Seventy Seven Energy Inc. - FORM 10-K

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K



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

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2015



¬	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. 333-187766

Seventy Seven Energy Inc.

(Exact name of registrant as specified in its charter)



Oklahoma		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:



Title of Each Class		Name of Each Exchange on Which Registered
Common Stock, par value $0.01		New York Stock Exchange

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

None

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. ý

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

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

The aggregate market value of the common equity held by non-affiliates as of June 30, 2015 was approximately $226.0 million. At February 15, 2016, there were 59,311,401 shares of our $0.01 par value common stock outstanding.

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		Page
PART I		1
Item 1.	Business	1
Item 1A.	Risk Factors	9
Item 1B.	Unresolved Staff Comments	23
Item 2.	Properties	23
Item 3.	Legal Proceedings	23
Item 4.	Mine Safety Disclosures	23

PART II		24
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	24
Item 6.	Selected Financial Data	27
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	29
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	55
Item 8.	Financial Statements and Supplementary Data	56
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	94
Item 9A.	Controls and Procedures	95
Item 9B.	Other Information	96

PART III		97
Item 10.	Directors, Executive Officers and Corporate Governance	97
Item 11.	Executive Compensation	97
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	97
Item 13.	Certain Relationships and Related Transactions, and Director Independence	97
Item 14.	Principal Accounting Fees and Services	97

PART IV		98
Item 15.	Exhibits, Financial Statement Schedules	98

SIGNATURES		102

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Forward-Looking Statements

All references in this report to "SSE", the "Company", "us", "we", and "our" are to Seventy Seven Energy Inc. and its consolidated subsidiaries. Certain statements contained in this report constitute forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Act of 1934. These statements relate to future events or our future performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as "seek," "anticipate," "plan," "continue," "estimate," "expect," "may," "project," "predict," "potential," "targeting," "exploring," "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:


•	access to and cost of capital;


•	market prices for oil and natural gas;


•	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;


•	our customers' expenditures for oilfield services;


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


•	our ability to reduce the level of our long-term debt and lower our cash interest obligations;


•	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;


•	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.

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PART I



Item 1.	Business

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

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.

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").

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 15 of 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 drilling services for oil and natural gas E&P activities.

Drilling rig fleet. Our rig fleet, one of the largest in the industry, is categorized into three operational "Tiers." All of our Tier 1 and Tier 2 rigs are electronically driven and 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 Tier 1 and Tier 2 rigs are multi-well pad capable, equipped with skidding or walking systems. Our Tier 3 rig is a mechanical drive rig that is currently active.

As of December 31, 2015, our marketed fleet of 91 rigs consisted of 33 Tier 1 rigs, including 22 proprietary PeakeRigs™, 57 Tier 2 rigs and one Tier 3 rig. Additionally, we had four additional contracted PeakeRigs™ under construction, one of which has been delivered and three of which are scheduled to be delivered during the remainder of 2016. Our PeakeRigs™ are designed for long lateral drilling of multiple wells from a single location, which makes them well suited for unconventional resource development. We are aggressively pursuing a strategy of upgrading our fleet to better align with the market's demand for multi-well pad drilling in unconventional resource plays.

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, 2015, 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

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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.

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. Currently, we own 11 hydraulic fracturing fleets with an aggregate of 440,000 horsepower, and six of these fleets are contracted in the Anadarko Basin and the Eagle Ford and Utica Shales. Our equipment currently has an average age of approximately three 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 results. 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 allocates 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, with 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. ("GPOR"), and provides premium rental tools and specialized services for land-based oil and natural gas 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,

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we offer surface rental equipment including blowout preventers, frac tanks, mud tanks and environmental containment that leverage all phases of the hydrocarbon extraction and production process. Our air drilling equipment and services enable extraction in select basins where segments of certain 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-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, 2015, we offered oilfield rental services in the Anadarko and Permian Basins 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 4 to our consolidated financial statements included in Item 8 of this report), 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, 2015, 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 $200.0 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 $25.0 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. Please read "Risk Factors - Risks relating to Our Industry and Our Business" in Item 1A of this report.

Additional 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 has 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 Administration’s goal is to reduce methane emissions from the oil and gas industry by 40-45% by 2025 as compared to 2012 levels. The EPA therefore issued a proposed rule in the summer of 2015 that would set additional standards for methane and volatile organic compound ("VOC") emissions from oil and gas production sources, including hydraulically fractured oil wells, and natural gas processing and transmission sources. The EPA intends to issue a final rule in 2016. An accompanying EPA proposal would clarify when oil and natural gas sites should be aggregated for purposes of air permitting, which could increase compliance and permitting costs. As another prong of the Administration’s methane strategy, BLM has proposed standards for reducing venting and flaring on public lands. Various state governments and regional organizations comprising state governments similarly 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. Legislative and regulatory proposals for restricting greenhouse gas emissions or otherwise addressing climate change could require us to incur additional operating costs and could adversely affect the oil and natural gas industry and, therefore, could reduce the demand for our products and services. The potential increase in our operating costs could include new or increased costs to obtain permits, operate and maintain our equipment and facilities, install new emission controls on our equipment and facilities, acquire allowances to authorize our greenhouse gas emissions, pay taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program. Moreover, incentives to conserve energy or use alternative energy sources could reduce demand for oil, natural gas and natural gas liquids. Restrictions on emissions of methane or carbon dioxide that may be imposed, whether in various states or at the federal level, could adversely affect the oil and natural gas industry and, therefore, could reduce the demand for our products and services.

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, which we refer to as the "Transactions":


•	the entrance into our new $275.0 million senior secured revolving credit facility (the "credit facility") and a $400.0 million secured term loan (the "Term Loan"). We used the proceeds from borrowings under these new facilities to repay in full and terminate our existing $500.0 million senior secured revolving credit facility (the "Old Credit Facility");


•	the issuance of 6.50% senior unsecured notes due 2022 (the "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 credit facility and for general corporate purposes.

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•	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 and $16.5 million for the years ended December 31, 2014 and 2013, respectively. In connection with the spin-off, the facilities lease agreement was terminated.


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


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

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, 2015 was approximately $282.7 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, 2015 was approximately $314.5 million and our early contract termination value related to the Drilling Contracts was $224.0 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.

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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 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

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 years ended December 31, 2015, 2014 and 2013, CHK and its working interest partners accounted for approximately 70%, 81% and 90% of our 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. CHK's ability to generate cash flow from operations sufficient to fund its capital expenditures has been diminished due to the sharp decline in oil and natural gas prices since mid-2014 and as a result CHK has significantly reduced its drilling and completions activities. If CHK continues to be unable to generate cash flow from operations sufficient to fund its capital expenditures, CHK may be required to further reduce its drilling and completion activities, which could have a material adverse impact on our business, financial condition and results of operations.

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

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

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

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

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

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


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


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


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


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


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


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


•	laws and regulations relating to environmental matters;


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


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


•	oil refining capacity;


•	merger and divestiture activity among oil and gas producers;


•	tax laws, regulation and policies;


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


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


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


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


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


•	uncertainty in capital and commodities markets; and


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

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

We negotiate the rates payable under our contracts based on prevailing market prices, and, consequently, the prices we are able to charge will fluctuate with market conditions. A material decline in oil and natural gas prices or drilling and completions activity levels or sustained lower prices or activity levels could have a material adverse effect on our business, financial condition, results of operations and cash flows. For example, beginning at the end of the fourth quarter of 2014 and continuing throughout 2015, 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. Further price declines or prolonged levels of low prices will further negatively affect the demand for our services and the prices we are able to charge to our customers. Additionally, we may incur costs and have downtime during periods when our customers' activities are refocused towards different drilling regions.

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

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

As of December 31, 2015, the contract backlog associated with our drilling and hydraulic fracturing services was approximately $639 million, of which approximately 94% was with CHK. We calculate our drilling backlog by multiplying the day rate under our contracts by the number of days remaining under the contract. 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.

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

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

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

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

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


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


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


•	pollution and other damage to the environment;


•	exposure to toxic gases or other hazardous substances;


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


•	fires and explosions;


•	mechanical or technological failures;


•	spillage handling and disposing of materials;


•	adverse weather conditions; and


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

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

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

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

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

If we cannot meet the continued listing requirements of the New York Stock Exchange (the “NYSE”), the NYSE may delist our common stock, which would have an adverse impact on the trading volume, liquidity and market price of our common stock.

On January 18, 2016, we were notified by the NYSE that the average closing price of our common stock had fallen below $1.00 per share over a period of 30 consecutive trading days, which is the minimum average share price required by the NYSE under Section 802.01C of the NYSE Listed Company Manual. The notice has no immediate impact on the listing of our common stock, which will continue to be listed and traded on the NYSE during the six-month period described below, subject to our compliance with other continued listing standards.

We have six months following receipt of the NYSE’s notice to regain compliance with the NYSE’s minimum share price requirement. We can regain compliance at any time during the six-month cure period if on the last trading day of any calendar month during the cure period our common stock has a closing share price of at least $1.00 and an average closing share price of at least $1.00 over the 30 trading-day period ending on the last trading day of such month. Notwithstanding the foregoing, if we determine that we must cure the price condition by taking an action that will require approval of our stockholders (such as a reverse stock split), we may also regain compliance by: (i) obtaining the requisite stockholder approval by no later than our next annual meeting, (ii) implementing the action promptly thereafter, and (iii) the price of our common stock promptly exceeding $1.00 per share, and the price remaining above that level for at least the following 30 trading days. However, if at any time our common stock price drops to the point where the NYSE considers the price to be "abnormally low," the NYSE has the discretion to begin delisting proceedings immediately. While there is no formal definition of "abnormally low" in the NYSE rules, the NYSE has recently delisted the common stock of issuers when it trades below $0.16 per share. In addition, the NYSE will promptly initiate suspension and delisting procedures if the NYSE determines that we have an average global market capitalization over a consecutive 30 trading-day period of less than $15.0 million.

A delisting of our common stock from the NYSE could negatively impact us as it would likely reduce the liquidity and market price of our common stock; reduce the number of investors willing to hold or acquire our common stock; and negatively impact our ability to access equity markets and obtain financing.

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, term loan, and in the indentures governing our outstanding notes 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 and the indenture governing our outstanding notes limit 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 minimum fixed charge coverage ratio of 1.0 to 1.0 when availability under the facility is less than 10%.

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.

We are highly leveraged and may incur additional debt in the future.

As of December 31, 2015, we had $1.593 billion of indebtedness, comprised of $1.1 billion of senior notes, $493.3 million of borrowings outstanding under our term loan, and no borrowings outstanding under our credit facility. As of December 31, 2015, we had approximately $125.5 million of additional borrowing capacity, net of letters of credit of $10.2 million, under our credit facility.

Our level of indebtedness will have several important effects on our future operations, including, without limitation:


•	requiring us to dedicate a significant portion of our cash flows from operations to support the payment of debt service;


•	increasing our vulnerability to adverse changes in general economic and industry conditions, and putting us at a competitive disadvantage relative to competitors that have fewer fixed obligations and greater cash flows to devote to their businesses;


•	limiting our ability to obtain additional financing for working capital, capital expenditures, general corporate and other purposes; and


•	limiting our flexibility in operating our business and preventing us from engaging in certain transactions that might otherwise be beneficial to us.

Any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis or to satisfy our liquidity needs would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. Any of the foregoing could have a material adverse effect on our business, financial condition and results of operations.

Due to the relatively high level of our indebtedness, we have retained restructuring advisors and are actively exploring and evaluating various strategic alternatives to reduce the level of our long-term debt and lower our future cash interest obligations, including debt repurchases, exchanges of existing debt securities for new debt securities and exchanges or conversions of existing debt securities for new equity securities, among other options. The outcome of these efforts is highly uncertain and one or more of these alternatives could potentially be consummated, without the consent of any one or more of our current security holders, through voluntary bankruptcy proceedings. In addition, our debt reduction efforts may prove to be inadequate to fully mitigate the foregoing risks. Further, should any of these strategic alternatives be successfully concluded, it may adversely affect the trading prices and values of our current debt or equity securities.

In addition, our credit facility, term loan, and the indentures governing our senior notes restrict, but do not prohibit, us from incurring additional indebtedness and other obligations in the future. If we incur additional debt, the related risks that we face could intensify.

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 may restrict us from adopting some of these alternatives. If debt and equity capital or alternative financing plans are not available on favorable terms or at all, we would be required to curtail our capital spending, and our ability to sustain or improve our profits may be adversely affected. Our ability to refinance or restructure our debt will depend on the condition of the capital markets and our financial condition at such time, among other things. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations.

We may need to obtain additional capital or financing to fund expansion of our asset base, which could increase our financial leverage.

In order to expand our asset base, we will need to make growth capital expenditures. These expenditures may be significant because our assets require significant capital to purchase and modify. If we do not make sufficient or effective expansion capital expenditures, we will be unable to expand our business operations and may be required to use cash from our operations or incur borrowings or sell common stock or other securities in order to fund our expansion capital expenditures. Our ability to obtain financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering, as well as by the covenants in our debt agreements, general economic conditions and contingencies and uncertainties that are beyond our control. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing common stock may result in significant dilution to our current shareholders.

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 5 to the audited consolidated financial statements in Item 8 of this report 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.

We may not be successful in identifying and making acquisitions.

Part of our strategy to grow our business is dependent on our ability to make acquisitions that result in an increase in revenues and customer contracts. We may be unable to make accretive acquisitions or realize expected benefits of any acquisitions for any of the following reasons:


•	failure to identify attractive targets in the marketplace;


•	incorrect assumptions regarding the future results of acquired operations or assets or expected cost reductions or other synergies expected to be realized as a result of acquiring operations or assets;


•	failure to obtain acceptable financing;


•	restrictions in our debt agreements;


•	failure to integrate successfully the operations or management of any acquired operations or assets in a timely manner;


•	failure to retain or attract key employees; and


•	diversion of management's attention from existing operations or other priorities.

Our acquisition strategy requires that we successfully integrate acquired companies into our business practices as well as our procurement, management and enterprise-wide information technology systems. We may not be successful in implementing our business practices at acquired companies, and our acquisitions could face difficulty in transitioning from their previous information technology systems to our own. Any such difficulties, or increased costs associated with such integration, could affect our financial performance and operations.

If we are unable to identify, complete and integrate acquisitions, it could have a material adverse effect on our growth strategy, business, financial condition and results of operations.

The unavailability of skilled workers could hurt our operations.

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

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

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

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

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

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

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

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

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

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 2015, those agencies proposed a second phase of fuel efficiency and GHG standards for medium-and heavy-duty trucks. 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. This has led to federal, state and local proposals that would increase the regulatory burden on hydraulic fracturing. Presently, hydraulic fracturing is regulated primarily at the state level, typically by state oil and natural gas commissions and similar agencies. Several states where we conduct our water and environmental services business, such as Texas and Pennsylvania, have 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. 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.

Federal agencies have been pursuing a variety of initiatives relating to hydraulic fracturing. 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 using diesel fuels 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, including requirements for disclosure, well bore integrity and handling of flowback water. 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.

In addition, the EPA is conducting a study of the potential impacts of hydraulic fracturing activities on drinking water. The EPA released a draft final report for public comment and peer review in 2015. This study, or other studies that may be undertaken by the EPA or other governmental authorities, could spur still additional initiatives to regulate hydraulic fracturing under the SDWA or otherwise. 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.

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

Our and our customers' operations are subject to stringent federal, state and local laws and regulations relating to, among other things, protection of natural resources, wetlands, endangered species, the environment, health and safety, waste management, waste disposal and transportation of waste and other materials. Our operations pose risks of environmental liability, including leakage or spills from our operations to surface or subsurface soils, surface water or groundwater. Environmental laws and regulations often impose strict liability and may impose joint and several liability. Therefore, in some situations, we could be exposed to liability as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, third parties without regard to whether we caused or contributed to the conditions. Actions arising under these laws and regulations could result in the shutdown of our operations, fines and penalties, expenditures for remediation or other corrective measures, and claims for liability for property damage, exposure to hazardous materials, exposure to hazardous waste or personal injuries. Sanctions for noncompliance with applicable environmental laws and regulations also may include the assessment of administrative, civil or criminal penalties, revocation of permits, temporary or permanent cessation of operations in a particular location and issuance of corrective action orders. Such claims or sanctions and related costs could cause us to incur substantial costs or losses and could have a material adverse effect on our business, financial condition and results of operations. Additionally, an increase in regulatory requirements on oil and natural gas exploration and completion activities could significantly delay or interrupt our operations.

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. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the Clean Air Act ("CAA"). The EPA has already adopted rules under the CAA that, among other things, cover reductions in GHG emissions from motor vehicles, permits for certain large stationary sources of GHGs, monitoring and annual reporting of GHG emissions from specified GHG emission sources, including oil and natural gas exploration and production operations, and power plant performance standards that are designed to lead to the creation of additional state GHG control programs. 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 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.

The EPA 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.

Laws protecting the environment generally have become more stringent over time and we expect them to continue to do so, which could lead to material increases in our costs for future environmental compliance and remediation.

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.

Since the spin-off, we have implemented and used enterprise resource planning systems to operate our business. A sustained failure of these systems could adversely affect our business by preventing us from:


•	closing our financials and preparing financial statements;


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


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


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


•	being able to properly manage the needs of customers.

Since the completion of implementation, we have begun to integrate our enterprise resource planning systems into our operations. If our information technology systems are disrupted due to problems with the integration of such systems or otherwise, our customers could determine that we have become unreliable and decrease their utilization of our services. Such a disruption to our information technology systems could have an adverse effect on our business, financial condition and results of operations.

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

There are several significant areas where the liabilities of CHK may become our obligations. For example, 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. Other provisions of federal law establish similar liability for other matters, including laws governing tax-qualified pension plans as well as other contingent liabilities.

Our tax sharing agreement limits our ability to take certain actions and may require us to indemnify CHK for significant tax liabilities which cannot be precisely quantified at this time.

Under the terms of our tax sharing agreement with CHK, we generally are responsible for all taxes attributable to our business, whether accruing before, on or after the date of the spin-off, and CHK generally is responsible for any taxes arising from the spin-off or certain related transactions that are imposed on us, CHK or its other subsidiaries. Although CHK generally will be responsible for any taxes arising from the spin-off, we would be responsible for any such taxes to the extent such taxes result from certain actions or failures to act by us that occur after June 30, 2014, the effective date of the tax sharing agreement. Our liabilities under the tax sharing agreement could have a material adverse effect on us. At this time, we cannot precisely quantify the amount of liabilities we may have under the tax sharing agreement and there can be no assurances as to their final amounts.

In addition, in the tax sharing agreement we covenanted not to take any action, or fail to take any action, after the effective date of the tax sharing agreement, which action or failure to act is inconsistent with the spin-off qualifying under Sections 355 and 368(a)(1)(D) of the Code. In particular, we might determine to continue to operate certain of our business operations for the foreseeable future even if a sale or discontinuance of such business might otherwise have been advantageous. Moreover, in light of the requirements of Section 355(e) of the Code, we might determine to forgo certain transactions, including share repurchases, stock issuances, certain asset dispositions or other strategic transactions for some period of time following the spin-off. In addition, our indemnity obligation under the tax sharing agreement might discourage, delay or prevent a change of control transaction for some period of time following the spin-off.

For a more detailed discussion, please read "Business—The Spin-Off—Agreements Between Us and CHK" in Item 1 of this report.

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.

Our historical financial information is not necessarily indicative of our future financial condition or future results of operations nor does it reflect what our financial condition or results of operations would have been as an independent public company during the periods presented.

The historical financial information prior to June 30, 2014 that we have included in this Form 10-K does not reflect what our financial condition or results of operations would have been as an independent public company during the periods presented

and is not necessarily indicative of our future financial condition or future results of operations. This is primarily a result of the following factors:


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


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


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


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


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


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

Members of our board and management may have conflicts of interest because of their ownership of shares of common stock or performance share units of CHK.

Members of our board and management own shares of common stock of CHK, and with respect to our Chief Executive Officer, performance share units 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.



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. Each 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

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



Item 4.	Mine Safety Disclosures

Not applicable.

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PART II. OTHER INFORMATION



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

Market Information

Our common stock is traded on the NYSE under the symbol "SSE." On January 18, 2016, we were notified by the NYSE that the average closing price of our common stock had fallen below $1.00 per share over a period of 30 consecutive trading days, which is the minimum average share price required by the NYSE under Section 802.01C of the NYSE Listed Company Manual. The notice has no immediate impact on the listing of our common stock, which will continue to be listed and traded on the NYSE during the six-month cure period, subject to our compliance with other continued listing standards. For additional information, please read “Risk Factors - If we cannot meet the continued listing requirements of the NYSE, the NYSE may delist our common stock, which would have an adverse impact on the trading volume, liquidity and market price of our common stock” in Item 1A of this report.

The following table presents the high and low sales prices of our common stock for each quarter in 2015 and 2014:



	High		Low
2015
First Quarter	$	5.88	$	3.06
Second Quarter	$	6.14	$	3.82
Third Quarter	$	4.08	$	1.38
Fourth Quarter	$	1.73	$	0.90
2014
First Quarter	$	—	$	—
Second Quarter ^(a)	$	28.34	$	23.47
Third Quarter	$	27.17	$	21.89
Fourth Quarter	$	24.39	$	4.54


(a)	Our common stock commenced trading on the NYSE on June 17, 2014.

As of February 12, 2016, there were 1,461 registered holders of our issued and outstanding common stock.

