administrative expenses settled in cash were 7% and 4% for the years ended December 31, 2015 and 2014, respectively.

We incurred non-cash compensation expenses of $30.2 million and $19.4 million in addition to severance-related costs of $6.4 million and $2.0 million for the years ended December 31, 2015 and 2014, respectively. Included in the non-cash compensation expenses and severance-related costs for 2015 are $2.1 million and $0.6 million, respectively, related to our sale of Hodges in the second quarter of 2015.

Below is a breakout of general and administrative expenses incurred in 2015 and 2014.



	Years Ended December 31,
	2015			2014
	(in thousands)
G&A expenses settled in cash	$	75,473		$	86,707
Restructuring charges	(9		)	—
Non-cash compensation expenses	30,244			19,415
Severance-related costs	6,433			2,017
Total General and Administrative Expenses	$	112,141		$	108,139

Loss on Sale of a Business. On June, 14, 2015, we sold Hodges for aggregate consideration of $42.0 million, comprised of $15.0 million in cash and a $27.0 million secured promissory note due June 15, 2020. We recognized a loss of $35.0 million on the sale during 2015.

Losses (Gains) on Sales of Property and Equipment, net. We recorded losses (gains) on sales of property and equipment of approximately $14.7 million and ($6.3) million during the years ended December 31, 2015 and 2014, respectively. During 2015, we sold our water hauling and ancillary equipment not utilized in our business. During 2014, we sold 28 Tier 3 drilling rigs and ancillary drilling equipment and our crude hauling assets, which included 124 fluid handling trucks and 122 trailers.

Impairments and Other. During 2015 and 2014, we recognized impairments of $18.6 million and $30.8 million, respectively. During 2015, we recognized impairment charges of $8.7 million, $5.2 million and $2.7 million related to drilling-

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related services equipment, certain drilling rigs and trucking and fluid disposal equipment, respectively, which we determined were impaired based on the expected future cash flows for these rigs and equipment. During 2014, we recognized impairment charges of $8.4 million related to drilling rigs we deemed to be impaired based on our assessment of future demand and the suitability of the identified rigs in light of this demand. We also paid lease termination costs of $9.7 million during the year ended December 31, 2014. During 2014, we recognized impairments of $11.2 million related to certain drilling rigs and spare equipment that we had identified as held for sale. See Note 9 “Asset Sales and Impairments and Other” of the Notes to Consolidated Financial Statements in Item 8 herein for further details.

We identified certain other property and equipment during the years ended December 31, 2015 and 2014 that we deemed to be impaired based on our assessment of the market value and expected future cash flows of the related long-lived assets. We recorded impairment charges of $2.0 million and $1.5 million during the years ended December 31, 2015 and 2014, respectively, related to these other assets.

Interest Expense. Interest expense for the years ended December 31, 2015 and 2014 was $99.3 million and $79.7 million, respectively, related to borrowings under our senior notes, term loans and credit facility. The increase in interest expense from 2014 to 2015 was primarily due to additional debt issued in conjunction with the spin-off, along with the $100.0 million Incremental Term Loan entered into in 2015. These debt increases were partially offset by the repurchase and cancellation of $50.0 million in aggregate principal amount of 6.50% Senior Notes due 2022.

Gains on Extinguishment of Debt. During 2015, we repurchased and cancelled $50.0 million in aggregate principal amount of the 2022 Notes in multiple transactions for $31.3 million. We recognized gains on extinguishment of debt of $18.1 million, which included accelerated amortization of deferred financing costs of $0.6 million.

Loss and Impairment from Equity Investees. Loss and impairment from equity investees was $7.9 million and $6.1 million for the years ended December 31, 2015 and 2014, respectively, which was a direct result of our 49% membership interest in Maalt. We recorded non-cash impairment charges of $8.8 million and $4.5 million for the years ended December 31, 2015 and 2014, respectively, which resulted from an excess of carrying value over the estimated fair value for this investment.

Other Income. Other income for the years ended December 31, 2015 and 2014 was $3.1 million and $0.7 million, respectively.

Income Tax Benefit. We recorded an income tax benefit of $92.6 million and $2.2 million for the years ended December 31, 2015 and 2014, respectively. The $90.4 million increase in income tax benefit recorded for 2015 was primarily the result of an increase in our pre-tax loss from $10.2 million in 2014 to $314.0 million in 2015. Our effective income tax rate for 2015 and 2014 was 29% and 22%, respectively. The increase in our effective tax rate from 2014 to 2015 was primarily the result of permanent differences having a greater impact on our effective income tax rate due to a lower pre-tax loss base in 2014 compared to 2015.

Contractual Commitments and Obligations

In the normal course of business, we enter into various contractual obligations that impact, or could impact, our liquidity. The following table summarizes our material obligations as of December 31, 2016:



	Payments Due by Period
			Less Than		1-3		4-5		More Than
	Total		1 Year		Years		Years		5 Years
	(unaudited)
	(in thousands)
Principal amount of Term Loans^(a)	$	473,250	$	5,000	$	10,000	$	458,250	$	—
Interest^(b)	89,904		23,714		46,651		19,539		—
Operating leases^(c)	7,982		3,707		3,785		490		—
Total	$	571,136	$	32,421	$	60,436	$	478,279	$	—


(a)	Represents contractual redemption value.


(b)	Amount includes contractual interest payments on the Term Loans.

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(c)	Consists primarily of rail car leases. Amounts disclosed assume no exercise of options to renew or extend the leases. Please read Note 13 “Commitments and Contingencies” of the Notes to Consolidated Financial Statements in Item 8 herein.

Off-Balance Sheet Arrangements

As of December 31, 2016, we were party to five lease agreements with various third parties to utilize 724 lease rail cars for initial terms of five to seven years. Additional rental payments are required for the use of rail cars in excess of the allowable mileage stated in the respective agreement. We account for these leases as operating leases.

As of December 31, 2016, we were also party to various lease agreements for other property and equipment with varying terms. We account for these leases as operating leases.

Aggregate undiscounted minimum future lease payments as of December 31, 2016 under our rail car and other operating leases are presented below:



	Rail Cars		Other		Total
	(in thousands)
2017	$	3,290	$	417	$	3,707
2018	2,165		259		2,424
2019	1,331		30		1,361
2020	490		—		490
Total	$	7,276	$	706	$	7,982

Critical Accounting Policies

Our consolidated financial statements are prepared in accordance with generally accepted accounting principles in the United States of America, which require us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reported periods.

Property and Equipment

Property and equipment are carried at cost less accumulated depreciation. Depreciation is calculated using the straight-line method, based on estimates, assumptions and judgments relative to the assets’ estimated useful lives and salvage values. These estimates are based on various factors, including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Upon the disposition of an asset, we eliminate the cost and related accumulated depreciation and include any resulting gain or loss in the consolidated statements of operations as (gains) losses on the sale of property and equipment. Expenditures for maintenance and repairs that do not add capacity or extend the useful life of an asset are expensed as incurred.

Impairment of Long-Lived Assets

We review our long-lived assets, such as property and equipment, whenever, in management’s judgment, events or changes in circumstances indicate the carrying amount of the assets may not be fully recoverable. Factors that might indicate a potential impairment include a significant decrease in the market value of the long-lived asset, a significant change in the long-lived asset’s physical condition, a change in industry conditions or a reduction in cash flows associated with the use of the long-lived asset. If these or other factors indicate the carrying amount of the asset may not be recoverable, we determine whether an impairment has occurred through analysis of the future undiscounted cash flows of the asset. If an impairment has occurred, we

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recognize a loss for the difference between the carrying amount and the fair market value of the asset. We measure the fair value of the asset using market prices or, in the absence of market prices, based on an estimate of discounted cash flows.

Goodwill

Goodwill represents the cost in excess of fair value of the net assets of businesses acquired. Goodwill is not amortized. We reviewed goodwill for impairment annually on October 1 or more frequently if events or changes in circumstances indicated that the carrying amount of the reporting unit exceeds its fair value. Circumstances that could indicate a potential impairment include a significant adverse change in the economic or business climate, a significant adverse change in legal factors, an adverse action or assessment by a regulator, unanticipated competition, loss of key personnel and the likelihood that a reporting unit or significant portion of a reporting unit will be sold or otherwise disposed of. We have the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of one of our reporting units is greater than its carrying amount. If, after assessing the totality of events or circumstances, we determine it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, then there is no need to perform any further testing. However, if we conclude otherwise, accounting guidance requires a two-step process for testing impairment. First, the fair value of each reporting unit is compared to its carrying value to determine whether an indication of impairment exists. Second, if impairment is indicated, the fair value of the reporting unit’s goodwill is determined by allocating the unit’s fair value to its assets and liabilities (including any unrecognized intangible assets) as if the reporting unit had been acquired in a business combination on the impairment test date. The amount of impairment for goodwill is measured as the excess of the carrying value of the reporting unit over its fair value. We have the option to bypass the qualitative assessment for any reporting unit in any period and proceed directly to performing the first step of the two-step goodwill impairment test.

When estimating fair values of a reporting unit for our goodwill impairment test, we use the income approach. The income approach provides an estimated fair value based on the reporting unit’s anticipated cash flows that are discounted using a weighted average cost of capital rate. Estimated cash flows are primarily based on projected revenues, operating expenses and capital expenditures and are discounted using comparable industry average rates for weighted average cost of capital.

In response to further deterioration of industry conditions in the fourth quarter of 2015, the Company determined that there were indications of impairment present. During the fourth quarter of 2015, the Company completed its assessment and recognized an impairment loss of $27.4 million on the goodwill associated with the Bronco acquisition. As of December 31, 2016 and 2015, we had no recorded goodwill on our consolidated balance sheet.

Revenue Recognition

We recognize revenue when services are performed, collection of receivables is reasonably assured, persuasive evidence of an arrangement exists and the price is fixed or determinable.

Drilling. We earn revenues by drilling oil and natural gas wells for our customers under daywork contracts. We recognize revenue on daywork contracts for the days completed based on the day rate each contract specifies. Payments received and costs incurred for mobilization services are recognized as earned over the days of mobilization. We also recognize revenue for contract termination fees paid by our customers. Under certain of our contracts, we have agreed to allow customers to pay the termination cost over the life of the contract in lieu of a lump sum, and we refer to a rig in this circumstance as “idle but contracted” or “IBC”. IBC payments are structured to preserve our anticipated operating margins for the affected rigs through the end of the contract terms and are recognized as revenue over the life of the contract.

Hydraulic Fracturing. We recognize revenue upon the completion of each fracturing stage. We typically complete one or more fracturing stages per day per active crew during the course of a job. A stage is considered complete when the customer requests or the job design dictates that pumping discontinue for that stage. Invoices typically include a lump sum equipment charge determined by the rate per stage each contract specifies and product charges for sand, chemicals and other products actually consumed during the course of providing our services.

Oilfield Rentals. We rent many types of oilfield equipment, including drill pipe, drill collars, tubing, blowout preventers, frac tanks, mud tanks and environmental containment. We also provide air drilling, flowback services and services associated with the transfer of water to the wellsite for well completions. We price our rentals and services by the day or hour based on the type of equipment rented and the services performed and recognize revenue ratably over the term of the rental.

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Former Oilfield Trucking. During the second quarter of 2015, we sold our drilling rig relocation and logistics business and water hauling assets. As of June 30, 2015, there were no remaining assets or operations in this former segment.

Income Taxes

A valuation allowance for deferred tax assets is recognized when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. To assess that likelihood, we use estimates and judgment regarding our future taxable income, as well as the jurisdiction in which such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include our current financial position, our results of operations, both actual and forecasted, the reversal of deferred tax liabilities, and tax planning strategies as well as the current and forecasted business economics of our industry. As of December 31, 2016, we are in a net deferred tax asset position. We believe it is more likely than not that these deferred tax assets will not be realized, and accordingly, we have recorded a full valuation allowance against our net deferred tax assets.

The benefit of an uncertain tax position taken or expected to be taken on an income tax return is recognized in the consolidated financial statements at the largest amount that is more likely than not to be sustained upon examination by the relevant taxing authority. Interest and penalties, if any, related to uncertain tax positions would be recorded in interest expense and other expense, respectively. We had no uncertain tax positions as of December 31, 2016 and 2015.

New Accounting Pronouncements

In October 2016, the FASB issued ASU No. 2016-16, “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Inventory”, which updates previously issued standards to improve the income tax consequences of intra-entity transfers of assets other than inventory. This ASU is effective for annual reporting periods beginning after December 15, 2017, with early adoption permitted. We are currently evaluating what impact this standard will have on our consolidated financial statements.

In August 2016, the FASB issued ASU No. 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments,” which amends eight specific cash flow issues with the objective of reducing diversity in practice. This ASU is effective for annual reporting periods beginning after December 15, 2017, with early adoption permitted. We are currently evaluating what impact this standard will have on our consolidated financial statements.

In February 2016, the FASB issued ASU No. 2016-02, “Leases,” which modifies the lease recognition requirements and requires entities to recognize the assets and liabilities arising from leases on the balance sheet. ASU 2016-02 is effective for annual reporting periods beginning after December 15, 2018, with early adoption permitted. We are currently evaluating what impact this standard will have on our consolidated financial statements.

In January 2016, the FASB issued ASU No. 2016-01, “Financial Instruments - Overall,” which requires separate presentation of financial assets and liabilities on the balance sheet and requires evaluation of the need for valuation allowance of deferred tax assets related to available-for-sale securities. ASU 2016-01 is effective for annual reporting periods beginning after December 15, 2017, with early adoption not permitted. We do not expect the adoption of this guidance will have a material effect on our consolidated financial statements.

In July 2015, the FASB issued ASU No. 2015-11, “Inventory (Topic 330): Simplifying the Measurement of Inventory,” which changes inventory measured using any method other than LIFO or the retail inventory method (for example, inventory measured using first-in, first-out (FIFO) or average cost) at the lower of cost and net realizable value. ASU 2015-11 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption permitted. We do not expect the adoption of this guidance will have a material effect on our consolidated financial statements.

In August 2014, the FASB issued ASU No. 2014-15, “Presentation of Financial Statements - Going Concern,” which requires management to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued (or within one year after the date that the financial statements are available to be issued when applicable). ASU 2014-15 is effective for fiscal years, and interim periods within those years, ending after December 15, 2016. Adoption of this standard had no impact on our consolidated financial statements.

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In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers,” which supersedes the revenue recognition requirements in “Revenue Recognition (Topic 605)” and requires entities to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services. In August 2015, the FASB deferred the effective date of ASU No. 2014-09 to annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period; the FASB also provided for early adoption for annual reporting periods beginning after December 15, 2016. We are currently evaluating what impact this standard, including related ASU Nos. 2016-08, 2016-10, 2016-12 and 2016-20, will have on our consolidated financial statements.

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Item 7A.	Quantitative and Qualitative Disclosures About Market Risk

Historically, we have provided a significant percentage of our oilfield services to CHK and its working interest partners. For the 2016 Successor Period, the 2016 Predecessor Period and the years ended December 31, 2015 and 2014, CHK accounted for approximately 51%, 65%, 70% and 81% of our revenues, respectively. The decline in commodity prices since mid-2014 has had an adverse effect on CHK’s and our other customers’ capital spending, which has adversely impacted our cash flows and financial position. While industry activity, commodity prices and pricing for our services have shown recent signs of improvement, a sustained recovery is not certain. A return to reduced activity and pricing could have a further adverse effect on our customers’ capital spending. This would likely have a material adverse impact on our cash flows and financial position and could adversely affect our ability to comply with the financial covenant under our credit facility and limit our ability to fund our planned capital expenditures.

Changes in interest rates affect the amount of interest we earn on our cash, cash equivalents and short-term investments and the interest rate we pay on borrowings under our credit facility and term loans. We have borrowings outstanding under our term loans and may in the future borrow under fixed rate and variable rate debt instruments that give rise to interest rate risk. For fixed rate debt, changes in interest rates generally affect the fair value of the debt instrument, but not our earnings or cash flows. Conversely, for variable rate debt, changes in interest rates generally do not impact the fair value of the debt instrument, but may affect our future earnings and cash flows. Our primary exposure to interest rate risk results from outstanding borrowings under our credit facility and term loans.

Borrowings under our term loans bear interest based on the London Interbank Offered Rate (“LIBOR”). Based on the outstanding borrowings under our term loans at December 31, 2016, a one percentage point increase or decrease in LIBOR would result in approximately a $4.7 million increase or decrease in interest expense annually.

The following table provides information about our debt instruments that are sensitive to changes in interest rates. The table presents principal cash flows and related weighted-average interest rates by expected maturity dates. Weighted-average variable rates are based on effective rates at December 31, 2016.



	Floating Rate Maturity		Average Interest Rate
	(in thousands)
2017	$	5,000	5.110	%
2018	5,000		5.110	%
2019	5,000		5.110	%
2020	379,000		3.903	%
2021	79,250		10.000	%
Total	$	473,250
Fair Value	$	469,377

Our fuel costs, which consist primarily of diesel fuel used by our various trucks and other equipment, can expose us to commodity price risk and, as our hydraulic fracturing operations grow, we will face increased risks associated with the prices of materials used in hydraulic fracturing, such as sand and chemicals. The prices for fuel and these materials can be volatile and are impacted by changes in supply and demand, as well as market uncertainty and regional shortages. We currently do not hedge our exposure to these risks.

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Item 8.	Financial Statements and Supplementary Data



INDEX TO FINANCIAL STATEMENTS
SEVENTY SEVEN ENERGY INC.
	Page
Consolidated Financial Statements:
Reports of Independent Registered Public Accounting Firm	62
Consolidated Balance Sheets at December 31, 2016 and 2015	64
Consolidated Statements of Operations for the Five Months Ended December 31, 2016 (Successor), Seven Months Ended July 31, 2016 (Predecessor), and Years Ended December 31, 2015 and 2014 (Predecessor)	65
Consolidated Statements of Changes in Equity for the Five Months Ended December 31, 2016 (Successor), Seven Months Ended July 31, 2016 (Predecessor), and Years Ended December 31, 2015 and 2014 (Predecessor)	66
Consolidated Statements of Cash Flows for the Five Months Ended December 31, 2016 (Successor), Seven Months Ended July 31, 2016 (Predecessor), and Years Ended December 31, 2015 and 2014 (Predecessor)	67
Notes to Consolidated Financial Statements	69

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of Seventy Seven Energy Inc.

