10-K 1 sse2016123110-k.htm 10-K Document

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.
Large accelerated filer
 
¬
 
Accelerated filer
 
¬
 
 
 
 
 
 
 
Non-accelerated filer
 
¬ (Do not check if a smaller reporting company)
 
Smaller reporting company
 
ý

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.



TABLE OF CONTENTS
 
 
 
Page
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
 
 
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
 
 
 
 
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
 
 
 
Item 15.
Item 16.
 
 





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.




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.





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.
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

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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.


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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;


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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.


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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.


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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

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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.


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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,

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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.


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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

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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

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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

23


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:


24


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;


25


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.

26



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

27


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.

28


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.

29


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.

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. 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 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.



30


 
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.

31


 
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



32


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

33


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.

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.


34


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.

35



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

36


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.

37


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.


38



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.


39


 
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)
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.



40


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.


41


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)
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.



42


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)
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.

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.


43


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