Dividends

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

Our debt arrangements restrict our ability to distribute dividends.

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Issuer Purchases of Equity Securities

The following table presents information about repurchases of our common stock during the quarter ended December 31, 2015:



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, 2015 - October 31, 2015	805	$	1.14	—	—
November 1, 2015 - November 30, 2015	231	1.11		—	—
December 1, 2015 - December 31, 2015	25	1.02		—	—
Total	1,061	$	1.13	—	—


(a)	Reflects shares surrendered as payment for statutory withholding taxes upon the vesting of restricted stock issued pursuant to the Seventy Seven Energy Inc. 2014 Incentive Plan.

Equity Compensation Plan Information

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

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Performance Graph

The following graph and table compares the cumulative total return of a $100 investment in our common stock from July 1, 2014, the date on which our stock began trading "regular way" on the NYSE, through December 31, 2015, with the total cumulative return of a $100 investment in the Standard & Poors Stock Index and the Philadelphia Stock Exchange Oil Service Sector Index during that period.



	July 1,		January 1,		December 31,
	2014		2015		2015
Seventy Seven Energy Inc.	$	100.00	$	22.97	$	4.46
S&P 500 Stock Index	$	100.00	$	105.03	$	104.26
PHLX Oil Service Sector Index	$	100.00	$	67.80	$	50.71

This graph shall not be deemed to be "soliciting material" or to be "filed" with the SEC.

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Item 6.	Selected Financial Data

The following table sets forth certain consolidated financial data for the periods presented, which has been derived from our audited consolidated financial statements and the audited consolidated financial statements of our predecessor, COO. The historical combined financial statements of COO for periods and as of dates prior to its formation on October 25, 2011 were prepared on a "carve-out" basis from CHK and are intended to represent the financial results of CHK's oilfield services operations, which is COO's accounting predecessor, for the periods presented. 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.



	Years Ended December 31,
	2015			2014			2013			2012			2011
	(in thousands, except per share data)
Income Statement Data:
Revenues	$	1,131,244		$	2,080,892		$	2,188,205		$	1,920,022		$	1,303,496
Operating Expenses:
Operating costs^(a)	855,870			1,580,353			1,717,709			1,390,786			986,239
Depreciation and amortization	295,421			292,912			289,591			231,322			175,790
General and administrative	112,141			108,139			80,354			66,360			37,074
Loss on sale of a business	35,027			—			—			—			—
Losses (gains) on sales of property and equipment, net	14,656			(6,272		)	(2,629		)	2,025			(3,571		)
Impairment of goodwill	27,434			—			—			—			—
Impairments and other^(b)	18,632			30,764			74,762			60,710			2,729
Total Operating Expenses	1,359,181			2,005,896			2,159,787			1,751,203			1,198,261
Operating (Loss) Income	(227,937		)	74,996			28,418			168,819			105,235
Other (Expense) Income:
Interest expense	(99,267		)	(79,734		)	(56,786		)	(53,548		)	(48,802		)
Gains on early extinguishment of debt	18,061			—			—			—			—
Loss and impairment from equity investees	(7,928		)	(6,094		)	(958		)	(361		)	—
Other income (expense)	3,052			664			1,758			1,543			(2,464		)
Total Other Expense	(86,082		)	(85,164		)	(55,986		)	(52,366		)	(51,266		)
(Loss) Income Before Income Taxes	(314,019		)	(10,168		)	(27,568		)	116,453			53,969
Income Tax (Benefit) Expense	(92,628		)	(2,189		)	(7,833		)	46,877			26,279
Net (Loss) Income	(221,391		)	(7,979		)	(19,735		)	69,576			27,690
Less: Net Loss Attributable to Noncontrolling Interest	—			—			—			—			(154		)
Net (Loss) Income Attributable to Seventy Seven Energy	$	(221,391	)	$	(7,979	)	$	(19,735	)	$	69,576		$	27,844
(Loss) Earnings Per Common Share^(c):
Basic	$	(4.42	)	$	(0.17	)	$	(0.42	)	$	1.48		$	0.59
Diluted	$	(4.42	)	$	(0.17	)	$	(0.42	)	$	1.48		$	0.59
Cash Flow Data:
Cash flows provided by operations	$	284,106		$	265,296		$	337,071		$	211,151		$	240,046
Cash flows used in investing activities	$	(159,667	)	$	(367,646	)	$	(296,817	)	$	(577,324	)	$	(658,470	)
Cash flows provided by (used in) financing activities	$	5,318		$	101,563		$	(39,803	)	$	366,870		$	418,584
Other Financial Data:
Capital expenditures (including acquisitions)	$	205,706		$	457,618		$	349,806		$	622,825		$	752,715

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(a)	Historical operating costs include the effect of $18.9 million, $76.9 million, $100.8 million and $105.6 million of rig rent expense associated with our lease of drilling rigs for the years December 31, 2014, 2013, 2012 and 2011, respectively. As of December 31, 2014, we had purchased all rigs that were subject to these lease arrangements.

(b)

We recorded impairments of long-lived assets of $18.6 million for the year ended December 31, 2015. We recorded impairments of long-lived assets and lease termination costs of $21.1 million and $9.7 million, respectively, for the year ended December 31, 2014. We recorded impairments of long-lived assets and lease termination costs of $52.4 million and $22.4 million, respectively, for the year ended December 31, 2013.


(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.



	As of December 31,
	2015		2014		2013		2012		2011
	(in thousands)
Balance Sheet Data:
Cash	$	130,648	$	891	$	1,678	$	1,227	$	530
Property and equipment, net	$	1,530,420	$	1,767,053	$	1,497,476	$	1,581,519	$	1,247,817
Total assets	$	1,902,618	$	2,290,293	$	2,015,845	$	2,106,870	$	1,582,660
Long-term debt, less current maturities	$	1,564,592	$	1,572,241	$	1,043,952	$	1,055,559	$	664,524
Total equity	$	118,840	$	291,023	$	547,192	$	596,817	$	548,896

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

Comparability of Historical Results

The historical results discussed in this section prior to June 30, 2014 are those of COO, which is our predecessor. The transactions in which SSE 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 to our consolidated financial statements in Item 8 of this report.

Overview

We are a diversified oilfield services company that provides a wide range of wellsite services to U.S. land-based E&P customers operating in unconventional resource plays. 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 commencing operations in 2001, we have actively grown and modernized our asset base. As of December 31, 2015, our marketed fleet of 91 rigs consisted of 33 Tier 1 rigs, including 22 proprietary PeakeRigs, 57 Tier 2 rigs and one Tier 3 rig. Currently, we also own 11 hydraulic fracturing fleets with an aggregate of 440,000 horsepower and a diversified oilfield rentals business. We continue to modernize our asset base and are currently building four additional PeakeRigs. 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 price increases occur, producers increase their capital expenditures, which generally results in greater revenues and profits for oilfield service companies. The increased capital expenditures also ultimately result in greater production, which historically has resulted in increased supplies and reduced prices that, in turn, tends to reduce demand for oilfield services. For these reasons, our results of operations may fluctuate from quarter-to-quarter and from year-to-year. For instance, the price of crude oil has fallen significantly since mid-year 2014, as a result of robust non-OPEC supply growth led by unconventional production in the United States, weakening demand in emerging markets, and OPEC’s decision to raise its production ceiling, partly in an effort to protect its market share and drive higher cost producers out of the marketplace.

The sustained decline in commodity prices since mid-2014 has dramatically reduced the level of onshore United States drilling and completions activity and, consequently, the demand for our services. As of December 31, 2015, NYMEX WTI oil spot prices had declined to their lowest levels since 2003 and NYMEX natural gas spot prices had fallen from multi-year highs reached in early 2014. The extent and length of the current down cycle continues to be uncertain and is dependent on a number of economic, geopolitical and monetary policy factors that are outside our control. Until there is a sustained recovery in commodity prices, we expect that reduced equipment utilization levels and pricing pressure across each of our operating segments will persist. If drilling and completions activity remains at depressed levels or worsens, it will likely have a material adverse impact on our business, financial condition, cash flows and results of operations.

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:

Improve flexibility in our balance sheet and enhance our liquidity. We believe that the relatively high level of our indebtedness is having a disproportionately negative effect on the valuation of the company in the debt and equity capital markets and is limiting our ability to take advantage of our operational strengths and grow our business. As a result, we have retained restructuring advisors and are actively exploring and evaluating various strategic alternatives to reduce the level of our long-term debt and lower our future cash interest obligations, including debt repurchases, exchanges of existing debt securities

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for new debt securities and exchanges or conversions of existing debt securities for new equity securities, among other options. The timing and outcome of these efforts is highly uncertain and one or more of these strategic alternatives could potentially be consummated, without the consent of any one or more of our current security holders, through voluntary bankruptcy proceedings. Although we believe that we will have adequate liquidity over the next twelve months to operate our business and to meet our cash requirements based on current market conditions, we believe that a reduction of our long-term debt is needed to improve our financial position and flexibility and to better position us to take advantage of the growth opportunities that are likely to result from the current industry downturn.

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.

Upgrade our asset base. We intend to continue to upgrade our rigs by placing in service the new Tier 1 rigs that we are currently fabricating. As of December 31. 2015, 31 of our 33 Tier 1 rigs and 40 of our 57 Tier 2 rigs are multi-well pad-ready and able to efficiently execute our customers' drilling programs. Additionally, we had four additional contracted PeakeRigs™ under construction, one of which has been delivered and three of which are scheduled to be delivered during the remainder of 2016. We also have options for two additional PeakeRig^TM deliveries in 2016 that may be exercised depending on future market conditions. We currently expect to spend approximately $100.0 million in aggregate growth and maintenance capital expenditures in 2016. We also intend to explore opportunistic acquisitions, particularly within our hydraulic fracturing segment in a manner that is complementary to our existing asset base.

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.

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, 2015, which are based on existing contracts, were approximately $355.8 million and $282.7 million, respectively, with average durations of 16 months and 13 months, respectively. We calculate our drilling backlog by multiplying the day rate under our contracts by the number of days remaining under the contract. 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 thereunder, which will be negotiated based on then-prevailing market pricing and 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 contracts are subject to termination by the customer on short notice and provide for an early termination payment to us in the event that the contract is terminated by the customer. We calculate our contract drilling early termination value assuming each rig remains stacked for the remainder of the term of the terminated contract. As a result of the foregoing, revenues could differ materially from the backlog and early termination amounts presented.

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As of December 31, 2015, our revenue backlog was as follows (in millions):



	2016		2017		Thereafter
Backlog	$	271.8	$	310.6	$	56.1

As of December 31, 2015, our total contract early termination value related to our drilling backlog was as follows (in millions):



	2016		2017		Thereafter
Drilling contract early termination value	$	159.9	$	88.3	$	5.2

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, excluding depreciation and amortization, general and administrative expenses, net gains or losses on sales of property and equipment, impairment of goodwill and impairments and other. We view segment gross margin as one of our key management tools for managing costs at the segment level and evaluating segment performance. Our management 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 have operated in the past 30 days divided by the number of rigs that have operated in the last 90 days.

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.

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Adjusted EBITDA. Our 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 early extinguishment of debt, impairment of goodwill, impairments and other, loss on sale of a business and exit costs, gain or loss on sale of property and equipment, non-cash stock compensation, severance-related costs, impairment of equity method investment, rent expense on buildings and real estate transferred from CHK, rig rent expense, interest income and certain other non-recurring items, such as the sale of our drilling rig relocation and logistics business, the distribution of our compression unit manufacturing and geosteering businesses to CHK as part of the spin-off, and the sale of our crude and water hauling assets to a third party. The table below shows our Adjusted EBITDA for the years ended December 31, 2015, 2014 and 2013.



	Years Ended December 31,
	2015		2014		2013
	(unaudited) (in thousands)
Adjusted EBITDA:
Consolidated	$	235,019	$	432,178	$	432,496
Drilling	$	184,522	$	301,291	$	258,607
Hydraulic Fracturing	$	60,752	$	144,720	$	138,889
Oilfield Rentals	$	1,145	$	53,028	$	59,387

Adjusted Revenues and Adjusted Operating Costs. Key financial and operating measurements that our management uses to analyze and monitor our period-over-period operating performance are "Adjusted Revenues" and "Adjusted Operating Costs", 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. Adjusted Operating Costs is further adjusted to subtract rig rent expense.

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 financial measurement that is used by rating agencies, lenders and other parties to evaluate our creditworthiness; and

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•	is used by our management for various purposes, including as a measure of performance of 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 income and cash provided by operating activities. The following tables also present a reconciliation of Adjusted EBITDA to the GAAP financial measure of net income for each of our operating segments.

Consolidated



	Years Ended December 31,
	2015			2014			2013
	(in thousands)
Net loss	$	(221,391	)	$	(7,979	)	$	(19,735	)
Add:
Interest expense	99,267			79,734			56,786
Gains on early extinguishment of debt	(18,061		)	—			—
Income tax benefit	(92,628		)	(2,189		)	(7,833		)
Depreciation and amortization	295,421			292,912			289,591
Impairment of goodwill	27,434			—			—
Impairments and other	18,632			30,764			74,762
Loss on sale of a business and exit costs	35,018			—			—
Losses (gains) on sales of property and equipment, net	14,656			(6,272		)	(2,629		)
Non-cash compensation	48,509			47,184			—
Severance-related costs	6,433			2,017			3,896
Impairment of equity method investment	8,806			4,500			1,789
Rent expense on buildings and real estate transferred from CHK^(a)	—			8,187			16,459
Rig rent expense^(b)	—			18,900			76,923
Interest income	(1,353		)	—			—
Less:
Drilling rig relocation and logistics Adjusted EBITDA	(9,745		)	17,450			17,490
Water hauling Adjusted EBITDA	(4,531		)	(1,364		)	2,417
Compression unit manufacturing Adjusted EBITDA	—			13,073			18,965
Geosteering Adjusted EBITDA	—			957			2,870
Crude hauling Adjusted EBITDA	—			(5,066		)	15,771
Non-recurring credit to stock compensation expense	—			10,530			—
Adjusted EBITDA	$	235,019		$	432,178		$	432,496

(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 include $8.0 million and $15.7 million of rent expense associated with our lease of these facilities for the years ended December 31, 2014 and 2013, respectively. Our general and administrative expenses include $0.2 million and $0.8 million of rent expense associated with our lease of these facilities for the years ended December 31, 2014 and 2013, respectively.

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(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.



	Years Ended December 31,
	2015			2014			2013
	(in thousands)
Cash provided by operating activities	$	284,106		$	265,296		$	337,071
Add:
Changes in assets and liabilities	(163,356		)	88,588			(36,731		)
Interest expense	99,267			79,734			56,786
Lease termination costs	—			9,701			22,362
Amortization of sale/leaseback gains	—			5,414			15,995
Amortization of deferred financing costs	(4,623		)	(6,122		)	(2,928		)
Loss on sale of a business and exit costs	(9		)	—			—
Income (loss) from equity investees	878			(1,594		)	831
Provision for doubtful accounts	(1,375		)	(2,887		)	(436		)
Current tax expense	58			674			1,422
Severance-related costs	6,433			2,017			3,896
Rent expense on buildings and real estate transferred from CHK^(a)	—			8,187			16,459
Rig rent expense^(b)	—			18,900			76,923
Interest Income	(1,353		)	—			—
Other	717			(150		)	(1,641		)
Less:
Drilling rig relocation and logistics Adjusted EBITDA	(9,745		)	17,450			17,490
Water hauling Adjusted EBITDA	(4,531		)	(1,364		)	2,417
Compression unit manufacturing Adjusted EBITDA	—			13,073			18,965
Geosteering Adjusted EBITDA	—			957			2,870
Crude hauling Adjusted EBITDA	—			(5,066		)	15,771
Non-recurring credit to stock compensation expense	—			10,530			—
Adjusted EBITDA	$	235,019		$	432,178		$	432,496

(a)


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

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Drilling



	Years Ended December 31,
	2015			2014		2013
	(in thousands)
Net (loss) income	$	(30,454	)	$	49,528	$	(17,378	)
Add:
Income tax (benefit) expense	(12,741		)	30,471		(8,982		)
Depreciation and amortization	163,380			140,884		133,745
Impairment of goodwill	27,434			—		—
Impairments and other	14,329			29,602		71,548
Losses on sales of property and equipment, net	10,566			17,931		663
Non-cash compensation	10,745			17,188		—
Rent expense on buildings and real estate transferred from CHK	—			1,688		3,574
Severance-related costs	1,263			374		1,384
Rig rent expense	—			18,900		76,923
Less:
Geosteering Adjusted EBITDA	—			957		2,870
Non-recurring credit to stock compensation expense	—			4,318		—
Adjusted EBITDA	$	184,522		$	301,291	$	258,607

Hydraulic Fracturing



	Years Ended December 31,
	2015			2014			2013
	(in thousands)
Net (loss) income	$	(15,990	)	$	38,985		$	40,472
Add:
Income tax (benefit) expense	(6,690		)	24,563			26,752
Depreciation and amortization	70,605			72,105			69,507
Impairments	—			207			—
Losses (gains) on sales of property and equipment, net	230			(17		)	—
Non-cash compensation	3,440			3,369			—
Impairment of equity method investment	8,806			4,500			—
Severance-related costs	351			226			—
Rent expense on buildings and real estate transferred from CHK	—			1,259			2,158
Less:
Non-recurring credit to stock compensation expense	—			477			—
Adjusted EBITDA	$	60,752		$	144,720		$	138,889

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Oilfield Rentals



	Years Ended December 31,
	2015			2014			2013
	(in thousands)
Net loss	$	(28,353	)	$	(1,705	)	$	(1,001	)
Add:
Income tax benefit	(11,863		)	(754		)	(1,543		)
Depreciation and amortization	41,049			52,680			59,559
Impairments	—			955			1
Gains on sales of property and equipment, net	(1,780		)	(2,355		)	(1,146		)
Non-cash compensation	1,917			2,691			—
Severance-related costs	175			702			962
Rent expense on buildings and real estate transferred from CHK	—			1,415			2,555
Less:
Non-recurring credit to stock compensation expense	—			601			—
Adjusted EBITDA	$	1,145		$	53,028		$	59,387

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 provided for by cash on hand, cash flows from operations, borrowings under our credit facility 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, 2015, we had cash of $130.6 million and working capital of $175.5 million. As of December 31, 2014, we had cash of $0.9 million and working capital of $208.6 million.

We have retained restructuring advisors and are actively exploring and evaluating various strategic alternatives to reduce the level of our long-term debt and lower our future cash interest obligations, including debt repurchases, exchanges of existing debt securities for new debt securities and exchanges or conversions of existing debt securities for new equity securities, among other options. The timing and outcome of these efforts is highly uncertain and one or more of these strategic alternatives could potentially be consummated, without the consent of any one or more of our current security holders, through voluntary bankruptcy proceedings. Although we believe that we will have adequate liquidity over the next twelve months to operate our business and to meet our cash requirements, based on current market conditions, we believe that a reduction of our long-term debt is needed to improve our financial position and flexibility and to better position us to take advantage of the growth opportunities that are likely to result from the current industry downturn.

Long-Term Debt

The following table presents our long-term debt as of December 31, 2015 and 2014:



	December 31,
	2015		2014
	(in thousands)
6.625% Senior Notes due 2019	$	650,000	$	650,000
6.50% Senior Notes due 2022	450,000		500,000
Term Loans	493,250		398,000
Credit Facility	—		50,500
Total debt	1,593,250		1,598,500
Less: Current portion of long-term debt	5,000		4,000
Total principal amount long-term debt^(a)	1,588,250		1,594,500
Less: Unamortized deferred financing costs^(a)	23,658		22,259
Total long-term debt^(a)	$	1,564,592	$	1,572,241

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(a)	Please read Note 2 to our consolidated financial statements included in Item 8 of this report.

On May 13, 2015, we entered into an incremental term supplement to the Term Loan and borrowed an additional $100.0 million in aggregate principal amount (the “Incremental Term Loan”), receiving net proceeds of $94.5 million. Borrowings under the Incremental Term Loan bear interest at our option at either (i) LIBOR, with a floor of 1.00% or (ii) the Base Rate, calculated as the greatest of (1) the Bank of America, N.A. prime rate, (2) the federal funds rate plus 0.50% and (3) a one-month LIBOR rate adjusted daily plus 1.00%, plus, in each case, an applicable margin. The applicable margin for borrowings is 9.00% for LIBOR loans and 8.00% for Base Rate loans, depending on whether the Base Rate or LIBOR is used. As of December 31, 2015, the applicable rate for borrowings under the Incremental Term Loan was 10.00%. The Incremental Term Loan is payable in equal consecutive quarterly installments equal to 0.25% (1.00% per annum) of the original principal amount of the Incremental Term Loan and will mature in full on June 25, 2021.

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

For further information on our long-term debt, please read Note 6 to our consolidated financial statements included in Item 8 of this report.

Capital Expenditures

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


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


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


•	prior to 2015, the purchase of leased drilling rigs.

Total capital expenditures were $205.7 million, $457.6 million and $349.8 million for the years ended December 31, 2015, 2014 and 2013, respectively. During the year ended December 31, 2014, we purchased 45 leased drilling rigs for approximately $158.4 million and paid lease termination costs of approximately $9.7 million, which ended our drilling rig leasing program. For the year ended December 31, 2013, we purchased 23 leased drilling rigs for approximately $140.2 million and paid lease termination costs of approximately $22.4 million. We currently expect to spend approximately $100.0 million in aggregate growth and maintenance capital expenditures in 2016. We may increase, decrease or re-allocate our anticipated capital expenditures during any period based on industry conditions, the availability of capital or other factors, and a significant component of our anticipated capital spending is discretionary. In addition, from time to time we may use cash on hand in excess of our budgeted capital expenditures to repurchase and cancel our outstanding long-term debt or our common stock, subject to approval by our Board of Directors.