In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations, of changes in equity and of cash flows present fairly, in all material respects, the financial position of Seventy Seven Energy Inc. and its subsidiaries (Successor) as of December 31, 2016 and the results of their operations and their cash flows for the five months ended December 31, 2016 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

As discussed in Note 3 to the consolidated financial statements, the United States Bankruptcy Court for the district of Delaware confirmed the Company's Joint Pre-packaged Plan of Reorganization (the "Plan") on July 14, 2016. Confirmation of the Plan resulted in the discharge of certain debt of the Company and substantially altered rights and interests of debt and equity security holders as provided for in the Plan. The Plan was substantially consummated on August 1, 2016 and the Company emerged from bankruptcy. In connection with its emergence from bankruptcy, the Company adopted fresh-start accounting as of August 1, 2016.

/s/ PricewaterhouseCoopers LLP

Oklahoma City, Oklahoma

February 13, 2017

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of Seventy Seven Energy Inc.

In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations, of changes in equity and of cash flows present fairly, in all material respects, the financial position of Seventy Seven Energy Inc. and its subsidiaries (Predecessor) as of December 31, 2015 and the results of their operations and their cash flows for the seven months ended July 31, 2016, and for each of the two years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 3 to the consolidated financial statements, the Company filed a petition on June 7, 2016 with the United States Bankruptcy Court for the district of Delaware for reorganization under the provisions of Chapter 11 of the Bankruptcy Code. The Company’s Joint Pre-packaged Plan of Reorganization was substantially consummated on August 1, 2016 and the Company emerged from bankruptcy. In connection with its emergence from bankruptcy, the Company adopted fresh-start accounting.

/s/ PricewaterhouseCoopers LLP

Oklahoma City, Oklahoma

February 13, 2017

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SEVENTY SEVEN ENERGY INC.

(Debtor-in-possession June 7, 2016 through July 31, 2016)

Consolidated Balance Sheets

(in thousands, except share amounts)



	Successor			Predecessor
	December 31, 2016			December 31, 2015

Assets:
Current Assets:
Cash	$	48,654		$	130,648
Accounts receivable, net of allowance of $59 and $3,680 at December 31, 2016 and December 31, 2015, respectively	99,530			164,721
Inventory	12,935			18,553
Deferred income tax asset	—			1,499
Prepaid expenses and other	14,414			17,141
Total Current Assets	175,533			332,562
Property and Equipment:
Property and equipment, at cost	813,291			2,646,446
Less: accumulated depreciation	(71,977		)	(1,116,026		)
Property and equipment held for sale, net	8,226			—
Total Property and Equipment, Net	749,540			1,530,420
Other Assets:
Deferred financing costs	1,132			1,238
Other long-term assets	22,345			38,398
Total Other Assets	23,477			39,636
Total Assets	$	948,550		$	1,902,618
Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts payable	$	15,590		$	53,767
Current portion of long-term debt	5,000			5,000
Other current liabilities	49,776			98,318
Total Current Liabilities	70,366			157,085
Long-Term Liabilities:
Deferred income tax liabilities	—			60,623
Long-term debt, less current maturities	425,212			1,564,592
Other long-term liabilities	1,724			1,478
Total Long-Term Liabilities	426,936			1,626,693
Commitments and Contingencies (Note 13)
Stockholders’ Equity:
Predecessor common stock, $0.01 par value: authorized 250,000,000 shares; issued and outstanding 59,397,831 shares at December 31, 2015	—			594
Predecessor paid-in capital	—			350,770
Successor preferred stock, $0.01 par value: authorized 10,000,000 shares; zero outstanding at December 31, 2016	—			—
Successor common stock, $0.01 par value: authorized 90,000,000 shares; issued and outstanding 22,353,536 shares at December 31, 2016	224			—
Successor paid-in capital	514,583			—
Accumulated deficit	(63,559		)	(232,524		)
Total Stockholders’ Equity	451,248			118,840
Total Liabilities and Stockholders’ Equity	$	948,550		$	1,902,618

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

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SEVENTY SEVEN ENERGY INC.

(Debtor-in-possession June 7, 2016 through July 31, 2016)

Consolidated Statements of Operations

(in thousands, except share amounts)



	Successor			Predecessor
	Five Months Ended			Seven Months Ended			Years Ended December 31,
	December 31, 2016			July 31, 2016			2015			2014

Revenues:
Revenues	$	222,378		$	333,919		$	1,131,244		$	2,080,892
Operating Expenses:
Operating costs	166,726			237,014			855,870			1,580,353
Depreciation and amortization	73,898			162,425			295,421			292,912
General and administrative	31,808			66,667			112,141			108,139
Loss on sale of a business	—			—			35,027			—
(Gains) losses on sales of property and equipment, net	(1,748		)	848			14,656			(6,272		)
Impairment of goodwill	—			—			27,434			—
Impairments and other	—			6,116			18,632			30,764
Total Operating Expenses	270,684			473,070			1,359,181			2,005,896
Operating (Loss) Income	(48,306		)	(139,151		)	(227,937		)	74,996
Other (Expense) Income:
Interest expense	(15,497		)	(48,116		)	(99,267		)	(79,734		)
Gains on early extinguishment of debt	—			—			18,061			—
Loss and impairment from equity investees	—			—			(7,928		)	(6,094		)
Other income	2,112			2,318			3,052			664
Reorganization items, net (Note 5)	(1,868		)	(29,892		)	—			—
Total Other Expense	(15,253		)	(75,690		)	(86,082		)	(85,164		)
Loss Before Income Taxes	(63,559		)	(214,841		)	(314,019		)	(10,168		)
Income Tax Benefit	—			(59,131		)	(92,628		)	(2,189		)
Net Loss	$	(63,559	)	$	(155,710	)	$	(221,391	)	$	(7,979	)

Loss Per Common Share (Note 7)

Basic	$	(2.86	)	$	(2.84	)	$	(4.42	)	$	(0.17	)
Diluted	$	(2.86	)	$	(2.84	)	$	(4.42	)	$	(0.17	)

Weighted Average Common Shares Outstanding (Note 7)
Basic	22,186			54,832			50,096			47,236
Diluted	22,186			54,832			50,096			47,236

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

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SEVENTY SEVEN ENERGY INC.

(Debtor-in-possession June 7, 2016 through July 31, 2016)

Consolidated Statements of Changes in Equity



	Common Stock		Common Stock			Paid-in Capital			Owner’s Equity			Accumulated Deficit			Total Stockholders’ / Owner’s Equity
	(Shares)		(in thousands)
Balance at December 31, 2013 (Predecessor)	—		$	—		$	—		$	547,192		$	—		$	547,192
Net income (loss)	—		—			—			3,154			(11,133		)	(7,979		)
Contributions from Chesapeake	—		—			—			190,297			—			190,297
Distributions to Chesapeake	—		—			—			(482,001		)	—			(482,001		)
Reclassification of owner’s equity to paid-in capital	—		—			258,642			(258,642		)	—			—
Issuance of common stock at spin-off	46,932		469			(469		)	—			—			—
Share-based compensation	4,227		43			43,471			—			—			43,514
Balance at December 31, 2014 (Predecessor)	51,159		$	512		$	301,644		$	—		$	(11,133	)	$	291,023
Net loss	—		—			—						(221,391		)	(221,391		)
Share-based compensation	8,239		82			49,126						—			49,208
Balance at December 31, 2015 (Predecessor)	59,398		$	594		$	350,770		$	—		$	(232,524	)	$	118,840
Net loss	—		—			—			—			(155,710		)	(155,710		)
Share-based compensation	(1,930	)	(19		)	36,889			—			—			36,870
Balance at July 31, 2016 (Predecessor)	57,468		$	575		$	387,659		$	—		$	(388,234	)	$	—
Cancellation of Predecessor equity	(57,468	)	(575		)	(387,659		)	—			388,234			—
Balance at August 1, 2016 (Predecessor)	—		$	—		$	—		$	—		$	—		$	—


Issuance of Successor common stock and warrants	22,000		220			510,010			—			—			510,230
Balance at August 1, 2016 (Successor)	22,000		$	220		$	510,010		$	—		$	—		$	510,230
Net loss	—		—			—			—			(63,559		)	(63,559		)
Share-based compensation	353		4			4,571			—			—			4,575
Shares issued for warrants exercised	1		—			2			—			—			2
Balance at December 31, 2016 (Successor)	22,354		$	224		$	514,583		$	—		$	(63,559	)	$	451,248

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

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SEVENTY SEVEN ENERGY INC.

(Debtor-in-possession June 7, 2016 through July 31, 2016)

Consolidated Statements of Cash Flows

(in thousands)



	Successor			Predecessor
	Five Months Ended			Seven Months Ended			Years Ended December 31,
	December 31, 2016			July 31, 2016			2015			2014
Cash Flows from Operating Activities:
Net Loss	$	(63,559	)	$	(155,710	)	$	(221,391	)	$	(7,979	)
Adjustments to Reconcile Net Loss to Cash Provided by Operating Activities:
Depreciation and amortization	73,898			162,425			295,421			292,912
Amortization of sale/leaseback gains	—			—			—			(5,414		)
Accretion of discount on term loans	5,192			—			—			—
Accretion of discount on note receivable	(694		)	—			—			—
Amortization of deferred financing costs	103			2,455			4,623			6,122
Gains on early extinguishment of debt	—			—			(18,061		)	—
Loss on sale of a business	—			—			35,027			—
(Gains) losses on sales of property and equipment	(1,748		)	848			14,656			(6,272		)
Impairment of goodwill	—			—			27,434			—
Impairments of long-lived assets	—			6,116			18,632			21,063
Loss and impairment from equity investees	—			—			7,928			6,094
Non-cash reorganization items, net	—			9,185			—			—
Provision for doubtful accounts	16			1,406			1,375			2,887
Non-cash compensation	10,577			12,635			48,509			47,184
Deferred income tax benefit	—			(59,124		)	(92,686		)	(2,863		)
Other	68			(10		)	(717		)	150
Changes in operating assets and liabilities,
Accounts receivable	(5,250		)	69,291			236,977			(81,001		)
Inventory	487			5,131			7,099			(6,543		)
Accounts payable	(5,828		)	(32,349		)	9,109			(11,954		)
Other current liabilities	8,418			(17,872		)	(89,650		)	9,949
Other	210			2,042			(179		)	961
Net cash provided by operating activities	21,890			6,469			284,106			265,296
Cash Flows from Investing Activities:
Additions to property and equipment	(12,502		)	(82,787		)	(205,706		)	(457,618		)
Purchases of short-term investments	—			(6,242		)	—			—
Proceeds from sales of assets	9,985			2,638			27,695			88,556
Proceeds from sale of a business	—			—			15,000			—
Proceeds from sales of short-term investments	—			6,236			—			—
Additions to investments	—			—			(113		)	(675		)
Other	35			29			3,457			2,091
Net cash used in investing activities	(2,482		)	(80,126		)	(159,667		)	(367,646		)
Cash Flows from Financing Activities
Borrowings from revolving credit facility	—			—			160,100			1,201,400
Payments on revolving credit facility	—			—			(210,600		)	(1,555,900		)
Proceeds from issuance of senior notes, net of offering costs	—			—			—			493,825
Payments to extinguish senior notes	—			—			(31,305		)	—
Proceeds from issuance of term loan, net of issuance costs	—			—			94,481			393,879
Payments on term loans	(2,500		)	(17,500		)	(4,750		)	(2,000		)
Deferred financing costs	—			(1,235		)	(784		)	(3,597		)
Distributions to CHK	—			—			—			(422,839		)
Employee tax withholding on restricted stock vestings	(6,004		)	(506		)	(1,824		)	(3,205		)
Net cash (used in) provided by financing activities	(8,504		)	(19,241		)	5,318			101,563
Net increase (decrease) in cash	10,904			(92,898		)	129,757			(787		)
Cash, beginning of period	37,750			130,648			891			1,678
Cash, end of period	$	48,654		$	37,750		$	130,648		$	891

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SEVENTY SEVEN ENERGY INC.

(Debtor-in-possession June 7, 2016 through July 31, 2016)

Consolidated Statements of Cash Flows - (Continued)



	Successor			Predecessor
	Five Months Ended			Seven Months Ended			Years Ended December 31,
	December 31, 2016			July 31, 2016			2015			2014

Supplemental Disclosure of Significant Non-Cash Investing and Financing Activities:
(Decrease) increase in other current liabilities related to purchases of property and equipment	$	(590	)	$	(3,351	)	$	(20,016	)	$	18,999
Note receivable received as consideration for sale of a business	$	—		$	—		$	27,000		$	—
Property and equipment distributed to Chesapeake at spin-off	$	—		$	—		$	—		$	(792	)
Property and equipment contributed from Chesapeake at spin-off	$	—		$	—		$	—		$	190,297
Supplemental Disclosure of Cash Payments:
Interest, net of amount capitalized	$	8,830		$	30,814		$	96,730		$	54,439

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

SEVENTY SEVEN ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Basis of Presentation and Spin-off

Basis of Presentation

The accompanying consolidated financial statements and related notes include the accounts of Seventy Seven Energy Inc. (“SSE”, “we”, “us”, “our”, “Company”, or “ours”) and its subsidiaries, all of which are 100% owned. SSE’s accounting and financial reporting policies conform to accounting principles and practices generally accepted in the United States of America (“GAAP”). All significant intercompany accounts and transactions within SSE have been eliminated.

On June 7, 2016 (the “Petition Date”), SSE and its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Code in the United States Bankruptcy Court for the District of Delaware, case number 16-11409. The Debtors continued to operate their business as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court. The subsidiary Debtors in these Chapter 11 cases were Seventy Seven Operating LLC, Seventy Seven Land Company LLC, Seventy Seven Finance Inc., Performance Technologies, L.L.C., PTL Prop Solutions, L.L.C., Western Wisconsin Sand Company, LLC, Nomac Drilling, L.L.C., SSE Leasing LLC, Keystone Rock & Excavation, L.L.C. and Great Plains Oilfield Rental, L.L.C., which represent all subsidiaries of SSE. On July 14, 2016, the Bankruptcy Court issued an order confirming the Joint Pre-packaged Plan of Reorganization of the Debtors. On August 1, 2016, the Plan became effective pursuant to its terms and the Debtors emerged from their Chapter 11 cases.

Subsequent to the Petition Date, all expenses, gains and losses directly associated with the reorganization are reported within “Reorganization items, net” in the accompanying statements of operations.

References to “Successor” or “Successor Company” relate to SSE on and subsequent to August 1, 2016. References to “Predecessor” or “Predecessor Company” relate to SSE prior to August 1, 2016. References to “2016 Successor Period” and “2016 Predecessor Period” relate to the five months ended December 31, 2016 and the seven months ended July 31, 2016, respectively.

Spin-Off

On June 9, 2014, Chesapeake Energy Corporation (“CHK”) announced that its board of directors approved the spin-off of its oilfield services division through the pro rata distribution of 100% of the shares of common stock of SSE to CHK’s shareholders of record as of the close of business on June 19, 2014, the record date. On June 30, 2014, each CHK shareholder received one share of SSE common stock for every fourteen shares of CHK common stock held by such shareholder on the record date, and SSE became an independent, publicly traded company as a result of the distribution. The transactions in which SSE became an independent, publicly traded company, including the distribution, are referred to collectively as the “spin-off”. Prior to the spin-off, we conducted our business as CHK Oilfield Operating, L.L.C. (“COO”), a wholly owned subsidiary of CHK. Following the spin-off, CHK retained no ownership interest in SSE, and each company has separate public ownership, boards of directors and management. A registration statement on Form 10, as amended through the time of its effectiveness, describing the spin-off was filed by SSE with the U.S. Securities and Exchange Commission (“SEC”) and was declared effective on June 17, 2014. See Note 19 for further discussion of agreements entered into as part of the spin-off, including a master separation agreement, a transition services agreement, an employee matters agreement and a tax sharing agreement, among others. As part of the spin-off, we completed the following transactions, among others:


•	we entered into a new $275.0 million senior secured revolving credit facility (the “Pre-Petition Credit Facility”) and a $400.0 million secured term loan (the “Term Loan”). We used the proceeds from borrowings under these new facilities to repay in full and terminate our $500.0 million senior secured revolving credit facility (the “Old Credit Facility”).


•	we issued new 6.50% senior unsecured notes due 2022 (the “2022 Notes”) and used the net proceeds of approximately $493.8 million to make a cash distribution of approximately $391.0 million to CHK, to repay a portion of outstanding indebtedness under the Pre-Petition Credit Facility, and for general corporate purposes.


•	we distributed our compression unit manufacturing and geosteering businesses to CHK.

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•	we sold our crude hauling assets to a third party and used a portion of the net proceeds received to make a $30.9 million cash distribution to CHK.


•	CHK transferred to us buildings and real estate used in our business, including property and equipment, at cost of approximately $212.5 million and accumulated depreciation of $22.2 million as of the date of the spin-off.


•	COO transferred all of its existing assets, operations and liabilities, including our 6.625% senior unsecured notes due 2019 (the “2019 Notes”), to Seventy Seven Operating LLC (“SSO”), an Oklahoma limited liability company, our direct wholly-owned subsidiary and the owner of all our operating subsidiaries.


•	COO was renamed SSE and converted from a limited liability company to a corporation.

2. Patterson-UTI Merger Agreement

On December 12, 2016, SSE entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Patterson-UTI Energy, Inc., a Delaware corporation (“Patterson-UTI”), and Pyramid Merger Sub, Inc., a Delaware corporation and a direct, wholly owned subsidiary of Patterson-UTI (“Merger Sub”), pursuant to which Patterson-UTI will acquire SSE in exchange for newly issued shares of Patterson-UTI common stock, par value $0.01 per share (“Patterson-UTI Common Stock”). The Merger Agreement provides that, upon the terms and subject to the conditions set forth therein, Merger Sub will be merged with and into SSE, with SSE continuing as the surviving entity and a wholly owned subsidiary of Patterson-UTI (the “Merger”).

Under the terms and conditions of the Merger Agreement, at the effective time of the Merger (the “Effective Time”), each issued and outstanding share of SSE common stock, par value $0.01 per share (“SSE Common Stock”), will be converted into the right to receive a number of shares of Patterson-UTI Common Stock equal to the exchange ratio, as described in the next sentence. The exchange ratio will be equal to 49,559,000 shares of Patterson-UTI Common Stock, divided by the total number of shares of SSE outstanding or deemed outstanding immediately prior to the effective time (including, among other things, shares issued upon exercise of warrants to acquire SSE Common Stock and restricted stock units that are exercised or deemed exercised); provided that, in the event that any Series A warrants to acquire SSE Common Stock are forfeited or net settled, such 49,559,000 shares of Patterson-UTI Common Stock will be reduced by a number equal to (i) the aggregate exercise price for the warrants that are forfeited or net settled, divided by (ii) the volume weighted average price of a share of Patterson-UTI Common Stock for the 10 consecutive trading days immediately preceding the 3rd business day prior to the closing. In no event will Patterson-UTI issue more than 49,559,000 of its shares as merger consideration.

