Annual Report (10-k)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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FORM 10-K

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(Mark One)



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

For the fiscal year ended: December 31, 2014



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

For the transition period from to

Commission File Number: 001-33816

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(A Delaware Corporation)

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I.R.S. Employer Identification No. 26-0287117

14624 N. Scottsdale Rd., Suite 300, Scottsdale, Arizona 85254

Telephone: (602) 903-7802

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



Title of each class		Name of each exchange on which registered
Common Stock, $0.001 par value		New York Stock Exchange

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

None

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

Indicate by check mark if 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 website, 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 registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

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



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

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

As of June 30, 2014, the last business day of the registrant’s most recently completed second fiscal quarter, the aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant was $328.8 million based on the closing sale price on such date as reported on the New York Stock Exchange. Shares held by executive officers, directors and persons owning directly or indirectly more than 10% of the outstanding common stock have been excluded from the preceding number because such persons may be deemed to be affiliates of the registrant. This determination of affiliate status is not necessarily a conclusive determination for any other purposes.

The number of shares outstanding of the registrant’s common stock as of March 13, 2015 was 27,912,221.

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Documents Incorporated by Reference

Portions of the registrant’s Proxy Statement for the 2014 Annual Meeting of Stockholders to be held on May 5, 2015, are incorporated by reference into Part III, Items 10-14 of this Annual Report on Form 10-K.

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Cautionary Note for Forward-Looking Statements		3
	PART I	5
Item 1.	Business	5
Item 1A.	Risk Factors	14
Item 1B.	Unresolved Staff Comments	31
Item 2.	Properties	31
Item 3.	Legal Proceedings	31
Item 4.	Mine Safety Disclosures	31

	PART II	31
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	32
Item 6.	Selected Financial Data	34
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	36
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	54
Item 8.	Financial Statements and Supplementary Data	55
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	55
Item 9A.	Controls and Procedures	55
Item 9B.	Other Information	58

	PART III	58
Item 10.	Directors, Executive Officers and Corporate Governance	58
Item 11.	Executive Compensation	58
Item 12.	Security Ownership of Certain Beneficial Owners and Management Related Stockholder Matters	58
Item 13.	Certain Relationships and Related Transactions, and Director Independence	58
Item 14.	Principal Accounting Fees and Services	58

	PART IV	59
Item 15.	Exhibits and Financial Statement Schedules	59

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CAUTIONARY NOTE ON FORWARD-LOOKING STATEMENTS

In addition to historical information, this Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the United States Securities Act of 1933, as amended, or the “Securities Act,” and Section 21E of the United States Securities Exchange Act of 1934, as amended, or the “Exchange Act.” These statements relate to our expectations for future events and time periods. All statements other than statements of historical fact are statements that could be deemed to be forward-looking statements, including, but not limited to, statements regarding:


•	future financial performance and growth targets or expectations;


•	market and industry trends and developments;


•	the potential benefits of our completed and any future merger, acquisition, disposition and financing transactions, including the potential sale of Thermo Fluids Inc.; and


•	plans to increase operational capacity, including additional trucks, saltwater disposal wells, frac tanks, landfills, processing and treatment facilities and pipeline construction or expansion.

You can identify these and other forward-looking statements by the use of words such as “anticipates,” “expects,” “intends,” “plans,” “predicts,” “believes,” “seeks,” “estimates,” “may,” “will,” “should,” “would,” “could,” “potential,” “future,” “continue,” “ongoing,” “forecast,” “project,” “target” or similar expressions, and variations or negatives of these words.

These forward-looking statements are based on information available to us as of the date of this Annual Report and our current expectations, forecasts and assumptions, and involve a number of risks and uncertainties. Accordingly, forward-looking statements should not be relied upon as representing our views as of any subsequent date. Future performance cannot be ensured, and actual results may differ materially from those in the forward-looking statements. Some factors that could cause actual results to differ include:

•

financial results that may be volatile and may not reflect historical trends due to, among other things, changes in commodity prices or general market conditions, acquisition and disposition activities, fluctuations in consumer trends, pricing pressures, changes in raw material or labor prices or rates related to our business and changing regulations or political developments in the markets in which we operate;


•	risks associated with our indebtedness, including our ability to manage our liquidity needs and to comply with covenants under our credit facilities, including the indenture governing our notes;


•	risks associated with our capital structure, including our ability to access necessary funding under our existing or future credit facilities and to generate sufficient operating cash flow to meet our debt service obligation;


•	difficulties in identifying and completing acquisitions and divestitures, and differences in the type and availability of consideration or financing for such acquisitions and divestitures;


•	difficulties in successfully executing our growth initiatives, including difficulties in permitting, financing and constructing pipelines and waste treatment assets and in structuring economically viable agreements with potential customers, financing sources and other parties;


•	our ability to attract, motivate and retain key executives and qualified employees in key areas of our business;


•	fluctuations in prices, transportation costs and demand for commodities such as oil and natural gas;


•	changes in customer drilling, completion and production activities and capital expenditure plans, including impacts due to low oil and/or natural gas prices or the economic or regulatory environment;


•	risks associated with the operation, construction and development of saltwater disposal wells, solids and liquids treatment assets, landfills and pipelines, including access to additional locations and rights-of-way, unscheduled delays or inefficiencies and reductions in volume due to micro- and macro-economic factors or the availability of less expensive alternatives;


•	risks associated with new technologies and the impact on our business;


•	the effects of competition in the markets in which we operate, including the adverse impact of competitive product announcements or new entrants into our markets and transfers of resources by competitors into our markets;

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•	changes in economic conditions in the markets in which we operate or in the world generally, including as a result of political uncertainty;


•	reduced demand for our services due to regulatory or other influences related to extraction methods such as hydraulic fracturing, shifts in production among shale areas in which we operate or into shale areas in which we do not currently have operations or the loss of key customers;


•	the impact of changes in laws and regulation on waste management and disposal activities, including those impacting the delivery, storage, collection, transportation treatment and disposal of waste products, as well as the use or reuse of recycled or treated products or byproducts;


•	control of costs and expenses;


•	present and possible future claims, litigation or enforcement actions or investigations;


•	natural disasters, such as hurricanes, earthquakes and floods, or acts of terrorism, or extreme weather conditions, that may impact our corporate headquarters, assets, including wells or pipelines, distribution channels, or which otherwise disrupt our or our customers’ operations or the markets we serve;


•	the threat or occurrence of international armed conflict;


•	the unknown future impact on our business from the legislation and governmental rulemaking, including the Affordable Care Act, the Dodd-Frank Wall Street Reform and Consumer Protection Act and the rules to be promulgated thereunder;


•	risks involving developments in environmental or other governmental laws and regulations in the markets in which we operate and our ability to effectively respond to those developments including laws and regulations relating to oil and gas extraction businesses, particularly relating to water usage, and the disposal, transportation and treatment of liquid and solid wastes; and


•	other risks identified in this Annual Report or referenced from time to time in our filings with the United States Securities and Exchange Commission (the “SEC”).

You are cautioned not to place undue reliance on any forward-looking statements, which speak only as of the date of this Annual Report. Except as required by law, we do not undertake any obligation to update or release any revisions to these forward-looking statements to reflect any events or circumstances, whether as a result of new information, future events, changes in assumptions or otherwise, after the date hereof.

Where You Can Find Other Information

Our website is www.nuverra.com. Information contained on our website is not part of this Annual Report on Form 10-K. Information that we file with or furnish to the SEC, including our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to or exhibits included in these reports are available for download, free of charge, on our website soon after such reports are filed with or furnished to the SEC. These reports and other information, including exhibits filed or furnished therewith, are also available at the SEC’s website at www.sec.gov. You may also obtain and copy any document we file with or furnish to the SEC at the SEC’s public reference room at 100 F Street, NE, Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the SEC’s public reference facilities by calling the SEC at 1-800-SEC-0330. You may request copies of these documents, upon payment of a duplicating fee, by writing to the SEC at its principal office at 100 F Street, NE, Room 1580, Washington, D.C. 20549.

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NUVERRA ENVIRONMENTAL SOLUTIONS, INC.

PART I



ITEM 1.	Business

When used in this Annual Report, the terms “Nuverra,” the “Company,” “we,” “our,” and “us” refer to Nuverra Environmental Solutions, Inc. and its consolidated subsidiaries, unless otherwise specified.

Overview

Nuverra Environmental Solutions, Inc. is among the largest companies in the United States dedicated to providing comprehensive, full-cycle environmental solutions to customers focused on the development and ongoing production of oil and natural gas from shale formations. Nuverra provides one-stop, total environmental solutions, including delivery, collection, treatment, recycling, and disposal of water, wastewater, waste fluids, hydrocarbons, and restricted solids that are part of the drilling, completion, and ongoing production of shale oil and natural gas.

To meet its customers’ environmental needs, Nuverra utilizes a broad array of assets to provide a comprehensive environmental solution. The Company’s logistics assets include trucks and trailers, temporary and permanent pipelines, temporary and permanent storage facilities, ancillary rental equipment, treatment and processing facilities, and liquid and solid waste disposal sites. The Company provides its suite of solutions to customers who demand environmental compliance and accountability from their service providers.

The following chart describes our focus on providing comprehensive environmental solutions and the assets we currently utilize or are in the process of implementing to execute on our strategy:



		Delivery		Collection		Treatment		Recycling		Disposal
Solutions	• • •	Fresh water to drilling sites Drilling mud Water procurement	• • •	Liquid waste from hydraulic fracturing Liquid waste from ongoing well production Solid drilling waste	• •	Oily waste water Liquid and solid waste from drilling, completion and ongoing well production	•	Liquid and solid waste from drilling, completion and ongoing well production	•	Liquid and solid waste from drilling, completion and ongoing well production

Assets	• • • •	More than 1,000 trucks Approximately 5,500 tanks 50 miles of freshwater delivery pipeline 50 miles of produced water collection pipeline			• •	Appalachian Water Services, LLC (“AWS”) plant—a wastewater treatment recycling facility specifically designed to treat and recycle water involved in the hydraulic fracturing process in the Marcellus Shale area Thermal treatment assets for solid waste			• •	56 liquid waste disposal wells Solid waste landfill

Our shale solutions business consists of operations in shale basins where customer exploration and production (“E&P”) activities are predominantly focused on shale oil and natural gas as follows:


•	Oil shale areas: includes our operations in the Bakken, the Utica, the Eagle Ford, the Mississippian, the Tuscaloosa Marine and the Permian Basin Shale areas. During 2014, approximately 75.2% of our revenues from continuing operations were derived from these shale areas.


•	Gas shale areas: includes our operations in the Marcellus, Haynesville and Barnett (which we substantially exited during the three months ended March 31, 2014) Shale areas. During 2014, approximately 24.8% of our revenues from continuing operations were derived from these shale areas.

Nuverra supports its customers’ demand for diverse, comprehensive and regulatory compliant environmental solutions required for the safe and efficient drilling, completion and production of oil and natural gas from shale formations. Current services include (i) fluid logistics via water procurement, delivery, collection, storage, treatment, recycling and disposal, (ii) solid waste collection, treatment, recycling and disposal, (iii) temporary and permanent pipeline facilities and water infrastructure services, (iv) equipment rental services, and (v) other ancillary services for E&P companies focused on the extraction of oil and natural gas resources from shale basins.

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As part of its environmental solution for water and water-related services, Nuverra serves E&P customers seeking fresh water acquisition, temporary or permanent water transmission and storage, transportation, treatment or disposal of fresh flowback and produced water in connection with shale oil and natural gas hydraulic fracturing operations. The Company also provides services for water pit excavations, well site preparation and well site remediation. The Company owns a 50-mile underground pipeline network in the Haynesville Shale area for the efficient delivery of fresh water and removal of produced water, a fleet of more than 1,000 trucks for delivery and collection, and approximately 5,500 storage tanks. The Company also owns or leases 56 operating saltwater disposal wells in the Bakken, Marcellus/Utica, Haynesville, Eagle Ford, and Tuscaloosa Marine Shale areas. Nuverra has a majority interest investment in Appalachian Water Services, LLC (“AWS”), which owns and operates a wastewater treatment facility specifically designed to treat and recycle water resulting from the hydraulic fracturing process in the Marcellus Shale area.

As part of its environmental solution for solid waste, the Company owns an oilfield solids disposal landfill in the Bakken Shale area. The landfill is located on a 60-acre site with permitted capacity of more than 1.7 million cubic yards of airspace. The Company believes that permitted capacity at this site could be expanded up to 5.8 million cubic yards in the future, subject to receipt of requisite regulatory approvals. During 2014, the Company completed construction of an advanced solids processing and recycling facility at the landfill site in North Dakota. Nuverra’s process for treating and recycling wet cuttings is named Terrafficient^SM, and it is a unique facility serving the Bakken Shale region. Terrafficient^SMenables E&P operators to recycle and re-use 100% of drill cuttings, bypassing the need for wellsite cuttings pits or special-purpose landfills. The end product resulting from the Terrafficient^SM process is intended for re-use in a variety of industrial settings, including road base, general fill and flowable fill for well pads and other commercial applications. The Company is currently in the process of commissioning the facility.

During the fourth quarter of 2013, Nuverra announced a strategic rationalization of its shale solutions business designed to maximize operating efficiencies, leverage future growth opportunities, and optimize sales and business development activities to align with its customers. The Company completed the initiative during 2014, which resulted in the creation of three geographically distinct divisions, which are further described in Note 19 of the Notes to Consolidated Financial Statements herein:


•	Northeast Division: comprising the Marcellus and Utica Shale areas;


•	Southern Division: comprising the Haynesville, Barnett (which we substantially exited during the three months ended March 31, 2014), Eagle Ford, Mississippian and Tuscaloosa Marine Shale areas and the Permian Basin; and


•	Rocky Mountain Division: comprising the Bakken Shale area.

Competitive Strengths

We believe our business possesses the following competitive strengths, which position us to better serve our customers and grow revenue and cash flow:

Leading Transportation and Logistics Network to Control Delivery, Collection, Treatment, Recycling and Disposal.

We operate a transportation and logistics network consisting of more than 1,000 trucks, 5,500 storage tanks, 50 miles of fresh water delivery pipeline and 50 miles of produced water collection pipeline. The products we move within our logistics network include fresh water, drilling fluids, liquid waste, solid drilling waste, and oily wastewater. Our business practices and standards promote the safe and responsible collection, treatment, recycling and/or disposal of restricted environmental waste on behalf of our customers. As we expand our treatment, recycling, and disposal solutions, we believe controlling the products that are processed by these assets through our transportation and logistics network is a competitive strength when compared to competitors that rely more heavily on third-party providers for transportation and logistics expertise.

Our Customers are Highly Focused on Environmental Responsibility and Compliance.

Our customers are committed to conducting their operations with high levels of environmental responsibility and compliance. They value a national environmental solutions provider that is focused exclusively on the safe and responsible delivery, collection, treatment, recycling, and disposal of their restricted products. There is a high level of scrutiny on the environmental impact of shale oil and natural gas drilling and production. As a result, we believe there is significant demand for Nuverra’s focus on surface environmental matters. We provide customers the ability to effectively outsource a portion of the regulatory risk surrounding their products, making it possible for them to focus on their core competencies.

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National Operating Footprint Appeals to Customers Operating in Multiple Shale Basins.

We are one of the few companies solely focused on surface environmental solutions that has a national operating capability with a strong presence in the majority of the North American unconventional shale basins. An increasing number of E&P operators have a presence in multiple basins, including a growing number of super majors, majors, and large independent companies. As a result, we believe we have a competitive advantage relative to many smaller local and regional competitors due to our national customer relationships and the growing demand for consistent and comprehensive solutions to customers' environmental needs across multiple basins.

Differentiated Value Proposition.

We believe the future, long-term growth of domestic production of oil and natural gas in unconventional shale basins presents a unique growth opportunity for companies such as Nuverra that provide comprehensive environmental solutions in a one-stop business model. Despite the decline in oil prices that began in mid-2014 and continued into 2015, many industry experts and financial analysts are forecasting continuing advances in drilling and completion techniques in the unconventional shale basins in which we operate. These new techniques require significant environmental solutions to manage restricted waste products, and our customers remain committed to the responsible and safe handling of these products. As such, we believe our strategy to provide comprehensive environmental solutions, from collection through treatment, recycling or disposal, provides us with a strong competitive advantage. Many of our competitors offer only a single component of this value chain, with environmental solutions comprising a component of their overall business services. We believe our focus on the spectrum of surface-related environmental solutions makes it possible for us to provide our customers with a consistent, compliant, professional, and highly differentiated value proposition.

Operational, Environmental and Regulatory Expertise.

We believe our management team and employees have significant expertise regarding the issues surrounding environmental waste products and can efficiently and safely provide services to our customers to manage this aspect of their business. We apply this experience to providing excellent service and identifying innovative, new solutions for our customers. We expect increasing regulatory compliance will increase the financial and operational burdens on our customers, which may increase demand for our services.

Strategy

Our strategy is to leverage our full-cycle business model to expand relationships with current and new customers and to provide comprehensive environmental solutions, including delivery, collection, treatment, recycling, and disposal of the environmental waste generated from unconventional shale oil and natural gas production. The principal elements of our business strategy are to:

Utilize Our Leading Transportation and Logistics Network to Expand Pipeline, Rental, Treatment, Recycling, and Disposal Solutions.

We intend to leverage our advanced transportation and logistics system to expand our pipeline, rental, treatment, recycling, and disposal services. We believe as the market in the unconventional shales evolves, customers will increasingly value a one-stop provider for all of their environmental solutions, including pipeline, rental, treatment, recycling and disposal solutions for liquid and solid waste products. Our current transportation and logistics footprint provides the platform from which we can continue to expand our customer network and provide end-to-end environmental solutions.

Establish and Maintain Leading Market Positions in Core Operating Areas.

We strive to establish and maintain leading market positions within our core operating areas to realize benefits from scale and customer penetration, as well as to maximize our returns on invested capital. As a result, we seek to maintain close customer relationships and to provide comprehensive, end-to-end environmental solutions, rather than one-off individual services. Combined with the increasing number of customers operating in multiple basins, we seek a national-level dialogue with these customers in order to provide a consistent and comprehensive solutions-based approach to their environmental needs.

Provide Solutions in a Reliable and Responsible Manner.

Nuverra is a company focused on efficiency and environmental sustainability through responsible practices. We are committed to protecting the health and safety of our employees, partners and other stakeholders, reducing the impact of our operations on the environment, supporting our communities, and enhancing the operations of our partners. These are key tenets that govern our daily activities and strategic vision. Our customers require high levels of regulatory, environmental and safety compliance,

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which we support through employee training, the maintenance of our asset base and our approach to developing environmentally sustainable solutions for customers.

Develop and Implement Best Practices to Drive Efficiency and Economy.

We believe that there are best-practices in certain of our current shale geographies that can be expanded to other areas of operations to drive efficiency. We also intend to pursue the implementation of new invoicing and fleet management systems to reduce costs, improve data collection and increase operating efficiency.

Industry Overview

Over the past several years, E&P companies have focused on utilizing the vast resource potential available across many of North America’s unconventional shale areas through the application of horizontal drilling and completion technologies, including multi-stage hydraulic fracturing. We believe the majority of the capital for the continued development of shale oil and natural gas resources will be provided in part by the large, well-capitalized domestic and international oil and natural gas companies. We believe these companies are highly focused on environmental responsibility, compliance, and regulatory matters and prefer vendors that represent experienced, highly qualified national companies.

Advances in drilling technology and the development of unconventional North American hydrocarbon plays allow previously inaccessible or non-economical formations in the earth’s crust to be accessed by utilizing high pressure methods from millions of gallons of water (or the process known as hydraulic fracturing) combined with proppant fluids (containing sand grains or ceramic beads) to create new perforation depths and fissures to extract natural gas, oil, and other hydrocarbon resources. Significant amounts of water are required to be delivered to the well for hydraulic fracturing operations, and subsequently, complex water flows, in the forms of flowback and produced water, represent a waste stream generated by these methods of hydrocarbon exploration and production. In addition to the liquid product stream involved in the hydraulic fracturing process, there are also significant environmental solid waste streams that are generated during the drilling and completion of a well. During the drilling process, a combination of the cut rock, or “cuttings,” mixed with the liquid used to drill the well, is returned to the surface and must be handled in accordance with environmental and other regulations. Historically, much of this solid waste byproduct was buried at the well site. We believe that customers will increasingly be focused on the treatment and offsite disposal or recycling of the solid waste byproduct. Produced water volumes, which represent water from the formation produced alongside hydrocarbons over the life of the well, are generally driven by marginal costs of production and frequently create a multi-year demand for our services once the well has been drilled and completed.

We primarily operate in the Bakken, Marcellus, Utica, Haynesville and Eagle Ford Shale areas.

•

The Bakken and underlying Three Forks formations are the two primary reservoirs currently being developed in the Williston Basin, which covers most of western North Dakota, eastern Montana, northwest South Dakota and southern Saskatchewan. The Bakken formation occupies approximately 200,000 square miles of the subsurface of the Williston Basin in Montana, North Dakota and Saskatchewan. The Three Forks formation lies directly below North Dakota’s portion of the Bakken formation, where oil-producing rock is located between layers of shale approximately two miles underground. According to the United States Geological Survey - April 2013 Oil and Gas Resource Assessment, the Bakken and Three Forks Shale formations in North Dakota, South Dakota, and Montana contain an estimated 7.4 billion barrels of technically recoverable oil reserves. The Bakken Shale area is one of the most actively drilled unconventional resources in North America, with North Dakota daily crude oil production reaching more than 1.2 million barrels per day as of November 2014, currently ranking second among U.S. states in daily average crude oil production.


•	The Marcellus Shale area is located in the Appalachian Basin in the Northeastern United States, primarily in Pennsylvania, West Virginia, New York and Ohio. The Marcellus Shale is the largest natural gas field in North America with approximately 118.9 Tcf of technically recoverable gas, according to the EIA.

•

Adjacent to the Marcellus Shale is the emerging Utica Shale, located primarily in southwestern Pennsylvania and eastern Ohio. Still in the early stages of development, the Utica Shale play has three identified areas: oil, condensate and dry gas. According to the EIA, the Utica Shale is estimated to have approximately 37.4 Tcf of technically recoverable gas and 0.9 Tcf of recoverable oil reserve potential.


•	The Haynesville Shale area is located across northwest Louisiana and east Texas, and extends into Arkansas. The Haynesville Shale area is the third largest natural gas-producing basin in North America, with an estimated 70.9 Tcf of technically recoverable gas according to the EIA's 2014 Annual Energy Assumptions Report.

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•	The Eagle Ford Shale area is a gas and oil play located across southern Texas. The play contains a high liquid component, which has led to the definition of three areas: oil, condensate and dry gas. The Eagle Ford Shale is estimated to have approximately 53.4 Tcf of technically recoverable gas and 6.9 billion barrels of technically recoverable oil, according to the EIA.

Customers

Our customers include major domestic and international oil and gas companies, foreign national oil and gas companies and independent oil and natural gas production companies that are active in our core areas of operations. In the year ended December 31, 2014, our three largest customers represented 15%, 10% and 10%, respectively, of our total consolidated revenues.

Competitors

Our competition includes small regional service providers as well as larger companies with operations throughout the continental United States and internationally. Our larger competitors are Basic Energy Services, Inc., Superior Energy Services, Inc., Forbes Energy Services, Inc., Key Energy Services, Inc., Nabors Industries Ltd., Waste Connections (R360 Environmental Solutions), Republic Services (Tervita Corporation USA) and Stallion Oilfield Services, Ltd.

We differentiate ourselves from our major competitors by our operating philosophy. Unlike Nuverra, many of our competitors also conduct hydraulic fracturing and/or workover operations. However, none of these companies focus exclusively on the surface environmental aspects of unconventional oil and natural gas operations, a key aspect of our strategy as we focus on our fluid and solid waste treatment, recycling, and disposal capabilities. We believe that offering a comprehensive environmental solution, which includes certainty of control of products from generation through disposal, recycling or reuse, to our customers, is an important value proposition and will increase in importance over time. We believe our delivery and collection logistics network is a significant competitive advantage relative to competitors that are focused solely on treatment, recycling and disposal operations such as Republic Services (Tervita Corporation USA), Waste Connections, Inc., Waste Management and Clean Harbors, Inc.

Health, Safety & Environment

We are committed to excellence in HS&E in our operations, which we believe is a critical characteristic of our business. Our customers in the unconventional shale basins, including many of the large integrated and international oil and gas companies, require us, as a service provider, to meet high standards on HS&E matters. As a result, we believe that being a leading environmental solutions company with a national presence and a dedicated focus on environmental solutions is a competitive advantage relative to smaller, regional companies, as well as companies that provide certain environmental services as ancillary offerings.

Seasonality

Our business divisions are impacted by seasonal factors. Generally, our business is negatively impacted during the winter months due to inclement weather, fewer daylight hours and holidays. During periods of heavy snow, ice or rain, we may be unable to move our trucks and equipment between locations, thereby reducing our ability to provide services and generate revenue. In addition, these conditions may impact our customers’ operations, and, as our customers’ drilling and/or hydraulic fracturing activities are curtailed, our services may also be reduced.

Intellectual Property

We operate under numerous trade names and own several trademarks, the most important of which are “Nuverra,” “HWR,” “Power Fuels,” and “Heckmann Water Resources.” We also have access, through certain exclusive and business relationships, to various water treatment technologies which, based on our experience, we utilize to create cost-effective and proprietary total water treatment solutions for our customers.

Operating Risks

Our operations are subject to hazards inherent in our industry, including accidents and fires that could cause personal injury or loss of life, damage to or destruction of property, equipment and the environment, suspension of operations and litigation, as described in Note 16 of the Notes to Consolidated Financial Statements herein, associated with these hazards. Because our business involves the transportation of environmentally regulated materials, we may also experience traffic accidents or pipeline breaks that may result in spills, property damage and personal injury. We have implemented a comprehensive HS&E program designed to minimize accidents in the workplace, enhance our safety programs, maintain environmental compliance and improve the efficiency of our operations.

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Discontinued Operations

Our industrial solutions division provides route-based environmental services and waste recycling solutions, offering customers a reliable, high-quality and environmentally responsible solution through our “one-stop shop” of collection and recycling services for waste products including used motor oil (“UMO”), oily water, spent antifreeze, used oil filters and parts washers. The industrial solutions division collects UMO and reprocesses it to be sold in the form of reprocessed fuel oil (“RFO”) to (i) refiners as a critical feedstock for the production of base lubricants and (ii) industrial customers as a lower cost, higher “BTU” alternative to diesel fuel. Our assets focused on servicing industrial end-markets include processing facilities, tanker trucks, vacuum trucks and trailers, and railcars. UMO volume is sourced from participants within the automotive service industry (e.g. quick lube shops, auto dealerships, retail automotive service providers, etc.) and a diverse array of commercial and industrial operations across the trucking, railroad, manufacturing and mining industries. We have established relationships with RFO customers located throughout the United States, typically consisting of re-refiners and energy-intensive industries that require the use of a boiler or furnace, such as the asphalt, pulp, paper and bunker fuel markets.

Following an assessment of various alternatives regarding our industrial solutions business in the third quarter of 2013 and a decision to focus exclusively on our shale solutions business, our board of directors approved and committed to a plan to divest Thermo Fluids Inc. ("TFI"), which comprises its industrial solutions operating and reportable segment, in the fourth quarter of 2013. In March 2014, we entered into a Stock Purchase Agreement with respect to the sale of 100% of the equity of TFI to a prospective acquirer in exchange for $165.0 million in cash and $10.0 million in stock. In June 2014, we entered into an Amended and Restated Stock Purchase Agreement which, among other items, extended the closing date of the transaction. In August 2014, the agreement was terminated pursuant to the terms of the agreement. Subsequent to the termination of the agreement, we engaged in negotiations with other potential acquirers. In September 2014, Nuverra entered into a non-binding letter of intent for the sale of TFI to a new prospective acquirer in exchange for a combination of cash and common stock of the acquirer. Definitive transaction documentation was not executed with the new prospective acquirer. On February 4, 2015, Nuverra entered into a definitive agreement with Safety-Kleen, Inc. ("Safety-Kleen"), a subsidiary of Clean Harbors, Inc., whereby Safety-Kleen will acquire TFI for $85 million in an all-cash transaction, subject to working capital adjustments. We currently expect the transaction to close promptly following receipt of required governmental approvals.

The February 4, 2015 definitive agreement for the proposed sale was for an amount that is below the carrying value of TFI's net assets. Based on the definitive agreement with Safety-Kleen, TFI recorded charges of approximately $74.4 million in the year ended December 31, 2014, reducing the estimated net recoverable value of its net assets to approximately $84.5 million at December 31, 2014. The charges were primarily related to a reduction of goodwill in the amount of $48.0 million, $26.4 million in intangible assets, as well as estimated additional transaction costs related to the sale.

We classified TFI as discontinued operations in its consolidated statements of operations for the years ended December 31, 2014, 2013 and 2012 (since its acquisition on April 10, 2012). The assets and liabilities related to TFI are presented separately as "Assets held for sale" and "Liabilities of discontinued operations" in our consolidated balance sheets at December 31, 2014 and December 31, 2013.

Governmental Regulation, including Environmental Regulation and Climate Change

Our operations are subject to stringent United States federal, state and local laws and regulations regulating the discharge of materials into the environment or otherwise relating to health and safety or the protection of the environment. Additional laws and regulations, or changes in the interpretations of existing laws and regulations, that affect our business and operations may be adopted, which may in turn impact our financial condition. The following is a summary of the more significant existing health, safety and environmental laws and regulations to which our operations are subject.

Hazardous Substances and Waste.

The United States Comprehensive Environmental Response, Compensation, and Liability Act, as amended, referred to as “CERCLA” or the “Superfund” law, and comparable state laws, impose liability without regard to fault or the legality of the original conduct on certain defined persons, including current and prior owners or operators of a site where a release of hazardous substances occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these “responsible persons” may be liable for the costs of cleaning up the hazardous substances, for damages to natural resources and for the costs of certain health studies.

In the course of our operations, we occasionally generate materials that are considered “hazardous substances” and, as a result, may incur CERCLA liability for cleanup costs. Also, claims may be filed for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants. We also generate solid wastes that are subject to the requirements of the United States Resource Conservation and Recovery Act, as amended, or “RCRA,” and comparable state statutes.

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Although we use operating and disposal practices that are standard in the industry, hydrocarbons or other wastes may have been released at properties owned or leased by us now or in the past, or at other locations where these hydrocarbons and wastes were taken for treatment or disposal. Under CERCLA, RCRA and analogous state laws, we could be required to clean up contaminated property (including contaminated groundwater), or to perform remedial activities to prevent future contamination.

Air Emissions.

The Clean Air Act, as amended, or “CAA,” and similar state laws and regulations restrict the emission of air pollutants and also impose various monitoring and reporting requirements. These laws and regulations may require us to obtain approvals or permits for construction, modification or operation of certain projects or facilities and may require use of emission controls.

Global Warming and Climate Change.

While we do not believe our operations raise climate change issues different from those generally raised by the commercial use of fossil fuels, legislation or regulatory programs that restrict greenhouse gas emissions in areas where we conduct business or that would require reducing emissions from our truck fleet could increase our costs.

Water Discharges.

We operate facilities that are subject to requirements of the United States Clean Water Act, as amended, or “CWA,” and analogous state laws for regulating discharges of pollutants into the waters of the United States and regulating quality standards for surface waters. Among other things, these laws impose restrictions and controls on the discharge of pollutants, including into navigable waters as well as protecting drinking water sources. Spill prevention, control and counter-measure requirements under the CWA require implementation of measures to help prevent the contamination of navigable waters in the event of a hydrocarbon spill. Other requirements for the prevention of spills are established under the United States Oil Pollution Act of 1990, as amended, or “OPA”, which amended the CWA and applies to owners and operators of vessels, including barges, offshore platforms and certain onshore facilities. Under OPA, regulated parties are strictly liable for oil spills and must establish and maintain evidence of financial responsibility sufficient to cover liabilities related to an oil spill for which such parties could be statutorily responsible.

Oil Pollution Act.

The United States Oil Pollution Act, as amended, or “OPA,” governs any facility that has the capacity to store more than 1,320 gallons of oil and/or petroleum products and has the potential to discharge to a “navigable water” of the United States. All of our industrial solutions facilities are subject to this regulation, which requires that each facility develop and maintain a Spill Prevention Control and Countermeasures Plan, or “SPCC.” The SPCC requires certain planning and training to minimize the potential for oil and/or other petroleum products to be released into a navigable waterway.

National Pollutant Discharge Elimination System.

Our industrial solutions division’s storm water discharges and waste water discharges are regulated by the National Pollutant Discharge Elimination System, or “NPDES,” permit program. Many of industrial solutions’ facilities are required to manage their storm water runoff according to a “Multi Sector General Permit” issued by the EPA or by a particular state, if the state has been delegated authority to administer the program. Under NPDES, our regulated facilities must maintain a Storm Water Pollution Prevention Plan that identifies certain best management practices to minimize the off-site impact of any pollutants that may be carried off-site by precipitation. Very few of our industrial solutions’ locations require specific waste water discharge permits from industrial processes.

State Environmental Regulations.

Our operations involve the storage, handling, transport and disposal of bulk waste materials, some of which contain oil, contaminants and other regulated substances. Various environmental laws and regulations require prevention, and where necessary, cleanup of spills and leaks of such materials and some of our operations must obtain permits that limit the discharge of materials. Failure to comply with such environmental requirements or permits may result in fines and penalties, remediation orders and revocation of permits. In Texas, we are subject to rules and regulations promulgated by the Texas Railroad Commission and the Texas Commission on Environmental Quality, including those designed to protect the environment and monitor compliance with water quality. In Louisiana, we are subject to rules and regulations promulgated by the Louisiana Department of Environmental Quality and the Louisiana Department of Natural Resources as to environmental and water quality issues, and the Louisiana Public Service Commission as to allocation of intrastate routes and territories for waste water transportation. In Pennsylvania, we are subject to the rules and regulations of the Pennsylvania Department of Environmental Protection and the Pennsylvania Public Service Commission. In Ohio, we are subject to the rules and regulations of the Ohio

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Department of Natural Resources and the Ohio Environmental Protection Agency. In North Dakota, we are subject to the rules and regulations of the North Dakota Department of Health, the North Dakota Industrial Commission, Oil and Gas Division, and the North Dakota State Water Commission. In Montana, we are subject to the rules and regulations of the Montana Department of Environmental Quality and the Montana Board of Oil and Gas.

In addition, industrial solutions’ operations involve the storage, handling, transport and disposal of bulk waste materials, some of which contain oil, contaminants and other regulated substances. Various state environmental laws and regulations require prevention, and where necessary, cleanup of spills and leaks of such materials and some of our operations must obtain permits that limit the discharge of materials. Failure to comply with such environmental requirements or permits may result in fines and penalties, remediation orders and revocation of permits. For example, in California, industrial solutions is subject to the Department of Toxic Substances Control, or “DTSC,” controls on the shipment and management of used oil. Industrial solutions has worked with the California DTSC to develop a testing and reporting agreement to assist transporters of used motor oil with meeting the state’s standard.

Occupational Safety and Health Act.

We are subject to the requirements of the United States Occupational Safety and Health Act, as amended, or “OSHA,” and comparable state laws that regulate the protection of employee health and safety. OSHA’s hazard communication standard requires that information about hazardous materials used or produced in our operations be maintained and provided to employees, state and local government authorities and citizens.

Saltwater Disposal Wells.

We operate saltwater disposal wells that are subject to the CWA, the Safe Drinking Water Act, or “SDWA,” and state and local laws and regulations, including those established by the Underground Injection Control Program of the United States Environmental Protection Agency, or “EPA,” which establishes minimum requirements for permitting, testing, monitoring, record keeping and reporting of injection well activities. All of our saltwater disposal wells are located in Ohio, Mississippi, Texas, North Dakota and Montana. Regulations in many states require us to obtain a permit to operate each of our saltwater disposal wells in those states. These regulatory agencies have the general authority to suspend or modify one or more of these permits if continued operation of one of our saltwater wells is likely to result in pollution of freshwater, substantial violation of permit conditions or applicable rules, or leaks to the environment. Any leakage from the subsurface portions of the saltwater wells could cause degradation of fresh groundwater resources, potentially resulting in cancellation of operations of a well, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource and claims by third parties for property damages and personal injuries.

Transportation Regulations.

We conduct interstate motor carrier (trucking) operations that are subject to federal regulation by the Federal Motor Carrier Safety Administration, or “FMCSA,” a unit within the United States Department of Transportation, or “USDOT.” The FMCSA publishes and enforces comprehensive trucking safety regulations, including rules on commercial driver licensing, controlled substance testing, medical and other qualifications for drivers, equipment maintenance, and drivers’ hours of service, referred to as “HOS.” The agency also performs certain functions relating to such matters as motor carrier registration (licensing), insurance, and extension of credit to motor carriers’ customers. Another unit within USDOT publishes and enforces regulations regarding the transportation of hazardous materials, or “hazmat,” but the waste water and other water flows we transport by truck are generally not regulated as hazmat at this time.

In December 2010, the FMCSA launched a program called Compliance, Safety, Accountability, or “CSA,” in an effort to improve commercial truck and bus safety. A component of CSA is the Safety Measurement System, or “SMS,” which analyzes all safety violations recorded by federal and state law enforcement personnel to determine a carrier’s safety performance. The SMS is intended to allow the FMCSA to identify carriers with safety issues and intervene to address those problems. Although our trucking operations currently hold a “Satisfactory” safety rating from FMCSA (the best rating available), the agency has announced a future intention to revise its safety rating system by making greater use of SMS data in lieu of on-site compliance audits of carriers. We cannot predict the effect such a revision may have on our safety rating.

Our intrastate trucking operations are also subject to various state environmental and waste water transportation regulations discussed under “Environmental Regulations” above. Federal law also allows states to impose insurance and safety requirements on motor carriers conducting intrastate business within their borders, and to collect a variety of taxes and fees on an apportioned basis reflecting miles actually operated within each state.

The HOS regulations establish the maximum number of hours that a commercial truck driver may work. A FMCSA rule reducing the number of hours a commercial truck driver may work each day became effective in February 2012 and the

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compliance date of selected provisions was July 1, 2013. The rule, which is intended to reduce the risk of fatigue and fatigue-related crashes and harm to driver health, prohibits a driver from driving if more than eight hours have passed since the driver’s last off-duty or sleeper berth break of at least 30 minutes and limits the use of the restart to once a week, which, on average, will cut the maximum work week from 82 to 70 hours. The effect of this rule on reduced driver hours may raise our operating costs.

In addition, the USDOT’s Pipeline and Hazardous Materials Safety Administration regulates the transportation of materials deemed to be hazardous while in transport. A small portion of the materials that industrial solutions transports are subject to these regulations, which require certain training and communication rules to ensure the safe transport of hazardous materials.

Hydraulic Fracturing.

Although we do not directly engage in hydraulic fracturing activities, certain of our shale solutions customers perform hydraulic fracturing operations. While we believe that the adoption of new federal and/or state laws or regulations imposing increased regulatory burdens on hydraulic fracturing could increase demand for our services, it is possible that it could harm our business by making it more difficult to complete, or potentially suspend or prohibit, crude oil and natural gas wells in shale formations, increasing our and our customers’ costs of compliance and adversely affecting the services that we provide for our customers.

Due at least in part to public concerns that have been raised regarding the potential impact of hydraulic fracturing on drinking water, the EPA has commenced a comprehensive study, at the order of the United States Congress, of the potential environmental and health impacts of hydraulic fracturing activities. A final draft assessment report is expected to be issued by the EPA for peer review and public comment in early 2015. On October 15, 2012, a rule promulgated by the EPA that established new air emission controls for crude oil and natural gas production and natural gas processing operations became effective. The rule includes New Source Performance Standards, or “NSPS,” to address emissions of sulfur dioxide and volatile organic compounds, or “VOCs,” and a separate set of emission standards to address hazardous air pollutants associated with oil and natural gas production and processing activities. The EPA’s final rule requires the reduction of VOC emissions from crude oil and natural gas production facilities by mandating the use of “green completions” for hydraulic fracturing, which requires the operator to recover rather than vent the gas and natural gas liquids that come to the surface during completion of the fracturing process.

Legislation, including bills known collectively as the Fracturing Responsibility and Awareness of Chemicals Act, or FRAC Act, has been introduced before both houses of Congress to remove the exemption of hydraulic fracturing under the SDWA and to require disclosure to a regulatory agency of chemicals used in the fracturing process and otherwise restrict hydraulic fracturing. To date, this legislation has not been passed by either house.

Various state, regional and local governments have implemented, or are considering, increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, disclosure requirements, and temporary or permanent bans on hydraulic fracturing in certain environmentally sensitive areas such as certain watersheds. The North Dakota Industrial Commission, Oil and Gas Division recently proposed regulations requiring owners, operators, and service companies to post the composition of the hydraulic fracturing fluid used during certain hydraulic fracturing stimulations on the FracFocus Chemical Disclosure Registry. The availability of information regarding the constituents of hydraulic fracturing fluids could potentially make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, North Dakota recently proposed regulations prohibiting the discharge of fluids, wastes, and debris other than drill cuttings into open pits.

Employees

As of December 31, 2014, we had approximately 2,400 full time employees, of whom approximately 400 were executive, managerial, sales, general, administrative, and accounting staff, and approximately 2,000 were truck drivers, service providers and field workers. None of our employees are under collective bargaining agreements. We believe that we maintain a satisfactory working relationship with our employees and we have not experienced any significant labor disputes.

Available Information

Information that we file with or furnish to the SEC, including our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to or exhibits included in these reports, are available free of charge on our website at www.nuverra.com soon after such reports are filed with or furnished to the SEC. From time to time, we also post announcements, updates, events, investor information and presentations on our website in addition to copies of all recent press releases. Our reports, including any exhibits included in such reports, that are filed with or furnished to the SEC are also available on the SEC’s website at www.sec.gov. You may also read and copy any materials we file with or furnish to the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Room 1580, Washington, D.C. 20549; information on the operation of

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the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. You may request copies of these documents from the SEC, upon payment of a duplicating fee, by writing to the SEC at its principal office at 100 F Street, NE, Room 1580, and Washington, D.C. 20549.

Neither the contents of our website nor that maintained by the SEC are incorporated into or otherwise a part of this filing. Further, references to the URLs for these websites are intended to be inactive textual references only.



ITEM 1A.	Risk Factors

This section describes material risks to our businesses that currently are known to us. You should carefully consider the risks described below. If any of the risks and uncertainties described in the cautionary factors described below actually occurs, our business, financial condition and results of operations could be materially and adversely affected. The risks and factors listed below, however, are not exhaustive. Other sections of this Annual Report on Form 10-K include additional factors that could materially and adversely impact our business, financial condition and results of operations. Moreover, we operate in a rapidly changing environment. Other known risks that we currently believe to be immaterial could become material in the future. We also are subject to legal and regulatory changes. New factors emerge from time to time and it is not possible to predict the impact of all these factors on our business, financial condition or results of operations.

Risks Related to Our Company

Our business depends on spending by the oil and natural gas industry in the United States, and this spending and our business has been, and may continue to be, adversely affected by industry and financial market conditions that are beyond our control. A substantial or an extended decline in oil and natural gas prices could result in lower expenditures by our customers, which could have a material adverse effect on our financial condition, results of operations and cash flows.

We depend on our customers’ willingness to make operating and capital expenditures to explore, develop and produce oil and natural gas in the United States. These expenditures are generally dependent on current oil and natural gas prices and the industry’s view of future oil and natural gas prices, including the industry’s view of future economic growth and the resulting impact on demand for oil and natural gas. Recent declines in oil and natural gas prices, and any substantial or extended decline in oil and natural gas prices, could result in reductions in our customers’ operating and capital expenditures. Declines in these expenditures could result in project modifications, delays or cancellations, general business disruptions, delays in, or nonpayment of, amounts owed to us, increased exposure to credit risk and bad debts, and a general reduction in demand for our services. These effects could have a material adverse effect on our financial condition, results of operations and cash flows.

Industry conditions are influenced by numerous factors over which we have no control, including:


•	the domestic and worldwide price and supply of natural gas, natural gas liquids and oil, including the natural gas inventories and oil reserves of the United States;


•	changes in the level of consumer demand;


•	the price and availability of alternative fuels;


•	weather conditions;


•	the availability, proximity and capacity of pipelines, other transportation facilities and processing facilities;


•	the level and effect of trading in commodity futures markets, including by commodity price speculators and others;


•	the nature and extent of domestic and foreign governmental regulations and taxes;


•	actions of the members of the Organization of the Petroleum Exporting Countries or "OPEC," relating to oil price and production controls;


•	the level of excess production and projected rates of production growth;


•	political instability or armed conflict in oil and natural gas producing regions; and


•	overall domestic and global economic and market conditions.

The oil and gas industry is currently experiencing a downturn due to significant declines in oil and natural gas prices. Since the second half of 2014, oil prices have declined substantially from historic highs and may remain depressed for the foreseeable

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future. Historically, downturns in the industry have been characterized by diminished demand for oilfield services and downward pressure on the prices customers are willing to pay for services such as ours. An extended downturn in the oil and gas industry could result in a reduction in demand for oilfield services as well as lower prices and operating margins, and could adversely affect our financial condition, results of operations and cash flows.

In the past, we have experienced periods of low demand and have incurred operating losses. In the future, we may not be able to achieve or maintain our profitability due to an inability to reduce costs, increase revenue, or reduce our debt obligations. Under such circumstances, we may incur further operating losses and experience negative operating cash flow.

Future charges due to possible impairments of assets may have a material adverse effect on our results of operations and stock price.

As discussed more fully in Note 8 of the Notes to Consolidated Financial Statements and “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Impairment of Long-Lived Assets and Goodwill” included in Item 7 herein, during the year ended December 31, 2014 we recorded asset impairments totaling $416.4 million, including $112.4 million for the impairment of long-lived assets and $304.0 million for the impairment of goodwill. Additionally, as discussed in Note 20, we recorded asset impairments totaling $74.4 million during the year ended December 31, 2014 as a component of "Loss from discontinued operations, net of income taxes" in our consolidated statement of operations. If there is further deterioration in our business operations or prospects, our stock price, the broader economy or our industry, including further declines in oil and natural gas prices, the value of our long-lived assets and goodwill, or those we may acquire in the future, could decrease significantly and result in additional impairment and financial statement write-offs.

The testing of long-lived assets and goodwill for impairment requires us to make significant estimates about our future performance and cash flows, as well as other assumptions. These estimates can be affected by numerous factors, including changes in the composition of our reporting units; changes in economic, industry or market conditions; changes in business operations; changes in competition; changes in goodwill; or potential changes in the share price of our common stock and market capitalization. Changes in these factors, or differences in our actual performance compared with estimates of our future performance, could affect the fair value of long-lived assets and goodwill, which may result in further impairment charges. We perform the assessment of potential impairment at least annually, or more often if events and circumstances require.

During the three months ended September 30, 2014, we completed the previously-announced organizational realignment of our shale solutions segment into three operating divisions, which we consider to be our new operating and reportable segments: (1) the Northeast Division comprising the Marcellus and Utica Shale areas, (2) the Southern Division comprising the Haynesville, Eagle Ford, Mississippian and Permian Basin Shale areas and (3) the Rocky Mountain Division comprising the Bakken Shale area. As part of this organizational realignment, we re-evaluated the goodwill of our reporting units, defined as an operating segment or one level below an operating segment, for impairment. We determined that our reporting units are the same as our new operating and reportable segments. Previously, the shale solutions operating segment was comprised of the shale solutions (excluding AWS and Pipeline) reporting unit, the AWS reporting unit and the Pipeline reporting unit. Given the change in the composition of its reporting units, we were required to allocate our $408.7 million of goodwill on a relative fair value basis to the new reporting units.

In addition to the annual goodwill impairment test performed as of September 30, we test our goodwill and long-lived assets, including other identifiable intangible assets with useful lives, for impairment if and when events or changes in circumstances indicate that the carrying value of goodwill and/or long-lived assets may not be recoverable. During the quarter ended June 30, 2014, we considered a number of relevant factors which are potential indicators of impairment, including (among others) the potential impacts of the aforementioned organizational realignment of its continuing operations and our current and near-term financial results as well as the fact that the market price of our common stock, taking into consideration potential control premiums, has wavered above and below our book value since the third quarter of 2013, as previously disclosed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2013 and subsequent Quarterly Reports on Form 10-Q. Based on these factors, we were required to perform impairment tests to determine whether the carrying values are fully recoverable of both our long-lived assets and goodwill. We completed the review of our long-lived assets in the quarter ended September 30, 2014 and concluded the fair value of such assets exceeded their carrying values, thus no long-lived asset impairment was indicated.

The goodwill impairment test has two steps. The first step of the goodwill impairment test, used to identify potential impairment, compares the fair value of a reporting unit with its carrying amount including goodwill. During the three months ended September 30, 2014, we performed step one of the goodwill impairment test for each of our three new reporting units: the Northeast division, Southern division and Rocky Mountain division. To measure the fair value of each new reporting unit, we used a combination of the discounted cash flow method and the guideline public company method. Based

on the results of the step-one goodwill impairment review, we concluded the fair value of the Rocky Mountain

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division exceeded our carrying amount by approximately 14% and accordingly, the second step of the impairment test was not

necessary for this reporting unit. Conversely, we concluded the fair value of the Northeast and Southern reporting units were less than their carrying values thereby requiring us to proceed to the second step of the goodwill impairment test. The second step of the goodwill impairment test, used to measure the amount of the impairment loss, compares the implied fair value of the reporting unit goodwill with its carrying amount. For both the Northeast and Southern reporting units, the carrying values of the re-allocated goodwill exceeded their implied fair values. Accordingly, we recognized a charge of $100.7 million ($66.9 million in the Southern division and $33.8 million in the Northeast division) during the three months ended September 30, 2014, which is characterized as "Impairment of goodwill" in our consolidated statement of operations.

Due to the continued significant decline in oil and gas prices and the market price of our common stock during the three months ended December 31, 2014, we determined that these triggering events required us to complete further impairment tests. Long-lived assets were grouped at the basin level for purposes of assessing their recoverability as we concluded the basin level is the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. In the Northeast division and Southern divisions, the undiscounted cash flows of the asset groups exceeded their carrying values; therefore, no impairment was indicated. In the Bakken Shale basin, the carrying value of the asset group exceeded its undiscounted cash flows indicating impairment which resulted in an impairment charge of $112.4 million related to the customer relationship intangible asset. Such amount is reported in "Impairment of long-lived assets" in our consolidated statement of operations. The Northeast division and Southern divisions had no goodwill balances; therefore, we performed step one of the goodwill impairment test only for the Rocky Mountain division. The Rocky Mountain division is comprised of the Rocky Mountain reporting unit. We used a combination of the discounted cash flow method and the guideline public company method to measure the fair value of the Rocky Mountain reporting unit. Based on the results of the step-one goodwill impairment review, we concluded the fair value of the Rocky Mountain division was less than its carrying value thereby requiring us to proceed to the second step of the goodwill impairment test. The second step of the goodwill impairment test, used to measure the amount of the impairment loss, compares the implied fair value of the reporting unit goodwill with its carrying amount. The carrying value of the Rocky Mountain reporting unit goodwill exceeded its implied fair value and as such, we recognized a charge of $203.3 million during the three months ended December 31, 2014, which is characterized as "Impairment of goodwill" in our consolidated statement of operations.