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Cash Flow

Our cash flow depends in large part on the level of spending by our customers on exploration, development and production activities. Sustained increases or decreases in the price of oil or natural gas could have a material impact on these activities, thus materially affecting our future cash flows. The following is a discussion of our cash flow for the years ended December 31, 2015, 2014 and 2013.



	Years Ended December 31,
	2015			2014			2013
	(in thousands)
Cash Flow Statement Data:
Net cash provided by operating activities	$	284,106		$	265,296		$	337,071
Net cash used in investing activities	$	(159,667	)	$	(367,646	)	$	(296,817	)
Net cash provided by (used in) financing activities	$	5,318		$	101,563		$	(39,803	)
Cash, beginning of period	$	891		$	1,678		$	1,227
Cash, end of period	$	130,648		$	891		$	1,678

Operating Activities. Cash provided by operating activities was $284.1 million, $265.3 million and $337.1 million for the years ended December 31, 2015, 2014 and 2013, respectively. Changes in working capital items increased (decreased) cash flow provided by operating activities by $163.4 million, ($88.6) million, and $36.7 million for the years ended December 31, 2015, 2014 and 2013, respectively. During the year ended December 31, 2015, the increase in cash provided by operating activities due to changes in working capital items was impacted by the timing of collection of accounts receivable and the decline in overall operational activity. Factors affecting changes in operating cash flows are largely the same as those that affect net income, with the exception of non-cash expenses such as depreciation and amortization, amortization of sale-leaseback gains, amortization of deferred financing costs, gains on early extinguishment of debt, loss on sale of a business, gains or losses on sales of property and equipment, impairments, non-cash compensation, income or losses from equity investees and deferred income taxes.

Investing Activities. Cash used in investing activities was $159.7 million, $367.6 million and $296.8 million for the years ended December 31, 2015, 2014 and 2013, respectively. Capital expenditures are the main component of our investing activities. The majority of our capital expenditures for the years ended December 31, 2015, 2014 and 2013 were related to our investment in PeakeRigs^™and the purchase of certain leased drilling rigs. We purchased 45 leased drilling rigs for approximately $158.4 million during 2014 and 23 leased drilling rigs for approximately $140.2 million during 2013. Cash used in investing activities was partially offset by proceeds from the sale of Hodges of $15.0 million during the second quarter of 2015 and proceeds from asset sales in the amounts of $27.7 million, $88.6 million and $50.6 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Financing Activities. Net cash provided by (used in) financing activities was $5.3 million, $101.6 million and ($39.8) million for the years ended December 31, 2015, 2014 and 2013, respectively. We had borrowings and repayments under our credit facility of $160.1 million and $210.6 million, respectively, during 2015. We had borrowings and repayments under our credit facility of $1.201 billion and $1.556 billion, respectively, during 2014. We had borrowings and repayments under our credit facility of $1.217 billion and $1.230 billion, respectively, during 2013. During 2015, we borrowed $100.0 million under the Incremental Term Loan and received net proceeds of $94.5 million. We also repurchased and cancelled $50.0 million in aggregate principal amount of the 2022 Notes in multiple transactions for $31.3 million during 2015. During 2014, we (i) issued $500.0 million in aggregate principal amount of 6.50% Senior Notes due 2022 and used the net proceeds of $493.8 million from the 2022 Notes issuance to make a distribution of approximately $391.0 million to CHK and for general corporate purposes, and (ii) we entered into a $400.0 million seven-year term loan credit agreement and used the net proceeds of $393.9 million to repay and terminate the Old Credit Facility. We paid $0.8 million and $3.6 million in deferred financing costs in 2015 and 2014, respectively. We made term loan repayments of $4.8 million and $2.0 million during 2015 and 2014, respectively. For the years ended December 31, 2014 and 2013 our distributions to CHK were $422.8 million and $29.9 million, respectively.

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Results of Operations

Years Ended December 31, 2015, 2014 and 2013

The following table sets forth our consolidated statements of operations for the years ended December 31, 2015, 2014 and 2013.



	Years Ended December 31,
	2015			2014			2013
	(in thousands)
Revenues:
Revenues	$	1,131,244		$	2,080,892		$	2,188,205
Operating Expenses:
Operating costs	855,870			1,580,353			1,717,709
Depreciation and amortization	295,421			292,912			289,591
General and administrative	112,141			108,139			80,354
Loss on sale of a business	35,027			—			—
Losses (gains) on sales of property and equipment, net	14,656			(6,272		)	(2,629		)
Impairment of goodwill	27,434			—			—
Impairments and other	18,632			30,764			74,762
Total Operating Expenses	1,359,181			2,005,896			2,159,787
Operating (Loss) Income	(227,937		)	74,996			28,418
Other (Expense) Income:
Interest expense	(99,267		)	(79,734		)	(56,786		)
Gains on early extinguishment of debt	18,061			—			—
Loss and impairment from equity investees	(7,928		)	(6,094		)	(958		)
Other income	3,052			664			1,758
Total Other Expense	(86,082		)	(85,164		)	(55,986		)
Loss Before Income Taxes	(314,019		)	(10,168		)	(27,568		)
Income Tax Benefit	(92,628		)	(2,189		)	(7,833		)
Net Loss	$	(221,391	)	$	(7,979	)	$	(19,735	)

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Comparison of Years Ended December 31, 2015 and 2014

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



	Years Ended December 31,
	2015		2014
	(in thousands)
Drilling	$	436,404	$	774,530
Hydraulic fracturing	575,495		885,907
Oilfield rentals	76,587		153,120
Oilfield trucking	42,739		190,479
Other operations	19		76,856
Total	$	1,131,244	$	2,080,892

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

(a)

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

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



	Years Ended December 31,
	2015		2014
	(in thousands)
Drilling	$	231,544	$	499,059
Hydraulic fracturing	494,554		735,967
Oilfield rentals	68,317		102,025
Oilfield trucking	54,674		180,084
Other operations	6,781		63,218
Total	$	855,870	$	1,580,353

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

(a)

“Adjusted Operating Costs” is a non-GAAP financial measure of operating costs that excludes 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 and our crude hauling assets that were sold to a third party as part of the spin-off, further adjusted to subtract rig rent expense. For a description of our calculation of Adjusted Operating Costs and the reasons why our management uses this measure to evaluate our business, see “—How We Evaluate Our Operations” and “—Non-GAAP Financial Measures.”

Drilling



	Years Ended December 31,
	2015		2014
	(in thousands)
Revenues	$	436,404	$	774,530
Operating costs	231,544		499,059
Gross margin	$	204,860	$	275,471
Adjusted EBITDA	$	184,522	$	301,291

Drilling revenues for 2015 decreased $338.1 million, or 44%, compared to 2014, due to a 51% decrease in revenue days, which represents the aggregate number of days that each active rig generated revenue. Revenues from non-CHK customers decreased $92.0 million in 2015 as compared to 2014. However, revenues from non-CHK customers increased to 39% of total segment revenues in 2015, compared to 34% in 2014.

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

Hydraulic Fracturing



	Years Ended December 31,
	2015		2014
	(in thousands)
Revenues	$	575,495	$	885,907
Operating costs	494,554		735,967
Gross margin	$	80,941	$	149,940
Adjusted EBITDA	$	60,752	$	144,720

Hydraulic fracturing revenues for 2015 decreased $310.4 million, or 35%, compared to 2014, which was primarily due to a 40% decrease in revenue per stage from 2014 to 2015, partially offset by an 8% increase in completed stages from 2014 to 2015. The decrease in revenue per stage was primarily due to market pricing pressure. Revenues from non-CHK customers increased $75.7 million to 17% of total segment revenues in 2015, compared to 3% in 2014.

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

Oilfield Rentals



	Years Ended December 31,
	2015		2014
	(in thousands)
Revenues	$	76,587	$	153,120
Operating costs	68,317		102,025
Gross margin	$	8,270	$	51,095
Adjusted EBITDA	$	1,145	$	53,028

Oilfield rental revenues for 2015 decreased $76.5 million, or 50%, compared to 2014, due to a decline in utilization and pricing pressure. Revenues from non-CHK customers increased $16.5 million to 59% of total segment revenues in 2015, compared to 19% in 2014.

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

Former Oilfield Trucking



	Years Ended December 31,
	2015			2014
	(in thousands)
Revenues	$	42,739		$	190,479
Operating costs	54,674			180,084
Gross margin	$	(11,935	)	$	10,395

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

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Other Operations



	Years Ended December 31,
	2015		2014
	(in thousands)
Revenues	$	19	$	76,856
Less:
Compression unit manufacturing revenues	—		74,650
Adjusted Revenues^(a):	$	19	$	2,206

Operating Costs	$	6,781	$	63,218
Less:
Compression unit manufacturing operating costs	—		60,616
Adjusted Operating Costs ^(a)	$	6,781	$	2,602

(a)

"Adjusted Revenues" and "Adjusted Operating Costs" are non-GAAP financial measures that we define as revenues and operating costs before revenues and operating costs associated with the compression unit manufacturing business distributed to CHK as part of the spin-off. For a description of our calculation of Adjusted Revenues and Adjusted Operating Costs and the reasons why our management uses this measure to evaluate our business, please read "—How We Evaluate Our Operations" and "—Non-GAAP Financial Measures."

Our other operations currently consists of corporate functions. As part of the spin-off, we distributed our compression manufacturing business to CHK, which was historically included in our other operations results.

Depreciation and Amortization. Depreciation and amortization for the years ended December 31, 2015 and 2014 was $295.4 million and $292.9 million, respectively. The increase is primarily due to a change in the estimated useful lives of certain components of drilling rigs and certain drilling rigs. Please read Note 2 to our consolidated financial statements included in Item 8 of this report. As a percentage of revenues, depreciation and amortization expense was 26% and 14% for 2015 and 2014, respectively.

General and Administrative Expenses. General and administrative expenses for the years ended December 31, 2015 and 2014 were $112.1 million and $108.1 million, respectively. The increase was primarily due to an increase in non-cash compensation expenses, which was partially offset by a decrease in CHK transition services costs. We incurred non-cash compensation expenses of $30.2 million and $19.4 million in addition to severance-related costs of $6.4 million and $2.0 million for the years ended December 31, 2015 and 2014, respectively. Included in the non-cash compensation expenses and severance-related costs for 2015 are $2.1 million and $0.6 million, respectively, related to the sale of Hodges. Prior to the spin-off, we were allocated corporate overhead from CHK which covered functions such as legal, accounting, treasury, environmental safety, information technology and other corporate services. Under this allocation, we incurred charges of $26.8 million in 2014. During 2015 and 2014, we incurred charges of $8.3 million and $18.0 million, respectively, for services provided by CHK pursuant to the transition services agreement. As of June 30, 2015, SSE terminated all remaining services being provided by CHK. As a percentage of revenues, general and administrative expenses were 10% and 5% for the years ended December 31, 2015 and 2014, respectively.

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

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

Impairment of Goodwill. During the fourth quarter of 2015, we recognized an impairment loss of $27.4 million on the goodwill associated with our 2011 Bronco acquisition. See Note 2 of Item 8 for further discussion.

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Impairments and Other. During 2015 and 2014, we recognized impairments of $18.6 million and $30.8 million, respectively. During 2015, we recognized impairment charges of $8.7 million, $5.2 million and $2.7 million related to drilling-related services equipment, certain drilling rigs and trucking and fluid disposal equipment, respectively, which we determined were impaired based on the expected future cash flows for these rigs and equipment. During 2014, we recognized impairment charges of $8.4 million related to drilling rigs we deemed to be impaired based on our assessment of future demand and the suitability of the identified rigs in light of this demand. We paid lease termination costs of $9.7 million during the year ended December 31, 2014. During 2014, we recognized impairments of $11.2 million related to certain drilling rigs and spare equipment that we had identified as held for sale. See Note 5 of Item 8 for further details.

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

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

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

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

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

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

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Comparison of Years Ended December 31, 2014 and 2013

Revenues. For 2014 and 2013, revenues were $2.081 billion and $2.188 billion, respectively. The $107.3 million decrease from 2013 to 2014 was primarily due was due to the distribution to CHK of our compression unit manufacturing and geosteering businesses and the sale of our crude hauling assets to a third party as part of the spin-off. Our Revenues and Adjusted Revenues for 2014 and 2013 are detailed below:



	Years Ended December 31,
	2014		2013
	(in thousands)
Drilling	$	774,530	$	740,812
Hydraulic fracturing	885,907		897,809
Oilfield rentals	153,120		160,241
Oilfield trucking	190,479		244,380
Other operations	76,856		144,963
Total	$	2,080,892	$	2,188,205

Adjusted Revenues^(a):
Revenue	$	2,080,892	$	2,188,205
Less:
Rig relocation and logistics revenues	120,311		135,493
Water hauling revenues	46,339		48,242
Compression unit manufacturing revenues	74,650		143,995
Geosteering revenues	3,940		8,516
Crude hauling revenues	23,829		60,645
Adjusted Revenues	$	1,811,823	$	1,791,314

(a)

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Operating Costs. Operating costs decreased $137.4 million and Adjusted Operating Costs increased $13.2 million in 2014 compared to 2013. The decline in operating costs was due to the distribution to CHK of our compression unit manufacturing and geosteering businesses and the sale of our crude hauling assets to a third party as part of the spin-off. As a percentage of Adjusted Revenues, Adjusted Operating Costs were 73% and 73% for the 2014 and 2013, respectively.



	Years Ended December 31,
	2014		2013
	(in thousands)
Drilling	$	499,059	$	543,279
Hydraulic fracturing	735,967		740,439
Oilfield rentals	102,025		101,746
Oilfield trucking	180,084		207,692
Other operations	63,218		124,553
Total	$	1,580,353	$	1,717,709

Adjusted Operating Costs^(a):
Operating costs	$	1,580,353	$	1,717,709
Less:
Rig relocation and logistics operating costs	104,729		117,620
Water hauling operating costs	48,101		46,011
Rig rent expense	18,900		76,923
Compression unit manufacturing operating costs	60,616		123,020
Geosteering operating costs	2,895		5,427
Crude hauling operating costs	27,254		44,061
Adjusted Operating Costs	$	1,317,858	$	1,304,647

(a)

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

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Drilling



	Years Ended December 31,
	2014		2013
	(in thousands)
Revenues	$	774,530	$	740,812
Operating costs	499,059		543,279
Gross margin	$	275,471	$	197,533
Adjusted EBITDA	$	301,291	$	258,607

Drilling revenues for 2014 increased $33.7 million, or 5%, compared to 2013, primarily due to an increase in revenue days of 2,155 days, or 8%. Revenues from non-CHK customers increased $113.6 million to 34% of total segment revenues in 2014, compared to 20% in 2013.

Drilling operating costs for 2014 decreased $44.2 million, or 8%, compared to 2013, primarily as result of a $58.0 million reduction in rig rent expense due to the repurchase of 45 drilling rigs during 2014. As a percentage of drilling revenues, drilling operating costs were 64% and 73% for 2014 and 2013, respectively. As a percentage of drilling revenues, rig rent expense was 2% and 10% for 2014 and 2013, respectively.

Hydraulic Fracturing



	Years Ended December 31,
	2014		2013
	(in thousands)
Revenues	$	885,907	$	897,809
Operating costs	735,967		740,439
Gross margin	$	149,940	$	157,370
Adjusted EBITDA	$	144,720	$	138,889

Hydraulic fracturing revenues for 2014 decreased $11.9 million, or 1%, compared to 2013. This decrease was due to a 15% decrease in revenue per stage from 2013 to 2014, partially offset by a 16% increase in completed stages from 2013 to 2014. The decrease in revenue per stage was primarily due to market pricing pressure. Revenues from non-CHK customers increased $22.0 million to 3% of total segment revenues in 2014.

Hydraulic fracturing operating costs for 2014 decreased $4.5 million compared to 2013, primarily due to a decrease in product costs, partially offset by an increase in repairs and maintenance expenses. As a percentage of hydraulic fracturing revenues, hydraulic fracturing operating costs increased from 82% in 2013 to 83% in 2014.

Oilfield Rentals



	Years Ended December 31,
	2014		2013
	(in thousands)
Revenues	$	153,120	$	160,241
Operating costs	102,025		101,746
Gross margin	$	51,095	$	58,495
Adjusted EBITDA	$	53,028	$	59,387

Oilfield rental revenues for 2014 decreased $7.1 million, or 4%, compared to 2013. The decrease was primarily due to market pricing pressure for certain of our equipment. Revenues from non-CHK customers increased $21.0 million to 19% of total segment revenues in 2014, compared to 5% in 2013.

Oilfield rental operating costs for 2014 increased $0.3 million, or less than 1%, compared to 2013. As a percentage of oilfield rental revenues, oilfield rental operating costs were 67% and 63% for 2014 and 2013, respectively. The increase in

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oilfield rental operating costs as a percentage of oilfield rental revenues was primarily attributable to market pricing pressure for certain services, which compressed margins, and an increase in labor-related costs related to the expansion of our business development organization. As a percentage of oilfield rental revenues, labor-related costs were 32% and 29% in 2014 and 2013, respectively.

Former Oilfield Trucking



	Years Ended December 31,
	2014		2013
	(in thousands)
Revenues	$	190,479	$	244,380
Operating costs	180,084		207,692
Gross margin	$	10,395	$	36,688

Oilfield trucking revenues for 2014 decreased $53.9 million or 22%, compared to 2013. The decrease was primarily due to the sale of our crude hauling assets to a third party in the second quarter of 2014. Revenues from non-CHK customers increased $26.9 million to 32% of total segment revenues in 2014, compared to 14% in 2013.

Oilfield trucking operating costs for 2014 decreased $27.6 million, or 13%, compared to 2013. As a percentage of oilfield trucking revenue, oilfield trucking operating costs were 95% and 85% for 2014 and 2013, respectively. The increase in operating costs as a percentage of revenue was primarily attributable to an increase in labor-related costs due to higher wages in a competitive market for trucking labor, and secondarily, a decrease in utilization of our assets which resulted in fixed costs being spread over a smaller revenue base. As a percentage of oilfield trucking revenues, labor-related costs were 46% and 42% for 2014 and 2013, respectively.

During the second quarter of 2014, we sold our crude hauling assets to a third party. The operating results related to the crude hauling assets were historically included in our oilfield trucking segment and the associated revenues and operating costs are detailed below:



	Years Ended December 31,
	2014			2013
	(in thousands)
Revenues	$	23,829		$	60,645
Operating costs	27,254			44,061
Gross margin	$	(3,425	)	$	16,584

Other Operations



	Years Ended December 31,
	2014		2013
	(in thousands)
Revenues	$	76,856	$	144,963
Operating costs	63,218		124,553
Gross margin	$	13,638	$	20,410

Our other operations currently consists of corporate functions. As part of the spin-off, we distributed our compression unit manufacturing business to CHK, which was historically included in our other operations results. For 2014, revenues from our other operations decreased $68.1 million compared to 2013, which was primarily attributable to the distribution of our compression unit manufacturing business to CHK.

For 2014, operating costs for our other operations decreased $61.3 million compared to 2013, which was primarily attributable to the distribution of our compression unit manufacturing business to CHK. This business was historically included in our other operations results and the associated revenues and operating costs are detailed below:

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	Years Ended December 31,
	2014		2013
	(in thousands)
Revenues	$	74,650	$	143,995
Operating costs	60,616		123,020
Gross margin	$	14,034	$	20,975

Depreciation and Amortization. Depreciation and amortization for the years ended December 31, 2014 and 2013 was $292.9 million and $289.6 million, respectively. The increase reflects the additional investments in our asset base as a result of capital expenditures, primarily for new hydraulic fracturing equipment and PeakeRigs^™. As a percentage of revenues, depreciation and amortization expense was 14% and 13% for 2014 and 2013, respectively.

General and Administrative Expenses. General and administrative expenses for the years ended December 31, 2014 and 2013 were $108.1 million and $80.4 million, respectively. The increase was primarily due to an increase in labor-related costs and secondarily, the incremental costs of being a stand-alone public entity and implementing an enterprise resource planning system. Prior to the spin-off, we were allocated corporate overhead from CHK which covered functions such as legal, accounting, treasury, environmental safety, information technology and other corporate services. These charges from CHK were $26.8 million and $55.5 million for 2014 and 2013, respectively. Following the spin-off, we incurred charges of $18.0 million for services provided to us by CHK pursuant to a transition services agreement. As a percentage of revenues, general and administrative expenses were 5% and 4% for 2014 and 2013, respectively.

Gains on Sales of Property and Equipment. During the year ended December 31, 2014, we sold 28 drilling rigs and ancillary equipment not utilized in our business as well as our crude hauling fleet, which included 124 fluid handling trucks and 122 trailers. During the year ended December 31, 2013, we sold 14 drilling rigs and ancillary equipment not utilized in our business. We recorded net gains on sales of property and equipment of approximately $6.3 million and $2.6 million related to these asset sales during the years ended December 31, 2014 and 2013, respectively.