The value of the merger consideration that SSE stockholders receive will depend on the price per share of Patterson-UTI common stock at the effective time. In addition, the value of the merger consideration is dependent upon the exchange ratio. The exchange ratio will be 1.7725 if all outstanding Series A Warrants of SSE are exercised for cash, no other warrants are exercised, no other shares of SSE are issued prior to closing and certain other assumptions set forth in the joint proxy statement/prospectus occur. The exchange ratio will be reduced if holders of Series A Warrants of SSE fail to exercise their warrants by tendering the cash exercise price, either by forfeiting the warrants or by net share settling such warrants. The exchange ratio will also be reduced if Series B or Series C Warrants of SSE—all of which are presently “out-of-the-money”—nevertheless exercise their warrants. The exchange ratio will further be reduced by any additional restricted stock unit awards granted by SSE for retention purposes, which will not exceed 300,000 restricted stock units in the aggregate.

In connection with the Merger, each SSE restricted stock unit award granted prior to December 12, 2016 that is outstanding as of the Effective Time will fully vest immediately prior to the closing of the Merger, and such awards will be treated as shares of SSE Common Stock and receive the merger consideration in respect of each share of SSE Common Stock subject to the award. In addition, at the Effective Time, each SSE restricted stock unit award granted on or following December 12, 2016 will be assumed by Patterson-UTI and converted into a restricted stock unit award covering a number of shares of Patterson-UTI Common Stock equal to (i) the number of shares of SSE Common Stock subject to the award immediately prior to the Effective Time, multiplied by (ii) the exchange ratio (discussed above), rounded to the nearest whole share.

SSE and Patterson-UTI have agreed, subject to certain exceptions, not to directly or indirectly solicit, initiate, facilitate, knowingly encourage or induce or take any other action that could be reasonably expected to lead to the making, submission, or announcement of competing acquisition proposals. With respect to competing acquisition proposals, subject to certain exceptions, both parties are also prohibited from furnishing any nonpublic information, engaging in discussions or negotiations, entering into a letter of intent or similar document, or otherwise approving, endorsing or recommending a competing proposal. SSE and Patterson-UTI have also agreed to cease all existing discussions with third parties regarding any competing acquisition proposals.

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Notwithstanding the prior paragraph, either party may, subject to the terms and conditions set forth in the Merger Agreement, furnish information to, and engage in discussions and negotiations with, a third party that makes an unsolicited competing acquisition proposal if the board of directors of such party determines in good faith, after consultation with its outside counsel and its outside financial advisor, that such competing acquisition proposal is or is reasonably likely to result in a superior proposal, and that the failure to take such action would be inconsistent with its fiduciary duties under applicable law. Prior to the time that the relevant stockholders approve the Merger Agreement (in the case of SSE) or the issuance of Patterson-UTI Common Stock as merger consideration (the “Patterson-UTI Stock Issuance”) (in the case of Patterson-UTI), the board of directors of each of SSE and Patterson-UTI may change its recommendation with respect to the adoption of the Merger Agreement (in the case of SSE) or the Patterson-UTI Stock Issuance (in the case of Patterson-UTI), in each case, in response to a superior proposal or an intervening event if the board of directors determines in good faith, after consultation with its outside counsel, that, among other things, the failure to do so would be inconsistent with its fiduciary duties under applicable law and complies with certain other specified conditions.

The Merger Agreement contains representations and warranties from both Patterson-UTI and SSE, and each party has agreed to covenants, including, among others, covenants relating to (i) the conduct of its business during the interim period between the execution of the Merger Agreement and the Effective Time, (ii) the obligation to use reasonable best efforts to cause the Merger to be consummated and to obtain expiration of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (“HSR Act”), (iii) the obligation of SSE to call a meeting of its stockholders to approve the Merger Agreement and (iv) the obligation of Patterson-UTI to call a meeting of its stockholders to approve the Patterson-UTI Stock Issuance.

The completion of the Merger is subject to satisfaction or waiver of certain closing conditions, including but not limited to: (i) adoption of the Merger Agreement by SSE’s stockholders and approval of the Patterson-UTI Stock Issuance by Patterson-UTI’s stockholders, (ii) the expiration or termination of any waiting period under the HSR Act, (iii) the absence of any law, order, decree or injunction prohibiting the consummation of the Merger, (iv) the effectiveness of the registration statement on Form S-4 pursuant to which the shares of Patterson-UTI Common Stock to be issued as merger consideration will be registered, (v) approval for listing on the Nasdaq Global Select Market of the shares of Patterson-UTI Common Stock to be issued in connection with the Merger subject to official notice of issuance, (vi) subject to specified materiality standards, the accuracy of the representations and warranties of each party, (vii) compliance by each party in all material respects with its covenants under the Merger Agreement, (viii) receipt of a tax opinion from each party’s counsel, dated as of the closing date, to the effect that the merger will be treated as a “reorganization” within the meaning of Section 368(a) of the Internal Revenue Code of 1986, as amended, (ix) the absence of material losses (as defined in the Merger Agreement) during the interim period between the date of execution of the Merger Agreement and the Effective Time that exceed, or would reasonably be expected to exceed, individually or in the aggregate, $100 million with respect to SSE and its subsidiaries, and $300 million with respect to Patterson-UTI and its subsidiaries, in each case, net of certain insurance or indemnification proceeds and certain other deductions, and (x) an amount of net debt (as defined in the Merger Agreement) as of the closing date not exceeding $500 million with respect to SSE and its subsidiaries, and $725 million (not including debt incurred to refinance SSE’s debt or pay for the expenses of the transaction) with respect to Patterson-UTI and its subsidiaries.

Upon termination of the Merger Agreement, if the stockholders of either party do not provide the requisite approval, such party must reimburse the expenses of the other party, capped at $7,500,000. In certain circumstances, including if the board of directors of SSE changes its recommendation or if the Merger Agreement is terminated in certain circumstances and SSE enters into an alternative acquisition transaction within 12 months of termination, SSE may be required to pay Patterson-UTI a termination fee of $40,000,000. Patterson-UTI may be required to pay SSE a termination fee of $100,000,000 in certain circumstances, including if the board of directors of Patterson-UTI changes its recommendation as a result of a Superior Parent Proposal or if the Merger Agreement is terminated in certain circumstances and Patterson-UTI enters into certain types of alternative acquisition transactions within 12 months of termination. In certain other circumstances, Patterson-UTI may be required to pay SSE a termination fee of $40,000,000. In no event will either party be entitled to receive more than one expense reimbursement payment or more than one termination fee payment to which either party is entitled.

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with each such stockholder being able to vote the balance of its shares of SSE common stock on such proposal in such stockholder’s sole discretion.

The description of the Merger Agreement and related voting and support agreements above does not purport to be complete and is qualified in its entirety by the full text of the Merger Agreement and related voting and support agreements, which were filed with the SEC on December 13, 2016 as Exhibits 2.1, 99.2, 99.3 and 99.4 to our Current Report on Form 8-K.

The transaction is expected to close late in the first quarter or early in the second quarter of 2017. However, SSE cannot predict with certainty when, or if, the pending merger will be completed because completion of the transaction is subject to conditions beyond the control of the Company.

3. Emergence from Voluntary Reorganization under Chapter 11 Proceedings and Related Events

On May 12, 2016, the Company and all of its wholly owned subsidiaries entered into a Second Amended and Restated Restructuring Support Agreement (the “Restructuring Support Agreement”) with (i) certain holders of the 2019 Notes, (ii) certain lenders under the Company’s Incremental Term Supplement (Tranche A) loan (the “Incremental Term Loan”), (iii) certain lenders under the Company’s $400.0 million Term Loan Credit Agreement dated June 25, 2014 (the “Term Loan”), and (iv) certain holders 2022 Notes.

On June 7, 2016, the Debtors filed the Bankruptcy Petitions for reorganization under Chapter 11 in the Bankruptcy Court. The filings of the Bankruptcy Petitions constituted an event of default with respect to the 2019 Notes, the 2022 Notes, the Term Loan (see Note 11) and the Incremental Term Loan (see Note 11) (collectively, the “Outstanding Debt”) and constituted an event of default under our Pre-Petition Credit Facility. Pursuant to Chapter 11, the filing of the Bankruptcy Petitions automatically stayed most actions against the Debtors, including actions to collect indebtedness incurred prior to the filing of the Bankruptcy Petitions or to exercise control over the Debtor’s property. Accordingly, although the Bankruptcy Petitions triggered defaults under the Outstanding Debt, creditors were generally stayed from taking action as a result of these defaults. These defaults were deemed waived or cured upon the Effective Date of the Plan. The Debtors also filed the Plan and a related solicitation and disclosure statement on June 7, 2016.


•	payment in full of all trade creditors and other general unsecured creditors in the ordinary course of business;


•	the exchange of the full $650.0 million of the 2019 Notes into 96.75% of new common stock issued in the reorganization (the “New Common Stock”);


•	the exchange of the full $450.0 million of the 2022 Notes for 3.25% of the New Common Stock as well as

warrants exercisable for 15% of the New Common Stock at predetermined equity values;


•	the issuance to our existing common stockholders of two series of warrants exercisable for an aggregate of 20% of the New Common Stock at predetermined equity values;

•


•	the payment of a consent fee equal to 2% of the Incremental Term Loan plus $15.0 million of the outstanding Incremental Term Loan balance, together with the maintenance of the remaining $84.0 million balance of the Incremental Term Loan on identical terms other than the suspension of any prepayment premium for a period of 18 months.

The Plan effectuated, among other things, a substantial reduction in our debt, including $1.1 billion in the aggregate of the face amount of the 2019 Notes and 2022 Notes.

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In accordance with the Plan, on the Effective Date, we issued an aggregate of 22,000,000 shares of New Common Stock to the holders of the 2019 and 2022 Notes.


•	We issued Series A Warrants (“Series A Warrants”), which are exercisable until August 1, 2021, to purchase up to an aggregate of 3,882,353 shares of New Common Stock, at an exercise price of $23.82 per share, to holders of the 2022 Notes.


•	We issued Series B Warrants (“Series B Warrants”), which are exercisable until August 1, 2021, to purchase up to an aggregate of 2,875,817 shares of New Common Stock, at an exercise price of $69.08 per share, to our existing common stockholders.


•	We issued Series C Warrants (“Series C Warrants,” and, together with the Series A Warrants and Series B Warrants, the “Warrants”), which are exercisable until August 1, 2023, to purchase up to an aggregate of 3,195,352 shares of New Common Stock at an exercise price of $86.93 per share, to our existing common stockholders.

All unexercised Warrants will expire and the rights of the holders of such warrants (the “Warrant Holders”) to purchase shares of New Common Stock will terminate on the first to occur of (i) the close of business on their respective expiration dates or (ii) the date of completion of (A) any Affiliated Asset Sale (as defined in the Warrant Agreement), or (B) a Change of Control (as defined in the Warrant Agreement). Following the Effective Date, there are 3,882,353 Series A Warrants, 2,875,817 Series B Warrants and 3,195,352 Series C Warrants outstanding.

In the event of a merger or consolidation where (i) the acquirer is not an affiliate of the Company and (ii) all of the equity held by equity holders of the Company outstanding immediately prior thereto is extinguished or replaced by equity in a different entity (except in cases where the equity holders of the Company represent more than 50% of the total equity of such surviving entity) (a “Non-Affiliate Combination”), holders of Warrants shall be solely entitled to receive the consideration per Warrant that is payable per share of common stock of the Company, less the applicable exercise price of the Warrant, paid in the same form and in the same proportion as is payable to holders of common stock. If the consideration is any form other than cash, the holders of the Warrants shall have ten business days prior to the consummation of the Non-Affiliate Combination to exercise their respective Warrants, and any Warrants not exercised will terminate.

In accordance with the Plan, on September 20, 2016, the Company adopted the Seventy Seven Energy Inc. 2016 Omnibus Incentive Plan (the “2016 Omnibus Incentive Plan”) (see Note 14).

Successor Issuer

Trading of New Common Stock

The New Common Stock is not traded on a national securities exchange. The Company can provide no assurance that the New Common Stock will trade on a nationally recognized market or an over-the-counter market, whether broker-dealers will provide public quotes of the reorganized Company’s common stock on an over-the-counter market, whether the trading volume on an over-the-counter market of the Company’s common stock will be sufficient to provide for an efficient trading market, or whether quotes for the Company’s common stock may be blocked by the OTC Markets Group in the future. Since August 17, 2016, SSE’s common stock has traded on the OTC Grey market under the symbol “SVNT.” If we complete the merger with Patterson-UTI, shares of SSE common stock will cease to be traded on the OTC Grey market.

Registration Rights Agreement

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Management, LLC, Axar Capital Management, LLC and Mudrick Capital Management, L.P. (collectively, the “Registration Rights Holders”).

Senior Secured Debtor-In-Possession Credit Agreement; New ABL Credit Facility

On June 8, 2016, in connection with the filings of the Bankruptcy Petitions, the Company, with certain of our subsidiaries as borrowers, entered into a senior secured debtor-in-possession credit facility (the “DIP Facility”) with total commitments of $100.0 million. See Note 11 for additional discussion related to the DIP Facility.

New Directors

Conversion to Delaware Corporation

4. Fresh-Start Accounting

In connection with the Company’s emergence from Chapter 11, the Company applied the provisions of fresh-start accounting, pursuant to Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 852, Reorganizations, (“ASC 852”), to its consolidated financial statements. The Company qualified for fresh-start accounting because (i) the holders of existing voting shares of the Predecessor Company received less than 50% of the voting shares of the Successor Company, and (ii) the reorganization value of the Company’s assets immediately prior to confirmation was less than the post-petition liabilities and allowed claims. The Company applied fresh-start accounting as of August 1, 2016, which was the date of emergence from Chapter 11. Adopting fresh-start reporting results in a new reporting entity with no beginning

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retained earnings or accumulated deficit. The cancellation of all existing common shares outstanding on the Effective Date and issuance of new shares of the reorganized entity caused a related change of control of the Company under ASC 852, as the holders of existing voting shares immediately before confirmation received less than 50% of the voting shares of the Successor Company.

Reorganization value represents the fair value of the Successor Company’s assets before considering liabilities. Upon the application of fresh-start accounting, the Company allocated the reorganization value to its individual assets based on their estimated fair values.

Reorganization Value

In support of the Plan, the enterprise value of the Successor Company was estimated and approved by the Bankruptcy Court to be in the range of $700 million to $900 million. The Company used the high end of the Bankruptcy Court approved enterprise value of the Successor Company of $900 million as its estimated enterprise value.

The following table reconciles the enterprise value to the estimated fair value of Successor common stock as of the Effective Date (in thousands, except per share value):



Enterprise value	$	900,000
Plus: Cash and cash equivalents	37,750
Less: Fair value of debt	(427,520		)
Less: Fair value of warrants	(24,733		)
Fair value of Successor common stock	$	485,497
Shares outstanding at August 1, 2016	22,000
Per share value	$	22.07

In connection with fresh-start accounting, the Company’s debt was recorded at fair value of $427.5 million as determined using a market approach. The difference between the $475.8 million face amount and the fair value recorded in fresh-start accounting is being amortized over the life of the debt. The fair value of the Company’s debt was estimated using Level 2 inputs.

The fair values of the Series A, Series B and Series C Warrants were estimated to be $4.62, $1.03 and $1.20, respectively. The fair values of the Warrants were estimated using a Black-Scholes pricing model with the following assumptions:



	Series A			Series B			Series C
Stock price	$	16.27		$	13.83		$	12.45
Strike price	$	23.82		$	69.08		$	86.93
Expected volatility	50		%	50		%	50		%
Expected dividend rate	0		%	0		%	0		%
Risk free interest rate	1.26		%	1.26		%	1.57		%
Expiration date	5 years			5 years			7 years

The fair value of these warrants were estimated using Level 2 inputs.

The following table reconciles the enterprise value to the estimated reorganization value as of the Effective Date (in thousands):



Enterprise value	$	900,000
Plus: Cash and cash equivalents	37,750
Plus: Fair value of non-debt working capital liabilities	63,365
Plus: Fair value of non-debt long-term liabilities	1,933
Reorganization value of Successor assets	$	1,003,048

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In determining reorganization value, the Company estimated fair value for property and equipment using significant unobservable inputs (Level 3) based on market and income approaches. SSE commissioned third-party appraisal services to estimate the fair value of its revenue-generating fixed assets and considered current market conditions and management’s judgment to estimate the fair value of non-revenue-generating assets. Additionally, the Company utilized a discounted cash flow method to fair value certain assets. SSE estimated future cash flows for the period from August 1, 2016 to July 31, 2026 and discounted such estimated future cash flows to present value using its weighted average cost of capital.

Reorganization value and enterprise value were estimated using various projections and assumptions that are inherently subject to significant uncertainties beyond our control. Accordingly, the estimates set forth herein are not necessarily indicative of actual outcomes, and there can be no assurance that the estimates, projections or assumptions will be realized.

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Consolidated Balance Sheet

The adjustments set forth in the following consolidated balance sheet reflect the effects of (i) the consummation of the transactions contemplated by the Plan (reflected in the column “Reorganization Adjustments”), and (ii) estimated fair value adjustments resulting from the adoption of fresh-start accounting (reflected in the column “Fresh-Start Adjustments”). The explanatory notes highlight methods used to determine estimated fair values or other amounts of assets and liabilities, as well as significant assumptions.



