UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

Form 10-K
 
(MARK ONE)

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 No. 001-36260

CYPRESS ENERGY PARTNERS, L.P.
(Exact name of registrant as specified in its charter)

Delaware
 
61-1721523
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
     
5727 South Lewis Avenue, Suite 500
 
Tulsa, Oklahoma 
74105
(Address of principal executive offices)
 
(Zip Code)

(Registrant’s telephone number, including area code):  (918) 748-3900

Securities Registered Pursuant to Section 12(b) of the Act:

Common Units Representing Limited Partner Interests
 
New York Stock Exchange
(Title of each class)
 
(Name of each exchange on which registered)

Securities Registered Pursuant to Section 12(g) of the Act:  N o n e

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

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     No

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the 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
Non-accelerated filer ý
Smaller  reporting company 
       
(Do not check if a smaller reporting company)

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

The aggregate market value of the registrant’s Common Units Representing Limited Partner Interests held by non-affiliates computed by reference to the price at which the limited partner units were last sold as of June 30, 2014 was $102,594,375.

As of March 25, 2015, the registrant had 5,913,000 common units and 5,913,000 subordinated units outstanding.
 

 
DOCUMENTS  INCORPORATED  BY  REFERENCE:    N o n e.
 


 Table of Contents

   
Page
PART I
   
Item 1.
3
Item 1A.
15
Item 1B.
40
Item 2.
41
Item 3.
41
Item 4.
41
     
PART II
   
Item 5.
42
Item 6.
44
Item 7.
49
Item 7A.
66
Item 8.
67
Item 9.
102
Item 9A.
102
Item 9B.
102
     
PART III
   
Item 10.
103
Item 11.
108
Item 12.
113
Item 13.
115
Item 14.
122
     
PART IV
 
Item 15.
123
 
125
 

GLOSSARY OF TERMS
 
The following includes a description of the meanings of some of the terms used in this Annual Report on Form 10-K.

“Dig site
The location where pipeline maintenance occurs by excavating the ground above the pipeline.
   
Flowback water
The fluid that returns to the surface during and for the weeks following the hydraulic fracturing process.
   
Gun barrel
A settling tank used for treating oil where oil and brine are separated only by gravity segregation forces.
   
Hydraulic fracturing
The process of pumping fluids, mixed with granular proppant, into a geological formation at pressures sufficient to create fractures in the hydrocarbon-bearing rock.
   
In-line inspection
An inspection technique used to assess the integrity of natural gas transmission pipelines from inside of the pipe.
   
“IPO”
Our initial public offering of common units representing limited partner interests in us.
   
Injection intervals
The part of the injection zone in which the well is screened or in which the waste is otherwise directly emplaced.
   
NGLs
Natural gas liquids. The combination of ethane, propane, butane, isobutene and natural gasolines that, when removed from natural gas, become liquid under various levels of higher pressure and lower temperature.
   
OPEC
The Organization of Petroleum Exporting Countries.
   
Pig tracking
The locating, mapping and monitoring of the in-line inspection pig.
   
Produced water
Naturally occurring water found in hydrocarbon-bearing formations that flows to the surface along with oil and natural gas.
   
Proppant
Sized particles mixed with fracturing fluid to hold fractures open after a hydraulic fracturing treatment.
   
Residual oil
Oil separated and recovered during the saltwater treatment process.
   
Separation tank
A cylindrical or spherical vessel used to separate oil, gas and water from the total fluid stream produced by a well.
   
Settling tank
A non-circulating storage tank where gravitational segregation forces separate liquids from solids.
   
Staking
The process of marking the location where pipeline maintenance will occur.
   
SWD
Salt water disposal.
 
1

NAMES OF ENTITIES
 
Unless the context otherwise requires, references in this Annual Report on Form 10-K to “Cypress Energy Partners, L.P.,” “our partnership,” “we,” “our,” “us,” or like terms, refer to Cypress Energy Partners, L.P. and its subsidiaries.

References to:

General Partner” refers to Cypress Energy Partners GP, LLC, a subsidiary of Holdings II;

Holdings” refers to Cypress Energy Holdings, LLC, the owner of Holdings II;

Holdings II” refers to Cypress Energy Holdings II, LLC, the owner of 671,250 common units representing 11.4% of our outstanding common units and 4,939,299 subordinated units representing 83.5% of our subordinated units;

CEM LLC” refers to Cypress Energy Management, LLC, a wholly owned subsidiary of the General Partner;

CEM-BO” refers to Cypress Energy Management – Bakken Operations, LLC, a 51% owned subsidiary of CEM LLC;

CEM TIR” refers to Cypress Energy Management - TIR, LLC, a wholly owned subsidiary of the General Partner;