Impairments and Other. During the years ended December 31, 2014 and 2013, we recognized $11.2 million and $23.6 million, respectively, of impairment charges for certain drilling rigs and spare equipment that we identified for sale as part of our broader strategy to divest non-essential drilling rigs. We also identified certain drilling rigs during the years ended December 31, 2014 and 2013 that we deemed to be impaired based on our assessment of future demand, and the suitability of the identified rigs in light of this demand. We recorded impairment charges of $8.4 million and $25.4 million during the years ended December 31, 2014 and 2013, respectively, related to these drilling rigs.

During the year ended December 31, 2014, we purchased 45 of our drilling rigs for approximately $158.4 million and paid lease termination costs of $9.7 million. During the year ended December 31, 2013, we purchased 23 of our drilling rigs for approximately $140.2 million and paid lease termination costs of $22.4 million.

We identified certain other property and equipment during the years ended December 31, 2014 and 2013 that we deemed to be impaired based on our assessment of the fair value of such assets. We recorded impairment charges of $1.5 million and $3.4 million during the years ended December 31, 2014 and 2013, respectively, related to these assets.

Interest Expense. Interest expense for the years ended December 31, 2014 and 2013 was $79.7 million and $56.8 million, respectively. The increase in interest expense from 2013 to 2014 was due to the additional debt issued in conjunction with the spin-off.

Loss and Impairment from Equity Investees. Loss and impairment from equity investees was $6.1 million and $1.0 million for the years ended December 31, 2014 and 2013, respectively, which was a result of our investments in Maalt Specialized Bulk, L.L.C. ("Maalt") and Big Star Crude Co., L.L.C. ("Big Star"). We own 49% of the membership interest in Maalt. In the second quarter of 2014, we recorded a non-cash impairment charge of $4.5 million, which resulted from an excess of carrying value over the estimated fair value for this investment. During the year ended December 31, 2013, we sold our membership interest in Big Star and recorded a loss on sale of $1.8 million.

Other Income. Other income for the years ended December 31, 2014 and 2013 was $0.7 million and $1.8 million, respectively.

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Income Tax Benefit. We recorded income tax benefit of $2.2 million and $7.8 million for the years ended December 31, 2014 and 2013, respectively. The $5.6 million decrease in income tax benefit recorded for 2014 was primarily the result of a decrease in our pre-tax loss from $27.6 million in 2013 to $10.2 million in 2014. Our effective income tax rate for 2014 and 2013 was 22% and 28%, respectively. The decrease in our effective tax rate from 2013 to 2014 was primarily the result of permanent differences having a greater impact on our effective income tax rate due to lower pre-tax loss base in 2014 compared to 2013.

Contractual Commitments and Obligations

In the normal course of business, we enter into various contractual obligations that impact, or could impact, our liquidity. The following table summarizes our material obligations as of December 31, 2015:



	Payments Due by Period
			Less Than		1-3		4-5		More Than
	Total		1 Year		Years		Years		5 Years
	(unaudited)
	(in thousands)
Principal Amount of Long-Term Debt^(a):
6.625% Senior Notes due 2019^(b)	$	650,000	$	—	$	—	$	650,000	$	—
6.50% Senior Notes due 2022^(b)	450,000		—		—		—		450,000
Term Loans	493,250		5,000		10,000		10,000		468,250
Interest^(c)	505,404		97,329		193,759		144,366		69,950
Purchase obligations^(d)	69,029		69,029		—		—		—
Operating leases^(e)	11,931		6,324		4,889		718		—
Total	$	2,179,614	$	177,682	$	208,648	$	805,084	$	988,200


(a)	Please read Note 2 to our consolidated financial statements included in Item 8 of this report.


(b)	Please read Note 6 to our consolidated financial statements included in Item 8 of this report.


(c)	Amount includes contractual interest payments on the 2019 Senior Notes, 2022 Senior Notes and Term Loans.


(d)	Consists of unconditional obligations to purchase equipment. Please read Note 8 to our consolidated financial statements included in Item 8 of this report.


(e)	Consists of rail car and other operating leases. Amounts disclosed assume no exercise of options to renew or extend the leases. Please read Note 8 to our consolidated financial statements included in Item 8 of this report.

Off-Balance Sheet Arrangements

As of December 31, 2015, we were party to five lease agreements with various third parties to utilize 725 lease rail cars for initial terms of five to seven years. Additional rental payments are required for the use of rail cars in excess of the allowable mileage stated in the respective agreement. We account for these leases as operating leases.

As of December 31, 2015, we were also party to various lease agreements for other property and equipment with varying terms. We account for these leases as operating leases.

Aggregate undiscounted minimum future lease payments as of December 31, 2015 under our rail car and other operating leases are presented below:



	Rail Cars		Other		Total
	(in thousands)
2016	$	5,298	$	1,026	$	6,324
2017	2,724		553		3,277
2018	1,430		182		1,612
2019	715		3		718
Total	$	10,167	$	1,764	$	11,931

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Other Commitments

Much of the equipment we purchase requires long production lead times. As a result, we usually have outstanding orders and commitments for such equipment. As of December 31, 2015, we had $69.0 million of purchase commitments related to future inventory and capital expenditures that we expect to incur in 2016.

Critical Accounting Policies

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

Property and Equipment

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

Interest is capitalized on the average amount of accumulated expenditures for major capital projects under construction using a weighted average interest rate based on our outstanding borrowings until the underlying assets are placed into service. The capitalized interest is added to the cost of the assets and amortized to depreciation expense over the useful life of the assets.

Impairment of Long-Lived Assets

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

During 2015, other than in the second quarter of 2015 when oil prices improved and averaged $57.85 per barrel, the sustained decline in commodity prices since mid-2014 significantly reduced the level of onshore United States drilling and completions activity and, consequently, the demand for our services. As of December 31, 2015, NYMEX WTI oil spot prices had declined significantly to their lowest levels since 2003. Due to the prolonged period of depressed oil and natural gas prices and the further deterioration of industry conditions in the fourth quarter of 2015, management deemed it necessary to assess the recoverability of the long-lived asset groups for drilling, hydraulic fracturing and oilfield rentals. We performed a Step 1 analysis as required by ASC 360-10-35 to assess the recoverability of the long-lived assets within these segments. With respect to these assets, future cash flows were estimated over the expected remaining useful life of the assets and on an undiscounted basis. Based on the analysis, we determined that, other than for certain Tier 2 drilling rigs, estimated cash flows exceeded the carrying value of the long-lived assets, and no impairment was indicated as of December 31, 2015. The estimated cash flows for the drilling and hydraulic fracturing asset groups include the backlog of contract revenues, which was approximately $355.8 million and $282.7 million, respectively, as of December 31, 2015. Assets not under contracts will be subject to pricing in the spot market. Utilization and rates for assets in the spot market were estimated based upon our management's experience in prior downturns. Also, the estimated cash flows are based on the assumption that activity levels in drilling, hydraulic fracturing and oilfield rentals will begin to recover in the first half of 2017 in response to improved oil and natural gas prices. While management believes its assumptions are reasonable, actual events may vary materially from assumptions. The timing and the extent to which oil and natural gas prices will recover is highly uncertain. Potential events that could affect our assumptions include factors such as:

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•	market supply and demand for oil and natural gas,


•	domestic and international military, political, economic and weather conditions,


•	the desire and ability of the Organization of Petroleum Exporting Countries, commonly known as OPEC, to set and maintain production and price targets that support oil and natural gas prices,


•	legal and other limitations or restrictions on exportation and/or importation of oil and natural gas,


•	technical advances affecting energy consumption and production,


•	the price and availability of alternative fuels,


•	the cost of exploring for, developing, producing and delivering oil and natural gas, and


•	regulations regarding the exploration, development, production and delivery of oil and natural gas.

All of these factors, as well as others discussed in the "Risk Factors" section of this report, may cause actual results to differ and vary beyond our control. If the current lower oil and natural gas commodity price and capital spending environment were to last into 2017 and beyond, our actual cash flows would likely be less than the estimated cash flows used in our assessment and could result in impairment charges in the future, which could be material. See Note 5 for discussion of impairments recognized.

Goodwill, Intangible Assets and Amortization

Goodwill represents the cost in excess of fair value of the net assets of businesses acquired. Goodwill is not amortized. Intangible assets with finite lives are amortized on a basis that reflects the pattern in which the economic benefits of the intangible assets are realized, which is generally on a straight-line basis over an asset's estimated useful life.

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

In response to further deterioration of industry conditions in the fourth quarter of 2015, the Company determined that there were indications of impairment present. During the fourth quarter of 2015, the Company completed its assessment and recognized an impairment loss of $27.4 million on the goodwill associated with Bronco acquisition.

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Revenue Recognition

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

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

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

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

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

Income Taxes

A valuation allowance for deferred tax assets is recognized when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. To assess that likelihood, we use estimates and judgment regarding our future taxable income, as well as the jurisdiction in which such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include our current financial position, our results of operations, both actual and forecasted, the reversal of deferred tax liabilities, and tax planning strategies as well as the current and forecasted business economics of our industry. We had no income tax valuation allowance as of December 31, 2015 and 2014.

The benefit of an uncertain tax position taken or expected to be taken on an income tax return is recognized in the consolidated financial statements at the largest amount that is more likely than not to be sustained upon examination by the relevant taxing authority. Interest and penalties, if any, related to uncertain tax positions would be recorded in interest expense and other expense, respectively. There were no uncertain tax positions as of December 31, 2015 and 2014.

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New Accounting Pronouncements

In November 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2015-17, "Income Taxes," which simplifies the presentation of deferred income taxes by requiring deferred tax liabilities and assets be classified as noncurrent in the balance sheet. ASU 2015-17 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption permitted. We do not expect the adoption of this guidance to have a material effect on our consolidated financial statements.

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

In August 2014, the FASB issued ASU No 2014-15, "Presentation of Financial Statements - Going Concern," which requires management to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity's ability to continue as a going concern within one year after the date that the financial statements are issued (or within one year after the date that the financial statements are available to be issued when applicable). ASU 2014-15 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early application permitted. We do not expect the adoption of this guidance to have a material effect on our consolidated financial statements.

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

Inflation

Inflation in the U.S. has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2015, 2014 and 2013. Although the impact of inflation has been insignificant in recent years, it is still a factor in the U.S. economy and we tend to experience inflationary pressure on the cost of energy services and equipment as increasing oil and natural gas prices increase activity in our areas of operations.

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Item 7A.	Quantitative and Qualitative Disclosures About Market Risk

Historically, we have provided a significant percentage of our oilfield services to CHK and its working interest partners. For the years ended December 31, 2015, 2014 and 2013, CHK accounted for approximately 70%, 81% and 90% of our revenues, respectively. The decline in commodity prices since mid-2014 has had an adverse effect on CHK's and our other customers' capital spending, which has adversely impacted our cash flows and financial position. The extent and length of the current down cycle is uncertain. If it is prolonged or worsens, it could have a further adverse effect on our customers' capital spending. This would likely have a material adverse impact on our cash flows and financial position and could adversely affect our ability to comply with the financial covenant under our credit facility and limit our ability to fund our planned capital expenditures.

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

The following table provides information about our debt instruments that are sensitive to changes in interest rates. The table presents principal cash flows and related weighted-average interest rates by expected maturity dates. Weighted-average variable rates are based on effective rates at December 31, 2015.



	Fixed Rate Maturity		Average Interest Rate		Floating Rate Maturity		Average Interest Rate
	(in thousands)				(in thousands)
2016	$	—	—		$	5,000	5.000	%
2017	—		—		5,000		5.000	%
2018	—		—		5,000		5.000	%
2019	650,000		6.625	%	5,000		5.000	%
After 2019	450,000		6.500	%	473,250		5.008	%
Total	$	1,100,000			$	493,250
Fair Value	$	293,840			$	371,080

Our fuel costs, which consist primarily of diesel fuel used by our various trucks and other equipment, can expose us to commodity price risk and, as our hydraulic fracturing operations grow, we will face increased risks associated with the prices of materials used in hydraulic fracturing, such as sand and chemicals. The prices for fuel and these materials can be volatile and are impacted by changes in supply and demand, as well as market uncertainty and regional shortages.

Historically, we have not used derivative financial instruments to manage our exposure to these risks.

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Item 8.	Financial Statements and Supplementary Data



INDEX TO FINANCIAL STATEMENTS
SEVENTY SEVEN ENERGY INC.
	Page
Consolidated Financial Statements:
Report of Independent Registered Public Accounting Firm	57
Consolidated Balance Sheets at December 31, 2015 and 2014	58
Consolidated Statements of Operations for the Years Ended December 31, 2015, 2014 and 2013	59
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2015, 2014 and 2013	60
Consolidated Statements of Cash Flows for the Years Ended December 31, 2015, 2014 and 2013	61
Notes to Consolidated Financial Statements	62

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Report of Independent Registered Public Accounting Firm

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

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of changes in equity and of cash flows present fairly, in all material respects, the financial position of Seventy Seven Energy Inc. and its subsidiaries (the "Company") at December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As discussed in Note 2 to the consolidated financial statements, the Company is actively exploring and evaluating strategic alternatives to reduce the level of the Company's long-term debt and lower its future cash interest obligations.

As discussed in Note 2 to the consolidated financial statements, the Company changed the manner in which it presents deferred financing costs in 2015.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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

/s/ PricewaterhouseCoopers LLP

Oklahoma City, Oklahoma

February 17, 2016

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SEVENTY SEVEN ENERGY INC.

Consolidated Balance Sheets



	December 31,
	2015			2014
	(in thousands)
Assets:
Current Assets:
Cash	$	130,648		$	891
Accounts receivable, net of allowance of $3,680 and $3,311 at December 31, 2015 and December 31, 2014, respectively	164,721			421,555
Inventory	18,553			25,073
Deferred income tax asset	1,499			7,463
Prepaid expenses and other	17,141			19,072
Total Current Assets	332,562			474,054
Property and Equipment:
Property and equipment, at cost	2,646,446			2,749,886
Less: accumulated depreciation	(1,116,026		)	(982,833		)
Total Property and Equipment, Net	1,530,420			1,767,053
Other Assets:
Equity method investment	—			7,816
Goodwill	—			27,434
Intangible assets, net	—			5,420
Deferred financing costs	1,238			1,592
Other long-term assets	38,398			6,924
Total Other Assets	39,636			49,186
Total Assets	$	1,902,618		$	2,290,293
Liabilities and Equity:
Current Liabilities:
Accounts payable	$	53,767		$	45,657
Current portion of long-term debt	5,000			4,000
Other current liabilities	98,318			215,752
Total Current Liabilities	157,085			265,409
Long-Term Liabilities:
Deferred income tax liabilities	60,623			159,273
Long-term debt, less current maturities	1,564,592			1,572,241
Other long-term liabilities	1,478			2,347
Total Long-Term Liabilities	1,626,693			1,733,861
Commitments and Contingencies (Note 8)
Common stock. $0.01 par value: authorized 250,000,000 shares; issued and outstanding 59,397,831 and 51,158,968 shares at December 31, 2015 and 2014, respectively	594			512
Paid-in capital	350,770			301,644
Accumulated deficit	(232,524		)	(11,133		)
Total Equity	118,840			291,023
Total Liabilities and Equity	$	1,902,618		$	2,290,293

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

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SEVENTY SEVEN ENERGY INC.

Consolidated Statements of Operations



	Years Ended December 31,
	2015			2014			2013
	(in thousands)
Revenues:
Revenues	$	1,131,244		$	2,080,892		$	2,188,205
Operating Expenses:
Operating costs	855,870			1,580,353			1,717,709
Depreciation and amortization	295,421			292,912			289,591
General and administrative	112,141			108,139			80,354
Loss on sale of a business	35,027			—			—
Losses (gains) on sales of property and equipment, net	14,656			(6,272		)	(2,629		)
Impairment of goodwill	27,434			—			—
Impairments and other	18,632			30,764			74,762
Total Operating Expenses	1,359,181			2,005,896			2,159,787
Operating (Loss) Income	(227,937		)	74,996			28,418
Other (Expense) Income:
Interest expense	(99,267		)	(79,734		)	(56,786		)
Gains on early extinguishment of debt	18,061			—			—
Loss and impairment from equity investees	(7,928		)	(6,094		)	(958		)
Other income	3,052			664			1,758
Total Other Expense	(86,082		)	(85,164		)	(55,986		)
Loss Before Income Taxes	(314,019		)	(10,168		)	(27,568		)
Income Tax Benefit	(92,628		)	(2,189		)	(7,833		)
Net Loss	$	(221,391	)	$	(7,979	)	$	(19,735	)

Loss Per Common Share (Note 3)

Basic	$	(4.42	)	$	(0.17	)	$	(0.42	)
Diluted	$	(4.42	)	$	(0.17	)	$	(0.42	)

Weighted Average Common Shares Outstanding
Basic	50,096			47,236			46,932
Diluted	50,096			47,236			46,932

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

Table of Contents

SEVENTY SEVEN ENERGY INC.

Consolidated Statements of Changes in Equity



	Common Stock		Common Stock		Paid-in Capital			Owner's Equity			Accumulated Deficit			Total Stockholders' / Owner's Equity
	(Shares)		(in thousands)
Balance at December 31, 2012	$	—	$	—	$	—		$	596,817		$	—		$	596,817
Net loss	—		—		—			(19,735		)	—			(19,735		)
Distributions to Chesapeake, net	—		—		—			(29,890		)	—			(29,890		)
Balance at December 31, 2013	—		$	—	$	—		$	547,192		$	—		$	547,192
Net income (loss)	—		—		—			3,154			(11,133		)	(7,979		)
Contributions from Chesapeake	—		—		—			190,297			—			190,297
Distributions to Chesapeake	—		—		—			(482,001		)	—			(482,001		)
Reclassification of owner's equity to paid-in capital	—		—		258,642			(258,642		)	—			—
Issuance of common stock at spin-off	46,932		469		(469		)	—			—			—
Share-based compensation	4,227		43		43,471			—			—			43,514
Balance at December 31, 2014	51,159		$	512	$	301,644		$	—		$	(11,133	)	$	291,023
Net loss	—		—		—			—			(221,391		)	(221,391		)
Share-based compensation	8,239		82		49,126			—			—			49,208
Balance at December 31, 2015	59,398		$	594	$	350,770		$	—		$	(232,524	)	$	118,840

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

Table of Contents

SEVENTY SEVEN ENERGY INC.

Consolidated Statements of Cash Flows



	Years Ended December 31,
	2015			2014			2013
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
NET LOSS	$	(221,391	)	$	(7,979	)	$	(19,735	)
ADJUSTMENTS TO RECONCILE NET LOSS TO CASH PROVIDED BY OPERATING ACTIVITIES:
Depreciation and amortization	295,421			292,912			289,591
Amortization of sale/leaseback gains	—			(5,414		)	(15,995		)
Amortization of deferred financing costs	4,623			6,122			2,928
Gains on early extinguishment of debt	(18,061		)	—			—
Loss on sale of a business	35,027			—			—
Losses (gains) on sales of property and equipment	14,656			(6,272		)	(2,629		)
Impairment of goodwill	27,434			—			—
Impairments of long-lived assets	18,632			21,063			52,400
Loss and impairment from equity investees	7,928			6,094			958
Provision for doubtful accounts	1,375			2,887			436
Non-cash compensation	48,509			47,184			—
Deferred income tax benefit	(92,686		)	(2,863		)	(9,255		)
Other	(717		)	150			1,641
Changes in operating assets and liabilities,
Accounts receivable	236,977			(81,001		)	(12,385		)
Inventory	7,099			(6,543		)	7,193
Accounts payable	9,109			(11,954		)	4,464
Other current liabilities	(89,650		)	9,949			38,324
Other	(179		)	961			(865		)
Net cash provided by operating activities	284,106			265,296			337,071
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment	(205,706		)	(457,618		)	(349,806		)
Proceeds from sales of assets	27,695			88,556			50,602
Proceeds from sale of a business	15,000			—			—
Proceeds from sale of investment	—			—			2,790
Additions to investments	(113		)	(675		)	(431		)
Other	3,457			2,091			28
Net cash used in investing activities	(159,667		)	(367,646		)	(296,817		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings from revolving credit facility	160,100			1,201,400			1,216,900
Payments on revolving credit facility	(210,600		)	(1,555,900		)	(1,230,100		)
Proceeds from issuance of senior notes, net of offering costs	—			493,825			—
Payments to extinguish senior notes	(31,305		)	—			—
Proceeds from issuance of term loan, net of issuance costs	94,481			393,879			—
Payments on term loans	(4,750		)	(2,000		)	—
Deferred financing costs	(784		)	(3,597		)	—
Distributions to CHK	—			(422,839		)	(29,890		)
Other	(1,824		)	(3,205		)	3,287
Net cash provided by (used in) financing activities	5,318			101,563			(39,803		)
Net increase (decrease) in cash	129,757			(787		)	451
Cash, beginning of period	891			1,678			1,227
Cash, end of period	$	130,648		$	891		$	1,678

SUPPLEMENTAL DISCLOSURE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:
(Decrease) increase in other current liabilities related to purchases of property and equipment	$	(20,016	)	$	18,999		$	(54,457	)
Note receivable received as consideration for sale of a business	$	27,000		$	—		$	—
Property and equipment distributed to Chesapeake at spin-off	$	—		$	(792	)	$	—
Property and equipment contributed from Chesapeake at spin-off	$	—		$	190,297		$	—
SUPPLEMENTAL DISCLOSURE OF CASH PAYMENTS:
Interest, net of amount capitalized	$	96,730		$	54,439		$	55,250

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

SEVENTY SEVEN ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Spin-off and Basis of Presentation

Spin-Off

On June 9, 2014, Chesapeake Energy Corporation ("CHK") announced that its board of directors approved the spin-off of its oilfield services division through the pro rata distribution of 100% of the shares of common stock of Seventy Seven Energy Inc. ("SSE," "we," "us," "our," "Company," or "ours") to CHK's shareholders of record as of the close of business on June 19, 2014, the record date. On June 30, 2014, each CHK shareholder received one share of SSE common stock for every fourteen shares of CHK common stock held by such shareholder on the record date, and SSE became an independent, publicly traded company as a result of the distribution. The transactions in which SSE became an independent, publicly traded company, including the distribution, are referred to collectively as the "spin-off". Prior to the spin-off, we conducted our business as CHK Oilfield Operating, L.L.C. ("COO"), a wholly owned subsidiary of CHK. Following the spin-off, CHK retained no ownership interest in SSE, and each company has separate public ownership, boards of directors and management. A registration statement on Form 10, as amended through the time of its effectiveness, describing the spin-off was filed by SSE with the U.S. Securities and Exchange Commission ("SEC") and was declared effective on June 17, 2014. On July 1, 2014, SSE stock began trading the "regular-way" on the New York Stock Exchange under the ticker symbol of "SSE". See Note 14 for further discussion of agreements entered into as part of the spin-off, including a master separation agreement, a transition services agreement, an employee matters agreement and a tax sharing agreement, among others. As part of the spin-off, we completed the following transactions, among others, which we refer to as the "Transactions":


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


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


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


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


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


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


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

Basis of Presentation

The accompanying consolidated financial statements and related notes include the accounts of SSE and its subsidiaries, all of which are 100% owned. SSE's accounting and financial reporting policies conform to accounting principles and practices generally accepted in the United States of America ("GAAP"). All significant intercompany accounts and transactions within SSE have been eliminated.