	July 31, 2016 Predecessor Company			Reorganization Adjustments				Fresh-Start Adjustments				August 1, 2016 Successor Company
	(in thousands, except share amounts)
Assets:
Current Assets:
Cash and cash equivalents	$	71,376		$	(33,626	)	(1)	$	—			$	37,750
Accounts receivable, net	94,024			—				—				94,024
Inventory	13,422			—				—				13,422
Deferred income tax asset	20,773			(20,773		)	(2)	—				—
Prepaid expenses and other	15,309			—				—				15,309
Total Current Assets	214,904			(54,399		)		—				160,505
Property and Equipment:
Property and equipment, at cost	2,681,896			—				(1,862,505		)	(10)	819,391
Less: accumulated depreciation	(1,244,536		)	—				1,244,536			(10)	—
Total Property and Equipment, Net	1,437,360			—				(617,969		)		819,391
Other Assets:
Deferred financing costs	—			1,235			(3)	—				1,235
Other long-term assets	39,098			—				(17,181		)	(11)	21,917
Total Other Assets	39,098			1,235				(17,181		)		23,152
Total Assets	$	1,691,362		$	(53,164	)		$	(635,150	)		$	1,003,048
Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts Payable	$	21,418		$	—			$	—			$	21,418
Current portion of long-term debt	5,000			—				—				5,000
Other current liabilities	59,338			(17,391		)	(4)	—				41,947
Total Current Liabilities	85,756			(17,391		)		—				68,365
Long-Term Liabilities:
Deferred income tax liabilities	47,868			(46,638		)	(2)	(1,230		)	(12)	—
Long-term debt, excluding current maturities	475,852			(14,226		)	(5)	(39,106		)	(13)	422,520
Other long-term liabilities	1,933			—				—				1,933
Liabilities subject to compromise	1,135,493			(1,135,493		)	(6)	—				—
Total Long-Term Liabilities	1,661,146			(1,196,357		)		(40,336		)		424,453
Commitments and Contingencies
Stockholders’ Equity:
Predecessor common stock, $0.01 par value: authorized 250,000,000 shares; issued and outstanding 57,467,915	575			(575		)	(7)	—				—
Predecessor paid-in capital	387,659			(387,659		)	(7)	—				—
Successor common stock, $0.01 par value: authorized 90,000,000 shares; issued and outstanding 22,000,000	—			220			(8)	—				220
Successor paid-in capital	—			510,010			(8)	—				510,010
Retained earnings (accumulated deficit)	(443,774		)	1,038,588			(9)	(594,814		)	(14)	—
Total Stockholders’ Equity (Deficit)	(55,540		)	1,160,584				(594,814		)		510,230
Total Liabilities and Stockholders’ Equity	$	1,691,362		$	(53,164	)		$	(635,150	)		$	1,003,048

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Reorganization Adjustments


1.	Reflects the following cash payments recorded as of the Effective Date from implementation of the Plan (in thousands):



Predecessor liabilities paid upon emergence	$	17,391
Partial repayment of Incremental Term Loan	15,000
Debt issuance costs	1,235
Total	$	33,626


2.	Reflects the tax adjustments and corresponding change in valuation allowance as a result of the Company’s emergence from Chapter 11 bankruptcy.


3.	Reflects the $1.2 million of debt issuance costs incurred on the New ABL Credit Facility.


4.	Reflects the payment of $17.4 million in professional fees associated with the implementation of the Plan that were previously accrued in other current liabilities.


5.	Reflects the payment of $15.0 million principal on the Incremental Term Loan and the write-off of related deferred issuance costs of $0.8 million.


6.	Liabilities subject to compromise were settled as follows in accordance with the Plan (in thousands):



6.625% Senior Notes due 2019	$	650,000
6.50% Senior Notes due 2022	450,000
Accrued interest	35,493
Liabilities subject to compromise of the Predecessor Company	1,135,493
Fair value of equity issued to holders of the senior notes of the Predecessor Company	(503,434		)
Gain on settlement of liabilities subject to compromise	$	632,059


7.	Reflects the cancellation of the Predecessor Company equity to retained earnings.


8.	Reflects the issuance of 22.0 million shares of common stock at a per share price of $22.07 to the holders of the Predecessor Company’s 2019 and 2022 Notes and the issuance of 9.954 million warrants to purchase up to 35% of the Successor Company’s equity valued at $24.7 million with a weighted average per unit value of $2.48.


9.	Reflects the cumulative impact of the reorganization adjustments discussed above (in thousands):



Gain on settlement of liabilities subject to compromise	$	632,059
Fair value of warrants issued to Predecessor stockholders	(6,797		)
Cancellation of Predecessor Company equity	388,234
Tax impact of reorganization adjustments	25,865
Other reorganization adjustments	(773		)
Net impact to retained earnings (accumulated deficit)	$	1,038,588

The net gain on reorganization adjustments totaled $624.5 million and is included in reorganization items, net in the Predecessor Company's statement of operations (see Note 5). The cancellation of Predecessor Company equity was recorded as a direct reduction to retained earnings and had no impact to the Predecessor Company's statement of operations.

Fresh-Start Adjustments


10.	Reflects a $618.0 million reduction in the net book value of property and equipment to estimated fair value.

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•	To estimate the fair value of drilling rigs and related equipment, hydraulic fracturing equipment and oilfield rental equipment, the Company commissioned a third-party appraisal service to value such assets using a market approach. This approach relies upon recent sales and offerings of similar assets.


•	To estimate the fair value of land and buildings and other property and equipment, the Company considered recent comparable sales as well as current market conditions and demand.


•	The fair value of these assets was estimated using significant unobservable inputs (Level 3) based on market and income approaches.

The following table summarizes the components of property and equipment, net of the Successor Company and the Predecessor Company (in thousands):



	Successor		Predecessor
Drilling rigs and related equipment	$	510,902	$	1,019,792
Hydraulic fracturing equipment	127,438		157,236
Oilfield rental equipment	34,313		52,397
Land and buildings	118,759		170,110
Other	27,979		37,825
Total	$	819,391	$	1,437,360

For property and equipment owned at August 1, 2016, the depreciable lives were revised to reflect remaining estimated useful lives.


11.	An adjustment of $17.2 million was recorded to decrease other long-term assets to estimated fair value based on the following:


•	The Company recorded a $6.5 million adjustment to decrease the book value of the Note Receivable (as defined in Note 8) to fair value. Fair value of the Note Receivable was estimated using Level 2 inputs based on a market approach.


•	Based on management’s judgment and the current economics of the industry, the Company recorded additional adjustments totaling $10.7 million to decrease other long-term assets to fair value.


12.	Reflects the tax adjustments and corresponding change in valuation allowance as a result of the Company’s emergence from Chapter 11 bankruptcy proceedings.


13.	Represents a $39.1 million adjustment to record the Term Loan and Incremental Term Loan at fair value using Level 2 inputs, including the write-off of the remaining balance of deferred issuance costs totaling $9.1 million.


14.	Reflects the cumulative impact of fresh-start adjustments as discussed above (in thousands):



Property and equipment fair value adjustment	$	(617,969	)
Other long-term assets fair value adjustments	(17,181		)
Long-term debt fair value adjustment	39,106
Net loss on fresh-start adjustments	(596,044		)
Tax impact on fresh-start adjustments	1,230
Net impact to retained earnings (accumulated deficit)	$	(594,814	)

The $596.0 million net loss on fresh-start adjustments is included in reorganization items, net in the Predecessor Company's statement of operations (see Note 5).

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5. Reorganization Items, Net

Reorganization items represent liabilities settled, net of amounts incurred subsequent to the Chapter 11 filing as a direct result of the Plan, and such items are classified as Reorganization items, net in our condensed consolidated statement of operations. The following table summarizes reorganization items, net (in thousands):



	Successor		Predecessor
	Period from August 1, 2016 to December 31, 2016		Period from January 1, 2016 to July 31, 2016
Net gain on settlement of liabilities subject to compromise	$	—	$	(632,059	)
Net loss on fresh-start adjustments	—		596,044
Stock-based compensation acceleration expense	—		25,086
Professional fees	1,868		20,228
Write-off of debt issuance costs	—		13,318
Fair value of warrants issued to Predecessor stockholders	—		6,797
DIP credit agreement financing costs	—		478
Total	$	1,868	$	29,892

For the 2016 Successor Period and the 2016 Predecessor Period, cash payments for reorganization items totaled $2.5 million and $18.6 million, respectively.

6. Significant Accounting Policies

Accounting Estimates

The preparation of 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 balance sheet date and the reported amounts of revenues and expenses during the reporting periods. Although management believes these estimates are reasonable, actual results could differ from those estimates. Areas where critical accounting estimates are made by management include:


•	estimated useful lives of assets, which impacts depreciation and amortization of property and equipment;


•	impairment of long-lived assets, goodwill and intangibles;


•	income taxes;


•	accruals related to revenue, expenses, capital costs and contingencies; and


•	cost allocations as described in Note 19.

Fresh-Start Accounting

As discussed in Note 4, the Company applied fresh-start accounting upon emergence from bankruptcy on August 1, 2016, which resulted in the Company becoming a new entity for financial reporting purposes. Upon adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the Effective Date. The Effective Date fair values of our assets and liabilities differed materially from the recorded values of our assets and liabilities as reflected in our historical consolidated balance sheet. The effects of the Plan and the application of fresh-start accounting were reflected in our consolidated financial statements as of August 1, 2016, and the related adjustments thereto were recorded in our consolidated statements of operations as reorganization items, net for the periods prior to August 1, 2016 (Predecessor Company).

As a result of our application of fresh-start accounting, our consolidated balance sheets and consolidated statement of operations subsequent to the Effective Date will not be comparable to our consolidated balance sheets and statements of operations prior to the Effective Date. Our consolidated financial statements and related footnotes are presented with a black line division which delineates the lack of comparability between amounts presented on or after August 1, 2016 and dates prior thereto. Our financial results for future periods following the application of fresh-start accounting will be different from historical trends, and such differences may be material.

Risks and Uncertainties

We operate in a highly cyclical industry. The main factor influencing demand for oilfield services is the level of drilling and completions activity by E&P companies, which in turn depends largely on current and anticipated future crude oil and natural gas prices and production depletion rates. Demand for oil and natural gas is cyclical and is subject to large and rapid fluctuations. When oil and natural gas price increases occur, producers increase their capital expenditures, which generally results in greater revenues and profits for oilfield service companies. The increased capital expenditures also ultimately result in greater production, which historically has resulted in increased supplies and reduced prices that, in turn, tend to reduce demand for oilfield services. For these reasons, our results of operations may fluctuate from quarter-to-quarter and from year-to-year.

Historically, we have provided a significant percentage of our oilfield services to CHK. For the 2016 Successor Period, the 2016 Predecessor Period, and the years ended December 31, 2015 and 2014, CHK accounted for approximately 51%, 65%, 70% and 81%, respectively, of our revenues. As of December 31, 2016 and 2015, CHK accounted for approximately 49% and 65%, respectively, of our accounts receivable. If CHK ceases to engage us on terms that are attractive to us during any future period, our business, financial condition, cash flows and results of operations would be materially adversely affected during such period.

Accounts Receivable

Trade accounts receivable are recorded at the invoice amount and do not bear interest. As of December 31, 2016 and 2015, 49% and 65%, respectively, of our receivables are with CHK and its subsidiaries. The allowance for doubtful accounts represents our best estimate for losses that may occur resulting from disputed amounts with our customers or their inability to pay amounts owed. We determine the allowance based on historical write-off experience and information about specific customers. For the 2016 Successor Period, the 2016 Predecessor Period, and the years ended December 31, 2015 and 2014, we recognized a nominal amount, $1.4 million, $1.4 million and $2.9 million, respectively, of bad debt expense related to potentially uncollectible receivables.

On August 1, 2016, in connection with the application of fresh-start accounting, the carrying value of accounts receivable was adjusted to fair value, eliminating our historical allowance for doubtful accounts totaling $2.8 million. We recognized reductions to our allowance of $2.3 million, $0.5 million and $0.1 million as we wrote off specific receivables against our allowance for the 2016 Predecessor Period and the years ended December 31, 2015 and 2014, respectively.

Inventory

We value inventory at the lower of cost or market, with cost determined using the average cost method. Average cost is derived from third-party invoices and production cost. Production cost includes material, labor and manufacturing overhead. Inventory primarily consists of proppants and chemicals used in our hydraulic fracturing operations.

Property and Equipment

Property and equipment are carried at cost less accumulated depreciation. Depreciation of assets is based on estimates, assumptions and judgments relative to useful lives and salvage values. Upon the disposition of an asset, we eliminate the cost and related accumulated depreciation and include any resulting gain or loss in operating expenses in the consolidated statements of operations. Expenditures for maintenance and repairs that do not add capacity or extend the useful life of an asset are expensed as incurred.

In connection with our application of fresh-start accounting, property and equipment were adjusted to estimated fair value on August 1, 2016. A summary of our property and equipment amounts (in thousands) and useful lives (in years) is as follows:



	Successor			Predecessor			Estimated
	December 31,			December 31,			Useful
	2016			2015			Life
Drilling rigs and related equipment	$	509,734		$	1,594,377		5-15
Hydraulic fracturing equipment	98,102			323,989			2-7
Oilfield rental equipment	34,157			324,976			2-10
Trucks and tractors	18,887			77,678			7
Vehicles	5,674			33,478			3
Buildings and improvements	107,450			196,240			10-39
Land	7,432			16,261			—
Other	31,855			79,447			3-7
Total property and equipment, at cost	813,291			2,646,446
Less: accumulated depreciation and amortization	(71,977		)	(1,116,026		)
Property and equipment held for sale, net (see Note 10)	8,226			—
Total property and equipment, net	$	749,540		$	1,530,420

Depreciation is calculated using the straight-line method based on the assets’ estimated useful lives and salvage values. These estimates are based on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets.

We review the estimated useful lives of our property and equipment on an ongoing basis. Based on this review in the first quarter of 2015, we concluded that the estimated useful lives of certain drilling rig components and certain drilling rigs were shorter than the estimated useful lives used for depreciation in our consolidated financial statements. We reflected this useful life change as a change in estimate, effective January 1, 2015, which increased depreciation expense by $13.7 million, increased net loss by $9.7 million and increased our basic and diluted loss per share by $0.19 for the year ended December 31, 2015. Effective July 1, 2014, we concluded that the estimated useful lives of certain of our drilling rigs were shorter than the estimated useful lives used for depreciation, which increased depreciation expense by $3.9 million, increased net loss by $3.0 million and increased basic and diluted loss per share by $0.08 for the year ended December 31, 2014.

Depreciation expense on property and equipment for the 2016 Successor Period, the 2016 Predecessor Period, and the years ended December 31, 2015 and 2014 was $73.9 million, $162.4 million, $295.1 million and $290.9 million, respectively. Included in property and equipment are $10.9 million and $77.7 million at December 31, 2016 and 2015, respectively, of assets that are being constructed or have not been placed into service, and therefore are not subject to depreciation.

Interest is capitalized on the average amount of accumulated expenditures for major capital projects under construction using a weighted average interest rate based on our outstanding borrowings until the underlying assets are placed into service. Capitalized interest is added to the cost of the assets and amortized to depreciation expense over the useful life of the assets. During the 2016 Predecessor Period and the years ended December 31, 2015 and 2014, we capitalized interest of approximately $1.0 million, $2.3 million and $2.1 million, respectively.

Impairment of Long-Lived Assets

We review our long-lived assets, such as property and equipment, whenever, in management’s judgment, events or changes in circumstances indicate the carrying amount of the assets may not be recoverable. Factors that might indicate a potential impairment include a significant decrease in the market value of the long-lived asset, a significant change in the long-lived asset’s physical condition, a change in industry conditions or a reduction in cash flows associated with the expected use of the long-lived asset. If these or other factors indicate the carrying amount of the asset may not be recoverable, we determine whether an impairment has occurred through analysis of the future undiscounted cash flows of the asset. If an impairment has occurred, we recognize a loss for the difference between the carrying amount and the fair value of the asset. We measure the fair value of the asset using market prices or, in the absence of market prices, based on an estimate of discounted cash flows.

Investments

Investments in securities are accounted for under the equity method in circumstances where we have the ability to exercise significant influence, but not control, over the operating and investing policies of the investee. Under the equity method, we recognize our share of the investee’s earnings in our consolidated statements of operations. We consolidate all subsidiaries in which we hold a controlling interest.

We evaluate our investments for impairment and recognize a charge to earnings when any identified impairment is determined to be other-than-temporary. See Note 16 for further discussion of investments.

Goodwill

Goodwill represents the cost in excess of fair value of the net assets of businesses acquired. In 2011, we recorded goodwill in the amount of $27.4 million related to our acquisition of Bronco Drilling Company, Inc. (“Bronco”). This goodwill was assigned to our drilling segment. Goodwill is not amortized.

We review goodwill for impairment annually on October 1 or more frequently if events or changes in circumstances indicate that the carrying amount of the reporting unit exceeds its fair value. Circumstances that could indicate a potential impairment include a significant adverse change in the economic or business climate, a significant adverse change in legal factors, an adverse action or assessment by a regulator, unanticipated competition, loss of key personnel, and the likelihood that a reporting unit or significant portion of a reporting unit will be sold or otherwise disposed of. Under GAAP, we have the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of one of our reporting units is greater than its carrying amount. If, after assessing the totality of events or circumstances, we determine it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, there is no need to perform any further testing. However, if we conclude otherwise, accounting guidance requires a two-step process for testing impairment. First, the fair value of each reporting unit is compared to its carrying value to determine whether an indication of impairment exists. Second, if impairment is indicated, the fair value of the reporting unit’s goodwill is determined by allocating the unit’s fair value to its assets and liabilities (including any unrecognized intangible assets) as if the reporting unit had been acquired in a business combination on the impairment test date. The amount of impairment for goodwill is measured as the excess of the carrying value of the goodwill over its implied fair value.

For purposes of performing the impairment tests for goodwill, all of our goodwill related to our drilling reporting unit. We performed the two-step process for testing goodwill for impairment on October 1, 2015. Due to the further deterioration of industry conditions in the fourth quarter of 2015, including the further decline in oil and natural gas prices, the Company determined that there was an indication of impairment present based on the results of the first step of the goodwill impairment test. During the fourth quarter of 2015, we completed our assessment and recognized an impairment loss of $27.4 million on the goodwill associated with the Bronco acquisition. As of December 31, 2016 and 2015, we had no recorded goodwill on our consolidated balance sheet.

Deferred Financing Costs

Legal fees and other costs incurred in obtaining financing are amortized over the term of the related debt using a method that approximates the effective interest method. We had gross capitalized costs of $1.2 million and $37.3 million, net of accumulated amortization of $0.1 million and $12.4 million, at December 31, 2016 and 2015, respectively. We capitalized costs of $1.2 million associated with our New ABL Credit Facility (see Note 11) in the 2016 Predecessor Period. In 2015, we capitalized costs of $6.3 million associated with the issuance of a Term Loan due 2021. Amortization expense related to deferred financing costs was $0.1 million, $2.5 million, $4.6 million and $6.1 million for the 2016 Successor Period, the 2016 Predecessor Period, and the years ended December 31, 2015 and 2014, respectively, and is included in interest expense in the consolidated statements of operations. During the 2016 Predecessor Period, in connection with the reorganization and application of fresh-start accounting, unamortized costs totaling $22.4 million related to the Pre-Petition Credit Facility, Term Loan, Incremental Term Loan, 2019 Notes and 2022 Notes were written off and included in reorganization items, net in the consolidated statement of operations.

Revenue Recognition

We recognize revenue when services are performed, collection of receivables is reasonably assured, persuasive evidence of an arrangement exists and the price is fixed or determinable.

Oilfield Rentals. We rent many types of oilfield equipment including drill pipe, drill collars, tubing, blowout preventers, frac tanks, mud tanks and environmental containment. We also provide air drilling, flowback services and services associated with the transfer of water to the wellsite for well completions. We price our rentals and services by the day or hour based on the type of equipment rented and the services performed and recognize revenue ratably over the term of the rental.