CEP LLC” refers to Cypress Energy Partners, LLC, which became our wholly owned subsidiary at the closing of our initial public offering (“IPO”);

CEP-TIR” refers to Cypress Energy Partners – TIR, LLC, an indirect subsidiary of Holdings, and an owner of 673,400 common units representing 11.4% of our outstanding common units, 673,400 subordinated units representing 11.4% of our subordinated units and an owner of a 36.2% interest in the TIR Entities prior to the sale of its interests to the Partnership effective February 1, 2015;

CES LLC” refers to Cypress Energy Services, LLC, our 51.0% indirectly owned subsidiary that performs management services for 10 salt water disposal (“SWD”) facilities in North Dakota – seven of which are owned by CEP LLC.  SBG Energy Services, LLC (“SBG Energy”) owns the remaining interests and CEP LLC has the right to acquire such interests;

CF Inspection” refers to CF Inspection Management, LLC, owned 49% by TIR-PUC, controlled and consolidated by TIR-PUC;

Partnership” refers to the registrant, Cypress Energy Partners, L.P.;

·
“PI&IS” refers to our Pipeline Inspection and Integrity Services business segment;

Predecessor” refers to the accounting predecessor of CEP LLC, which is comprised of the seven North Dakota limited liability companies we acquired from SBG Energy Services, LLC;

TIR LLC” refers to Tulsa Inspection Resources, LLC;

TIR-Canada” refers to Tulsa Inspection Resources – Canada ULC, a Canadian subsidiary of TIR Holdings;

TIR Entities” refer collectively to TIR LLC and its subsidiary, TIR Holdings and its subsidiaries and TIR-NDE, all of which were 50.1% owned by CEP LLC from our IPO until February 1, 2015 at which time CEP LLC acquired the remaining interests from affiliates of Holdings and now own 100%;

TIR-Foley” refers to Foley Inspection Services ULC, a Canadian subsidiary of TIR Holdings;

TIR Holdings” refers to Tulsa Inspection Resources Holdings, LLC;

TIR-NDE” refers to Tulsa Inspection Resources – Nondestructive Examination, LLC;

TIR-PUC” refers to Tulsa Inspection Resources – PUC, LLC, a corporate subsidiary of TIR LLC; and

“W&ES” refers to our Water and Environmental Services business segment.
 
2

CAUTIONARY REMARKS REGARDING FORWARD LOOKING STATEMENTS

The information discussed in this Annual Report on Form 10-K includes “forward-looking statements.” These forward-looking statements are identified by their use of terms and phrases such as “may,” “expect,” “estimate,” “project,” “plan,” “believe,” “intend,” “achievable,” “anticipate,” “continue,” “potential,” “should,” “could,” and similar terms and phrases.  Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties and we can give no assurance that such expectations or assumptions will be achieved.  Important factors that could cause actual results to differ materially from those in the forward-looking statements are described under “Item 1A - Risk Factors” and “Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations” in this Annual Report.  All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements in this paragraph and elsewhere in this Annual Report on Form 10-K and speak only as of the date of this Annual Report on Form 10-K.  Other than as required under the securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

 PART I

ITEM 1. BUSINESS

Overview
 
The Partnership is a Delaware limited partnership formed on September 19, 2013 to become a diversified Partnership serving energy companies throughout North America.  We currently provide independent pipeline inspection and integrity services to producers and pipeline companies and water and environmental services with SWD facilities to U.S. onshore oil and natural gas producers and trucking companies.  On January 21, 2014, we completed the IPO of our limited partner common units.  As part of the transaction, affiliates of Holdings, conveyed an aggregate 50.1% interest in the TIR Entities in exchange for an aggregate 15.7% ownership in the Partnership.  Affiliates of Holdings held the remaining 49.9% interest in the TIR Entities that was recently acquired by the Partnership effective February 1, 2015.  As a result, the Partnership now owns 100% of the TIR Entities.