Seventy Seven Finance Inc. ("SSF") is a 100% owned finance subsidiary of SSE that was incorporated for the purpose of facilitating the offering of SSE's 2019 Notes (see Note 6). SSF does not have any operations or revenues.

SEVENTY SEVEN ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

2. Significant Accounting Policies

Accounting Estimates

The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the balance sheet date and the reported amounts of revenues and expenses during the reporting periods. Although management believes these estimates are reasonable, actual results could differ from those estimates. Areas where critical accounting estimates are made by management include:


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


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


•	income taxes;


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


•	cost allocations as described in Note 14.

Risks and Uncertainties

The sustained decline in commodity prices since mid-2014 has dramatically reduced the level of onshore United States drilling and completions activity and, consequently, the demand for our services. As of December 31, 2015, NYMEX WTI oil spot prices had declined to their lowest levels since 2003 and NYMEX natural gas spot prices had fallen from multi-year highs reached in early 2014. The extent and length of the current down cycle continues to be uncertain and is dependent on a number of economic, geopolitical and monetary policy factors that are outside our control. Until there is a sustained recovery in commodity prices, we expect that reduced equipment utilization levels and pricing pressure across each of our operating segments will persist. If drilling and completions activity remains at depressed levels or worsens, it would likely have a material adverse impact on our business, financial condition, cash flows and results of operations.

We have retained restructuring advisors and are actively exploring and evaluating various strategic alternatives to reduce the level of our long-term debt and lower our future cash interest obligations, including debt repurchases, exchanges of existing debt securities for new debt securities and exchanges or conversions of existing debt securities for new equity securities, among other options. The timing and outcome of these efforts is highly uncertain, and one or more of these alternatives could potentially be consummated, without the consent of any one or more of our current security holders, through voluntary bankruptcy proceedings. Although we believe that we will have adequate liquidity over the next twelve months to operate our business and to meet our cash requirements, based on current market conditions, we believe that a reduction in our long-term debt is needed to improve our financial position and flexibility and to better position us to take advantage of the growth opportunities that are likely to result from the current industry downturn.

In addition, on January 18, 2016, we received notice that we are not in compliance with the continued listing standards of the NYSE because the current trading price for our common stock is below the minimum listing requirements. We intend to take actions to meet the compliance standards for continued listing on the NYSE. However, we cannot guarantee that we will be able to meet the necessary requirements for continued listing, and, therefore, we cannot guarantee that our common stock will remain listed for trading on the NYSE.

Historically, we have provided a significant percentage of our oilfield services to CHK. For the years ended December 31, 2015, 2014 and 2013, CHK accounted for approximately 70%, 81% and 90%, respectively, of our revenues. As of December 31, 2015 and 2014, CHK accounted for approximately 65% and 77%, respectively, of our accounts receivable. If CHK ceases to engage us on terms that are attractive to us during any future period, our business, financial condition, cash flows and results of operations would be materially adversely affected during such period.

SEVENTY SEVEN ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Accounts Receivable

Trade accounts receivable are recorded at the invoice amount and do not bear interest. The majority of our receivables, 65% and 77% at December 31, 2015 and 2014, respectively, are with CHK and its subsidiaries. The allowance for doubtful accounts represents our best estimate for losses that may occur resulting from disputed amounts with our customers and their inability to pay amounts owed. We determine the allowance based on historical write-off experience and information about specific customers. During the years ended December 31, 2015, 2014 and 2013, we recognized $1.4 million, $2.9 million and $0.4 million, respectively, of bad debt expense related to potentially uncollectible receivables. We also recognized reductions to our allowance of $0.5 million, $0.1 million and $0.4 million as we wrote off specific receivables against our allowance for the years ended December 31, 2015, 2014 and 2013, respectively.

Inventory

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

Property and Equipment

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

A summary of our property and equipment amounts and useful lives is as follows:



							Estimated
	December 31,						Useful
	2015			2014			Life
	(in thousands)						(in years)
Drilling rigs and related equipment	$	1,594,377		$	1,521,561		5-15
Hydraulic fracturing equipment	323,989			360,122			2-7
Oilfield rental equipment	324,976			332,085			2-10
Trucks and tractors	77,678			183,511			7
Vehicles	33,478			53,316			3
Buildings and improvements	196,240			202,196			10-39
Land	16,261			21,613			—
Other	79,447			75,482			3-7
Total property and equipment, at cost	2,646,446			2,749,886
Less: accumulated depreciation and amortization	(1,116,026		)	(982,833		)
Total property and equipment, net	$	1,530,420		$	1,767,053

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

We review the estimated useful lives of our property and equipment on an ongoing basis. Based on this review in 2015, we concluded that the estimated useful lives of certain drilling rig components and certain drilling rigs were shorter than the estimated useful lives used for depreciation in our consolidated financial statements. We reflected this useful life change as a change in estimate, effective January 1, 2015, which increased depreciation expense by $13.7 million, increased net loss by $9.7 million and increased our basic and diluted loss per share by $0.19 for the year ended December 31, 2015. Effective July 1, 2014, we concluded that the estimated useful lives of certain of our Tier 2 and Tier 3 drilling rigs were shorter than the

SEVENTY SEVEN ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

estimated useful lives used for depreciation. This change in estimate increased depreciation expense by $3.9 million, increased net loss by $3.0 million and increased basic and diluted loss per share by $0.08 for the year ended December 31, 2014.

Depreciation expense on property and equipment for the years ended December 31, 2015, 2014 and 2013 was $295.1 million, $290.9 million and $285.6 million, respectively. Included in property and equipment are $77.7 million and $139.3 million at December 31, 2015 and 2014, respectively, of assets that are being constructed or have not been placed into service, and therefore are not subject to depreciation.

Interest is capitalized on the average amount of accumulated expenditures for major capital projects under construction using a weighted average interest rate based on our outstanding borrowings until the underlying assets are placed into service. Capitalized interest is added to the cost of the assets and amortized to depreciation expense over the useful life of the assets. During the years ended December 31, 2015, 2014 and 2013, we capitalized interest of approximately $2.3 million, $2.1 million and $1.1 million, respectively.

Impairment of Long-Lived Assets

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

Investments

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

We evaluate our investments for impairment and recognize a charge to earnings when any identified impairment is determined to be other-than-temporary. See Note 11 for further discussion of investments.

Goodwill, Intangible Assets and Amortization

Goodwill represents the cost in excess of fair value of the net assets of businesses acquired. In 2011, we recorded goodwill in the amount of $27.4 million related to our acquisition of Bronco Drilling Company, Inc. ("Bronco"). This goodwill was assigned to our drilling segment. Goodwill is not amortized. Intangible assets with finite lives are amortized on a basis that reflects the pattern in which the economic benefits of the intangible assets are realized, which is generally on a straight-line basis over an asset's estimated useful life.

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

SEVENTY SEVEN ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

When estimating fair values of a reporting unit for our goodwill impairment test, we use the income approach. The income approach provides an estimated fair value based on the reporting unit's anticipated cash flows that are discounted using a weighted average cost of capital rate. Estimated cash flows are primarily based on projected revenues, operating expenses and capital expenditures and are discounted using comparable industry average rates for weighted average cost of capital. For purposes of performing the impairment tests for goodwill, all of our goodwill related to our drilling reporting unit. We performed the two-step process for testing goodwill for impairment on October 1, 2015.

Due to the further deterioration of industry conditions in the fourth quarter of 2015, including the further decline in oil and natural gas prices, the Company determined that there was an indication of impairment present based on the results of the first step of the goodwill impairment test. During the fourth quarter of 2015, we completed our assessment and recognized an impairment loss of $27.4 million on the goodwill associated with the Bronco acquisition.

Deferred Financing Costs

Legal fees and other costs incurred in obtaining financing are amortized over the term of the related debt using a method that approximates the effective interest method. We had gross capitalized costs of $37.3 million and $31.0 million, net of accumulated amortization of $12.4 million and $7.1 million, at December 31, 2015 and 2014, respectively. In 2015, we capitalized costs of $6.3 million associated with the issuance of a Term Loan due 2021. Amortization expense related to deferred financing costs was $4.6 million, $6.1 million and $2.9 million for the years ended December 31, 2015, 2014 and 2013, respectively, and is included in interest expense in the consolidated statements of operations.

In April 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2015-03, which requires debt issuance costs to be presented in the balance sheet as a direct deduction from the associated debt liability. This standard requires retrospective application. This ASU is effective for annual reporting periods beginning after December 15, 2015. Early adoption is permitted and we elected to adopt ASU 2015-03 effective December 31, 2015. This change in accounting principle is preferable since it allows debt issuance costs and debt issuance discounts to be presented similarly in the consolidated balance sheets as a reduction to the face amount of our debt balances. A retrospective change to the December 31, 2014 consolidated balance sheet as previously presented is required pursuant to ASU 2015-03. The retrospective adjustment to the December 31, 2014 consolidated balance sheet is shown below.



	December 31, 2014
	As Adjusted		Adjustment Effect			As Previously Reported
	(in thousands)
Deferred financing costs^(a)	$	1,592	$	(22,259	)	$	23,851
Long-term debt, less current maturities	$	1,572,241	$	22,259		$	1,594,500


(a)	The deferred financing costs, as adjusted, were incurred in association with the credit facility (See Note 6).

Accounts Payable

Included in accounts payable at December 31, 2014 are liabilities of $4.5 million representing the amount by which checks issued, but not yet presented to our banks for collection, exceeded balances in applicable bank accounts, considering the legal right of offset.

Revenue Recognition

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

SEVENTY SEVEN ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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

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

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

Litigation Accruals

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

Environmental Costs

Our operations involve the storage, handling, transport and disposal of bulk waste materials, some of which contain oil, contaminants and regulated substances. These operations are subject to various federal, state and local laws and regulations intended to protect the environment. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. There were no amounts capitalized as of December 31, 2015 and 2014. We record liabilities on an undiscounted basis when remediation efforts are probable and the costs to conduct such remediation efforts can be reasonably estimated.

Leases

We lease rail cars and other property and equipment through various leasing arrangements (see Note 8). When we enter into a leasing arrangement, we analyze the terms of the arrangement to determine its accounting treatment. As of December 31, 2015, all leases have been accounted for as operating leases.

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

Share-Based Compensation

Our share-based compensation program consists of restricted stock and stock options granted to employees and restricted stock granted to non-employee directors under the SSE 2014 Incentive Plan (the "2014 Plan"). We recognize in our financial statements the cost of employee services received in exchange for restricted stock and stock options based on the fair value of the equity instruments as of the grant date. In general, this value is amortized over the vesting period; for grants with a non-

SEVENTY SEVEN ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

substantive service condition, this value is recognized immediately. Amounts are recognized in operating costs and general and administrative expenses.

Income Taxes

Through the effective date of the spin-off, our operations were included in the consolidated federal income tax return and other state returns for CHK. The income tax provision for the period before the spin-off has been prepared on a separate return basis for us and all of our subsidiaries. Accordingly, we have recognized deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases for all our subsidiaries as if each entity were a corporation, regardless of its actual characterization for U.S. federal income tax purposes. Our effective tax rate was 29%, 22% and 28% for the years ended December 31, 2015, 2014 and 2013, respectively. Our effective tax rate can fluctuate as a result of the impact of state income taxes, permanent differences and changes in pre-tax income. Effective with the spin-off, we entered into a tax sharing agreement with CHK which governs the respective rights, responsibilities and obligations of each company, for tax periods prior to the spin-off, with respect to the payment of taxes, filing of tax returns, reimbursement of taxes, control of audits and other tax proceedings, liability for taxes that may be triggered as a result of the spin-off and other matters regarding taxes. Following the spin-off, we are not entitled to federal income tax net operating loss ("NOL") carryforwards that were generated prior to the spin-off and that have historically been reflected in our net deferred income tax liabilities on our consolidated balance sheet. As of the spin-off date, we made an adjustment to our deferred tax liabilities of approximately $178.8 million to reflect the treatment of NOLs under the tax sharing agreement. In connection with the spin-off, we received a one-time step-up in tax basis of our assets due to the tax gain recognized by CHK related to the spin-off in the tax affected amount of approximately $202.6 million.

A valuation allowance for deferred tax assets is recognized when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. To assess that likelihood, we use estimates and judgment regarding our future taxable income, as well as the jurisdiction in which such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include our current financial position, our results of operations, both actual and forecasted, the reversal of deferred tax liabilities, and tax planning strategies as well as the current and forecasted business economics of our industry. Based on the expected reversal of our recorded deferred tax liabilities, we had no valuation allowance at December 31, 2015 and 2014.

3. Earnings Per Share

Basic earnings per share is computed using the weighted average number of shares of common stock outstanding and includes the effect of any participating securities as appropriate. Participating securities consist of unvested restricted stock issued to our employees and non-employee directors that provide non-forfeitable dividend rights and are required to be included in the computation of our basic earnings per share using the two-class method. The two-class method is an earnings allocation formula that determines earnings per share for common stock and participating securities according to dividends declared and participation rights in undistributed earnings. Diluted earnings per share is computed using the weighted average shares outstanding for basic earnings per share, plus the dilutive effect of stock options. The dilutive effect of unvested restricted stock and stock options is determined using the treasury stock method, which assumes the amount of unrecognized compensation expense related to unvested share-based compensation awards is used to repurchase shares at the average market price for the period.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)



	Years Ended December 31,
	2015			2014			2013
	(in thousands, except per share data)
Basic loss per share:
Allocation of earnings:
Net loss	$	(221,391	)	$	(7,979	)	$	(19,735	)

Weighted average common shares outstanding ^(a)	50,096			47,236			46,932
Basic loss per share	$	(4.42	)	$	(0.17	)	$	(0.42	)

Diluted loss per share:
Allocation of earnings:
Net loss	$	(221,391	)	$	(7,979	)	$	(19,735	)

Weighted average common shares, including dilutive effect ^(a)(b)(c)	50,096			47,236			46,932
Diluted loss per share	$	(4.42	)	$	(0.17	)	$	(0.42	)


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


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


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

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

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

The consideration received consisted of $15.0 million in cash and a $27.0 million secured promissory note due June 15, 2020 (the “Note Receivable”). The Note Receivable bears a fixed interest rate of 9.00% per annum, which is payable quarterly in arrears beginning on June 30, 2015. Aveda can, at any time, make prepayments of principal before the maturity date without premium or penalty. The Note Receivable is secured by a second lien on substantially all of Aveda’s fixed assets and accounts receivable. The Note Receivable is presented in other long-term assets on our condensed consolidated balance sheet. During 2015, we recognized interest income of $1.4 million related to the Note Receivable.

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

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

5. Asset Sales and Impairments and Other

Asset Sales

During 2015, we sold our water hauling assets, which consisted of property and equipment that had a total carrying amount of $12.3 million, for $6.5 million. We sold other ancillary equipment for $21.2 million. During 2014, we sold 28 Tier 3 drilling rigs and ancillary drilling equipment for $44.8 million. We sold our crude hauling assets, which included 124 fluid handling trucks and 122 trailers that had a total carrying amount of $20.7 million, for $43.8 million. During 2013, we sold 14

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

drilling rigs and ancillary equipment that were not being utilized in our business for $50.6 million, net of selling expenses. We recorded net losses (gains) on sales of property and equipment of approximately $14.7 million, ($6.3) million and ($2.6) million during the years ended December 31, 2015, 2014 and 2013, respectively.

Impairments and Other

A summary of our impairments and other is as follows:



	Years Ended December 31,
	2015		2014		2013
	(in thousands)
Trucking and water disposal equipment	$	2,737	$	—	$	—
Drilling rigs held for sale	—		11,237		23,574
Drilling rigs held for use	5,202		8,366		25,417
Lease termination costs	—		9,701		22,362
Drilling related services equipment	8,687		—		—
Other	2,006		1,460		3,409
Total impairments and other	$	18,632	$	30,764	$	74,762

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

During the years ended December 31, 2014 and 2013, we recognized $11.2 million and $23.6 million, respectively, of impairment charges for certain drilling rigs and spare equipment we had identified to sell as part of our broader strategy to divest of non-essential drilling rigs. We are required to present such assets at the lower of carrying amount or fair value less the anticipated costs to sell at the time they meet the criteria for held for sale accounting. Estimated fair value was based on the expected sales price, less costs to sell.

We also identified certain drilling rigs during the years ended December 31, 2015, 2014 and 2013 that we deemed to be impaired based on our assessment of future demand and the suitability of the identified rigs in light of this demand. We recorded impairment charges of $5.2 million, $8.4 million and $25.4 million during the years ended December 31, 2015, 2014 and 2013, respectively, related to these drilling rigs. Estimated fair value for these drilling rigs was determined using significant unobservable inputs (Level 3) based on a market approach.

During the year ended December 31, 2014, we purchased 45 leased drilling rigs for approximately $158.4 million and paid lease termination costs of approximately $9.7 million. During the year ended December 31, 2013, we purchased 23 leased drilling rigs for approximately $140.2 million and paid lease termination costs of approximately $22.4 million.

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

We identified certain other property and equipment during the years ended December 31, 2015, 2014 and 2013 that we deemed to be impaired based on our assessment of the market value and expected future cash flows of the long-lived asset. We recorded impairment charges of $2.0 million, $1.5 million and $3.4 million during the years ended December 31, 2015, 2014 and 2013, respectively, related to these assets. Estimated fair value for this property and equipment was determined using significant unobservable inputs (Level 3) based on an income approach.

The assumptions used in the impairment evaluation for long-lived assets are inherently uncertain and require management’s judgment. A prolonged period of low oil and natural gas prices or continued reductions in capital expenditures by CHK or our other customers would likely have an adverse impact on our utilization and the prices that we receive for our services. This could result in the recognition of future material impairment charges on the same, or additional, property and

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

equipment if future cash flow estimates, based upon information then available to management, indicate that their carrying values are not recoverable.

6. Debt

As of December 31, 2015 and 2014, our long-term debt consisted of the following:



	December 31,
	2015			2014
	(in thousands)
6.625% Senior Notes due 2019	$	650,000		$	650,000
6.50% Senior Notes due 2022	450,000			500,000
Term Loans	493,250			398,000
Credit Facility	—			50,500
Total principal amount of debt	1,593,250			1,598,500
Less: Current portion of long-term debt	(5,000		)	(4,000		)
Less: Unamortized deferred financing costs^(a)	(23,658		)	(22,259		)
Total long-term debt^(a)	$	1,564,592		$	1,572,241


(a)	See Note 2 for applicable disclosures relating to a change in an accounting principle

2019 Senior Notes

In October 2011, we and SSF co-issued $650.0 million in aggregate principal amount of 6.625% Senior Notes due 2019 (the "2019 Notes"). The 2019 Notes will mature on November 15, 2019 and interest is payable semi-annually in arrears on May 15 and November 15 of each year. The 2019 Notes are guaranteed by all of our existing subsidiaries other than certain immaterial subsidiaries and SSF, which is a co-issuer of the 2019 Notes.