Former Oilfield Trucking. Oilfield trucking provided rig relocation and logistics services as well as fluid handling services. Our trucks moved drilling rigs, crude oil, and other fluids and construction materials to and from the wellsite and also transported produced water from the wellsite. We priced these services by the hour and volume and recognized revenue as services were performed. As part of the spin-off, we sold our crude hauling business to a third party. During the second quarter of 2015, we sold our drilling rig relocation and logistics business and water hauling assets. As of June 30, 2015, there were no remaining assets or operations in this former segment.

Other Operations. We designed, engineered and fabricated natural gas compression packages, accessories and related equipment that we sold to CHK and other customers. We priced our compression units based on certain specifications such as horsepower, stages and additional options. We recognized revenue upon completion and transfer of ownership of the natural gas compression equipment. As part of the spin-off, we distributed our compression unit manufacturing business to CHK.

Litigation Accruals

We estimate our accruals related to litigation based on the facts and circumstances specific to the litigation and our past experience with similar claims. We estimate our liability related to pending litigation when we believe the amount or a range of the loss can be reasonably estimated. We record our best estimate of a loss when the loss is considered probable. When a loss is probable and there is a range of estimated loss with no best estimate in the range, we record the minimum estimated liability related to a lawsuit or claim. As additional information becomes available, we assess the potential liability related to our pending litigation and claims and revise our estimates accordingly.

Environmental Costs

Our operations involve the storage, handling, transport and disposal of bulk waste materials, some of which contain oil, contaminants and regulated substances. These operations are subject to various federal, state and local laws and regulations intended to protect the environment. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. There were no amounts capitalized as of December 31, 2016 and 2015. We record liabilities on an undiscounted basis when remediation efforts are probable and the costs to conduct such remediation efforts can be reasonably estimated.

Leases

We lease rail cars and other property and equipment through various leasing arrangements (see Note 13). When we enter into a leasing arrangement, we analyze the terms of the arrangement to determine its accounting treatment. As of December 31, 2016, all leases have been accounted for as operating leases.

We periodically incur costs to improve the assets that we lease under these arrangements. We record the improvement as a component of property and equipment and amortize the improvement over the shorter of the useful life of the improvement or the remaining lease term.

Share-Based Compensation

For the Successor Company, our share-based compensation program consists of restricted stock granted to employees and non-employee directors under the 2016 Omnibus Incentive Plan. For the Predecessor Company, our share-based compensation program consisted of restricted stock and stock options granted to employees and restricted stock granted to non-employee directors under the SSE 2014 Incentive Plan (the “2014 Incentive Plan”).

We recognize in our financial statements the cost of employee services received in exchange for restricted stock and stock options based on the fair value of the equity instruments as of the grant date. In general, this value is amortized over the vesting period; for grants with a non-substantive service condition, this value is recognized immediately. Amounts are recognized in operating costs and general and administrative expenses.

Income Taxes

Our effective tax rate was 0%, 28%, 29% and 22% for the 2016 Successor Period, the 2016 Predecessor Period, and the years ended December 31, 2015 and 2014, respectively. We did not record any income tax benefit for the 2016 Successor Period due to the tax benefit at expected rates being offset by a full valuation allowance. Our effective tax rate can fluctuate as a result of state income taxes, permanent differences and changes in pre-tax income.

As of December 31, 2016, we are in a net deferred tax asset position. We believe it is more likely than not that these deferred tax assets will not be realized, and accordingly, we have recorded a full valuation allowance against our net deferred tax assets. In connection with the Company's emergence from Chapter 11 and subsequent application of fresh-start accounting, we recorded a full valuation allowance of $219.6 million in the 2016 Predecessor Period. We recorded the reduction of net operating losses related to cancellation of indebtedness income (“CODI”) in the 2016 Successor Period. The deferred tax impact of the tax attribute reduction was fully offset by a corresponding decrease in valuation allowance in the 2016 Successor Period.

7. Earnings Per Share

Upon emergence from bankruptcy on August 1, 2016, the Company’s then outstanding common stock was cancelled and the New Common Stock and Warrants were issued.

Basic earnings per share is computed using the weighted average number of shares of common stock outstanding and includes the effect of any participating securities as appropriate. Participating securities consist of unvested restricted stock issued to our employees and non-employee directors that provide nonforfeitable dividend rights and are required to be included in the computation of our basic earnings per share using the two-class method. The two-class method is an earnings allocation

formula that determines earnings per share for common stock and participating securities according to dividends declared and participation rights in undistributed earnings. Diluted earnings per share is computed using the weighted average shares outstanding for basic earnings per share, plus the dilutive effect of stock options for the Predecessor periods and warrants for the Successor Period. For the Predecessor periods, the dilutive effect of unvested restricted stock and stock options was determined using the treasury stock method, which assumes the amount of unrecognized compensation expense related to unvested share-based compensation awards is used to repurchase shares at the average market price for the period. For the Successor Period, the dilutive effect of warrants is determined using the treasury stock method, which assumes that any proceeds obtained upon the exercise of the warrants would be used to purchase common stock at the average market price for the period.



	Successor			Predecessor
	Five Months Ended			Seven Months Ended			Years Ended December 31,
	December 31, 2016			July 31, 2016			2015			2014
				(in thousands, except per share data)
Basic loss per share:
Allocation of earnings:
Net loss	$	(63,559	)	$	(155,710	)	$	(221,391	)	$	(7,979	)

Weighted average common shares outstanding ^(a)	22,186			54,832			50,096			47,236
Basic loss per share	$	(2.86	)	$	(2.84	)	$	(4.42	)	$	(0.17	)

Diluted loss per share:
Allocation of earnings:
Net loss	$	(63,559	)	$	(155,710	)	$	(221,391	)	$	(7,979	)

Weighted average common shares, including dilutive effect ^(a)(b)(c)(d)	22,186			54,832			50,096			47,236
Diluted loss per share	$	(2.86	)	$	(2.84	)	$	(4.42	)	$	(0.17	)


(a)	On June 30, 2014, 46,932,433 shares of our common stock were distributed to CHK shareholders in conjunction with the spin-off. For comparative purposes, and to provide a more meaningful calculation for weighted average shares, we have assumed this amount to be outstanding for periods prior to the spin-off.


(b)	No incremental shares of potentially dilutive restricted stock awards or units were included for the periods presented as their effect was antidilutive under the treasury stock method.


(c)	The exercise price of stock options exceeded the average market price of our common stock during the 2016 Predecessor Period and the years ended December 31, 2015 and 2014. Therefore, the stock options were not dilutive.


(d)	No incremental shares of potentially dilutive Series A Warrants were included for the 2016 Successor Period as their effect was antidilutive under the treasury stock method. The exercise price of the Series B and Series C Warrants exceeded the average market price of our common stock during the 2016 Successor Period. Therefore, the Series B and Series C Warrants were not dilutive.

8. Sale of Hodges Trucking Company, L.L.C.

On June 14, 2015, we sold Hodges Trucking Company, L.L.C. (“Hodges”), our previously wholly-owned subsidiary that provided drilling rig relocation and logistics services, to Aveda Transportation and Energy Services Inc. (“Aveda”) for aggregate consideration of $42.0 million. At the time of the sale, Hodges owned 270 rig relocation trucks and 65 cranes and forklifts. The sale did not include the land and buildings used in Hodges’ operations.

The consideration received consisted of $15.0 million in cash and a $27.0 million secured promissory note due June 15, 2020 (the “Note Receivable”). The Note Receivable bears a fixed interest rate of 9.00% per annum, which is payable quarterly in arrears beginning on June 30, 2015. Aveda can, at any time, make prepayments of principal before the maturity date without premium or penalty. The Note Receivable is secured by a second lien on substantially all of Aveda’s fixed assets and accounts receivable. The Note Receivable is presented in other long-term assets on our consolidated balance sheet.

In connection with the application of fresh-start accounting (see Note 4), the Note Receivable was written down to fair value of $20.5 million using an income approach. The difference between the $27.0 million face amount and the fair value recorded in fresh-start accounting is being accreted over the remaining life of the Note Receivable.

We recognized interest income of $1.0 million, $1.4 million and $1.4 million during the the 2016 Successor Period, the 2016 Predecessor Period and the year ended December 31, 2015, respectively, related to the Note Receivable.

We recognized a loss of $35.0 million on the sale of Hodges during the year ended December 31, 2015. Additionally, we recognized $2.1 million of stock-based compensation expense related to the vesting of restricted stock held by Hodges employees and $0.6 million of severance-related costs during the year ended December 31, 2015.

Hodges was included in our former oilfield trucking segment. The sale of Hodges did not qualify as discontinued operations because the sale did not represent a strategic shift that had or will have a major effect on our operations or financial results.

9. Asset Sales and Impairments and Other

Asset Sales

During the 2016 Successor Period and 2016 Predecessor Period, we sold assets, primarily consisting of real estate and ancillary equipment, for $11.9 million and $3.3 million, respectively. During the year ended December 31, 2015, we sold our water hauling assets for $6.5 million, which consisted of property and equipment that had a total carrying amount of $12.3 million, and other ancillary equipment for $21.2 million. During the year ended December 31, 2014, we sold 28 Tier 3 drilling rigs and ancillary drilling equipment for $44.8 million. Additionally, during 2014, we sold our crude hauling assets, which included 124 fluid handling trucks and 122 trailers that had a total carrying amount of $20.7 million, for $43.8 million. We recorded net losses (gains) on sales of property and equipment of approximately ($1.7) million, $0.8 million, $14.7 million and ($6.3) million during the 2016 Successor Period, the 2016 Predecessor Period, and the years ended December 31 2015 and 2014, respectively.

Impairments and Other

A summary of our impairments and other is as follows:



	Successor			Predecessor
	Five Months Ended			Seven Months Ended		Years Ended December 31,
	December 31, 2016			July 31, 2016		2015		2014
			(in thousands)
Trucking and water disposal equipment	$	—		$	—	$	2,737	$	—
Drilling rigs held for sale	—			—		—		11,237
Drilling rigs held for use	—			305		5,202		8,366
Lease termination costs	—			—		—		9,701
Drilling related services equipment	—			2,900		8,687		—
Other	—			2,911		2,006		1,460
Total impairments and other	$	—		$	6,116	$	18,632	$	30,764

We recognized $2.7 million of impairment charges during the year ended December 31, 2015 for certain trucking and water disposal equipment that we deemed to be impaired based on expected future cash flows of this equipment. Estimated fair value for the trucking and water disposal equipment was determined using significant unobservable inputs (Level 3) based on an income approach.

During the year ended December 31, 2014 we recognized $11.2 million of impairment charges for certain drilling rigs and spare equipment we had identified to sell as part of our broader strategy to divest of non-essential drilling rigs. We were required to present such assets at the lower of carrying amount or fair value less the anticipated costs to sell at the time they met the criteria for held for sale accounting. Estimated fair value was based on the expected sales price, less costs to sell.

We recognized $0.3 million, $5.2 million and $8.4 million of impairment charges during the 2016 Predecessor Period and the years ended December 31, 2015 and 2014, respectively, for certain drilling rigs that we deemed to be impaired based on our assessment of future demand and the suitability of the identified rigs in light of this demand. Estimated fair value for these drilling rigs was determined using significant unobservable inputs (Level 3) based on a market approach.

During the year ended December 31, 2014, we purchased 45 leased drilling rigs for approximately $158.4 million and paid lease termination costs of approximately $9.7 million.

We recognized $2.9 million and $8.7 million of impairment charges during the 2016 Predecessor Period and the year ended December 31, 2015 for drilling-related services equipment that we deemed to be impaired based on the expected future cash flows of this equipment. The estimated fair value for the drilling-related services equipment was determined using significant unobservable inputs (Level 3) based on a market approach.

We recognized impairment charges of $2.9 million, $2.0 million and $1.5 million during the 2016 Predecessor Period and the years ended December 31, 2015 and 2014, respectively, related to certain other property and equipment that we deemed to be impaired based on our assessment of the market value and expected future cash flows of the long-lived asset. Estimated fair value for this property and equipment was determined using significant unobservable inputs (Level 3) based on an income approach.

The assumptions used in our impairment evaluation for long-lived assets are inherently uncertain and require management’s judgment.

10. Property and Equipment Held for Sale

During the 2016 Successor Period, we identified certain drilling rigs to sell. We are required to present such assets at the lower of carrying amount or fair value less the anticipated costs to sell at the time they meet the criteria for held-for-sale accounting. Estimated fair value was based on the expected sales price, less costs to sell. As of December 31, 2016, $8.2 million was included in property and equipment held for sale on our consolidated balance sheet. These assets are included in our drilling segment.

11. Debt

As of December 31, 2016 and 2015, our long-term debt consisted of the following (in thousands):



	Successor		Predecessor
	December 31, 2016		December 31, 2015
6.625% Senior Notes due 2019	$	—	$	650,000
6.50% Senior Notes due 2022	—		450,000
Term Loans	473,250		493,250
Total principal amount of debt	473,250		1,593,250
Less:
Discount on Term Loans	43,038		—
Current portion of long-term debt	5,000		5,000
Unamortized deferred financing costs	—		23,658
Total long-term debt	$	425,212	$	1,564,592

2019 Senior Notes

In October 2011, we issued $650.0 million in aggregate principal amount of 6.625% Senior Notes due 2019. The filings of the Bankruptcy Petitions described in Note 3 constituted an event of default with respect to the 2019 Notes. The Company did not make the payment of $21.5 million in accrued interest that was due on May 15, 2016. The amount of contractual interest on the 2019 Notes that was not recorded from June 7, 2016 through July 31, 2016 was $6.5 million.

On the Effective Date, by operation of the Plan, all outstanding obligations under the 2019 Notes were cancelled.

2022 Senior Notes

In June 2014, we issued $500.0 million in aggregate principal amount of 6.50% Senior Notes due 2022. The filings of the Bankruptcy Petitions described in Note 3 constituted an event of default with respect to the 2022 Notes. The Company did not make the payment of $14.6 million in accrued interest that was due on July 15, 2016. The amount of contractual interest on the 2022 Notes that was not recorded from June 7, 2016 through July 31, 2016 was $4.4 million.

On the Effective Date, by operation of the Plan, all outstanding obligations under the 2022 Notes were cancelled.

During the year ended December 31, 2015, we repurchased and cancelled $50.0 million in aggregate principal amount of the 2022 Notes in multiple transactions for $31.3 million. We recognized gains on extinguishment of debt of $18.1 million, which included the accelerated amortization of deferred financing costs of $0.6 million.

Term Loans

In June 2014, we entered into a $400.0 million seven-year term loan credit agreement. Borrowings under the Term Loan bear interest at our option at either (i) the Base Rate, calculated as the greatest of (1) the Bank of America, N.A. prime rate, (2) the federal funds rate plus 0.50% and (3) a one-month London Interbank Offered Rate (“LIBOR”) rate adjusted daily plus 1.00% or (ii) LIBOR, with a floor of 0.75%, plus, in each case, an applicable margin. The applicable margin for borrowings is 2.00% for Base Rate loans and 3.00% for LIBOR loans, depending on whether the Base Rate or LIBOR is used, provided that if and for so long as the leverage ratio is less than a certain level and the term loans have certain ratings from each of S&P and Moody’s, such margins will be reduced by 0.25%. As of December 31, 2016, the applicable rate for borrowings under the Term Loan was 3.88733%. The Term Loan is repayable in equal consecutive quarterly installments equal to 0.25% (1.00% per annum) of the original principal amount of the Term Loan and will mature in full on June 25, 2020.

Obligations under the Term Loan are guaranteed jointly and severally by all of our present and future direct and indirect wholly-owned material domestic subsidiaries, other than certain excluded subsidiaries. Amounts borrowed under the Term Loan are secured by liens on all of our equity interests in our current and future subsidiaries, and all of our subsidiaries’ present and future real property, equipment (including drilling rigs and frac spread equipment), fixtures and other fixed assets.

We may prepay all or a portion of our Term Loan at any time. Borrowings under our Term Loan may be subject to mandatory prepayments with the net cash proceeds of certain issuances of debt, certain asset sales and other dispositions and certain condemnation events, and with excess cash flow in any calendar year in which our leverage ratio exceeds 3.25 to 1.00. The Term Loan contains various covenants and restrictive provisions which limit our ability to (1) enter into asset sales; (2) incur additional indebtedness; (3) make investments or loans and create liens; (4) pay certain dividends or make other distributions and (5) engage in transactions with affiliates. We are in compliance with the related covenants as of December 31, 2016.

In May 2015, we entered into an incremental term supplement to the Term Loan and borrowed an additional $100.0 million in aggregate principal amount (the “Incremental Term Loan”), receiving net proceeds of $94.5 million. Borrowings under the Incremental Term Loan bear interest at our option at either (i) LIBOR, with a floor of 1.00% or (ii) the Base Rate, calculated as the greatest of (1) the Bank of America, N.A. prime rate, (2) the federal funds rate plus 0.50% and (3) a one-month LIBOR rate adjusted daily plus 1.00%, plus, in each case, an applicable margin. The applicable margin for borrowings is 9.00% for LIBOR loans and 8.00% for Base Rate loans, depending on whether the Base Rate or LIBOR is used. As of December 31, 2016, the applicable rate for borrowings under the Incremental Term Loan was 10.00%. The Incremental Term Loan is payable in equal consecutive quarterly installments equal to 0.25% (1.00% per annum) of the original principal amount of the Incremental Term Loan and will mature in full on June 25, 2021.

Obligations under the Incremental Term Loan are guaranteed jointly and severally by all of our present and future direct and indirect wholly-owned material domestic subsidiaries, other than certain excluded subsidiaries. Amounts borrowed under the Incremental Term Loan are secured by liens on all of our equity interests in our current and future subsidiaries, and all of our subsidiaries’ present and future real property, equipment (including drilling rigs and frac spread equipment), fixtures and other fixed assets.

We may prepay all or a portion of our Incremental Term Loan at any time. Borrowings under our Incremental Term Loan may be subject to mandatory prepayments with the net cash proceeds of certain issuances of debt, certain asset sales and other dispositions and certain condemnation events, and with excess cash flow in any calendar year in which our leverage ratio exceeds 3.25 to 1.00. The Incremental Term Loan contains various covenants and restrictive provisions which limit our ability

to (1) enter into asset sales; (2) incur additional indebtedness; (3) make investments or loans and create liens; (4) pay certain dividends or make other distributions and (5) engage in transactions with affiliates. All prepayments of the Incremental Term Loan, except for mandatory prepayments described above, if made on or prior to the 42-month anniversary of the Incremental Term Loan, are subject to a prepayment premium equal to (i) a make-whole premium determined pursuant to a formula set forth in the Incremental Term Loan if made on or prior to the 18-month anniversary of the Incremental Term Loan, (ii) 5.00% of such principal amount if made after the 18-month anniversary and on or prior to the 30-month anniversary of the Incremental Term Loan, or (iii) 3.00% of such principal amount if made after the 30-month anniversary and on or prior to the 42-month anniversary of the Incremental Term Loan. We are in compliance with the related covenants as of December 31, 2016.