The fair values of each of the reporting units as well as the related assets and liabilities utilized to determine the 2014 impairment were measured using Level 2 and Level 3 inputs as described in Note 11.

We believe the assumptions used in our discounted cash flow analysis are appropriate and result in reasonable estimates of the implied fair value of each reporting unit. We further believe the most significant assumption used in our analysis is the revenue growth as limited by oil and gas prices. However, we may not meet our revenue targets, working capital and capital investment requirements may be higher than forecast, changes in credit or equity markets may result in changes to our discount rate and general business conditions may result in changes to our terminal value assumptions for our reporting units.

In evaluating the reasonableness of our fair value estimates, we consider (among other factors) the relationship between our book value, the market price of our common stock and the fair value of our reporting units. At December 31, 2014 and March 13, 2015, the closing market prices of our common stock were $5.55 and $2.92 per share, respectively, compared to our book value per share of $5.56 as of December 31, 2014. If our book value per share were to continue to exceed our market price per share plus a control premium, in addition to continued downward pricing in services driven by oil and gas price depression, it would likely indicate the occurrence of events or changes that would cause us to perform additional impairment analyses which could result in further revisions to our fair value estimates. While we believe that our estimates of fair value are reasonable, we will continue to monitor and evaluate this relationship. Additionally, should actual results differ materially from our projections, additional impairment would likely result.

Should the value of our long-lived assets and goodwill become further impaired, we would incur additional charges which could have a material adverse effect on our consolidated results of operations and could result in us incurring additional net operating losses in future periods. We cannot accurately predict the amount or timing of any impairment of assets. Any future determination requiring the write-off of a significant portion of long-lived assets or goodwill, although not requiring any additional cash outlay, could have a material adverse effect on our results of operations and stock price.

We may not recognize the anticipated benefits from our sale of the industrial solutions division or any other divestitures we may pursue in the future.

As described in Note 20 of the Notes to Consolidated Financial Statements herein, in October 2013, our Board of Directors authorized commencement of a process for the sale of TFI, comprising our industrial solutions division. As disclosed on a Form 8-K filed with Securities and Exchange Commission on February 4, 2015, we entered into a material definitive agreement with Safety-Kleen pursuant to which Safety-Kleen will purchase TFI. There can be no assurance that we will be able to obtain the

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requisite government approvals and successfully close the sale of TFI. Additionally, we may evaluate other potential divestiture opportunities with respect to portions of our business from time to time, and may determine to proceed with a divestiture opportunity if and when we believe such opportunity is consistent with our business strategy and we would be able to realize value for our stockholders in so doing. Any divestiture, including the planned sale of TFI, could expose us to significant risks, including, without limitation, fees for legal and transaction-related services, diversion of management resources, transaction execution risks (including risks resulting from buyer financing and due diligence contingencies and other closing conditions), loss of key personnel and reduction in revenue. Further, as contemplated in the definitive agreement relating to the sale of TFI, we may be required to retain or indemnify a buyer against certain liabilities and obligations in connection with any such divestiture, and we may also become subject to third-party claims arising out of such divestiture. In addition, we may not achieve the expected price in such a transaction, which could result in additional losses being recorded. If we do not realize the expected strategic, economic or other benefits of any divestiture transaction, it could adversely affect our financial condition and results of operations. The sale of TFI is subject to various third party consents. There can be no assurances that we will obtain any necessary consents of governmental authorities or other third parties, including consent of the lenders under our credit facility that might be required in order for us to sell TFI or effectuate any other divesture. The expected sale of TFI will take the form of a stock sale of TFI rather than a sale of TFI’s assets which will result in a significant capital loss for tax purposes. The goodwill impairment charges recorded during the years ended December 31, 2014 and 2013 did not result in a reduction of our tax basis in the stock of TFI. We will not be able to carry any recognized capital loss resulting from a sale of TFI stock back to prior years as we did not generate capital gains nor pay any federal tax during such prior carryback years. We also do not currently expect to have significant capital gains in the five succeeding carryforward tax years to offset the capital loss carryforward. Consequently, we expect that any deferred tax asset resulting from a capital loss generated from the sale of TFI stock will require a valuation allowance.

If we are unable to consummate the divestiture of TFI for any reason, our business would be adversely impacted, including our cash flows, and, in addition, we would be subject to the risks associated with the continued operation of TFI’s business, including (without limitation) operational, financial, legal, environmental and regulatory and compliance risks, any or all of which could be material to our business.

We may not be able to grow successfully through future acquisitions or successfully manage future growth, and we may not be able to effectively integrate the businesses we do acquire.

We have historically grown through strategic acquisitions of other businesses. We may not be able to continue to identify attractive acquisition opportunities or successfully acquire those opportunities identified. In order to complete acquisitions, we would expect to require additional debt and/or equity financing, which could increase our interest expense, leverage and/or shares outstanding (see "Risks Related to Our Indebtedness"). Businesses that we acquire, or have previously acquired, may not perform as expected. Future revenues, profits and cash flows of an acquired business may not materialize due to the failure or inability to capture expected synergies, increased competition, regulatory issues, changes in market conditions, or other factors beyond our control. In addition, we may not be successful in integrating future acquisitions into our existing operations, which may result in unforeseen operational difficulties or diminished financial performance or require a disproportionate amount of our management’s attention.

Even if we are successful in integrating our current or future acquisitions into our existing operations, we may not derive the benefits, such as operational or administrative synergies or earnings gains, that we expected from such acquisitions, which may result in the commitment of our capital resources without the expected returns on such capital. Also, competition for acquisition opportunities may escalate, increasing our cost of making further acquisitions or causing us to refrain from making additional acquisitions. These effects could have a material adverse effect on our financial condition, results of operations and cash flows.

Additional risks related to acquisitions include, but are not limited to:


•	the potential disruption of our existing businesses;


•	entering new markets or industries in which we have limited prior experience;


•	difficulties integrating and retaining key management, sales, research and development, production and other personnel or diversion of management attention from ongoing business concerns to integration matters;


•	difficulties integrating or expanding information technology systems and other business processes or administrative infrastructures to accommodate the acquired businesses;


•	complexities associated with managing the combined businesses and consolidating multiple physical locations;


•	risks associated with integrating financial reporting and internal control systems; and

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•	whether any necessary additional debt or equity financing will be available on terms acceptable to us, or at all, and the impact of such financing on our operating performance and results of operations.

We depend on the continued service of Mark D. Johnsrud, our Chief Executive Officer and Chairman, and other senior management.

Our success is largely dependent on the skills, experience and efforts of our people and, in particular, the continued services of Mr. Johnsrud, our Chief Executive Officer and Chairman. The loss of the services of Mr. Johnsrud, or of other members of our senior management, could have a negative effect on our business, financial condition and results of operations and future growth, as we may not be able to find suitable individuals to replace them on a timely basis, if at all. In addition, any such departure could be viewed in a negative light by investors and analysts, which may cause the price of our common stock to decline. We do not carry key-person life insurance on any of our senior management.

Our Chief Executive Officer and Chairman, Mark D. Johnsrud, owns a significant amount of our voting stock and may have interests that differ from other shareholders. Mr. Johnsrud, as a significant shareholder, may, therefore, take actions that are not in the interest of other shareholders.

Mark D. Johnsrud, Chief Executive Officer and Chairman, owns shares representing approximately 37% of our common stock as of December 31, 2014, and, therefore, he has significant control on the outcome of matters submitted to a vote of shareholders, including, but not limited to, electing directors, adopting amendments to our certificate of incorporation and approving corporate transactions. In addition, Mr. Johnsrud, as Chief Executive Officer and Chairman, has the power to exert significant influence over our corporate management and policies. Circumstances may occur in which the interests of Mr. Johnsrud, as a significant shareholder, could be in conflict with the interests of other shareholders, and Mr. Johnsrud would have significant influence to cause us to take actions that align with his interests. Should conflicts of interest arise, we can provide no assurance that Mr. Johnsrud would act in the best interests of our other shareholders or that any conflicts of interest would be resolved in a manner favorable to our other shareholders.

The litigation environment in which we operate poses a significant risk to our businesses.

We are involved in the ordinary course of business in a number of lawsuits involving employment, commercial, and environmental issues, other claims for injuries and damages, and various shareholder and class action litigation, among other matters. We may experience negative outcomes in such lawsuits in the future. Any such negative outcomes could have a material adverse effect on our business, liquidity, financial condition and results of operations. We evaluate litigation claims and legal proceedings to assess the likelihood of unfavorable outcomes and to estimate, if possible, the amount of potential losses. Based on these assessments and estimates, we establish reserves and disclose the relevant litigation claims or legal proceedings, as appropriate. These assessments and estimates are based on the information available to management at the time and involve a significant amount of judgment. Actual outcomes or losses may differ materially from such assessments and estimates. The settlement or resolution of such claims or proceedings may have a material adverse effect on our results of operations. In addition, judges and juries in certain jurisdictions in which we conduct business have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage and other tort cases. We use appropriate means to contest litigation threatened or filed against us, but the litigation environment in these areas poses a significant business risk to us and could cause a significant diversion of management resources and could have a material adverse effect on our financial condition, results of operations and cash flows.

Litigation related to personal injury from the operation of our business may result in significant liabilities and limit our profitability.

The hazards and risks associated with the transport, storage, and handling, treatment and disposal of our customers’ waste (such as fires, spills, explosions and accidents) may expose us to personal injury claims, property damage claims and/or products liability claims from our customers or third parties. As protection against such claims and operating hazards, we maintain insurance coverage against some, but not all, potential losses. However, we may sustain losses for uninsurable or uninsured risks, or in amounts in excess of existing insurance coverage. As more fully described in Note 16 of the Notes to Consolidated Financial Statements herein, due to the unpredictable nature of personal injury litigation, it is not possible to predict the ultimate outcome of these claims and lawsuits, and we may be held liable for significant personal injury or damage to property or third parties, or other losses, that are not fully covered by our insurance, which could have a material adverse effect on our financial condition, results of operations and cash flows.

Significant capital expenditures are required to conduct our business.

The development of our business and services, excluding acquisition activities, requires substantial capital expenditures. During the year ended December 31, 2014, we made capital expenditures of approximately $55.7 million, primarily involving the

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completion of construction of the initial cells of our oilfield waste landfill in the Bakken Shale area and construction and development costs relating to our solids treatment capabilities, also in the Bakken Shale area. We continue to focus on improving the utilization of our existing assets and optimizing the allocation of resources in the various shale areas in which we operate. Our capital expenditure program is subject to market conditions, including customer activity levels, commodity prices, industry capacity and specific customer needs. In addition to capital expenditures required to maintain our current level of business activity, we may incur capital expenditures to support future growth of our business. We may also incur additional capital expenditures for acquisitions. We currently plan to reduce our level of capital expenditures for 2015, due in part to the ongoing declines in oil and natural gas prices and the corresponding effect on the oil and natural gas industry. Prolonged reductions or delays in capital expenditures could delay or diminish future cash flows and adversely affect our business and results of operations. Our planned capital expenditures for 2015, as well as any acquisitions we choose to pursue, will likely be financed through a combination of existing asset sales, cash on hand, cash flow from operations, borrowings under our available credit facilities and capital leases, and, in the case of larger acquisitions, possible issuances of new debt and/or equity. We may also incur additional indebtedness to support growth initiatives. Future cash flows from operations are subject to a number of risks and variables, such as the level of drilling activity and oil and natural gas production of our customers, prices of natural gas and oil, and the other risk factors discussed herein. Our ability to obtain capital from other sources, such as the capital markets, is dependent upon many of those same factors as well as the orderly functioning of credit and capital markets. To the extent we fail to have adequate funds, we could be required to reduce or defer our capital spending, or pursue other funding alternatives which may not be as economically attractive to us, which in turn could have a materially adverse effect on our financial condition, results of operations and cash flows.

The compensation we offer our drivers is subject to market conditions, and we may find it necessary to increase driver compensation and/or modify the benefits provided to our employees in future periods.

We employed approximately 1,300 truck drivers as of December 31, 2014. Maintaining a staff of qualified truck drivers is critical to the success of our operations. We and other companies in the oil and gas industry suffer from a high turnover rate of drivers. The high turnover rate requires us to continually recruit a substantial number of drivers in order to operate existing equipment. If we are unable to continue to attract and retain a sufficient number of qualified drivers, we could be forced to, among other things, increase driver compensation and/or modify our benefit packages, or operate with fewer trucks and face difficulty meeting customer demands, any of which could adversely affect our growth and profitability. Additionally, in anticipation of or in response to geographical and market-related fluctuations in the demand for our services, we strategically relocate our equipment and personnel from one area to another, which may result in operating inefficiencies, increased labor, fuel and other operating costs and could adversely affect our growth and profitability. As a result, our driver and employee training and orientation costs could be negatively impacted. We also utilize the services of independent contractor truck drivers to supplement our trucking capacity in certain shale areas on an as-needed basis. There can be no assurance that we will be able to enter into these types of arrangements on favorable terms, or that there will be sufficient qualified independent contractors available to meet our needs, which could have a material adverse effect on our financial condition, results of operations and cash flows.

In addition, the supply of critical infrastructure assets, in particular employee housing in the Bakken Shale area, is limited. There is a shortage of fixed housing in the region, making it difficult for energy services operators and other businesses to attract quality, long-term personnel. Through an entity he controls, but which is separate from the Company, Mr. Johnsrud owns fixed-housing rental units in the Bakken Shale area. However, there is no formal arrangement with Mr. Johnsrud to ensure that our employees will be able to rent this housing. There can be no assurance that there will be sufficient housing available for all of our employees in the Bakken Shale area, which could have a material adverse impact on our business and our ability to provide services.

We depend on certain key customers for a significant portion of our revenues. The loss of any of these key customers or the loss of any contracted volumes could result in a decline in our business.

We rely on a limited number of customers for a significant portion of our revenues. Our three largest customers represented 15%, 10% and 10%, respectively, of our total consolidated revenues for the year ended December 31, 2014 and in total equaled 30% of the Company’s consolidated accounts receivable at December 31, 2014. The loss of all, or even a portion, of the revenues from these customers, as a result of competition, market conditions or otherwise, could have a material adverse effect on our business, results of operations, financial condition, and cash flows. A reduction in exploration, development and production activities by key customers due to the current declines in oil and natural gas prices, or otherwise, could have a material adverse effect on our financial condition, results of operations and cash flows.

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Customer payment delays of outstanding receivables could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.

We often provide credit to our customers for our services, and are therefore subject to our customers delaying or failing to pay outstanding invoices. In weak economic environments, customers’ delays and failures to pay often increase due to, among other reasons, a reduction in our customers’ cash flow from operations and their access to credit markets. If our customers delay or fail to pay a significant amount of outstanding receivables, it could have a material adverse effect on our liquidity, financial condition, results of operations and cash flows.

The fees charged to customers under our agreements with them may not escalate sufficiently to cover increases in costs and the agreements may be suspended in some circumstances, which would affect our profitability.

Under our agreements with our customers, we may be unable to increase the fees that we charge our customers at a rate sufficient to offset any increases in our costs. Additionally, some customers’ obligations under their agreements with us may be permanently or temporarily reduced upon the occurrence of certain events, some of which are beyond our control, including force majeure events. Force majeure events may include (but are not limited to) events such as revolutions, wars, acts of enemies, embargoes, import or export restrictions, strikes, lockouts, fires, storms, floods, acts of God, explosions, mechanical or physical failures of our equipment or facilities of our customers. If the escalation of fees is insufficient to cover increased costs or if any customer suspends or terminates its contracts with us, the effects could have a material adverse effect on our financial condition, results of operations and cash flows.

We operate in competitive markets, and there can be no certainty that we will maintain our current customers or attract new customers or that our operating margins will not be impacted by competition.

The industries in which our business operates are highly competitive. We compete with numerous local and regional companies of varying sizes and financial resources. Competition could intensify in the future. Furthermore, numerous well-established companies are focusing significant resources on providing similar services to those that we provide that will compete with our services. We cannot assure you that we will be able to effectively compete with these other companies or that competitive pressures, including possible downward pressure on the prices we charge for our products and services, will not arise. In addition, the current declines in oil and natural gas prices may result in competitors moving resources from higher-cost exploration and production areas to relatively lower-cost exploration and production areas where we are located thereby increasing supply and putting further downward pressure on the prices we can charge for our products and services, including our rental business. In the event that we cannot effectively compete on a continuing basis, or competitive pressures arise, such inability to compete or competitive pressures could have a material adverse effect on our financial condition, results of operations and cash flows.

Any interruption in our services due to pipeline ruptures or spills or necessary maintenance could impair our financial performance and negatively affect our brand.

Our water transport pipelines are susceptible to ruptures and spills, particularly during start up and initial operation, and require ongoing inspection and maintenance. For example, in 2010 and 2011, we had breaks in our 50-mile underground pipeline network in the Haynesville Shale area that resulted in delays in transporting our customers’ water and resulted in significant repair and remediation costs. We may experience further difficulties in maintaining the operation of our pipelines, which may cause downtime and delays. We also may be required to periodically shut down all or part of our pipelines for regulatory compliance and inspection purposes. Any interruption in our services due to pipeline breakdowns or necessary maintenance, inspection or regulatory compliance could reduce revenues and earnings and result in remediation costs. Transportation interruptions at our pipelines, even if only temporary, could severely harm our business and reputation, and could have a material adverse effect on our financial condition, results of operations and cash flows.

Our operations are subject to risks inherent in the oil and natural gas industry, some of which are beyond our control. These risks may not be fully covered under our insurance policies.

Our operations are subject to operational hazards, including accidents or equipment failures that can cause pollution and other damage to the environment. Pursuant to applicable law, we may be required to remediate the environmental impact of any such accidents or incidents, which may include costs related to site investigation and soil, groundwater and surface water cleanup. In addition, hazards inherent in the oil and natural gas industry, such as, but not limited to, accidents, blowouts, explosions, pollution and other damage to the environment, fires and hydrocarbon spills, may delay or halt operations at extraction sites which we service. These conditions can cause:


•	personal injury or loss of life;

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•	liabilities from pipeline breaks and accidents by our fleet of trucks and other equipment;


•	damage to or destruction of property, equipment and the environment; and


•	the suspension of operations.

The occurrence of a significant event or a series of events that together are significant, or adverse claims in excess of the insurance coverage that we maintain or that are not covered by insurance, could have a material adverse effect on our financial condition, results of operations and cash flows. Litigation arising from a catastrophic occurrence at a location where our equipment and services are being used may result in our being named as a defendant in lawsuits asserting large claims.

We maintain insurance coverage that we believe to be customary in the industry against these hazards. We may not be able to maintain adequate insurance in the future at rates we consider reasonable. In addition, insurance may not be available to cover any or all of the risks to which we are subject, or, even if available, the coverage provided by such insurance may be inadequate, or insurance premiums or other costs could make such insurance prohibitively expensive. It is likely that, in our insurance renewals, our premiums and deductibles will be higher, and certain insurance coverage either will be unavailable or considerably more expensive than it has been in the past. In addition, our insurance is subject to coverage limits, and some policies exclude coverage for damages resulting from environmental contamination.

Improvements in or new discoveries of alternative energy technologies or fracking methodologies could have a material adverse effect on our financial condition and results of operations.

Because our business depends on the level of activity in the oil and natural gas industry, any improvement in or new discoveries of alternative energy technologies (such as wind, solar, geothermal, fuel cells and biofuels) that increase the use of alternative forms of energy and reduce the demand for oil and natural gas could have a material adverse effect on our financial condition, results of operations and cash flows. In addition, technological changes could decrease the quantities of water required for fracking operations or otherwise affect demand for our services.

Seasonal weather conditions and natural disasters could severely disrupt normal operations and harm our business.

Areas in which we operate are adversely affected by seasonal weather conditions, primarily in the winter and spring. During periods of heavy snow, ice or rain, our customers may curtail their operations or we may be unable to move our trucks between locations or provide other services, thereby reducing demand for, or our ability to provide services and generate revenues. For example, many municipalities impose weight restrictions on the roads that lead to our customers’ job sites in the spring due to the muddy conditions caused by spring thaws, limiting our access and our ability to provide service in these areas. In 2013 and the first quarter of 2014, inclement weather negatively impacted our operations in Pennsylvania and North Dakota. In September 2011 and October 2012, portions of Pennsylvania and other areas in the eastern United States had record rainfall and flooding. In February 2011, portions of Texas had record snowfalls. During those periods, we and our customers had to significantly reduce or halt operations, resulting in a loss of revenue. In addition, the regions in which we operate have in the past been, and may in the future be, affected by natural disasters such as hurricanes, windstorms, floods and tornadoes. In certain areas, our business may be dependent on our customers’ ability to access sufficient water supplies to support their hydraulic fracturing operations. To the extent severe drought conditions or other factors prevent our customers from accessing adequate water supplies, our business could be negatively impacted. Future natural disasters or inclement weather conditions could severely disrupt the normal operation of our business, or our customers’ business, and have a material adverse effect on our financial condition, results of operations and cash flows.

Our operating margins and profitability may be negatively impacted by changes in fuel and energy costs, in part due to the fixed cost structure of our business.

Our business is dependent on availability of fuel for operating our fleet of trucks. Changes and volatility in the price of crude oil can adversely impact the prices for these products and therefore affect our operating results. The price and supply of fuel is unpredictable and fluctuates based on events beyond our control, including geopolitical developments, supply and demand for oil and gas, actions by OPEC and other oil and gas producers, war and unrest in oil producing countries, regional production patterns, and environmental concerns.

Furthermore, our facilities, fleet and personnel subject us to fixed costs, which make our margins and earnings sensitive to changes in revenues. In periods of declining demand, our fixed cost structure may limit our ability to cut costs, which may put us at a competitive disadvantage to firms with lower or more flexible cost structures, and may result in reduced operating margins and/or higher operating losses. These effects could have a material adverse effect on our financial condition, results of operations and cash flows.

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Our financial and operating performance may be affected by the inability to renew landfill operating permits, obtain new landfills and expand existing ones.

We currently own one landfill and our ability to meet our financial and operating objectives may depend, in part, on our ability to acquire, lease, or renew landfill operating permits, expand existing landfills and develop new landfill sites. It has become increasingly difficult and expensive to obtain required permits and approvals to build, operate and expand solid waste management facilities, including landfills. Operating permits for landfills in states where we operate must generally be renewed every five to ten years, although some permits are required to be renewed more frequently. These operating permits often must be renewed several times during the permitted life of a landfill. The permit and approval process is often time consuming, requires numerous hearings and compliance with zoning, environmental and other requirements, is frequently challenged by special interest and other groups, and may result in the denial of a permit or renewal, the award of a permit or renewal for a shorter duration than we believed was otherwise required by law, or burdensome terms and conditions being imposed on our operations. We may not be able to obtain new landfill sites or expand the permitted capacity of our landfills when necessary. Any of these circumstances could have a material adverse effect on our financial condition, results of operations and cash flows.

Our ability to utilize net operating loss carryforwards in the future may be subject to substantial limitations.

We believe that our ability to use our U.S. federal net operating loss carryforwards and other tax attributes in future years could be limited. Internal Revenue Code Sections 382 and 383 provide annual limitations with respect to the ability of a corporation to utilize its net operating loss (as well as certain built-in losses) and tax credit carryforwards, respectively (“Tax Attributes”), against future U.S. taxable income, if the corporation experiences an “ownership change.” In general terms, an ownership change may result from transactions increasing the ownership of certain stockholders in the stock of a corporation by more than 50 percentage points over a three-year period. A future transaction or transactions and the timing of such transaction or transactions could trigger an ownership change under Section 382. As a result of an ownership change, utilization of our Tax Attributes would be subject to an overall annual limitation determined in part by multiplying the total adjusted aggregate market value of our common stock immediately preceding the ownership change by the applicable long-term tax-exempt rate, possibly subject to increase based on the built-in gain, if any, in our assets at the time of the ownership change. Any unused annual limitation may be carried over to later years. If an ownership change were to occur, future U.S. taxable income may not be fully offset by existing Tax Attributes in a given year if such income exceeds our annual limitation, resulting in higher cash taxes. Additionally, a Section 382 limitation could result in Tax Attributes expiring unused.

We are self-insured against many potential liabilities, and our reserves may not be sufficient to cover future claims.

We maintain high deductible or self-insured retention insurance policies for certain exposures including automobile, workers’ compensation and employee group health insurance. We carry policies for certain types of claims to provide excess coverage beyond the underlying policies and per incident deductibles or self-insured retentions. Because many claims against us do not exceed the deductibles under our insurance policies, we are effectively self-insured for a substantial portion of our claims. Our insurance accruals are based on claims filed and estimates of claims incurred but not reported. The insurance accruals are influenced by our past claims experience factors, which have a limited history, and by published industry development factors. The estimates inherent in these accruals are determined using actuarial methods that are widely used and accepted in the insurance industry. If our insurance claims increase or if costs exceed our estimates of insurance liabilities, we could experience a decline in profitability and liquidity, which would adversely affect our business, financial condition or results of operations. In addition, should there be a loss or adverse judgment or other decision in an area for which we are self-insured, then our business, financial condition, results of operations and liquidity may be adversely affected.

We evaluate our insurance accruals, and the underlying assumptions, regularly throughout the year and make adjustments as needed. While we believe that the recorded amounts are reasonable, there can be no assurance that changes to our estimates will not occur due to limitations inherent in the estimation process. Changes in our assumptions and estimates could have a material adverse effect on our financial condition, results of operations and cash flows.

Security breaches and other disruptions could compromise our information and expose us to liability, which would cause our business and reputation to suffer.

In the ordinary course of business, we collect and store sensitive data, including intellectual property, our proprietary business information and that of our customers, suppliers and business partners, and personally identifiable information of our customers and employees, in our data centers and on our networks. The secure processing, storage, maintenance and transmission of this information is critical to our operations and business strategy. Despite our security measures, our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or

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stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings, liability under laws that protect the privacy of personal information, and regulatory penalties, disrupt our operations and the services we provide to customers, and damage our reputation, and cause a loss of confidence in our products and services, which could adversely affect our business/operating margins, revenues and competitive position. These effects could have a material adverse effect on our financial condition, results of operations and cash flows.

A failure in our operational systems, or those of third parties, may adversely affect our business.

Our business is dependent upon our operational and technological systems to process a large amount of data. If any of our financial, operational, or other data processing systems fail or have other significant shortcomings, our financial results could be adversely affected. Our financial results could also be adversely affected if an employee causes our operational systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating our operational systems. In addition, dependence upon automated systems may further increase the risk that operational system flaws, employee tampering or manipulation of those systems could result in losses that are difficult to detect. We are heavily reliant on technology for communications, financial reporting, treasury management and many other important aspects of our business. Any failure in our operational systems could have a material adverse impact on our business. Third-party systems on which we rely could also suffer operational failures. Any of these occurrences could disrupt our business, including the ability to close our financial ledgers and report the results of our operations publicly on a timely basis or otherwise have a material adverse effect on our financial condition, results of operations and cash flows.

Risks Related to Our Indebtedness

Our substantial level of indebtedness could adversely affect our financial condition and prevent us from fulfilling our obligations under our indebtedness.

As of December 31, 2014, we had approximately $597.3 million of indebtedness, net of premiums and discounts of $0.6 million, outstanding on a consolidated basis, including our $400.0 million aggregate principal amount of 9.875% Senior Notes due 2018 (the "2018 Notes"), $183.1 million under our asset-based revolving credit facility (the “ABL Facility”) and $14.9 million of capital leases and notes payable for trucks and other vehicle financings. We had approximately $27.2 million of net availability under our credit facility as of March 13, 2015.

Our primary source of capital is from borrowings available under our ABL Facility, as well as from cash generated by our operations with additional sources of capital in prior years from additional debt and equity accessed through the capital markets. Our historical acquisition activity was highly capital intensive and required significant investments in order to expand our presence in existing shale basins, access new markets and to expand the breadth and scope of services we provide. Additionally, we have historically issued equity as consideration in acquisition transactions. Our expected sources of capital in 2015 are expected to be from borrowings under our ABL Facility, cash generated by our operations and the net proceeds from the planned sale of TFI. Other sources of cash may include potential sales of assets, sale/leaseback transactions, additional debt or equity financing and reductions in our operating costs.

Given the current macro environment and oil and gas prices, we anticipate declining revenues in 2015, with corresponding reductions in costs from operations. In this environment, we expect sufficient availability under the ABL Facility to meet our operating needs. Our financing strategy includes using the proceeds from the planned sale of TFI, closely monitoring and lowering our operating costs and capital spending, and managing our working capital to enhance liquidity. Based on our current expectations and projections, we believe that our available cash, together with availability under the ABL Facility, will be sufficient to fund our operations, capital expenditures and interest payments under our debt obligations through at least the first quarter of 2016, which is our current, one-year forecast period.

However, our substantial level of indebtedness increases the risk that we may be unable to generate cash sufficient to pay amounts due in respect of our indebtedness. Our substantial level of indebtedness could have other important consequences. For example, our level of indebtedness and the terms of our debt agreements may:


•	make it more difficult for us to satisfy our financial obligations under our other indebtedness and our contractual and commercial commitments and increase the risk that we may default on our debt obligations;


•	prevent us from raising the funds necessary to repurchase the 2018 Notes tendered to us if there is a change of control, which would constitute a default under the indenture governing the 2018 Notes;


•	heighten our vulnerability to downturns in our business, our industry or in the general economy and restrict us from exploiting business opportunities or making acquisitions;

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•	limit management’s discretion in operating our business;


•	require us to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness, thereby reducing the availability of our cash flow to fund working capital, capital expenditures, and other general corporate purposes;


•	place us at a competitive disadvantage compared to our competitors that have less debt;


•	limit our ability to borrow additional funds or cause lenders to be unwilling to lend additional amounts under existing or future lending credit facilities;


•	constrain our ability to fund increased working capital needs; and


•	limit our flexibility in planning for, or reacting to, changes in our business, the industry in which we operate or the general economy.

Each of these factors may have a material and adverse effect on our financial condition and viability. Our ability to make payments with respect to the 2018 Notes and to satisfy our other debt obligations will depend on our future operating performance, which will be affected by prevailing economic conditions and financial, business and other factors affecting us and our industry, many of which are beyond our control. In addition, the indenture governing the 2018 Notes and the credit facility documentation contain restrictive covenants that will affect our ability to engage in activities that may be in our long-term best interests. Our failure to comply with those covenants could result in an event of default that, if not cured or waived, could result in the acceleration of all of our debt.

Borrowings under our credit facility bear interest at variable rates. If we were to borrow funds and these rates were to increase significantly, our ability to borrow additional funds may be reduced and the risks related to our substantial indebtedness could increase. While we may enter into agreements limiting our exposure to higher interest rates, any such agreements may not offer complete protection from this risk. The effects of this risk could have a material adverse effect on our financial condition, results of operations and cash flows.

We may not be able to generate sufficient cash flow to meet our debt service, lease payments and other obligations due to events beyond our control.

Our interest expense related to the 2018 Notes, the borrowings under our credit facility, and our other indebtedness was approximately $50.9 million in the year ended December 31, 2014. Our ability to generate cash flows from operations, to make scheduled payments on or refinance our indebtedness and to fund working capital needs and planned capital expenditures will depend on our future financial performance and our ability to generate cash in the future. Our future financial performance will be affected by a range of economic, financial, competitive, business and other factors that we cannot control, such as general economic, legislative, regulatory and financial conditions in our industry, the economy generally or other risks described in our reports filed with the SEC. A significant reduction in operating cash flows resulting from changes in economic, legislative or regulatory conditions, increased competition or other events beyond our control could increase the need for additional or alternative sources of liquidity and could have a material adverse effect on our business, financial condition, results of operations, prospects and our ability to service our debt and other obligations. If we are unable to service our indebtedness or to fund our other liquidity needs, we may be forced to adopt an alternative strategy that may include actions such as reducing or delaying capital expenditures, selling assets, restructuring or refinancing our indebtedness, seeking additional capital, or any combination of the foregoing. If we raise additional debt, it would increase our interest expense, leverage and our operating and financial costs. We cannot assure you that any of these alternative strategies could be affected on satisfactory terms, if at all, or that they would yield sufficient funds to make required payments on our indebtedness or to fund our other liquidity needs. Reducing or delaying capital expenditures or selling assets could delay or diminish future cash flows. In addition, the terms of existing or future debt agreements may restrict us from adopting any of these alternatives. We cannot assure you that our business will generate sufficient cash flows from operations or that future borrowings will be available in an amount sufficient to enable us to pay our indebtedness or to fund our other liquidity needs.

If for any reason we are unable to meet our debt service and repayment obligations, we would be in default under the terms of the agreements governing our indebtedness, which would allow our creditors at that time to declare all outstanding indebtedness to be immediately due and payable. This would likely in turn trigger cross-acceleration or cross-default rights between our applicable debt agreements. Under these circumstances, our lenders could compel us to apply all of our available cash to repay our borrowings or they could prevent us from making payments on the 2018 Notes or our other indebtedness. In addition, the lenders under our credit facility or other secured indebtedness could seek to foreclose on our assets that collateralize the facility. If the amounts outstanding under our indebtedness were to be accelerated, or were the subject of foreclosure actions, we cannot assure you that our assets would be sufficient to repay in full the money owed to the lenders or

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to our other debt holders. The effects of this risk could have a material adverse effect on our financial condition, results of operations and cash flows.

Despite existing debt levels, we may still be able to incur substantially more debt, which would increase the risks associated with our leverage.

Even with our existing debt levels, we and our subsidiaries may be able to incur substantial amounts of additional debt in the future, some or all of which may be secured. As of March 13, 2015 we had approximately $27.2 million of net availability under our credit facility. In addition, the indenture governing the 2018 Notes and the credit facility documentation allow us to issue additional debt, including additional notes, as well as capital leases and project finance obligations along with other forms of indebtedness, under certain circumstances. Although the terms of the credit facility and the indenture governing the 2018 Notes limit our ability to incur additional debt, these terms do not and will not prohibit us from incurring substantial amounts of additional debt for specific purposes or under certain circumstances, some or all of which may be secured. If new debt is added to our current debt levels, the related risks that we now face to satisfy our obligations could increase. The effects of this risk could have a material adverse effect on our financial condition, results of operations and cash flows.

Our credit facility and the indenture governing the 2018 Notes impose significant operating and financial restrictions on us and our subsidiaries that may prevent us from pursuing certain business opportunities and restrict our ability to operate our business.

The credit facility and the indenture governing the 2018 Notes contain covenants that restrict our and our subsidiaries’ ability to take various actions, such as:


•	transferring or selling assets;


•	paying dividends or distributions, buying subordinated indebtedness or securities, making certain investments or making other restricted payments;


•	incurring or guaranteeing additional indebtedness or issuing preferred stock;


•	creating or incurring liens;


•	incurring dividend or other payment restrictions affecting subsidiary guarantors;


•	consummating a merger, consolidation or sale of all or substantially all our assets;


•	entering into transactions with affiliates;


•	engaging in business other than a business that is the same or similar, reasonably related, complementary or incidental to our business;


•	making acquisitions;


•	making capital expenditures;


•	entering into sale and leaseback transactions; and


•	prepaying, redeeming or repurchasing debt prior to stated maturities.

Our credit facility requires, and any future credit facilities will likely require, us to comply with specified financial ratios that may limit the amount we can borrow under our credit facility. A breach of any of the covenants under the indenture governing the 2018 Notes or the credit facility, as applicable, could result in a default. Our ability to satisfy those covenants depends principally upon our ability to meet or exceed certain positive operating performance metrics including, but not limited to, earnings before interest, taxes, depreciation and amortization, or EBITDA, and ratios thereof, as well as certain balance sheet ratios. Any debt agreements we enter into in the future may further limit our ability to enter into certain types of transactions.

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fixed charge coverage ratio, which only applies if excess availability under the ABL Facility falls below 12.5% of the maximum revolver amount, requires the ratio of adjusted EBITDA (as defined) less capital expenditures to fixed charges (as defined) to be at least 1.1 to 1.0. The senior leverage ratio and fixed charge coverage ratio covenants could have the effect of limiting our availability under the ABL Facility, as additional borrowings would be prohibited if, after giving pro forma effect thereto, we would be in violation of either such covenant. As of December 31, 2014, we remained in compliance with our debt covenants and the availability was $56.5 million; however, our ratio of adjusted EBITDA to fixed charges was less than 1.1 to 1.0 (as calculated pursuant to the ABL Facility). As such, our net availability was reduced by 12.5% of the maximum revolver amount, or $30.6 million, resulting in approximately $25.9 million of net availability as of December 31, 2014.

The maximum amount we can borrow under our ABL Facility is subject to contractual and borrowing base limitations which could significantly and negatively impact our future access to capital required to operate our business. Borrowing base limitations are based upon eligible accounts receivable and equipment. If the value of our accounts receivable or equipment decreases for any reason, or if some portion of our accounts receivable or equipment is deemed ineligible under the terms of our credit facility agreement, the amount we can borrow under the credit facility could be reduced. These limitations could have a material adverse impact on our liquidity and financial condition. In addition, the administrative agent for our ABL Facility has the periodic right to perform an appraisal of the assets comprising our borrowing base. If an appraisal results in a reduction of the borrowing base, then a portion of the outstanding indebtedness under the credit facility could become immediately due and payable. Any such repayment obligation could have a material adverse impact on our liquidity and financial condition.

The indenture governing the 2018 Notes contains restrictive covenants on the incurrence of senior secured indebtedness, including incurring new borrowings under our revolving credit facility, which would limit our ability to incur incremental new senior secured indebtedness in certain circumstances and access to capital if our fixed charge coverage ratio falls below 2.0 to 1.0. To the extent that the fixed charge coverage ratio is below 2.0 to 1.0, the indenture prohibits our incurrence of new senior secured indebtedness, at that point in time, to the greater of $150.0 million and the amount of debt as restricted by the secured leverage ratio, which is the ratio of senior secured debt to EBITDA, of 2.0 to 1.0, as determined pursuant to the indenture. The covenant does not require repayment of existing borrowings if greater than $150 million at that time, but rather limits new borrowings during any such period. The 2.0 to 1.0 fixed charge coverage ratio is an incurrence covenant, not a maintenance covenant.

The covenants described above are subject to important exceptions and qualifications. Our ability to comply with these covenants will likely be affected by some events beyond our control, and we cannot assure you that we will satisfy those requirements. A breach of any of these provisions could result in a default under such indenture, credit facility or other debt obligation, or any future credit facilities we may enter into, which could allow all amounts outstanding thereunder to be declared immediately due and payable, subject to the terms and conditions of the documents governing such indebtedness. If we were unable to repay the accelerated amounts, our secured lenders could proceed against the collateral granted to them to secure such indebtedness. This would likely in turn trigger cross-acceleration and cross-default rights under any other credit facilities and indentures. If the amounts outstanding under the 2018 Notes or any other indebtedness outstanding at such time were to be accelerated or were the subject of foreclosure actions, we cannot assure you that our assets would be sufficient to repay in full the money owed to the lenders or to our other debt holders. We were in compliance with such covenants as of December 31, 2014 and March 13, 2015.

We may also be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by such restrictive covenants. These restrictions may also limit our ability to plan for or react to market conditions, meet capital needs or otherwise restrict our activities or business plans and adversely affect our ability to finance our operations, enter into acquisitions, execute our business strategy, effectively compete with companies that are not similarly restricted or engage in other business activities that would be in our interest. In the future, we may also incur debt obligations that might subject us to additional and different restrictive covenants that could affect our financial and operational flexibility. We cannot assure you that we will be granted waivers or amendments to the indenture governing the 2018 Notes, the credit facility or such other debt obligations if for any reason we are unable to comply with our obligations thereunder or that we will be able to refinance our debt on acceptable terms, or at all, should we seek to do so. Any such limitations on borrowing under our credit facility could have a material adverse impact on our liquidity.

Our borrowings under our credit facility expose us to interest rate risk.

Our earnings are exposed to interest rate risk associated with borrowings under our credit facility. Our credit facility carries a floating interest rate; therefore, as interest rates increase, so will our interest costs, which may have a material adverse effect on our financial condition, results of operations and cash flows.

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Our ability to make acquisitions may be adversely impacted by our outstanding indebtedness and by the price of our stock.

Our ability to make future business acquisitions, particularly those that would be financed solely or in part through cash from operations, will be curtailed due to our obligations to make payments of principal and interest on our outstanding indebtedness. We may not have sufficient capital resources, now or in the future, and may be unable to raise sufficient additional capital resources on terms satisfactory to us, if at all, in order to meet our capital requirements for such acquisitions. In addition, the terms of our indebtedness include covenants that directly restrict, or have the effect of restricting, our ability to make certain acquisitions while this indebtedness remains outstanding. To the extent that the amount of our outstanding indebtedness has a negative impact on our stock price, using our common stock as consideration will be less attractive for potential acquisition candidates. The future trading price of our common stock could limit our willingness to use our equity as consideration and the willingness of sellers to accept our shares and as a result could limit the size and scope of our acquisition program. If we are unable to pursue strategic acquisitions that would enhance our business or operations, the potential growth of our business and our financial condition, results of operations and cash flows could have a material adverse effect.

Risks Related to Our Common Stock

We may issue a substantial number of shares of our common stock in the future and stockholders may be adversely affected by the issuance of those shares.

We may raise additional capital by issuing shares of common stock, which will increase the number of common shares outstanding and may result in dilution in the equity interest of our current stockholders and may adversely affect the market price of our common stock. We have filed a shelf registration statement on Form S-3 with the SEC which allows us to issue up to $400.0 million in debt, equity and hybrid securities. As of December 31, 2014, we had issued 1.8 million shares of common stock at a total price of $80.1 million, under this registration statement and could issue up to an additional $319.9 million of debt, equity or hybrid securities. In addition, we have issued shares of our common stock pursuant to private placement exemptions from Securities Act registration requirements, and may do so in connection with financings, acquisitions, the settlement of litigation and other strategic transactions in the future. The issuance, and the resale or potential resale, of shares of our common stock could adversely affect the market price of our common stock and could be dilutive to our stockholders.

Our stock price may be volatile, which could result in substantial losses for investors in our securities.

The stock markets have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock.

The market price of our common stock may also fluctuate significantly in response to the following factors, some of which are beyond our control:


•	variations in our quarterly operating results and changes in our liquidity position;


•	changes in securities analysts’ estimates of our financial performance;


•	inaccurate or negative comments about us on social networking websites or other media channels;


•	changes in market valuations of similar companies;


•	announcements by us or our competitors of significant contracts, acquisitions, strategic partnerships, joint ventures, capital commitments, new products or product enhancements, as well as our or our competitors' success or failure in successfully executing such matters;


•	changes in the price of oil and natural gas;


•	loss of a major customer or failure to complete significant transactions; and


•	additions or departures of key personnel.

The trading price of our common stock on the New York Stock Exchange, or “NYSE,” since our initial public offering has ranged from a high of $107.40 on September 3, 2008 to a low of $4.80 on December 24, 2014. The last reported price of our common stock on the NYSE on March 13, 2015 was $2.92 per share.

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If our common stock fails to meet all applicable listing requirements, it could be delisted from the NYSE, which could adversely affect the market price and liquidity of our common stock and harm our financial condition and results of operations.

Our common stock is currently traded on the NYSE. If we fail to meet any of the continued listing standards of the NYSE, our common stock could be delisted from the NYSE. These continued listing standards include, among others, maintaining a $1.00 minimum average closing stock price per share. Our common stock has traded as low as $1.65 per share during the prior 52-week period. If the average price of our common stock is less than $1.00 per share for thirty consecutive trading days, there can be no assurance that the NYSE will not take action to enforce its continued listing standards. Any delisting of our common stock from the NYSE could adversely affect the market price and liquidity of our common stock, impair our ability to raise capital necessary to maintain operations and service our debt, cause significant loss of investor interest in our securities, cause a loss of confidence among our employees and customers and otherwise negatively affect our financial condition, results of operations and cash flows.

We currently do not intend to pay any dividends on our common stock.

We currently do not intend to pay any dividends on our common stock, and restrictions and covenants in our debt agreements may prohibit us from paying dividends now or in the future. While we may declare dividends at some point in the future, subject to compliance with such restrictions and covenants, we cannot assure you that you will ever receive cash dividends as a result of ownership of our common stock and any gains from investment in our common stock may only come from increases in the market price of our common stock, if any.

We are subject to anti-takeover effects of certain charter and bylaw provisions and Delaware law, as well as of our substantial insider ownership.

Provisions of our certificate of incorporation and bylaws, each as amended and restated, and Delaware law may discourage, delay or prevent a merger or acquisition that stockholders may consider favorable, including transactions in which you might otherwise receive a premium for your shares. In addition, these provisions may frustrate or prevent any attempts by our stockholders to replace or remove our management and board of directors. These provisions include:


•	authorizing the issuance of “blank check” preferred stock without any need for action by stockholders;


•	establishing a classified board of directors, so that only approximately one-third of our directors are elected each year;


•	providing our board of directors the ability to set the number of directors and to fill vacancies on the board of directors occurring between stockholder meetings;


•	providing that directors may only be removed only for “cause” and only by the affirmative vote of the holders of at least a majority in voting power of our issued and outstanding capital stock; and


•	limiting the ability of our stockholders to call special meetings.

We are also subject to provisions of the Delaware corporation law that, in general, prohibit any business combination with a beneficial owner of 15% or more of our common stock for three years following the date the beneficial owner acquired at least 15% of our stock, unless various conditions are met, such as approval of the transaction by our board of directors. Together, these charter and statutory provisions could make the removal of management more difficult and may discourage transactions that otherwise could involve payment of a premium over prevailing market prices for our common stock.

The existence of the foregoing provisions and anti-takeover measures, as well as the significant amount of common stock beneficially owned by our Chief Executive Officer and Chairman, Mr. Johnsrud, could limit the price that investors might be willing to pay in the future for shares of our common stock. They could also deter potential acquirers of our company, thereby reducing the likelihood that you could receive a premium for your common stock in an acquisition.

Risks Related to Environmental and Other Governmental Regulation

We are subject to United States federal, state and local laws and regulations relating to health, safety, transportation, and protection of natural resources and the environment. Under these laws and regulations, we may become liable for significant penalties, damages or costs of remediation. Any changes in laws and regulations could increase our costs of doing business.

Our operations, and those of our customers, are subject to United States federal, state and local laws and regulations relating to health, safety, transportation and protection of natural resources and the environment and worker safety, including those relating

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to waste management and transportation and disposal of produced water and other materials. For example, we are subject to environmental regulation relating to disposal into injection wells, which can pose some risks of environmental liability, including leakage from the wells to surface or subsurface soils, surface water or groundwater. Liability under these laws and regulations could result in cancellation of well operations, fines and penalties, expenditures for remediation, and liability for property damage and personal injuries. In addition, federal, state and local laws and regulations may be passed which would have the effect of increasing costs to our customers and possibly decreasing demand for our services. For example, if new laws and regulations are passed requiring increased safety measures for rail transport of crude oil, such laws and regulations may make it more difficult and expensive for customers to transport their product, which could decrease our customers’ demand for our services and negatively affect our results of operations and financial condition. Similarly, many of our customers have intrastate pipeline operations that are subject to regulation by various agencies of the states in which they are located. If new laws and/or regulations that further regulate intrastate pipelines are adopted in response to equipment failures, spills, negative environmental effects, or public sentiment, our customers may face increased costs of compliance, and thus reduce demand for our services

Our business involves the use, handling, storage, and contracting for recycling or disposal of environmentally sensitive materials. Accordingly, we are subject to regulation by federal, state, and local authorities establishing investigation and health and environmental quality standards, and liability related thereto, and providing penalties for violations of those standards. We also are subject to laws, ordinances, and regulations governing investigation and remediation of contamination at facilities we operate or to which we send hazardous or toxic substances or wastes for treatment, recycling, or disposal. In particular, CERCLA imposes joint, strict, and several liability on owners or operators of facilities at, from, or to which a release of hazardous substances has occurred; parties that generated hazardous substances that were released at such facilities; and parties that transported or arranged for the transportation of hazardous substances to such facilities. A majority of states have adopted statutes comparable to and, in some cases, more stringent than CERCLA. If we were to be found to be a responsible party under CERCLA or a similar state statute, we could be held liable for all investigative and remedial costs associated with addressing such contamination. In addition, claims alleging personal injury or property damage may be brought against us as a result of alleged exposure to hazardous substances resulting from our operations.

Failure to comply with these laws and regulations could result in the assessment of significant administrative, civil or criminal penalties, imposition of cleanup and site restoration costs and liens, revocation of permits, and orders to limit or cease certain operations. In addition, certain environmental laws impose strict and/or joint and several liability, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time of those actions. For example, if a landfill or disposal operator mismanages our wastes in a way that creates an environmental hazard, we and all others who sent materials could become liable for cleanup costs, fines and other expenses many years after the disposal or recycling was completed. Future events, such as the discovery of currently unknown matters, spills caused by future pipeline ruptures, changes in existing environmental laws and regulations or their interpretation, and more vigorous enforcement policies by regulatory agencies, may give rise to additional expenditures or liabilities, which could impair our operations and could have a material adverse effect on our financial condition, results of operations and cash flows.

Although we believe that we are in substantial compliance with all applicable laws and regulations, legal requirements are changing frequently and are subject to interpretation. New laws, regulations and changing interpretations by regulatory authorities, together with uncertainty regarding adequate testing and sampling procedures, new pollution control technology and cost benefit analysis based on market conditions are all factors that may increase our future capital expenditures to comply with environmental requirements. Accordingly, we are unable to predict the ultimate cost of future compliance with these requirements or their effect on our operations.

Increased regulation of hydraulic fracturing, including regulation of the quantities, sources and methods of water use and disposal, could result in reduction in drilling and completing new oil and natural gas wells or minimize water use or disposal, which could adversely impact the demand for our services.

Demand for our services depends, in large part, on the level of exploration and production of oil and gas and the oil and gas industry’s willingness to purchase our services. Most of our customer base uses hydraulic fracturing to drill new oil and gas wells. Hydraulic fracturing is a process that is used to release hydrocarbons, particularly natural gas, from certain geological formations. The process involves the injection of water (typically mixed with significant quantities of sand and small quantities of chemical additives) under pressure into the formation to fracture the surrounding rock and stimulate movement of hydrocarbons through the formation. The process is typically regulated by state oil and gas commissions and has been exempt (except when the fracturing fluids or propping agents contain diesel fuels) since 2005 from United States federal regulation pursuant to the SDWA.

The EPA is conducting a comprehensive study of the potential environmental impacts of hydraulic fracturing activities, and a committee of the United States House of Representatives is also conducting an investigation of hydraulic fracturing practices.