We may redeem all or part of the 2019 Notes at the following prices (as a percentage of principal), plus accrued and unpaid interest, if redeemed during the 12-month period beginning on November 15 of the years indicated below:



Year	Redemption Price
2016	101.656	%
2017 and thereafter	100.000	%

The 2019 Notes are subject to covenants that, among other things, limit our ability and the ability of certain of our subsidiaries to: (1) sell assets; (2) declare dividends or make distributions on our equity interests or purchase or redeem our equity interests; (3) make investments or other specified restricted payments; (4) incur or guarantee additional indebtedness and issue disqualified or preferred equity; (5) create or incur certain liens; (6) enter into agreements that restrict the ability of our restricted subsidiaries to pay dividends, make intercompany loans or transfer assets to us; (7) effect a merger, consolidation or sale of all or substantially all of our assets; (8) enter into transactions with affiliates; and (9) designate subsidiaries as unrestricted subsidiaries. The 2019 Notes also have cross default provisions that apply to other indebtedness SSE or any of its guarantor subsidiaries may have from time to time with an outstanding principal amount of $50.0 million or more. If the 2019 Notes achieve an investment grade rating from either Moody's Investors Service, Inc. ("Moody's") or Standard & Poor's Rating Services ("S&P"), our obligation to comply with certain of these covenants will be suspended, and if the 2019 Notes achieve an investment grade rating from both Moody's and S&P, all such covenants will terminate.

2022 Senior Notes

In June, 2014, we issued $500.0 million in aggregate principal amount of 6.50% Senior Notes due 2022 (the "2022 Notes"). The 2022 Notes will mature on July 15, 2022 and interest is payable semi-annually in arrears on July 15 and January 15 of each year. Upon the full repayment of the 2019 Notes, the 2022 Notes will be fully and unconditionally guaranteed on a senior unsecured basis by each of our domestic subsidiaries that has outstanding indebtedness or guarantees in an aggregate principal amount greater than $15.0 million. Prior to the full repayment or refinancing of the 2019 Notes, each of our domestic subsidiaries, if any, that has outstanding indebtedness or guarantees in an aggregate principal amount greater than $15.0 million, other than (i) guarantors of the 2019 Notes, (ii) SSO or (iii) subsidiaries of SSO are required to fully and

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

unconditionally guarantee the 2022 notes on a senior unsecured basis. We do not have any such subsidiaries currently; therefore, the 2022 Notes are not guaranteed.

We may redeem up to 35% of the 2022 Notes with proceeds of certain equity offerings at a redemption price of 106.5% of the principal amount plus accrued and unpaid interest prior to July 15, 2017, subject to certain conditions. Prior to July 15, 2017, we may redeem some or all of the 2022 Notes at a price equal to 100% of the principal amount plus a make-whole premium determined pursuant to a formula set forth in the indenture governing the 2022 Notes, plus accrued and unpaid interest. On or after July 15, 2017, we may redeem all or part of the 2022 Notes at the following prices (as a percentage of principal), plus accrued and unpaid interest, if redeemed during the 12-month period beginning on July 15 of the years indicated below:



Year	Redemption Price
2017	104.875	%
2018	103.250	%
2019	101.625	%
2020 and thereafter	100.000	%

The 2022 Notes are subject to covenants that, among other things, limit our ability and the ability of certain of our subsidiaries to: (1) sell assets; (2) declare dividends or make distributions on our equity interests or purchase or redeem our equity interests; (3) make investments or other specified restricted payments; (4) incur or guarantee additional indebtedness and issue disqualified or preferred equity; (5) create or incur certain liens; (6) enter into agreements that restrict the ability of our restricted subsidiaries to pay dividends, make intercompany loans or transfer assets to us; (7) effect a merger, consolidation or sale of all or substantially all of our assets; (8) enter into transactions with affiliates; and (9) designate subsidiaries as unrestricted subsidiaries. The 2022 Notes also have cross default provisions that apply to other indebtedness of SSE and certain of our subsidiaries. If the 2022 Notes achieve an investment grade rating from either Moody's or S&P, our obligation to comply with certain of these covenants will be suspended, and if the 2022 Notes achieve an investment grade rating from both Moody's and S&P, all such covenants will terminate.

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

Term Loans

In June 2014, we entered into a $400.0 million seven-year term loan credit agreement. Borrowings under the Term Loan bear interest at our option at either (i) the Base Rate, calculated as the greatest of (1) the Bank of America, N.A. prime rate, (2) the federal funds rate plus 0.50% and (3) a one-month London Interbank Offered Rate ("LIBOR") rate adjusted daily plus 1.00% or (ii) LIBOR, with a floor of 0.75%, plus, in each case, an applicable margin. The applicable margin for borrowings is 2.00% for Base Rate loans and 3.00% for LIBOR loans, depending on whether the Base Rate or LIBOR is used, provided that if and for so long as the leverage ratio is less than a certain level and the term loans have certain ratings from each of S&P and Moody's, such margins will be reduced by 0.25%. As of December 31, 2015, the applicable rate for borrowings under the Term Loan was 3.75%. The Term Loan is repayable in equal consecutive quarterly installments equal to 0.25% (1.00% per annum) of the original principal amount of the Term Loan and will mature in full on June 25, 2021.

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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

Credit Facilities

In November 2011, we entered into a five-year senior secured revolving bank credit facility with total commitments of $500.0 million. In connection with the spin-off, we repaid in full borrowings outstanding under this credit facility and terminated this credit facility.

In June 2014, we, through SSO, entered into a five-year senior secured revolving bank credit facility with total commitments of $275.0 million. The maximum amount that we may borrow under the credit facility is subject to the borrowing base, which is based on a percentage of eligible accounts receivable, subject to reserves and other adjustments. As of December 31, 2015, the credit facility had availability of $125.5 million, net of letters of credit of $10.2 million. All obligations under the credit facility are fully and unconditionally guaranteed jointly and severally by SSE, and all of our present and future direct and indirect material domestic subsidiaries. Borrowings under the credit facility are secured by liens on cash and accounts receivable of the borrowers and the guarantors, and bear interest at our option at either (i) the Base Rate, calculated as the greatest of (1) the rate of interest publicly announced by Wells Fargo Bank, National Association, as its "prime rate," subject to each increase or decrease in such prime rate effective as of the date such change occurs, (2) the federal funds effective rate plus 0.50% and (3) the one-month LIBOR Rate plus 1.00%, each of which is subject to an applicable margin, or (ii) LIBOR, plus, in each case, an applicable margin. The applicable margin ranges from 0.50% to 1.00% per annum for Base Rate loans and 1.50% to 2.00% per annum for LIBOR loans. The unused portion of the credit facility is subject to a commitment fee that varies from 0.250% to 0.375% per annum, according to average unused amounts. Interest on LIBOR loans is payable at the end of the selected interest period, but no less frequently than quarterly. Interest on Base Rate loans is payable monthly in arrears.

The credit facility contains various covenants and restrictive provisions which limit our ability to (1) enter into asset sales; (2) incur additional indebtedness; (3) make investments or loans and create liens; (4) pay certain dividends or make other distributions and (5) engage in transactions with affiliates. The credit facility requires maintenance of a fixed charge coverage ratio based on the ratio of consolidated EBITDA (minus unfinanced capital expenditures) to fixed charges, in each case as defined in the credit facility agreement, at any time availability is below a certain threshold and for a certain period of time thereafter. If we fail to perform our obligations under the agreement, the credit facility could be terminated and any outstanding borrowings under the credit facility may be declared immediately due and payable. The credit facility also contains cross default provisions that apply to our other indebtedness.

SEVENTY SEVEN ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

7. Other Current Liabilities

Other current liabilities as of December 31, 2015 and 2014 are detailed below:



	December 31,
	2015		2014
	(in thousands)
Other Current Liabilities:
Accrued expenses	$	29,760	$	88,538
Payroll related	21,561		47,711
Self-insurance reserves	9,718		14,521
Interest	22,950		25,035
Income, property, sales, use and other taxes	8,336		13,937
Property and equipment	5,993		26,010
Total Other Current Liabilities	$	98,318	$	215,752

8. Commitments and Contingencies

Operating Leases

As of December 31, 2015, we were also party to various lease agreements for other property and equipment with varying terms.

Aggregate undiscounted minimum future lease payments under our operating leases at December 31, 2015 are presented below:



	Rail Cars		Other		Total
	(in thousands)
2016	$	5,298	$	1,026	$	6,324
2017	2,724		553		3,277
2018	1,430		182		1,612
2019	715		3		718
Total	$	10,167	$	1,764	$	11,931

Rent expense for drilling rigs, real property, rail cars and other property and equipment for the years ended December 31, 2015, 2014 and 2013 was $8.0 million, $35.5 million and $103.9 million, respectively, and was included in operating costs in our consolidated statements of operations.

Other Commitments

Much of the equipment we purchase requires long production lead times. As a result, we typically have outstanding orders and commitments for such equipment. As of December 31, 2015, we had $69.0 million of purchase commitments related to future inventory and capital expenditures that we expect to incur in 2016.

Litigation

We are involved in various lawsuits and disputes incidental to our business operations, including commercial disputes, personal injury claims, property damage claims and contract actions. We record an associated liability when a loss is probable

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

and can be reasonably estimated. Although the outcome of litigation cannot be predicted with certainty, management is of the opinion that no pending or threatened lawsuit or dispute incidental to our business operations is likely to have a material adverse effect on our consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued and actual results could differ materially from management's estimates.

Self-Insured Reserves

We are self-insured up to certain retention limits with respect to workers' compensation and general liability matters. We maintain accruals for self-insurance retentions that we estimate using third-party data and claims history. Included in operating costs is workers' compensation expense of $4.0 million, $8.3 million and $13.6 million for the years ended December 31, 2015, 2014 and 2013, respectively.

9. Share-Based Compensation

Prior to the spin-off, our employees participated in the CHK share-based compensation program and received restricted stock, and in the case of senior management, stock options. Effective July 1, 2014, our employees participate in the SSE 2014 Incentive Plan (the "2014 Plan").

The 2014 Plan authorizes the Compensation Committee of our Board of Directors to grant incentive and nonqualified stock options, stock appreciation rights, restricted stock, restricted stock units, cash awards and performance awards. No more than 8.4 million shares of SSE common stock may be issued under the 2014 Plan.

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


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


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

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

Equity-Classified Awards

Restricted Stock. The fair value of restricted stock awards was determined based on the fair market value of SSE common shares on the date of the grant. This value is amortized over the vesting period.

A summary of the status and changes of the unvested shares of restricted stock under the 2014 Plan is presented below.



	Number of Unvested Restricted Shares		Weighted Average Grant-Date Fair Value
	(in thousands)
Unvested shares as of December 31, 2014	3,933		$	24.02
Granted	4,003		$	4.58
Vested	(1,487	)	$	21.82
Forfeited	(553	)	$	18.07
Unvested shares as of December 31, 2015	5,896		$	11.93

As of December 31, 2015, there was $38.1 million of total unrecognized compensation cost related to the unvested restricted stock. The cost is expected to be recognized over a weighted average period of approximately twenty-five months.

SEVENTY SEVEN ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Stock Options. CHK granted stock options to our chief executive officer under CHK’s Long-Term Incentive Plan for incentive and retention purposes, which were replaced with a substitute option to purchase shares of SSE common stock in connection with the spin-off. The substitute incentive-based stock options vest ratably over a three-year period and the substitute retention-based stock options will vest one-third on each of the third, fourth and fifth anniversaries of the grant date of the original CHK award. Outstanding options expire ten years from the date of grant of the original CHK award. We have not issued any new stock options, other than the replacement awards, since the spin-off.

The following table provides information related to stock option activity for the year ended December 31, 2015:



	Number of Shares Underlying Options	Weighted Average Exercise Price Per Share		Weighted Average Contract Life in Years	Aggregate Intrinsic Value^(a)
	(in thousands)				(in thousands)
Outstanding at January 1, 2015	348	$	16.19	9.24	$	—
Granted	—	$	—	—	$	—
Exercised	—	$	—	—	$	—
Outstanding at December 31, 2015	348	$	16.19	7.23	$	—
Exercisable at December 31, 2015	89	$	16.46	7.28	$	—


(a)	The intrinsic value of a stock option is the amount by which the current market value or the market value upon exercise of the underlying stock exceeds the exercise price of the option.

As of December 31, 2015, there was $0.4 million of total unrecognized compensation cost related to stock options. The cost is expected to be recognized over a weighted average period of approximately eleven months.

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

Included in operating costs and general administrative expenses is stock-based compensation expense of $38.5 million, $29.8 million and $13.2 million for the years ended December 31, 2015, 2014 and 2013. Prior to the spin-off, we reimbursed CHK for these costs in accordance with the administrative services agreement. To the extent the compensation cost relates to employees indirectly involved in oilfield services operations, such amounts were charged to us through an overhead allocation and are reflected as general and administrative expenses.

Other

Performance Share Units. CHK granted performance share units ("PSUs") to our chief executive officer under CHK's Long Term Incentive Plan that includes both an internal performance measure and external market condition as it relates to CHK. Following the spin-off, compensation expense is recognized through the changes in fair value of the PSUs over the vesting period with a corresponding adjustment to equity and any related cash obligations are the responsibility of CHK. We recognized (credits) expenses of ($1.6) million, ($0.4) million and $1.4 million related to these PSUs for the years ended December 31, 2015, 2014 and 2013, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

10. Income Taxes

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



	Years Ended December 31,
	2015			2014			2013
	(in thousands)
Current	$	58		$	674		$	1,422
Deferred	(92,686		)	(2,863		)	(9,255		)
Total	$	(92,628	)	$	(2,189	)	$	(7,833	)

The effective income benefit differed from the computed "expected" federal income tax expense on earnings before income taxes for the following reasons:



	Years Ended December 31,
	2015			2014			2013
	(in thousands)
Income tax benefit at the federal statutory rate (35%)	$	(109,906	)	$	(3,559	)	$	(9,649	)
State income taxes (net of federal income tax benefit)	(4,118		)	538			677
Stock-based compensation shortfall	8,967			—			—
Goodwill impairment	9,602			—			—
Other permanent differences	2,518			601			1,369
Effect of change in state taxes	(23		)	—			—
Other	332			231			(230		)
Total	$	(92,628	)	$	(2,189	)	$	(7,833	)

Deferred income taxes are provided to reflect temporary differences in the basis of net assets for income tax and financial reporting purposes. As of the spin-off date, we made an adjustment to our deferred tax liabilities of approximately $178.8 million to reflect the treatment of federal income tax NOL carryforwards under the tax sharing agreement. In connection with the spin-off, we received a one-time step-up in tax basis of our assets due to the tax gain recognized by CHK related to the spin-off in the tax-effected amount of approximately $202.6 million. The tax-effected temporary differences and tax loss carryforwards which comprise deferred taxes are as follows:

SEVENTY SEVEN ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)



	Years Ended December 31,
	2015			2014
	(in thousands)
Deferred tax liabilities:
Property and equipment	$	(242,879	)	$	(230,480	)
Intangible assets	(1,551		)	(2,032		)
Prepaid expenses	(3,580		)	(4,262		)
Other	(1,121		)	(779		)
Deferred tax liabilities	(249,131		)	(237,553		)

Deferred tax assets:
Net operating loss carryforwards	172,822			62,826
Deferred stock compensation	10,035			9,682
Accrued liabilities	3,231			9,840
Other	3,919			3,395
Deferred tax assets	190,007			85,743
Net deferred tax liability	$	(59,124	)	$	(151,810	)

Reflected in accompanying balance sheets as:
Current deferred income tax asset	$	1,499		$	7,463
Non-current deferred income tax liability	(60,623		)	(159,273		)
Total	$	(59,124	)	$	(151,810	)

At December 31, 2015, SSE had NOL carryforwards of approximately $469.5 million. The NOL carryforwards expire from 2034 through 2035. The value of these carryforwards depends on the ability of SSE to generate taxable income. We considered both positive and negative evidence in our determination of the need for valuation allowances for the deferred tax assets associated with our NOLs and other deferred tax assets. We determined it is more likely than not that our NOLs and other deferred tax assets will be utilized, and accordingly no valuation allowance has been recorded. However, some or all of these NOLs could expire unused if we are unable to generate sufficient taxable income in the future to utilize them or we enter into transactions that limit our right to use them. We have retained restructuring advisors and are actively exploring and evaluating various strategic alternatives to reduce the level of our long-term debt and lower our future cash interest obligations, including debt repurchases, exchanges of existing debt securities for new debt securities and exchanges or conversions of existing debt securities into new equity securities, among other options. The outcome of these efforts could potentially reduce our NOLs or limit the use of them in the future. If it became more likely than not NOLs would expire unused, we would have to create a valuation allowance to reflect this fact, which could materially increase our income tax expense, and therefore, adversely affect our results of operations in the period in which it is recorded. We will continue to assess the need for a valuation allowance in the future.

11. Equity Method Investment

We own 49% of the membership interest in Maalt Specialized Bulk, L.L.C. ("Maalt"). Maalt provides bulk transportation, transloading and sand hauling services, and its assets consist primarily of trucks and trailers. We recorded equity method adjustments to our investment of $0.9 million, ($1.6) million and $0.2 million for our share of Maalt's income (loss) for the years ended December 31, 2015, 2014 and 2013, respectively. We also made additional investments of $0.1 million, $0.7 million and $0.4 million during the years ended December 31, 2015, 2014 and 2013, respectively.

We review our equity method investments for impairment whenever certain impairment indicators exist, including the absence of an ability to recover the carrying amount of the investment or inability of the investee to sustain an earnings capacity that would justify the carrying amount of the investment. A loss in value of an investment which is other than a temporary decline should be recognized. Due to further deterioration of industry conditions in the fourth quarter of 2015, we determined that there were indications of impairment present. We estimated that the fair value of our investment in Maalt was zero as of

SEVENTY SEVEN ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

December 31, 2015, resulting in a non-cash impairment charge of $8.8 million for the year ended December 31, 2015. We also recognized a non-cash impairment charge of $4.5 million for the year ended December 31, 2014. The impairment charges are included in loss and impairment from equity investees in our condensed consolidated statements of operations. Estimated fair value for our investment in Maalt was determined using significant unobservable inputs (Level 3) based on an income approach.

12. Fair Value Measurements

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

Level 1- Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities.

Level 2- Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated by observable market data by correlation or other means.

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

Fair Value on Recurring Basis

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

Fair Value on Non-Recurring Basis

Fair value measurements were applied with respect to our non-financial assets and liabilities measured on a non-recurring basis, which consist primarily of impairments on long-lived assets, goodwill and an equity method investment based on Level 3 inputs. See Notes 2, 5 and 11 for additional discussion.

SEVENTY SEVEN ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Fair Value of Other Financial Instruments

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



	December 31, 2015				December 31, 2014
	Carrying Amount (a)		Fair Value (Level 2)		Carrying Amount (a)		Fair Value (Level 2)
	(in thousands)
Financial assets:
Note Receivable	$	27,000	$	17,842	$	—	$	—
Financial liabilities:
6.625% Senior Notes due 2019	$	642,713	$	221,975	$	640,832	$	519,188
6.50% Senior Notes due 2022	$	444,701	$	71,865	$	493,260	$	296,250
Term Loans	$	482,178	$	371,080	$	391,649	$	379,095
Credit Facility	$	—	$	—	$	50,500	$	47,407
Less: Current portion of long-term debt	$	5,000			$	4,000
Total long-term debt^(a)	$	1,564,592			$	1,572,241


(a)	See Note 2 for applicable disclosures relating to a change in an accounting principle

13. Concentration of Credit Risk and Major Customers

Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash and trade receivables. Accounts receivable from CHK and its affiliates were $109.6 million and $326.7 million as of December 31, 2015 and December 31, 2014, or 65% and 77%, respectively, of our total accounts receivable. Revenues from CHK and its affiliates were $789.5 million, $1.676 billion and $1.960 billion for the years ended December 31, 2015, 2014 and 2013, or 70%, 81% and 90%, respectively, of our total revenues. We believe that the loss of this customer would have a material adverse effect on our operating results as there can be no assurance that replacement customers would be identified and accessed in a timely fashion.

14. Transactions with CHK

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

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

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

On June 25, 2014, we entered into an employee matters agreement with CHK providing that each company has responsibility for our own employees and compensation plans. The agreement also contains provisions concerning benefit protection for both SSE and CHK employees, treatment of holders of CHK stock options, restricted stock, restricted stock units

SEVENTY SEVEN ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

and performance share units, and cooperation between us and CHK in the sharing of employee information and maintenance of confidentiality.

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

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

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

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

Prior to the spin-off, we were party to a facilities lease agreement with CHK pursuant to which we leased a number of the storage yards and physical facilities out of which we conduct our operations. We incurred $8.2 million and $16.5 million and of lease expense for the years ended December 31, 2014 and 2013, respectively, under this facilities lease agreement. In connection with the spin-off, we acquired the property subject to the facilities lease agreement, and the facilities lease agreement was terminated.

Prior to the spin-off, CHK provided us with general and administrative services and the services of its employees pursuant to an administrative services agreement. These services included legal, accounting, treasury, environmental, safety, information technology and other corporate services. In return for the general and administrative services provided by CHK, we reimbursed CHK on a monthly basis for the overhead expenses incurred by CHK on our behalf in accordance with its allocation policy, which included costs and expenses incurred in connection with the provision of any of the services under the agreement, including the wages and benefits of CHK employees who perform services on our behalf. The administrative expense allocation was determined by multiplying revenues by a percentage determined by CHK based on the historical average of costs incurred on our behalf. All of the administrative cost allocations were based on assumptions that management believes are reasonable; however, these allocations are not necessarily indicative of the costs and expenses that would have resulted if we had been operating as a stand-alone entity. These charges from CHK were $26.8 million and $55.5 million for the years ended December 31, 2014 and 2013, respectively. In connection with the spin-off, we terminated the administrative services agreement and entered into the transition services agreement described above.