The filings of the Bankruptcy Petitions described in Note 3 constituted an event of default with respect to the Term Loan and the Incremental Term Loan. Upon the Effective Date of the Plan, such defaults were deemed cured or waived. As outlined in the Plan, we paid a consent fee equal to 2% of the Term Loan and Incremental Term Loan, paid $15.0 million of the Incremental Term Loan balance and the Incremental Term Loan prepayment premium was suspended for an 18-month period beginning on the Effective Date of the Plan.

On the Effective Date, by operation of the Plan, the Company entered into an amendment to the Term Loan and related guaranty agreement that, among other things, requires us to use commercially reasonable efforts to maintain credit ratings with Moody’s Investor Service, Inc. and Standard & Poor’s Rating Services, restrict our ability to create foreign subsidiaries, and revise certain provisions to address the granting of new liens on our assets.

In addition, on the Effective Date, by operation of the Plan, the Company entered into a waiver in respect of the Incremental Term Loan (the “Incremental Term Loan Waiver”) whereby the incremental term lenders agreed to waive their right to any prepayment premium that may be payable in respect of the Incremental Term Loan (other than in connection with a pre-maturity acceleration of the Incremental Term Loan) for a period of eighteen months following the Effective Date. The Company also entered into an amendment to the Incremental Term Loan and the related guaranty agreement to revise certain provisions to address the granting of new liens on our assets.

On the Effective Date, by operation of the Plan, the Company entered into new amended and restated security documentation in connection with the Term Loan and Incremental Term Loan that grants liens on and security interests in substantially all of our assets (subject to certain exclusions). The Company also entered into an inter-creditor agreement with the agents for the New ABL Credit Facility, the Term Loan and the Incremental Term Loan that will govern the rights of its lenders with respect to the distribution of proceeds from our assets securing our obligations under the New ABL Credit Facility, the Term Loan and the Incremental Term Loan.

Senior Secured Debtor-In-Possession Credit Agreement

New ABL Credit Facility

On the Effective Date, by operation of the Plan, certain of our domestic subsidiaries as borrowers entered into a five-year senior secured revolving credit facility with total commitments of $100.0 million. The maximum amount that we may borrow under the New ABL Credit Facility is subject to the borrowing base, which is based on a percentage of eligible accounts receivable, subject to reserves and other adjustments.

All obligations under the New ABL Credit Facility are fully and unconditionally guaranteed jointly and severally by the Company and all of our other present and future direct and indirect material domestic subsidiaries. Borrowings under the New ABL Credit Facility are secured by liens on substantially all of our personal property, and bear interest at our option at either (i) the Base Rate, calculated as the greatest of (1) the rate of interest publicly announced by Wells Fargo Bank, National Association, as its “prime rate,” subject to each increase or decrease in such prime rate effective as of the date such change occurs, (2) the federal funds effective rate plus 0.50% and (3) the one-month LIBOR Rate plus 1.00%, each of which is subject to an applicable margin, or (ii) LIBOR, plus, in each case, an applicable margin. The applicable margin ranges from 1.00% to 1.50% per annum for Base Rate loans and 2.00% to 2.50% per annum for LIBOR loans. The unused portion of the New ABL Credit Facility is subject to a commitment fee that varies from 0.375% to 0.50% per annum, according to average unused amounts. Interest on LIBOR loans is payable at the end of the selected interest period, but no less frequently than quarterly. Interest on Base Rate loans is payable monthly in arrears.

The New ABL Credit Facility contains various covenants and restrictive provisions which limit our ability to (1) enter into asset sales; (2) incur additional indebtedness; (3) make investments or loans and create liens; (4) pay certain dividends or make other distributions and (5) engage in transactions with affiliates. The New ABL Credit Facility also requires maintenance of a fixed charge coverage ratio based on the ratio of consolidated EBITDA to fixed charges, in each case as defined in the New ABL Credit Facility. If we fail to perform our obligations under the agreement that results in an event of default, the commitments under the New ABL Credit Facility could be terminated and any outstanding borrowings under the New ABL Credit Facility may be declared immediately due and payable. The New ABL Credit Facility also contains cross default provisions that apply to our other indebtedness. We are in compliance with the related covenants as of December 31, 2016.

As of December 31, 2016, we had no borrowings outstanding under the New ABL Credit Facility, letters of credit of $15.9 million and availability of $58.6 million.

12. Other Current Liabilities

Other current liabilities as of December 31, 2016 and 2015 are detailed below (in thousands):



	Successor		Predecessor
	December 31, 2016		December 31, 2015

Other Current Liabilities:
Payroll-related accruals	$	15,964	$	21,561
Accrued operating expenses	15,499		29,760
Self-insurance reserves	7,638		9,718
Income, property, sales, use and other taxes	4,899		8,336
Accrued capital expenditures	2,115		5,993
Interest	3,661		22,950
Total Other Current Liabilities	$	49,776	$	98,318

13. Commitments and Contingencies

Operating Leases

As of December 31, 2016, we were also party to various lease agreements for other property and equipment with varying terms.

Aggregate undiscounted minimum future lease payments under our operating leases at December 31, 2016 are presented below:



	Rail Cars		Other		Total
	(in thousands)
2017	$	3,290	$	417	$	3,707
2018	2,165		259		$	2,424
2019	1,331		30		$	1,361
2020	490		—		$	490
Total	$	7,276	$	706	$	7,982

Rent expense for drilling rigs, real property, rail cars and other property and equipment for the 2016 Successor Period, the 2016 Predecessor Period, and the years ended December 31, 2015 and 2014 was $2.4 million, $4.1 million, $8.0 million and $35.5 million, respectively, and was included in operating costs in our consolidated statements of operations.

Litigation

We are involved in various lawsuits and disputes incidental to our business operations, including commercial disputes, personal injury claims, property damage claims and contract actions. We record an associated liability when a loss is probable and the amount can be reasonably estimated. Although the outcome of litigation cannot be predicted with certainty, management is of the opinion that no pending or threatened lawsuit or dispute incidental to our business operations is likely to have a material adverse effect on our consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued and actual results could differ materially from management’s estimates.

Self-Insured Reserves

We are self-insured up to certain retention limits with respect to workers’ compensation and general liability matters. We maintain accruals for self-insurance retentions that we estimate using third-party data and claims history. Included in operating costs is workers’ compensation (credits) expense of ($1.5) million, $2.4 million, $4.0 million and $8.3 million for the 2016 Successor Period, the 2016 Predecessor Period, and the years ended December 31, 2015 and 2014, respectively.

14. Share-Based Compensation

2016 Omnibus Incentive Plan

In accordance with the Plan, on September 20, 2016, the Company adopted the 2016 Omnibus Incentive Plan. Our stock-based compensation program currently consists of restricted stock units available to employees and directors, which are equity-classified awards. The aggregate number of shares of common stock reserved for issuance pursuant to the 2016 Omnibus Incentive Plan is 2,200,000.

The fair value of the restricted stock units is determined based on the estimated fair market value of SSE common shares on the date of grant. This value is amortized over the vesting period. Included in operating costs and general and administrative expenses is stock-based compensation expense of $10.6 million for the 2016 Successor Period related to the 2016 Omnibus Incentive Plan.

A summary of the status of changes of unvested shares of restricted stock units under the 2016 Omnibus Incentive Plan is presented below:



	Number of Unvested Restricted Shares		Weighted Average Grant-Date Fair Value
	(In thousands)
Unvested shares as of September 20, 2016	—		$	—
Granted	1,945		$	17.31
Vested	(605	)	$	17.31
Forfeited	—		$	—
Unvested shares as of December 31, 2016	1,340		$	17.31

As of December 31, 2016, there was $23.1 million of total unrecognized compensation cost related to the unvested restricted stock units. The cost is expected to be recognized over a period of 33 months.

2014 Incentive Plan

Prior to the spin-off, our employees participated in the CHK share-based compensation program and received restricted stock, and in the case of senior management, stock options. Effective July 1, 2014, our employees began participating in the SSE 2014 Incentive Plan. The 2014 Incentive Plan consisted of restricted stock available to employees and stock options. The restricted stock awards and stock options were equity-classified awards.

In connection with the spin-off, unvested awards granted under the CHK share-based compensation program were cancelled and substituted as follows:


•	Each outstanding award of options to purchase shares of CHK common stock was replaced with a substitute award of options to purchase shares of Predecessor SSE common stock. The substitute awards of options were intended to preserve the intrinsic value of the original option and the ratio of the exercise price to the fair market value of the stock subject to the option.


•	The CHK restricted stock awards and restricted stock unit awards were replaced with substitute awards in Predecessor SSE common stock, each of which generally preserved the value of the original award.

Awards granted in connection with the substitution of awards originally issued under the CHK share-based compensation program were a part of the 2014 Incentive Plan and reduced the maximum number of shares of common stock available for delivery under the 2014 Incentive Plan.

Upon the Company’s emergence from bankruptcy on August 1, 2016, as discussed in Note 3, the Company’s common stock was canceled and New Common Stock was issued. SSE’s existing stock-based compensation awards under the 2014 Incentive Plan were also either vested or canceled upon the Company’s emergence from bankruptcy. Accelerated vesting and cancellation of these stock-based compensation awards resulted in the recognition of expense, on the date of vesting or cancellation, to record any previously unamortized expense related to the awards.

Equity-Classified Awards

Restricted Stock. The fair value of restricted stock awards was determined based on the fair market value of SSE common shares on the date of the grant. This value was amortized over the vesting period. All unvested restricted stock awards under the 2014 Incentive Plan vested upon the Company’s emergence from bankruptcy. During the 2016 Predecessor Period, the Company recognized expense of $24.9 million as a result of the accelerated vesting of these awards, which is included in reorganization items, net in the consolidated statement of operations.

A summary of the changes of the shares of restricted stock under the 2014 Incentive Plan is presented below.



	Number of Unvested Restricted Shares		Weighted Average Grant-Date Fair Value
	(in thousands)
Unvested shares as of January 1, 2016	5,896		$	11.93
Granted	—		$	—
Vested	(5,746	)	$	6.74
Forfeited	(150	)	$	14.06
Unvested shares as of August 1, 2016	—		$	—

Stock Options. CHK granted stock options to our chief executive officer under CHK’s Long-Term Incentive Plan for incentive and retention purposes, which were replaced with a substitute option to purchase shares of SSE common stock in connection with the spin-off. The substitute incentive-based stock options vested ratably over a three-year period and the substitute retention-based stock options vested one-third on each of the third, fourth and fifth anniversaries of the grant date of the original CHK award. Outstanding options were scheduled to expire ten years from the date of grant of the original CHK award. We have not issued any new stock options, other than the replacement awards, since the spin-off. All stock options awarded under the 2014 Incentive Plan were cancelled upon the Company’s emergence from bankruptcy. During the 2016 Predecessor Period, the Company recognized expense of $0.2 million as a result of the cancellations, which is included in reorganization items, net in the consolidated statement of operations.

The following table provides information related to stock option activity for 2016 Predecessor Period:



	Number of Shares Underlying Options		Weighted Average Exercise Price Per Share		Weighted Average Contract Life in Years	Aggregate Intrinsic Value^(a)
	(in thousands)					(in thousands)
Outstanding at January 1, 2016	348		$	16.19	7.23	$	—
Granted	—		$	—	—	$	—
Exercised	—		$	—	—	$	—
Cancelled	(348	)	$	16.19	—	$	—
Outstanding at August 1, 2016	—		$	—	—	$	—
Exercisable at August 1, 2016	—		$	—	—	$	—

Through the date of the spin-off, we were charged by CHK for share-based compensation expense related to our direct employees. Pursuant to the employee matters agreement with CHK, our employees received a new award under the 2014 Plan in substitution for each unvested CHK award then held (which were cancelled). We recorded a non-recurring credit of $10.5 million to operating costs and general and administrative expenses during the second quarter of 2014 as a result of the cancellation of the unvested CHK awards.

Included in operating costs and general administrative expenses is stock-based compensation expense of $12.3 million, $38.5 million and $29.8 million for the 2016 Predecessor Period and the years ended December 31, 2015 and 2014, respectively, related to the 2014 Incentive Plan.

Other

Performance Share Units. CHK granted performance share units (“PSUs”) to our chief executive officer under CHK’s Long Term Incentive Plan that includes both an internal performance measure and external market condition as it relates to CHK. Following the spin-off, compensation expense is recognized through the changes in fair value of the PSUs over the vesting period with a corresponding adjustment to equity, and any related cash obligations are the responsibility of CHK. We recognized expenses (credits) of a nominal amount, $0.1 million, ($1.6) million and ($0.4) million related to these PSUs for the 2016 Successor Period, the 2016 Predecessor Period and the years ended December 31, 2015 and 2014, respectively.

In March 2016, the FASB issued ASU No. 2016-09, “Compensation - Stock Compensation,” which modifies several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. ASU 2016-09 is effective for annual reporting periods beginning after December 15, 2016 with early adoption permitted. We elected to adopt ASU 2016-09 effective December 31, 2016. The adoption of this standard had no impact on our consolidated financial statements.

15. Income Taxes

The components of income tax benefit for each of the periods presented below are as follows:



	Successor		Predecessor
	Five Months Ended		Seven Months Ended			Years Ended December 31,
	December 31, 2016		July 31, 2016			2015			2014
			(in thousands)
Current	$	—	$	(7	)	$	58		$	674
Deferred	—		(59,124		)	(92,686		)	(2,863		)
Total	$	—	$	(59,131	)	$	(92,628	)	$	(2,189	)

The effective income benefit differed from the computed “expected” federal income tax benefit on loss before income taxes for the following reasons:



	Successor			Predecessor
	Five Months Ended			Seven Months Ended			Years Ended December 31,
	December 31, 2016			July 31, 2016			2015			2014
				(in thousands)
Income tax benefit at the federal statutory rate (35%)	$	(22,246	)	$	(75,195	)	$	(109,906	)	$	(3,559	)
State income taxes (net of federal income tax benefit)	(1,015		)	(2,277		)	(4,118		)	538
Discharge of debt and other reorganization-related items	232,395			(37,283		)	—			—
Stock-based compensation shortfall	(1,282		)	23,443			8,967			—
Executive compensation	2,110			—			—			—
Goodwill impairment	—			—			9,602			—
Other permanent differences	1,192			676			2,518			601
Effect of change in state taxes	(2,010		)	40			(23		)	—
Other	(40		)	155			332			231
Change in valuation allowance	(209,104		)	31,310			—			—
Total	$	—		$	(59,131	)	$	(92,628	)	$	(2,189	)

Deferred income taxes are provided to reflect temporary differences in the basis of net assets for income tax and financial reporting purposes. The tax-effected temporary differences and tax loss carryforwards which comprise deferred taxes are as follows:



	Successor			Predecessor
	December 31, 2016			December 31, 2015

Deferred tax liabilities:
Property and equipment	$	(35,405	)	$	(242,879	)
Term Loan	(16,071		)	—
Intangible assets	(1,563		)	(1,551		)
Prepaid expenses	(2,489		)	(3,580		)
Other	(1,307		)	(1,121		)
Deferred tax liabilities	(56,835		)	(249,131		)

Deferred tax assets:
Net operating loss carryforwards	48,540			172,822
Intangible assets	8,271			—
Deferred stock compensation	47			10,035
Accrued liabilities	3,169			3,231
Other long-term assets	6,156			—
Other	1,128			3,919
Valuation allowance	(10,476		)	—
Deferred tax assets	56,835			190,007
Net deferred tax liability	$	—		$	(59,124	)

Reflected in accompanying balance sheets as:
Current deferred income tax asset	$	—		$	1,499
Non-current deferred income tax liability	—			(60,623		)
Total	$	—		$	(59,124	)

At December 31, 2016, we had NOL carryforwards of approximately $130.6 million. The NOL carryforwards expire from 2034 through 2036. The value of these carryforwards depends on our ability to generate future taxable income. We considered both positive and negative evidence in our determination of the need for valuation allowances for the deferred tax assets associated with our NOLs and other deferred tax assets. As of December 31, 2016, we are in a net deferred tax asset position. We believe it is more likely than not that these deferred tax assets will not be realized, and accordingly, have recorded a full valuation allowance against our net deferred tax assets. In connection with the Company's emergence from Chapter 11 and subsequent application of fresh-start accounting, we recorded a full valuation allowance of $219.6 million in the 2016 Predecessor Period.

As described in Note 3, elements of the Plan provided that our 2019 Notes and 2022 Notes were exchanged for New Common Stock. Absent an exception, a debtor recognizes CODI upon discharge of its outstanding indebtedness for an amount of consideration that is less than its adjusted issue price. The Internal Revenue Code of 1986, as amended (“IRC”), provides that a debtor in a Chapter 11 bankruptcy case may exclude CODI from taxable income but must reduce certain of its tax attributes by the amount of any CODI realized as a result of the consummation of a plan of reorganization. The amount of CODI realized by a taxpayer is determined based on the fair market value of the consideration received by the creditors in settlement of outstanding indebtedness. As a result of the market value of our equity upon emergence from Chapter 11 bankruptcy proceedings, the estimated amount of CODI is approximately $625.3 million, which will reduce the value of the Company's net operating losses. We recorded the reduction of net operating losses related to CODI in the 2016 Successor Period. The deferred tax impact of this tax attribute reduction was fully offset by a corresponding decrease in valuation allowance in the 2016 Successor Period.

The IRC provides an annual limitation with respect to the ability of a corporation to utilize its tax attributes, as well as certain built-in-losses, against future taxable income in the event of a change in ownership. Emergence from Chapter 11 bankruptcy proceedings resulted in a change in ownership for purposes of the IRC. The amount of remaining net operating loss carryforward available after the reduction for CODI will be subject to an annual limitation under IRC Section 382 due to the change in ownership.

In November 2015, the FASB issued ASU No. 2015-17, “Income Taxes,” which simplifies the presentation of deferred income taxes by requiring deferred tax liabilities and assets to be classified as noncurrent in the balance sheet. ASU 2015-17 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption permitted. We elected to adopt this change in accounting principle prospectively as of the bankruptcy emergence date of August 1, 2016. The adoption of this standard had no impact on our consolidated financial statements due to the full valuation allowance against our net deferred tax asset as of August 1, 2016. The adoption of this standard continued to have no impact on our consolidated financial statements due to the full valuation allowance recorded as of December 31, 2016.