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The results of the EPA study and House investigation could lead to restrictions on hydraulic fracturing. On February 11, 2014, the EPA released revised underground injection control (UIC) program permitting guidance for wells that use diesel fuels during hydraulic fracturing activities. EPA developed the guidance to clarify how companies can comply with a law passed by Congress in 2005, which exempted hydraulic fracturing operations from the requirement to obtain a UIC permit, except in cases where diesel fuel is used as a fracturing fluid. In a February 5, 2014 memorandum, EPA’s Inspector General (IG) announced plans to evaluate how EPA and the states have used their regulatory authority to address potential impacts of hydraulic fracturing on water resources. The IG reportedly will “evaluate what regulatory authority is available to the EPA and states, identify potential threats to water resources from hydraulic fracturing, and evaluate the EPA’s and states’ responses to them.” In addition, the EPA finalized regulations under the CAA in October 2012 regarding certain criteria and hazardous air pollutant emissions from hydraulic fracturing wells and, in October 2011, announced its intention to propose regulations by 2014 under the CWA to regulate wastewater discharges from hydraulic fracturing and other gas production. The EPA has also announced that it will propose rules on effluent limitations for the treatment of discharge of wastewater resulting from hydraulic fracturing in early 2015. Legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing, including, for example, requiring disclosure of chemicals used in the fracturing process or seeking to repeal the exemption from the SWDA. If adopted, such legislation would add an additional level of regulation and necessary permitting at the federal level and could make it more difficult to complete wells using hydraulic fracturing. Similar laws and regulations with respect to chemical disclosure also exist or are being considered by the United States Department of Interior and in several states, including certain states in which we operate, that could restrict hydraulic fracturing. The Delaware River Basin Commission is also considering regulations which may impact “hydrofracturing” water practices in certain areas of Pennsylvania, New York, New Jersey and Delaware. Some local governments have also sought to restrict drilling in certain areas.

Additionally, in response to concerns about seismic activity being triggered by the injection of produced waters into underground wells, certain regulators have adopted or are considering additional requirements related to seismic safety for hydraulic fracturing activities. For example, in January 2012, the Ohio Department of Natural Resources issued a temporary moratorium on the development of hydraulic fracturing disposal wells in northeast Ohio due to minor earthquakes reported in the area. In Texas, the Texas Railroad Commission (the "RRC") amended its existing oil and gas disposal well regulations to require applicants for new disposal wells to conduct seismic activity searches utilizing the U.S. Geological Survey to assess whether the RRC should impose limits on existing wells, including a temporary injection ban. Finally, the state of Arkansas imposed a moratorium on waste water injection in certain areas due to concerns that hydraulic fracturing may be related to increased earthquake activity. Such laws and regulations could delay or curtail production of oil and natural gas by our customers, and thus reduce demand for our services.

Future United States federal, state or local laws or regulations could significantly restrict, or increase costs associated with hydraulic fracturing and make it more difficult or costly for producers to conduct hydraulic fracturing operations, which could result in a decline in exploration and production. New laws and regulations, and new enforcement policies by regulatory agencies, could also expressly restrict the quantities, sources and methods of water use and disposal in hydraulic fracturing and otherwise increase our costs and our customers’ cost of compliance, which could minimize water use and disposal needs even if other limits on drilling and completing new wells were not imposed. Any decline in exploration and production or any restrictions on water use and disposal could result in a decline in demand for our services and have a material adverse effect on our business, financial condition, results of operations and cash flows.

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

In most states, our customers are required to obtain permits from one or more governmental agencies in order to perform drilling and completion activities and we may be required to procure permits for construction and operation of our disposal wells and pipelines. 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 our, or our customers’, 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. Delays or restrictions in obtaining saltwater disposal well permits could adversely impact our growth, which is dependent in part on new disposal capacity.

Our customers have been affected by moratoriums that have been imposed on the issuance of permits for drilling and completion activities in certain jurisdictions. For example, in December 2010, the State of New York imposed a moratorium on certain drilling and completion activities. In 2011, the state announced plans to lift the moratorium, however, in December 2014 the state announced that it intended to take action to prohibit certain drilling and completion activities, including hydraulic fracturing, in the state. A similar moratorium has been in place within the Delaware River Basin pending issuance of regulations by the Delaware River Basin Commission. Other states, including Texas, Arkansas, Pennsylvania, Wyoming and Colorado, have enacted laws and regulations applicable to our business activities, including disclosure of information regarding

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the substances used in hydraulic fracturing. California is presently considering similar requirements. The EPA published a rule on January 9, 2014 requiring oil and gas companies using hydraulic fracturing off the coast of California to disclose the chemicals they discharge into the ocean. Some of the drilling and completion activities of our customers may take place on federal land, requiring leases from the federal government to conduct such drilling and completion activities. In some cases, federal agencies have canceled oil and natural gas leases on federal lands. Consequently, our operations in certain areas of the country may be interrupted or suspended for varying lengths of time, causing a loss of revenue and potentially having a materially adverse effect on our financial condition, results of operations and cash flows.

We are subject to the trucking safety regulations, which are likely to be amended, and made stricter, as part of the initiative known as Compliance, Safety, Accountability, or “CSA.” If our current USDOT safety rating of “Satisfactory” is downgraded in connection with this initiative, our business and results of our operations may be adversely affected.

As part of the CSA initiative, the FMCSA is continuously revising its safety rating methodology and implementation of the same. These revisions will likely link safety ratings more closely to roadside inspection and driver violation data gathered and analyzed from month to month under the FMCSA’s new Safety Measurement System, or “SMS” and may place increased scrutiny on carriers transporting significant quantities of hazardous material. This linkage could result in greater variability in safety ratings than the current system. Preliminary studies by transportation consulting firms indicate that “Satisfactory” ratings (or any equivalent under a new SMS-based system) may become more difficult to achieve and maintain under such a system. If our operations lose their current “Satisfactory” rating, which is the highest and best rating under this initiative, we may lose some of our customer contracts that require such a rating, adversely affecting our financial condition, results of operations and cash flows.



Item 1B.	Unresolved Staff Comments

None.



Item 2.	Properties

We lease our corporate headquarters in Scottsdale, Arizona and we own or lease numerous facilities including administrative offices, sales offices, truck yards, maintenance and warehouse facilities, a landfill facility, a water treatment facility and well disposal sites in 14 states. We also own or lease 56 saltwater disposal wells in Texas, Ohio, Mississippi, North Dakota and Montana as of December 31, 2014. We believe that we have satisfactory title to the properties owned and used in our businesses, subject to liens for taxes not yet payable, liens incident to minor encumbrances, liens for credit arrangements (including liens under our credit facility) and easements and restrictions that do not materially detract from the value of these properties, our interests in these properties, or the use of these properties in our businesses.

We believe all properties that we currently occupy are suitable for their intended uses. We believe that we have sufficient facilities to conduct our operations. However, we continue to evaluate the purchase or lease of additional properties or the consolidation of our properties, as our business requires.



Item 3.	Legal Proceedings

We are party to legal proceedings and potential claims arising in the ordinary course of our business, including, but not limited to, claims related to employment matters, contractual disputes, personal injuries and property damage. In addition, various legal actions, claims and governmental inquiries and proceedings are pending or may be instituted or asserted in the future against us and our subsidiaries. See “Legal Matters” in Note 16 of the Notes to Consolidated Financial Statements herein for a description of our legal proceedings.



Item 4.	Mine Safety Disclosures

None.

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NUVERRA ENVIRONMENTAL SOLUTIONS, INC.

PART II



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

Market Information

The Company is a Delaware corporation and was formerly named Heckmann Corporation. At the 2013 annual meeting of shareholders, our shareholders approved an amendment to our Certificate of Incorporation to change our name from “Heckmann Corporation” to “Nuverra Environmental Solutions, Inc.” Our shares began trading on the New York Stock Exchange under our new name and stock ticker symbol “NES,” effective as of the market open on May 20, 2013.

On December 3, 2013, we filed a Certificate of Amendment to our Restated Certificate of Incorporation in order to effect a one-for-ten reverse split of our common stock and our common stock began trading on the New York Stock Exchange (“NYSE”) on a split-adjusted basis on the same date. No fractional shares were issued in connection with the reverse stock split. As a result of the reverse stock split, the number of authorized, issued and outstanding shares of our common stock was reduced to approximately 50.0 million, 28.9 million and 27.5 million, respectively, at December 31, 2014. Furthermore, proportional adjustments were made to stock options, warrants, and restricted stock units. The change in the number of shares resulting from the reverse stock split has been applied retroactively to all shares and per share amounts presented in this Annual Report on Form 10-K.

The table below presents the high and low daily sales prices of the common stock, as reported by the New York Stock Exchange, for each of the quarters in the years ended December 31, 2013 and 2014, respectively:



For the Year Ending December 31, 2013	High		Low
First Quarter	$	44.20	$	33.10
Second Quarter	$	42.70	$	28.50
Third Quarter	$	37.50	$	20.60
Fourth Quarter	$	25.10	$	13.10

For the Year Ending December 31, 2014	High		Low
First Quarter	$	20.60	$	13.17
Second Quarter	$	20.68	$	15.32
Third Quarter	$	21.29	$	12.90
Fourth Quarter	$	15.11	$	4.80

Holders

As of March 13, 2015, there were 39 holders of record of our common stock. The number of beneficial holders is substantially greater than the number of record holders because a significant portion of our common stock is held of record in broker “street names.”

Dividends

We have not paid any dividends on our common stock to date, and we currently do not intend to pay dividends in the future. The payment of dividends in the future will be contingent upon our revenues and earnings, if any, capital requirements and general financial condition. The payment of any dividends will be within the discretion of our board of directors and will be subject to other limitations as may be contained in our ABL Facility, the indenture governing the 2018 Notes or other applicable agreements governing our indebtedness. It is the present intention of our board of directors to retain all earnings, if any, for use in our business operations and, accordingly, our board does not anticipate declaring any dividends in the foreseeable future.

Unregistered Sales of Equity Securities

On March 4, 2014, the Company entered into a stipulation of settlement to settle a securities class action pending in the United States District Court for the District of Delaware as Case No. 1:10-cv-00378-LPS-MPT. The lawsuit relates to matters alleged to have occurred in connection with the acquisition by Heckmann Corporation of China Water and Drinks, Inc. in 2008. The settlement was approved by the court on June 26, 2014 and became effective on August 27, 2014. Pursuant to the court’s approval order, and as part of the consideration paid to settle such lawsuit, the Company issued 282,663 shares of Company common stock to the plaintiffs’ attorneys on July 2, 2014 and issued 565,327 shares of Company common stock to the plaintiffs

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on August 27, 2014. The shares are exempt from registration pursuant to Section 3(a)(10) of the Securities Act of 1933, as amended. The Company did not receive cash proceeds from the issuance of such shares.

Repurchases of Equity Securities

During the year ended December 31, 2014, we did not repurchase any options or warrants for shares of our common stock nor did we repurchase any shares of our common stock.

Recent Performance

The following performance graph and related information shall not be deemed “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act or Exchange Act, except to the extent that we specifically incorporate it by reference into such filing.

Performance Graph

The following graph compares the cumulative total shareholder return for our common stock from January 1, 2010, through December 31, 2014, with the comparable cumulative return of two indices, the S&P 500 Index and the Dow Jones Industrial Average Index (DJIA).

The chart assumes $100 invested on January 1, 2010, in our common stock and $100 invested at that same time in each of the two indices.



Company / Index	January 1, 2010		December 31, 2010		December 31, 2011		December 31, 2012		December 31, 2013		December 31, 2014
NES	$	100.00	$	100.80	$	133.27	$	80.76	$	33.65	$	11.12
S&P 500 Index	100.00		115.06		117.49		136.30		180.44		205.14
DJIA Index	100.00		114.06		123.62		136.28		176.69		194.44

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Item 6.	Selected Financial Data

The following table presents selected consolidated financial information and other operational data for our business. You should read the following information in conjunction with Item 7 of this Annual Report on Form 10-K entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and the consolidated financial statements and related notes included elsewhere in this Annual Report on Form 10-K.

Statement of Operations Data



	Year Ended December 31,
	2014			2013			2012			2011			2010 (7)
	($ in thousands, except per share data)
Revenue	$	536,282		$	525,816		$	256,671		$	156,837		$	15,208
Loss from operations (1)(2)(3)(4)	(417,654		)	(149,659		)	(37,574		)	(5,412		)	(19,513		)
Loss from continuing operations (1)(2)(3)(5)(6)	(457,178		)	(134,040		)	(6,597		)	(108		)	(10,300		)
(Loss) income from discontinued operations (1)(2)(8)(9)	(58,426		)	(98,251		)	9,124			(22,898		)	(4,393		)
(Loss) income attributable to common stockholders	(515,604		)	(232,291		)	2,527			(23,006		)	(14,693		)
Weighted average shares outstanding used in computing net (loss) income per basic and diluted common share	26,090			24,492			14,994			11,457			10,882
Basic and diluted loss per share from continuing operations	$	(17.52	)	$	(5.47	)	$	(0.44	)	$	(0.01	)	$	(0.95	)
Basic and diluted (loss) income per share from discontinued operations	$	(2.24	)	$	(4.01	)	$	0.61		$	(2.00	)	$	(0.40	)
Net (loss) income per basic and diluted share	$	(19.76	)	$	(9.48	)	$	0.17		$	(2.01	)	$	(1.35	)

(1)

Loss from continuing operations for the year ended December 31, 2014 includes a goodwill impairment charge of $304.0 million, a long-lived asset impairment charge of $112.4 million, approximately $8.8 million in litigation and environmental charges and the write-off of a portion of the unamortized deferred financings costs associated with the Amended Revolving Credit Facility of approximately $3.2 million. Additionally, as a result of the on-going sales process of the Company's industrial solutions division, the Company recorded charges totaling $74.4 million, which is included within "Loss from discontinued operations, net of income taxes" in the Company's Consolidated Statement of Operations herein.

(2)

During the fourth quarter of 2013, the Company’s board of directors approved and committed to a plan to divest the Company’s Thermo Fluids Inc. subsidiary, which comprises its industrial solutions business division. Subsequently, the sales process began and as a result, the Company considers TFI to be held for sale. As such, all prior periods have been restated to reflect TFI as discontinued operations. See “Assets Held for Sale and Discontinued Operations” in Note 20 of the Notes to Consolidated Financial Statements herein for further information. Loss from operations and loss from continuing operations for the year ended December 31, 2013 includes a long-lived asset impairment charge of $111.9 million, $24.6 million in litigation settlement charges and the write-off of $4.3 million of investments.

(3)

Loss from operations and loss from continuing operations for the year ended December 31, 2012 includes merger and acquisition costs of $7.7 million, impairment charges of $2.4 million and $3.7 million related to write-downs of the carrying values of a customer intangible asset and saltwater disposal wells, respectively, and a $1.4 million charge to accrue for the estimated costs of remediation and testing to comply with Louisiana Department of Environmental Quality requirements. In addition, loss from continuing operations for the year ended December 31, 2012 includes a $2.6 million charge for the write-off of unamortized deferred financing costs due to the repayment and replacement of our prior credit facility. 2012 results also include amounts from the acquisitions of Keystone Vacuum, Inc. and related entities, Thermo Fluids Inc., Homer Enterprises, Inc., JB Transportation Services, Inc. (“All Phase”), Appalachian Water Services, LLC and Badlands Power Fuels, LLC from their transaction dates of February 3, 2012, April 10, 2012, May 31, 2012, June 15, 2012, September 1, 2012 and November 30, 2012, respectively.


(4)	2011 results include amounts from the acquisitions of Bear Creek, LLC, Devonian Industries, Inc., Sand Hill Foundation, LLC, Excalibur Energy Services, Inc., and Blackhawk, LLC and Consolidated Petroleum, Inc. from their acquisition dates of April 1, 2011, April 4, 2011, April 12, 2011, May 5, 2011 and June 14, 2011, respectively.

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(5)	Loss from operations for the years ended December 31, 2011 and 2010 includes charges of $2.1 million and $11.8 million, respectively, for start-up and commissioning costs associated with a pipeline in the Haynesville Shale area.

(6)

In addition to the transactions described under item (3), loss from continuing operations for the year ended December 31, 2012 includes a $2.6 million charge for the write-off of unamortized deferred financing costs due to the repayment and replacement of our prior credit facility and an income tax benefit from the release of a $38.5 million valuation allowance associated with net operating losses because of a determination that the realization of the associated deferred tax assets is more likely than not based on future taxable income arising from the reversal of deferred tax liabilities that we acquired in the TFI acquisition and the Power Fuels merger.


(7)	2010 results include amounts from the acquisition of Complete Vacuum and Rental, Inc. since November 30, 2010, the date of its acquisition.


(8)	On September 30, 2011, we completed the disposition, through a sale and abandonment, of the China Water bottled water business. The business has, for all periods presented herein, been reported as discontinued operations for financial reporting purposes.

(9)

2014 results include charges totaling $74.4 million in the Company's industrial solutions division. See “Assets Held for Sale and Discontinued Operations” in Note 20 of the Notes to Consolidated Financial Statements herein for further information. 2013 results include a $98.5 million goodwill impairment charge associated with our industrial solutions business division. 2009 results include a goodwill impairment charge of $357.5 million related to our China Water bottled water business. Both businesses are presented as discontinued operations for all periods presented herein.

Balance Sheet Data



	Year Ended December 31,
	2014		2013		2012		2011		2010
	($ in thousands)
Consolidated balance sheet data:
Cash and cash equivalents (1)	$	13,367	$	8,783	$	14,776	$	80,194	$	80,752
Total current assets	154,672		161,691		165,981		139,761		186,021
Property, plant and equipment, net (2)	475,982		498,541		579,022		270,054		85,696
Goodwill (2)	104,721		408,696		415,176		90,008		41,008
Total assets (2)(3)	871,572		1,410,763		1,644,339		539,681		355,671
Current maturities of long-term debt	4,863		5,464		4,699		11,914		11,221
Current liabilities	96,193		124,538		86,470		49,329		30,779
Long-term debt, less current maturities (4)	592,455		549,713		561,427		132,156		20,474
Total liabilities	718,625		766,394		796,578		197,871		72,680
Total equity of Nuverra Environmental Solutions, Inc.	152,947		644,369		847,761		341,810		301,621


(1)	The decrease to cash and cash equivalents in 2012 was due primarily to the use of cash to fund 2012 merger and acquisition activity.


(2)	The 2014 decrease in goodwill and total assets relates to a goodwill and long-lived asset impairment charge of $304.0 million and $112.4 million respectively. 2013 results include an impairment of long-lived assets of $111.9 million. The 2012 increases to property, plant and equipment, goodwill and total assets were due to the 2012 acquisition and merger transactions.


(3)	Total assets as of December 31, 2014 and 2013 also reflect a reduction in goodwill relating to an impairment of $48.0 million and $98.5 million respectively, at TFI which is included in assets held for sale. Additionally, total assets as of December 31, 2014 also reflect a reduction in intangible assets of $26.4 million at TFI.


(4)	In April 2012 and November 2012, we issued $250.0 million and $150.0 million, respectively, aggregate principal amount of 9.875% senior unsecured notes due 2018 to partially finance the acquisition of TFI and the merger with Power Fuels.

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

This Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with our Consolidated Financial Statements, and the Notes and Schedules related thereto, which are included in this Annual Report.

Company Overview

Nuverra Environmental Solutions, Inc. is among the largest companies in the United States dedicated to providing comprehensive, full-cycle environmental solutions to customers focused on the development and ongoing production of oil and natural gas from shale formations. Nuverra’s strategy is to provide one-stop, total environmental solutions, including delivery, collection, treatment, recycling, and disposal of water, wastewater, waste fluids, hydrocarbons, and restricted solids that are part of the drilling, completion, and ongoing production of shale oil and natural gas.

To meet its customers’ environmental needs, Nuverra utilizes a broad array of assets to provide comprehensive environmental solutions. Our logistics assets include trucks and trailers, temporary and permanent pipelines, temporary and permanent storage facilities, ancillary rental equipment, treatment facilities, and liquid and solid waste disposal sites. We continue to expand our suite of solutions to customers who demand environmental compliance and accountability from their service providers.

As discussed in Note 8 and Note 19 of the Notes to Consolidated Financial Statements herein, during the three months ended September 30, 2014, we completed the organizational realignment of our shale solutions business into three operating divisions, the Northeast, Southern and Rocky Mountain divisions. During the fourth quarter of 2013, our board of directors approved and committed to a plan to divest TFI, which comprised our previously reported industrial solutions division. As a result, we consider TFI to be held for sale and its assets and liabilities, results of operations and cash flows are presented as discontinued operations in the accompanying consolidated financial statements for the years ended December 31, 2014, 2013 and 2012 (Note 20).

We operate in shale basins where customer exploration and production (“E&P”) activities are predominantly focused on shale oil and natural gas as follows:


•	Oil shale areas: includes our operations in the Bakken, Utica, Eagle Ford, Mississippian, Tuscaloosa Marine and Permian Basin Shale areas.


•	Gas shale areas: includes our operations in the Marcellus, Haynesville and Barnett (which we substantially exited during the three months ended March 31, 2014) Shale areas.

Nuverra supports its customers’ demand for diverse, comprehensive and regulatory compliant environmental solutions required for the safe and efficient drilling, completion and production of oil and natural gas from shale formations. Current services, as well as prospective services in which Nuverra has made investments, include (i) fluid logistics via water procurement, delivery, collection, storage, treatment, recycling and disposal, (ii) solid waste collection, treatment and disposal, (iii) permanent and portable pipeline facilities, water infrastructure services and equipment rental services, and (iv) other ancillary services for E&P companies focused on the extraction of oil and natural gas resources from shale basins.

Impairment of Long-Lived Assets and Goodwill

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financial results as well as the fact that the market price of our common stock, taking into consideration potential control premiums, has wavered above and below our book value since the third quarter of 2013, as previously disclosed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2013 and subsequent Quarterly Reports on Form 10-Q. Based on these factors, we were required to perform impairment tests to determine whether the carrying values are fully recoverable of both our long-lived assets and goodwill. We completed the review of our long-lived assets in the quarter ended September 30, 2014 and concluded the fair value of such assets exceeded their carrying values, thus no long-lived asset impairment was indicated.

on the results of the step-one goodwill impairment review, we concluded the fair value of the Rocky Mountain

division exceeded our carrying amount by approximately 14% and accordingly, the second step of the impairment test was not

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Trends Affecting Our Operating Results

Our results are driven by demand for our services, which are in turn affected by E&P trends in the shale areas in which we operate, in particular the level of drilling activity (which impacts the amount of environmental waste products being managed) and active wells (which impacts the amount of produced water being managed). In general, drilling activity in the oil and gas drilling industry is affected by the market prices (or anticipated prices) for those commodities. Persistent low natural gas prices have driven reduced drilling activity in “dry” gas shale areas such as the Barnett, Haynesville and Marcellus Shale areas where natural gas is the predominant natural resource. In addition, the low natural gas prices have in the past caused many natural gas producers to curtail capital budgets and these cuts in spending curtailed drilling programs as well as discretionary spending on well services in certain shale areas, and accordingly reduced demand for our services in these areas. While drilling and production activity in the oil and "wet" gas basins such as the Eagle Ford, Permian Basin, Utica and Bakken shale areas have been more robust when compared to the "dry" gas shale areas in the past few years, the dramatic decline in oil prices in the fourth quarter of 2014 has impacted drilling and completion activity in these shale areas. We anticipate our customer base to reduce their 2015 capital programs and expect lower drilling and completion activity levels in 2015, which we expect to be somewhat mitigated by our revenues from services supporting production from oil and natural gas operations. Demand for these production-related services tends to be relatively stable in moderate oil and gas price environments as these services are required to sustain production.

Our results are also driven by a number of other factors, including (i) our available inventory of equipment, which we have built through acquisitions and capital expenditures over the past several years, (ii) transportation costs, which are affected by fuel costs, (iii) utilization rates for our equipment, which are also affected by the level of our customers’ drilling and production activities and competition, and our ability to relocate our equipment to areas in which oil and gas exploration and production activities are growing, (iv) the availability of qualified drivers (or alternatively, subcontractors) in the areas in which we operate, particularly in the Bakken and Marcellus/Utica Shale areas, (v) labor costs, which have been generally increasing through the periods discussed due to tight labor market conditions and increased government regulation, including the Affordable Care Act, (vi) developments in governmental regulations, (vii) seasonality and weather events and (viii) our health, safety and environmental performance record.

Our operating results are also affected by our acquisition activities, and the expenses we incur in connection with those activities, including integration costs, which can limit comparability of our results from period to period. We completed three acquisitions in the year ended December 31, 2013, and six acquisitions during the year ended December 31, 2012, including Power Fuels and TFI, which were among our largest to date. We may complete other acquisitions in the future that could cause our future operating results to be substantially different from our historical operating results.

The following table summarizes our total revenues, loss from continuing operations before income taxes, loss from continuing operations and EBITDA (defined below) for the years ended December 31, 2014, 2013 and 2012 (in thousands):



	Year Ended December 31,
	2014			2013			2012
Revenue - from predominantly oil shale areas (a)	$	403,371		$	373,410		$	87,300
Revenue - from predominantly gas shale areas (b)	132,911			152,406			169,371
Total revenue	536,282			525,816			256,671
Loss from continuing operations before income taxes	(469,641		)	(207,135		)	(69,357		)
Loss from continuing operations	(457,178		)	(134,040		)	(6,597		)
EBITDA (c, d)	(332,844		)	(54,196		)	4,891

_________________________


(a)	Represents revenues that are derived from predominantly oil-rich areas consisting of the Bakken, Utica, Eagle Ford, Mississippian and Permian Basin Shale areas.


(b)	Represents revenues that are derived from predominantly gas-rich areas consisting of the Marcellus, Haynesville, Tuscaloosa Marine and Barnett Shale areas (prior to our substantial exit from this basin during the three months ended March 31, 2014).


(c)	Defined as consolidated net income (loss) from continuing operations before net interest expense, income taxes and depreciation and amortization. EBITDA is not a recognized measure under generally accepted accounting principles in

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the United States (“GAAP”). See the reconciliation between loss from continuing operations and EBITDA under “Liquidity and Capital Resources—EBITDA”.


(d)	The Company's debt covenants referred to in Note 10 of the Notes to Consolidated Financial Statements are based on EBITDA adjusted for certain items as defined.

The accompanying consolidated financial statements have been prepared by management in accordance with the instructions to Form 10-K and the rules and regulations of the SEC. These statements include all normal recurring adjustments considered necessary by management to present a fair statement of the consolidated balance sheets, results of operations and cash flows. The consolidated financial statements should be read in conjunction with the audited consolidated financial statements, including the notes thereto, contained in this Annual Report on Form 10-K.

For trends affecting our business and the markets in which we operate see “Trends Affecting our Operating Results” presented above and also “Risk Factors” in Part I, Item 1A of this Annual Report on Form 10-K.

Results of Operations

Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013

The following table sets forth for each of the periods indicated our statements of operations data and expresses revenue and expense data as a percentage of total revenues for the periods presented (dollars in thousands):



	Year Ended						Percent of Revenue
	December 31,						December 31,				Increase (Decrease)
	2014			2013			2014		2013		2014 versus 2013
Non-rental revenue	$	463,418		$	441,421		86.4	%	83.9	%	$	21,997		5.0	%
Rental revenue	72,864			84,395			13.6	%	16.1	%	(11,531		)	(13.7	)%
Total revenue	536,282			525,816			100.0	%	100.0	%	10,466			2.0	%
Costs and expenses:
Direct operating expenses	384,813			379,160			71.8	%	72.1	%	5,653			1.5	%
General and administrative expenses	66,832			84,280			12.5	%	16.0	%	(17,448		)	(20.7	)%
Depreciation and amortization	85,880			99,236			16.0	%	18.9	%	(13,356		)	(13.5	)%
Impairment of long-lived assets	112,436			111,900			21.0	%	21.3	%	536			0.5	%
Impairment of goodwill	303,975			—			56.7	%	—	%	303,975			100.0	%
Other, net	—			899			—	%	0.2	%	(899		)	(100.0	)%
Total costs and expenses	953,936			675,475			177.9	%	128.5	%	278,461			41.2	%
Loss from operations	(417,654		)	(149,659		)	(77.9	)%	(28.5	)%	267,995			179.1	%
Interest expense, net	(50,917		)	(53,703		)	(9.5	)%	(10.2	)%	(2,786		)	(5.2	)%
Other income (expense), net	2,107			(3,773		)	0.4	%	(0.7	)%	(5,880		)	(155.8	)%
Loss on extinguishment of debt	(3,177		)	—			(0.6	)%	—	%	3,177			100.0	%
Loss from continuing operations before income taxes	(469,641		)	(207,135		)	(87.6	)%	(39.4	)%	262,506			126.7	%
Income tax benefit	12,463			73,095			2.3	%	13.9	%	(60,632		)	(82.9	)%
Loss from continuing operations	(457,178		)	(134,040		)	(85.2	)%	(25.5	)%	323,138			241.1	%
Loss from discontinued operations, net of income taxes	(58,426		)	(98,251		)	(10.9	)%	(18.7	)%	(39,825		)	(40.5	)%
Net loss attributable to common stockholders	$	(515,604	)	$	(232,291	)	(96.1	)%	(44.2	)%	$	283,313		122.0	%

Non-Rental Revenue

Non-rental revenue consists of fees charged to customers for the sale and transportation of fresh water and saltwater by our fleet of logistics assets or through temporary or permanent water transport pipelines owned by us to customer sites for use in drilling and hydraulic fracturing activities and from customer sites to remove and dispose of flowback and produced water originating from oil and gas wells. Beginning in the third quarter of 2013, revenue also includes fees for solids management services following the Company's acquisition of a landfill in the Bakken Shale area. Non-rental revenue for the year ended December 31, 2014 was $463.4 million up $22.0 million from $441.4 million for the year ended December 31, 2013. The increase in revenues in our Rocky Mountain division was driven by improved pricing as our activity levels remained constant in

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2014 as compared to 2013, coupled with higher revenues from the solids management services. Some of these gains were offset by decreased logistics and disposal activity levels in the Southern division and, to a lesser extent, the Northeast division which were partially mitigated by increases in overall pricing. Additionally, our business in the Northeast was negatively impacted by severe winter weather earlier in 2014 as well as the interruption of the operations of our largest customer in the region due to a gas well explosion and fire.

Rental Revenue

Rental revenue consists of fees charged to customers for use of equipment owned by us over the term of the rental as well as other fees charged to customers for items such as delivery and pickup. Rental revenue for the year ended December 31, 2014 was $72.9 million, down $11.5 million, or 13.7%, from $84.4 million for the year ended December 31, 2013. The decrease was the result of lower utilization of the Company’s rental fleet primarily in the Rocky Mountain division driven by increased competition and customer efficiencies.

Direct Operating Expenses

Direct operating expenses for the year ended December 31, 2014 were $384.8 million, versus $379.2 million for the year ended December 31, 2013, an increase of less than 2%. Overall repairs and maintenance increased while fuel costs decreased. Compensation and benefits costs were lower in the Southern and Northeast divisions offset by the Rocky Mountain division. Additionally, we recorded a gain of $4.4 million related to the disposal of certain transportation assets in 2014 which was partially offset by a charge of $1.9 million related to a contract settlement. Direct operating expenses as a percentage of revenue was down slightly to 71.8% for the year ended December 31, 2014 from 72.1% in prior year period.

General and Administrative Expenses

General and administrative expenses for the year ended December 31, 2014 amounted to $66.8 million, down $17.4 million from $84.3 million for the year ended December 31, 2013. General and administrative expenses in the year ended December 31, 2014 include approximately $2.1 million of integration and rebranding costs which were completed during the year. Additionally, we recorded $6.3 million of legal and environmental expenses, including for the Texas Cases and Shareholder Litigation described in Note 16 of the Notes to Consolidated Financial Statements herein. For the year ended December 31, 2013, general and administrative expenses included charges totaling $24.6 million for the settlement of the 2010 Derivative Action and 2010 Class Action litigation, along with integration and rebranding costs of $8.2 million. Excluding the impact of these items, the higher general and administrative expenses in 2014 are chiefly attributable to increased personnel costs associated with higher staffing levels, costs related to the termination of an executive employment agreement and certain severance costs.

Depreciation and Amortization

Depreciation and amortization for the year ended December 31, 2014 was $85.9 million, down approximately $13.4 million from $99.2 million for the year ended December 31, 2013. The decrease resulted from the reduction in basis of certain long-lived assets, including write-downs to the freshwater pipeline, disposal wells and transportation equipment, totaling $111.9 million recorded in 2013.

Other, net

We recorded a net charge totaling approximately $0.9 million in the year ended December 31, 2013 to restructure our business in certain shale basins and improve overall operating efficiency.

Impairment of Long-Lived Assets

Long-lived asset impairment amounted to $112.4 million for the year ended December 31, 2014, and consisted of the write-off of our customer relationship intangible located in our Rocky Mountain division following impairment testing that resulted from triggering events occurring in the three months ended December 31, 2014, including the significant decline in oil and gas prices and the market price of the Company's common stock. Additionally, we recorded long-lived asset impairment charges of $111.9 million for the year ended December 31, 2013, which primarily consisted of write-downs totaling $108.4 million of the carrying values of our freshwater pipeline and certain other assets in the Haynesville, Eagle Ford and Barnett Shale basins. We also recognized a $3.5 million charge in 2013 to write down certain operating assets in connection with our decision to significantly curtail operations in the Tuscaloosa Marine Shale area. See also "Management's Discussion and Analysis of Financial Condition and Results of Operations - Impairment of Long-Lived Assets and Goodwill" and Note 8 of the Notes to Consolidated Financial Statements.

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Impairment of Goodwill

Goodwill impairment amounted to $304.0 million for the year ended December 31, 2014, and represents a $33.8 million, $66.9 million, and $203.3 million reduction of the carrying value of goodwill associated with our Northeast, Southern and Rocky Mountain divisions, respectively, following impairment testing that resulted from triggering events occurring throughout the year ended December 31, 2014, including the significant decline in oil and gas prices and the market price of the Company's common stock, as well as a redefinition of our reporting unit structure. No goodwill impairment was recorded for the year ended December 31, 2013 relating to these entities. See also "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Impairment of Long-Lived Assets and Goodwill" and Note 8 of the Notes to Consolidated Financial Statements.

Interest Expense, net

Interest expense, net during the year ended December 31, 2014 was $50.9 million compared to $53.7 million for the year ended December 31, 2013. The decrease in interest expense was primarily attributable to a lower average interest rate on the ABL Facility as compared to the Amended Revolving Credit Facility, and reduced amortization of deferred financing costs as a result of the write-off of a portion of such costs associated with the Amended Revolving Credit Facility (see “Loss on Extinguishment of Debt” below). These decreases were partially offset by higher average borrowings on the ABL Facility during the year ended December 31, 2014 compared to borrowings under the previous credit facility during the year ended December 31, 2013.

Other Income (Expense), net

Other income (expense), net was $2.1 million of income for the year ended December 31, 2014 compared to $3.8 million of expense for the year ended December 31, 2013. The year-to-year change in other income (expense), net was primarily attributable to a $2.0 million gain related to a change in the fair value of our Heckmann Water Resources (CVR), Inc. contingent consideration obligation (Note 11). Additionally, during the year ended December 31, 2013 we recognized a $3.8 million write-down to our cost-method investment in Underground Solutions, Inc. ("UGSI") (Note 18) and a $1.0 million loss incurred in the first quarter of 2013 as a result of a “make-whole” agreement with the seller of TFI in connection with a decline in the value of shares of the Company’s common stock held in escrow following the acquisition.

Loss on Extinguishment of Debt

In February 2014, we entered into the ABL Facility and wrote-off a portion of the unamortized deferred financing costs associated with our Amended Revolving Credit Facility of approximately $3.2 million during the year ended December 31, 2014.

Income Taxes

The income tax benefit for the year ended December 31, 2014 was $12.5 million (a 2.7% effective rate) compared to $73.1 million (effective rate of 35.3% ) in the prior year. The lower effective tax benefit rate in 2014 is primarily the result of the tax impact of the impairment of goodwill and an increased valuation allowance related to deferred tax assets.

We have significant deferred tax assets, consisting primarily of net operating losses (“NOLs”), which have a limited life,

generally expiring between the years 2029 and 2034. Management regularly assesses the available positive and negative

evidence to estimate if sufficient future taxable income will be generated to use the existing deferred tax assets. A significant

piece of objective negative evidence evaluated was the cumulative losses incurred this year and in recent years. Such objective

evidence limits the ability to consider other subjective evidence such as our projections for future taxable income.

In light of our continued losses, at December 31, 2014, we determined that our deferred tax liabilities (excluding net deferred tax liabilities included in discontinued operations which are expected to not be available after the sale of the stock of TFI) were not sufficient to fully realize our deferred tax assets and, as a result, a valuation allowance was required against a portion of our deferred tax assets. Accordingly, we have recorded a valuation allowance of approximately $70.3 million as of December 31, 2014.

Loss from Discontinued Operations

Loss from discontinued operations in the years ended December 31, 2014 and 2013 represents the financial results of TFI, which comprises our industrial solutions business segment. Such loss, which is presented net of income taxes, was $58.4 million and $98.3 million for the years ended December 31, 2014 and 2013, respectively. The 2014 loss includes impairment charges of $74.4 million. The 2013 loss includes a goodwill impairment charge of $98.5 million in the quarter ended September 30, 2013 and $12.3 million of depreciation and amortization expense. See Note 20 of the Notes to Consolidated Financial Statements herein for additional information.

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Results of Operations

Year Ended December 31, 2013 Compared to the Year Ended December 31, 2012



	Year Ended						Percent of Revenue
	December 31,						December 31,				Increase (Decrease)
	2013			2012			2013		2012		2013 versus 2012
Non-rental revenue	$	441,421		241,230			83.9	%	94.0	%	$	200,191		83.0	%
Rental revenue	84,395			15,441			16.1	%	6.0	%	68,954			446.6	%
Total revenue	525,816			256,671			100.0	%	100.0	%	269,145			104.9	%
Costs and expenses:
Direct operating expenses	379,160			197,832			72.1	%	77.1	%	181,328			91.7	%
General and administrative expenses	84,280			42,742			16.0	%	16.7	%	41,538			97.2	%
Depreciation and amortization	99,236			47,641			18.9	%	18.6	%	51,595			108.3	%
Impairment of long-lived assets	111,900			6,030			21.3	%	2.3	%	105,870			1,755.7	%
Other, net	899			—			0.2	%	—	%	899			100.0	%
Total costs and expenses	675,475			294,245			128.5	%	114.6	%	381,230			129.6	%
Loss from operations	(149,659		)	(37,574		)	(28.5	)%	(14.6	)%	112,085			298.3	%
Interest expense, net	(53,703		)	(26,607		)	(10.2	)%	(10.4	)%	27,096			101.8	%
Other income (expense), net	(3,773		)	(2,538		)	(0.7	)%	(1.0	)%	1,235			48.7	%
Loss on extinguishment of debt	—			(2,638		)	—	%	(1.0	)%	(2,638		)	(100.0	)%
Loss from continuing operations before income taxes	(207,135		)	(69,357		)	(39.4	)%	(27.0	)%	137,778			198.7	%
Income tax benefit	73,095			62,760			13.9	%	24.5	%	10,335			16.5	%
Loss from continuing operations	(134,040		)	(6,597		)	(25.5	)%	(2.6	)%	127,443			1,931.8	%
(Loss) income from discontinued operations, net of income taxes	(98,251		)	9,124			(18.7	)%	3.6	%	107,375			(1,176.8	)%
Net (loss) income attributable to common stockholders	$	(232,291	)	$	2,527		(44.2	)%	1.0	%	$	234,818		(9,292.4	)%

Non-Rental Revenue

Non-rental revenue for the year ended December 31, 2013 was $441.4 million, up $200.2 million from $241.2 million in the preceding year. The increase is primarily attributable to the merger with Power Fuels, which accounted for approximately $212.1 million of the year-over-year increase. A total of $2.3 million in fees were recognized for the transportation and landfill disposal of oilfield solid wastes beginning in the third quarter of 2013, following the acquisition of Ideal Oilfield Disposal, LLC in North Dakota. Additionally, strong growth in the Marcellus and Utica shale areas was offset by year-over-year revenue declines in the Haynesville, Barnett and Eagle Ford Shale areas. We continued to experience pricing pressure during 2013 due to competitive conditions across many of the shale areas in which we operate. Beginning in 2012, in some regions of our business, shifts in customer procurement practices, which effectively transfer more service efficiency risk to us, resulted in pricing and margin erosion. In terms of revenue mix, revenue from shale areas predominantly driven by natural gas production declined on a year-over-year basis, while revenue derived from basins where the primary resource is oil increased markedly due to the addition of Power Fuels in the oil-rich Bakken Shale area.

Rental Revenue

Rental revenue for the year ended December 31, 2013 was $84.4 million, versus $15.4 million for 2012, with the increase being nearly entirely attributable to Power Fuels. Prior to the Power Fuels merger, our rental revenue consisted primarily of tank rentals, whereas Power Fuels has a more comprehensive rental equipment service offering.

Direct Operating Expenses

Direct operating expense was $379.2 million for the year ended December 31, 2013, up $181.3 million from $197.8 million from the year ended December 31, 2012. Consistent with the increase in revenue, the increase in the overall cost of revenues

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was primarily attributable to the full-year impact in 2013 of Power Fuels, which accounted for approximately 183.4 million of the year-over-year increase.

General and Administrative Expenses

General and administrative expenses increased to $84.3 million in the year ended December 31, 2013 from $42.7 million for the comparable 2012 period. The higher costs in 2013 reflect a number of factors, including: (a) incremental general & administrative expenses amounting to $13.9 million related to the addition of Power Fuels; (b) charges totaling $24.6 million for the settlement of the 2010 Derivative Action and 2010 Class Action litigation described in Note 16 of Notes to Consolidated Financial Statements; (c) approximately $8.2 million of integration and rebranding costs following the Power Fuels merger in late 2012 and the Company’s rebranding in early 2013; and (d) increased personnel costs associated with higher staffing levels.

Depreciation and Amortization

Depreciation and amortization for the year ended December 31, 2013 was $99.2 million, up $51.6 million, or 108.3%, from $47.6 million in the prior year period. The overall increase included higher depreciation expense of $38.7 million, substantially all of which was attributable to assets acquired in the Power Fuels transaction. Additionally, the increase in amortization expense is due to the full-year impact in 2013 of the large increase in intangible assets acquired in connection with the acquisitions completed in 2012, including Power Fuels. The largest components of newly acquired intangible assets were customer relationships valued at approximately $145.0 million of which $16.5 million was amortized to expense during 2013.

Impairment of Long-Lived Assets

Long-lived asset impairment was $111.9 million and $6.0 million for the years ended December 31, 2013 and 2012, respectively. The 2013 impairment charge represents a write-down of the carrying values of certain intangible assets, disposal wells, motor vehicles, trailers, rental equipment and our freshwater pipeline in the Haynesville, Eagle Ford and Barnett Shale basins, primarily in the three-month period ended September 30, 2013. Due to impairment indicators present at June 30, 2013, we commenced a company-wide impairment review of our long-lived assets during the third quarter of 2013. Long-lived assets were grouped at the shale basin level for purposes of assessing their recoverability, which is the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. For reporting units in which the carrying value of the long-lived group exceeded the undiscounted future cash flows associated with the continued use and disposition of the asset group, we recorded an impairment charge for the amount by which the carrying values of the asset groups exceeded their respective fair values.

Other, net

During 2013, we recorded a net charge of approximately $0.9 million to restructure our operations in certain shale basins and improve overall operating efficiencies. The charge included severance and termination benefits and other costs in connection with the substantial curtailment of our activities in the Tuscaloosa Marine Shale.

Interest Expense, net

Interest expense, net for the year ended December 31, 2013 was $53.7 million as compared to $26.6 million in the prior year. The increase of $27.1 million in interest expense during 2013 included $19.0 million of additional interest on the $250.0 million and $150.0 million tranches of the 2018 Notes issued in April 2012 and November 2012, respectively, the proceeds of which were used to partially finance the acquisitions of TFI and Power Fuels. In addition, we amortized $4.5 million of deferred financing costs to interest expense during the year ended December 31, 2013, as compared to $1.8 million in the previous year.

Other Income (Expense), net

Other expense, net was $3.8 million for the year ended December 31, 2013 as compared to $2.5 million for the year ended December 31, 2013, and consisted primarily of a $3.8 million write-down to our investment in UGSI. See Note 18 of Notes to Consolidated Financial Statements for additional information. In addition, we incurred an approximate $1.0 million loss in 2013 in connection with a decline in the value of certain shares placed in escrow upon the closing of the TFI acquisition. Pursuant to the terms and conditions of the stock purchase agreement related to the TFI acquisition, the Company was required to indemnify the sellers for a decline in the value of escrowed shares after the one-year anniversary of the TFI acquisition and upon liquidation of the escrowed shares.

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Income Taxes

Our income tax benefit for the year ended December 31, 2013 was $73.1 million, resulting in an effective tax rate of 35.3%. Our income tax benefit for the year ended December 31, 2012 was $62.8 million, an effective rate of 90.4%. Our effective income tax benefit rate for the year ended December 31, 2012 differed from the federal statutory rate of 35.0% primarily due to reductions in previously-established valuation allowances due to acquired sources of taxable income in the form of deferred tax liabilities resulting from the acquisitions in 2012.

In 2013, we established a valuation allowance of $1.6 million to offset deferred tax assets associated with the book write-down of certain investments that would generate capital losses if sold at book value. Additionally, we maintained a valuation allowance of $4.5 million at December 31, 2013 to offset deferred tax assets associated with certain state net operating losses that we do not believe will be realized prior to their expiration.

(Loss) Income from Discontinued Operations

(Loss) income from discontinued operations in the years ended December 31, 2013 and 2012 represents the financial results of TFI, which comprises our industrial solutions business segment. Such income or loss, which is presented net of income taxes, was a loss of approximately $98.3 million for the year ended December 31, 2013 and income for the period ended December 31, 2012 of $9.2 million (since the acquisition of TFI on April 10, 2012). The 2013 loss includes a goodwill impairment charge of $98.5 million in the quarter ended September 30, 2013 and $12.3 million of depreciation and amortization expense. See Note 20 of the Notes to Consolidated Financial Statements herein for additional information.

Liquidity and Capital Resources

Cash Flows and Liquidity

At December 31, 2014, our total indebtedness was $597.9 million. We have incurred operating losses of $457.2 million, $134.0 million and $6.6 million for the years ended December 31, 2014, 2013 and 2012, respectively, including impairments of goodwill and long-lived assets. At December 31, 2014, we had cash and cash equivalents of $13.4 million and $25.9 million of net availability under the ABL Facility. Given the current macro environment and oil and gas prices, we anticipate declining revenues in 2015, with corresponding reductions in costs from operations. In this environment, we expect sufficient availability under the ABL Facility to meet our operating needs. Our financing strategy includes using the proceeds from the planned sale of TFI, closely monitoring and lowering our operating costs and capital spending, and managing our working capital to enhance liquidity. Based on our current expectations and projections, we believe that our available cash, together with availability under the ABL Facility, will be sufficient to fund our operations, capital expenditures and interest payments under our debt obligations through at least the first quarter of 2016, which is our current, one-year forecast period.

The following table summarizes our sources and uses of cash from continuing operations for the years ended December 31, 2014, 2013 and 2012 (in thousands):



	Year Ended December 31,
Net cash provided by (used in):	2014			2013			2012
Operating activities	$	17,376		66,668			25,078
Investing activities	(45,539		)	(52,788		)	(388,540		)
Financing activities	32,747			(19,873		)	298,044
Net increase (decrease) in cash and cash equivalents	$	4,584		$	(5,993	)	$	(65,418	)

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As of December 31, 2014, we had cash and cash equivalents of $13.4 million, an increase of $4.6 million from December 31, 2013. Generally, we manage our cash flow by drawing on our ABL Facility to fund short-term cash needs and by using any excess cash, after considering our working capital and capital expenditure needs, to pay down the outstanding balance of our ABL Facility.

Operating Activities — Net cash provided by operating activities was $17.4 million for the year ended December 31, 2014. The net loss from continuing operations, after adjustments for non-cash items, provided cash of $42.0 million, up significantly from the $26.0 million generated in 2013, as described below. Changes in operating assets and liabilities used $24.7 million primarily due to an increase in accounts receivable and a decrease in accounts payable which was partially offset by a decrease in prepaid expenses and other receivables. The non-cash items and other adjustments included $304.0 million in impairment of goodwill, $112.4 million in impairment of long-lived assets, $85.9 million of depreciation and amortization of intangible assets and the loss on extinguishment of debt of $3.2 million, partially offset by a deferred income tax benefit of $12.6 million and a $4.8 million gain on disposal of plant, property and equipment.

Net cash provided by operating activities was $66.7 million for the year ended December 31, 2013. The net loss from continuing operations, after adjustments for non-cash items, provided cash of $26.0 million. Changes in operating assets and liabilities provided an additional $40.7 million and were largely the result of an increase in accounts payable and accrued liabilities and a decrease in accounts receivable. The non-cash items and other adjustments included $99.2 million of depreciation and amortization of intangible assets, $111.9 million of impairment of property, plant and equipment and the write-down of cost method investments of $4.3 million, partially offset by a deferred income tax benefit of $68.6 million.

Net cash provided by operating activities was $25.1 million for the year ended December 31, 2012. The net loss from continuing operations, after adjustments for non-cash items, provided cash of $6.5 million. Changes in operating assets and liabilities provided an additional $18.5 million and were largely the result of an increase in accounts payable and accrued liabilities and a decrease in accounts receivable. The non-cash items and other adjustments included $47.6 million of depreciation and amortization of intangible assets, $6.0 million of impairment of property, plant and equipment and the loss on extinguishment of debt of $2.6 million, partially offset by a deferred income tax benefit of $56.7 million.

Investing Activities — Net cash used in investing activities was $45.5 million for the year ended December 31, 2014, which primarily consisting of $55.7 million of purchases of property, plant and equipment, partially offset by $10.2 million of proceeds from the sale of property, plant and equipment.

Net cash used in investing activities was $52.8 million for the year ended December 31, 2013 and consisted primarily of $46.6 million of capital expenditures, $10.6 million for acquisitions, net of cash acquired. These capital outlays were partially offset by $4.4 million in proceeds from the settlement of the Power Fuels working capital adjustment and sales of property and equipment.

Net cash used in investing activities was $388.5 million for the year ended December 31, 2012. The higher investment activity in 2012 was primarily attributable to payments made in connection with the Power Fuels merger and the TFI acquisition, which totaled $127.3 million and $229.6 million, respectively. Excluding acquisitions, cash required to support capital spending in 2012 was marginally lower than in 2013 and 2012.

Financing Activities — Net cash provided by financing activities was $32.7 million for the year ended December 31, 2014 and was comprised of $40.2 million of net borrowings under our credit facilities, partially offset by $5.3 million of payments under capital leases and notes payable, $1.0 million of payments for deferred financing costs and $1.2 million of other cash requirements.

Net cash used in financing activities was $19.9 million for the year ended December 31, 2013 and consisted of $11.0 million of net payments under our prior credit facility, $5.4 million of payments under capital leases and notes payable, $0.9 million of payments on deferred financing costs and $2.6 million in other disbursements.

Net cash provided by financing activities was $298.0 million for the year ended December 31, 2012 consisting of $399.0 million of proceeds, net of original issue discounts, received in connection with the issuance of the 2018 Notes, $147.0 million of net proceeds drawn from our Amended Revolving Credit Facility and of the 2018 Notes and $74.4 million of cash proceeds received in connection with an equity offering of our common shares. Cash provided by financing activities was partially offset by a $140.2 million repayment of our old credit facility, a $150.4 million repayment of debt acquired in connection with the Power Fuels merger and $26.2 million of deferred financing fees associated with the 2018 Notes and the Amended Revolving Credit Facility. The higher net cash provided by financing activities was attributable to the larger funding needs to support the TFI and Power Fuels acquisitions in 2012.