SEVENTY SEVEN ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

15. Segment Information

As of December 31, 2015, our revenues, income (loss) before income taxes and identifiable assets are primarily attributable to three reportable segments. Each of these segments represents a distinct type of business. These segments have separate management teams which report to our chief operating decision maker. The results of operations in these segments are regularly reviewed by our chief operating decision maker for purposes of determining resource allocation and assessing performance. Management evaluates the performance of our segments based upon earnings before interest, taxes, depreciation and amortization, as further adjusted to add back nonrecurring items. The following is a description of the segments and other operations:

Drilling. Our drilling segment provides land drilling services for oil and natural gas E&P activities. As of December 31, 2015, we owned a fleet of 91 land drilling rigs.

Hydraulic Fracturing. Our hydraulic fracturing segment provides hydraulic fracturing and other well stimulation services. Currently, we own 11 hydraulic fracturing fleets with an aggregate of 440,000 horsepower.

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

Former Oilfield Trucking. Our 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 and our water hauling assets. As part of the spin-off, we sold our crude hauling assets to a third party. As of June 30, 2015, there were no remaining assets or operations in the oilfield trucking segment. Our former oilfield trucking segment's historical results for periods prior to the sale continue to be included in our historical financial results as a component of continuing operations as reflected in the tables below.

Other Operations. Prior to the spin-off, our other operations consisted primarily of our compression unit manufacturing business and corporate functions, including our 2019 Notes, 2022 Notes, Term Loans and credit facilities. As part of the spin-off, we distributed our compression unit manufacturing business to CHK.

SEVENTY SEVEN ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)



	Drilling			Hydraulic Fracturing			Oilfield Rentals			Former Oilfield Trucking			Other Operations			Intercompany Eliminations			Consolidated Total
	(in thousands)
For The Year Ended December 31, 2015:
Revenues	$	437,749		$	575,495		$	77,292		$	45,512		$	8,461		$	(13,265	)	$	1,131,244
Intersegment revenues	(1,345		)	—			(705		)	(2,773		)	(8,442		)	13,265			—
Total revenues	$	436,404		$	575,495		$	76,587		$	42,739		$	19		$	—		$	1,131,244
Depreciation and amortization	163,380			70,605			41,049			8,787			11,600			—			295,421
Losses (gains) on sales of property and equipment, net	10,566			230			(1,780		)	5,728			(88		)	—			14,656
Impairment of goodwill	27,434			—			—			—			—			—			27,434
Impairments and other	14,329			—			—			2,737			1,566			—			18,632
Gains on early extinguishment of debt	—			—			—			—			18,061			—			18,061
Interest expense	—			—			—			—			(99,267		)	—			(99,267		)
Loss and impairment from equity investees	—			(7,928		)	—			—			—			—			(7,928		)
Other income	813			1,201			68			16			954			—			3,052
Loss Before Income Taxes	$	(43,195	)	$	(22,680	)	$	(40,216	)	$	(38,420	)	$	(169,508	)	$	—		$	(314,019	)
Total Assets	$	1,144,144		$	291,584		$	92,588		$	—		$	374,302		$	—		$	1,902,618
Capital Expenditures	$	153,279		$	32,743		$	6,706		$	—		$	12,978		$	—		$	205,706

For The Year Ended December 31, 2014:
Revenues	$	774,888		$	885,907		$	154,416		$	195,618		$	109,942		$	(39,879	)	$	2,080,892
Intersegment revenues	(358		)	—			(1,296		)	(5,139		)	(33,086		)	39,879			—
Total revenues	$	774,530		$	885,907		$	153,120		$	190,479		$	76,856		$	—		$	2,080,892
Depreciation and amortization	140,884			72,105			52,680			21,817			5,426			—			292,912
Losses (gains) on sales of property and equipment, net	17,931			(17		)	(2,355		)	(21,853		)	22			—			(6,272		)
Impairments and other^(a)	29,602			207			955			—			—			—			30,764
Interest expense	—			—			—			—			(79,734		)	—			(79,734		)
Loss and impairment from equity investees	—			(6,094		)	—			—			—			—			(6,094		)
Other income (expense)	364			60			179			226			(165		)	—			664
Income (Loss) Before Income Taxes	$	79,999		$	63,548		$	(2,459	)	$	6,359		$	(157,615	)	$	—		$	(10,168	)
Total Assets	$	1,322,160		$	449,966		$	155,683		$	138,909		$	224,754		$	(1,179	)	$	2,290,293
Capital Expenditures	$	373,353		$	37,211		$	22,337		$	3,599		$	21,118		$	—		$	457,618

For The Year Ended December 31, 2013:
Revenues	$	745,800		$	897,809		$	161,676		$	250,495		$	165,500		$	(33,075	)	$	2,188,205
Intersegment revenues	(4,988		)	—			(1,435		)	(6,115		)	(20,537		)	33,075			—
Total revenues	$	740,812		$	897,809		$	160,241		$	244,380		$	144,963		$	—		$	2,188,205
Depreciation and amortization	133,785			69,507			59,559			25,870			870			—			289,591
Losses (gains) on sales of property and equipment, net	663			—			(1,146		)	(2,249		)	103			—			(2,629		)
Impairments and other^(a)	71,548			—			1			—			3,213			—			74,762
Interest expense	—			—			—			—			(56,786		)	—			(56,786		)
Loss and impairment from equity investees	—			159			—			(1,117		)	—			—			(958		)
Other (expense) income	(231		)	254			1,129			184			422			—			1,758
(Loss) income Before Income Taxes	(26,360		)	67,224			(2,544		)	5,555			(71,443		)	—			$	(27,568	)
Total Assets	1,134,026			454,559			184,285			204,386			44,384			(5,795		)	$	2,015,845
Capital Expenditures	284,354			41,286			16,925			3,712			3,529			—			$	349,806

SEVENTY SEVEN ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


(a)	Includes lease termination costs of $9.7 million and $22.4 million for the years ended December 31, 2014 and 2013, respectively.

16. Condensed Consolidating Financial Information

In October 2011, we issued and sold the 2019 Senior Notes with an aggregate principal amount of $650.0 million (see Note 6). In connection with the spin-off, COO transferred all of its assets, operations, and liabilities, including the 2019 Notes, to SSO, which has been reflected retrospectively in the consolidating financial information. Pursuant to the Indenture governing the 2019 Notes, such notes are fully and unconditionally and jointly and severally guaranteed by SSO's parent, SSE, and all of SSO's material subsidiaries, other than SSF, which is a co-issuer of the 2019 Notes. Each of the subsidiary guarantors is 100% owned by SSO and there are no material subsidiaries of SSO other than the subsidiary guarantors. SSF and Western Wisconsin Sand Company, LLC are minor non-guarantor subsidiaries whose condensed consolidating financial information is included with the subsidiary guarantors. SSE and SSO have independent assets and operations. There are no significant restrictions on the ability of SSO or any subsidiary guarantor to obtain funds from its subsidiaries by dividend or loan.

Set forth below are condensed consolidating financial statements for SSE ("Parent") and SSO ("Subsidiary Issuer") on a stand-alone, unconsolidated basis, and its combined guarantor subsidiaries as of December 31, 2015 and 2014 and for the years ended December 31, 2015, 2014 and 2013. The financial information may not necessarily be indicative of results of operations, cash flows or financial position had the subsidiaries operated as independent entities.

SEVENTY SEVEN ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF DECEMBER 31, 2015

(in thousands)



	Parent		Subsidiary Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
Assets:
Current Assets:
Cash	$	46	$	130,602		$	—		$	—		$	130,648
Accounts receivable	—		138			164,583			—			164,721
Inventory	—		—			18,553			—			18,553
Deferred income tax asset	—		376			1,123			—			1,499
Prepaid expenses and other	20		37,523			9,324			(29,726		)	17,141
Total Current Assets	66		168,639			193,583			(29,726		)	332,562
Property and Equipment:
Property and equipment, at cost	—		31,265			2,615,181			—			2,646,446
Less: accumulated depreciation	—		(4,958		)	(1,111,068		)	—			(1,116,026		)
Total Property and Equipment, Net	—		26,307			1,504,113			—			1,530,420
Other Assets:
Deferred financing costs, net	—		1,238			—			—			1,238
Other long-term assets	2,575		114,087			10,901			(89,165		)	38,398
Investments in subsidiaries and intercompany advances	575,089		1,415,997			—			(1,991,086		)	—
Total Other Assets	577,664		1,531,322			10,901			(2,080,251		)	39,636
Total Assets	$	577,730	$	1,726,268		$	1,708,597		$	(2,109,977	)	$	1,902,618
Liabilities and Equity:
Current Liabilities:
Accounts payable	$	58	$	517		$	53,192		$	—		$	53,767
Current portion of long-term debt	—		5,000			—			—			5,000
Other current liabilities	14,131		25,276			88,637			(29,726		)	98,318
Total Current Liabilities	14,189		30,793			141,829			(29,726		)	157,085
Long-Term Liabilities:
Deferred income tax liabilities	—		—			149,788			(89,165		)	60,623
Long-term debt, less current maturities	444,701		1,119,891			—			—			1,564,592
Other long-term liabilities	—		495			983			—			1,478
Total Long-Term Liabilities	444,701		1,120,386			150,771			(89,165		)	1,626,693
Total Equity	118,840		575,089			1,415,997			(1,991,086		)	118,840
Total Liabilities and Equity	$	577,730	$	1,726,268		$	1,708,597		$	(2,109,977	)	$	1,902,618

SEVENTY SEVEN ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF DECEMBER 31, 2014

(in thousands)



	Parent		Subsidiary Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
Assets:
Current Assets:
Cash	$	77	$	733		$	81		$	—		$	891
Accounts receivable	—		4			421,551			—			421,555
Inventory	—		—			25,073			—			25,073
Deferred income tax asset	—		2,091			6,029			(657		)	7,463
Prepaid expenses and other	—		5,309			13,763			—			19,072
Total Current Assets	77		8,137			466,497			(657		)	474,054
Property and Equipment:
Property and equipment, at cost	—		22,397			2,727,489			—			2,749,886
Less: accumulated depreciation	—		(643		)	(982,190		)	—			(982,833		)
Total Property and Equipment, Net	—		21,754			1,745,299			—			1,767,053
Other Assets:
Equity method investment	—		—			7,816			—			7,816
Goodwill	—		—			27,434			—			27,434
Intangible assets, net	—		—			5,420			—			5,420
Deferred financing costs, net	—		1,592			—			—			1,592
Other long-term assets	—		38,950			5,731			(37,757		)	6,924
Investments in subsidiaries and intercompany advances	803,383		1,853,480			—			(2,656,863		)	—
Total Other Assets	803,383		1,894,022			46,401			(2,694,620		)	49,186
Total Assets	$	803,460	$	1,923,913		$	2,258,197		$	(2,695,277	)	$	2,290,293
Liabilities and Equity:
Current Liabilities:
Accounts payable	$	—	$	6,579		$	39,078		$	—		$	45,657
Current portion of long-term debt	—		4,000			—			—			4,000
Other current liabilities	18,032		29,776			168,601			(657		)	215,752
Total Current Liabilities	18,032		40,355			207,679			(657		)	265,409
Long-Term Liabilities:
Deferred income tax liabilities	1,145		—			195,885			(37,757		)	159,273
Long-term debt	493,260		1,078,981			—			—			1,572,241
Other long-term liabilities	—		1,194			1,153			—			2,347
Total Long-Term Liabilities	494,405		1,080,175			197,038			(37,757		)	1,733,861
Total Equity	291,023		803,383			1,853,480			(2,656,863		)	291,023
Total Liabilities and Equity	$	803,460	$	1,923,913		$	2,258,197		$	(2,695,277	)	$	2,290,293

SEVENTY SEVEN ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2015

(in thousands)



	Parent			Subsidiary Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Revenues	$	—		$	3		$	1,135,347		$	(4,106	)	$	1,131,244
Operating Expenses:
Operating costs	—			—			855,870			—			855,870
Depreciation and amortization	—			4,152			291,269			—			295,421
General and administrative	50			37,705			78,492			(4,106		)	112,141
Loss on sale of a business	—			35,027			—			—			35,027
(Gains) losses on sales of property and equipment, net	—			(229		)	14,885			—			14,656
Impairment of goodwill	—			—			27,434			—			27,434
Impairments and other	—			—			18,632			—			18,632
Total Operating Expenses	50			76,655			1,286,582			(4,106		)	1,359,181
Operating Loss	(50		)	(76,652		)	(151,235		)	—			(227,937		)
Other (Expense) Income:
Interest expense	(31,626		)	(67,641		)	—			—			(99,267		)
Gains on early extinguishment of debt	18,061			—			—			—			18,061
Loss and impairment from equity investee	—			—			(7,928		)	—			(7,928		)
Other income	—			771			2,281			—			3,052
Equity in net earnings of subsidiary	(212,094		)	(115,690		)	—			327,784			—
Total Other Expense	(225,659		)	(182,560		)	(5,647		)	327,784			(86,082		)
Loss Before Income Taxes	(225,709		)	(259,212		)	(156,882		)	327,784			(314,019		)
Income Tax Benefit	(4,318		)	(47,118		)	(41,192		)	—			(92,628		)
Net Loss	$	(221,391	)	$	(212,094	)	$	(115,690	)	$	327,784		$	(221,391	)

SEVENTY SEVEN ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2014

(in thousands)



	Parent			Subsidiary Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Revenues	$	—		$	3,531		$	2,080,812		$	(3,451	)	$	2,080,892
Operating Expenses:
Operating costs	—			4,652			1,580,974			(5,273		)	1,580,353
Depreciation and amortization	—			218			292,694			—			292,912
General and administrative	166			78,175			29,798			—			108,139
Losses (gains) on sales of property and equipment, net	—			6			(6,278		)	—			(6,272		)
Impairments and other	—			—			30,764			—			30,764
Total Operating Expenses	166			83,051			1,927,952			(5,273		)	2,005,896
Operating (Loss) Income	(166		)	(79,520		)	152,860			1,822			74,996
Other (Expense) Income:
Interest expense	(17,168		)	(62,566		)	—			—			(79,734		)
Loss and impairment from equity investee	—			—			(6,094		)	—			(6,094		)
Other (expense) income	—			(216		)	880			—			664
Equity in net earnings of subsidiary	2,656			90,446			—			(93,102		)	—
Total Other (Expense) Income	(14,512		)	27,664			(5,214		)	(93,102		)	(85,164		)
(Loss) Income Before Income Taxes	(14,678		)	(51,856		)	147,646			(91,280		)	(10,168		)
Income Tax (Benefit) Expense	(6,699		)	(53,382		)	57,200			692			(2,189		)
Net (Loss) Income	$	(7,979	)	$	1,526		$	90,446		$	(91,972	)	$	(7,979	)

SEVENTY SEVEN ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2013

(in thousands)



	Parent			Subsidiary Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Revenues	$	—		$	8,011		$	2,187,966		$	(7,772	)	$	2,188,205
Operating Expenses:
Operating costs	—			9,513			1,717,235			(9,039		)	1,717,709
Depreciation and amortization	—			27			289,564			—			289,591
General and administrative	—			20,506			59,848			—			80,354
Gains on sales of property and equipment, net	—			—			(2,629		)	—			(2,629		)
Impairments and other	—			—			74,762			—			74,762
Total Operating Expenses	—			30,046			2,138,780			(9,039		)	2,159,787
Operating (Loss) Income	—			(22,035		)	49,186			1,267			28,418
Other (Expense) Income:
Interest expense	—			(56,786		)	—			—			(56,786		)
Loss from equity investees	—			—			(958		)	—			(958		)
Other income	—			—			1,758			—			1,758
Equity in net earnings of subsidiary	(18,948		)	29,334			—			(10,386		)	—
Total Other (Expense) Income	(18,948		)	(27,452		)	800			(10,386		)	(55,986		)
(Loss) Income Before Income Taxes	(18,948		)	(49,487		)	49,986			(9,119		)	(27,568		)
Income Tax Expense (Benefit)	787			(29,752		)	21,439			(307		)	(7,833		)
Net (Loss) Income	$	(19,735	)	$	(19,735	)	$	28,547		$	(8,812	)	$	(19,735	)

SEVENTY SEVEN ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2015

(in thousands)



	Parent			Subsidiary Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
Cash Flows From Operating Activities:	$	(34,133	)	$	155,945		$	506,502		$	(344,208	)	$	284,106
Cash Flows From Investing Activities:
Additions to property and equipment	—			(11,668		)	(194,038		)	—			(205,706		)
Proceeds from sale of assets	—			(624		)	28,319			—			27,695
Proceeds from sale of a business	—			15,000			—			—			15,000
Additions to investments	—			—			(113		)	—			(113		)
Distributions from affiliates	65,407			—			—			(65,407		)	—
Other	—			—			3,457			—			3,457
Net cash provided by (used in) investing activities	65,407			2,708			(162,375		)	(65,407		)	(159,667		)
Cash Flows From Financing Activities:
Borrowings from revolving credit facility	—			160,100			—			—			160,100
Payments on revolving credit facility	—			(210,600		)	—			—			(210,600		)
Payments to extinguish senior notes	(31,305		)	—			—			—			(31,305		)
Proceeds from issuance of term loan, net of issuance costs	—			94,481			—			—			94,481
Payments on term loans	—			(4,750		)	—			—			(4,750		)
Deferred financing costs	—			(784		)	—			—			(784		)
Contributions to (distributions from) affiliates	—			(65,407		)	(344,208		)	409,615			—
Other	—			(1,824		)	—			—			(1,824		)
Net cash used in financing activities	(31,305		)	(28,784		)	(344,208		)	409,615			5,318
Net (decrease) increase in cash	(31		)	129,869			(81		)	—			129,757
Cash, beginning of period	77			733			81			—			891
Cash, end of period	$	46		$	130,602		$	—		$	—		$	130,648

SEVENTY SEVEN ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2014

(in thousands)



	Parent			Subsidiary Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
Cash Flows From Operating Activities:	$	53,039		$	(59,411	)	$	363,855		$	(92,187	)	$	265,296
Cash Flows From Investing Activities:
Additions to property and equipment	—			(17,888		)	(439,730		)	—			(457,618		)
Proceeds from sale of assets	—			—			88,556			—			88,556
Additions to investments	—			—			(675		)	—			(675		)
Contributions to affiliates	(119,711		)	(38,218		)	—			157,929			—
Other	—			—			2,091			—			2,091
Cash used in investing activities	(119,711		)	(56,106		)	(349,758		)	157,929			(367,646		)
Cash Flows From Financing Activities:
Borrowings from revolving credit facility	—			1,201,400			—			—			1,201,400
Payments on revolving credit facility	—			(1,555,900		)	—			—			(1,555,900		)
Proceeds from issuance of senior notes, net of offering costs	493,825			—			—			—			493,825
Proceeds from issuance of term loan, net of issuance costs	—			393,879			—			—			393,879
Payments on term loan	—			(2,000		)	—			—			(2,000		)
Deferred financing costs	(1,032		)	(2,565		)	—			—			(3,597		)
Distributions to CHK	(422,839		)	—			—			—			(422,839		)
Contributions from (distributions to) affiliates	—			79,823			(14,081		)	(65,742		)	—
Other	(3,205		)	—			—			—			(3,205		)
Net cash provided by (used in) financing activities	66,749			114,637			(14,081		)	(65,742		)	101,563
Net increase (decrease) in cash	77			(880		)	16			—			(787		)
Cash, beginning of period	—			1,613			65			—			1,678
Cash, end of period	$	77		$	733		$	81		$	—		$	891

SEVENTY SEVEN ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2013

(in thousands)



	Parent		Subsidiary Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
Cash Flows From Operating Activities:	$	—	$	13,766		$	404,170		$	(80,865	)	$	337,071
Cash Flows From Investing Activities:
Additions to property and equipment	—		(3,103		)	(346,703		)	—			(349,806		)
Proceeds from sale of assets	—		—			50,602			—			50,602
Proceeds from sale of investment	—		—			2,790			—			2,790
Additions to investments	—		—			(431		)	—			(431		)
Other	—		—			28			—			28
Cash used in investing activities	—		(3,103		)	(293,714		)	—			(296,817		)
Cash Flows From Financing Activities:
Borrowings from revolving credit facility	—		1,216,900			—			—			1,216,900
Payments on revolving credit facility	—		(1,230,100		)	—			—			(1,230,100		)
Distributions to affiliates	—		—			(110,755		)	80,865			(29,890		)
Other	—		3,287			—			—			3,287
Net cash used in financing activities	—		(9,913		)	(110,755		)	80,865			(39,803		)
Net increase (decrease) in cash	—		750			(299		)	—			451
Cash, beginning of period	—		863			364			—			1,227
Cash, end of period	$	—	$	1,613		$	65		$	—		$	1,678

SEVENTY SEVEN ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

17. Quarterly Financial Data (unaudited)

Summarized unaudited quarterly financial data for 2015 and 2014 are as follows:



	Quarters Ended
	March 31, 2015			June 30, 2015			September 30, 2015			December 31, 2015
	(in thousands)
Revenues	$	429,787		$	295,128		$	213,541		$	192,788
Operating loss ^(a)	$	(31,193	)	$	(104,645	)	$	(46,281	)	$	(45,818	)
Net loss^(a)	$	(37,601	)	$	(74,670	)	$	(48,530	)	$	(60,590	)
Loss per share^(d):
Basic	$	(0.78	)	$	(1.51	)	$	(0.95	)	$	(1.18	)
Diluted	$	(0.78	)	$	(1.51	)	$	(0.95	)	$	(1.18	)
	Quarters Ended
	March 31, 2014			June 30, 2014			September 30, 2014			December 31, 2014
	(in thousands)
Revenues	$	509,710		$	549,466		$	526,773		$	494,943
Operating (loss) income^(b)	$	(14,016	)	$	57,475		$	19,852		$	11,685
Net (loss) income^(b)	$	(18,557	)	$	21,710		$	(1,770	)	$	(9,362	)
(Loss) earnings per share^(c)(d):
Basic	$	(0.40	)	$	0.46		$	(0.04	)	$	(0.20	)
Diluted	$	(0.40	)	$	0.46		$	(0.04	)	$	(0.20	)


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


(b)	Includes a non-recurring credit of $10.5 million for the quarter ended June 30, 2014 as a result of the cancellation of the unvested CHK restricted stock and stock option awards and $7.8 million, $3.2 million and $19.8 million of impairments and other for the quarters ended September 30, 2014, June 30, 2014 and March 31, 2014, 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.