16. Equity Method Investment

Effective June 6, 2016, we assigned our 49% ownership of the membership interest in Maalt Specialized Bulk, L.L.C. (“Maalt”) back to the majority owners. Prior to this assignment, we used the equity method of accounting to account for our investment in Maalt, which had a zero value as of June 6, 2016. We recorded equity method adjustments to our investment of $0.9 million and ($1.6) million for our share of Maalt’s income (loss) for the years ended December 31, 2015 and 2014, respectively. We also made additional investments of $0.1 million and $0.7 million for the years ended December 31, 2015 and 2014, respectively.

We reviewed our equity method investment for impairment whenever certain impairment indicators existed, including the absence of an ability to recover the carrying amount of the investment or inability of the investee to sustain an earnings capacity which would justify the carrying amount of the investment. A loss in value of an investment which is other than a temporary decline should be recognized. We estimated that the fair value of our investment in Maalt was approximately zero as of December 31, 2015, which was below the carrying value of the investment and resulted in a non-cash impairment charge of $8.8 million during the year ended December 31, 2015. We also recognized a non-cash impairment charge of $4.5 million for the year ended December 31, 2014. Estimated fair value for our investment in Maalt was determined using significant unobservable inputs (Level 3) based on an income approach.

17. Fair Value Measurements

The fair value measurement standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (referred to as an “exit price”). Authoritative guidance on fair value measurements and disclosures clarifies that a fair value measurement for a liability should reflect the entity’s non-performance risk. In addition, a fair value hierarchy is established that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets and liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are as follows:

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. This category includes quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated by observable market data by correlation or other means.

Level 3- Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources.

Fair Value on Recurring Basis

The carrying values of our cash, trade receivables and trade payables are considered to be representative of their respective fair values due to the short-term nature of these instruments.

Fair Value on Non-Recurring Basis

Fair value measurements were applied with respect to our non-financial assets and liabilities measured on a non-recurring basis, which consist primarily of impairments on long-lived assets, goodwill and an equity method investment based on Level 3 inputs. See Notes 6, 9 and 16 for additional discussion.

Fair Value of Other Financial Instruments

The fair values of our note receivable and debt, as shown in the table below, reflect the estimated amounts that a market participant would have to pay to purchase the note receivable or our debt, including any premium or discount attributable to the difference between the stated interest rate and market rate of interest at the balance sheet date. Fair values are based on quoted market prices, or average valuations of similar debt instruments at the balance sheet date for those debt instruments for which quoted market prices are not available. Estimated fair values are determined using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.



	Successor				Predecessor
	December 31, 2016				December 31, 2015
	Carrying Amount		Fair Value (Level 2)		Carrying Amount		Fair Value (Level 2)
					(in thousands)
Financial assets:
Note Receivable	$	21,243	$	23,498	$	27,000	$	17,842

Financial liabilities:
6.625% Senior Notes due 2019	$	—	$	—	$	642,713	$	221,975
6.50% Senior Notes due 2022	$	—	$	—	$	444,701	$	71,865
Term Loans	$	430,212	$	469,377	$	482,178	$	371,080
Less: Current portion of long-term debt	$	5,000			$	5,000
Total long-term debt	$	425,212			$	1,564,592

18. Concentration of Credit Risk and Major Customers

Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash and trade receivables. Accounts receivable from CHK and its affiliates were $48.6 million and $109.6 million as of December 31, 2016 and December 31, 2015, or 49% and 65%, respectively, of our total accounts receivable.

Revenues from CHK and its affiliates were $114.5 million, $217.6 million, $789.5 million and $1.676 billion for the 2016 Successor Period, the 2016 Predecessor Period and the years ended December 31, 2015 and 2014, or 51%, 65%, 70% and 81%, respectively, of our total revenues. Additionally, revenues from another customer of our Hydraulic Fracturing segment represents approximately 11% of our total revenues during the 2016 Successor Period. We believe that the loss of these customers would have a material adverse effect on our operating results as there can be no assurance that replacement customers would be identified and accessed in a timely fashion.

Included in total revenues are amounts related to IBC payments of $38.9 million, $80.7 million and $87.9 million for the 2016 Successor Period, the 2016 Predecessor Period and the year ended December 31, 2015 respectively. Excluding IBC revenues, non-CHK revenue as a percentage of total revenue was 58% and 42% for the 2016 Successor Period and 2016 Predecessor Period, respectively, compared to 32% for the year ended December 31, 2015. See Note 19 for further discussion of agreements entered into with CHK as part of the spin-off, including a services agreement and rig-specific daywork drilling contracts.

19. Transactions with CHK

Prior to the completion of our spin-off on June 30, 2014, we were a wholly owned subsidiary of CHK, and transactions between us and CHK (including its subsidiaries) were considered to be transactions with affiliates. Subsequent to June 30, 2014, CHK and its subsidiaries are not considered affiliates of us or any of our subsidiaries. We have disclosed below all agreements entered into between us and CHK prior to the completion of our spin-off.

On June 25, 2014, we entered into a master separation agreement and several other agreements with CHK as part of the spin-off. The master separation agreement entered into between CHK and us governs the separation of our businesses from CHK, the distribution of our shares to CHK shareholders and other matters related to CHK’s relationship with us, including cross-indemnities between us and CHK. In general, CHK agreed to indemnify us for any liabilities relating to CHK’s business and we agreed to indemnify CHK for any liabilities relating to our business.

On June 25, 2014, we entered into a tax sharing agreement with CHK, which governs the respective rights, responsibilities and obligations of CHK and us with respect to tax liabilities and benefits, tax attributes, the preparation and filing of tax returns, the control of audits and other tax proceedings, and certain other matters regarding taxes.

On June 25, 2014, we entered into an employee matters agreement with CHK providing that each company has responsibility for its own employees and compensation plans. The agreement also contains provisions concerning benefit protection for both SSE and CHK employees, treatment of holders of CHK stock options, restricted stock, restricted stock units and performance share units, and cooperation between us and CHK in the sharing of employee information and maintenance of confidentiality.

On June 25, 2014, we entered into a transition services agreement with CHK under which CHK provided or made available to us various administrative services and assets for specified periods beginning on the distribution date. In consideration for such services, we paid CHK certain fees, a portion of which was a flat fee, generally in amounts intended to allow CHK to recover all of its direct and indirect costs incurred in providing those services. These charges from CHK were $8.3 million and $18.0 million for the years ended December 31, 2015 and 2014, respectively. This agreement was terminated during the second quarter of 2015.

We are party to a master services agreement with CHK pursuant to which we provide drilling and other services and supply materials and equipment to CHK. Drilling services are typically provided pursuant to rig-specific daywork drilling contracts similar to those we use for other customers. The specific terms of each request for other services are typically set forth in a field ticket, purchase order or work order. The master services agreement contains general terms and provisions, including minimum insurance coverage amounts that we are required to maintain and confidentiality obligations with respect to CHK’s business, and allocates certain operational risks between CHK and us through indemnity provisions. The master services agreement will remain in effect until we or CHK provides 30 days written notice of termination, although such agreement may not be terminated during the term of the services agreement described below.

Prior to the spin-off, we were party to a services agreement with CHK under which CHK guaranteed the utilization of a portion of our drilling rig and hydraulic fracturing fleets during the term of the agreement. In connection with the spin-off, we entered into new services agreements with CHK which supplements the master services agreement. Under the new services agreement, CHK is required to utilize the lesser of (i) seven, five and three of our hydraulic fracturing crews in years one, two and three of the agreement, respectively, or (ii) 50% of the total number of all hydraulic fracturing crews working for CHK in all its operating regions during the respective year. CHK is required to utilize our hydraulic fracturing services for a minimum number of stages as set forth in the agreement. CHK is entitled to terminate the agreement in certain situations, including in the event we fail to materially comply with the overall quality of service provided by similar service providers. Additionally, CHK’s requirement to utilize our services may be suspended under certain circumstances, such as if we are unable to timely accept and supply services ordered by CHK or as a result of a force majeure event.

In connection with the spin-off, we entered into rig-specific daywork drilling contracts with CHK for the provision of drilling services. The drilling contracts had a commencement date of July 1, 2014 and terms ranging from three months to three years. CHK has the right to terminate the drilling contracts under certain circumstances.

Prior to the spin-off, we were party to a facilities lease agreement with CHK pursuant to which we leased a number of the storage yards and physical facilities out of which we conduct our operations. We incurred $8.2 million of lease expense for the

year ended December 31, 2014 under this facilities lease agreement. In connection with the spin-off, we acquired the property subject to the facilities lease agreement, and the facilities lease agreement was terminated.

Prior to the spin-off, CHK provided us with general and administrative services and the services of its employees pursuant to an administrative services agreement. These services included legal, accounting, treasury, environmental, safety, information technology and other corporate services. In return for the general and administrative services provided by CHK, we reimbursed CHK on a monthly basis for the overhead expenses incurred by CHK on our behalf in accordance with its allocation policy, which included costs and expenses incurred in connection with the provision of any of the services under the agreement, including the wages and benefits of CHK employees who perform services on our behalf. The administrative expense allocation was determined by multiplying revenues by a percentage determined by CHK based on the historical average of costs incurred on our behalf. All of the administrative cost allocations were based on assumptions that management believes are reasonable; however, these allocations are not necessarily indicative of the costs and expenses that would have resulted if we had been operating as a stand-alone entity. These charges from CHK were $26.8 million for the year ended December 31, 2014. In connection with the spin-off, we terminated the administrative services agreement and entered into the transition services agreement described above.

20. Segment Information

As of December 31, 2016, our revenues, income (loss) before income taxes and identifiable assets are primarily attributable to three reportable segments. During the second quarter of 2015, we sold the remaining business and assets included in our former oilfield trucking segment. Our former oilfield trucking segment’s historical results for periods prior to the sale continue to be included in our historical financial results as a component of continuing operations as reflected in the tables below.

Each of these segments represents a distinct type of business. These segments have separate management teams which report to our chief operating decision-maker. The results of operations in these segments are regularly reviewed by the chief operating decision-maker for purposes of determining resource allocation and assessing performance. Management evaluates the performance of our segments based upon adjusted earnings before interest, taxes and depreciation and amortization.

Prior to 2016, the information that was regularly reviewed by our chief operating decision-maker included general and administrative expenses that were allocated to each of our reportable segments for corporate overhead functions provided by the Other Operations segment on behalf of our reportable segments. Effective January 1, 2016, we no longer allocate general and administrative expenses to our reportable segments from the Other Operations segment in the information that is reviewed by our chief operating decision-maker. For comparability purposes, this change has been reflected through retroactive revision of our segment information for the year ended December 31, 2015.

The following is a description of our segments and other operations:

Drilling. Our drilling segment provides land-based drilling services. As of December 31, 2016, we owned a fleet of 91 land drilling rigs.

Hydraulic Fracturing. Our hydraulic fracturing segment provides land-based hydraulic fracturing and other well stimulation services. As of December 31, 2016, we owned 13 hydraulic fracturing fleets with an aggregate of 500,000 horsepower.

Oilfield Rentals. Our oilfield rentals segment provides premium rental tools for land-based drilling, completion and workover activities.

Former Oilfield Trucking. Our oilfield trucking segment historically provided drilling rig relocation and logistics services as well as fluid handling services. During the second quarter of 2015, we sold Hodges and sold our water hauling assets. As part of the spin-off, we sold our crude hauling assets to a third party. As of June 30, 2015, there were no remaining assets or operations in the oilfield trucking segment, although we do have ongoing liabilities, primarily related to insurance claims, whose income statement impact is charged to general and administrative expense. Our former oilfield trucking segment’s historical results for periods prior to the sale continue to be included in our historical financial results as a component of continuing operations as reflected in the tables below.

100

Other Operations. Our other operations consists primarily of our corporate functions, including our Term Loans and New ABL Credit Facility for the Successor Period and 2019 Notes, 2022 Notes, Term Loans and Pre-Petition Credit Facility for the Predecessor periods.



	Drilling			Hydraulic Fracturing			Oilfield Rentals			Other Operations			Intercompany Eliminations			Consolidated Total
	(in thousands)
Successor
For the Five Months Ended December 31, 2016:
Revenues	$	116,767		$	89,493		$	16,361		$	1,197		$	(1,440	)	$	222,378
Intersegment revenues	(37		)	—			(206		)	(1,197		)	1,440			—
Total revenues	$	116,730		$	89,493		$	16,155		$	—		$	—		$	222,378
Depreciation and amortization	26,979			34,079			9,032			3,808			—			73,898
Losses (gains) on sales of property and equipment, net	(984		)	31			(590		)	(205		)	—			(1,748		)
Interest expense	—			—			—			(15,497		)	—			(15,497		)
Other income	100			63			75			1,874			—			2,112
Reorganization items, net	(43		)	(32		)	(13		)	(1,780		)	—			(1,868		)
Income (Loss) Before Income Taxes	$	37,934		$	(45,385	)	$	(5,140	)	$	(50,968	)	$	—		$	(63,559	)
Capital Expenditures	$	10,658		$	989		$	805		$	50		$	—		$	12,502

As of December 31, 2016:
Total Assets	$	551,870		$	148,524		$	40,677		$	207,479		$	—		$	948,550



	Drilling			Hydraulic Fracturing			Oilfield Rentals			Other Operations			Intercompany Eliminations			Consolidated Total
	(in thousands)
Predecessor
For the Seven Months Ended July 31, 2016
Revenues	$	154,813		$	160,723		$	18,597		$	4,842		$	(5,056	)	$	333,919
Intersegment revenues	(19		)	—			(195		)	(4,842		)	5,056			—
Total revenues	$	154,794		$	160,723		$	18,402		$	—		$	—		$	333,919
Depreciation and amortization	87,160			49,124			18,773			7,368			—			162,425
Losses (gains) on sales of property and equipment, net	1,211			66			(425		)	(4		)	—			848
Impairments and other	3,205			—			287			2,624			—			6,116
Interest expense	—			—			—			(48,116		)	—			(48,116		)
Other income	362			349			3			1,604			—			2,318
Reorganization items, net	(514,627		)	(45,046		)	(18,966		)	548,747			—			(29,892		)
Income (Loss) Before Income Taxes	$	(509,157	)	$	(91,966	)	$	(39,638	)	$	425,920		$	—		$	(214,841	)
Capital Expenditures	$	66,084		$	16,302		$	—		$	401		$	—		$	82,787

101



	Drilling			Hydraulic Fracturing			Oilfield Rentals			Former Oilfield Trucking			Other Operations			Intercompany Eliminations			Consolidated Total
	(in thousands)
Predecessor
For The Year Ended December 31, 2015:
Revenues	$	437,749		$	575,495		$	77,292		$	45,512		$	8,461		$	(13,265	)	$	1,131,244
Intersegment revenues	(1,345		)	—			(705		)	(2,773		)	(8,442		)	13,265			—
Total revenues	$	436,404		$	575,495		$	76,587		$	42,739		$	19		$	—		$	1,131,244
Depreciation and amortization	163,380			70,605			41,049			8,787			11,600			—			295,421
Losses (gains) on sales of property and equipment, net	10,566			230			(1,780		)	5,728			(88		)	—			14,656
Impairment of goodwill	27,434			—			—			—			—			—			27,434
Impairments and other	14,329			—			—			2,737			1,566			—			18,632
Gains on early extinguishment of debt	—			—			—			—			18,061			—			18,061
Interest expense	—			—			—			—			(99,267		)	—			(99,267		)
Loss and impairment from equity investees	—			(7,928		)	—			—			—			—			(7,928		)
Other income	813			1,201			68			16			954			—			3,052
Loss Before Income Taxes (as Previously Reported)	$	(43,195	)	$	(22,680	)	$	(40,216	)	$	(38,420	)	$	(169,508	)	$	—		$	(314,019	)
Corporate overhead allocation	31,894			25,647			9,109			4,182			(70,832		)	—			—
Loss Before Income Taxes (as Adjusted)	$	(11,301	)	$	2,967		$	(31,107	)	$	(34,238	)	$	(240,340	)	$	—		$	(314,019	)
Capital Expenditures	$	153,279		$	32,743		$	6,706		$	—		$	12,978		$	—		$	205,706

As of December 31, 2015:
Total Assets	$	1,144,144		$	291,584		$	92,588		$	—		$	374,302		$	—		$	1,902,618

For The Year Ended December 31, 2014:
Revenues	$	774,888		$	885,907		$	154,416		$	195,618		$	109,942		$	(39,879	)	$	2,080,892
Intersegment revenues	(358		)	—			(1,296		)	(5,139		)	(33,086		)	39,879			—
Total revenues	$	774,530		$	885,907		$	153,120		$	190,479		$	76,856		$	—		$	2,080,892
Depreciation and amortization	140,884			72,105			52,680			21,817			5,426			—			292,912
Losses (gains) on sales of property and equipment, net	17,931			(17		)	(2,355		)	(21,853		)	22			—			(6,272		)
Impairments and other^(a)	29,602			207			955			—			—			—			30,764
Interest expense	—			—			—			—			(79,734		)	—			(79,734		)
Loss and impairment from equity investees	—			(6,094		)	—			—			—			—			(6,094		)
Other income (expense)	364			60			179			226			(165		)	—			664
Income (Loss) Before Income Taxes	$	79,999		$	63,548		$	(2,459	)	$	6,359		$	(157,615	)	$	—		$	(10,168	)
Capital Expenditures	$	373,353		$	37,211		$	22,337		$	3,599		$	21,118		$	—		$	457,618

As of December 31, 2014:
Total Assets	$	1,322,160		$	449,966		$	155,683		$	138,909		$	224,754		$	(1,179	)	$	2,290,293


(a)	Includes lease termination costs of $9.7 million for the year ended December 31, 2014, respectively.