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Capital Expenditures

Cash required for capital expenditures (related to continuing operations) for the year ended December 31, 2014 totaled $55.7 million compared to $46.6 million for the year ended December 31, 2013. Capital expenditures for the year ended December 31, 2014 included payments for a thermal desorption system as part of the expansion of solids treatment capabilities at our Bakken Shale landfill site and other equipment. Capital expenditures in the year ended December 31, 2013 included capital outlays for our produced water pipeline in the Haynesville Shale area. Historically, a portion of our transportation-related capital requirements were financed through capital leases, which are excluded from the capital expenditures figures cited in the preceding sentences. Such equipment additions under capital leases totaled approximately $5.8 million for the year ended December 31, 2013 and there were $0.3 million in fleet purchases under capital leases for the year ended December 31, 2014. We continue to focus on improving the utilization of our existing assets and optimizing the allocation of resources in the various shale areas in which we operate. Our capital expenditures program is subject to market conditions, including customer activity levels, commodity prices, industry capacity and specific customer needs. We may also incur additional capital expenditures for acquisitions. Our planned capital expenditures for 2015, as well as any growth initiatives or acquisitions we choose to pursue, are expected to be financed through cash flow from operations, borrowings under existing or new credit facilities, issuances of debt or equity, capital leases, other financing structures, or a combination of the foregoing.

Revolving Credit Agreement

In February 2014, we entered into a new asset-based revolving credit facility (“ABL Facility”) with Wells Fargo Bank as Administrative Agent and other lenders which amended and replaced our Amended Revolving Credit Facility. Initially, the ABL Facility provided a maximum credit amount of $200.0 million, with an increase of up to $225.0 million through a $25.0 million accordion feature. Initial borrowings under the ABL Facility were used to refinance amounts outstanding under the Amended Revolving Credit Facility and fund certain related fees and expenses. In March 2014, we expanded the ABL Facility to increase the maximum availability from $200.0 million to $245.0 million and also increased the accordion feature from $25.0 million to $50.0 million. The terms and pricing of the facility remained the same and were unaffected by the upsizing of the facility. The ABL Facility is being used to support ongoing working capital needs and other general corporate purposes, including growth initiatives, and may be utilized for the potential repurchase of a portion of our currently outstanding 2018 Notes. The ABL Facility, which matures at the earlier of five years from the closing date or 90 days prior to the maturity of other material indebtedness including the 2018 Notes, is secured by substantially all of our assets.

Indebtedness

We are highly leveraged and a substantial portion of our liquidity needs result from debt service requirements and from funding our costs of operations and capital expenditures, including acquisitions. As of December 31, 2014, we had $597.9 million ($597.3 million net of unamortized discount and premium) of indebtedness outstanding, consisting of $400.0 million of 2018 Notes, $183.1 million under the ABL Facility, and $14.9 million of capital leases and installment notes payable for vehicle financings. As of December 31, 2014, our borrowing base would support additional borrowings under the ABL Facility of up to $25.9 million. As of March 13, 2015, net availability under the ABL Facility was approximately $27.2 million.

Financial Covenants and Borrowing Limitations

The ABL Facility contains certain financial covenants that require us to maintain a senior leverage ratio and, upon the occurrence of certain specified conditions, a fixed charge coverage ratio as well as certain customary limitations on our ability to, among other things, incur debt, grant liens, make acquisitions and other investments, make certain restricted payments such as dividends, dispose of assets or undergo a change in control. The senior leverage ratio is calculated as the ratio of senior secured debt to adjusted EBITDA (which includes net (loss) income loss plus certain items such as interest, taxes, depreciation, amortization, impairment charges, stock-based compensation and other adjustments as defined in the indenture), and is limited to 3.0 to 1.0. Our $400.0 million of 2018 Notes are not secured and thus are excluded from the calculation of this ratio. The fixed charge coverage ratio, which only applies if excess availability under the ABL Facility falls below 12.5% of the maximum revolver amount, requires the ratio of adjusted EBITDA (as defined) less capital expenditures to fixed charges (as defined) to be at least 1.1 to 1.0. The senior leverage ratio and fixed charge coverage ratio covenants could have the effect of limiting our availability under the ABL Facility, as additional borrowings would be prohibited if, after giving pro forma effect thereto, we

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would be in violation of either such covenant. As of December 31, 2014, we remained in compliance with our debt covenants and the availability was $56.5 million; however, our ratio of adjusted EBITDA to fixed charges was less than 1.1 to 1.0 (as calculated pursuant to the ABL Facility). As such, our net availability was reduced by 12.5% of the maximum revolver amount, or $30.6 million, resulting in approximately $25.9 million of net availability as of December 31, 2014.

Planned Sale of TFI

In March 2014, we entered into a Stock Purchase Agreement with respect to the sale of 100% of the equity of TFI to a prospective acquirer in exchange for $165.0 million in cash and $10.0 million in stock. In June 2014, we entered into an Amended and Restated Stock Purchase Agreement which, among other items, extended the closing date of the transaction. In August 2014, the agreement was terminated pursuant to the terms of the agreement. Subsequent to the termination of the agreement, we engaged in negotiations with other potential acquirers. In September 2014, Nuverra entered into a non-binding letter of intent for the sale of TFI to a new prospective acquirer in exchange for a combination of cash and common stock of the acquirer. Definitive transaction documentation was not executed with the new prospective acquirer. On February 4, 2015, Nuverra entered into a definitive agreement with Safety-Kleen, Inc. ("Safety-Kleen"), a subsidiary of Clean Harbors, Inc., whereby Safety-Kleen will acquire TFI for $85 million in an all-cash transaction, subject to working capital adjustments. We

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intend to use the final net sales proceeds to reduce outstanding indebtedness under the ABL Facility or for other general corporate purposes.

Contractual Obligations

The following table details our contractual cash obligations as of December 31, 2014 (in thousands). See Note 15 of the Notes to Consolidated Financial Statements for additional information.



	Payments due by Period
	Total		Less than 1 Year		1-3 Years		3-5 Years		More than 5 Years
Debt obligations including capital leases (1)	$	597,936	$	4,931	$	8,655	$	584,350	$	—
Interest on debt and capital leases (2)	144,758		44,568		88,625		11,565		—
Operating leases (3)	19,226		5,937		7,883		3,202		2,204
Capital expenditures (4)	6,148		6,148		—		—		—
Contingent consideration (5)	9,824		8,500		1,324		—		—
Asset retirement obligation (6)	5,334		401		133		200		4,600
Total	$	783,226	$	70,485	$	106,620	$	599,317	$	6,804


(1)	Principal payments are reflected when contractually required.


(2)	Estimated interest on debt for all periods presented is calculated using interest rates available as of December 31, 2014 and includes fees for the unused portion of our Amended Revolving Credit Facility. In February 2014, the Amended Revolving Credit Facility was replaced with the ABL Facility. See Note 10 of the Notes to Consolidated Financial Statements for additional information.


(3)	Represents operating leases primarily for facilities, vehicles and rental equipment.


(4)	Represents remaining amounts due for the purchase of thermal desorption equipment in connection with the expansion of solids treatment capabilities at our North Dakota landfill site and amounts due for the purchase of equipment related to the pipeline infrastructure located in the Bakken Shale basin.


(5)	Represents contingent consideration payments in connection with certain acquisitions, which are payable in shares of the Company’s common stock or cash at the Company’s discretion (Note 11).


(6)	Represents estimated future costs related to the closure and/or remediation of the Company’s disposal wells and landfill.

Off Balance Sheet Arrangements

As of December 31, 2014, we did not have any material off-balance-sheet arrangements, as defined in Item 303(a)(4)(ii) of SEC Regulation S-K.

EBITDA

As a supplement to the financial statements in this Annual Report on Form 10-K, which are prepared in accordance with GAAP, we also present EBITDA. EBITDA is consolidated net income (loss) from continuing operations before net interest expense, income taxes and depreciation and amortization. We present EBITDA because we believe this information is useful to financial statement users in evaluating our financial performance. We also use EBITDA to evaluate our financial performance, make business decisions, including developing budgets, managing expenditures, forecasting future periods, and evaluating capital structure impacts of various strategic scenarios. EBITDA is not a measure of performance calculated in accordance with GAAP, may not necessarily be indicative of cash flow as a measure of liquidity or ability to fund cash needs, and there are material limitations to its usefulness on a stand-alone basis. EBITDA does not include reductions for cash payments for our obligations to service our debt, fund our working capital and pay our income taxes. In addition, certain items excluded from EBTIDA such as interest, income taxes, depreciation and amortization are significant components in understanding and assessing our financial performance. All companies do not calculate EBITDA in the same manner and our presentation may not be comparable to those presented by other companies. Financial statement users should use EBITDA in addition to, and not as an alternative to, net income (loss) from continuing operations as defined under and calculated in accordance with GAAP.

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The table below provides a reconciliation between loss from continuing operations, as determined in accordance with GAAP, and EBITDA (in thousands):



	Year Ended December 31,
	2014			2013			2012
Loss from continuing operations	$	(457,178	)	$	(134,040	)	$	(6,597	)
Depreciation of property, plant and equipment	68,710			78,812			40,130
Amortization of intangible assets	17,170			20,424			7,511
Interest expense, net	50,917			53,703			26,607
Income tax benefit	(12,463		)	(73,095		)	(62,760		)
EBITDA	$	(332,844	)	$	(54,196	)	$	4,891

Critical Accounting Policies and Estimates

Our discussion and analysis of financial condition and results of operations are based upon our audited consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these financial statements requires management to make estimates and judgments that affect the reported amounts in the consolidated financial statements and accompanying notes. Actual results, however, may materially differ from our calculated estimates.

We believe the following critical accounting policies affect the more significant judgments and estimates used in the preparation of our financial statements and changes in these judgments and estimates may impact future results of operations and financial condition. For additional discussion of our accounting policies see Note 3 of the Notes to Consolidated Financial Statements included in this Annual Report on Form 10-K.

Allowance for Doubtful Accounts

Accounts receivable are recognized and carried at the original invoice amount less an allowance for doubtful accounts. We provide an allowance for doubtful accounts to reflect the expected uncollectability of trade receivables for both billed and unbilled receivables on our rental and non-rental revenues. We perform ongoing credit evaluations of prospective and existing customers and adjust credit limits based upon payment history and the customer’s current credit worthiness, as determined by a review of their current credit information. In addition, we continuously monitor collections and payments from customers and maintain a provision for estimated credit losses based upon historical experience and any specific customer collection issues that have been identified. Inherent in the assessment of the allowance for doubtful accounts are certain judgments and estimates including, among others, the customer’s willingness or ability to pay, the Company’s compliance with customer invoicing requirements, the effect of general economic conditions and the ongoing relationship with the customer. Additionally, if the financial condition of a specific customer or our general customer base were to deteriorate, resulting in an impairment of their ability to make payments, additional allowances may be required. Accounts receivable are presented net of allowances for doubtful accounts of approximately $7.6 million, $5.5 million and $6.1 million at December 31, 2014, 2013 and 2012 respectively.

Accounting for Business Combinations

We allocate the purchase price of acquisitions to the assets acquired and liabilities assumed based on their estimated fair value at the date of acquisition. Any purchase price in excess of the net fair value of the assets acquired and liabilities assumed is allocated to goodwill. The fair value of certain of our assets and liabilities is determined by (1) using estimates of replacement costs for tangible fixed assets and (2) using discounted cash flow valuation methods for estimating identifiable intangibles such as customer contracts and customer relationship intangibles (Income Approach). We believe the assumptions used in our discounted cash flow analyses are appropriate and result in reasonable estimates of the fair value of assets acquired and liabilities assumed at the time of each acquisition. We further believe the most significant assumptions used in our analyses are the anticipated margins and overall profitability. However, we may not meet our revenue and profitability targets, working capital needs and capital expenditures may be higher than forecast, changes in credit or equity markets may result in changes to our discount rate and general business conditions may result in changes to our terminal value assumptions used in the estimate of fair value. The purchase price allocation requires subjective estimates that, if incorrectly estimated, could be material to our consolidated financial statements including the amount of depreciation and amortization expense recognized. The determination of the final purchase price allocation could extend over several quarters resulting in the use of preliminary estimates that are subject to adjustment until finalized. The income approach used to value identifiable intangible assets utilizes forward-looking assumptions and projections, but considers factors unique to our businesses and related long-range plans that may not be comparable to other companies and that are not yet publicly available. The determination of fair value under the income

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approach requires significant judgment on our part. Our judgment is required in developing assumptions about future revenue growth, projected capital expenditures, changes in working capital, general and administrative expenses, attrition rates, demand for our products and services and the weighted average cost of capital. The estimated future cash flows and projected capital expenditures used under the income approach are based on our business plans and forecasts, which consider historical results adjusted for future expectations. Future expectations include assumptions related to including economic trends, market conditions and other factors which are beyond management’s control.

Contingent Consideration

Contingent consideration primarily consists of earnout obligations in connection with business combinations that are payable by us to the former owners of an acquiree as part of the exchange for control of the acquiree if specified future events occur or conditions are met. Contingent consideration is recorded at the acquisition date fair value, which is measured at the present value of the consideration expected to be transferred. The fair value of contingent consideration is remeasured at the end of each reporting period with the change in fair value recognized as other income (expense) in the consolidated statements of operations. Estimates of the fair value of contingent consideration are impacted by changes to cash flow projections, results of operations, growth rates, discount rates and probabilities of achieving future milestones. Contingent consideration obligations were $9.8 million at December 31, 2014, of which approximately $9.3 million and $0.5 million were classified as current and long-term, respectively, in our Consolidated Balance Sheets.

Impairment of Long-Lived Assets and Intangible Assets with Finite Useful Lives

We review long-lived assets including intangible assets with finite useful lives for impairment whenever events or changes in circumstances indicate the carrying value of a long-lived asset (or asset group) may not be recoverable. If an impairment indicator is present, we evaluate recoverability by comparing the estimated future cash flows of the asset group, on an undiscounted basis, to their carrying values. The assets group represents the lowest level for which identifiable cash flows are largely independent of the cash flows of other groups of assets and liabilities. If the undiscounted cash flows exceed the carrying value, the asset group is recoverable and no impairment is present. If the undiscounted cash flows are less than the carrying value, the impairment is measured as the difference between the carrying value and the fair value of the long-lived asset (or asset group). Our determination that an event or change in circumstance has occurred potentially indicating the carrying amount of an asset (or asset group) may not be recoverable generally includes but is not limited to one or more of the following: (1) a deterioration in an asset’s financial performance compared to historical results, (2) a shortfall in an asset’s financial performance compared to forecasted results, (3) changes affecting the utility and estimated future demands for the asset, (4) a significant decrease in the market price of an asset, and (5) a current expectation that a long-lived asset will be sold or disposed of significantly before the end of its previously estimated useful life and a significant adverse change in the extent or manner in which a long-lived asset (asset group) is being used or in its physical condition.

During the year ended December 31, 2014, long-lived asset impairment expense was $112.4 million. The impairment charge recognized consisted of write-down to the carrying value of our customer relationship intangible associated with the Rocky Mountain division following impairment testing that resulted from certain triggering events including the fourth quarter decline in oil and gas prices and the continued market price decline of the Company's common stock during the year ended December 31, 2014. During the year ended December 31, 2013, long-lived asset impairment expense was $111.9 million. The impairment charge recognized consisted of write-downs to the carrying values of certain disposal wells, motor vehicles, trailers, rental equipment and its freshwater pipeline; including customer relationship and disposal permit intangibles associated with the Haynesville, Eagle Ford and Barnett Shale basins. During the year ended December 31, 2012, we recognized a $3.7 million impairment loss on three saltwater disposal wells primarily in the Haynesville Shale area. We tested the disposal wells for recoverability after the wells developed technical problems which required us to suspend their use. Additionally, we also recognized a $2.4 million impairment loss related to the write-down of a customer relationship intangible associated with a portion of a prior business acquisition. The impairment review and associated write-down was triggered by management’s updated assessment of the reduced growth prospects of the business and the related impact on its expected financial performance. We could recognize future impairments to the extent adverse events or changes in circumstances result in conditions in which long-lived assets are not recoverable. See Note 8 of the Notes to Consolidated Financial Statements for additional information.

Goodwill

Goodwill represents the excess of the purchase price over the fair value of the net assets of businesses acquired. In accordance with GAAP, goodwill is not amortized. Instead, goodwill is required to be tested for impairment annually and between annual tests if events or circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. The goodwill impairment test involves a two-step process; however, if after assessing the totality of events or circumstances, an entity determines it is not more likely than not that the fair value of a reporting unit is less than its carrying

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amount, then performing the two-step impairment test is unnecessary. In evaluating whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount, an entity shall assess all relevant events and circumstances indicating whether it is more likely than not that the fair value of a reporting unit is less than its carrying value, which include but are not limited to one or more of the following: (1) macroeconomic conditions such as a deterioration in general economic conditions, limitations on accessing capital or other developments in equity and capital markets, (2) industry and market conditions such as a deterioration in the environment in which an entity operates, an increased competitive environment, a change in the market for an entity, (3) cost factors such as increases in raw materials or labor, (4) overall financial performance such as negative or declining cash flows or a decline in actual revenue or earnings compared with projected results or relevant prior periods, (5) entity specific events such as changes in management, key personnel, strategy, or customers, (6) events affecting a reporting unit such as a change in the composition or carrying amount of its net assets, or a more-likely-than not expectation of selling or disposing of all, or a portion, of a reporting unit and (7) a sustained decrease in share price.

In the event a determination is made that it is more likely than not that the fair value of a reporting unit is less than its carrying value, the first step of the two-step process must be performed. The first step of the test, used to identify potential impairment, compares the estimated fair value of a reporting unit with its carrying amount, including goodwill. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is not considered to be impaired and the second step of the impairment test is unnecessary. If the carrying amount of a reporting unit exceeds its fair value, the second step of the impairment test must be performed to measure the amount of the impairment loss, if any. The second step of the goodwill impairment test compares the implied fair value of reporting unit goodwill with the carrying amount of that goodwill. The implied fair value of goodwill is determined in the same manner as goodwill recognized in a business combination. If the carrying amount of the reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to that excess. An entity has 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.

on the results of the step-one goodwill impairment review, we concluded the fair value of the Rocky Mountain

division exceeded our carrying amount by approximately 14% and accordingly, the second step of the impairment test was not

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the re-allocated goodwill exceeded their implied fair values. Accordingly, we recognized a charge of $100.7 million ($66.9 million in the Southern division and $33.8 million in the Northeast division) during the three months ended September 30, 2014, which is characterized as "Impairment of goodwill" in our consolidated statement of operations.

Income Taxes and Valuation of Deferred Tax Assets

We are subject to federal income taxes and state income taxes in those jurisdictions in which we operate. We exercise judgment with regard to income taxes in interpreting whether expenses are deductible in accordance with federal income tax and state income tax codes, estimating annual effective federal and state income tax rates and assessing whether deferred tax assets are, more likely than not, expected to be realized. The accuracy of these judgments impacts the amount of income tax expense we recognize each period.

With regard to the valuation of deferred tax assets, we record valuation allowances to reduce net deferred tax assets to the amount considered more likely than not to be realized. All available evidence is considered to determine whether, based on the weight of that evidence, a valuation allowance for deferred tax assets is needed.

Future realization of the tax benefit of an existing deductible temporary difference or carryforward ultimately depends on the existence of sufficient taxable income of the appropriate character (for example ordinary income or capital gain) within the carryback or carryforward periods available under the tax law. We have had significant pretax losses in recent years. Accordingly, we do not have income in carryback years. These cumulative losses also present significant negative evidence towards the likelihood of income in carryforward periods.

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Future reversals of existing taxable temporary differences are another source of taxable income that is used in this analysis. As a result, deferred tax liabilities in excess of deferred tax assets generally will provide support for recognition of deferred tax assets. However, most of our deferred tax assets are associated with net operating loss (NOL) carryforwards, which statutorily expire after a specified number of years; therefore, we compare the estimated timing of these taxable timing difference reversals with the scheduled expiration of our NOL carryforwards, considering any limitations on use of NOL carryforwards, and record a valuation allowance against deferred tax assets that would expire unused.

As a matter of law, we are subject to examination by federal and state taxing authorities. We have estimated and provided for income taxes in accordance with settlements reached with the Internal Revenue Service in prior audits. Although we believe that the amounts reflected in our tax returns substantially comply with the applicable federal and state tax regulations, both the IRS and the various state taxing authorities can take positions contrary to our position based on their interpretation of the law. A tax position that is challenged by a taxing authority could result in an adjustment to our income tax liabilities and related tax provision.

We measure and record tax contingency accruals in accordance with GAAP which prescribes a threshold for the financial statement recognition and measurement of a tax position taken or expected to be taken in a return. Only positions meeting the “more likely than not” recognition threshold at the effective date may be recognized or continue to be recognized. A tax position is measured at the largest amount that is greater than 50 percent likely of being realized upon ultimate settlement.

Revenue Recognition

We recognize revenues in accordance with Accounting Standards Codification 605 (ASC 605 “Revenue Recognition”) and Staff Accounting Bulletin No 104, and accordingly all of the following criteria must be met for revenues to be recognized: persuasive evidence of an arrangement exists, delivery has occurred or services have been rendered, the price to the buyer is fixed and determinable and collectability is reasonably assured.

The majority of our revenues are from the transportation of fresh and saltwater by our trucks or through temporary or permanent water transport pipelines to customer sites for use in drilling and hydraulic fracturing activities and from customer sites to remove and dispose of flowback and produced water originating from oil and gas wells. Revenues are also generated through fees charged for disposal of oilfield wastes in our landfill, disposal of fluids in our disposal wells and from the rental of tanks and other equipment. Certain customers are under contract with us to utilize our saltwater pipeline and have an obligation to dispose of a minimum quantity (number of barrels) of saltwater over the contract period. Transportation and disposal rates are generally based on a fixed fee per barrel of disposal water or, in certain circumstances transportation is based on an hourly rate. Revenue is recognized based on the number of barrels transported or disposed of at hourly rates for transportation services, depending on the customer contract. Rates for other services are based on negotiated rates with our customers and revenue is recognized when the services have been performed.

Our discontinued industrial solutions business derives the majority of its revenue from the sale of used motor oil and antifreeze after it is refined by one of its processing facilities. Revenue is recognized upon shipment or delivery, dependent on contracted terms, of salable fuel oil or upon recovery service provided in the receipt of waste oil and antifreeze per specific customer contract terms. Transportation costs charged to customers are included in revenue.

Environmental and Legal Contingencies

We have established liabilities for environmental and legal contingencies. We record a loss contingency for these matters when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. In determining the liability, we consider a number of factors including, but not limited to, the jurisdiction of the claim, related claims, insurance coverage when insurance covers the type of claim and our historic outcomes in similar matters, if applicable. A significant amount of judgment and the use of estimates are required to quantify our ultimate exposure in these matters. The determination of liabilities for these contingencies is reviewed periodically to ensure that we have accrued the proper level of expense. The liability balances are adjusted to account for changes in circumstances for ongoing issues, including the effect of any applicable insurance coverage for these matters. While we believe that the amount accrued to-date is adequate, future changes in circumstances could impact these determinations.

We record obligations to retire tangible, long-lived assets on our balance sheet as liabilities, which are recorded at a discount when we incur the liability. A certain amount of judgment is involved in estimating the future cash flows of such obligations, as well as the timing of these cash flows. If our assumptions and estimates on the amount or timing of the future cash flows change, it could potentially have a negative impact on our earnings.

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Recent Accounting Pronouncements

In April 2014, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (“ASU 2014-08”). The amendments in this update will be added to Accounting Standards Codification (“ASC”) Topic 205, Presentation of Financial Statements and ASC Topic 360, Property, Plant, and Equipment. The standard changes the criteria for reporting discontinued operations and enhancing convergence of the FASB’s and the International Accounting Standard Board’s reporting requirements for discontinued operations. The amendment adds a requirement to the threshold for items held for sale or disposed of that the discontinuation of the component of the entity must also have a strategic shift with a major effect on operations and financial results. Additionally, an asset held for sale on acquisition will have to meet all of the held for sale criteria on the acquisition date. The amendment removed the prohibition of significant ongoing involvement in the operations of the component of the entity. The amendments in this update are effective prospectively for reporting periods beginning after December 15, 2014, which for us is the reporting period beginning January 1, 2015. The amendment does not apply to components classified as held for sale before the effective date and does not change the presentation of components previously classified as discontinued operations. We do not believe the adoption of ASU 2014-08 will have a material impact on our consolidated financial statements.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The amendments in this update will be added to the ASC as Topic 606, Revenue from Contracts with Customers, and replaces the guidance in Topic 605. The underlying principle of the guidance in this update is that a business or other organization will recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects what it expects to receive in exchange for the goods or services. This new revenue standard also calls for more detailed disclosures and provides guidance for transactions that weren’t addressed completely, such as service revenue and contract modifications. The amendments in this update may be applied retrospectively or modified retrospectively effective for reporting periods beginning after December 15, 2016, which for us is the reporting period starting January 1, 2017. We are reviewing the guidance in ASU 2014-09 and have not yet assessed the impact, if any, on our consolidated financial statements and have not determined its method of adoption.



Item 7A.	Quantitative and Qualitative Disclosures about Market Risk

Inflation

Inflationary factors, such as increases in our cost structure, could impair our operating results. Although we do not believe that inflation has had a material impact on our financial position or results of operations to date, a high rate of inflation in the future may have an adverse effect on our ability to maintain current levels of gross margin and selling, general and administrative expenses as a percentage of sales revenue if the selling prices of our products do not increase with these increased costs.

Commodity Risk

We are subject to market risk exposures arising from declines in oil and natural gas drilling activity in unconventional areas, which is primarily a function of the market price for oil and natural gas. Various factors beyond our control affect the market prices for oil and natural gas, including but not limited to the level of consumer demand, governmental regulation, the price and availability of alternative fuels, political instability in foreign markets, weather-related factors and the overall economic environment. Market prices for oil and natural gas historically have been volatile and unpredictable, and we expect this volatility to continue in the future. Prolonged declines in the market price of oil and/or natural gas could contribute to declines in drilling activity and accordingly would reduce demand for our services. We attempt to manage this risk by strategically aligning our assets with those areas where we believe demand is highest and market conditions for our services are most favorable. If there is further deterioration in our business operations or prospects, our stock price, the broader economy or our industry, including further declines in oil and natural gas prices, the value of our long-lived assets and goodwill, or those we may acquire in the future, could decrease significantly and result in additional impairment and financial statement write-offs which could have a material adverse effect on our financial condition, results of operations and cash flows.

Interest Rates

As of December 31, 2014 the outstanding principal balance on our asset-based revolving credit facility (“ABL Facility”) was $183.1 million with variable rates of interest based on, at the Company’s election, (i) the greater of (a) the prime lending rate as publicly announced by Wells Fargo, (b) the Federal Funds rate plus 0.5% or (c) the one month LIBOR plus one percent, plus, in each case, an applicable margin of 0.75% to 1.50% or (ii) the LIBOR rate plus an applicable margin of 1.75% to 2.50%. The weighted average interest rate for the year ended December 31, 2014 was 2.41%. We have assessed our exposure to changes in interest rates on variable rate debt by analyzing the sensitivity to our earnings assuming various changes in market interest rates. Assuming a hypothetical increase of 1% to the interest rates on the average outstanding balance of our variable rate debt

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portfolio during the year ended December 31, 2014 our net interest expense for the year ended December 31, 2014 would have increased by an estimated $1.8 million, respectively.

As of December 31, 2014 the carrying value and the fair value of our 2018 Notes was $400.0 million and $245.0 million, respectively. The fair value of our 2018 Notes is affected, among other things, by changes to market interest rates. Should we decide to retire our 2018 Notes early, a change in interest rates could affect our future repurchase price. We have assessed our exposure to changes in interest rates by analyzing the sensitivity to the fair value of our 2018 Notes assuming various changes in market interest rates. Assuming a hypothetical increase to market interest rates of 1%, we estimate the fair value of our 2018 Notes would decrease by approximately $5.8 million. Assuming a hypothetical decrease to market interest rates of 1%, we estimate the fair value of our 2018 Notes would increase by approximately $6.0 million.



Item 8.	Financial Statements and Supplementary Data

The financial statements and supplementary data required by Regulation S-X are included in Item 15. “Exhibits, Financial Statement Schedules” contained in Part IV, Item 15 of this Annual Report on Form 10-K.



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

None.



Item 9A.	Controls and Procedures

Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed in company reports filed or submitted 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 rules and forms of the Securities and Exchange Commission, and that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Evaluation of Disclosure Controls and Procedures

An evaluation of the effectiveness of our disclosure controls and procedures was performed under the supervision of, and with the participation of, management, including our Chief Executive Officer and Chief Financial Officer, as of the end of the period covered by this Annual Report on Form 10-K. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective.

Management’s Annual Report on Internal Control over Financial Reporting

The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. The Company’s internal control system is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.

The Company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of consolidated 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 (3) 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 consolidated 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.

Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2014. In making its assessment of internal control over financial reporting, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control—Integrated Framework (1992). Based on this assessment, management concluded that our internal control over financial reporting was effective as of December 31, 2014.

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Our independent registered public accounting firm, KPMG LLP, has issued an audit report on the effectiveness of our internal control over financial reporting. This report has been included on page 57 of this Annual Report on Form 10-K.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the three months ended December 31, 2014 that materially affected, or were reasonably likely to materially affect, our internal control over financial reporting. However, as previously disclosed in our Form 8-K filed on November 6, 2014, our Chief Financial Officer resigned from that position effective November 2, 2014. As of December 31, 2014 the roles and responsibilities of our former Chief Financial Officer related to internal control over financial reporting were performed by our Interim Chief Financial Officer until January 5, 2015 when the Company hired a new Chief Financial Officer. Concurrent with hiring a new Chief Financial Officer, our Interim Chief Financial Officer resigned as an officer of the Company. With the departure of our Interim Chief Financial Officer, on January 5, 2015 the Company promoted its Corporate Controller to Principal Accounting Officer. Our new Chief Financial Officer has assumed the roles and responsibilities related to internal control over financial reporting.

As previously mentioned, the Company began operating under a new organizational structure effective January 5, 2015. As a result of the new organizational structure, there have been changes in the individuals responsible for executing the controls; however, we continue to execute our business processes under the same controls and we do not believe that these organizational changes materially affected, or were reasonably likely to materially affect, our internal control over financial reporting.

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Nuverra Environmental Solutions, Inc.:

We have audited Nuverra Environmental Solutions, Inc. and subsidiaries' (the Company) internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Nuverra Environmental Solutions, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Item 9A (a), Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit 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 audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

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 (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) 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 (3) 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.

In our opinion, Nuverra Environmental Solutions, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (1992) issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Nuverra Environmental Solutions, Inc. and subsidiaries as of December 31, 2014 and 2013, and the related consolidated statements of operations, changes in equity, and cash flows for each of the years in the three-year period ended December 31, 2014, and our report dated March 16, 2015 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Phoenix, Arizona

March 16, 2015

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Item 9B.	Other Information

None.

NUVERRA ENVIRONMENTAL SOLUTIONS, INC.

PART III



Item 10.	Directors, Executive Officers and Corporate Governance

The information required by this item is incorporated by reference from our proxy statement to be filed pursuant to Regulation 14A within 120 days after our year ended December 31, 2014 in connection with our 2015 Annual Meeting of Stockholders, or “Proxy Statement.”



Item 11.	Executive Compensation

The information required by this item is incorporated by reference to our Proxy Statement.



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

The information required by this item is incorporated by reference to our Proxy Statement.



Item 13.	Certain Relationships and Related Transactions, and Director Independence

The information required by this item is incorporated by reference to our Proxy Statement.



Item 14.	Principal Accounting Fees and Services

The information required by this item is incorporated by reference to our Proxy Statement.

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NUVERRA ENVIRONMENTAL SOLUTIONS, INC.

PART IV



Item 15.	Exhibits, Financial Statement Schedules

(a) The following documents are filed as part of this Annual Report on Form 10-K:


(1)	Audited Consolidated Financial Statements



		Page
Report of Independent Registered Public Accounting Firm		62
Consolidated Balance Sheets at December 31, 2014 and 2013		63
Consolidated Statements of Operations for the year ended December 31, 2014, 2013 and 2012		64
Consolidated Statements of Changes in Equity for the year ended December 31, 2014, 2013 and 2012		65
Consolidated Statements of Cash Flows for the year ended December 31, 2014, 2013 and 2012		66
Notes to Consolidated Financial Statements		67


(2)	Financial Statement Schedules

All financial statement schedules have been omitted since they are not required, not applicable, or the information is otherwise included in the audited consolidated financial statements.

(b) The exhibits listed on the “Exhibit Index” following the audited consolidated financial statements are filed with this Annual Report on Form 10-K or incorporated by reference as set forth below.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Scottsdale, State of Arizona, on March 16, 2015.




				Nuverra Environmental Solutions, Inc.

				By:		/s/ MARK D. JOHNSRUD
				Name:		Mark D. Johnsrud
				Title:		Chief Executive Officer, President and Chairman

POWER OF ATTORNEY

KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Mark D. Johnsrud and Gregory J. Heinlein, and each of them, as his true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him and in his name, place, and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K and to file the same, with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, or their or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

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



Signature	Title	Date

/s/ MARK D. JOHNSRUD	Chairman of the Board, Chief Executive Officer, President and Director (Principal Executive Officer)	March 16, 2015
Mark D. Johnsrud


/s/ GREGORY J. HEINLEIN	Executive Vice President and Chief Financial Officer (Principal Financial Officer)	March 16, 2015
Gregory J. Heinlein


/s/ STACY W. HILGENDORF	Corporate Controller (Principal Accounting Officer)	March 16, 2015
Stacy W. Hilgendorf	Corporate Controller (Principal Accounting Officer)

/s/ ROBERT B. SIMONDS, JR.	Vice Chairman of the Board and Director	March 16, 2015
Robert B. Simonds, Jr.	Vice Chairman of the Board and Director

/s/ WILLIAM M. AUSTIN	Director	March 16, 2015
William M. Austin

/s/ EDWARD A. BARKETT	Director	March 16, 2015
Edward A. Barkett

/s/ TOD C. HOLMES	Director	March 16, 2015
Tod C. Holmes

/s/ R.D. NELSON	Director	March 16, 2015
R.D. NELSON

/s/ DR. ALFRED E. OSBORNE, JR.	Director	March 16, 2015
Dr. Alfred E. Osborne, Jr.

/s/ J. DANFORTH QUAYLE	Director	March 16, 2015
J. Danforth Quayle

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INDEX TO FINANCIAL STATEMENTS

NUVERRA ENVIRONMENTAL SOLUTIONS, INC. AND SUBSIDIARIES

The following financial statements of the Company and its subsidiaries required to be included in Item 15(a)(1) of Form 10-K are listed below:




		Page
Audited Consolidated Financial Statements:
Report of Independent Registered Public Accounting Firm		62
Consolidated Balance Sheets at December 31, 2014 and 2013		63
Consolidated Statements of Operations for the year ended December 31, 2014, 2013 and 2012		64
Consolidated Statements of Changes in Equity for the year ended December 31, 2014, 2013 and 2012		65
Consolidated Statements of Cash Flows for the year ended December 31, 2014, 2013 and 2012		66
Notes to Consolidated Financial Statements		67

Supplementary Financial Data:

The supplementary financial data of the Registrant and its subsidiaries required to be included in Item 15(a)(2) of Form 10-K have been omitted as not applicable or because the required information is included in the Consolidated Financial Statements or in the notes thereto.

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Nuverra Environmental Solutions, Inc.

We have audited the accompanying consolidated balance sheets of Nuverra Environmental Solutions, Inc. and subsidiaries (the Company) as of December 31, 2014 and 2013, and the related consolidated statements of operations, changes in equity, and cash flows for each of the years in the three‑year period ended December 31, 2014. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our 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 audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Nuverra Environmental Solutions, Inc. and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the years in the three‑year period ended December 31, 2014, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Nuverra Environmental Solutions, Inc.’s internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 16, 2015 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

Phoenix, Arizona

March 16, 2015

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NUVERRA ENVIRONMENTAL SOLUTIONS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands)



	December 31,
	2014			2013
Assets
Cash and cash equivalents	$	13,367		$	8,783
Restricted cash	114			110
Accounts receivable, net	108,813			87,086
Inventories	4,413			3,328
Prepaid expenses and other receivables	4,147			10,457
Deferred income taxes	3,179			30,072
Other current assets	173			409
Current assets held for sale	20,466			21,446
Total current assets	154,672			161,691
Property, plant and equipment, net	475,982			498,541
Equity investments	3,814			4,032
Intangibles, net	19,757			149,363
Goodwill	104,721			408,696
Other assets	17,688			21,136
Long-term assets held for sale	94,938			167,304
Total assets	$	871,572		$	1,410,763
Liabilities and Equity
Accounts payable	$	18,859		$	33,229
Accrued liabilities	43,395			63,431
Current portion of contingent consideration	9,274			13,113
Current portion of long-term debt	4,863			5,464
Financing obligation to acquire non-controlling interest	11,000			—
Current liabilities of discontinued operations	8,802			9,301
Total current liabilities	96,193			124,538
Deferred income taxes	3,448			42,982
Long-term portion of debt	592,455			549,713
Long-term portion of contingent consideration	550			2,344
Financing obligation to acquire non-controlling interest	—			10,104
Other long-term liabilities	3,874			4,324
Long-term liabilities of discontinued operations	22,105			32,389
Total liabilities	718,625			766,394
Commitments and contingencies
Preferred stock $0.001 par value, (1,000 shares authorized, no shares issued and outstanding at December 31, 2014 and December 31, 2013	—			—
Common stock, $0.001 par value (50,000 shares authorized, 28,937 shares issued and 27,488 outstanding at December 31, 2014 and 27,425 shares issued and 25,994 outstanding at December 31, 2013	29			27
Additional paid-in capital	1,365,537			1,341,209
Treasury stock	(19,651		)	(19,503		)
Accumulated deficit	(1,192,968		)	(677,364		)
Total equity of Nuverra Environmental Solutions, Inc.	152,947			644,369
Total liabilities and equity	$	871,572		$	1,410,763

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

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NUVERRA ENVIRONMENTAL SOLUTIONS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)



	Year Ended December 31,
	2014			2013			2012
Revenue:
Non-rental revenue	$	463,418		$	441,421		$	241,230
Rental revenue	72,864			84,395			15,441
Total revenue	536,282			525,816			256,671
Costs and expenses:
Direct operating expenses	384,813			379,160			197,832
General and administrative expenses	66,832			84,280			42,742
Depreciation and amortization	85,880			99,236			47,641
Impairment of long-lived assets	112,436			111,900			6,030
Impairment of goodwill	303,975			—			—
Other, net	—			899			—
Total costs and expenses	953,936			675,475			294,245
Loss from operations	(417,654		)	(149,659		)	(37,574		)
Interest expense, net	(50,917		)	(53,703		)	(26,607		)
Other income (expense), net	2,107			(3,773		)	(2,538		)
Loss on extinguishment of debt	(3,177		)	—			(2,638		)
Loss from continuing operations before income taxes	(469,641		)	(207,135		)	(69,357		)
Income tax benefit	12,463			73,095			62,760
Loss from continuing operations	(457,178		)	(134,040		)	(6,597		)
(Loss) income from discontinued operations, net of income taxes	(58,426		)	(98,251		)	9,124
Net (loss) income attributable to common stockholders	$	(515,604	)	$	(232,291	)	$	2,527

Net (loss) income per common share attributable to common stockholders:
Basic and diluted loss from continuing operations	$	(17.52	)	$	(5.47	)	$	(0.44	)
Basic and diluted (loss) income from discontinued operations	(2.24		)	(4.01		)	0.61
Net (loss) income per basic and diluted common share	$	(19.76	)	$	(9.48	)	$	0.17

Weighted average shares outstanding used in computing net (loss) income per basic and diluted common share	26,090			24,492			14,994

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

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NUVERRA ENVIRONMENTAL SOLUTIONS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(In thousands)



	Total			Common Stock			Additional Paid-In Capital			Treasury Stock				Purchased Warrants					Accumulated Deficit			Accumulated Other Comprehensive Income (Loss)
	Total			Shares	Amount		Additional Paid-In Capital			Shares	Amount			Shares		Amount			Accumulated Deficit			Accumulated Other Comprehensive Income (Loss)
Balance at December 31, 2011	$	341,810		13,917	$	14	$	815,000		1,431	$	(19,503	)	1,133		$	(6,844	)	$	(446,865	)	$	8
Stock-based compensation	3,610			10	—		3,610			—	—			—		—			—			—
Issuance of common stock for equity offering	74,448			1,820	2		74,446			—	—			—		—			—			—
Issuance of common stock for acquisitions	417,733			10,664	11		417,722			—	—			—		—			—			—
Issuance of common stock for contingent consideration	7,770			173	—		7,770			—	—			—		—			—			—
Exercise of warrants	32			28	—		32			—	—			—		—			—			—
Shares returned from escrow	(161		)	—	—		(161		)	—	—			—		—			—			—
Net income	2,527			—	—		—			—	—			—		—			2,527			—
Accumulated other comprehensive loss:
Unrealized loss from available for sale securities	(8		)	—	—		—			—	—			—		—			—			(8		)
Balance at December 31, 2012	$	847,761		26,612	$	27	$	1,318,419		1,431	$	(19,503	)	1,133		$	(6,844	)	$	(444,338	)	$	—
Stock-based compensation	3,708			—	—		3,708			—	$	—		—		$	—		$	—		$	—
Issuance of common stock to employees	—			15	—		—			—	—			—		—			—			—
Issuance of common stock for acquisitions	24,286			741	—		24,286			—	—			—		—			—			—
Issuance of common stock for contingent consideration	47			1			47			—	—			—		—			—			—
Issuance of common stock for legal settlement	1,621			56	—		1,621			—	—			—		—			—			—
Shares returned from escrow	(28		)	—	—		(28		)	—	—			—		—			—			—
Retirement of purchased warrants	—			—	—		(6,844		)	—	—			(1,133	)	6,844			—			—
Distribution to noncontrolling shareholder	(735		)	—	—		—			—	—			—		—			(735		)	—
Net loss	(232,291		)	—	—		—			—	—			—		—			(232,291		)	—
Balance at December 31, 2013	$	644,369		27,425	$	27	$	1,341,209		1,431	$	(19,503	)	—		$	—		$	(677,364	)	$	—
Stock-based compensation	2,971			—	—		2,971			—	$	—		—		$	—		$	—		$	—
Issuance of common stock to employees	—			125	—		—			—	—			—		—			—			—
Issuance of treasury stock	(148		)	—	—		—			18	(148		)	—		—			—			—
Issuance of common stock for contingent consideration	3,790			243	1		3,789			—	—			—		—			—			—
Issuance of common stock for legal settlement	13,401			848	1		13,400			—	—			—		—			—			—
401(k) match issued	4,079			292	—		4,079			—	—			—		—			—			—
ESPP distribution	89			4	—		89			—	—			—		—			—			—
Net loss	(515,604		)	—	—		—			—	—			—		—			(515,604		)	—
Balance at December 31, 2014	$	152,947		28,937	$	29	$	1,365,537		1,449	$	(19,651	)	—		$	—		$	(1,192,968	)	$	—

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

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NUVERRA ENVIRONMENTAL SOLUTIONS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)



	Year Ended December 31,
	2014			2013			2012
Cash flows from operating activities:
Net (loss) income	$	(515,604	)	$	(232,291	)	$	2,527
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Loss (income) from discontinued operations, net of income taxes	58,426			98,251			(9,124		)
Depreciation	68,710			78,812			40,130
Amortization of intangible assets	17,170			20,424			7,511
Amortization of deferred financing costs	4,038			4,492			1,762
Amortization of original issue discounts and premiums, net	150			142			108
Stock-based compensation	2,971			3,708			3,610
Impairment of long-lived assets	112,436			111,900			6,030
Impairment of goodwill	303,975			—			—
(Gain) loss on disposal of property, plant and equipment	(4,773		)	708			1,672
Bad debt expense	3,833			3,275			6,517
Loss on extinguishment of debt	3,177			—			2,638
Deferred income taxes	(12,641		)	(68,599		)	(56,678		)
Write-down of cost method investments	—			4,300			—
Other, net	176			894			(165		)
Changes in operating assets and liabilities, net of business acquisitions and purchase price adjustments:
Accounts receivable	(25,560		)	15,492			(2,101		)
Prepaid expenses and other receivables	6,310			(2,864		)	(1,096		)
Accounts payable and accrued liabilities	(4,213		)	27,331			22,938
Other assets and liabilities, net	(1,205		)	693			(1,201		)
Net cash provided by operating activities from continuing operations	17,376			66,668			25,078
Net cash provided by operating activities from discontinued operations	3,966			3,589			5,593
Net cash provided by operating activities	21,342			70,257			30,671
Cash flows from investing activities:
Cash paid for acquisitions, net of cash acquired	—			(10,570		)	(357,346		)
Proceeds from the sale of property, plant and equipment	10,192			2,308			7,235
Purchases of property, plant and equipment	(55,731		)	(46,593		)	(43,516		)
Proceeds from acquisition-related working capital adjustment	—			2,067			—
Proceeds from the sale of available-for-sale securities	—			—			5,169
Other investing activities	—			—			(82		)
Net cash used in investing activities from continuing operations	(45,539		)	(52,788		)	(388,540		)
Net cash used in investing activities from discontinued operations	(2,451		)	(4,195		)	(4,158		)
Net cash used in investing activities	(47,990		)	(56,983		)	(392,698		)
Cash flows from financing activities:
Proceeds from revolving credit facility	107,725			98,501			193,490
Payments on revolving credit facility	(67,500		)	(109,501		)	(186,674		)
Proceeds from other debt	—			—			398,980
Payments on other debt	—			—			(150,367		)
Proceeds from equity offering	—			—			74,448
Payments for deferred financing costs	(1,030		)	(855		)	(26,170		)
Payments on notes payable and capital leases	(5,289		)	(5,416		)	(4,605		)
Other financing activities	(1,159		)	(2,602		)	(1,058		)
Net cash provided by (used in) financing activities from continuing operations	32,747			(19,873		)	298,044
Net cash provided by (used in) financing activities from discontinued operations	105			(400		)	—
Net cash provided by (used in) financing activities	32,852			(20,273		)	298,044
Net increase (decrease) in cash and cash equivalents	6,204			(6,999		)	(63,983		)
Cash and cash equivalents - beginning of year	9,212			16,211			80,194
Cash and cash equivalents - end of year	15,416			9,212			16,211
Less: cash and cash equivalents of discontinued operations - end of year	2,049			429			1,435
Cash and cash equivalents of continuing operations - end of year	$	13,367		$	8,783		$	14,776

Supplemental disclosure of cash flow information:
Cash paid for interest	$	40,471		$	48,175		$	13,605
Cash paid for taxes, net	(189		)	554			1,759
Supplemental schedule of non-cash investing and financing activities:
Common stock issued for business acquisitions	—			24,286			417,733
Common stock issued for contingent consideration	3,790			47			7,770
Common stock issued for legal settlements	13,401			1,621			—
Common stock issued for 401(k) match	4,079			—			—
Purchases of property, plant and equipment under capital leases	340			5,774			20,771
Property, plant and equipment purchases in accounts payable	2,921			7,863			4,238
Restricted cash payable to former sole owner of Power Fuels	114			110			3,536
Conversion of accrued interest on principal debt balance	4,308			—			—
Deferred financing costs financed through principal debt balance	2,541			—			—
Deferred financing costs in accounts payable and accrued liabilities	180			—			—

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

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NUVERRA ENVIRONMENTAL SOLUTIONS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) Organization and Nature of Business Operations

Description of Business

Nuverra Environmental Solutions, Inc., a Delaware Corporation, together with its subsidiaries (collectively, the “Company”, “we”, “us” or “our”) is an environmental solutions company providing full-cycle environmental solutions to our customers in energy and industrial end-markets. The Company focuses on the delivery, collection, treatment, recycling, and disposal of water, wastewater, waste fluids, hydrocarbons, and restricted solids that are part of the drilling, completion, and ongoing production of shale oil and natural gas.

The Company's shale solutions business provides comprehensive environmental solutions for “unconventional” oil and gas exploration and production including the delivery, collection, treatment, recycling, and disposal of restricted environmental products used in the development of unconventional oil and natural gas fields. The shale solutions business currently operates in select shale areas in the United States including the predominantly oil-rich shale areas consisting of the Bakken, Utica, Eagle Ford, Mississippian Lime and Permian Shale areas and the predominantly gas-rich Haynesville, Marcellus and Barnett Shale areas. The Company's shale solutions business serves customers seeking fresh water acquisition, temporary water transmission and storage, transportation, treatment, recycling or disposal of complex water flows, such as flowback and produced brine water, and solids such as drill cuttings, and management of other environmental products in connection with shale oil and gas hydraulic fracturing operations. Additionally, the Company's shale solutions business rents equipment to customers, including providing for delivery and pickup.

During the year ended December 31, 2014 the Company completed the organizational realignment of its shale solutions business into three operating divisions, which the Company considers to be operating and reportable segments of its continuing operations: (1) the Northeast division comprising the Marcellus and Utica Shale areas, (2) the Southern division comprising the Haynesville, Eagle Ford, Mississippian and Permian Basin Shale areas and (3) the Rocky Mountain division comprising the Bakken Shale area. The Company's industrial solutions business is comprised of Thermo Fluids, Inc. ("TFI") as a single operating and reportable segment (Note 20).

(2) Basis of Presentation

The accompanying audited consolidated financial statements of Nuverra Environmental Solutions, Inc. and its subsidiaries (collectively, “Nuverra,” the “Company” or “we”) have been prepared in accordance with the rules and regulations of the SEC. In the opinion of management, the consolidated financial statements include the normal, recurring adjustments necessary for a fair statement of the information required to be set forth herein. The accompanying consolidated financial statements include the accounts of the Company and its subsidiaries.

All dollar and share amounts in the footnote tabular presentations are in thousands, except per share amounts and unless otherwise noted.

Unless stated otherwise, any reference to statement of operations items in these accompanying audited consolidated financial statements refers to results from continuing operations. The Company has not included a statement of comprehensive income as there were no transactions to report in the 2014 and 2013 periods presented, and less than $0.1 million related to unrealized losses on available for sale securities in the 2012 period presented. The business comprising the Company’s industrial solutions division is presented as discontinued operations in the Company’s consolidated financial statements for the years ended December 31, 2014, 2013, and 2012 (since its acquisition on April 10, 2012). See Note 20 for additional information. Unless stated otherwise, any reference to balance sheet, income statement and cash flow items in these consolidated financial statement notes refers to results from continuing operations.

Principles of Consolidation

The consolidated financial statements include the accounts of the Company and its subsidiaries. All intercompany accounts, transactions and profits are eliminated in consolidation.

Liquidity

The Company's primary source of capital is from borrowings available under its ABL Facility, as well as from cash generated by its operations with additional sources of capital in prior years from additional debt and equity accessed through the capital markets. The Company's historical acquisition activity was highly capital intensive and required significant investments in

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order to expand its presence in existing shale basins, access new markets and to expand the breadth and scope of services the Company provides. Additionally, the Company has historically issued equity as consideration in acquisition transactions. The Company's expected sources of capital in 2015 are expected to be from borrowings under its ABL Facility, cash generated by its operations and the net proceeds from the planned sale of TFI. Other sources of cash may include potential sales of assets, sale/leaseback transactions, additional debt or equity financing and reductions in its operating costs.