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

18. Recently Issued and Proposed Accounting Standards

Recently Issued Accounting Standards

In November 2015, the FASB issued ASU No. 2015-17, "Income Taxes," which simplifies the presentation of deferred income taxes by requiring deferred tax liabilities and assets be classified as noncurrent in the balance sheet. ASU 2015-17 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption permitted. We do not expect the adoption of this guidance to have a material effect on our consolidated financial statements.

In August 2014, the FASB issued ASU No. 2014-15, “Presentation of Financial Statements—Going Concern,” which requires management to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial

doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued (or within one year after the date that the financial statements are available to be issued when applicable). ASU 2014-15 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early application permitted. We do not expect the adoption of this guidance to have a material effect on our consolidated financial statements.



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

Not applicable.

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Item 9A.	Controls and Procedures

Disclosure Controls and Procedures

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

As required by SEC Rule 13a-15(b), we carried out an evaluation, under the supervision and with the participation of our management, including our CEO and CFO, of the effectiveness of our disclosure controls and procedures. Based on that evaluation, the CEO and CFO have concluded that those disclosure controls and procedures were effective as of December 31, 2015.

Management's Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting.

Under the supervision and with the participation of our management, including the CEO and the CFO, we carried out an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2015 using the criteria established in "Internal Control-Integrated Framework" (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our assessment we concluded that, as of December 31, 2015, our internal control over financial reporting was effective based on the criteria in “Internal Control - Integrated Framework” (2013) issued by the COSO.

The effectiveness of our internal control over financial reporting as of December 31, 2015 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears in Item 8 of this Annual Report.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) of the Exchange Act) during the quarter ended December 31, 2015 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

/s/ Jerry Winchester

Jerry Winchester

Director, President and Chief Executive Officer

/s/ Cary Baetz

Cary Baetz

Chief Financial Officer and Treasurer

February 17, 2016

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Item 9B.	Other Information

Not applicable.

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PART III



Item 10.	Directors, Executive Officers and Corporate Governance

Information required by Item 10 of Part III is incorporated herein by reference to the definitive Proxy Statement to be filed by us pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 30, 2016 (the "2016 Proxy Statement").



Item 11.	Executive Compensation

The information required by Item 11 of Part III is incorporated by reference to the 2016 Proxy Statement.



Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information required by Item 12 of Part III is incorporated by reference to the 2016 Proxy Statement.



Item 13.	Certain Relationships and Related Transactions and Director Independence

The information required by Item 13 of Part III is incorporated by reference to the 2016 Proxy Statement.



Item 14.	Principal Accountant Fees and Services

The information required by Item 14 of Part III is incorporated by reference to the 2016 Proxy Statement.

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PART IV



Item 15.	Exhibits, Financial Statement Schedules

The following exhibits are filed as a part of this report:



		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	Commission File No.	Exhibit	Filing Date	Filed Herewith	Furnished Herewith
2.1	Master Separation Agreement, dated as of June 25, 2014, by and between Chesapeake Oilfield Operating, L.L.C., and Chesapeake Energy Corporation.	8-K	001-36354	2.1	7/1/2014
3.1	Certificate of Incorporation of Seventy Seven Energy Inc.	8-K	001-36354	3.1	7/1/2014
3.2	Bylaws of Seventy Seven Energy Inc.	8-K	001-36354	3.2	7/1/2014
4.1	Form of Common Stock Certificate of Seventy Seven Energy Inc.	10-12B	001-36354	4.1	6/13/2014
4.2	Indenture dated June 26, 2014, by and between Chesapeake Oilfield Operating, L.L.C. and Wells Fargo Bank, National Association.	8-K	001-36354	4.2	7/1/2014
4.3	Form of 6.5% Senior Note due 2022 (included in Exhibit 4.2).
4.4	Indenture, dated as of October 28, 2011, among Chesapeake Oilfield Operating, L.L.C., Chesapeake Oilfield Finance, Inc., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee.	S-4	333-187766	4.4	5/30/2013
4.5	Form of 6.625% Senior Note due 2019 (included in Exhibit 4.4).
4.6	Supplemental Indenture, dated June 26, 2014, by and between Chesapeake Oilfield Operating, L.L.C., Chesapeake Oilfield Finance, Inc., Seventy Seven Operating LLC and The Bank of New York Mellon Trust Company, N.A., as trustee.	8-K	001-36354	4.1	7/1/2014
4.7	Second Supplemental Indenture, dated June 15, 2015, by and among Seventy Seven Operating LLC, Seventy Seven Finance Inc., the guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., as trustee.	10-Q	001-36354	4.1	7/29/2015
4.8	Third Supplemental Indenture, dated August 31, 2015, by and among Seventy Seven Operating LLC, Seventy Seven Finance Inc., the guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., as trustee.	10-Q	001-36354	4.1	7/29/2015

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4.9	Fourth Supplemental Indenture, dated January 1, 2016, by and between Seventy Seven Operating LLC, Seventy Seven Finance Inc., the guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., as trustee.					X
10.1	Master Services Agreement, dated as of October 25, 2011, between COS Holdings, L.L.C. and Chesapeake Operating, Inc.	S-4	333-187766	10.1	5/30/2013
10.2	Letter Agreement, dated June 25, 2014, to the Master Services Agreement, dated October 25, 2011, between Chesapeake Operating, L.L.C. and Chesapeake Oilfield Operating, L.L.C.	10-Q	001-36354	10.7	8/5/2014
10.3	Tax Sharing Agreement, dated June 25, 2014, by and between Chesapeake Oilfield Operating, L.L.C. and Chesapeake Energy Corporation.	8-K	001-36354	10.1	7/1/2014
10.4	Employee Matters Agreement, dated June 25, 2014, by and between Chesapeake Oilfield Operating, L.L.C. and Chesapeake Energy Corporation.	8-K	001-36354	10.2	7/1/2014
10.5	Transition Services Agreement, dated as of June 25, 2014, by and between Chesapeake Oilfield Operating, L.L.C. and Chesapeake Energy Corporation.	8-K	001-36354	10.3	7/1/2014
10.6	Services Agreement (hydraulic fracturing), dated June 25, 2014, by and between Performance Technologies, L.L.C. and Chesapeake Operating, Inc.	8-K	001-36354	10.4	7/1/2014
10.7	Term Loan Credit Agreement dated June 25, 2014, by and among Chesapeake Oilfield Operating, L.L.C., Seventy Seven Operating LLC, as borrower, Bank of America, N.A., as administrative agent and the lenders name therein.	8-K	001-36354	10.5	7/1/2014
10.8	Incremental Term Supplement, dated May 13, 2015, by and among Seventy Seven Energy Inc., Seventy Seven Operating LLC, as borrower, Bank of America, N.A., as administrative agent and the lenders named therein.	8-K	001-36354	10.3	5/14/2015
10.9	ABL Credit Agreement, dated June 25, 2014, by and among Nomac Drilling, L.L.C., Performance Technologies, L.L.C., Great Plains Oilfield Rental, L.L.C., Hodges Trucking Company, L.L.C., and Oilfield Trucking Solutions, L.L.C., as borrowers, the guarantors named therein, Wells Fargo Bank, National Association and Bank of America, N.A., as joint lead arrangers and joint book runners, Bank of America, N.A., as syndication agent, Credit Agricole Corporate and Investment Bank and SunTrust Bank, as co-documentation agents, and the lenders name therein.	8-K	001-36354	10.6	7/1/2014

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10.10	Amendment No. 1 to Credit Agreement, dated April 23, 2015, by and among Wells Fargo Bank, National Association, as administrative agent, as administrative agent, the lenders named therein, Nomac Drilling, L.L.C., Performance Technologies, L.L.C., Great Plains Oilfield Rental, L.L.C., Hodges Trucking Company, L.L.C. and Oilfield Trucking Solutions, L.L.C., as borrowers, and the guarantors named therein.	10-Q	001-36354	10.8	5/14/2015
10.11	Consent, dated June 15, 2015, by and among Wells Fargo Bank, National Association, as administrative agent and collateral agent, the lenders named therein, Nomac Drilling, L.L.C., Performance Technologies, L.L.C., Great Plains Oilfield Rental, L.L.C., Hodges Trucking Company, L.L.C. and Oilfield Trucking Solutions, L.L.C., as borrowers, and the guarantors named therein.	10-Q	001-36354	10.8	7/29
10.12	Employment Agreement with Jerry Winchester dated August 2014.*	10-Q	001-36354	10.8	8/5/2014
10.13	Employment Agreement with Cary Baetz dated August 2014.*	10-Q	001-36354	10.9	8/5/2014
10.14	First Amendment to Employment Agreement with Cary Baetz, made effective October 29, 2014.*	10-Q	001-36354	10.1	10/30/2014
10.15	Employment Agreement with Karl Blanchard, made effective August 2014.*	10-Q	001-36354	10.10	8/5/2014
10.16	First Amendment to Employment Agreement with Karl Blanchard, made effective October 29, 2014.*	10-Q	001-36354	10.2	10/30/2014
10.17	Employment Agreement with James Minmier, made effective August 2014.*	10-Q	001-36354	10.11	8/5/2014
10.18	First Amendment to Employment Agreement with James Minmier, made effective October 29, 2014.*	10-Q	001-36354	10.3	10/30/2014
10.19	Employment Agreement with Bill Stanger, made effective August 2014.*	10-Q	001-36354	10.12	8/5/2014
10.20	First Amendment to Employment Agreement with Bill Stanger, made effective October 29, 2014.*	10-Q	001-36354	10.4	10/30/2014
10.21	Seventy Seven Energy Inc. Amended and Restated 2014 Incentive Plan.	S-8	333-204838	99.1	6/9/2015
10.22	Form of Restricted Stock Unit Replacement Agreement under 2014 Incentive Plan.*	10-Q	001-36354	10.13	8/5/2014
10.23	Form of 2013 Restricted Stock Replacement Agreement under 2014 Incentive Plan.*	10-Q	001-36354	10.14	8/5/2014
10.24	Form of 2003 Restricted Stock Replacement Agreement under 2014 Incentive Plan.*	10-Q	001-36354	10.15	8/5/2014
10.25	Form of Director Restricted Stock Agreement under 2014 Incentive Plan.	10-Q	001-36354	10.16	8/5/2014
10.26	Form of Employee Restricted Stock Agreement under 2014 Incentive Plan.*	10-Q	001-36354	10.17	8/5/2014

100

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10.27

2014 Executive Performance Management Plan.*

10-K

001-36354

10.24

3/2/2015

10.28

2015 Executive Performance Management Plan. *

10-Q

001-36354

10.17

5/5/2015

12.1

Schedule of Computation of Ratio of Earnings to Fixed Charges.

21.1

List of Subsidiaries

23.1

Consent of PricewaterhouseCoopers LLP.

31.1

Certification of Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.

31.2

Certification of Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.

32.1

Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2

Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.1

Interactive data files pursuant to Rule 405 of Regulation S-T.

†



†	Pursuant to Rule 406T of Regulation S-T, interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of sections 11 and 12 of the Securities Act of 1933, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to any liability under those sections.
*	Management contract or compensatory plan or arrangement.

101

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

SEVENTY SEVEN ENERGY INC.

Date: February 17, 2016 By: /s/ Jerry Winchester

Jerry Winchester

Director, President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.



Signature	Capacity	Date

/s/ Jerry Winchester	Director, President and Chief Executive Officer (Principal Executive Officer)	February 17, 2016
Jerry Winchester

/s/ Cary Baetz	Chief Financial Officer and Treasurer (Principal Financial Officer and Principal Accounting Officer)	February 17, 2016
Cary Baetz

/s/ Edward J. DiPaolo	Chairman of the Board	February 17, 2016
Edward J. DiPaolo

/s/ Bob G. Alexander	Director	February 17, 2016
Bob G. Alexander

/s/ Ronnie Irani	Director	February 17, 2016
Ronnie Irani

/s/ Alvin Bernard Krongard	Director	February 17, 2016
Alvin Bernard Krongard

/s/ Tucker Link	Director	February 17, 2016
Tucker Link

/s/ Marran H. Ogilvie	Director	February 17, 2016
Marran H. Ogilvie

102

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INDEX TO EXHIBITS



		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	Commission File No.	Exhibit	Filing Date	Filed Herewith	Furnished Herewith
2.1	Master Separation Agreement, dated as of June 25, 2014, by and between Chesapeake Oilfield Operating, L.L.C., and Chesapeake Energy Corporation.	8-K	001-36354	2.1	7/1/2014
3.1	Certificate of Incorporation of Seventy Seven Energy Inc.	8-K	001-36354	3.1	7/1/2014
3.2	Bylaws of Seventy Seven Energy Inc.	8-K	001-36354	3.2	7/1/2014
4.1	Form of Common Stock Certificate of Seventy Seven Energy Inc.	10-12B	001-36354	4.1	6/13/2014
4.2	Indenture dated June 26, 2014, by and between Chesapeake Oilfield Operating, L.L.C. and Wells Fargo Bank, National Association.	8-K	001-36354	4.2	7/1/2014
4.3	Form of 6.5% Senior Note due 2022 (included in Exhibit 4.2).
4.4	Indenture, dated as of October 28, 2011, among Chesapeake Oilfield Operating, L.L.C., Chesapeake Oilfield Finance, Inc., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee.	S-4	333-187766	4.4	5/30/2013
4.5	Form of 6.625% Senior Note due 2019 (included in Exhibit 4.4).
4.6	Supplemental Indenture, dated June 26, 2014, by and between Chesapeake Oilfield Operating, L.L.C., Chesapeake Oilfield Finance, Inc., Seventy Seven Operating LLC and The Bank of New York Mellon Trust Company, N.A., as trustee.	8-K	001-36354	4.1	7/1/2014
4.7	Second Supplemental Indenture, dated June 15, 2015, by and among Seventy Seven Operating LLC, Seventy Seven Finance Inc., the guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., as trustee.	10-Q	001-36354	4.1	7/29/2015
4.8	Third Supplemental Indenture, dated August 31, 2015, by and among Seventy Seven Operating LLC, Seventy Seven Finance Inc., the guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., as trustee.	10-Q	001-36354	4.1	7/29/2015
4.9	Fourth Supplemental Indenture, dated January 1, 2016, by and between Seventy Seven Operating LLC, Seventy Seven Finance Inc., the guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., as trustee.					X
10.1	Master Services Agreement, dated as of October 25, 2011, between COS Holdings, L.L.C. and Chesapeake Operating, Inc.	S-4	333-187766	10.1	5/30/2013

103

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10.2	Letter Agreement, dated June 25, 2014, to the Master Services Agreement, dated October 25, 2011, between Chesapeake Operating, L.L.C. and Chesapeake Oilfield Operating, L.L.C.	10-Q	001-36354	10.7	8/5/2014
10.3	Tax Sharing Agreement, dated June 25, 2014, by and between Chesapeake Oilfield Operating, L.L.C. and Chesapeake Energy Corporation.	8-K	001-36354	10.1	7/1/2014
10.4	Employee Matters Agreement, dated June 25, 2014, by and between Chesapeake Oilfield Operating, L.L.C. and Chesapeake Energy Corporation.	8-K	001-36354	10.2	7/1/2014
10.5	Transition Services Agreement, dated as of June 25, 2014, by and between Chesapeake Oilfield Operating, L.L.C. and Chesapeake Energy Corporation.	8-K	001-36354	10.3	7/1/2014
10.6	Services Agreement (hydraulic fracturing), dated June 25, 2014, by and between Performance Technologies, L.L.C. and Chesapeake Operating, Inc.	8-K	001-36354	10.4	7/1/2014
10.7	Term Loan Credit Agreement dated June 25, 2014, by and among Chesapeake Oilfield Operating, L.L.C., Seventy Seven Operating LLC, as borrower, Bank of America, N.A., as administrative agent and the lenders name therein.	8-K	001-36354	10.5	7/1/2014
10.8	Incremental Term Supplement, dated May 13, 2015, by and among Seventy Seven Energy Inc., Seventy Seven Operating LLC, as borrower, Bank of America, N.A., as administrative agent and the lenders named therein.	8-K	001-36354	10.3	5/14/2015
10.9	ABL Credit Agreement, dated June 25, 2014, by and among Nomac Drilling, L.L.C., Performance Technologies, L.L.C., Great Plains Oilfield Rental, L.L.C., Hodges Trucking Company, L.L.C., and Oilfield Trucking Solutions, L.L.C., as borrowers, the guarantors named therein, Wells Fargo Bank, National Association and Bank of America, N.A., as joint lead arrangers and joint book runners, Bank of America, N.A., as syndication agent, Credit Agricole Corporate and Investment Bank and SunTrust Bank, as co-documentation agents, and the lenders name therein.	8-K	001-36354	10.6	7/1/2014
10.10	Amendment No. 1 to Credit Agreement, dated April 23, 2015, by and among Wells Fargo Bank, National Association, as administrative agent, as administrative agent, the lenders named therein, Nomac Drilling, L.L.C., Performance Technologies, L.L.C., Great Plains Oilfield Rental, L.L.C., Hodges Trucking Company, L.L.C. and Oilfield Trucking Solutions, L.L.C., as borrowers, and the guarantors named therein.	10-Q	001-36354	10.8	5/14/2015

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10.11	Consent, dated June 15, 2015, by and among Wells Fargo Bank, National Association, as administrative agent and collateral agent, the lenders named therein, Nomac Drilling, L.L.C., Performance Technologies, L.L.C., Great Plains Oilfield Rental, L.L.C., Hodges Trucking Company, L.L.C. and Oilfield Trucking Solutions, L.L.C., as borrowers, and the guarantors named therein.	10-Q	001-36354	10.8	7/29
10.12	Employment Agreement with Jerry Winchester dated August 2014.*	10-Q	001-36354	10.8	8/5/2014
10.13	Employment Agreement with Cary Baetz dated August 2014.*	10-Q	001-36354	10.9	8/5/2014
10.14	First Amendment to Employment Agreement with Cary Baetz, made effective October 29, 2014.*	10-Q	001-36354	10.1	10/30/2014
10.15	Employment Agreement with Karl Blanchard, made effective August 2014.*	10-Q	001-36354	10.10	8/5/2014
10.16	First Amendment to Employment Agreement with Karl Blanchard, made effective October 29, 2014.*	10-Q	001-36354	10.2	10/30/2014
10.17	Employment Agreement with James Minmier, made effective August 2014.*	10-Q	001-36354	10.11	8/5/2014
10.18	First Amendment to Employment Agreement with James Minmier, made effective October 29, 2014.*	10-Q	001-36354	10.3	10/30/2014
10.19	Employment Agreement with Bill Stanger, made effective August 2014.*	10-Q	001-36354	10.12	8/5/2014
10.20	First Amendment to Employment Agreement with Bill Stanger, made effective October 29, 2014.*	10-Q	001-36354	10.4	10/30/2014
10.21	Seventy Seven Energy Inc. Amended and Restated 2014 Incentive Plan.	S-8	333-204838	99.1	6/9/2015
10.22	Form of Restricted Stock Unit Replacement Agreement under 2014 Incentive Plan.*	10-Q	001-36354	10.13	8/5/2014
10.23	Form of 2013 Restricted Stock Replacement Agreement under 2014 Incentive Plan.*	10-Q	001-36354	10.14	8/5/2014
10.24	Form of 2003 Restricted Stock Replacement Agreement under 2014 Incentive Plan.*	10-Q	001-36354	10.15	8/5/2014
10.25	Form of Director Restricted Stock Agreement under 2014 Incentive Plan.	10-Q	001-36354	10.16	8/5/2014
10.26	Form of Employee Restricted Stock Agreement under 2014 Incentive Plan.*	10-Q	001-36354	10.17	8/5/2014
10.27	2014 Executive Performance Management Plan.*	10-K	001-36354	10.24	3/2/2015
10.28	2015 Executive Performance Management Plan. *	10-Q	001-36354	10.17	5/5/2015
12.1	Schedule of Computation of Ratio of Earnings to Fixed Charges.					X
21.1	List of Subsidiaries					X
23.1	Consent of PricewaterhouseCoopers LLP.					X

105

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31.1

Certification of Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.

31.2

Certification of Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.

32.1

Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2

Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.1

Interactive data files pursuant to Rule 405 of Regulation S-T.

†



†	Pursuant to Rule 406T of Regulation S-T, interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of sections 11 and 12 of the Securities Act of 1933, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to any liability under those sections.
*	Management contract or compensatory plan or arrangement.

106

Large accelerated filer

Accelerated filer

Non-accelerated filer

¬ (Do not check if a smaller reporting company)

Smaller reporting company