102

21. Quarterly Financial Data (unaudited)

Summarized unaudited quarterly financial data for 2016 and 2015 are as follows (in thousands):



	Successor						Predecessor
	Three Months Ended December 31, 2016			Two Months Ended September 30, 2016			One Month Ended July 31, 2016			Three Months Ended June 30, 2016			Three Months Ended March 31, 2016

Revenues	$	142,722		$	79,656		$	40,438		$	138,120		$	155,361
Operating loss ^(a)	$	(17,323	)	$	(30,983	)	$	(21,294	)	$	(74,496	)	$	(43,361	)
Net loss^(a)	$	(27,031	)	$	(36,528	)	$	(11,640	)	$	(84,505	)	$	(59,563	)
Loss per share^(c):
Basic	$	(1.21	)	$	(1.66	)	$	(0.21	)	$	(1.53	)	$	(1.09	)
Diluted	$	(1.21	)	$	(1.66	)	$	(0.21	)	$	(1.53	)	$	(1.09	)



	Predecessor
	Three Months Ended December 31, 2015			Three Months Ended September 30, 2015			Three Months Ended June 30, 2015			Three Months Ended March 31, 2015

Revenues	$	192,788		$	213,541		$	295,128		$	429,787
Operating loss ^(b)	$	(45,818	)	$	(46,281	)	$	(104,645	)	$	(31,193	)
Net loss^(b)	$	(60,590	)	$	(48,530	)	$	(74,670	)	$	(37,601	)
Loss per share^(c):
Basic	$	(1.18	)	$	(0.95	)	$	(1.51	)	$	(0.78	)
Diluted	$	(1.18	)	$	(0.95	)	$	(1.51	)	$	(0.78	)

(a)

Includes $2.9 million, $0.1 million, ($0.5) million, $23.7 million and $4.7 million in restructuring charges related to the Chapter 11 filing for the quarter ended December 31, 2016, the two months ended September 30, 2016, the one month ended July 31, 2016, the quarter ended June 30, 2016 and the quarter ended March 31, 2016, respectively. Includes $1.6 million, $0.2 million, $16.5 million and $13.4 million in reorganization items related to the Chapter 11 filing for the quarter ended December 31, 2016, the two months ended September 30, 2016, the one month ended July 31, 2016 and the quarter ended June 30, 2016, respectively. Includes $0.02 million, $5.8 million and $0.3 million of impairments and other for the one month ended July 31, 2016, the quarter ended June 30, 2016 and the quarter ended March 31, 2016, respectively.


(b)	Includes $35.0 million of loss on sale of a business for the quarter ended June 30, 2015, $27.4 million of impairment of goodwill for the quarter ended December 31, 2015 and $1.9 million, $1.6 million, $8.8 million and $6.3 million of impairments and other for the quarters ended December 31, 2015, September 30, 2015, June 30, 2015 and March 31, 2015, respectively.


(c)	The sum of quarterly net income per share may not agree to the total for the year as each period’s computation is based on the weighted average number of common shares outstanding during each period.

22. Recently Issued and Proposed Accounting Standards

103

In January 2016, the FASB issued ASU No. 2016-01, “Financial Instruments - Overall,” which requires separate presentation of financial assets and liabilities on the balance sheet and requires evaluation of the need for valuation allowance of deferred tax assets related to available-for-sale securities. ASU 2016-01 is effective for annual reporting periods beginning after December 15, 2017 with early adoption not permitted. We do not expect the adoption of this guidance will have a material effect on our consolidated financial statements.

23. Subsequent Events

Between January 1, 2017 and February 9, 2017, 564,854 Series A Warrants were exercised through cash settlement and 30,201 Series A Warrants were exercised through net share settlement. As a result, the Company received cash proceeds of $13.5 million and issued 578,986 shares of New Common Stock subsequent to December 31, 2016.



Item 9.	Changes In and Disagreements with Accountants on Accounting and Financial Disclosure

None.

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Item 9A.	Controls and Procedures

Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to provide reasonable assurance that information required to be disclosed by us in reports that we file or submit under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our chief executive officer (“CEO”) (principal executive officer) and chief financial officer (“CFO”) (principal financial officer), as appropriate, to allow for timely decisions regarding required disclosure.

As required by SEC Rule 13a-15(b), we carried out an evaluation, under the supervision and with the participation of our management, including our CEO and CFO, of the effectiveness of our disclosure controls and procedures as of December 31, 2016. Based on that evaluation, the CEO and CFO have concluded that those disclosure controls and procedures were effective as of December 31, 2016.

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) and 15d-15(f) of the Exchange Act.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Under the supervision and with the participation of our management, including the CEO and the CFO, we carried out an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2016 using the criteria established in “Internal Control-Integrated Framework” (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our assessment we concluded that, as of December 31, 2016, our internal control over financial reporting was effective based on the criteria in “Internal Control - Integrated Framework” (2013) issued by the COSO.

Previously Reported Material Weakness

As previously reported in our amended Annual Report on Form 10-K/A for the year ended December 31, 2015, our management concluded that our internal control over financial reporting and our disclosure controls and procedures were ineffective as of December 31, 2015 as a result of the following material weakness:

We did not design and maintain effective controls related to the recoverability of the carrying value of property and equipment. Specifically, we did not design a review precise enough to determine the accuracy and support of certain assumptions related to the property and equipment impairment assessments.

To remediate the material weakness described above and enhance our internal control over financial reporting, during the quarter ended December 31, 2016, management conducted a thorough review of its internal controls over the recoverability of the carrying value of property and equipment. Following this review, management implemented control activities to specifically address the accuracy of significant assumptions used in performing the “Step 1” recoverability test related to property and equipment asset groups, the level at which those activities are performed, and the evidence maintained in support of those review activities. As a result of the above actions, management has determined that the material weakness related to the recoverability of the carrying value of property and equipment has been remediated.

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Changes in Internal Control Over Financial Reporting

As desribed above under Previously Reported Material Weakness, there were changes in our internal control over financial reporting during the quarter ended December 31, 2016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

/s/ Jerry Winchester

Jerry Winchester

Director, President and Chief Executive Officer

/s/ Cary Baetz

Cary Baetz

Chief Financial Officer and Treasurer

February 13, 2017



Item 9B.	Other Information

Not applicable.

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PART III



Item 10.	Directors, Executive Officers and Corporate Governance

Information required by Item 10 of Part III is incorporated herein by reference to the definitive Proxy Statement to be filed by us pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 30, 2017 (the “2017 Proxy Statement”).



Item 11.	Executive Compensation

The information required by Item 11 of Part III is incorporated by reference to the 2017 Proxy Statement.



Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information required by Item 12 of Part III is incorporated by reference to the 2017 Proxy Statement.



Item 13.	Certain Relationships and Related Transactions and Director Independence

The information required by Item 13 of Part III is incorporated by reference to the 2017 Proxy Statement.



Item 14.	Principal Accountant Fees and Services

The information required by Item 14 of Part III is incorporated by reference to the 2017 Proxy Statement.

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PART IV



Item 15.	Exhibits, Financial Statement Schedules

The following exhibits are filed as a part of this report:



		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	Commission File No.	Exhibit	Filing Date	Filed Herewith	Furnished Herewith
2.1	Master Separation Agreement, dated as of June 25, 2014, by and between Chesapeake Oilfield Operating, L.L.C., and Chesapeake Energy Corporation.	8-K	001-36354	2.1	7/1/2014
2.2	Confirmation Order for Prepackaged Plan of Reorganization	8-K	001-36354	2.1	7/20/2016
2.3	Agreement and Plan of Merger by and among Patterson-UTI Energy, Inc., Pyramid Merger Sub, Inc. and Seventy Seven Energy Inc., dated as of December 12, 2016	8-K	001-36354	2.1	12/13/2016
3.1	Certificate of Incorporation of Seventy Seven Energy Inc.	8-K	001-36354	3.1	8/4/2016
3.2	Bylaws of Seventy Seven Energy Inc.	8-K	001-36354	3.2	8/4/2016
10.1	Master Services Agreement, dated as of October 25, 2011, between COS Holdings, L.L.C. and Chesapeake Operating, Inc.	S-4	333-187766	10.1	5/30/2013
10.2	Letter Agreement, dated June 25, 2014, to the Master Services Agreement, dated October 25, 2011, between Chesapeake Operating, L.L.C. and Chesapeake Oilfield Operating, L.L.C.	10-Q	001-36354	10.7	8/5/2014
10.3	Tax Sharing Agreement, dated June 25, 2014, by and between Chesapeake Oilfield Operating, L.L.C. and Chesapeake Energy Corporation.	8-K	001-36354	10.1	7/1/2014
10.4	Employee Matters Agreement, dated June 25, 2014, by and between Chesapeake Oilfield Operating, L.L.C. and Chesapeake Energy Corporation.	8-K	001-36354	10.2	7/1/2014
10.5	Transition Services Agreement, dated as of June 25, 2014, by and between Chesapeake Oilfield Operating, L.L.C. and Chesapeake Energy Corporation.	8-K	001-36354	10.3	7/1/2014
10.6	Services Agreement (hydraulic fracturing), dated June 25, 2014, by and between Performance Technologies, L.L.C. and Chesapeake Operating, Inc.	8-K	001-36354	10.4	7/1/2014
10.7	Warrant Agreement, dated as of August 1, 2016	8-K	001-36354	10.1	8/4/2016
10.8	Stockholders Agreement, dated as of August 1, 2016	8-K	001-36354	10.2	8/4/2016
10.9	Registration Rights Agreement, dated as of August 1, 2016	8-K	001-36354	10.3	8/4/2016
10.10	Board Observer Agreement, dated as of August 1, 2016	8-K	001-36354	10.4	8/4/2016

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10.11	Litigation Trust Agreement, dated as of August 1, 2016	8-K	001-36354	10.5	8/4/2016
10.12	Amended and Restated Credit Agreement, dated as of August 1, 2016	8-K	001-36354	10.6	8/4/2016
10.13	First Amendment to Incremental Term Loan, dated as of August 1, 2016	8-K	001-36354	10.7	8/4/2016
10.14	Incremental Term Loan Waiver, dated as of August 1, 2016	8-K	001-36354	10.8	8/4/2016
10.15	Intercreditor Agreement, dated as of August 1, 2016	8-K	001-36354	10.9	8/4/2016
10.16	Form of Indemnification Agreement*	8-K	001-36354	10.1	9/23/2016
10.17	Employment Agreement entered into between Seventy Seven Energy Inc. and Karl Blanchard as of September 23, 2016*	8-K	001-36354	10.2	9/23/2016
10.18	Employment Agreement entered into between Seventy Seven Energy Inc. and Cary Baetz as of September 23, 2016*	8-K	001-36354	10.3	9/23/2016
10.19	Employment Agreement entered into between Seventy Seven Energy Inc. and James Minmier as of September 23, 2016*	8-K	001-36354	10.4	9/23/2016
10.20	Employment Agreement entered into between Seventy Seven Energy Inc. and William Stanger as of September 23, 2016*	8-K	001-36354	10.5	9/23/2016
10.21	Employment Agreement entered into between Seventy Seven Energy Inc. and Jerry Winchester as of September 23, 2016*	8-K	001-36354	10.6	9/23/2016
10.22	Seventy Seven Energy Inc. 2016 Omnibus Incentive Plan*	8-K	001-36354	10.7	9/23/2016
10.23	Form of Director Restricted Stock Unit Award Agreement*	8-K	001-36354	10.1	9/27/2016
10.24	Form of Executive Restricted Stock Unit Award Agreement*	8-K	001-36354	10.2	9/27/2016
10.25	Form of Employee Restricted Stock Unit Award Agreement*	8-K	001-36354	10.3	9/27/2016
21.1	List of Subsidiaries					X
23.1	Consent of PricewaterhouseCoopers LLP.					X
31.1	Certification of Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.					X
31.2	Certification of Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.					X
32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.						X
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.						X

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99.1	Voting and Support Agreement, by and among Patterson-UTI Energy, Inc., and certain affiliates of Axar Capital Management, LLC, dated as of December 12, 2016.	8-K	001-36354	99.2	12/13/2016
99.2	Voting and Support Agreement, by and among Patterson-UTI Energy, Inc., and certain affiliates of BlueMountain Capital Management, LLC, dated as of December 12, 2016.	8-K	001-36354	99.3	12/13/2016
99.3	Voting and Support Agreement, by and among Patterson-UTI Energy, Inc., and certain affiliates of Mudrick Capital Management, L.P., dated as of December 12, 2016.	8-K	001-36354	99.4	12/13/2016
101.1	Interactive data files pursuant to Rule 405 of Regulation S-T.					†



†	Pursuant to Rule 406T of Regulation S-T, interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of sections 11 and 12 of the Securities Act of 1933, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to any liability under those sections.
*	Management contract or compensatory plan or arrangement.

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Item 16.	Form 10-K Summary

The Company has elected not to include summary information.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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.

SEVENTY SEVEN ENERGY INC.

Date: February 13, 2017 By: /s/ Jerry Winchester

Jerry Winchester

Director, President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.



Signature	Capacity	Date

/s/ Jerry Winchester	Director, President and Chief Executive Officer (Principal Executive Officer)	February 13, 2017
Jerry Winchester

/s/ Cary Baetz	Chief Financial Officer and Treasurer (Principal Financial Officer and Principal Accounting Officer)	February 13, 2017
Cary Baetz

/s/ Edward J. DiPaolo	Chairman of the Board	February 13, 2017
Edward J. DiPaolo

/s/ Andrew Axelrod	Director	February 13, 2017
Andrew Axelrod

/s/ Victor Danh	Director	February 13, 2017
Victor Danh

/s/ Steven Hinchman	Director	February 13, 2017
Steven Hinchman

/s/ David King	Director	February 13, 2017
David King

/s/ Doug Wall	Director	February 13, 2017
Doug Wall

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INDEX TO EXHIBITS



		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	Commission File No.	Exhibit	Filing Date	Filed Herewith	Furnished Herewith
2.1	Master Separation Agreement, dated as of June 25, 2014, by and between Chesapeake Oilfield Operating, L.L.C., and Chesapeake Energy Corporation.	8-K	001-36354	2.1	7/1/2014
2.2	Confirmation Order for Prepackaged Plan of Reorganization	8-K	001-36354	2.1	7/20/2016
2.3	Agreement and Plan of Merger by and among Patterson-UTI Energy, Inc., Pyramid Merger Sub, Inc. and Seventy Seven Energy Inc., dated as of December 12, 2016	8-K	001-36354	2.1	12/13/2016
3.1	Certificate of Incorporation of Seventy Seven Energy Inc.	8-K	001-36354	3.1	8/4/2016
3.2	Bylaws of Seventy Seven Energy Inc.	8-K	001-36354	3.2	8/4/2016
10.1	Master Services Agreement, dated as of October 25, 2011, between COS Holdings, L.L.C. and Chesapeake Operating, Inc.	S-4	333-187766	10.1	5/30/2013
10.2	Letter Agreement, dated June 25, 2014, to the Master Services Agreement, dated October 25, 2011, between Chesapeake Operating, L.L.C. and Chesapeake Oilfield Operating, L.L.C.	10-Q	001-36354	10.7	8/5/2014
10.3	Tax Sharing Agreement, dated June 25, 2014, by and between Chesapeake Oilfield Operating, L.L.C. and Chesapeake Energy Corporation.	8-K	001-36354	10.1	7/1/2014
10.4	Employee Matters Agreement, dated June 25, 2014, by and between Chesapeake Oilfield Operating, L.L.C. and Chesapeake Energy Corporation.	8-K	001-36354	10.2	7/1/2014
10.5	Transition Services Agreement, dated as of June 25, 2014, by and between Chesapeake Oilfield Operating, L.L.C. and Chesapeake Energy Corporation.	8-K	001-36354	10.3	7/1/2014
10.6	Services Agreement (hydraulic fracturing), dated June 25, 2014, by and between Performance Technologies, L.L.C. and Chesapeake Operating, Inc.	8-K	001-36354	10.4	7/1/2014
10.7	Warrant Agreement, dated as of August 1, 2016	8-K	001-36354	10.1	8/4/2016
10.8	Stockholders Agreement, dated as of August 1, 2016	8-K	001-36354	10.2	8/4/2016
10.9	Registration Rights Agreement, dated as of August 1, 2016	8-K	001-36354	10.3	8/4/2016
10.10	Board Observer Agreement, dated as of August 1, 2016	8-K	001-36354	10.4	8/4/2016
10.11	Litigation Trust Agreement, dated as of August 1, 2016	8-K	001-36354	10.5	8/4/2016
10.12	Amended and Restated Credit Agreement, dated as of August 1, 2016	8-K	001-36354	10.6	8/4/2016
10.13	First Amendment to Incremental Term Loan, dated as of August 1, 2016	8-K	001-36354	10.7	8/4/2016

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10.14	Incremental Term Loan Waiver, dated as of August 1, 2016	8-K	001-36354	10.8	8/4/2016
10.15	Intercreditor Agreement, dated as of August 1, 2016	8-K	001-36354	10.9	8/4/2016
10.16	Form of Indemnification Agreement*	8-K	001-36354	10.1	9/23/2016
10.17	Employment Agreement entered into between Seventy Seven Energy Inc. and Karl Blanchard as of September 23, 2016*	8-K	001-36354	10.2	9/23/2016
10.18	Employment Agreement entered into between Seventy Seven Energy Inc. and Cary Baetz as of September 23, 2016*	8-K	001-36354	10.3	9/23/2016
10.19	Employment Agreement entered into between Seventy Seven Energy Inc. and James Minmier as of September 23, 2016*	8-K	001-36354	10.4	9/23/2016
10.20	Employment Agreement entered into between Seventy Seven Energy Inc. and William Stanger as of September 23, 2016*	8-K	001-36354	10.5	9/23/2016
10.21	Employment Agreement entered into between Seventy Seven Energy Inc. and Jerry Winchester as of September 23, 2016*	8-K	001-36354	10.6	9/23/2016
10.22	Seventy Seven Energy Inc. 2016 Omnibus Incentive Plan*	8-K	001-36354	10.7	9/23/2016
10.23	Form of Director Restricted Stock Unit Award Agreement*	8-K	001-36354	10.1	9/27/2016
10.24	Form of Executive Restricted Stock Unit Award Agreement*	8-K	001-36354	10.2	9/27/2016
10.25	Form of Employee Restricted Stock Unit Award Agreement*	8-K	001-36354	10.3	9/27/2016
21.1	List of Subsidiaries					X
23.1	Consent of PricewaterhouseCoopers LLP.					X
31.1	Certification of Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.					X
31.2	Certification of Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.					X
32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.						X
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.						X
99.1	Voting and Support Agreement, by and among Patterson-UTI Energy, Inc., and certain affiliates of Axar Capital Management, LLC, dated as of December 12, 2016.	8-K	001-36354	99.2	12/13/2016

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99.2	Voting and Support Agreement, by and among Patterson-UTI Energy, Inc., and certain affiliates of BlueMountain Capital Management, LLC, dated as of December 12, 2016.	8-K	001-36354	99.3	12/13/2016
99.3	Voting and Support Agreement, by and among Patterson-UTI Energy, Inc., and certain affiliates of Mudrick Capital Management, L.P., dated as of December 12, 2016.	8-K	001-36354	99.4	12/13/2016
101.1	Interactive data files pursuant to Rule 405 of Regulation S-T.					†



†	Pursuant to Rule 406T of Regulation S-T, interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of sections 11 and 12 of the Securities Act of 1933, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to any liability under those sections.
*	Management contract or compensatory plan or arrangement.

115

Large accelerated filer

Accelerated filer

Non-accelerated filer

¬ (Do not check if a smaller reporting company)

Smaller reporting company