At December 31, 2014, the Company's total indebtedness was $597.9 million. The Company has incurred operating losses of $457.2 million, $134.0 million and $6.6 million for the years ended December 31, 2014, 2013 and 2012, respectively, including impairments of goodwill and long-lived assets. At December 31, 2014, the Company had cash and cash equivalents of $13.4 million and $25.9 million of net availability under the ABL Facility. Given the current macro environment and oil and gas prices, the Company anticipates declining revenues in 2015, with corresponding reductions in costs from operations. In this environment, the Company expects sufficient availability under the ABL Facility to meet its operating needs. The Company's financing strategy includes using the proceeds from the planned sale of TFI, closely monitoring and lowering its operating costs and capital spending, and managing its working capital to enhance liquidity. Based on the Company's current expectations and projections, the Company believes that its available cash, together with availability under the ABL Facility, will be sufficient to fund its operations, capital expenditures and interest payments under its debt obligations through at least the first quarter of 2016, which is the Company's current, one-year forecast period. See Note 10 for additional information on the Company's debt, financial covenants and borrowing limitations.

Reclassifications

Certain reclassifications and adjustments have been made to prior period amounts in the accompanying consolidated balance sheets, statements of operations and cash flows in order to conform to the current year’s presentation including:


•	As discussed in Note 20, the Company has recast its industrial solutions business comprised of TFI as held-for-sale and discontinued operations.


•	As described in Note 19, the Company redefined its operating and reportable segments during the three months ended September 30, 2014 and as a result, prior year periods have been recast to conform to the current year segment presentation.

•

The consolidated statements of operations now contain the line items “Direct operating expenses” and “Depreciation and amortization.” “Direct operating expenses” was previously reported as “Costs of revenues.” Depreciation expense was previously presented as a component of “Costs of revenues” and “General and administrative expenses” in the amounts of $77.0 million and $1.8 million, respectively, for the year ended December 31, 2013. No depreciation expense was presented as a component of “General and administrative expenses” for the year ended December 31, 2012.

•

The Company adjusted the gross carrying value of previously impaired property, plant and equipment by $45.9 million from $616.0 million to $570.1 million and accumulated depreciation from $137.3 million to $91.4 million and intangibles by $7.0 million from $182.3 million to $175.3 million and accumulated amortization from $33.0 million to $26.0 million, respectively, with no change to the net balances as of December 31, 2013.


•	Certain similar line items in the consolidated statements of operations and cash flows have been combined to present a more concise and easier to follow presentation.

(3) Significant Accounting Policies

Use of Estimates

The Company’s consolidated financial statements have been prepared in conformity with generally accepted accounting principles in the United States (“GAAP”). The preparation of the financial statements requires management to make estimates and judgments that affect the reported amounts of assets and liabilities and the disclosure of contingencies at the date of the financial statements, as well as the reported amounts of revenues and expenses during the reporting period. Estimates have been prepared on the basis of the most current and best available information, however actual results could differ from those estimates.

Cash Equivalents

The Company considers all highly liquid investments with original maturities of three months or less when purchased to be cash equivalents. The Company maintains bank accounts in the United States. A majority of funds considered cash equivalents

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are invested in institutional money market funds. The Company has not experienced any historical losses in such accounts and believes that the risk of any loss is minimal.

Restricted Cash

In connection with the 2012 Power Fuels merger, assets received in exchange for the merger consideration excluded accounts receivable greater than ninety days as of November 30, 2012. Subsequent collections on these accounts receivable by the Company are required to be remitted to the former owner of Power Fuels (Note 18). At December 31, 2014 and 2013, such unremitted collections totaled $0.1 million. Such amounts are classified as restricted cash and the corresponding liability due to the former owner is classified as a component of accrued liabilities in the accompanying consolidated balance sheets.

Accounts Receivable

Accounts receivable are recognized and carried at original billed and unbilled amounts less allowances for estimated uncollectible amounts and estimates for potential credits. Inherent in the assessment of these allowances are certain judgments and estimates including, among others, the customer’s willingness or ability to pay, the Company’s compliance with customer invoicing requirements, the effect of general economic conditions and the ongoing relationship with the customer. Accounts with outstanding balances longer than the payment terms are considered past due. The Company writes off trade receivables when it determines that they have become uncollectible. Bad debt expense is reflected as a component of general and administrative expenses in the consolidated statements of operations.

Unbilled accounts receivable result from revenue earned for services rendered where customer billing is still in progress at the balance sheet date. Such amounts totaled approximately $26.2 million at December 31, 2014.

The following table summarizes activity in the allowance for doubtful accounts:



	December 31,
	2014			2013			2012
Balance at beginning of period	$	5,528		$	6,128		$	2,636
Bad debt expense	3,833			3,275			6,517
Write-offs, net	(1,804		)	(3,875		)	(3,025		)
Balance at end of period	$	7,557		$	5,528		$	6,128

Fair Value of Financial Instruments

Fair value is 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. The carrying amounts of the Company’s cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-term nature of these instruments. The carrying value of the Company’s contingent consideration is adjusted to fair value at the end of each reporting period using a probability-weighted discounted cash flow model. See Note 11 for disclosures on the fair value of the Company’s contingent consideration at December 31, 2014 and 2013.

The Company’s 2018 Notes are carried at cost. Their estimated fair values are based on quoted market prices. The fair value of the Company’s Amended Revolving Credit Facility and other debt obligations including capital leases, secured by various properties and equipment, bears interest at rates commensurate with market rates and therefore their respective carrying values approximate fair value. See Note 10 for disclosures on the fair value of the Company’s debt instruments at December 31, 2014.

Property and Equipment

Property and equipment is recorded at cost. Depreciation is recorded using the straight-line method over the estimated useful lives of the related assets ranging from three to thirty-nine years. The Company’s landfill is depreciated using the units-of-consumption method based on estimated remaining airspace. Leasehold improvements are depreciated over the life of the lease or the life of the asset, whichever is shorter. The range of useful lives for the components of property, plant and equipment are

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as follows:



Buildings	15-39 years
Building improvements	5-20 years
Pipelines	10-30 years
Disposal wells	3-10 years
Machinery and equipment	3-15 years
Equipment under capital leases	4-6 years
Motor vehicles and trailers	3-11 years
Rental equipment	5-15 years
Office equipment	3-7 years

Expenditures for betterments that increase productivity and/or extend the useful life of an asset are capitalized. Maintenance and repair costs are charged to expense as incurred. Upon disposal, the related cost and accumulated depreciation of the assets are removed from their respective accounts, and any gains or losses are included in direct operating expenses in the consolidated statements of operations. Depreciation expense was $68.7 million, $78.8 million, and $40.1 million for the years ended December 31, 2014, 2013 and 2012, respectively, and is characterized as a component of depreciation and amortization in the consolidated statements of operations.

Goodwill

Goodwill represents the excess of the purchase price over the fair value of the net assets of businesses acquired. The Company has made acquisitions over the years that have resulted in the recognition and accumulation of significant goodwill. The carrying values of goodwill at December 31, 2014 and 2013 were $104.7 million and $408.7 million, respectively (Note 7).

Goodwill is tested for impairment annually at September 30^th and more frequently if events or circumstances lead to a determination that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. The goodwill impairment test involves a two-step process; however, if, after assessing the totality of events or circumstances, an entity determines it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, then performing the two-step impairment test is unnecessary.

During the year ended December 31, 2014, the Company recorded goodwill impairment charges totaling $304.0 million related to its shale solutions business (Note 8). Such amount is included in "Impairment of goodwill" in the Company's consolidated statement of operations. Additionally, the Company recorded goodwill impairment charges of $48.0 million and $98.5 million for its industrial solutions reporting unit for the years ended December 31, 2014 and 2013, respectively. Such amounts are included in "(Loss) income from discontinued operations, net of income taxes" in the Company’s consolidated statements of operations for the years ended December 31, 2014 and 2013 (Note 20).

Debt Issuance Costs

The Company capitalizes costs associated with the issuance of debt and amortizes them as additional interest expense over the lives of the respective debt instrument on a straight-line basis, which approximates the effective interest method. The unamortized balance of deferred financing costs was $17.3 million and $20.8 million at December 31, 2014, and 2013, respectively, and is included in other long-term assets in the consolidated balance sheets. Upon the prepayment of related debt, the Company accelerates the recognition of the unamortized cost, which is characterized as loss on extinguishment of debt in the consolidated statements of operations. During the years ended December 31, 2014, and 2012 the Company wrote off the unamortized balance of issuance costs of $3.2 million and $2.6 million, respectively. Such amounts are included in "Loss on extinguishment of debt" in the Company's consolidated statement of operations (Note 10).

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Impairment of Long-Lived Assets and Intangible Assets with Finite Useful Lives

Long-lived assets including intangible assets with finite useful lives are evaluated for impairment whenever events or changes in circumstances indicate the carrying value of a long-lived asset (or asset group) may not be recoverable. If an impairment indicator is present, the Company evaluates recoverability by comparing the estimated future cash flows of the asset group, on an undiscounted basis, to their carrying values. The asset group represents the lowest level for which identifiable cash flows are largely independent of the cash flows of other groups of assets and liabilities. If the undiscounted cash flows exceed the carrying value, the asset group is recoverable and no impairment is present. If the undiscounted cash flows are less than the carrying value, the impairment is measured as the difference between the carrying value and the fair value of the long-lived asset (or asset group).

The Company recorded long-lived asset impairment charges of $112.4 million, $111.9 million and $6.0 million for the years ended December 31, 2014, 2013 and 2012, respectively. Such amounts are included in "Impairment of long-lived assets" in the Company's consolidated statement of operations (Note 8). Additionally, the Company recorded a long-lived asset impairment charge of $26.4 million in "(Loss) income from discontinued operations, net of income taxes" in the Company’s consolidated statements of operations for the year ended December 31, 2014 (Note 20).

Asset Retirement Obligations

The Company records the fair value of estimated asset retirement obligations (AROs) associated with tangible long-lived assets in the period incurred. Retirement obligations associated with long-lived assets are those for which there is an obligation for closures and/or site remediation at the end of the assets’ useful lives. These obligations, which are initially estimated based on discounted cash flow estimates, are accreted to full value over time through charges to interest expense (Note 15). In addition, asset retirement costs are capitalized as part of the related asset’s carrying value and are depreciated on a straight line basis for disposal wells and using a units-of-consumption basis for landfill costs over the assets’ respective useful lives.

Revenue Recognition

The Company recognizes revenues in accordance with Accounting Standards Codification 605 (ASC 605 “Revenue Recognition”) and Staff Accounting Bulletin No 104, and accordingly all of the following criteria must be met for revenues to be recognized: persuasive evidence of an arrangement exists, delivery has occurred or services have been rendered, the price to the buyer is fixed and determinable and collectability is reasonably assured. Revenues are generated upon the performance of contracted services under formal and informal contracts with direct customers. Taxes assessed on sales transactions are presented on a net basis and are not included in revenue.

The majority of the Company's revenues are from the transportation of fresh and saltwater by Company-owned trucks or through temporary or permanent water transport pipelines to customer sites for use in drilling and hydraulic fracturing activities and from customer sites to remove and dispose of flowback and produced water originating from oil and gas wells. Revenues are also generated through fees charged for disposal of oilfield wastes in the Company’s landfill, disposal of fluids in the Company’s disposal wells and from the rental of tanks and other equipment. Certain customers are under contract with the Company to utilize its saltwater pipeline and have an obligation to dispose of a minimum quantity (number of barrels) of saltwater over the contract period. Transportation and disposal rates are generally based on a fixed fee per barrel of disposal water or, in certain circumstances transportation is based on an hourly rate. Revenue is recognized based on the number of barrels transported or disposed of at hourly rates for transportation services, depending on the customer contract. Rates for other services are based on negotiated rates with the Company’s customers and revenue is recognized when the services have been performed.

The Company’s discontinued industrial solutions division derives the majority of its revenue from the sale of used motor oil and antifreeze after it is refined by one of its processing facilities. Revenue is recognized upon shipment or delivery, dependent on contracted terms, of salable fuel oil or upon recovery service provided in the receipt of waste oil and antifreeze per specific customer contract terms. Transportation costs charged to customers are included in revenue.

Concentration of Customer Risk

Three of the Company’s customers comprised 35%, 40% and 39% of the Company’s consolidated revenues for the years ended December 31, 2014, 2013 and 2012 respectively, and 30%, 31% and 34% of the Company’s consolidated accounts receivable at December 31, 2014, 2013 and 2012, respectively.

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impact on demand for oil and natural gas. Recent declines in oil and natural gas prices, and any substantial or extended decline in oil and natural gas prices, could result in reductions in our customers’ operating and capital expenditures. Declines in these expenditures could result in project modifications, delays or cancellations, general business disruptions, delays in, or nonpayment of, amounts owed to us, increased exposure to credit risk and bad debts, and a general reduction in demand for our services. These effects could have a material adverse effect on our financial condition, results of operations and cash flows.

Direct Operating Expenses

Direct operating expenses consists primarily of wages and benefits for employees performing operational activities; fuel expense associated with transportation and logistics activities; and costs to repair and maintain transportation and rental equipment and disposal wells.

Income Taxes

Income taxes are accounted for using the asset and liability method. Under this method, deferred income tax assets and liabilities are recognized for the expected future tax consequences attributable to temporary differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases including temporary differences related to assets acquired in business combinations. Deferred tax assets are also recognized for net operating loss, capital loss and tax credit carryforwards. Deferred income tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which the related temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is provided for those deferred tax assets for which realization of the related benefits is not more likely than not.

The Company measures and records tax contingency accruals in accordance with GAAP which prescribes a threshold for the financial statement recognition and measurement of a tax position taken or expected to be taken in a return. Only positions meeting the “more likely than not” recognition threshold may be recognized or continue to be recognized. A tax position is measured at the largest amount that is greater than 50 percent likely of being realized upon ultimate settlement. The Company’s policy is to recognize interest and penalties accrued on any unrecognized tax benefits as a component of income tax expense.

Share-Based Compensation

Share-based compensation for all share-based payment awards granted is based on the grant-date fair value. Generally, awards of stock options granted to employees vest in equal increments over a three-year service period from the date of grant and awards of restricted stock vest over a two or three year service period from the date of grant. The grant date fair value of the award is recognized to expense on a straight-line basis over the service period for the entire award, that is, over the requisite service period of the last separately vesting portion of the award. As of December 31, 2014 there was approximately $0.7 million of unrecognized compensation cost related to unvested stock options, which are expected to vest over a weighted average period of approximately of 1.5 years. As of December 31, 2014 there was $0.6 million of unrecognized compensation cost related to unvested shares of restricted stock, which are expected to vest over a weighted average period of approximately 1.6 years. As of December 31, 2014 there was approximately $2.5 million of unrecognized compensation cost related to unvested restricted stock units. See Note 13 for additional information.

Advertising

Advertising costs are expensed as incurred. Advertising expense was approximately $0.3 million, $0.2 million and $0.2 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Recent Accounting Pronouncements

In April 2014, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (“ASU 2014-08”). The amendments in this update will be added to Accounting Standards Codification (“ASC”) Topic 205, Presentation of Financial Statements and ASC Topic 360, Property, Plant, and Equipment. The standard changes the criteria for reporting discontinued operations and enhancing convergence of the FASB’s and the International Accounting Standard Board’s reporting requirements for discontinued operations. The amendment adds a requirement to the threshold for items held for sale or disposed of that the discontinuation of the component of the entity must also have a strategic shift with a major effect on operations and financial results. Additionally, an asset held for sale on acquisition will have to meet all of the held for sale criteria on the acquisition date. The amendment removed the prohibition of significant ongoing involvement in the operations of the component of the entity. The amendments in this update are effective prospectively for reporting periods beginning after December 15, 2014, which for the Company is the reporting period beginning January 1, 2015. The amendment does not apply

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to components classified as held for sale before the effective date and does not change the presentation of components previously classified as discontinued operations. The Company does not believe the adoption of ASU 2014-08 will have a material impact on the Company’s consolidated financial statements.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The amendments in this update will be added to the ASC as Topic 606, Revenue from Contracts with Customers, and replaces the guidance in Topic 605. The underlying principle of the guidance in this update is that a business or other organization will recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects what it expects to receive in exchange for the goods or services. This new revenue standard also calls for more detailed disclosures and provides guidance for transactions that weren’t addressed completely, such as service revenue and contract modifications. The amendments in this update may be applied retrospectively or modified retrospectively effective for reporting periods beginning after December 15, 2016, which for the Company is the reporting period starting January 1, 2017. The Company is reviewing the guidance in ASU 2014-09 and has not yet assessed the impact, if any, on its consolidated financial statements and has not determined its method of adoption.

(4) Acquisitions

2013 Acquisitions

During the year ended December 31, 2013, the Company completed three acquisitions in its shale solutions business, including two in the Marcellus/Utica Shale and one in the Bakken Shale area. In the Bakken Shale, in July 2013, the Company acquired Ideal Oilfield Disposal, LLC (“Ideal”), a greenfield oilfield waste disposal landfill site located in North Dakota. Total consideration was $24.6 million including stock valued at $6.7 million, cash of $9.8 million, and contingent consideration of approximately $8.1 million. The acquisition included land, certain land improvements and a disposal permit. See Note 11 for additional information regarding the contingent consideration related to Ideal. The Company has also agreed to pay the former owners of Ideal certain additional amounts based on future revenues of the landfill, which is expensed as revenue is incurred. Such amounts totaled $0.1 million and $0.2 million in the year ended December 31, 2014 and 2013, respectively.

The aggregate purchase price of the 2013 acquired businesses was approximately $42.9 million consisting of approximately 0.7 million shares of the Company’s common stock with an estimated fair value of approximately $24.3 million, cash consideration of approximately $10.5 million and contingent consideration of approximately $8.1 million. The results of operations of the three acquisitions were not material to our consolidated results of operations during the year ended December 31, 2013.

The final allocations of the combined aggregate purchase prices of the three acquisitions are summarized as follows:



Accounts receivable	$	753
Other current assets	13
Property, plant and equipment, including landfill of $24.0 million	41,942
Customer relationships	400
Goodwill	341
Accounts payable and accrued liabilities	(189		)
Other long-term liabilities	(302		)
Total	$	42,958

The goodwill related to the pool of customer-qualified drivers acquired in connection with one of the Marcellus/Utica acquisitions.

2012 Acquisitions

Power Fuels Merger

On November 30, 2012, the Company completed a merger (the “Power Fuels Merger”) with Badlands Power Fuels, LLC (collectively with its subsidiaries, “Power Fuels”) of which the Company’s Chief Executive Officer and Chairman, Mark D. Johnsrud, was the sole member. Prior to the merger, Power Fuels was a privately-held North Dakota-based environmental solutions company providing delivery and disposal of environmental products, fluids transportation and handling, water sales, and equipment rental services for unconventional oil and gas exploration and production customers. As a result of the Power Fuels Merger on November 30, 2012, Power Fuels and its subsidiaries became wholly-owned subsidiaries of the Company.

The aggregate purchase price was approximately $498.8 million (net of settlement of the working capital adjustment of $2.1 million) and was comprised of the following:

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•	9.5 million unregistered shares of the Company’s common stock, with a fair value of approximately $371.5 million, of which 1.0 million shares were placed into escrow for up to three years to pay certain potential indemnity claims; and


•	$127.3 million in cash including adjustments for targeted versus actual debt and working capital.

The Power Fuels Merger has been accounted for as a business combination under the acquisition method of accounting. During the year ended December 31, 2013, the Company amended its original purchase price allocation to reflect settlement of the working capital adjustment and finalized appraisals and assessments of the tangible and intangible assets acquired and liabilities assumed, including related tax effects. Such adjustments resulted in a decrease in recorded goodwill of $8.7 million, primarily due to an increase in the final values assigned to property, plant and equipment and the settlement of the working capital adjustment.

The final allocation of the purchase price is summarized as follows:



Cash	$	2,111
Accounts receivable	57,484
Inventory	3,443
Other assets	3,271
Property, plant and equipment	287,818
Customer relationships	145,000
Goodwill	304,031
Accounts payable and accrued liabilities	(24,291		)
Debt	(150,367		)
Deferred income tax liabilities, net	(129,711		)
Total	$	498,789

The purchase price allocation requires subjective estimates that, if incorrect, could be material to the Company’s consolidated financial statements including the amount of depreciation and amortization expense. The most important estimates for measurement of tangible fixed assets are (a) the cost to replace the asset with a new asset and (b) the economic useful life of the asset after giving effect to its age, quality and condition. The most important estimates for measurement of intangible assets are (a) discount rates and (b) timing and amount of cash flows including estimates regarding customer renewals and cancellations. The goodwill recognized was attributable to the premium associated with the immediate entry into the Bakken Shale area where Power Fuels had an established workforce and operations.

Other 2012 Acquisitions

During the year ended December 31, 2012, the Company completed three other acquisitions in its shale solutions business (one in each of the first, second and third quarters of 2012). The aggregate purchase price of the acquired businesses was approximately $36.1 million consisting of 0.8 million shares of the Company’s common stock with an estimated fair value of approximately $30.5 million, cash consideration of approximately $0.4 million and approximately $5.2 million of contingent consideration.

In conjunction with the acquisition completed in shale solutions in the third quarter of 2012, the Company acquired a 51% interest in Appalachian Water Services, LLC (“AWS”) which owns and operates a water treatment and recycling facility in southwestern Pennsylvania, and has a call option to buy the remaining 49% at a fixed price at a stated future date, and the noncontrolling interest holder has a put option to sell the remaining 49% percent to the Company under those same terms. As such, the fixed price of the call option is equal to the fixed price of the put option. In accordance with ASC 480, “Distinguishing Liabilities from Equity”, the option contracts are viewed on a combined basis with the noncontrolling interest and accounted for as the Company’s financing of the purchase of the noncontrolling interest. Accordingly, $10.1 and $9.0 million, representing the present value of the option, was classified as other long-term obligations in the accompanying consolidated balance sheets at December 31, 2013 and 2012, respectively, with the financing accreted, as interest expense, to the strike price of the option over the period until settlement.

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The allocations of the combined aggregate purchase prices at the respective 2012 acquisition dates are summarized as follows (in thousands):



Accounts receivable	$	2,653
Equipment	21,108
Customer relationships	9,270
Goodwill	12,452
Other long-term obligations	(8,768		)
Other liabilities	(613		)
Total	$	36,102

Pro forma Financial Information Reflecting 2012-2013 Acquisitions

The following unaudited pro forma results of operations for the years ended December 31, 2013 and 2012, respectively, assume that all of the 2012 and 2013 acquisitions, excluding the acquisition of TFI which is presented as discontinued operations, were completed at the beginning of the periods presented. The pro forma results include adjustments to reflect additional amortization of intangibles and depreciation of assets associated with the acquired and merged businesses and additional interest expense for debt issued to consummate these transactions:



	December 31,
	2013			2012
Revenue	$	529,398		$	622,853
Net (loss) income	$	(133,693	)	$	26,515
Net (loss) income per share:
Basic	$	(5.43	)	$	1.11
Diluted	$	(5.43	)	$	1.00

The pro forma financial information presented above is not necessarily indicative of either the results of operations that would have occurred had the acquisitions been effective as of January 1 of the respective years or of future operations of the Company.

(5) Earnings Per Share

Basic and diluted loss per common share from continuing operations, basic and diluted loss per common share from discontinued operations and net loss per basic and diluted common share have been computed using the weighted average number of shares of common stock outstanding during the period. Basic earnings per share (“EPS”) excludes dilution and is computed by dividing net income (loss) applicable to common stockholders by the weighted average number of common shares outstanding for the period. Diluted EPS is based upon the weighted average number of common shares outstanding during the period plus the additional weighted average common equivalent shares during the period. Common equivalent shares result from the assumed exercise of outstanding warrants, restricted stock and stock options, the proceeds of which are then assumed to have been used to repurchase outstanding shares of common stock. Inherently, stock warrants are deemed to be antidilutive when the average market price of the common stock during the period is less than the exercise prices of the stock warrants.

Pursuant to ASC Topic 260-10-45-18, an entity that reports a discontinued operation in a period shall use income (loss) from continuing operations, adjusted for preferred dividends, as the control number in determining whether potential common equivalent shares are dilutive or antidilutive. That is, the same number of potential common equivalent shares used in computing the diluted per-share amount for income (loss) from continuing operations shall be used in computing all other reported diluted per-share amounts even if those amounts would be antidilutive to their respective basic per-share amounts. For the years ended December 31, 2014, 2013 and 2012, no shares of common stock underlying stock options, restricted stock, or other common stock equivalents were included in the computation of diluted EPS from continuing operations because the inclusion of such shares would be antidilutive based on the net losses from continuing operations reported for those periods. Accordingly, for the years ended December 31, 2014, 2013 and 2012, no shares of common stock underlying stock options, restricted stock, or other common stock equivalents were included in the computations of diluted EPS from loss from discontinued operations or diluted EPS from net loss per common share, because such shares were excluded from the computation of diluted EPS from continuing operations for those periods based on the guidance referenced above.

For the purpose of the computation of EPS, shares issued in connection with acquisitions that are contingently returnable are classified as issued but are not included in the basic weighted average number of shares outstanding until all applicable

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conditions are satisfied such that the shares are no longer contingently returnable. As of December 31, 2014, 2013 and 2012, respectively, excluded from the computation of basic EPS are approximately 0.3 million, 1.0 million and 1.3 million, respectively of contingently returnable shares that are subject to sellers’ indemnification obligations and were being held in escrow as of such dates.

The following table presents the calculation of basic and diluted net loss per common share:



	Year Ended December 31,
	2014			2013			2012
Numerator:
Loss from continuing operations	$	(457,178	)	$	(134,040	)	$	(6,597	)
Loss from discontinued operations	(58,426		)	(98,251		)	9,124
Net loss attributable to common stockholders	$	(515,604	)	$	(232,291	)	$	2,527

Denominator:
Weighted average shares—basic	26,090			24,492			14,994
Common stock equivalents	—			—			—
Weighted average shares—diluted	26,090			24,492			14,994

Basic and diluted loss per common share from continuing operations	$	(17.52	)	$	(5.47	)	$	(0.44	)
Basic and diluted loss per common share from discontinued operations	(2.24		)	(4.01		)	0.61
Net loss per basic and diluted common share	$	(19.76	)	$	(9.48	)	$	0.17

Antidilutive stock-based awards excluded	230			272			1,166

(6) Property, Plant and Equipment, net

Property, plant and equipment consists of the following:



	December 31,
	2014			2013
Land	$	11,750		$	10,640
Buildings and improvements	43,410			39,965
Pipelines	70,511			70,511
Disposal wells	61,070			56,864
Landfill	28,130			28,130
Machinery and equipment	38,543			35,911
Equipment under capital leases	16,180			16,308
Motor vehicles and trailers	146,242			144,099
Rental equipment	164,640			162,947
Office equipment	6,647			4,729
	587,123			570,104
Less accumulated depreciation	(155,790		)	(91,446		)
Construction in process	44,649			19,883
Property, plant and equipment, net	$	475,982		$	498,541

Depreciation expense for the years ended December 31, 2014, 2013, and 2012 was $68.7 million, $78.8 million and $40.1 million, respectively. During the year ended December 31, 2013, the Company recorded impairment of property, plant and equipment of $107.4 million (Note 8).

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(7) Goodwill and Intangible Assets

Goodwill

Changes in the carrying amount of goodwill were as follows:



Balance at December 31, 2012	$	415,176
Additions - 2013 acquisitions (Note 4)	341
Acquisition adjustments, net	(6,821		)
Balance at December 31, 2013	408,696
Impairment (Note 8)	(303,975		)
Balance at December 31, 2014	$	104,721

As described in Note 8, the Company recorded a goodwill impairment charge of $100.7 million related to the Company's Northeast ($33.8 million) and Southern ($66.9 million) divisions at September 30, 2014. During the three months ended December 31, 2014 the Company took an additional goodwill charge of $203.3 million in the Rocky Mountain division. The remaining goodwill balance resides in the Rocky Mountain division.

Intangible Assets

Intangible assets consist of the following:



	December 31, 2014								December 31, 2013
	Gross Carrying Amount		Accumulated Amortization			Net		Remaining Useful Life	Gross Carrying Amount		Accumulated Amortization			Net		Remaining Useful Life
Customer relationships	$	11,694	$	(5,133	)	$	6,561	6.6	$	156,694	$	(21,715	)	$	134,979	13.6
Disposal permits	1,269		(288		)	981		6.2	1,269		(132		)	1,137		7.2
Customer contracts	17,352		(5,137		)	12,215		12.0	17,352		(4,105		)	13,247		13.0
	$	30,315	$	(10,558	)	$	19,757	9.9	$	175,315	$	(25,952	)	$	149,363	13.4

The remaining weighted average useful lives shown are calculated based on the net book value and remaining amortization period of each respective intangible asset. During the years ended December 31, 2014 and 2013, the Company recorded impairment charges of $112.4 million and $4.5 million, respectively, for the write-down of certain intangible assets (Note 8). The remaining $6.6 million of customer relationships are comprised of $5.6 million in the Northeast division and $1.0 million in the Southern division. The $1.0 million of remaining disposal permits and $12.2 million of customer contracts are in the Southern division.

Amortization expense was $17.2 million, $20.4 million and $7.5 million for the years ended December 31, 2014, 2013 and 2012, respectively. As of December 31, 2014, future amortization expense of intangible assets is estimated to be:



2015	$	2,836
2016	2,578
2017	2,129
2018	1,998
2019	1,784
Thereafter	8,432
Total	$	19,757

(8) Impairment of Long-Lived Assets and Goodwill

During the year ended December 31, 2012, the Company recognized a $3.7 million impairment charge on three saltwater disposal wells primarily in the Haynesville shale area (Southern division) after the wells developed technical problems which required the Company to suspend their use. During the year ended December 31, 2012, the Company also recognized a $2.4 million impairment charge related to the write-down of a customer relationship intangible associated with a portion of a prior business acquisition in the Northeast division.

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During the year ended December 31, 2013, the Company recognized long-lived asset impairment charges totaling $111.9 million for write-downs to the carrying values of the Company’s freshwater pipeline in the Haynesville Shale basin of $27.0 million and certain other long-lived assets including customer relationships and disposal permit intangibles totaling $4.5 million and disposal wells and equipment of $80.4 million in the Haynesville, Eagle Ford, Tuscaloosa Marine and Barnett Shale basins, which is characterized as impairment of long-lived assets in the Company's consolidated statement of operations. Additionally, the Company recorded a goodwill impairment charge in its industrial solutions division of $98.5 million during the three months ended September 30, 2013, which is included within the amounts reported in "Loss from discontinued operations, net of income taxes" in the Company's consolidated statements of operations.

During the three months ended September 30, 2014, the Company completed the previously-announced organizational realignment of its shale solutions segment into three operating divisions, which the Company considers to be its new operating and reportable segments: (1) the Northeast Division comprising the Marcellus and Utica Shale areas, (2) the Southern Division comprising the Haynesville, Eagle Ford, Mississippian and Permian Basin Shale areas and (3) the Rocky Mountain Division comprising the Bakken Shale area. As part of this organizational realignment, the Company re-evaluated the goodwill of its reporting units, defined as an operating segment or one level below an operating segment, for impairment. The Company determined that its reporting units are the same as its new operating and reportable segments. Previously, the shale solutions operating segment was comprised of the shale solutions (excluding AWS and Pipeline) reporting unit, the AWS reporting unit and the Pipeline reporting unit. Given the change in the composition of its reporting units, the Company was required to allocate its $408.7 million of goodwill on a relative fair value basis to the new reporting units.

In addition to the annual goodwill impairment test performed as of September 30, the Company tests its goodwill and long-lived assets, including other identifiable intangible assets with useful lives, for impairment if and when events or changes in circumstances indicate that the carrying value of goodwill and/or long-lived assets may not be recoverable. During the quarter ended June 30, 2014, the Company considered a number of relevant factors which are potential indicators of impairment, including (among others) the potential impacts of the aforementioned organizational realignment of its continuing operations and the Company’s current and near-term financial results as well as the fact that the market price of the Company’s common stock, taking into consideration potential control premiums, has wavered above and below its book value since the third quarter of 2013, as previously disclosed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2013 and subsequent Quarterly Reports on Form 10-Q. Based on these factors, the Company was required to perform impairment tests to determine whether the carrying values are fully recoverable of both its long-lived assets and goodwill. The Company completed the review of its long-lived assets in the quarter ended September 30, 2014 and concluded the fair value of such assets exceeded their carrying values, thus no long-lived asset impairment was indicated.

The goodwill impairment test has two steps. The first step of the goodwill impairment test, used to identify potential impairment, compares the fair value of a reporting unit with its carrying amount including goodwill. During the three months ended September 30, 2014, the Company performed step one of the goodwill impairment test for each of its three new reporting units: the Northeast division, Southern division and Rocky Mountain division. To measure the fair value of each new reporting unit, the Company used a combination of the discounted cash flow method and the guideline public company method. Based

on the results of the step-one goodwill impairment review, the Company concluded the fair value of the Rocky Mountain

division exceeded its carrying amount by approximately 14% and accordingly, the second step of the impairment test was not

necessary for this reporting unit. Conversely, the Company concluded the fair value of the Northeast and Southern reporting units were less than their carrying values thereby requiring the Company to proceed to the second step of the goodwill impairment test. The second step of the goodwill impairment test, used to measure the amount of the impairment loss, compares the implied fair value of the reporting unit goodwill with its carrying amount. For both the Northeast and Southern reporting units, the carrying values of the re-allocated goodwill exceeded their implied fair values. Accordingly, the Company recognized a charge of $100.7 million ($66.9 million in the Southern division and $33.8 million in the Northeast division) during the three months ended September 30, 2014, which is characterized as "Impairment of goodwill" in the Company’s

consolidated statement of operations.

Due to the continued significant decline in oil and gas prices and the market price of the Company's common stock during the three months ended December 31, 2014, the Company determined that these triggering events required the Company to complete further impairment tests. Long-lived assets were grouped at the basin level for purposes of assessing their recoverability as the Company concluded the basin level is the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. In the Northeast division and Southern divisions, the undiscounted cash flows of the asset groups exceeded their carrying values; therefore, no impairment was indicated. In the Bakken Shale basin, the carrying value of the asset group exceeded its undiscounted cash flows indicating impairment which resulted in an impairment charge of $112.4 million related to the customer relationship intangible asset. Such amount is reported in "Impairment of long-lived assets" in the Company's consolidated statement of operations. The Northeast division and Southern divisions had no goodwill balances; therefore, the Company performed step one of the goodwill impairment test only for the

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Rocky Mountain division. The Rocky Mountain division is comprised of the Rocky Mountain reporting unit. The Company used a combination of the discounted cash flow method and the guideline public company method to measure the fair value of the Rocky Mountain reporting unit. Based on the results of the step-one goodwill impairment review, the Company concluded the fair value of the Rocky Mountain division was less than its carrying value thereby requiring the Company to proceed to the second step of the goodwill impairment test. The second step of the goodwill impairment test, used to measure the amount of the impairment loss, compares the implied fair value of the reporting unit goodwill with its carrying amount. The carrying value of the Rocky Mountain reporting unit goodwill exceeded its implied fair value and as such, the Company recognized a charge of $203.3 million during the three months ended December 31, 2014, which is characterized as "Impairment of goodwill" in the Company’s consolidated statement of operations.

Impairment charges recorded for the year ended December 31, 2014 and 2013, related to continuing operations by reportable segment consist of the following:



	December 31, 2014								December 31, 2013
	Northeast		Southern		Rocky Mountain		Total		Northeast		Southern		Rocky Mountain		Total
Impairment of property, plant and equipment, net	$	—	$	—	$	—	$	—	$	152	$	107,261	$	—	$	107,413
Impairment of intangibles, net	—		—		112,436		112,436		—		4,487		—		4,487
Impairment of Goodwill	33,831		66,885		203,259		303,975		—		—		—		—
Total	$	33,831	$	66,885	$	315,695	$	416,411	$	152	$	111,748	$	—	$	111,900

The fair values of each of the reporting units as well as the related assets and liabilities utilized to determine both the 2014 and 2013 impairment were measured using Level 2 and Level 3 inputs as described in Note 11.

The Company believes the assumptions used in its discounted cash flow analysis are appropriate and result in reasonable estimates of the implied fair value of each reporting unit. The Company further believes the most significant assumption used in its analysis is the revenue growth as limited by oil and gas prices. However, the Company may not meet its revenue targets, working capital and capital investment requirements may be higher than forecast, changes in credit or equity markets may result in changes to the Company’s discount rate and general business conditions may result in changes to the Company’s terminal value assumptions for its reporting units.

In evaluating the reasonableness of the Company’s fair value estimates, the Company considers (among other factors) the relationship between its book value, the market price of its common stock and the fair value of its reporting units. At December 31, 2014 and March 13, 2015, the closing market prices of the Company’s common stock were $5.55 and $2.92 per share, respectively, compared to its book value per share of $5.56 as of December 31, 2014. If the Company’s book value per share were to continue to exceed its market price per share plus a control premium as indicated at March 13, 2015, in addition to continued downward pricing in services driven by oil and gas price depression, it would likely indicate the occurrence of events or changes that would cause the Company to perform additional impairment analyses which could result in further revisions to its fair value estimates. While the Company believes that its estimates of fair value are reasonable, the Company will continue to monitor and evaluate this relationship. Additionally, should actual results differ materially from our projections, additional impairment would likely result.

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(9) Accrued Liabilities

Accrued liabilities consist of the following:



	December 31,
	2014		2013
Accrued payroll and employee benefits	$	12,566	$	9,380
Accrued insurance	6,830		2,881
Accrued legal and environmental costs	1,421		33,707
Accrued taxes	1,477		1,239
Accrued interest	8,570		8,294
Amounts payable to related party (Note 18)	114		110
Accrued operating costs	5,685		3,765
Accrued other	6,732		4,055
Total accrued liabilities	$	43,395	$	63,431

Accrued legal and environmental costs included $0.4 million and $27.0 million at December 31, 2014 and 2013, respectively, in connection with the settlement of the 2010 Class Action litigation. As further described in Note 16, during the year ended December 31, 2014, the cash portion of the settlement of the 2010 Class Action litigation was paid and the Company issued 0.8 million shares of its common stock in connection with such settlement.

(10) Debt

Debt consists of the following at December 31, 2014 and December 31, 2013:



			December 31, 2014							December 31, 2013
	Interest Rate	Maturity Date	Unamortized Deferred Financing Costs		Fair Value of Debt (f)		Carrying Value of Debt			Carrying Value of Debt
Amended Revolving Credit Facility (a)	4.61%	Nov. 2017	$	—	$	—	$	—		$	135,990
Asset-Based Revolving Credit Facility (b)	2.41%	Jan. 2018	5,476		183,065		183,065			—
2018 Notes (c)	9.875%	Apr. 2018	11,866		245,000		400,000			400,000
Vehicle financings (d)	3.60%	Various	—		14,872		14,872			19,956
Total debt			$	17,342	$	442,937	597,937			555,946
Original issue discount (e)							(874		)	(1,084		)
Original issue premium (e)							255			315
Total debt, net							597,318			555,177
Less: current portion							(4,863		)	(5,464		)
Long-term portion of debt							$	592,455		$	549,713

_____________________


(a)	The interest rate presented represents the interest rate on the $325.0 million senior secured revolving credit facility (the “Amended Revolving Credit Facility”) at December 31, 2013.


(b)	The interest rate presented represents the interest rate on the $245.0 million asset-based revolving credit facility (the “ABL Facility”) at December 31, 2014.

(c)

The interest rate presented represents the coupon rate on the Company’s outstanding $400.0 million aggregate principal amounts of 9.875% Senior Notes due 2018 (the “2018 Notes”), excluding the effects of deferred financing costs, original issue discounts and original issue premiums. Including the impact of these items, the effective interest rate on the 2018 Notes is approximately 11.0%. Interest payments are due semi-annually in April and October.

(d)

Vehicle financings consist of installment notes payable and capital lease arrangements related to fleet purchases with a weighted-average annual interest rate of approximately 3.60% and which mature in varying installments between 2014 and 2019. Installment notes payable and capital lease obligations were $0.3 million and $14.6 million, respectively, at December 31, 2014 and were $1.1 million and $18.8 million, respectively, at December 31, 2013.

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(e)

The issuance discount represents the unamortized difference between the $250.0 million aggregate principal amount of the 2018 Notes issued in April 2012 and the proceeds received upon issuance (excluding interest and fees). The issuance premium represents the unamortized difference between the proceeds received in connection with the November 2012 issuance of the 2018 Notes (excluding interest and fees) and the $150.0 million aggregate principal amount thereunder.


(f)	The estimated fair value of the Company’s 2018 Notes is based on quoted market prices as of December 31, 2014. The Company’s ABL Facility and vehicle financings bear interest at rates commensurate with market rates and therefore their respective carrying values approximate fair value.

The required principal payments for all borrowings for each of the five years following the balance sheet date are as follows:



2015	$	4,931
2016	4,276
2017	4,379
2018	584,287
2019	64
Thereafter	—
Total	$	597,937

2018 Notes

The estimated fair value of the Company’s 2018 Notes is based on quoted market prices as of December 31, 2014. The Company’s Revolving Credit Facility and other debt obligations, including capital leases, bear interest at rates commensurate with market rates and therefore their respective carrying values approximate fair value.

On April 10, 2012, the Company completed a private placement offering of $250.0 million aggregate principal amount of 9.875% senior unsecured notes due April 2018 (the “Notes”). Net proceeds from the issuance of the Notes, after deducting underwriters’ fees and offering expenses, totaled $240.8 million and were used to repay the outstanding principal balances of the Company’s old credit facility and to partially finance the acquisition of TFI. In connection with the repayment of the old credit facility, the Company wrote-off approximately $2.6 million of unamortized deferred financing costs, which is characterized as loss on extinguishment of debt in the accompanying consolidated statement of operations for the year ended December 31, 2012.

On November 5, 2012, the Company completed a private placement offering of $150.0 million aggregate principal amount of 9.875% senior unsecured notes due April 2018 (the “Additional Notes” and with the Notes, are collectively referred to as the “2018 Notes” ). Net proceeds from the issuance of the Additional Notes, after deducting underwriters’ fees and offering expenses, totaled approximately $147.0 million and were used to partially finance the merger with Power Fuels.

The 2018 Notes are redeemable, at the Company’s option, in whole or in part, at any time and from time to time on and after April 15, 2015 at the applicable redemption price set forth below, if redeemed during the 12-month period commencing on April 15 of the years set forth below:



Redemption Period	Price
2015	104.938	%
2016	102.469	%
2017 and thereafter	100.000	%

In addition, at any time on or prior to April 15, 2015, the Company may on any one or more occasions redeem up to 35% of the original aggregate principal amount of the 2018 Notes, with funds in an equal aggregate amount up to the aggregate proceeds of certain equity offerings of the Company, at a redemption price of 109.875%. The indentures governing the 2018 Notes also contain restrictive covenants that, among other things, limit the Company’s ability to transfer or sell assets; pay dividends or make certain distributions, buy subordinated indebtedness or securities, make certain investments or make other restricted payments; incur or guarantee additional indebtedness or issue preferred stock; create or incur liens securing indebtedness; incur dividend or other payment restrictions affecting subsidiary guarantors; consummate a merger, consolidation or sale of all or substantially all of our assets; enter into transactions with affiliates; engage in business other than a business that is the same or similar, reasonably related, complementary or incidental to our current business and/or that of our subsidiaries; and make certain acquisitions or investments. The Company was compliant with these covenants at December 31, 2014.

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The 2018 Notes also contain restrictive covenants that limit any borrowing subsequent to breaching a fixed charge coverage ratio and senior leverage ratio as defined in the indenture. We were in compliance with such covenants as of December 31, 2014 and March 13, 2015.

Amended Revolving Credit Facility

Concurrent with the April 10, 2012 repayment and termination of its previous credit facility, the Company entered into a new $150.0 million senior revolving credit agreement (the “Revolving Credit Facility”) with Wells Fargo Bank as Administrative Agent and the lenders party thereto. The Revolving Credit Facility contained an uncommitted “accordion” feature, which allowed the Company to increase borrowings by up to an additional $100.0 million. On November 30, 2012, the Company amended this senior revolving credit agreement (the “Amended Revolving Credit Facility”) to increase the commitment from $150.0 million to $325.0 million and extend the maturity from April 10, 2017 to November 30, 2017. Together with the $100.0 million uncommitted “accordion” feature under the agreement (which was not affected by the amendment), the Amended Revolving Credit Facility provided for total maximum potential borrowings of $425.0 million. Interest on the Amended Revolving Credit Facility accrued based generally on London inter-bank offered rate (“LIBOR”) plus a margin of between 2.50% and 3.75% based on a ratio of the Company’s total debt to EBITDA, or an alternate interest rate equal to the higher of the Federal Funds Rate as published by the Federal Reserve Bank of New York plus ¹/2 of 1.00%, the prime commercial lending rate of the administrative agent under the Credit Agreement, and monthly LIBOR plus 1.00%, plus a margin of between 1.50% and 2.75% based on the Company’s total debt to EBITDA. As of December 31, 2012, the Company had $177.0 million available for borrowing under the Amended Revolving Credit Facility. A portion of the Amended Revolving Credit Facility was available for the issuance of letters of credit up to $20.0 million in the aggregate and swingline loans, which are three day loans that can be drawn on the same day as requested for an amount not to exceed $30.0 million. The Company was required to pay fees on the unused commitments of the lenders under the Amended Revolving Credit Facility, a letter of credit fee on the outstanding stated amount of letters of credit plus facing fees for the letter of credit issuing banks and any other customary fees.

In September 2013, the Company executed an amendment to the Amended Revolving Credit Facility (the “Amendment”) to increase the permissible maximum total debt leverage ratio for the periods ending September 30, 2013, December 31, 2013, March 31, 2014 and June 30, 2014. The pricing of the Amended Revolving Credit Facility was unchanged by the Amendment. In connection with the Amendment, the Company incurred lender and third party fees of approximately $0.6 million

ABL Facility

In February 2014, the Company entered into a new asset-based revolving credit facility (“ABL Facility”) with Wells Fargo Bank as Administrative Agent and other lenders which amended and replaced its Amended Revolving Credit Facility. Initially, the ABL Facility provided a maximum credit amount of $200.0 million, which could be increased to $225.0 million through a $25.0 million accordion feature. Initial borrowings under the ABL Facility were used to refinance amounts outstanding under the Amended Revolving Credit Facility and fund certain related fees and expenses. In March 2014, the Company expanded the ABL Facility to increase the maximum availability from $200.0 million to $245.0 million and also increased the accordion feature from $25.0 million to $50.0 million. The terms and pricing of the facility remained the same and were unaffected by the upsizing of the facility size. The ABL Facility is used to support ongoing working capital needs and other general corporate purposes, including growth initiatives. The ABL Facility, which matures at the earlier of five years from the closing date or 90 days prior to the maturity of other material indebtedness including the 2018 Notes, is secured by substantially all of the Company’s assets.

The terms of the ABL Facility limit the amount the Company can borrow up to the lesser of (a) $245.0 million or (b) 85% of the amount of the Company’s eligible accounts receivable plus the lower of (i) 95% of the net book value of the Company’s eligible rental equipment, tractors and trailers, and (ii) 85% of the appraised net orderly liquidation value of the Company’s eligible rental equipment, tractors and trailers, less any customary reserves. The borrowing base is evaluated monthly. The ABL Facility includes a letter of credit sub-limit of $10.0 million and a swingline facility sub-limit equal to 10% of the total facility size for more immediate cash needs.

Interest accrues on outstanding loans under the ABL Facility at a floating rate based on, at the Company’s election, (i) the greater of (a) the prime lending rate as publicly announced by Wells Fargo, (b) the Federal Funds rate plus 0.5% or (c) the one month LIBOR plus one percent, plus, in each case, an applicable margin of 0.75% to 1.50% or (ii) the LIBOR rate plus an applicable margin of 1.75% to 2.50%. The Company is also required to pay fees on the unused commitments of the lenders under the ABL Facility, fees for outstanding letters of credit and other customary fees.

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Costs associated with the ABL Facility totaling approximately $3.6 million were capitalized as deferred financing costs in the year ended December 31, 2014, and the Company wrote off unamortized deferred financing costs associated with its Amended Revolving Credit Facility of approximately $3.2 million in the same period.

Indebtedness

Financial Covenants and Borrowing Limitations

The Company's credit facility requires, and any future credit facilities will likely require, the Company to comply with specified financial ratios that may limit the amount the Company can borrow under its credit facility. A breach of any of the covenants under the indenture governing the 2018 Notes or the credit facility, as applicable, could result in a default. The Company's ability to satisfy those covenants depends principally upon its ability to meet or exceed certain positive operating performance metrics including, but not limited to, earnings before interest, taxes, depreciation and amortization, or EBITDA, and ratios thereof, as well as certain balance sheet ratios. Any debt agreements the Company enters into in the future may further limit its ability to enter into certain types of transactions.

The ABL Facility contains certain financial covenants that require the Company to maintain a senior leverage ratio and, upon the occurrence of certain specified conditions, a fixed charge coverage ratio as well as certain customary limitations on our ability to, among other things, incur debt, grant liens, make acquisitions and other investments, make certain restricted payments such as dividends, dispose of assets or undergo a change in control. The senior leverage ratio is calculated as the ratio of senior secured debt to adjusted EBITDA (which includes net (loss) income loss plus certain items such as interest, taxes, depreciation, amortization, impairment charges, stock-based compensation and other adjustments as defined in the indenture), and is limited to 3.0 to 1.0. The Company's $400.0 million of 2018 Notes are not secured and thus are excluded from the calculation of this ratio. The fixed charge coverage ratio, which only applies if excess availability under the ABL Facility falls below 12.5% of the maximum revolver amount, requires the ratio of adjusted EBITDA (as defined) less capital expenditures to fixed charges (as defined) to be at least 1.1 to 1.0. The senior leverage ratio and fixed charge coverage ratio covenants could have the effect of limiting the Company's availability under the ABL Facility, as additional borrowings would be prohibited if, after giving pro forma effect thereto, the Company would be in violation of either such covenant. As of December 31, 2014, the Company remained in compliance with its debt covenants and the availability was $56.5 million; however, the Company's ratio of adjusted EBITDA to fixed charges was less than 1.1 to 1.0 (as calculated pursuant to the ABL Facility). As such, the Company's net availability was reduced by 12.5% of the maximum revolver amount, or $30.6 million, resulting in approximately $25.9 million of net availability as of December 31, 2014.

The maximum amount the Company can borrow under our ABL Facility is subject to contractual and borrowing base limitations which could significantly and negatively impact its future access to capital required to operate its business. Borrowing base limitations are based upon eligible accounts receivable and equipment. If the value of its accounts receivable or equipment decreases for any reason, or if some portion of its accounts receivable or equipment is deemed ineligible under the terms of its credit facility agreement, the amount the Company can borrow under the credit facility could be reduced. These limitations could have a material adverse impact on the Company's liquidity and financial condition. In addition, the administrative agent for the Company's ABL Facility has the periodic right to perform an appraisal of the assets comprising the Company's borrowing base. If an appraisal results in a reduction of the borrowing base, then a portion of the outstanding indebtedness under the credit facility could become immediately due and payable. Any such repayment obligation could have a material adverse impact on the Company's liquidity and financial condition.

The indenture governing the 2018 Notes contains restrictive covenants on the incurrence of senior secured indebtedness, including incurring new borrowings under the Company's revolving credit facility, which would limit its ability to incur incremental new senior secured indebtedness in certain circumstances and access to capital if the Company's fixed charge coverage ratio falls below 2.0 to 1.0. To the extent that the fixed charge coverage ratio is below 2.0 to 1.0, the indenture prohibits the Company's incurrence of new senior secured indebtedness, at that point in time, to the greater of $150.0 million and the amount of debt as restricted by the secured leverage ratio, which is the ratio of senior secured debt to EBITDA, of 2.0 to 1.0, as determined pursuant to the indenture. The covenant does not require repayment of existing borrowings if greater than $150 million at that time, but rather limits new borrowings during any such period. The 2.0 to 1.0 fixed charge coverage ratio is an incurrence covenant, not a maintenance covenant.

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The covenants described above are subject to important exceptions and qualifications. The Company's ability to comply with these covenants will likely be affected by some events beyond its control, and the Company cannot assure you that it will satisfy those requirements. A breach of any of these provisions could result in a default under such indenture, credit facility or other debt obligation, or any future credit facilities the Company may enter into, which could allow all amounts outstanding thereunder to be declared immediately due and payable, subject to the terms and conditions of the documents governing such indebtedness. If the Company was unable to repay the accelerated amounts, its secured lenders could proceed against the collateral granted to them to secure such indebtedness. This would likely in turn trigger cross-acceleration and cross-default rights under any other credit facilities and indentures. If the amounts outstanding under the 2018 Notes or any other indebtedness outstanding at such time were to be accelerated or were the subject of foreclosure actions, the Company cannot assure you that its assets would be sufficient to repay in full the money owed to the lenders or to its other debt holders. The Company was in compliance with such covenants as of December 31, 2014 and March 13, 2015.

The Company may also be prevented from taking advantage of business opportunities that arise because of the limitations imposed on it by such restrictive covenants. These restrictions may also limit the Company's ability to plan for or react to market conditions, meet capital needs or otherwise restrict its activities or business plans and adversely affect its ability to finance its operations, enter into acquisitions, execute its business strategy, effectively compete with companies that are not similarly restricted or engage in other business activities that would be in its interest. In the future, the Company may also incur debt obligations that might subject it to additional and different restrictive covenants that could affect its financial and operational flexibility. The Company cannot assure you that it will be granted waivers or amendments to the indenture governing the 2018 Notes, the credit facility or such other debt obligations if for any reason the Company is unable to comply with its obligations thereunder or that it will be able to refinance its debt on acceptable terms, or at all, should the Company seek to do so. Any such limitations on borrowing under our credit facility could have a material adverse impact on the Company's liquidity.

(11) Fair Value Measurements

Measurements

Fair value represents an exit price, representing the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that should be determined based on assumptions that market participants would use in pricing an asset or liability. GAAP establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows:


•	Level 1 — Observable inputs such as quoted prices in active markets that are accessible at the measurement date for identical assets or liabilities;


•	Level 2 — Inputs, other than the quoted prices in active markets, that are observable either directly or indirectly; and


•	Level 3 — Unobservable inputs in which there is little or no market data, which require the reporting entity to develop its own assumptions.

Assets and liabilities measured at fair value on a recurring basis as of December 31, 2014 and December 31, 2013 and the fair value hierarchy of the valuation techniques the Company utilized to determine such fair value used significant unobservable inputs (Level 3) and were as follows:



	Fair Value
December 31, 2014
Assets - cost method investment	$	3,169
Liabilities:
Contingent consideration	9,824
Financing obligation to acquire non-controlling interest	11,000
December 31, 2013
Assets - cost method investment	$	3,382
Liabilities:
Contingent consideration	15,457
Financing obligation to acquire non-controlling interest	10,104

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Contingent Consideration

The Company and its subsidiaries are liable for certain contingent consideration payments in connection with various acquisitions. The fair value of the contingent consideration obligations was determined using a probability-weighted income approach at the acquisition date and is revalued at each reporting date or more frequently if circumstances dictate based on changes in the discount periods and rates, changes in the timing and amount of the revenue estimates and changes in probability assumptions with respect to the likelihood of achieving the obligations. Contingent consideration is reported as "Current portion of contingent consideration" and "Long-term portion of contingent consideration" in the Company’s consolidated balance sheets. Changes to the fair value of contingent consideration are recorded as "Other income (expense), net" in the Company’s consolidated statements of operations. Accretion expense related to the increase in the net present value of the contingent liabilities is included in interest expense for the period. The fair value measurement is based on significant inputs not observable in the market, which are referred to as Level 3 inputs.

Changes to contingent consideration obligations during the year ended December 31, 2014 and the year ended December 31, 2013 were as follows:



	December 31,
	2014			2013
Balance at beginning of period	$	15,457		$	10,431
Additions related to acquisitions	—			8,141
Accretion	476			293
Cash payments	(1,014		)	(1,884		)
Issuances of stock	(3,789		)	(47		)
Changes in fair value of contingent consideration, net	(1,306		)	(1,477		)
Balance at end of period	9,824			15,457
Less: current portion	(9,274		)	(13,113		)
Long-term portion of contingent consideration	$	550		$	2,344

Acquisitions with remaining contingent consideration obligations are as follows:

Keystone Vacuum, Inc.—In addition to the initial purchase price, the Company is obligated to make additional payments to the sellers of Keystone Vacuum, Inc. (“KVI”), which the Company acquired on February 3, 2012, for each of the fiscal years ended January 31, 2013 through 2016, in which KVI’s adjusted EBITDA (as defined) is greater than applicable adjusted EBITDA targets. Any additional amounts payable are payable in shares of the Company’s common stock or cash at the Company’s discretion and any such additional payments are capped at an aggregate value of $7.5 million. During 2013, the Company issued less than 0.1 million shares of our common stock and made a cash payment of approximately $0.9 million in satisfaction of contingent consideration obligation for the contract period ended January 31, 2013. During 2014, the Company made a cash payment of approximately $0.5 million in satisfaction of contingent consideration obligation for the contract period ended January 31, 2014.

Complete Vacuum and Rentals, Inc.—In addition to the initial purchase price, the Company is obligated to make additional payments to the former shareholders of Complete Vacuum and Rentals, Inc. (“CVRI”), which the Company acquired on November 30, 2010. Under the terms of a February 2014 settlement agreement and release, which resolved certain previous disputes regarding additional consideration due by the Company and indemnification obligations of the former shareholders of CVRI, the Company issued 0.2 million shares to the former shareholders of CVRI with a value of $3.8 million. The remaining $2.0 million obligation to issue additional shares based on the Company's financial performance was reduced to zero as of December 31, 2014.

Ideal Oilfield Disposal, LLC—In addition to the initial purchase price, the Company is obligated to pay the former owners of Ideal up to a maximum amount of $8.5 million upon the issuance of a second special waste disposal permit issued to expand its current landfill, depending on permitted capacity. The additional amount is payable in cash or in shares of the Company’s common stock at the Company’s discretion and is due at such time the former owners deliver to the Company all permits, certificates and other documents necessary to operate the portion of the landfill associated with the additional capacity. The Company has also agreed to pay the former owners of Ideal certain additional amounts based on future revenues of the landfill, which was determined to be appropriately expensed as revenue is incurred.

Financing Obligation to Acquire Non-Controlling Interest

The fair value of the financing obligation to acquire non-controlling interest represents the present value of the Company’s right to acquire the remaining 49% interest in Appalachian Water Services, LLC (“AWS”) from the non-controlling interest holder at

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a fixed price of $11.0 million payable in shares of the Company’s common stock. The non-controlling interest holder has a put option to sell the remaining 49% to the Company under the same terms beginning in January 2015, and in January 2015, the non-controlling interest holder provided notice to the Company of exercise of such put option. The closing of such put option has not occurred. In accordance with ASC 480, Distinguishing Liabilities from Equity, the instrument is accounted for as a financing of the Company’s purchase of the minority interest. Total accretion expense related to the Company’s financing obligation in AWS was $0.9 million and $1.1 million for the year ended December 31, 2014 and 2013, respectively.

Other

In addition to the Company’s assets and liabilities that are measured at fair value on a recurring basis, the Company is required by GAAP to measure certain assets and liabilities at fair value on a nonrecurring basis after initial recognition. Generally, assets, liabilities and reporting units are measured at fair value on a nonrecurring basis as a result of impairment reviews and any resulting impairment charge. In connection with its impairment review of long-lived assets described in Note 8, the Company measured the fair value of its asset groups for those asset groups deemed not recoverable, based on Level 3 inputs consisting of the discounted future cash flows associated with the use and eventual disposition of the asset group. In connection with its goodwill impairment review described in Note 8, the Company measured the fair value of its reporting units using a combination of the discounted cash flow method and the guideline public company method. The discounted cash flow method is based on Level 3 inputs consisting primarily of the Company’s five-year forecast and utilizes forward-looking assumptions and projections as well as factors impacting long-range plans such as pricing, discount rates and commodity prices. The guideline public company method is based on Level 2 inputs and considers potentially comparable companies and transactions within the industries where the Company’s reporting units participate, and applies their trading multiples to the Company’s reporting units. This approach utilizes data from actual marketplace transactions, but reliance on its results is limited by difficulty in identifying entities that are specifically comparable to the Company’s reporting units, considering their diversity, relative sizes and levels of complexity.

Cost method investments are measured at fair value on a nonrecurring basis when deemed necessary, using observable inputs such as trading prices of the stock as well as using discounted cash flows, incorporating adjusted available market discount rate information and the Company’s estimates for liquidity risk.

(12) Equity

2014 Common Stock Issuances


•	On March 14, 2014, the Company issued approximately 0.2 million shares of common stock in connection with a partial payment under an earn-out obligation (Note 11).


•	On July 2, 2014, the Company issued approximately 0.3 million shares of common stock in connection with the settlement of the 2010 Class Action litigation (Note 16).


•	On August 27, 2014, the Company issued an additional 0.5 million shares of common stock in connection with the settlement of the 2010 Class Action litigation (Note 16).

2013 Common Stock Issuances


•	On June 17, 2013, the Company issued approximately 0.5 million unregistered shares of common stock in a private placement pursuant to Section 4(a)(2) under the Securities Act in connection with an acquisition in the Utica Shale basin (Note 3).


•	On July 9, 2013, the Company issued approximately 0.2 million unregistered shares of common stock in a private placement pursuant to Section 4(a)(2) under the Securities Act in connection with the acquisition of Ideal Oilfield Disposal, LLC (Note 3).


•	On July 18, 2013, the Company issued approximately 0.1 million shares of common stock in connection with the settlement of the 2010 Derivative Action (Note 16).

Preferred Stock

The Company is authorized to issue 1.0 million shares of preferred stock with such designations, voting and other rights and preferences as may be determined from time to time by the Board of Directors. At December 31, 2014 and 2013, no shares of preferred stock were outstanding.

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(13) Share-based Compensation

We may grant stock options, stock appreciation rights, restricted common stock and restricted stock units, performance shares and units, other stock-based awards and cash-based awards to our employees, directors, consultants and advisors pursuant to the Nuverra Environmental Solutions 2009 Equity Incentive Plan (as amended, the “2009 Plan”).

Stock Options

The Company measures the cost of employee services received in exchange for awards of stock options based on the fair value of those awards at the date of grant. Awards of stock options generally vest in equal increments over a three-year service period from the date of grant. The fair value of stock options on the date of grant is amortized to compensation expense on a straight-line basis over the requisite service period for the entire award, that is, over the requisite service period of the last separately vesting portion of the award. The exercise price for stock options is equal to the market price of the Company’s common stock on the date of grant. The maximum contractual term of stock options is 10 years. The Company estimates the fair value of stock options using a Black-Scholes option-pricing model.

The assumptions used to estimate the fair value of stock awards granted in the years ended December 31, 2014, 2013 and 2012 are as follows:



	Year Ended December 31,
	2014		2013		2012
Volatility	48.7	%	44.4	%	40.1	%
Expected term (years)	8.0		8.0		10.0
Risk free interest rate	2.4	%	2.0	%	2.1	%
Expected dividend yield	—	%	—	%	—	%

The expected term of stock options represents the period of time that the stock options granted are expected to be outstanding taking into consideration the contractual term of the options and termination history and option exercise behaviors of the Company’s employees. The expected volatility is based on the historical price volatility of the Company’s common stock. The risk-free interest rate represents the U.S. Treasury bill rate for the expected term of the related stock options. The dividend yield represents the Company’s anticipated cash dividend over the expected term of the stock options.

Compensation cost for stock options recognized in operating results is included in general and administrative expense in the consolidated statements of operations and was $0.8 million, $1.7 million and $2.0 million for the years ended December 31, 2014, 2013 and 2012, respectively. There was no income tax benefit recognized in the consolidated statement of operations for the year ended December 31, 2014 associated with stock option activity, as all deferred tax assets were fully reserved by a valuation allowance. The income tax (expense) benefit recognized in the consolidated statements of operations was $(0.1) million and $0.9 million for the years ended December 31, 2013 and 2012, respectively.

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A summary of stock option activity during 2014 is presented below:



Options	Shares Outstanding		Shares Exercisable	Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Term (Years)	Aggregate Intrinsic Value
December 31, 2011	266			$	46.70
Granted	166			35.30
Exercised	—			—
Forfeited, canceled, or expired	(33	)		48.10
December 31, 2012	399			41.80		9.0	103.1
Exercisable at December 31, 2012			154	43.00		7.6	11.4
Granted	74			32.10
Exercised	—			—
Forfeited, canceled, or expired	(157	)		42.10
December 31, 2013	316			39.40		6.5	—
Exercisable at December 31, 2013			184	42.30		2.6	—
Granted	16			16.04
Exercised	—			—
Forfeited, canceled, or expired	(100	)		33.46
December 31, 2014	232			$	40.30	7.2	—
Exercisable at December 31, 2014			102	$	45.82	5.9	—

As of December 31, 2014, there was approximately $0.7 million of unrecognized compensation expense for employee stock options, which is expected to be recognized over a weighted-average period of approximately 1.5 years.

Restricted Stock

The Company measures the cost of employee services received in exchange for awards of restricted stock based on the market value of the Company’s common shares at the date of grant. Shares of restricted common stock generally vest over a two or three year service period from the date of grant. The fair value of the restricted stock is amortized on a straight-line basis over the requisite service period for the entire award, that is, over the requisite service period of the last separately vesting portion of the award.

Compensation cost for shares of restricted common stock recognized in operating results is included in general and administrative expense in the consolidated statements of operations and was $0.8 million, $1.4 million and $1.6 million, for the years ended December 31, 2014, 2013 and 2012, respectively. There was no income tax benefit recognized in the consolidated statement of operations for the year ended December 31, 2014 associated with restricted common stock activity, as all deferred tax assets were fully reserved by a valuation allowance. The income tax expense (benefit) associated with restricted stock activity recognized in the consolidated statements of operations was $0.2 million and $(0.7) million for the years ended December 31, 2013 and 2012, respectively.

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A summary of non-vested restricted common stock activity is presented below:



Non-Vested Restricted Stock	Shares		Weighted-Average Grant-Date Fair Value
Non-vested at December 31, 2011	55		$	57.60
Granted	42		41.60
Vested	(10	)	45.00
Forfeited	—		—
Non-vested at December 31, 2012	87		$	51.30
Granted	41		15.82
Vested	(25	)	52.87
Forfeited	(10	)	47.43
Non-vested at December 31, 2013	93		$	35.64
Granted	65		7.92
Vested	(87	)	33.96
Forfeited	(5	)	39.90
Non-vested at December 31, 2014	66		$	9.78

As of December 31, 2014, there was $0.6 million of unrecognized compensation expense for restricted common stock, which is expected to be recognized over a weighted-average period of approximately 1.6 years. The total fair value of shares vested during the years ended December 31, 2014, 2013 and 2012, was approximately $0.5 million, $0.4 million and $0.4 million, respectively.

Restricted Stock Units

The Company measures the cost of employee services received in exchange for awards of restricted stock units based on the market value of the Company’s common shares at the date of grant. Restricted common stock units generally vest over a two or three year service period from the date of grant. The fair value of the restricted stock units is amortized on a straight-line basis over the requisite service period for the entire award, that is, over the requisite service period of the last separately vesting portion of the award.

Compensation cost for restricted common stock units recognized in operating results is included in general and administrative expense in the consolidated statements of operations and was approximately $1.4 million and $0.6 million for the years ended December 31, 2014 and 2013, respectively. There was no compensation cost recognized in the consolidated statements of operations for restricted common stock units for the year ended December 31, 2012 as no restricted common stock units were granted in that year. There was no income tax benefit recognized in the consolidated statement of operations for the year ended December 31, 2014 associated with stock option activity, as all deferred tax assets were fully reserved by a valuation allowance. The income tax benefit associated with restricted common stock unit activity recognized in the consolidated statements of operations was and $0.2 million for the year ended December 31, 2013. There was no income tax benefit recognized in the consolidated statements of operations for the year ended December 31, 2012 as restricted common stock units were not granted until fiscal 2013.

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A summary of non-vested restricted common stock activity is presented below:



Non-Vested Restricted Stock Units	Shares		Weighted-Average Grant-Date Fair Value
Non-vested at December 31, 2012	—		$	—
Granted	62		34.40
Vested	—		—
Forfeited	(6	)	36.30
Non-vested at December 31, 2013	56		$	35.64
Granted	296		14.90
Vested	(26	)	16.05
Forfeited	(78	)	18.19
Non-vested at December 31, 2014	248		$	18.42

As of December 31, 2014 , there was approximately $2.5 million of unrecognized compensation expense for restricted common stock units, which is expected to be recognized over a weighted-average period of approximately 1.9 years. During the year ended December 31, 2014 the Company granted 0.3 million restricted stock units, and less than 0.1 million units vested, as restricted stock units were not granted prior to 2013, and the first units were not expected to vest until 2014.

Employee Stock Purchase Plan

Effective September 1, 2013, the Company established a noncompensatory employee stock purchase plan (“ESPP”) which permits all regular full-time employees and employees who work part time over 20 hours per week to purchase shares of the Company’s common stock at a five percent discount. Annual employee contributions are limited to twenty-five thousand dollars, are voluntary and made through a bi-weekly payroll deduction.

(14) Income Taxes

The following table shows the components of the income tax benefit for the periods indicated:



	Year Ended December 31,
	2014			2013			2012
Current income tax (benefit) expense:
Federal	$	—		$	(3,443	)	$	(6,845	)
State	178			(1,053		)	763
Total Current	178			(4,496		)	(6,082		)
Deferred income tax benefit:
Federal	(8,589		)	(64,292		)	(51,557		)
State	(4,052		)	(4,307		)	(5,121		)
Total Deferred	(12,641		)	(68,599		)	(56,678		)
Total income tax benefit attributable to continuing operations	$	(12,463	)	$	(73,095	)	$	(62,760	)

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A reconciliation of the income tax benefit and the amount computed by applying the statutory federal income tax rate of 35% to loss from continuing operations before income taxes is as follows:



	Year Ended December 31,
	2014		2013		2012
U.S. federal income tax benefit at statutory rate	35.0	%	35.0	%	35.0	%
State and local income taxes, net of federal benefit	1.3	%	4.1	%	4.3	%
Compensation	(0.2	)%	(0.3	)%	(0.4	)%
Transaction costs	—	%	—	%	(2.4	)%
Change in fair value of contingent consideration	0.1	%	0.1	%	(1.2	)%
Impairment of Goodwill	(19.0	)%	—	%	—	%
Change in valuation allowance	(14.1	)%	(2.1	)%	55.4	%
Other	(0.4	)%	(1.5	)%	(0.3	)%
Benefit for income taxes	2.7	%	35.3	%	90.4	%

On May 3, 2013, North Dakota enacted SB 2156, which lowered the top corporate income tax rate from 5.15% to 4.53%, effective for tax years beginning after December 31, 2012. This rate reduction resulted in a reduction to the Company’s overall deferred tax liability of $1.1 million, and was recorded as an income tax benefit in the quarter ended June 30, 2013.

Significant components of the Company’s deferred tax assets and liabilities as of December 31, 2014 and 2013 are as follows:



	December 31,
	2014			2013
Deferred tax assets:
Reserves	$	3,089		$	11,783
Net operating losses	127,603			106,763
Equity based compensation	1,234			1,806
Intangible asset and goodwill	19,888			—
Other	8,642			5,114
Total	160,456			125,466
Less: Valuation allowance	(70,331		)	(6,076		)
Total deferred tax assets	90,125			119,390
Deferred tax liabilities:
Fixed assets	(86,947		)	(88,469		)
Intangible assets and goodwill	—			(41,563		)
Deferred financing costs	(2,793		)	(2,041		)
Other	(654		)	(227		)
Total deferred tax liabilities	(90,394		)	(132,300		)
Net deferred tax liability	$	(269	)	$	(12,910	)

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	December 31,
	2014			2013
Current deferred tax assets, net:
Deferred tax assets	$	6,815		$	31,754
Deferred tax liabilities	(653		)	(219		)
Valuation allowance	(2,983		)	(1,463		)
Total current deferred tax assets, net	3,179			30,072
Long-term deferred tax liabilities, net:
Deferred tax assets	153,641			93,712
Deferred tax liabilities	(89,741		)	(132,081		)
Valuation allowance	(67,348		)	(4,613		)
Total long-term deferred tax liabilities, net	(3,448		)	(42,982		)
Net deferred tax liability	$	(269	)	$	(12,910	)

As of December 31, 2014, the Company had net operating loss (“NOL”) carryforwards for federal income tax purposes of approximately $336.3 million, which expire in 2029through -2034, and state NOL carryforwards of approximately $217.7 million, which expire in 2017 through 2034.

As required by GAAP, management assesses the recoverability of the Company’s deferred tax assets on a regular basis and records a valuation allowance for any such assets where recoverability is determined to be not more likely than not. The Company had recorded a valuation allowance of $6.1 million as of December 31, 2013 for certain state net operating loss carryforwards that management did not believe are more likely than not to be realized and for the write-down of the Company’s investment in UGSI, which would result in a capital loss that would more likely than not be unrealizable prior to its expiration. As a result of the Company's continued losses, the Company determined in 2014 that its deferred tax liabilities (excluding deferred tax liabilities included in discontinued operations) were not sufficient to fully realize its deferred tax assets prior to the expiration of its NOLs, and accordingly, a valuation allowance was required against a portion of its deferred tax assets. Accordingly, the Company has recorded a valuation allowance of approximately $70.3 million as of December 31, 2014.

A reconciliation of the Company’s valuation allowance on deferred tax assets for the years ended December 31, 2014 and 2013 is as follows:



	Year Ended December 31,
	2014		2013
Balance at beginning of period	$	6,076	$	1,657
Additions to valuation allowance	64,255		4,419
Valuation allowance release, net	—		—
Balance at end of period	$	70,331	$	6,076

Pursuant to United States Internal Revenue Code Section 382, if the Company underwent an ownership change, the NOL carryforward limitations would impose an annual limit on the amount of the taxable income that may be offset by the Company’s NOL generated prior to the ownership change. The Company has determined that an ownership change occurred on November 30, 2012 as a result of the stock consideration transferred in the Power Fuels Merger. The Company does not expect any limitation under Section 382 to result in federal NOL’s expiring unused. If a subsequent ownership change were to occur, the Company may be unable to use a significant portion of its NOL to offset future taxable income.

As of December 31, 2014 and 2013, the Company had unrecognized tax benefits attributable to a state tax position in discontinued operations totaling approximately $0.2 million and $0.3 million, respectively, which would favorably impact the Company’s effective tax rate if subsequently recognized.

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A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:



	Year Ended December 31,
	2014			2013
Unrecognized tax benefits balance at beginning of year	$	283		$	—
Additions for tax positions taken in prior periods	—			306
Reductions for lapses of statute of limitations	(68		)	(23		)
Unrecognized tax benefits balance at end of year	$	215		$	283

The Company recognizes potential accrued interest and penalties related to unrecognized tax benefits as a component of income tax expense. Accrued interest and penalties as of December 31, 2014 and 2013 was approximately $0.1 million, respectively. To the extent interest and penalties are not assessed with respect to uncertain tax positions, amounts accrued will be reduced and reflected as a reduction of the overall income tax provision.

The Company anticipates a reduction of $0.2 million in the total amount of unrecognized tax benefits during the next twelve months as a result of the lapsing of the statute of limitations related to a state tax position.

The Company and its subsidiaries are subject to the following significant taxing jurisdictions: U.S. federal, Pennsylvania, Louisiana, North Dakota, Texas, West Virginia, Arizona, and Oregon. The Company has had NOLs in various years for federal purposes and for many states. The statute of limitations for a particular tax year for examination by the Internal Revenue Service is generally three years subsequent to the filing of the associated tax return. However, the Internal Revenue Service can adjust NOL carryovers up to three years subsequent to the last year in which the loss carryover is finally used. Accordingly, there are multiple years open to examination. The statute of limitations is generally three to four years for many of the states where the Company operates.

During 2013, the Internal Revenue Service completed its examination of the Company’s federal income tax returns for the years ended December 31, 2008 through 2010 with no changes. The Company is currently not under income tax examination in any other tax jurisdictions.

(15) Commitments and Contingencies

Environmental Liabilities

The Company is subject to the environmental protection and health and safety laws and related rules and regulations of the United States and of the individual states, municipalities and other local jurisdictions where we operate. The Company’s continuing operations are subject to rules and regulations promulgated by the Texas Railroad Commission, the Texas Commission on Environmental Quality, the Louisiana Department of Natural Resources, the Louisiana Department of Environmental Quality, the Ohio Department of Natural Resources, the Pennsylvania Department of Environmental Protection, the North Dakota Department of Health, the North Dakota Industrial Commission, Oil and Gas Division, the North Dakota State Water Commission, the Montana Department of Environmental Quality and the Montana Board of Oil and Gas, among others. These laws, rules and regulations address environmental, health and safety and related concerns, including water quality and employee safety. The Company has installed safety, monitoring and environmental protection equipment such as pressure sensors and relief valves, and have established reporting and responsibility protocols for environmental protection and reporting to such relevant local environmental protection departments as required by law.

The Company’s industrial solutions business involves the use, handling, storage and contracting for recycling or disposal of environmentally sensitive materials, such as waste motor oil and filters, solvents, transmission fluid, antifreeze, lubricants and degreasing agents. Accordingly, the Company’s industrial solutions business is subject to regulation by various federal, state, and local authorities with respect to health, safety and environmental quality and standards. The industrial solutions business is also subject to laws, ordinances, and regulations governing the investigation and remediation of contamination at facilities we operate or to which we send hazardous substances for treatment, recycling or disposal. In particular, the United States Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”) imposes joint, strict, and several liability on owners or operators of facilities at, from, or to which a release of hazardous substances has occurred, parties that generated hazardous substances that were released at such facilities and parties that transported or arranged for the transportation of hazardous substances to such facilities. A majority of states have adopted statutes comparable to, and in some cases more stringent than, CERCLA. The industrial solutions business comprised of TFI is classified as held-for-sale and discontinued operations.

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Management believes the Company is in material compliance with all applicable environmental protection laws and regulations in the United States and the states in which the Company operates. The Company believes that there are no unrecorded liabilities in connection with the Company’s compliance with environmental laws and regulations. The consolidated balance sheets at December 31, 2014 and December 31, 2013 included accruals totaling $0.7 million and $1.5 million, respectively, for various environmental matters, including the estimated costs to comply with a Louisiana Department of Environmental Quality requirement that the Company perform testing and monitoring at certain locations to confirm that prior pipeline spills were remediated in accordance with applicable requirements.

Leases

Included in property and equipment in the accompanying consolidated balance sheets are the following assets held under capital leases at December 31, 2014:



Leased equipment	$	16,180
Less accumulated depreciation	(6,451		)
Leased equipment, net	$	9,729

Capital lease obligations consist primarily of vehicle leases with periods expiring at various dates through 2019 at variable interest rates and fixed interest rates, which were approximately 3.60% at December 31, 2014. Capital lease obligations amounted to $14.6 million and $18.8 million, at December 31, 2014 and 2013, respectively.

Future minimum lease payments, by year and in the aggregate, for capital leases are as follows at:



	December 31,
2015	$	5,105
2016	4,621
2017	4,491
2018	1,234
2019	68
Thereafter	—
Total minimum lease payments	15,519
Less amount representing executor costs	(262		)
Net minimum lease payments	15,257
Less amount representing interest (3.60% at December 31, 2014)	(704		)
Present value of net minimum lease payments	$	14,553

The Company also rents transportation equipment, real estate and certain office equipment under operating leases. Certain real estate leases require the Company to pay maintenance, insurance, taxes and certain other expenses in addition to the stated rentals. Lease expense under operating leases and rental contracts amounted to $7.7 million, $7.5 million and $7.8 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Future minimum lease payments, by year and in the aggregate, for noncancelable operating leases with initial or remaining terms of one year or more are as follows at:



	December 31,
2015	$	5,937
2016	4,364
2017	3,519
2018	2,381
2019	821
Thereafter	2,204
Total minimum lease payments	$	19,226

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Asset Retirement Obligations

At December 31, 2014, the Company had approximately $2.9 million of asset retirement obligations related to its disposal wells and landfill which are recorded in “Other long-term liabilities” in the accompanying consolidated balance sheet.

Surety Bonds and Letters of Credits

At December 31, 2014, the Company had surety bonds outstanding of approximately $7.0 million primarily to support financial assurance obligations related to its landfill and disposal wells. Additionally, at December 31, 2014, the Company had outstanding irrevocable letters of credit totaling $4.8 million to support various agreements, leases and insurance policies.

Capital Expenditures Commitment

The Company has entered into an agreement to purchase approximately $7.5 million of thermal desorption equipment for expansion of its solids treatment capabilities at its landfill site in North Dakota. Additionally, the Company entered into an agreement to purchase $2.7 million of equipment related to the pipeline infrastructure located in the Bakken Shale area. As of December 31, 2014, approximately $6.1 million of purchases remained under these agreements.

(16) Legal Matters

There are various lawsuits, claims, investigations and proceedings that have been brought or asserted against the Company, which arise in the ordinary course of business, including actions with respect to securities and shareholder class actions, personal injury, vehicular and industrial accidents, commercial contracts, legal and regulatory compliance, securities disclosure, labor and employment, and employee benefits and environmental matters, the more significant of which are summarized below. The Company records a provision for these matters when it is both probable that a liability has been incurred and the amount of the loss can be reasonably estimated. Any provisions are reviewed at least quarterly and are adjusted to reflect the impact and status of settlements, rulings, advice of counsel and other information and events pertinent to a particular matter.

The Company believes that it has valid defenses with respect to legal matters pending against it. Based on its experience, the Company also believes that the damage amounts claimed in the lawsuits disclosed below are not necessarily a meaningful indicator of the Company’s potential liability. Litigation is inherently unpredictable, and it is possible that the Company’s results of operations or cash flow could be materially affected in any particular period by the resolution of one or more of the legal matters pending against it.

Texas Cases

On June 4, 2012, a lawsuit was commenced in the District Court of Dimmit County, Texas, alleging wrongful death in a case involving a vehicle accident. The accident occurred in May 2012 and involved a truck owned by our subsidiary Heckmann Water Resources (CVR), Inc. (“CVR”) and one other vehicle. The case is captioned Jose Luis Aguilar, Individually; Eudelia Aguilar, Individually; Vanessa Arce, Individually; Eudelia Aguilar and Vanessa Arce, as Personal Representatives of the Estate of Carlos Aguilar; Clarissa Aguilar, as Next Friend of Carlos Aguilar, Jr., Alyssa Nicole Aguilar, Andrew Aguilar, Marcus Aguilar, and Kaylee Aguilar; and Elsa Quinones as Next Friend of Karime and Carla Aguilar, Plaintiffs vs. Heckmann Water Resources (CVR), Inc. and Ruben Osorio Gonzalez, Defendants. On December 5, 2013, a jury verdict was rendered against CVR in the amount of $281.6 million, which amount was subsequently reduced to $163.8 million by the Dimmit County court when the judgment was entered on January 7, 2014 and then subsequently further reduced to $105.2 million when the judgment was amended by the Dimmit County court on April 1, 2014. On January 29, 2014, a separate lawsuit was commenced in the District Court of Dimmit County, Texas captioned Clarissa Aguilar, as Next Friend of Carlos Aguilar, Jr., Alyssa Nicole Aguilar, Andrew Aguilar, Marcus Aguilar, and Kaylee Aguilar v. Zurich American Insurance Company, Heckmann Water Resources (CVR), Inc., Heckmann Water Resources Corp., and Nuverra Environmental Solutions, Inc. f/k/a Heckmann Corp., Cause No. 14-01-12176-DCV, seeking a declaratory judgment that Nuverra Environmental Solutions, Inc. and Heckmann Water Resources Corp. are the alter egos of CVR, and therefore these entities are jointly and severally liable for the judgment against CVR in the wrongful death action.

In June 2014, the Company entered into agreements to fully settle all claims relating to the foregoing lawsuits. The settlements were approved by the Dimmit County court on July 15, 2014. In connection with the settlement of these matters, the Company agreed to fund $5.5 million of the total settlement payments to fully resolve the matter, which was subsequently paid in July 2014, with the remainder of the total settlement payment funded by the Company’s insurer. The amount of the total settlement payment is confidential pursuant to the settlement agreements. These settlement agreements include all plaintiffs and the Company’s insurer and release the Company and all of its subsidiaries from all past and future claims or liabilities related to these matters. As a result of the settlement of these cases, the Company recorded expenses totaling $7.8 million during the year

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ended December 31, 2014 consisting of $5.5 million for the settlement payments and $2.3 million of additional related legal expenses.

Shareholder Litigation

2010 Class Action

On May 21, 2010, Richard P. Gielata, an individual purporting to act on behalf of stockholders, served a class action lawsuit filed May 6, 2010 against the Company and various directors and officers of the Company in the United States District Court for the District of Delaware captioned In re Heckmann Corporation Securities Class Action (Case No. 1:10-cv-00378-JJF-MPT). On March 4, 2014, the Company reached an agreement in principle to settle this matter by entering into a Stipulation of Settlement with the plaintiffs, which resolved all claims asserted against the Company and the individual defendants in this case. Under the terms of the Stipulation of Settlement, which was subject to approval by the court, the Company agreed to a cash payment of $13.5 million, a portion of which came come from remaining insurance proceeds, as well as the issuance of 0.8 million shares of its common stock. The Company agreed to provide a floor value of $13.5 million on the equity portion of the settlement; however, at the time of final court approval of the Stipulation of Settlement (described below) the equity value of the settlement consideration exceeded this amount and, as a result, the number of shares to be issued as settlement consideration was fixed at 0.8 million. Cash payments of $6.1 million from the Company, and the remaining $7.4 million from insurance proceeds, were deposited into escrow in April 2014. The Stipulation of Settlement was approved by the court on June 26, 2014 and became effective on August 27, 2014. Pursuant to the court’s approval order, one-third of the 0.8 million settlement shares and one-third of the cash settlement consideration were awarded to co-lead plaintiffs’ counsel as attorneys’ fees (in addition to reimbursement of certain court-approved expenses from the cash portion of the settlement escrow). The remaining two-thirds of the 0.8 million settlement shares were deposited into escrow on August 22, 2014.

2013 Shareholder Litigation

In September 2013, two separate but substantially-similar putative class action lawsuits were commenced in Federal court against the Company and certain of its current and former officers and directors alleging that the Company and the individual defendants made certain material misstatements and/or omissions relating to the Company’s operations and financial condition which caused the price of its shares to fall. By order dated October 29, 2013, the two putative class actions were consolidated and a consolidated complaint was filed. Defendants filed a motion to dismiss these claims in May 2014, and such motion was granted by the Court on November 17, 2014, whereby the forgoing class action was dismissed without prejudice. Plaintiffs were permitted by the Court to file a motion to amend the complaint and did so on December 8, 2014. Defendants filed their opposition to plaintiffs' motion to amend the complaint on December 22, 2014. On March 12, 2015, the Court issued an order denying plaintiffs' motion to amend the complaint as to certain claims, but granting plaintiffs' motion as to other claims. The Company believes these claims are without merit and the Company will continue to vigorously defend itself and the individual defendants in this action.

In September and October 2013, three separate but substantially-similar shareholder derivative lawsuits were commenced in Federal court against the Company and certain of its current and former officers and directors alleging that members of the Company’s board of directors failed to prevent the issuance of certain misstatements and omissions and asserting claims for breach of fiduciary duty, waste of corporate assets and unjust enrichment. Defendants filed a motion to dismiss these claims in February 2014. On September 15, 2014, the Court dismissed the consolidated cases following its dismissal of the consolidated complaint and plaintiffs' failure to amend. Also in October 2013, two identical shareholder derivative lawsuits were commenced in Arizona state court against the Company and certain of the Company’s current officers and directors alleging breach of fiduciary duty, waste of corporate assets and unjust enrichment. By order dated January 28, 2014, these two actions were consolidated, and defendants filed a motion to dismiss these claims in June 2014. On July 22, 2014, the parties filed a joint stipulation to dismiss these cases with prejudice, which was granted by the Court on August 1, 2014, and no settlement payment was made.

The Company does not expect that the outcome of other claims and legal actions not discussed above will have a material adverse effect on its consolidated financial position, results of operations or cash flows.

(17) Employee Benefit Plans

The Company sponsors a defined contribution 401(k) plan that is subject to the provisions of the Employee Retirement Income Security Act of 1974 (“ERISA”). Effective September 1, 2013, the Company established a defined contribution plan (the “401k Plan”) covering substantially all employees who have met certain eligibility requirements except those employees working less than 25 hours per week. Employees may participate in the 401k Plan on the first day of the first month following 60 days of employment. The Company provides a quarterly match in shares of Company common stock equal to 100% of each participant’s annual contribution up to 3% of each participant’s annual compensation and 50% of participant’s annual

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contribution up to an additional 2% of each participant’s annual compensation. Company contributions to the plans were $4.4 million, $1.9 million and $0.3 million for the years ended December 31, 2014, 2013 and 2012 respectively.

(18) Related Party and Affiliated Company Transactions

Richard J. Heckmann, the former Executive Chairman of the Company’s board of directors, and Mark D. Johnsrud, the Company’s Chief Executive Officer and Chairman of the Company’s board of directors, were members of an entity that owned an aircraft used periodically by the Company for business-related travel. During the three months ended September 30, 2014, the aircraft was sold to another entity in which both Mr. Johnsrud and Mr. Heckmann are members. Reimbursements paid to these entities in exchange for use of the aircraft were $0.2 million, $0.4 million and $1.2 million for the years ended December 31, 2014, 2013 and 2012, respectively.

During the three months ended September 30, 2014, the aircraft lease with an entity controlled by Mr. Heckmann was terminated and replaced with a new aircraft lease with an entity owned by Mr. Johnsrud and Heckmann Enterprises, Inc. (of which Mr. Johnsrud is the controlling shareholder) under substantially the same economic and other terms. Reimbursements payable to Mr. Johnsrud in exchange for use of the aircraft were $0.1 million for the year ended December 31, 2014.

Mr. Johnsrud is the sole member of an entity that owns apartment buildings in North Dakota which are rented to certain of the Company’s employees at rates that are equal to or below market rates. However, there is no formal arrangement between the Company and Mr. Johnsrud for this housing. Rent payments are collected from the employees by the Company through payroll deductions and remitted to the entity.

In connection with the Power Fuels Merger, assets received in exchange for the merger consideration excluded accounts receivable outstanding for more than ninety days as of November 30, 2012. Subsequent collections on these accounts receivable, which are recorded by the Company as restricted cash with an offsetting liability, are required to be periodically remitted to Mr. Johnsrud. Pursuant to the terms of this agreement, during the year ended December 31, 2013, the Company paid Mr. Johnsrud $3.6 million for such collections, net of a working capital adjustment of approximately $2.1 million. Amounts payable to Mr. Johnsrud at December 31, 2014 for accounts receivable collections totaled approximately $0.1 million.

The Company periodically purchases fresh water for resale to customers from a sole proprietorship owned by Mr. Johnsrud. Purchases made by the Company during the years ended December 31, 2014, and 2013 and amounted to $0.9 million and $0.7 million, respectively. Purchases made by Power Fuels prior to its merger with the Company totaled approximately $2.2 million during the year ended December 31, 2012. No amounts were due to the sole proprietorship at December 31, 2014.

Mr. Johnsrud is the sole member of an entity that owns land in North Dakota on which five of the Company’s saltwater disposal wells are situated. The Company has agreed to pay the entity a per-barrel royalty fee in exchange for the use of the land, which is consistent with rates charged by non-affiliated third parties under similar arrangements. Royalties paid by the Company were approximately $0.1 million in each of the years ended December 31, 2014 and 2013, respectively. Royalties payable to the entity were less than $0.1 million at December 31, 2014, and 2013, respectively.

During 2009, the Company acquired an approximate 7% investment in Underground Solutions, Inc. (“UGSI”) a supplier of water infrastructure pipeline products, whose chief executive officer, Andrew D. Seidel, was a member of the Company’s board of directors. The Company’s total investment in UGSI was $7.2 million. During the quarter ended September 30, 2013, management performed an evaluation of various alternatives for this non-strategic investment, including its potential liquidation. As a result, the Company recorded a $3.8 million charge for the write-down of this investment to its estimated net realizable value. The Company’s interest in UGSI is accounted for as a cost method investment in the Company’s consolidated balance sheet as of December 31, 2014 and December 31, 2013, and is included in the Corporate/Other group for purposes of reportable segments (Note 19). The $3.8 million write-down was classified as a component of other expense, net in the consolidated statement of operations for the year ended December 31, 2013. During the quarter ended December 31, 2014 management performed an evaluation of the UGSI investment and determined the fair value exceeded its carrying value, and therefore no additional write-down was deemed necessary.

(19) Segments

The Company evaluates business segment performance based on income (loss) before income taxes exclusive of corporate general and administrative costs and interest expense, which are not allocated to the segments. As described previously, during the three months ended September 30, 2014 the Company completed the organizational realignment of its shale solutions business into three operating divisions, which the Company considers to be operating and reportable segments of its continuing operations: (1) the Northeast division comprising the Marcellus and Utica Shale areas, (2) the Southern division comprising the Haynesville, Eagle Ford, Mississippian and Permian Basin Shale areas and (3) the Rocky Mountain division comprising the

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Bakken Shale area. Corporate/Other includes certain corporate costs and losses from discontinued operations, as well as assets held for sale and certain other corporate assets.

Financial information for the Company’s reportable segments related to continuing operations is presented below, including the Company's historical summary financial information for the years ended December 31, 2014, 2013 and 2012, which have been recast to conform to the new segment presentation.



	Northeast			Southern			Rocky Mountain			Corporate/ Other			Total
Year Ended December 31, 2014
Revenue	$	95,577		$	105,935		$	334,770		$	—		$	536,282
Depreciation and amortization	15,643			18,321			51,247			669			85,880
Loss from continuing operations before income taxes	(40,594		)	(82,454		)	(269,954		)	(76,639		)	(469,641		)
Total assets excluding those applicable to discontinued operations (a)	102,593			168,191			442,784			42,600			756,168
Total assets held for sale (b)	—			—			—			115,404			115,404
Year Ended December 31, 2013
Revenue	95,085			126,549			304,182			—			525,816
Depreciation and amortization	13,376			26,388			59,035			437			99,236
Income (loss) from continuing operations before income taxes	1,158			(132,930		)	31,684			(107,047		)	(207,135		)
Total assets excluding those applicable to discontinued operations (a)	136,235			241,937			772,536			71,305			1,222,013
Total assets held for sale (b)	—			—			—			188,750			188,750
Year Ended December 31, 2012
Revenue	69,103			162,232			25,336			—			256,671
Depreciation and amortization	10,331			31,449			5,861			—			47,641
(Loss) income from continuing operations before income taxes	(2,731		)	(23,137		)	2,881			(46,370		)	(69,357		)

(a) Total assets exclude intercompany receivables eliminated in consolidation.

(b) Represents the carrying value of the assets of discontinued operations (Note 20).

(20) Assets Held for Sale and Discontinued Operations

Following an assessment of various alternatives regarding its industrial solutions business in the third quarter of 2013 and a decision to focus exclusively on its shale solutions business, the Company’s board of directors approved and committed to a plan to divest Thermo Fluids Inc. ("TFI"), which comprises its industrial solutions operating and reportable segment, in the fourth quarter of 2013. In March 2014, the Company entered into a Stock Purchase Agreement with respect to the sale of 100% of the equity of TFI to a prospective acquirer in exchange for $165.0 million in cash and $10.0 million in stock. In June 2014, the Company entered into an Amended and Restated Stock Purchase Agreement which, among other items, extended the closing date of the transaction. In August 2014, the agreement was terminated pursuant to the terms of the agreement. Subsequent to the termination of the agreement, the Company engaged in negotiations with other potential acquirers. In September 2014, Nuverra entered into a non-binding letter of intent for the sale of TFI to a new prospective acquirer in exchange for a combination of cash and common stock of the acquirer. Definitive transaction documentation was not executed with the new prospective acquirer. On February 4, 2015, Nuverra entered into a definitive agreement with Safety-Kleen, Inc. ("Safety-Kleen"), a subsidiary of Clean Harbors, Inc., whereby Safety-Kleen will acquire TFI for $85 million in an all-cash transaction, subject to working capital adjustments. The Company currently expects the transaction to close promptly following receipt of required governmental approvals.

The February 4, 2015 definitive agreement for the proposed sale was for an amount that is below the carrying value of TFI's net assets. Based on the definitive agreement with Safety-Kleen, TFI recorded charges of approximately $74.4 million, in the year ended December 31, 2014, reducing the estimated net recoverable value of its net assets to approximately $84.5 million at December 31, 2014. The charges were primarily related to a reduction of goodwill in the amount of $48.0 million, $26.4 million in intangible assets, as well as estimated additional transaction costs related to the sale.

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The Company classified TFI as discontinued operations in its consolidated statements of operations for the years ended December 31, 2014, 2013 and 2012 (since its acquisition on April 10, 2012). The assets and liabilities related to TFI are presented separately as "Assets held for sale" and "Liabilities of discontinued operations" in the Company’s consolidated balance sheets at December 31, 2014 and December 31, 2013.

The following table provides selected financial information of discontinued operations related to TFI:



	Year Ended December 31,
	2014			2013			2012
Revenue	$	114,382		$	116,263		$	95,312
(Loss) income from discontinued operations before income taxes	$	(68,258	)	$	(98,237	)	$	13,279
Income tax benefit (expense)	9,832			(14		)	(4,155		)
(Loss) income from discontinued operations	$	(58,426	)	$	(98,251	)	$	9,124

The carrying value of the assets and liabilities of TFI that are classified as held for sale in the accompanying consolidated balance sheets at December 31, 2014 and December 31, 2013 are as follows:



	December 31,
	2014		2013
Assets:
Cash and cash equivalents	$	2,049	$	429
Accounts receivable, net	13,592		15,620
Inventories, net	2,011		2,328
Prepaid expenses and other receivables	2,545		2,475
Other current assets	269		594
Total current assets held for sale	20,466		21,446
Property, plant and equipment, net	28,366		26,369
Intangible assets, net	66,572		92,935
Goodwill	—		48,000
Total long-term assets held for sale	94,938		167,304
Total assets held for sale	$	115,404	$	188,750
Liabilities:
Accounts payable	$	4,544	$	6,625
Accrued expenses	4,214		2,676
Current portion of long-term debt	44		—
Total current liabilities of discontinued operations	8,802		9,301
Long-term portion of debt	61		—
Deferred income taxes	22,044		32,389
Total liabilities of discontinued operations	30,907		41,690
Net assets held for sale	$	84,497	$	147,060

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(21) Selected Unaudited Quarterly Financial Data



	Three Months Ended
	March 31, (1)			June 30, (2)			September 30, (3)			December 31, (4)
2014
Revenue	$	128,014		$	126,862		$	139,643		$	141,763
Loss from continuing operations	(11,914		)	(24,722		)	(99,418		)	(321,124		)
Income (loss) from discontinued operations	459			1,453			(45,568		)	(14,770		)
Net loss attributable to common stockholders	(11,455		)	(23,269		)	(144,986		)	(335,894		)
Loss per common share from continuing operations:
Basic and diluted	(0.48		)	(0.97		)	(3.73		)	(11.84		)
Income (loss) per common share from discontinued operations:
Basic and diluted	0.02			0.06			(1.71		)	(0.54		)
Net loss per common share:
Basic and diluted	(0.46		)	(0.91		)	(5.44		)	(12.38		)

The following pre-tax unusual or non-recurring items were recorded:


(1)	During the quarter ended March 31, 2014, the Company wrote-off a portion of the unamortized deferred financing costs associated with the Amended Revolving Credit Facility of approximately $3.2 million (Note 10). Additionally, the Company recorded a charge of $1.9 million related to litigation expenses.


(2)	During the quarter ended June 30, 2014, The Company recorded an additional charge of $12.8 million related to non-recurring legal and environmental expenses, specifically the settlement of the Texas Cases and Shareholder Litigation (Note 16).

(3)

During the quarter ended September 30, 2014 the Company recorded a goodwill impairment charge related to its Northeast and Southern Divisions of $100.7 million. Additionally, as a result of the on-going sales process of the Company's industrial solutions division, the Company recorded a charge of $49.0 million, which is included within "Loss from discontinued operations, net of income taxes" in the Company's consolidated statement of operations.

(4)

During the quarter ended December 31, 2014, the Company recorded long-lived asset and goodwill impairment charges in its Rocky Mountain division totaling $112.4 million and $203.3 million, respectively. Additionally, as a result of the on-going sales process of the Company's industrial solutions division, the Company recorded a charge of $28.9 million, which is included within "Loss from discontinued operations, net of income taxes" in the Company's consolidated statement of operations (Note 8).



	Three Months Ended
	March 31, (4)			June 30, (3)			September 30, (2)			December 31, (1)
2013
Revenue	$	130,647		$	134,977		$	131,804		$	128,388
Loss from continuing operations (1)(2)	(4,005		)	(21,665		)	(97,998		)	(10,372		)
Loss (income) from discontinued operations (1)(2)	(8,627		)	8,816			(95,740		)	(2,700		)
Net loss attributable to common stockholders (1)(2)	(12,632		)	(12,849		)	(193,738		)	(13,072		)
Loss per common share from continuing operations:
Basic and diluted	(0.17		)	(0.89		)	(3.94		)	(0.42		)
(Loss) income per common share from discontinued operations:
Basic and diluted	(0.36		)	0.36			(3.85		)	(0.11		)
Net loss per common share:
Basic and diluted	(0.53		)	(0.53		)	(7.80		)	(0.53		)


(1)	During the fourth quarter of 2013, the following unusual or non-recurring items were recorded:

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a.	The Company recorded an additional charge of $7.0 million related to the pending settlement of its 2010 class action litigation.


b.	The Company reduced its self-insurance liabilities by $3.3 million based on actuarial valuations performed in the period.


c.	The Company recorded a reduction to depreciation expense of $3.2 million following the completion of its assessment of the useful lives of the tangible assets acquired in the Power Fuels acquisition


(2)	During the third quarter of 2013, the Company recorded the following unusual or non-recurring items:


a.	The Company recorded a charge for goodwill impairment related to its industrial solutions business of $98.5 million.


b.	The Company recorded a charge of $107.4 million to write-down the carrying values of certain long-lived assets in its shale solutions business.


c.	The Company recorded a charge of $16.0 million related to the 2010 class action litigation.


d.	The Company wrote off $4.3 million of cost-method investments, primarily related to its minority ownership in a pipeline products supplier.


(3)	During the second quarter of 2013, the Company recorded charges for restructuring portions of its business in the amount of $1.5 million and the impairment of certain related assets totaling $3.5 million, along with a reduction of $0.8 million to amounts previously accrued for the settlement of the 2010 Derivative Action.


(4)	During the first quarter of 2013, the Company recorded a $2.4 million charge related to settlement of its 2010 Derivative Action litigation.

(22) Subsidiary Guarantors

The obligations of the Company under the 2018 Notes are jointly and severally, fully and unconditionally guaranteed by certain of the Company’s subsidiaries. Pursuant to the terms of the indenture governing the 2018 Notes (the “Indenture”), the guarantees are full and unconditional, but are subject to release under the following circumstances:


•	in connection with any sale, disposition or transfer of all or substantially all of the assets to a person that is not the Company or a subsidiary guarantor;


•	in connection with any sale, disposition or transfer of all of the capital stock of that subsidiary guarantor to a person that is not the Company or a subsidiary guarantor;


•	if the Company designates any restricted subsidiary that is a subsidiary guarantor to be an unrestricted subsidiary; or


•	upon legal defeasance or the discharge of the Company’s obligations under the Indenture.

Although the guarantees are subject to release under the above described circumstances, we have concluded they are still deemed full and unconditional for purposes of Rule 3-10 of Regulation S-X because these circumstances are customary, and accordingly, the Company concluded that it may rely on Rule 3-10 of Regulation S-X, as the other requirements of Rule 3-10 have been met.

The following tables present condensed consolidating financial information for Nuverra Environmental Solutions, Inc. (“Parent”), certain 100% wholly-owned subsidiaries (the “Guarantor Subsidiaries”) and Appalachian Water Services, LLC, a 51% owned subsidiary (the “Non-Guarantor Subsidiary”), as of December 31, 2014 and December 31, 2013 and for the years ended December 31, 2014, 2013 and 2012 . These consolidating financial statements have been prepared from the Company’s financial information on the same basis of accounting as the Company’s consolidated financial statements. The principal elimination entries relate to investments in subsidiaries and intercompany balances and transactions.

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CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2014



	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiary		Eliminations			Consolidated
ASSETS
Cash and cash equivalents	$	13,801		$	(1,706	)	$	1,272	$	—		$	13,367
Restricted cash	—			114			—		—			114
Accounts receivable, net	—			107,931			882		—			108,813
Deferred income taxes	173			3,006			—		—			3,179
Other current assets	738			7,972			23		—			8,733
Current assets held for sale	—			20,466			—		—			20,466
Total current assets	14,712			137,783			2,177		—			154,672
Property, plant and equipment, net	3,263			462,193			10,526		—			475,982
Equity investments	249,426			645			—		(246,257		)	3,814
Intangible assets, net	—			18,607			1,150		—			19,757
Goodwill	—			104,721			—		—			104,721
Other	453,048			11,208			—		(446,568		)	17,688
Long-term assets held for sale	—			94,938			—		—			94,938
TOTAL ASSETS	$	720,449		$	830,095		$	13,853	$	(692,825	)	$	871,572
LIABILITIES AND EQUITY
Accounts payable	$	1,310		$	17,294		$	255	$	—		$	18,859
Accrued expenses	16,404			26,813			178		—			43,395
Current portion of contingent consideration	—			9,274			—		—			9,274
Current portion of long-term debt	—			4,863			11,000		—			15,863
Current liabilities of discontinued operations	—			8,802			—		—			8,802
Total current liabilities	17,714			67,046			11,433		—			96,193
Deferred income taxes	(33,353		)	36,801			—		—			3,448
Long-term portion of debt	582,446			10,009			—		—			592,455
Long-term portion of contingent consideration	—			550			—		—			550
Other long-term liabilities	695			449,325			422		(446,568		)	3,874
Long-term liabilities of discontinued operations	—			22,105			—		—			22,105
Total shareholders' equity	152,947			244,259			1,998		(246,257		)	152,947
TOTAL LIABILITIES AND EQUITY	$	720,449		$	830,095		$	13,853	$	(692,825	)	$	871,572

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CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2013



	Parent			Guarantor Subsidiaries		Non-Guarantor Subsidiary		Eliminations			Consolidated
ASSETS
Cash and cash equivalents	$	3,839		$	3,201	$	1,743	$	—		$	8,783
Restricted cash	—			110		—		—			110
Accounts receivable, net	—			86,256		830		—			87,086
Deferred income taxes	27,167			2,905		—		—			30,072
Other current assets	6,642			7,466		86		—			14,194
Current assets held for sale	—			21,446		—		—			21,446
Total current assets	37,648			121,384		2,659		—			161,691
Property, plant and equipment, net	2,396			485,586		10,559		—			498,541
Equity investments	742,342			650		—		(738,960		)	4,032
Intangible assets, net	—			148,063		1,300		—			149,363
Goodwill	—			398,024		10,672		—			408,696
Other	410,774			120,786		—		(510,424		)	21,136
Long-term assets held for sale	—			167,304		—		—			167,304
TOTAL ASSETS	$	1,193,160		$	1,441,797	$	25,190	$	(1,249,384	)	$	1,410,763
LIABILITIES AND EQUITY
Accounts payable	$	3,784		$	27,850	$	1,595	$	—		$	33,229
Accrued expenses	43,274			19,941		216		—			63,431
Current portion of contingent consideration	—			13,113		—		—			13,113
Current portion of long-term debt	—			5,464		—		—			5,464
Current liabilities of discontinued operations	—			9,301		—		—			9,301
Total current liabilities	47,058			75,669		1,811		—			124,538
Deferred income taxes	(34,275		)	77,257		—		—			42,982
Long-term portion of debt	535,221			14,492		—		—			549,713
Long-term portion of contingent consideration	—			2,344		—		—			2,344
Other long-term liabilities	787			513,961		10,104		(510,424		)	14,428
Long-term liabilities of discontinued operations	—			32,389		—		—			32,389
Total shareholders' equity	644,369			725,685		13,275		(738,960		)	644,369
TOTAL LIABILITIES AND EQUITY	$	1,193,160		$	1,441,797	$	25,190	$	(1,249,384	)	$	1,410,763

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CONSOLIDATING STATEMENTS OF OPERATIONS

YEAR ENDED DECEMBER 31, 2014



	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations		Consolidated
Revenue	$	—		$	532,940		$	3,342		$	—	$	536,282
Costs and expenses:
Direct operating expenses	—			382,769			2,044			—		384,813
General and administrative expenses	24,234			42,459			139			—		66,832
Depreciation and amortization	669			84,343			868			—		85,880
Impairment of long-lived assets	—			112,436			—			—		112,436
Impairment of goodwill	—			293,303			10,672			—		303,975
Total costs and expenses	24,903			915,310			13,723			—		953,936
Loss from operations	(24,903		)	(382,370		)	(10,381		)	—		(417,654		)
Interest expense, net	(48,559		)	(1,462		)	(896		)	—		(50,917		)
Other income, net	—			2,112			1			—		2,113
Loss on extinguishment of debt	(3,177		)	—			—			—		(3,177		)
(Loss) income from equity investments	(439,418		)	(6		)	—			439,418		(6		)
(Loss) income from continuing operations before income taxes	(516,057		)	(381,726		)	(11,276		)	439,418		(469,641		)
Income tax benefit	453			12,010			—			—		12,463
(Loss) income from continuing operations	(515,604		)	(369,716		)	(11,276		)	439,418		(457,178		)
Loss from discontinued operations, net of income taxes	—			(58,426		)	—			—		(58,426		)
Net (loss) income attributable to common stockholders	$	(515,604	)	$	(428,142	)	$	(11,276	)	$	439,418	$	(515,604	)

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CONSOLIDATING STATEMENTS OF OPERATIONS

YEAR ENDED DECEMBER 31, 2013



	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations		Consolidated
Revenue	$	—		$	520,922		$	4,894		$	—	$	525,816
Costs and expenses:
Direct operating expenses	—			376,976			2,184			—		379,160
General and administrative expenses	49,136			35,071			73			—		84,280
Depreciation and amortization	437			98,273			526			—		99,236
Impairment of long-lived assets	—			111,900			—			—		111,900
Other, net	864			35			—			—		899
Total costs and expenses	50,437			622,255			2,783			—		675,475
(Loss) income from operations	(50,437		)	(101,333		)	2,111			—		(149,659		)
Interest expense, net	(51,318		)	(1,303		)	(1,082		)	—		(53,703		)
Other expense, net	(5,292		)	(35		)	1,500			—		(3,827		)
(Loss) income from equity investments	(161,203		)	54			—			161,203		54
(Loss) income from continuing operations before income taxes	(268,250		)	(102,617		)	2,529			161,203		(207,135		)
Income tax benefit	35,959			37,136			—			—		73,095
(Loss) income from continuing operations	(232,291		)	(65,481		)	2,529			161,203		(134,040		)
Loss from discontinued operations, net of income taxes	—			(98,251		)	—			—		(98,251		)
Net (loss) income attributable to common stockholders	$	(232,291	)	$	(163,732	)	$	2,529		$	161,203	$	(232,291	)

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CONSOLIDATING STATEMENTS OF OPERATIONS

YEAR ENDED DECEMBER 31, 2012



	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations		Consolidated
Revenue	$	—		$	255,263		$	1,408		$	—	$	256,671
Costs and expenses:												—
Direct operating expenses	—			197,394			438			—		197,832
General and administrative expenses	17,362			25,346			34			—		42,742
Depreciation and amortization	—			47,115			526			—		47,641
Impairment of long-lived assets	—			6,030			—			—		6,030
Total costs and expenses	17,362			275,885			998			—		294,245
(Loss) income from operations	(17,362		)	(20,622		)	410			—		(37,574		)
Interest expense, net	(25,200		)	(1,155		)	(252		)	—		(26,607		)
Other expense, net	(920		)	(1,630		)	—			—		(2,550		)
Loss on extinguishment of debt	(2,638		)	—			—					(2,638		)
Loss from equity investments	(5,701		)	12			—			5,701		12
(Loss) income from continuing operations before income taxes	(51,821		)	(23,395		)	158			5,701		(69,357		)
Income tax benefit	54,348			8,412			—			—		62,760
Income (loss) from continuing operations	2,527			(14,983		)	158			5,701		(6,597		)
Income from discontinued operations, net of income taxes	—			9,124			—			—		9,124
Net income (loss) attributable to common stockholders	$	2,527		$	(5,859	)	$	158		$	5,701	$	2,527

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CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2014



	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations		Consolidated
Net cash (used in) provided by operating activities from continuing operations	$	(27,860	)	$	43,581		$	1,655		$	—	$	17,376
Net cash provided by operating activities from discontinued operations	—			3,966			—			—		3,966
Net cash (used in) provided by operating activities	(27,860		)	47,547			1,655			—		21,342
Cash flows from investing activities:
Proceeds from the sale of property and equipment	—			10,192			—			—		10,192
Purchase of property, plant and equipment	(1,228		)	(52,377		)	(2,126		)	—		(55,731		)
Net cash used in investing activities from continuing operations	(1,228		)	(42,185		)	(2,126		)	—		(45,539		)
Net cash used in investing activities from discontinued operations	—			(2,451		)	—			—		(2,451		)
Net cash used in investing activities	(1,228		)	(44,636		)	(2,126		)	—		(47,990		)
Cash flows from financing activities:
Proceeds from revolving credit facility	107,725			—			—			—		107,725
Payments on revolving credit facility	(67,500		)	—			—			—		(67,500		)
Payments for deferred financing costs	(1,030		)	—			—			—		(1,030		)
Payments on notes payable and capital leases	—			(5,289		)	—			—		(5,289		)
Payments of contingent consideration and other financing activities	(145		)	(1,014		)	—			—		(1,159		)
Net cash provided by (used in) financing activities from continuing operations	39,050			(6,303		)	—			—		32,747
Net cash provided by financing activities from discontinued operations	—			105			—			—		105
Net cash provided by (used in) financing activities	39,050			(6,198		)	—			—		32,852
Net increase (decrease) in cash	9,962			(3,287		)	(471		)	—		6,204
Cash and cash equivalents - beginning of year	3,839			3,630			1,743			—		9,212
Cash and cash equivalents - end of year	13,801			343			1,272			—		15,416
Less: cash and cash equivalents of discontinued operations - end of year	—			(2,049		)	—			—		(2,049		)
Cash and cash equivalents of continuing operations - end of year	$	13,801		$	(1,706	)	$	1,272		$	—	$	13,367

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CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2013



	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations		Consolidated
Net cash provided by operating activities from continuing operations	$	20,693		$	43,458		$	2,517		$	—	$	66,668
Net cash provided by operating activities from discontinued operations	—			3,589			—			—		3,589
Net cash provided by operating activities	20,693			47,047			2,517			—		70,257
Cash flows from investing activities:
Cash paid for acquisitions, net of cash acquired	(10,570		)	—			—			—		(10,570		)
Proceeds from the sale of property and equipment	—			2,308			—			—		2,308
Proceeds from acquisition-related working capital adjustment	2,067			—			—			—		2,067
Purchase of property, plant and equipment	(1,597		)	(43,366		)	(1,630		)	—		(46,593		)
Net cash used in investing activities from continuing operations	(10,100		)	(41,058		)	(1,630		)	—		(52,788		)
Net cash used in investing activities from discontinued operations	—			(4,195		)	—			—		(4,195		)
Net cash used in investing activities	(10,100		)	(45,253		)	(1,630		)	—		(56,983		)
Cash flows from financing activities:
Proceeds from revolving credit facility	98,501			—			—			—		98,501
Payments on revolving credit facility	(109,501		)	—			—			—		(109,501		)
Payments for deferred financing costs	(855		)	—			—			—		(855		)
Payments on notes payable and capital leases	—			(5,416		)	—			—		(5,416		)
Payments of contingent consideration and other financing activities	(718		)	(1,884		)	—			—		(2,602		)
Net cash used in financing activities from continuing operations	(12,573		)	(7,300		)	—			—		(19,873		)
Net cash used in financing activities from discontinued operations	—			(400		)	—			—		(400		)
Net cash used in financing activities	(12,573		)	(7,700		)	—			—		(20,273		)
Net (decrease) increase in cash	(1,980		)	(5,906		)	887			—		(6,999		)
Cash and cash equivalents - beginning of year	5,819			9,536			856			—		16,211
Cash and cash equivalents - end of year	3,839			3,630			1,743			—		9,212
Less: cash and cash equivalents of discontinued operations - end of year	—			(429		)	—			—		(429		)
Cash and cash equivalents of continuing operations - end of year	$	3,839		$	3,201		$	1,743		$	—	$	8,783

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CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2012



	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations		Consolidated
Net cash (used in) provided by operating activities from continuing operations	$	(23,119	)	$	47,301		$	896		$	—	$	25,078
Net cash provided by operating activities from discontinued operations	—			5,593			—			—		5,593
Net cash (used in) provided by operating activities	(23,119		)	52,894			896			—		30,671
Cash flows from investing activities:												—
Cash paid for acquisitions, net of cash acquired	(359,456		)	2,110			—					(357,346		)
Proceeds from the sale of property and equipment	—			7,235			—			—		7,235
Proceeds from the sale of available-for-sale securities	5,169			—			—					5,169
Purchase of property, plant and equipment	(41		)	(43,466		)	(9		)	—		(43,516		)
Other investing activities	—			(51		)	(31		)			(82		)
Net cash used in investing activities from continuing operations	(354,328		)	(34,172		)	(40		)	—		(388,540		)
Net cash used in investing activities from discontinued operations	—			(4,158		)	—			—		(4,158		)
Net cash used in investing activities	(354,328		)	(38,330		)	(40		)	—		(392,698		)
Cash flows from financing activities:
Proceeds from revolving credit facility	193,490			—			—			—		193,490
Payments on revolving credit facility	(186,674		)	—			—			—		(186,674		)
Proceeds from other debt	398,980			—			—					398,980
Payments on other debt	(150,367		)	—			—					(150,367		)
Proceeds from equity offering	76,048			(1,600		)	—					74,448
Payments for deferred financing costs	(26,170		)	—			—			—		(26,170		)
Payments on notes payable and capital leases	—			(4,605		)	—			—		(4,605		)
Payments of contingent consideration and other financing activities	(1,569		)	511			—			—		(1,058		)
Net cash provided by (used in) financing activities from continuing operations	303,738			(5,694		)	—			—		298,044
Net cash provided by financing activities from discontinued operations	—			—			—			—		—
Net cash provided by (used in) financing activities	303,738			(5,694		)	—			—		298,044
Net (decrease) increase in cash	(73,709		)	8,870			856			—		(63,983		)
Cash and cash equivalents - beginning of year	79,528			666			—			—		80,194
Cash and cash equivalents - end of year	5,819			9,536			856			—		16,211
Less: cash and cash equivalents of discontinued operations - end of year	—			(1,435		)	—			—		(1,435		)
Cash and cash equivalents of continuing operations - end of year	$	5,819		$	8,101		$	856		$	—	$	14,776

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Exhibit Number		Description
2.1		Stock Purchase Agreement, dated as of November 8, 2010, among Heckmann Corporation, Complete Vacuum and Rental, Inc., Steven W. Kent, II, and Jana S. Kent (incorporated herein by reference to Exhibit 2.10 to Heckmann Corporation’s Current Report on Form 8-K filed with the SEC on November 9, 2010).

2.2		Share Purchase Agreement, dated as of September 30, 2011, among Pacific Water & Drinks (HK) Group Limited (f/k/a Sino Bloom Investments Limited), China Water & Drinks (BVI) Inc., and China Water Drinks (H.K.) Holdings Limited (incorporated herein by reference to Exhibit 10.1 to Heckmann Corporation’s Current Report on Form 8-K filed with the SEC on October 5, 2011).

2.3		Stock Purchase Agreement, dated as of March 7, 2012, among TFI Holdings, Inc., Green Fuel Services, LLC, Heckmann Hydrocarbons Holdings Corporation and Heckmann Corporation (incorporated herein by reference to Exhibit 2.1 to Heckmann Corporation’s Current Report on Form 8-K filed with the SEC on March 13, 2012).

2.4		Agreement and Plan of Merger, dated as of September 3, 2012, among Rough Rider Acquisition, LLC, Heckmann Corporation, Badlands Energy, LLC and Mark D. Johnsrud (incorporated herein by reference to Exhibit 2.1 to Heckmann Corporation’s Current Report on Form 8-K filed with the SEC on September 4, 2012).

2.4	A	Voting Agreement among Heckmann Corporation, Rough Rider Acquisition, LLC and the principal stockholders party thereto (incorporated herein by reference to Exhibit 10.1 to Heckmann Corporation’s Current Report on Form 8-K filed with the SEC on September 4, 2012).

2.4	B	Side Letter, dated November 29, 2012, among Heckmann Corporation, Rough Rider Acquisition, LLC, Badlands Power Fuels, LLC and Mark D. Johnsrud (incorporated herein by reference to Exhibit 2.1A to Heckmann Corporation’s Current Report on Form 8-K filed with the SEC on December 6, 2012).

2.5		Stock Purchase Agreement by and among Nuverra Environmental Solutions, Inc., Heckmann Environmental Services, Inc., Thermo Fluids Inc., and Safety-Kleen, Inc. (incorporated herein by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed with the SEC on February 4, 2015).

3.1		Amended and Restated Certificate of Incorporation (incorporated herein by reference to Exhibit 3.1 to Amendment No. 2 to Heckmann Corporation’s Registration Statement on Form S-1 filed with the SEC on September 4, 2007).

3.1	A	Certificate of Amendment to Amended and Restated Certificate of Incorporation (incorporated herein by reference to Exhibit 3.1 to Heckmann Corporation’s Current Report on Form 8-K filed with the SEC on November 5, 2008).

3.1	B	Second Certificate of Amendment of Amended and Restated Certificate of Incorporation (incorporated herein by reference to Exhibit 3.1B to Heckmann Corporation’s Annual Report on Form 10-K for the year ended December 31, 2010, filed with the SEC on March 14, 2011).

3.1	C	Third Certificate of Amendment of Amended and Restated Certificate of Incorporation (incorporated herein by reference to Exhibit 3.1C to the Company’s Registration Statement on Form S-4 filed with the SEC on May 23, 2013).

3.1	D	Fourth Certificate of Amendment of Amended and Restated Certificate of Incorporation (incorporated herein by reference to Exhibit 3.1 to Company’s Current Report on Form 8-K filed with the SEC on December 3, 2013).

3.2		Amended and Restated Bylaws (incorporated herein by reference to Amendment No. 4 to Heckmann Corporation’s Registration Statement on Form S-1 filed with the SEC on October 26, 2007).

4.1		Specimen Common Stock Certificate.

4.2		Indenture, dated as of April 10, 2012, among Heckmann Corporation, the Guarantors party thereto, and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.1 to Heckmann Corporation’s Current Report on Form 8-K filed with the SEC on April 13, 2012).

4.2	A	First Supplemental Indenture, dated as of April 10, 2012, among Heckmann Corporation, the Guarantors party thereto, and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.1A to Heckmann Corporation’s Current Report on Form 8-K filed with the SEC on April 13, 2012).

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Exhibit Number		Description
4.2	B	Second Supplemental Indenture, dated as of September 19, 2012, among Heckmann Corporation, the Guarantors party thereto, and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.1B to Heckmann Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, filed with the SEC on November 9, 2012).

4.2	C	Third Supplemental Indenture, dated as of November 30, 2012, among Heckmann Corporation, the Guarantors party thereto, and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.2C to Heckmann Corporation’s Current Report on Form 8-K filed with the SEC on December 6, 2012).

4.3		Registration Rights Agreement, dated as of April 10, 2012, among Heckmann Corporation, the Guarantors named therein, Jefferies & Company, Inc., Credit Suisse Securities (USA) LLC and Wells Fargo Securities, LLC, as Representatives of the various Initial Purchasers named therein, including Joinder Agreement, dated as of April 10, 2012 (incorporated herein by reference to Exhibit 4.2 to Heckmann Corporation’s Current Report on Form 8-K filed with the SEC on April 13, 2012).

4.4		Registration Rights Agreement, dated as of November 5, 2012, among Heckmann Corporation, the Guarantors named therein, and Jefferies & Company, Inc., Wells Fargo Securities, LLC and Credit Suisse Securities (USA) LLC, as Representatives of the various Initial Purchasers named therein (incorporated herein by reference to Exhibit 4.3 to Heckmann Corporation’s Current Report on Form 8-K filed with the SEC on November 7, 2012).

4.4	A	Joinder Agreement to the Registration Rights Agreement, dated November 30, 2012, among Badlands Power Fuels, LLC (Delaware), Badlands Power Fuels, LLC (North Dakota), Landtech Enterprises, L.L.C. and Badlands Leasing, LLC (incorporated herein by reference to Exhibit 4.3A to Heckmann Corporation’s Current Report on Form 8-K filed with the SEC on December 6, 2012).

4.5		Nuverra 2013 Employee Stock Purchase Plan (incorporated herein by reference to Exhibit 4.5 to the Company’s Registration Statement on Form S-8 filed with the SEC on August 16, 2013).

10.1		Amended and Restated Credit Agreement, dated February 3, 2014, by and among the Company, as borrower; Wells Fargo Bank, National Association, a national banking association, as administrative agent; Wells Fargo, Bank of America, N.A., a national banking association, and RBS Citizens, N.A., a national banking association, as joint lead arrangers; Wells Fargo, Bank of America and RBS Citizens, as joint book runners; Bank of America and RBS Citizens, as co-syndication agents; and Wells Fargo, Bank of America and Citizens Bank of Pennsylvania, as lenders (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on February 7, 2014).

10.1	A	Joinder and First Amendment to Amended and Restated Credit Agreement by and among Wells Fargo Bank, National Association, as agent for the Lenders, the Lenders party thereto, Nuverra Environmental Solutions, Inc., a Delaware corporation, Capital One Business Credit Corporation and CIT Finance LLC (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC March 24, 2014).

10.1	B	Amended and Restated Guaranty and Security Agreement, dated February 3, 2014, by and among the Company, Heckmann Environmental Services, Inc., Thermo Fluids Inc., Heckmann Water Resources Corporation, Heckmann Water Resources (CVR), Inc., 1960 Well Services, LLC, HEK Water Solutions, LLC, Appalachian Water Services, LLC, Badlands Power Fuels LLC, Badlands Power Fuels, LLC, Landtech Enterprises, LLC, Badlands Leasing, LLC, Ideal Oilfield Disposal, LLC; and Wells Fargo Bank, National Association (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the SEC on February 7, 2014).

10.1	C	Intercompany Subordination Agreement, dated February 3, 2014, by and among the Company, Heckmann Environmental Services, Inc., Thermo Fluids Inc., Heckmann Water Resources Corporation, Heckmann Water Resources (CVR), Inc., 1960 Well Services, LLC, HEK Water Solutions, LLC, Appalachian Water Services, LLC, Badlands Power Fuels LLC, Badlands Power Fuels, LLC, Landtech Enterprises, LLC, Badlands Leasing, LLC and Ideal Oilfield Disposal, LLC; and Wells Fargo Bank, National Association (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the SEC on February 7, 2014).

10.1	D	Patent Security Agreement, dated February 3, 2014, by and between the Company and Wells Fargo Bank, National Association (incorporated herein by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed with the SEC on February 7, 2014).

10.2		Novation Agreement dated as of September 30, 2011, between China Water and Drinks, Inc. and China Water & Drinks (BVI), Inc. (incorporated herein by reference to Exhibit 10.2 to Heckmann Corporation’s Current Report on Form 8-K filed with the SEC on October 5, 2011).

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Exhibit Number			Description
10.3	†		Heckmann Corporation 2009 Equity Incentive Plan (incorporated herein by reference to Appendix B to the Registrant’s Definitive Proxy Statement on Schedule 14A filed with the SEC on March 27, 2012).

10.3	A	†	First Amendment of the Heckmann Corporation 2009 Equity Incentive Plan (incorporated herein by reference to Appendix A to the Registrant’s Definitive Proxy Statement on Schedule 14A filed with the SEC on March 27, 2012).

10.3	B	†	Second Amendment to the Nuverra Environmental Solutions, Inc. 2009 Equity Incentive Plan (incorporated herein by reference to Exhibit 10.1 the Company’s Current Report on Form 8-K filed with the SEC May 8, 2014).

10.4	†		Executive Employment Agreement, dated November 30, 2012, between Heckmann Corporation and Mark D. Johnsrud (incorporated herein by reference to Exhibit 10.4 to Heckmann Corporation’s Current Report on Form 8-K filed with the SEC on December 6, 2012).

10.5			Stockholder’s Agreement, dated as of November 30, 2012, between Heckmann Corporation and Mark D. Johnsrud (incorporated herein by reference to Exhibit 10.2 to Heckmann Corporation’s Current Report on Form 8-K filed with the SEC on December 6, 2012).

10.5	A		First Amendment to Stockholder’s Agreement, dated as of March 10, 2014, between Nuverra Environmental Solutions, Inc. and Mark D. Johnsrud (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC March 10, 2014).

10.6	†		Second Amended and Restated Executive Employment Agreement, dated November 9, 2011, between Heckmann Corporation and Brian R. Anderson (incorporated herein by reference to Exhibit 10.2 to Heckmann Corporation’s Current Report on Form 8-K filed with the SEC on November 9, 2011).

10.7	*		Gathering and Disposal Services Agreement (Produced and Freshwater) dated November 21, 2014 by and between Nuverra Rocky Mountain Pipeline, LLC and XTO Energy Inc.**

14.1			Code of Business Conduct and Ethics (incorporated herein by reference to Exhibit 14.1 to Heckmann Corporation’s Current Report on Form 8-K filed with the SEC on September 21, 2011).

21.1	*		Subsidiaries of Nuverra Environmental Solutions, Inc.

23.1	*		Consent of KPMG LLP

24.1	*		Power of Attorney of Officers and Directors of the Company (set forth on the signature pages of this Form 10-K).

31.1	*		Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2	*		Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1	*		Certification of CEO and CFO Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS		*	XBRL Instance Document

101.SCH		*	XBRL Taxonomy Extension Schema Document

101.CAL		*	XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF		*	XBRL Taxonomy Extension Definition Linkbase Document

101.LAB		*	XBRL Taxonomy Extension Definition Linkbase Document

101.PRE		*	XBRL Taxonomy Extension Presentation Linkbase Document

*			Filed herewith
**			Pursuant to 17 CFR 240.24b-2, confidential information has been omitted and has been filed separately with the SEC pursuant to a Confidential Treatment Application filed with the SEC
†			Compensatory plan, contract or arrangement in which directors or executive officers may participate

112

Exhibit 10.7

GATHERING AND DISPOSAL SERVICES AGREEMENT

(PRODUCED & FRESH WATER)

Portions of this Exhibit have been redacted pursuant to a request for confidential treatment under Rule 24b-2 promulgated under the Securities Exchange Act of 1934, as amended. The redacted material marked “[***]” has been separately filed with the Securities and Exchange Commission, together with such request for confidential treatment.


ARTICLE 1	TERM 1


1.1	Term 1


ARTICLE 2	SERVICES 2


2.1	Produced/Fresh Water Services 2


ARTICLE 3	GATHERING SYSTEM AND DISPOSAL FACILITIES 3


3.1	Construction of the Pipelines 3


3.2	[***] 4


3.3	Purchase of Additional Equipment, Assignment of Salt Water Disposal Well 4


3.4	Additional Receipt Point Connection Requests 5


3.5	Construction of Gathering System and Disposal Facilities 6


3.6	Operation of Gathering System and Disposal Facilities 6


ARTICLE 4	FEES 6


4.1	Fees 6


4.2	Produced Water Gathering Fee 6


4.3	Produced Water Disposal Fee 7


4.4	Fresh Water Delivery Fee 7


4.5	Fresh Water Fee 7


4.6	Fees Renegotiation 7


ARTICLE 5	BILLING AND PAYMENTS 8


5.1	Invoices 8


5.2	Payment 8


5.3	Dispute 8


5.4	Audit 8


5.5	Late Payments 9


5.6	Financial Responsibility 9


ARTICLE 6	TAXES AND OTHER ASSESSMENTS 10


6.1	Taxes 10


ARTICLE 7	REPRESENTATIONS 10


7.1	Representations 10


7.2	Acknowledgements 11


ARTICLE 8	CONTROL, CUSTODY AND TITLE 11


8.1	Produced/Fresh Water 11


ARTICLE 9	INDEMNITIES 11


9.1	Mutual Indemnity 11


9.2	Limitations 12


9.3	Waiver of Consequential Damages 12


ARTICLE 10	INSURANCE 12


10.1	Insurance 12


ARTICLE 11	DEDICATION 13


11.1	Dedication 13


ARTICLE 12	TERMS AND CONDITIONS OF THE SERVICES 14


12.1	Frac Scheduling 14


12.2	Quality Specifications 15


12.3	Changes in Law 17


ARTICLE 13	FORCE MAJEURE AND MAINTENANCE 18


13.1	Non-Performance 18


13.2	Definition 18


13.3	Strikes 18


13.4	Notice 19


13.5	Maintenance and Other Operations 19


13.6	Payments During Force Majeure Events 19


ARTICLE 14	TERMINATION 20


14.1	Immediate Termination 20


14.2	Payment upon Termination 20


14.3	Survival 20


14.4	Damages for Early Termination 20


ARTICLE 15	ASSIGNMENT 20


15.1	Assignment 20


15.2	Inurement 21


ARTICLE 16	EASEMENTS/RIGHT-OF-WAY 21


16.1	Easements/Right-of-Way 21


ARTICLE 17	MISCELLANEOUS 21


17.1	Compliance 21


17.2	Notice 21


17.3	Governing Law 22


17.4	WAIVER OF JURY TRIAL 22


17.5	Enforceability 22


17.6	Waiver 22


17.7	Confidentiality, Non-Disclosure 22


17.8	Notification 22


17.9	Relief 22


17.10	No Third Party Beneficiaries 22


17.11	Amendment 22


17.12	Entire Agreement 23


17.13	[***] 23


17.14	Formation of Additional Entities 23

iii

GATHERING AND DISPOSAL SERVICES AGREEMENT

(PRODUCED & FRESH WATER)

THIS GATHERING AND DISPOSAL SERVICES AGREEMENT (PRODUCED & FRESH WATER) (this “Agreement”) dated November 21, 2014 (the “Effective Date”), is made by and between (i) Nuverra Rocky Mountain Pipeline, LLC, a Delaware limited liability company (“Gatherer”) and (ii) XTO Energy Inc., a Delaware corporation (“Producer”). Gatherer and Producer are sometimes referred to herein individually as a “Party” and collectively as the “Parties.”

Recitals

A. Producer owns or controls and has the right to engage in oil and gas drilling and production operations conducted on the Dedicated Properties (defined hereafter) as identified on Exhibit A, attached hereto and made a part hereof.

B. Gatherer desires to provide Produced Water (defined hereafter) gathering/disposal services as well as provide pipeline delivered Fresh Water (defined hereafter) with respect to the Dedicated Properties located in the Watford City and Charlson areas of McKenzie County, North Dakota.

C. Gatherer will construct, own and operate a Produced Water gathering system and disposal facilities and a Fresh Water delivery system in McKenzie County, North Dakota (as modified and expanded by Gatherer from time-to-time, the “Gathering System and Disposal Facilities”) for the purpose of providing the Services contemplated by this Agreement.

D. Exhibit B, attached hereto and made a part hereof, sets forth the definitions of various capitalized terms used in this Agreement.

Agreement:

NOW, THEREFORE, for good and valuable consideration, Gatherer and Producer agree as follows:

ARTICLE 1
TERM

1.1 Term. The obligations set forth in this Agreement shall commence on the earlier of (a) the date that Gatherer completes construction of the Gathering System and Disposal Facilities (which date shall be memorialized by a stipulation executed by both Parties) or (b) December 31, 2015 (the “In-Service Date”) and continue in effect until the fifteenth (15^th) anniversary of the In-Service Date (the “Primary Term”). Following the end of the Primary Term, either Party may renew this Agreement for up to [***] subsequent [***] extension periods (each a “[***]”) upon Notice of extension being served to the other Party at least one hundred twenty (120) days prior to the end of the Primary Term or any [***] then in effect.

The addition of additional Receipt Points per Article 3.4 shall not constitute an extension of the Primary Term or any applicable [***] of this Agreement. The Fees for any Services provided by Gatherer to Producer prior to the In-Service Date shall be at the rates outlined in Article 4, below. Notwithstanding anything to the contrary herein, no Party shall have the right to terminate this Agreement between the Effective Date and the In-Service Date, except as provided in Articles 14.1(a) and 14.1(b).

ARTICLE 2
SERVICES

2.1 Produced/Fresh Water Services.

(a) Producer shall deliver to the Produced Water Receipt Points, and Gatherer shall receive at the Produced Water Receipt Points and dispose of all Produced Water on and subject to the terms and conditions provided in this Agreement. If Gatherer is unable to receive the Firm Capacity Amount of Produced Water for any reason, other than a Force Majeure Event or a Maintenance Suspension Event, then Gatherer shall make commercially reasonable efforts to make other transportation arrangements for any volumes of Produced Water that Gatherer is unable to receive, up to the Firm Capacity Amount of Produced Water. During any interruption period less than or equal to [***] consecutive days (an “Interruption Period”), other than a Force Majeure Event or a Maintenance Suspension Event, Producer shall still be obligated to pay Gatherer the Produced Water Gathering Fee and the Produced Water Disposal Fee, as defined in Article 4, for any Produced Water received during an Interruption Period. During an Interruption Period, Gatherer shall be liable for [***]. In the event an interruption period, other than a Force Majeure Event or a Maintenance Suspension Event, continues for a period of time longer than [***] consecutive days (an “Extended Interruption Period”), Gatherer shall provide Producer with Notice containing the anticipated duration of the Extended Interruption Period and shall temporarily release Producer from the portion of the Dedication associated with the affected Produced Water Receipt Point(s) for which Gatherer is unable to receive Produced Water, until such time as Gatherer is able to resume receiving Produced Water at such affected Produced Water Receipt Point(s). During an Extended Interruption Period, Gatherer shall have [***]. In the event Gatherer is able to resume receiving Produced Water from the affected Produced Water Receipt Point(s), Gatherer shall provide Producer with ten (10) days advance Notice, including the date on which Gatherer shall resume receiving Produced Water, and upon such date the affected Produced Water Receipt Point(s) shall be re-dedicated under this Agreement.

(b) [***]. Gatherer shall deliver to the Fresh Water Receipt Points, and Producer shall receive at the Fresh Water Receipt Points Fresh Water on and subject to the terms and conditions provided in this Agreement. If Gatherer is unable to deliver the Firm Capacity Amount of Fresh Water for any reason, other than a Force Majeure Event or a Maintenance Suspension Event, then Gatherer shall make commercially reasonable efforts to make other transportation arrangements for any volumes of Fresh Water that Gatherer is unable to transport, up to the Firm Capacity Amount of Fresh Water. During any Interruption Period,

other than a Force Majeure Event or a Maintenance Suspension Event, Producer shall still be obligated to pay Gatherer the Fresh Water Fee and Fresh Water Delivery Fee, as defined in Article 4, for any Fresh Water delivered during an Interruption Period. Gatherer shall be liable for [***] during an Interruption Period. During an Extended Interruption Period, Gatherer shall provide Producer with Notice containing the anticipated duration of the Extended Interruption Period and shall temporarily release Producer from the portion of the Dedication associated with the affected Fresh Water Receipt Point(s) for which Gatherer is unable to deliver Fresh Water, until such time as Gatherer is able to resume delivering Fresh Water at such affected Fresh Water Receipt Point(s). During an Extended Interruption Period, Gatherer shall have [***]. In the event Gatherer is able to resume delivering Fresh Water to the affected Fresh Water Receipt Point(s), Gatherer shall provide Producer with ten (10) days advance Notice, including the date on which Gatherer shall resume delivering Fresh Water, and upon such date the affected Fresh Water Receipt Point(s) shall be re-dedicated under this Agreement.

ARTICLE 3
GATHERING SYSTEM AND DISPOSAL FACILITIES

3.1 Construction of the Pipelines. Gatherer shall design, purchase (or lease), construct, install, maintain (or cause to be designed, purchased [or leased], constructed, installed and maintained), own (or lease) and operate (or cause to be operated) the Pipelines including: (i) a service line, meter assembly, and isolation valve to the edge of each Producer Well pad located within a [***] radius of Gatherer’s trunk line, at a point on the Producer Well pad that is nearest to Gatherer’s applicable pipeline and (iii) any booster pumps, pig stations, or storage facilities necessary for the operation of the Pipelines located off the Producer Well pads. The Charlson Produced Water Pipeline and disposal system(s) and the Watford Produced Water Pipeline and disposal system(s) shall each have the capacity of receiving up to [***] Barrels of Produced Water per day. Gatherer shall provide firm capacity to Producer to transport up to [***] Barrels of Produced Water per day through the Watford Produced Water Pipeline and up to [***] Barrels of Produced Water per day through the Charlson Produced Water Pipeline (individually and/or collectively, as the context may require, the “Firm Capacity Amount of Produced Water”), provided, however, that Gatherer shall have no obligation to receive more than [***] Barrels of Produced Water from any one Producer spacing unit per day. Subject to curtailment and pipeline system capacity, Gatherer shall also provide additional capacity (on an Interruptible Basis) to Producer to transport up to an additional [***] Barrels of Produced Water per day through the Watford Produced Water Pipeline and up to an additional [***] Barrels of Produced Water per day through the Charlson Produced Water Pipeline. The Charlson Fresh Water Pipeline and the Watford Fresh Water Pipeline shall each have the capacity to deliver a firm amount of up to [***] Barrels of Fresh Water per day (individually and/or collectively, as the context may require, the “Firm Capacity Amount of Fresh Water”). If Gatherer is unable to receive up to the Firm Capacity Amount of Produced Water and deliver up to the Firm Capacity Amount of Fresh Water, as set forth above, then Article 2.1(a) and Article 2.1(b) shall apply, as applicable. To the extent on any given day, Gatherer is (A) unable to receive Produced Water above the Firm Capacity Amount of Produced Water, and additional capacity on an Interruptible Basis is not available, or is available, but not in sufficient quantities to satisfy the transportation needs of Producer on that particular day or (B) unable to provide for the delivery

of Fresh Water above the Firm Capacity Amount of Fresh Water, and additional capacity on an Interruptible Basis is not available, or is available, but not in sufficient quantities to satisfy the transportation needs of Producer on that particular day, then Gatherer shall [***]. Notwithstanding anything contained herein to the contrary, in no event shall Gatherer be obligated to supply Producer with any volumes of Fresh Water under this Agreement or otherwise, unless a written agreement signed by both Parties is entered into setting forth such obligations.

3.2 [***].

3.3 Purchase of Additional Equipment, Assignment of Salt Water Disposal Well.

(a) In addition to the facilities and equipment listed in Article 3.1, Gatherer shall construct (i) all meters and measurement equipment for Produced Water located at each Producer Well as required by the North Dakota Industrial Commission (“NDIC”), (ii) all pumps required to permit Producer to meet the minimum amount of volumes of Produced Water as set forth in Article 3.1, and (iii) all pump skids or piping that are to be located on Producer Well pads (collectively, the “Additional Equipment”). Upon Gatherer’s completion of the installation of the Additional Equipment at each Producer Well pad, Gatherer shall invoice Producer for the actual purchase price and labor costs for the design, purchase, construction, management and installation of the Additional Equipment (as supported by reasonable documentation upon request), which Producer shall promptly remit to Gatherer an amount equal to such invoice(s) pursuant to Article 5.2. Within thirty (30) days after receipt of payment, Gatherer shall assign, via a bill of sale, the Additional Equipment to Producer. After the foregoing assignment to Producer, [***] shall continue to maintain, repair, augment and replace the Additional Equipment, as needed, and all costs for goods and labor associated therewith shall be at [***] sole expense.

(b) Upon execution of this Agreement, [***] as set forth in the Producer’s salt water disposal lease agreement for the salt water disposal well commonly known as the [***] SWD well. [***] said salt water disposal lease agreement, and [***] said salt water disposal lease agreement, the equipment, facilities and fixtures on the [***] SWD well site and the permits, easements and rights-of-way associated with the [***] SWD well site.

3.4 Additional Receipt Point Connection Requests.

(a) In the event Producer desires Gatherer to add additional Receipt Point(s) on acreage contiguous to the Dedicated Properties that requires Gatherer to build new pipeline infrastructure (a “Pipeline Extension”) less than or equal to [***] in length in order to connect with Gatherer’s existing Gathering System and Disposal Facilities, Producer shall provide Gatherer with at least sixty (60) days advance written notice (a “Connection Request”). Upon receipt of a Connection Request, Gatherer shall commence activities necessary to construct the Pipeline Extension and additional Receipt Point(s) associated therewith for Producer Wells as soon as commercially practicable following the time such Connection Request is made by Producer. Such Pipeline Extension and Receipt Point(s) shall become a part of the existing Gathering System and Disposal Facilities and shall be subject to the specifications and terms and conditions contained in this Agreement (including adding the applicable property(ies) to Exhibit A, as Dedicated Properties). Gatherer shall provide the Services provided for herein to such new Receipt Points, and the applicable Fees for the Services shall be the rates outlined in Article 4, below. Producer shall not make consecutive adjoining [***] Connection Requests in an effort to extend the foregoing [***] obligation of Gatherer in a manner contrary to the intent of the foregoing provisions.

(b) In the event Producer desires Gatherer to add additional Receipt Point(s) on acreage contiguous to the Dedicated Properties that requires Gatherer to build a Pipeline Extension more than [***] in length in order to connect with Gatherer’s existing Gathering System and Disposal Facilities, Producer shall provide Gatherer with at least [***] days advance written notice (an “Outside Connection Request”). Upon receipt of an Outside Connection Request, the Parties shall meet in good faith to negotiate the terms that will govern construction of the Pipeline Extension and additional Receipt Point(s) associated therewith as requested in the Outside Connection Request, including which Party(ies) shall bear the costs of such construction. If the Parties mutually agree upon the terms, Gatherer shall commence activities necessary to construct the Pipeline Extension and additional Receipt Point(s) associated therewith for Producer Wells as soon as commercially practicable following agreement by the Parties as to the terms of the construction. Such Pipeline Extension and Receipt Point(s) shall become a part of the existing Gathering System and Disposal Facilities and shall be subject to the specifications and terms and conditions contained in this Agreement (including adding the applicable property(ies) to Exhibit A, as Dedicated Properties). Gatherer shall provide the Services provided for herein to such new Receipt Points, and the applicable Fees for the Services shall be the rates outlined in Article 4, below.

(c) In the event the Parties do not mutually agree upon terms for construction of the Pipeline Extension and Receipt Point(s) associated therewith as requested in the Outside Connection Request within [***] days from Gatherer’s receipt of the Outside Connection Request, Producer may [***], after delivering Notice to Gatherer. If [***] such Pipeline Extension, [***] the Receipt Point(s) associated therewith. Such Receipt Point(s) will, however, be located where the Pipeline Extension connects into the existing Gathering System and Disposal Facilities. Such Pipeline Extension shall not become part of the existing

Gathering System and Disposal Facilities, but the associated Receipt Point(s) shall become part of the existing Gathering System and Disposal Facilities. Such Pipeline Extension and Receipt Point(s) shall be subject to the specifications and terms and conditions contained in this Agreement (including adding the applicable property(ies) to Exhibit A, as Dedicated Properties), [***]. Gatherer shall provide the Services provided for herein to such new Receipt Points, and the applicable Fees for the Services shall be the rates outlined in Article 4, below.

3.5 Construction of Gathering System and Disposal Facilities. Gatherer shall use commercially reasonable efforts to complete construction of the Gathering System and Disposal Facilities and the Additional Equipment, as is necessary in order to cause the In-Service Date for such facilities to occur on or before [***]. Notwithstanding the foregoing, if a Force Majeure Event occurs, the above date shall be extended by a number equal to the number of days a Force Majeure Event was in effect. [***] shall have the [***] option to terminate any Receipt Point(s) not connected by [***] (subject to extension as the result of a Force Majeure Event as indicated above), and if [***] so opts, then [***] shall be released from its obligations under this Agreement as pertaining to such terminated Receipt Point(s). If [***] does not opt to terminate any Receipt Point(s) not connected by [***] (subject to extension as the result of a Force Majeure Event as indicated above), then Gatherer shall continue to use commercially reasonable efforts to complete construction of such Receipt Point(s), and such period of time between [***] and the time the construction of each such Receipt Point is completed shall be deemed an Extended Interruption Period as to any such Receipt Point for which the construction is not yet completed.

3.6 Operation of Gathering System and Disposal Facilities. Gatherer shall at all times, acting in its sole discretion, have the right to (i) maintain full and complete operational control of the Gathering Systems and Disposal Facilities and (ii) manage, operate, expand, reduce and reconfigure the Gathering System and Disposal Facilities.

ARTICLE 4
FEES

4.1 Fees. As consideration for Gatherer providing the Services contemplated in Article 2, Producer shall pay Gatherer each month an amount equal to the applicable fee specified below and other fees and charges set forth in this Article 4 (collectively, the “Fees”). Payment of such monthly amounts shall be made in accordance with the procedures set forth in Article 5.

4.2 Produced Water Gathering Fee. Producer shall pay Gatherer each month an amount equal to the Produced Water gathering fee (expressed in $/Barrel) of $[***]/Barrel applied to the volume of Produced Water received by Gatherer at the Produced Water Receipt Points during such month (the “Produced Water Gathering Fee”). The foregoing Produced Water Gathering Fee shall be fixed for the first [***] period following the In-Service Date.

4.3 Produced Water Disposal Fee. Producer shall pay Gatherer each month an amount equal to the Produced Water disposal fee (expressed in $/Barrel) of $[***]/Barrel applied to the volume of Produced Water received by Gatherer at the Produced Water Receipt Points during such month (the “Produced Water Disposal Fee”). The foregoing Produced Water Disposal Fee shall be fixed for the first [***] period following the In-Service Date.

4.4 Fresh Water Delivery Fee. Producer shall pay Gatherer each month an amount equal to the Fresh Water delivery fee (expressed in $/Barrel) of $[***]/Barrel for each Barrel or portion thereof for the volume of Fresh Water received by Producer at the Fresh Water Receipt Points during such month (the “Fresh Water Delivery Fee”). The foregoing Fresh Water Delivery Fee shall be fixed for the first [***] period following the In-Service Date.

4.5 Fresh Water Fee. Producer shall pay Gatherer each month an amount equal to the Fresh Water fee (expressed in $/Barrel) of Gatherer’s actual costs in contracting with third party suppliers to obtain the Fresh Water plus an administrative fee of $[***]/Barrel for each Barrel or portion thereof for the volume of Fresh Water received by Producer at the Fresh Water Receipt Points during such month (the “Fresh Water Fee”). The foregoing Fresh Water Fee shall not be fixed, but shall instead fluctuate with the actual costs in contracting with third party suppliers of Fresh Water, however, the administrative fee portion of the Fresh Water Fee shall be fixed.

4.6 Fees Renegotiation.

(a) Not less than thirty (30) days, and not more than ninety (90) days, prior to the end of each [***] period following the In-Service Date (a “[***] Anniversary”), the Parties shall meet in good faith to renegotiate the Produced Water Gathering Fee. [***]. The new Produced Water Gathering Fee shall be equal to [***] of the [***] (the “Default Renegotiated Produced Water Gathering Fee”).

(b) Not less than thirty (30) days, and not more than ninety (90) days, prior to each [***] Anniversary, the Parties shall meet in good faith to renegotiate the Produced Water Disposal Fee. In the event the Parties do not mutually agree on what the new Produced Water Disposal Fee should be prior to any such [***] Anniversary, the Produced Water Disposal Fee shall be adjusted to be the then current market rate for similar salt water well disposal services provided by [***] in the area, in Gatherer’s reasonable determination (the “Default Renegotiated Produced Water Disposal Fee”).

(c) Not less than thirty (30) days, and not more than ninety (90) days, prior to each [***] Anniversary, the Parties shall meet in good faith to renegotiate the Fresh Water Delivery Fee. [***]. The new Fresh Water Delivery Fee shall be equal to [***] of the [***] (the “Default Renegotiated Fresh Water Delivery Fee”).

ARTICLE 5
BILLING AND PAYMENTS

5.1 Invoices. (a) As soon as practicable each month, Gatherer shall invoice Producer for Services provided hereunder during the preceding month and provide a statement setting forth in itemized form:

(b) the volume (expressed in Barrels) of Produced Water received by Gatherer from Producer at each Produced Water Receipt Point;

(d) the Produced Water Disposal Fees attributable to such Produced Water;

(e) the volume (expressed in Barrels) of Fresh Water delivered by Gatherer to Producer at each Fresh Water Receipt Point;

(f) the Fresh Water Delivery Fees attributable to such Fresh Water; and

(g) the Fresh Water Fee attributable to such Fresh Water.

All invoices will be delivered to the “Invoice Delivery” address set forth on Exhibit C, attached hereto and made a part hereof.

5.2 Payment. Producer shall remit to Gatherer the amount due under Article 4 by check or wire transfer to Gatherer’s bank account (which shall be designated by a Notice given by Gatherer to Producer at or prior to the time when the first invoice is sent to Producer) by the thirtieth (30^th) day from the date of receipt of Gatherer’s invoice. If such due date is not a Business Day, payment is due on the next Business Day following such date.

5.3 Dispute. If Producer, in good faith, disputes the amount of any invoice of Gatherer or any part thereof, Producer will timely pay Gatherer such amount, if any, that is not in dispute and shall provide Gatherer Notice, no later than the date that payment of such invoice would be due under Article 5.2, of the disputed amount accompanied by a statement stating the basis for such dispute and supporting documentation reasonably acceptable in industry practice to support the disputed amount. If the Parties are unable to resolve such dispute, either Party may pursue any remedy available at law or in equity to enforce its rights under this Agreement. If Notice of a disputed invoice, with accompanying supporting documents, is not furnished to Gatherer by the date above, Producer shall be deemed to have waived the right to dispute such invoice, subject to Producer’s rights under Article 5.4.

5.4 Audit. Each Party or its designated representatives (which will not include any auditor compensated on a contingent fee basis) shall have the right, at its own expense, upon reasonable prior Notice, and only once at a reasonable time during each calendar year, to examine and audit and to obtain copies of the relevant portion of the books, records (including electronic measurement data, meter charts or records and other similar information supporting relevant calculations) of the other Party and its Affiliates to the extent reasonably necessary to verify the

accuracy of any statement, charge, payment or computation made under this Agreement. This right to examine, audit, and to obtain copies shall not be available with respect to information not directly relevant to transactions under this Agreement. All information obtained by a Party during such audit must be treated as confidential in accordance with Article 17.7 hereof. All invoices and billings shall be conclusively presumed final and accurate and all associated claims for underpayments or overpayments shall be deemed waived unless such invoices or billings are objected to in writing, with adequate explanation and/or documentation and in connection with an audit, within two (2) years after the month in which the Services related to the disputed item occurred. Any retroactive adjustment made in response to information furnished under an audit under this Article 5.4 shall be paid in full by the Party owing payment within thirty (30) days of Notice and substantiation of such inaccuracy.

5.5 Late Payments. If Producer fails to pay the amount of any invoice rendered by Gatherer hereunder when such amount is due, interest thereon shall accrue from the due date to, and including, the date payment thereof is actually made at the lesser of the Prime Rate, computed on an annualized basis, plus two percent (2%) per month and compounded monthly, or the maximum rate of interest permitted by Applicable Law in the state of North Dakota, not to exceed the maximum legal rate. “Prime Rate” means the prime rate on corporate loans at large U.S. money center commercial banks as set forth in The Wall Street Journal “Money Rates” table under the heading “Prime Rate,” or any generally-accepted successor thereto, on the first date of publication for the month in which payment is due. Gatherer shall render a late payment charge invoice, and Producer shall make payment upon receipt of such invoice.

5.6 Financial Responsibility. If Producer fails to pay Gatherer according to the provisions hereof and such failure continues for a period of thirty (30) days after the due date for such payment hereunder, then Gatherer shall have the additional right, to the maximum extent permissible under Applicable Law and upon five (5) days’ Notice to Producer (which Notice may be given prior to the expiration of such thirty (30) day period), to suspend or reduce all Services under this Agreement and without limiting any other rights or remedies available to it under this Agreement or otherwise. If Gatherer exercises the right to suspend or reduce Services under this Article 5.6, then Producer shall not be entitled to take, or cause to be taken, any action hereunder or otherwise against Gatherer for such suspension or reduction and shall pay Gatherer as a minimum fee, and not as a penalty, a [***] fee equal to [***] of the [***] average of Fees paid by Producer to Gatherer for the [***] immediately preceding the suspension or reduction of Services, proportionately reduced for any days for which suspension or reduction of Services does not occur in any given [***]. Failure of Gatherer to exercise its right to suspend or reduce Services as provided in this Article 5.6 shall not constitute a waiver by Gatherer of any rights or remedies, including suspension or reduction of Services, Gatherer may have under this Agreement, Applicable Law, or otherwise.

ARTICLE 6
TAXES AND OTHER ASSESSMENTS

6.1 Taxes. In addition to the Fees in Article 4, Producer shall pay or cause to be paid, and shall indemnify and hold harmless Gatherer and its Affiliates from and against the payment of, all excise, gross production, severance, sales, service, occupation and all other taxes, charges or impositions of every kind and character required by Applicable Law or by any Governmental Authority applicable to (a) Produced Water received or delivered hereunder by Producer or (b) Fresh Water received or delivered hereunder by Producer. Any taxes or statutory charges levied or assessed against Producer’s properties, facilities or operations shall be borne by Producer. Gatherer shall pay or cause to be paid, and shall indemnify and hold harmless Producer and its Affiliates from and against the payment of, all income taxes and any real or personal property taxes and statutory charges imposed on the Gathering System and Disposal Facilities, provided, however, that such taxes or statutory charges are currently in existence. To the extent new taxes or statutory charges are exacted or assessed by any Governmental Authority at any time after the date hereof, Producer shall pay or pay to Gatherer, upon being invoiced by Gatherer, for such new taxes or statutory charges.

ARTICLE 7
REPRESENTATIONS

7.1 Representations. Each Party represents to the other Party as of the date hereof that:

(a) there are no suits, proceedings, judgments, or orders by or before any Governmental Authority that materially adversely affect its ability to perform this Agreement or the rights of the other Party hereunder;

(b) it is duly organized, validly existing, and in good standing under the laws of the jurisdiction of its formation, and it has the legal right, power and authority and is qualified to conduct its business, and to execute and deliver this Agreement and perform its obligations hereunder;

(c) the making and performance by it of this Agreement are within its powers, and have been duly authorized by all necessary action on its part;

(d) this Agreement constitutes a legal, valid, and binding act and obligation of it, enforceable against it in accordance with its terms, subject to bankruptcy, insolvency, reorganization and other laws affecting creditors’ rights generally, and with regard to equitable remedies, to the discretion of the court before which proceedings to obtain same may be pending; and

(e) there are no bankruptcy, insolvency, reorganization, receivership or other arrangement proceedings pending or being contemplated by it.

7.2 Acknowledgements. Each Party acknowledges and agrees that:

(a) the Fees have been freely negotiated and agreed upon as a result of good faith negotiations and are not discriminatory or preferential, but are just, fair, and reasonable in light of the Parties’ respective covenants and undertakings herein during the Primary Term or any [***] of this Agreement; and

(b) neither Party had an unfair advantage over the other during the negotiation of this Agreement.

ARTICLE 8
CONTROL, CUSTODY AND TITLE

8.1 Produced/Fresh Water.

(c) Producer. Producer shall be deemed to be in exclusive control and custody of Produced Water delivered hereunder and shall be responsible for, and shall indemnify and hold harmless Gatherer and its Affiliates from and against, any claims relating to, or arising out of, any damage or injury caused thereby prior to the time such Produced Water shall have been delivered to Gatherer at the Produced Water Receipt Points. Producer shall be deemed to be in exclusive control and custody of Fresh Water received hereunder and shall be responsible for, and shall indemnify and hold harmless Gatherer and its Affiliates from and against, any claims relating to, or arising out of, any damage or injury caused thereby after the time such Fresh Water shall have been delivered to Producer at the Fresh Water Receipt Points.

(d) Gatherer. Subject to Producer’s delivery of Produced Water that conforms to the specifications set forth on Exhibit D, attached hereto and made a part hereof, at and after delivery by Producer to Gatherer of Produced Water at the Produced Water Receipt Points, Gatherer shall be deemed to be in exclusive control and custody thereof and shall be responsible for, and shall indemnify and hold harmless Producer and its Affiliates from and against, any claims relating to, or arising out of, any injury or damage caused thereby. Prior to delivery by Gatherer to Producer of Fresh Water at the Fresh Water Receipt Points, Gatherer shall be deemed to be in exclusive control and custody thereof and shall be responsible for, and shall indemnify and hold harmless Producer and its Affiliates from and against, any claims relating to, or arising out of, any injury or damage caused thereby.

ARTICLE 9
INDEMNITIES

9.1 Mutual Indemnity. Producer shall indemnify and hold harmless Gatherer and its Affiliates from and against any claims relating to or arising out of the operations of Producer, except to the extent such claims are the subject of any express indemnity set forth elsewhere in this Agreement. Gatherer shall indemnify and hold harmless Producer and its Affiliates from and against any claims relating to or arising out of the operations of Gatherer, except to the extent such claims are the subject of any express indemnity set forth elsewhere in this Agreement.

9.2 Limitations. THE INDEMNITIES SET FORTH IN THIS Article 9 AND ELSEWHERE IN THIS AGREEMENT AND THE LIMITATIONS ARE TO BE CONSTRUED WITHOUT REGARD TO ANY CAUSE FOR WHICH SUCH INDEMNITY MAY ARISE, INCLUDING THE STRICT LIABILITY OF ANY PARTY, WHETHER SOLE, JOINT, OR CONCURRENT, OR ACTIVE OR PASSIVE, EXCEPT TO THE EXTENT OF ANY GROSSLY NEGLIGENT ACTS OR OMISSIONS OR FRAUD OR WILLFUL MISCONDUCT OF THE INDEMNIFIED PARTY OR ANY OF ITS AFFILIATES.

9.3 Waiver of Consequential Damages. A PARTY’S LIABILITY UNDER THIS AGREEMENT SHALL BE LIMITED TO DIRECT ACTUAL DAMAGES ONLY. NEITHER PARTY SHALL BE LIABLE TO ANY OTHER PARTY OR ITS AFFILIATES FOR CONSEQUENTIAL, INCIDENTAL, PUNITIVE, EXEMPLARY, OR INDIRECT DAMAGES, LOST PROFITS, OR OTHER BUSINESS INTERRUPTION DAMAGES, BY STATUTE, IN TORT, OR CONTRACT, UNDER ANY INDEMNITY PROVISION IN THIS AGREEMENT OR OTHERWISE (COLLECTIVELY, “SPECIAL DAMAGES”), ALL OF THE SAME SPECIAL DAMAGES BEING HEREBY EXPRESSLY WAIVED AND NEGATED, EXCEPT TO THE EXTENT THE INDEMNIFIED PARTY IS OBLIGATED TO PAY ANY SUCH SPECIAL DAMAGES PURSUANT TO A CLAIM BY A THIRD PARTY. TO THE EXTENT ANY DAMAGES REQUIRED TO BE PAID HEREUNDER ARE LIQUIDATED, THE PARTIES ACKNOWLEDGE THAT THE DAMAGES ARE DIFFICULT OR IMPOSSIBLE TO DETERMINE, OR OTHERWISE OBTAINING AN ADEQUATE REMEDY IS INCONVENIENT, AND THE DAMAGES CALCULATED HEREUNDER CONSTITUTE A REASONABLE APPROXIMATION OF THE HARM OR LOSS.

ARTICLE 10
INSURANCE

10.1 Insurance. During the term of this Agreement, and for one (1) month following the termination of this Agreement, Producer and Gatherer will each maintain and keep in force and effect, at their own expense, the insurance coverages of the types and in the minimum amounts set forth on Exhibit E, attached hereto and made a part hereof. In the event of accident or loss resulting in an insurance claim in connection with this Agreement (whether or not the subject of an indemnification claim pursuant to this Agreement), upon request, Producer and Gatherer shall each provide to the other certified copies of the insurance policies required by this Article 10.1. Producer shall have the right to satisfy insurance obligations through self-insurance, satisfactory to Gatherer, in its sole good faith judgment. Gatherer shall have the right to satisfy insurance obligations through self-insurance, satisfactory to Producer, in its sole good faith judgment. The financial failure of an insurer (or Producer/Gatherer if self-insured) shall not relieve either Party of their indemnity obligations and liabilities under this Agreement.

ARTICLE 11
DEDICATION

11.1 Dedication.

(a) Producer’s Dedication.

(i) Subject only to Producer’s Reservations, as defined below, and the right of Producer to the release of certain acreage pursuant to Article 2, Article 3.5 and Article 11.1(d), Producer:

(A) exclusively dedicates and commits to the performance of this Agreement, as covenants running with the land, all of the well sites, wells and leases attributable to the Dedicated Properties per Exhibit A (the “Dedication”);

(B) represents and warrants that the Dedicated Properties are not otherwise subject to any other dedication, gathering agreement or other commitment or arrangement that would permit or require Produced Water from the Dedicated Properties to be gathered on any other gathering system or disposed of at any other disposal facility; and

(C) if the Dedicated Properties are augmented by Producer’s acquisition of interests from any Person, no pre-acquisition dedication of the augmented portion of the Dedicated Properties from that Person shall be deemed to breach the commitment of Producer in this Article 11. If the Dedicated Properties are augmented by Producer’s acquisition of interests from any Person, Producer shall make a good faith effort to have the pre-acquisition dedication released.

(ii) Prior to assigning any Dedicated Property or interest therein (to the extent permissible under, and in accordance with, this Agreement), Producer shall provide prior written notice to the potential acquiring party of the existence and terms of the Dedication hereunder. Simultaneous to the foregoing delivery of notice to a potential acquiring party, Producer shall also provide Notice to Gatherer informing Gatherer that such notice was provided to a potential acquiring party.

(b) Producer’s Reservations. Producer reserves the following rights (“Producer’s Reservations”): (i) to decide in its sole discretion whether, where, and when to drill any well on the Dedicated Properties; (ii) to operate wells producing from the Dedicated Properties (in respect of which operations Producer undertakes to act as a reasonably prudent operator); and (iii) to pool, communitize or unitize Producer’s interests in the Dedicated Properties with any Person, provided, however, that any pooling, communitizing or unitizing of Producer’s interest in the Dedicated Properties with any Person shall have no effect on the obligations of Producer nor the economic benefit to

Gatherer under this Agreement; otherwise, Producer may not pool, communitize or unitize Producer’s interests in the Dedicated Properties with any Person.

(c) Transfer of Producer’s Interests. Any transfer by Producer of any of its interests in the Dedicated Properties shall comply with Article 15 of this Agreement.

(d) Release from Dedication. To the extent that Gatherer is unable to obtain the rights-of-way required for Gatherer to connect to any previously agreed upon Receipt Point by [***] (subject to any extension of the foregoing date by a Force Majeure Event), and Producer and Gatherer cannot agree to an alternative Receipt Point (in each Party’s sole discretion), Gatherer will permanently release Producer from the portion of the Dedication associated with the Receipt Point(s) for which Gatherer is unable to obtain the rights-of-way, and Producer will permanently release Gatherer from its obligation to either receive Produced Water from such Produced Water Receipt Point(s) or deliver Fresh Water to such Fresh Water Receipt Point(s).

ARTICLE 12
TERMS AND CONDITIONS OF THE SERVICES

12.1 Frac Scheduling. Producer shall provide to Gatherer [***] an updated schedule listing the location and date of commencement for each Frac anticipated to be completed during the subsequent [***] period (the “Frac Schedule”), and Producer shall update Gatherer promptly to disclose any location or change in location and expected date of the commencement of hydraulic fracturing (“Frac”) of each new Producer Well. A sample Frac Schedule is attached hereto, and made a part hereof, as Exhibit F.

(a) Produced Water Disposal. Producer shall be responsible for taking such actions as may be necessary to cause the Produced Water delivered to the Produced Water Receipt Points to meet the specifications for Produced Water set forth on Exhibit D and to be in compliance with all Applicable Laws, and Producer shall indemnify and hold harmless Gatherer and its Affiliates from and against any claims relating to, or arising out of, any failure by Producer or any of its Affiliates to comply with Applicable Laws and the specifications for Produced Water set forth on Exhibit D. Gatherer shall dispose of the Produced Water received by it at the Produced Water Receipt Points in compliance with all Applicable Laws and shall indemnify and hold harmless Producer and its Affiliates from and against any claims relating to, or arising out of, any failure by Gatherer or any of its Affiliates to comply with Applicable Laws in respect of such disposal; provided, however, the Produced Water delivered to the Produced Water Receipt Points meets the specifications for Produced Water set forth on Exhibit D and is in compliance with all Applicable Laws.

(b) Receipt Pressure. The pressure obligations for Produced Water Receipt Points are as listed on Exhibit D.

(i) Pursuant to Article 3.3, Gatherer shall install, own and operate a meter and related measurement equipment for the measurement of Fresh Water and shall install and operate a meter and related measurement equipment for the measurement of Produced Water meeting industry standards and capable of [***].

(ii) Gatherer shall make available to Producer access to meter runs for addition of check meter, or provide measurement data electronically to Producer (or if Gatherer is not the hosting party, Gatherer will authorize the hosting party of any meter to provide data to Producer).

(iii) Each Party shall furnish or cause to be furnished to the other Party hereto all data required to accurately account for all Produced Water and Fresh Water received or delivered hereunder.

(iv) All meters may be inspected and verified for accuracy by Producer at any time upon reasonable advance Notice to Gatherer, at Producer’s expense. Not more than once every three (3) months, Producer may request that Gatherer test a meter if, upon inspection, it believes in good faith that the meter readings are inaccurate. Gatherer shall test the meter and determine after testing whether the meter is accurate. Producer shall reimburse Gatherer for the actual cost of the testing and calibration; provided, however, if it is determined as a result of the testing that the meter is inaccurate by more than two percent (2%) of volume, Gatherer shall be responsible for the actual cost to calibrate the meter and shall make any necessary adjustments.

(v) All meters and the measurement equipment shall be constructed, installed, operated and maintained by Gatherer in accordance with industry standards and all Applicable Laws, including meter testing and calibration at least as often as required by the NDIC, and the Bureau of Land Management, but not less than annually.

(vi) Producer shall be solely responsible for meeting all measurement and reporting requirements of the NDIC for each Producer Well.

12.2 Quality Specifications.

(a) Produced Water. Producer warrants that all Produced Water delivered at the Produced Water Receipt Points shall conform to the specifications set forth on Exhibit D.

(b) Failure to Meet Specifications.

(i) Notwithstanding anything in this Agreement to the contrary, if Gatherer determines at any time that Produced Water tendered by Producer for gathering does not meet any one or more of the quality specifications listed on Exhibit

D, then Gatherer shall have the right, at its option and effective immediately (with Notice to Producer to be provided by Gatherer prior to such refusal where commercially practicable or as soon as commercially practicable after such refusal), to refuse to accept such nonconforming Produced Water until Gatherer determines that the basis for its refusal to accept nonconforming Produced Water has been remediated by Producer to Gatherer’s reasonable satisfaction. Gatherer’s option to refuse receipt of nonconforming Produced Water is in addition to all other remedies available to Gatherer.

(ii) If the Parties determine that treatment for nonconforming Produced Water is feasible and economically viable, Gatherer shall have the option, but not the obligation, to treat such nonconforming Produced Water, and if Gatherer agrees to do so, it shall (within thirty (30) days of having provided Notice to Producer that it intends not to accept nonconforming Produced Water) prepare and provide to Producer an estimate of the costs to install the equipment and other facilities necessary to treat such nonconforming Produced Water. If Gatherer has consented to treat the nonconforming Produced Water, the Parties shall use good faith efforts to agree (within thirty (30) days of provision of the estimate of costs by Gatherer) on the allocation of the cost of the treatment facilities and to agree on a treating fee to be paid on a monthly basis by Producer to Gatherer. Gatherer shall have no obligation to treat Produced Water if the Parties cannot agree on the allocation of cost and on a fee structure, provided Producer shall still remit to Gatherer the Fees for Services provided for hereunder. If such an agreement is reached, then Gatherer shall install and construct such facilities as soon as commercially practicable. In the event an agreement is not reached, Producer shall be solely responsible for treating the nonconforming Produced Water prior to delivery to Gatherer.

(i) If Gatherer at any time accepts receipt of Produced Water that it has actual Knowledge of, and time to act in response to, the fact that the Produced Water was nonconforming, Producer shall have no liability to Gatherer for any claims or losses arising out of the nonconforming Produced Water, including physical damage to any pipeline or appurtenant facilities or economic damage to Gatherer’s commercial operations. Such acceptance will not constitute a waiver of this provision with respect to any future receipt of nonconforming Produced Water.

(ii) If Gatherer at any time accepts receipt of Produced Water that it did not have actual Knowledge was nonconforming or did have actual Knowledge but did not have time to act in response to the fact that the Produced Water was nonconforming, Producer shall be liable to Gatherer for any claims or losses arising out of the nonconforming Produced Water, including physical damage to any pipeline or appurtenant facilities or economic damage to Gatherer’s commercial operations or assessed to Gatherer by third parties caused by such nonconforming Produced Water. If Gatherer does not object to nonconforming Produced Water within [***]

after the date of delivery, then Gatherer will be deemed to have waived its right to be reimbursed under the preceding sentence (but only as to such nonconforming Produced Water volumes that Gatherer had actual Knowledge of the fact that such Produced Water was nonconforming and time to act in response to the fact that such Produced Water was nonconforming).

12.3 Changes in Law.

(a) Material Adverse Change. If a federal, state or local statute or regulation or order by a Governmental Authority with valid jurisdiction over the activities contemplated in this Agreement is anticipated to effect, or effects, a change to a substantive provision of this Agreement that has a material adverse impact upon the performance or benefits of either Party under this Agreement, including, without limitation, the imposition of terms, conditions, or rate restrictions that materially adversely affect the economic positions of the Parties under this Agreement, including any such impact on the economic position of Producer arising or anticipated to arise as a result of the application of this Article 12.3, then the Parties will enter into good faith negotiations to attempt to revise this Agreement so that (i) performance under this Agreement is no longer impacted in a material adverse fashion and (ii) this Agreement is revised in a manner that preserves, to the maximum extent possible, the respective economic positions of the Parties. If Producer and Gatherer are unable to reach agreement on such an amendment, Producer or Gatherer shall have the right to terminate this Agreement with ninety (90) days’ Notice to the non-terminating Party.

(b) Other Changes in Laws and Additional Fees. If there arises any new or subsequently applicable taxes, assessments, fees or other charges arising from any new tax or other regulatory assessment coming into effect after the date of this Agreement or other regulation adopted after the date of this Agreement, then Producer shall reimburse Gatherer for Producer’s allocable share of such taxes and other charges. To the extent such new taxes, assessments, fees or other charges (i) comprise excise duty, on a per-Barrel basis, upon salt water disposal activities and (ii) are imposed by the State of North Dakota, Producer’s allocable share of any such new taxes, assessments, fees or other charges relating to the Produced Water services provided hereunder shall be based on the ratio that the Produced Water received from Producer at the Produced Water Receipt Points bears to the total volume of Produced Water disposed of in Gatherer’s facilities used in the performance of its Produced Water services hereunder, in each case during the applicable period for which such taxes, assessments, fees or other charges are incurred or imposed, as the case may be. Following the [***] anniversary of the In-Service Date, if any new taxes, assessments, fees or other charges (only to the extent that each is described in subsections (i) and (ii) herein) cause this Agreement to become uneconomic, the affected Party shall provide Notice to the other Party and the Parties shall make reasonable commercial efforts to amend this Agreement to reflect mutually agreeable terms. If Producer and Gatherer are unable to reach agreement on such an amendment, Producer or Gatherer shall have the right to terminate this Agreement with ninety (90) days’ Notice to the non-terminating Party.

(c) Notice of Expected Change. Each Party will provide reasonable and prompt Notice to the other Party as to any proposed law, regulations or any regulatory proceedings or actions that could cause such Party to invoke its rights under this Article 12.3.

ARTICLE 13
FORCE MAJEURE AND MAINTENANCE

13.1 Non-Performance. Subject to the other provisions of this Agreement, if a Party is rendered unable, wholly or in part, by reason of a Force Majeure Event to perform its obligations under this Agreement, other than Producer’s obligations to make payments when due hereunder, then such Party’s obligations shall be suspended to the extent affected by the Force Majeure Event.

13.2 Definition. “Force Majeure Event” means any cause or event not reasonably within the control of the Party whose performance is sought to be excused thereby including the following causes and events (to the extent such causes and events are not reasonably within the control of the Party claiming suspension, and without any obligation to expend any funds to cure such causes or events): acts of God, strikes, lockouts, or other industrial disputes or disturbances, wars, civil disturbances and riots, landslides, lightning, earthquakes, fires, tornadoes, hurricanes, storms, floods, washouts and warnings for any of the foregoing which may necessitate the precautionary shut-down of wells, plants, pipelines, gathering systems, disposal facilities or other related facilities; orders, directives, restraints and requirements of governments and government agencies and people, either federal or state, civil and military; any application of government conservation or curtailment rules and regulations; explosions; sabotage; breakage or accidents to equipment, machinery, gathering systems, disposal facilities, facilities or lines of pipe (when either of the foregoing are not the result of actions by Gatherer); inability to secure labor or materials, frost or snow deeper than sixteen (16) inches (applicable during the construction and installation of lines of pipe or after the initial construction and installation of lines of pipe if the lines of pipe are damaged and such damage is not the result of actions by Gatherer), electric power shortages, necessity for compliance with any Applicable Law, weather that necessitates extraordinary measures and expense to construct facilities or maintain operations, or any other causes, whether of the kind enumerated herein or otherwise, not reasonably within the control of the Party claiming suspension. Such term shall likewise include, in those instances where any Party is required to obtain servitudes, rights-of-way, grants, permits, or licenses to enable such Party to fulfill its obligations hereunder, the inability of such Party to acquire, or delays on the part of such Party in acquiring, at reasonable cost and after the exercise of reasonable diligence, such servitudes, rights-of-way, grants, permits or licenses. “Force Majeure Event” also includes any event of force majeure occurring with respect to the facilities or services of any Party’s Affiliates or third party service providers providing a service or providing any equipment, goods, supplies, or other services or items necessary to the performance of such Party’s obligations hereunder, including the occurrence of an event of force majeure event under a third party gathering agreement.

13.3 Strikes. The settlement of strikes or lockouts shall be entirely within the discretion of the Party having the difficulty, and any obligation hereunder to remedy a Force Majeure Event shall not require the settlement of strikes or lockouts by acceding to the demands of the opposing party when such course is inadvisable in the sole discretion of the Party having the difficulty.

13.4 Notice. The Party whose performance is affected by a Force Majeure Event must provide Notice to the other Party as soon as reasonably practicable. Initial Notice may be given orally, but written Notice with reasonably full particulars of the Force Majeure Event is required as soon as reasonably possible after the occurrence of the Force Majeure Event. The Party affected by a Force Majeure Event shall use reasonable commercial efforts to (a) remedy and (b) mitigate the effects of the Force Majeure Event on such Party’s obligations under this Agreement.

13.5 Maintenance and Other Operations. Gatherer may suspend its performance hereunder to the extent required to make necessary (in Gatherer’s sole reasonable discretion) maintenance, testing, pigging, inspections, alterations, or repairs (not required as the result of the occurrence of a Force Majeure Event) to any part of the Gathering System and Disposal Facilities or to make any required relocations, replacements, expansions, connections, alterations, or modifications of pipelines and other equipment and facilities comprising part of the Gathering System and Disposal Facilities for a period of time not to exceed [***] per [***] for any given Receipt Point or Dedicated Property (a “Maintenance Suspension Event”). Gatherer shall give Producer thirty (30) days advance Notice of its intention to suspend its performance hereunder including the date on which such Maintenance Suspension Event shall commence (a “Maintenance Suspension Event Notice”), except in cases of emergency where such Notice is not reasonably practicable or in cases where the operations of Producer will not be affected. Within two (2) days receipt of the Maintenance Suspension Event Notice, Producer shall provide Gatherer with Notice of any requested changes to the date on which the Maintenance Suspension Event shall commence, and Gatherer shall use reasonable efforts to change the commencement of the Maintenance Suspension Event as requested by Producer. During a Maintenance Suspension Event, Gatherer shall use commercially reasonable efforts to make other transportation arrangements for any volumes of Produced Water or Fresh Watch which Gatherer is unable to receive or deliver up to the Firm Capacity Amount of Produced Water or the Firm Capacity Amount of Fresh Water, as applicable, and Producer shall reimburse Gatherer for all costs and expenses at standard rates associated with the alternative transportation arrangements. In the event a Maintenance Suspension Event exceeds [***] per [***] for any given Receipt Point or Dedicated Property, an Interruption Period shall be deemed to have ensued on the [***] of the Maintenance Suspension Event, and shall continue on until the Maintenance Suspension Event has concluded or until the [***] of the Maintenance Suspension Event, at which time an Extended Interruption Period shall be deemed to have begun.

13.6 Payments During Force Majeure Events. Upon the occurrence and during the continuance of a Force Majeure Event, whether affecting Producer or Gatherer, Producer shall remain obligated to pay to Gatherer the Fees described in Article 4 for any Produced Water actually received by Gatherer or any Fresh Water actually delivered by Gatherer. Notwithstanding anything contained herein to the contrary, Producer shall be liable for and shall reimburse Gatherer for all costs and expenses associated with any alternative transportation arrangements provided during a Force Majeure Event.

ARTICLE 14
TERMINATION

14.1 Immediate Termination. This Agreement may be immediately terminated:

(a) by Gatherer if Producer fails to pay any undisputed amount when due under this Agreement if such failure is not remedied within fifteen (15) days after Notice of such failure is given by Gatherer to Producer;

(b) by either Party by Notice to the other if such other Party (i) makes an assignment or any general arrangement for the benefit of creditors, (ii) files a petition or otherwise commences, authorizes, or acquiesces in the commencement of a proceeding or cause under any bankruptcy or similar law for the protection of creditors or have such petition filed or proceeding commenced against it, or (iii) otherwise becomes bankrupt or insolvent (however evidenced); or

14.2 Payment upon Termination. Upon termination by either Party, Producer shall immediately pay Gatherer for any amounts due under this Agreement upon receipt of an invoice from Gatherer.

14.3 Survival. Article 5, Article 6, Article 7, Article 8, Article 9, Article 10, Article 12, Article 14, Article 16, and Article 17 shall survive the termination of this Agreement.

14.4 Damages for Early Termination. If a Party terminates this Agreement under Article 14.1(a) or Article 14.1(b), then such Party may pursue any and all remedies at law or in equity for its claims resulting from such termination.

ARTICLE 15
ASSIGNMENT

15.1 Assignment.

(a) Gatherer may not assign this Agreement without the written consent of Producer unless Gatherer (i) assigns the entire Agreement, and (ii) transfers its ownership in the Gathering System and Disposal Facilities to the assignee contemporaneous with such assignment.

(b) Producer may not assign all or a part of this Agreement without the prior written consent of Gatherer.

(c) Any partial or full (i) assignment, (ii) transfer or (iii) conveyance of the Dedicated Properties made by Producer shall expressly require that the assignee assume and agree to discharge the duties and obligations of its assignor under this Agreement. For purposes of this Agreement, any agreements with a third party operator on the Dedicated

Properties or the creation of a third party working interest or a joint venture shall be deemed an assignment, transfer or conveyance and shall be subject to this Article 15.1(c).

(d) Notwithstanding anything to the contrary above: (i) a Party may assign this Agreement in whole (but not in part) to an Affiliate of such Party without the consent of the other Party, provided that the assigning Party will remain liable for all obligations of the assignee under this Agreement, (ii) a Party may assign this Agreement in connection with the sale of all or substantially all of the assets of the Party (or business unit which administers this Agreement) or a merger or other entity reorganization thereof, or (iii) a Party may assign, pledge or encumber with a lien or security interest its interests under this Agreement to secure the payment of any indebtedness of such Party or any Affiliate of such Party.

15.2 Inurement. Subject to the foregoing provisions of this Article 15, this Agreement shall bind and inure to the benefit of the Parties’ respective successors and assigns.

ARTICLE 16
EASEMENTS/RIGHT-OF-WAY

16.1 Easements/Right-of-Way. Gatherer shall be responsible for obtaining all surface rights necessary for the construction of the Receipt Points and the Additional Equipment. Producer shall, at Gatherer’s request, grant to Gatherer such surface rights, easements, and rights-of-way upon or across a Dedicated Property required by Gatherer to install the Receipt Points and the Additional Equipment and provide the Services on the Gathering System and Disposal Facilities required by this Agreement that Gatherer reasonably requests from Producer at no additional cost to Gatherer and to otherwise perform Gatherer’s obligations under this Agreement to the extent permitted by the various leases, easements, or any other applicable agreement contemplated in this Article 16. Upon the termination of this Agreement in its entirety or as to a specific Receipt Point, such surface rights, easements and rights-of-way shall also terminate except to the extent the surface rights, easements and rights-of-way remain required by Gatherer pursuant to Article 15.

ARTICLE 17
MISCELLANEOUS

17.1 Compliance. This Agreement is subject to, and each Party will comply with, all Applicable Laws of any Governmental Authority now or hereafter having jurisdiction over any Party or its facilities.

17.2 Notice. All notices, invoices, payments, and other communications made under this Agreement (“Notice”) shall be in writing and sent to the addresses shown on Exhibit C.

(a) Method. All Notices may be delivered by a nationally recognized courier service or delivered by hand.

(b) Delivery. Notice shall be given when received on a Business Day by the addressee.

17.3 Governing Law. This Agreement shall be construed, enforced and interpreted according to the laws of the State of North Dakota, without regard to the conflicts of law rules thereof.

17.4 WAIVER OF JURY TRIAL. EACH PARTY HEREBY IRREVOCABLY WAIVES TRIAL BY JURY IN ANY ACTION OR PROCEEDING WITH RESPECT TO THIS AGREEMENT.

17.5 Enforceability. If any provision in this Agreement is determined to be invalid, void or unenforceable by any court having jurisdiction, such determination shall not invalidate, void or make unenforceable any other provision, agreement or covenant of this Agreement.

17.6 Waiver. No waiver of any breach of this Agreement shall be held to be a waiver of any other or subsequent breach.

17.7 Confidentiality, Non-Disclosure. Neither Party shall disclose, directly or indirectly, without the prior written consent of the other Party the terms of this Agreement, or any other information shared between the Parties with respect to this Agreement, to a third party (other than Affiliates, employees, royalty owners, co-working interest owners, actual or prospective lenders, contractors, consultants, counsel, accountants and agents of the Party, or a prospective or actual assignee under Article 15 or prospective or actual purchaser of an interest in the assets or in any of the applicable oil and gas properties located in McKenzie County, North Dakota, provided such Persons shall have agreed to keep such terms confidential), except:

(i) to comply with any Applicable Law;

(ii) to the extent necessary for the enforcement of this Agreement;

(iii) to the extent necessary to comply with a Governmental Authority’s reporting requirements, including any reporting requirements of the United States Securities and Exchange Commission; or

(iv) disclosure of information that has become part of the public domain not due to a violation of this Article 17.

17.8 Notification. Each Party shall notify the other Party of any proceeding of which it is aware which may result in disclosure of the terms of this Agreement (other than as permitted hereunder) and use reasonable efforts to prevent or limit the disclosure.

17.9 Relief. The Parties shall be entitled to all remedies available at law or in equity to enforce or seek relief in connection with any obligations under this Agreement.

17.10 No Third Party Beneficiaries. There are no third party beneficiaries to this Agreement.

17.11 Amendment. This Agreement may be amended, supplemented or modified only by a written instrument duly executed by or on behalf of Gatherer and Producer.

17.12 Entire Agreement. This Agreement contains all of the agreements of the Parties hereto with respect to any matter covered or mentioned in this Agreement, and no prior agreement, understanding or representation pertaining to any such matter shall be effective for any purpose.

17.13 [***].

17.14 Formation of Additional Entities. If Gatherer elects to assign some or all of its assets related to this Agreement into two (2) newly formed entities, solely for the purpose of assigning all of the assets associated with the Charlson Pipelines into one entity and all of the assets associated with the Watford Pipelines into another entity, Producer shall fully cooperate and execute any additional documentation reasonably requested by Gatherer for such purpose, provided, however, that Gatherer shall pay for all such expenses related to Producer’s actual third party costs incurred as a result of Producer’s cooperation with the foregoing assignments, and provided, however, that the effect of such assignments shall have an economic neutral effect on Producer, and the newly created Gatherer entities shall execute this Agreement.

[Signature Page on Following Page]

IN WITNESS WHEREOF, the Parties have executed this Agreement as of the date first above written.

PRODUCER:

XTO Energy Inc.,

a Delaware corporation

By: /s/ Terry Schultz

Name: Terry Schultz

Title: Sr. Vice President - Marketing

GATHERER:

Nuverra Rocky Mountain Pipeline, LLC,

a Delaware limited liability company

By: /s/ Mark D. Johnsrud

Name: Mark D. Johnsrud

Title: Chairman and CEO

List of Exhibits



Exhibits
Exhibit A Exhibit B Exhibit C Exhibit D Exhibit E Exhibit F Exhibit G	Dedicated Properties Definitions and Interpretation Addresses for Notice Produced Water Quality Specifications Insurance Sample Frac Schedule Dedicated Area

Exhibit A

DEDICATED PROPERTIES

[***]

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Exhibit B

DEFINITIONS AND INTERPRETATION

1. Rules of Construction. In construing this Agreement: no consideration shall be given to the fact or presumption that one Party had a greater or lesser hand in drafting this Agreement; examples shall not be construed to limit, expressly or by implication, the matter they illustrate; the word “includes” and its syntactical variants mean “includes, but is not limited to” and corresponding syntactical variant expressions; a defined term has its defined meaning throughout this Agreement, regardless of whether it appears before or after the place in this Agreement where it is defined; unless otherwise specified, the plural shall be deemed to include the singular, and vice versa; each gender shall be deemed to include the other genders and neuter; and, unless otherwise indicated, references to “volumes” or “quantities” shall be deemed to refer to volumes or quantities measured in Barrels unless otherwise indicated.

2. Headings. The headings and subheadings contained in this Agreement are used solely for convenience and do not constitute a part of this Agreement between the Parties and shall not be used to construe or interpret the provisions of this Agreement.

3. Defined Terms. The following capitalized terms used in this Agreement and the attached exhibits shall have the meanings set forth below, unless otherwise indicated.

“Affiliate” means, as to any Person, any other Person that directly or indirectly through one or more intermediaries Controls, is Controlled by or is under common Control with such Person, whether by contract, voting power or otherwise. For the purposes of this definition, “Control” (and the correlative terms “controlling,” “controlled by” and “under common control with”) shall mean as to any entity the possession, directly or indirectly, through one or more intermediaries, by any Person or group (within the meaning of Article 13(d)(3) under the Securities Exchange Act of 1934, as amended) of the power or authority, through ownership of voting securities, by contract, or otherwise, to control or direct the management and policies of the entity.

“Additional Equipment” has the meaning set forth in Article 3.3(a).

“Agreement” means this Gathering and Disposal Services Agreement (Produced & Fresh Water) and all of the exhibits attached hereto, as amended from time to time, all of which are incorporated herein.

“Applicable Law” means any applicable law, statute, rule, regulation, ordinance, order, or other pronouncement, action or requirement of any Governmental Authority.

“Barrel” means forty-two (42) gallons.

“Business Day” means any day except Saturday, Sunday or Federal Reserve Bank holidays.

“Charlson Fresh Water Pipeline” means the pipeline that transports Fresh Water to the Dedicated Properties in [***].

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“Charlson Pipelines” means the Charlson Produced Water Pipeline and the Charlson Fresh Water Pipeline.

“Charlson Produced Water Pipeline” means the pipeline that transports Produced Water from the Dedicated Properties in [***].

“Connection Request” has the meaning set forth in Article 3.4(a).

“Dedicated Area” shall mean the map depicted on Exhibit G, attached hereto and made a part hereof.

“Dedicated Properties” means all interests of Producer (and its successors and assigns) in the oil, gas and/or mineral leases located on, in or under the properties identified on Exhibit A (as to all depths covered by such leases). “Dedicated Properties” shall also include all renewals or extensions of the leases located on, in or under the properties identified on Exhibit A that are acquired by Producer within six (6) months of the expiration or termination of any such lease.

“Dedication” has the meaning set forth in Article 11.1(a)(i)(A).

“Default Renegotiated Fees” means one or more of the Default Renegotiated Fresh Water Delivery Fee, the Default Renegotiated Produced Water Disposal Fee and the Default Renegotiated Produced Water Gathering Fee.

“Default Renegotiated Fresh Water Delivery Fee” has the meaning set forth in Article 4.6(c).

“Default Renegotiated Produced Water Disposal Fee” has the meaning set forth in Article 4.6(b).

“Default Renegotiated Produced Water Gathering Fee” has the meaning set forth in Article 4.6(a).

“Effective Date” has the meaning set forth in the Preamble.

“Extended Interruption Period” has the meaning set forth in Article 2.1(a).

“Fees” has the meaning set forth in Article 4.1.

“Firm Capacity Amount of Fresh Water” has the meaning set forth in Article 3.1.

“Firm Capacity Amount of Produced Water” has the meaning set forth in Article 3.1.

“[***]” has the meaning set forth in Article [***].

“Force Majeure Event” has the meaning set forth in Article 13.2.

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“Frac” has the meaning set forth in Article 12.1.

“Frac Schedule” has the meaning set forth in Article 12.1.

“Fresh Water” means fresh water acceptable and agreed to in writing signed by both Parties.

“[***]” has the meaning set forth in Article [***].

“Fresh Water Delivery Fee” has the meaning set forth in Article 4.4.

“Fresh Water Fee” has the meaning set forth in Article 4.5.

“Fresh Water Receipt Point” means the flange at the edge of the relevant drilling and spacing unit for the delivery by Gatherer and the receipt by Producer of Fresh Water.

“Gatherer” has the meaning set forth in the Preamble.

“Gathering System and Disposal Facilities” means the Produced Water gathering system and disposal facilities and the Fresh Water delivery system to be constructed, owned and operated by Gatherer and located in McKenzie County, North Dakota, and any modifications, alterations, replacements, extensions or expansions made to such system or facilities by Gatherer from time-to-time.

“Governmental Authority” means any court, government (federal, state, local, or foreign), department, political subdivision, commission, board, bureau, agency, official, or other regulatory, administrative or governmental authority.

“In-Service Date” has the meaning set forth in Article 1.1.

“Interruptible Basis” means a level of service committed or made available by Gatherer for gathering and transportation on the Gathering System and Disposal Facilities that has less priority than any other third party producers with firm capacity on the Gathering System and Disposal Facilities; provided, however, Producer shall have higher priority than any other third party producers with interruptible capacity on the Gathering System and Disposal Facilities.

“Interruption Period” has the meaning set forth in Article 2.1(a).

“Knowledge” means the present knowledge of an employee director or vice president having responsibility over the subject matter in question.

“Maintenance Suspension Event” has the meaning set forth in Article 13.5 .

“Maintenance Suspension Event Notice” has the meaning set forth in Article 13.5.

“NDIC” means North Dakota Industrial Commission.

“Notice” has the meaning as set forth in Article 17.2.

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“Outside Connection Request” has the meaning set forth in Article 3.4(b).

“Party” or “Parties” has the meaning set forth in the Preamble.

“Person” means any individual, corporation, partnership, joint venture, limited liability company, association (whether incorporated or unincorporated), joint-stock company, trust, Governmental Authority, unincorporated organization or other entity.

“Pipeline Extension” has the meaning set forth in Article 3.4(a).

“Pipelines” means both the Charlson Pipelines and the Watford Pipelines.

“Primary Term” has the meaning set forth in Article 1.1.

“Prime Rate” has the meaning set forth in Article 5.5.

“Produced Water” means all saltwater and other fluids produced from a wellbore that are attributable to the Dedicated Properties and that meet the Produced Water quality specifications listed on Exhibit D, attached hereto and made a part hereof.

“Produced Water Disposal Fee” has the meaning set forth in Article 4.3.

“[***]” has the meaning set forth in Article [***].

“Produced Water Gathering Fee” has the meaning set forth in has the meaning set forth in Article 4.2.

“Produced Water Receipt Point” means the flange at the edge of the relevant drilling and spacing unit for the delivery by Producer and the receipt by Gatherer of Produced Water.

“Producer” has the meaning set forth in the Preamble.

“Producer’s Reservations” means the rights reserved by producer pursuant to Article 11.1(b).

“Producer Well” means any oil and gas well, whether now existing or drilled hereafter, (a) for which Producer (i) has been, or is hereafter, designated as the operator under the applicable operating agreement or other similar contract for such well or (ii) has submitted, or in the future submits, a filing or notice with the applicable Governmental Authority having jurisdiction over such well designating Producer as operator of such well and (b) is drilled on lands covered by any Dedicated Property, and “Producer Well” shall include the existing wells on any Dedicated Property.

“Receipt Points” means Fresh Water Receipt Points and/or Produced Water Receipt Points, as applicable.

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“Services” shall mean those activities to be provided by Gatherer pursuant to Article 2.1(a) and Article 2.1(b).

“Special Damages” has the meaning set forth in Article 9.3.

“[***]” has the meaning set forth in Article [***].

“Watford Fresh Water Pipeline” means the pipeline that transports Fresh Water to the Dedicated Properties in [***].

“Watford Pipelines” means the Watford Produced Water Pipeline and the Watford Fresh Water Pipeline.

“Watford Produced Water Pipeline” means the pipeline that transports Produced Water from the Dedicated Properties in [***].

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Exhibit C

ADDRESSES FOR NOTICE

Nuverra Environmental Solutions, Inc.

Watford City Office

3711 4th Ave. NE,

Watford City, ND 58854

Attention: John Rivers

John.rivers@nuverra.com

269-266-2631

With a Copy to:

Nuverra Environmental Solutions, Inc.

14624 N. Scottsdale Road, Suite 300

Scottsdale, Arizona 85254

Attn: Scottsdale Legal

XTO Energy, Inc.

9127 South Jamaica Street

Engelwood, CO 80112

Attention: Steve Johnson

stevenjohnson@xtoenergy.com

303.397.3622

“Invoice Delivery” address:

XTO Energy, Inc.

___________________________

Attention: ___________________

Exhibit D

PRODUCED WATER QUALITY SPECIFICATIONS


•	Produced Water shall not contain any solids in excess of [***], including frac sand


•	Maximum oil content of [*] or a minimum Produced Water content of [*]


•	No hazardous chemicals over [***], excluding hydrate inhibition or remediation and scale remediation


•	All Produced Water shall consist solely of saltwater and associated oil and gas waste and shall be free of hazardous wastes and other substances that may not, in accordance with Applicable Law, be transported or disposed of in the Gathering System and Disposal Facilities


•	Temperature not to exceed [***] at any Produced Water Receipt Point


•	Produced Water Receipt Point pressure shall not exceed [***]

Exhibit E

INSURANCE

Workers’ Compensation Insurance and Employer’s Liability Insurance. Workers’ Compensation insurance in accordance with the laws of the State of North Dakota and Employer’s Liability insurance with the minimum limits of $1,000,000.

Comprehensive General Liability Insurance. Comprehensive (or Commercial) General Liability, including coverage for “Action Over” claims, Products and Completed Operations, and other contractual obligations as respects this contract and proper coverage for all other obligations assumed in this Agreement. The minimum limit shall be $2,500,000 combined single limit per occurrence for Bodily Injury and Property Damage and $5,000,000 in the aggregate. If the policy has an annual aggregate limit, the aggregate will be on a “per project” or “per location” basis; or the Parties shall carry Excess Liability (or Umbrella) coverage that will “drop down” over each claim if such limit becomes exhausted. The policy shall cover “In Rem” if operations are over water.

Automobile Liability Insurance. Automobile Liability insurance covering owned, non-owned and hired automotive equipment with minimum limits of $1,000,000 combined single limit for Bodily Injury and Property Damage.

Excess Liability Coverage. The Parties shall carry Excess (or Umbrella) Liability coverage of $25,000,000 in excess of the preceding liability policies limits carried by the Parties, and the limit of such coverage shall be reported on the required Certificate of Insurance.

Exhibit F

SAMPLE FRAC SCHEDULE

[Not attached.]

Exhibit G

DEDICATED AREA

[Not attached.]

[***]

Exhibit 21.1

Schedule of Significant Subsidiaries




Name of Organization		State/Jurisdiction of Incorporation
Heckmann Water Resources Corporation		Texas
Heckmann Water Resources (CVR), Inc.		Texas
Heckmann Environmental Services, Inc.		Delaware
Thermo Fluids Inc.		Delaware
Badlands Power Fuels, LLC		Delaware
Badlands Power Fuels, LLC		North Dakota
Landtech Enterprises, LLC		North Dakota
Badlands Leasing, LLC		North Dakota
Ideal Oilfield Disposal, LLC		North Dakota

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

The Board of Directors

Nuverra Environmental Solutions, Inc.:

We consent to the incorporation by reference in the registration statement (Nos. 333-159086, 333-182068, and 333-190678) on Form S-8, the registration statements (Nos. 333-158266 and 333-179518) on Form S-3, and the registration statements (Nos. 333-177343, 333-182400, and 333-188810) on Form S-4 of Nuverra Environmental Solutions, Inc. of our reports dated March 16, 2015, with respect to the consolidated balance sheets of Nuverra Environmental Solutions, Inc. and subsidiaries as of December 31, 2014 and 2013, and the related consolidated statements of operations, changes in equity, and cash flows for each of the years in the three-year period ended December 31, 2014, and the effectiveness of internal control over financial reporting as of December 31, 2014, which reports appear in the December 31, 2014 Annual Report on Form 10-K of Nuverra Environmental Solutions, Inc.

/s/ KPMG LLP

Phoenix, Arizona

March 16, 2015

Exhibit 31.1

Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350,

As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

I, Mark D. Johnsrud, certify that:


1.	I have reviewed this report on Form 10-K of Nuverra Environmental Solutions, Inc.


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report.


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report.


4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;


c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.


5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):


a)	All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and


b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 16, 2015



By:	/s/ Mark D. Johnsrud
Name:	Mark D. Johnsrud
Title:	President and Chief Executive Officer

Exhibit 31.2

Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350,

As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

I, Gregory J. Heinlein, certify that:


1.	I have reviewed this report on Form 10-K of Nuverra Environmental Solutions, Inc.


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report.


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report.


4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;


c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.


5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):


a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and


b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 16, 2015



By:	/s/ Gregory J. Heinlein
Name:	Gregory J. Heinlein
Title:	Executive Vice President and Chief Financial Officer (Principal Financial Officer)

Exhibit 32.1

Certification of CEO and CFO Pursuant to 18 U.S.C. Section 1350,

As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the report of Nuverra Environmental Solutions, Inc. (the “Company”) on Form 10-K for the period ended December 31, 2014, as filed with the Securities and Exchange Commission on the date hereof, we, the undersigned, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our knowledge, that:


(1)	The report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 as amended; and


(2)	The information contained in the report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: March 16, 2015



By:	/s/ Mark D. Johnsrud	By:	/s/ Gregory J. Heinlein
Name:	Mark D. Johnsrud	Name:	Gregory J. Heinlein
Title:	President and Chief Executive Officer (Principal Executive Officer)	Title:	Executive Vice President and Chief Financial Officer (Principal Financial Officer)

This certification accompanies this report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not be deemed filed by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended or otherwise subject to liability pursuant to that section. The certification shall not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act, except to the extent that the Company specifically incorporates it by reference.

A signed original of this written statement required by Section 906 has been provided to the Secretary of the Company and will be retained by the Office of General Counsel of the Company and furnished to the Securities and Exchange Commission or its staff upon request.

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