Our business is currently organized into two reportable segments:  (1) Water and Environmental Services (“W&ES”) and (2) Pipeline Inspection and Integrity Services (“PI&IS”).  We also have a number of other lines of business in our IRS private letter ruling (“PLR”) that would allow us to further diversify our business activities and lines of business serving the energy industry.  W&ES provides SWD services to oil and natural gas producers and trucking companies and consists of the operations of CEP LLC, which owns and operates eight commercial SWD facilities in the Bakken Shale region of the Williston Basin in North Dakota and two in the Permian Basin in Texas.  We generate revenue by treating produced water and flowback water and injecting the water into our SWD facilities.  Results are driven primarily by the volume of water injected into our SWD facilities and the fees charged related to these services.  These fees are charged on a per barrel basis and vary based on the quantity and type of saltwater disposed, competitive dynamics and operating costs.  Our SWD facilities currently utilize specialized equipment, full-time attendants, and remote monitoring to minimize downtime and increase efficiency for peak utilization and are located in close proximity to existing producing wells and expected future drilling sites, making our SWD facilities economically attractive to our current and future customers.  These facilities also contain oil skimming processes that remove any remaining oil from flowback and produced water that has been delivered to the sites.  We then generate revenue by selling the residual oil recovered from the water treatment process.  In addition to the ten SWD facilities owned by CEP LLC, our consolidated 51% subsidiary, CES LLC, provides management and staffing services for three additional SWD facilities in the Bakken Shale region, pursuant to management agreements.  CES LLC also owns a 25% member interest in one of the managed wells.   The W&ES segment is directly tied to oil and gas activity and is impacted by lower commodity prices and newly completed oil and gas wells.
 
PI&IS is comprised of the operations of the TIR Entities.  Through this segment, we provide independent inspection and integrity services to various energy, public utility and pipeline companies in both the United States and Canada.  Inspectors in this segment perform a variety of inspection and integrity services on midstream pipelines, midstream assets and infrastructure, gathering systems and distribution systems, including data gathering and supervision of third-party construction, inspection, and maintenance and repair projects.  Results in this segment are driven primarily by the number and type of inspectors performing services for our customers and the fees they charge for those services, which depend on the nature and duration of the project.
 

3

Our Relationship with Cypress Energy Holdings, LLC
 
All of the equity interests in our general partner are owned by Holdings, which is owned by Charles C. Stephenson, Jr., various family trusts, a company controlled by our Chairman and Chief Executive Officer, Peter C. Boylan III and Henry Cornell.  Holdings’ owners bring substantial industry relationships and specialized, value-creation capabilities that we believe will continue to benefit us.  Mr. Stephenson has over 50 years of experience as a leader in the oil and natural gas industry.  He was the founder, Chairman and Chief Executive Officer of Vintage Petroleum prior to its sale to Occidental Petroleum in 2006 and is currently the Chairman of Premier Natural Resources, a private oil and natural gas exploration and production company that he co-founded.  Mr. Boylan has extensive executive management experience with public and private companies and also has extensive public company directorship experience.  As the owners of our general partner and the direct or indirect owners of approximately 58.8% of our outstanding limited partner interests, Holdings and its affiliates have a strong incentive to support and promote the on-going successful execution of our business plan.
 
Business Strategies
 
Our principal business objective is to build a diversified Partnership serving energy customers that will allow us, over time, to incrementally increase the quarterly cash distributions that we pay to our unitholders. We expect to achieve this objective through the following business strategies:

Capitalize on compelling industry fundamentals.

W&ES.  We believe that the on-going water and environmental services market will continue to offer long-term growth fundamentals and we intend to maintain our position as a high quality operator of SWD facilities despite the recent downturn in the oil and gas industry as a whole.  We plan to focus on pipeline opportunities with E&P companies that will secure water for our SWD facilities.  Regulations continue to increase and we have proven to our customers that we are a trusted and dependable service provider.  Increasingly, we are seeing E&P companies have their central procurement and Environment, Health and Safety ("EHS") groups inspect our SWD facilities.   This trend should benefit our Partnership.  Although the oil and gas industry can be cyclical in nature (as is evidenced by this current downturn), our current business strategy is such that 75% - 80% of our treated water is derived from existing wells. Although new drilling activity is currently curtailed and commodity oil prices have declined significantly, our focus will remain on the produced water that is generated for the life of an oil and gas well.  With curtailed drilling activity and depressed oil prices, a portion of W&ES will suffer declines in volumes and pricing until the market rebounds leading to additional drilling and completions that, in turn, generate new produced water for the life of those newly completed oil and gas wells.  We intend to capitalize on the continued demand for removal, treatment, storage and disposal of flowback and produced water by positioning ourselves as a trusted, dependable provider of safe, high-quality water and environmental services to our energy customers.
 
PI&IS.  We intend to continue to position ourselves as a trusted provider of high quality inspection and integrity services, as we believe the pipeline inspection and integrity services market offers attractive long-term growth fundamentals.  Over the last few years, new laws have been enacted in the U.S. that, in the future, will require operators to undertake more frequent and more extensive inspections of their pipeline assets.  These requirements are independent and not tied to the current state of the oil and gas industry as a whole.  Additionally, a significant portion of the pipeline infrastructure in North America was installed decades ago and is therefore more susceptible to failure and requires more frequent inspections.  We believe that increasingly stringent U.S. federal and state laws and regulations and aging pipeline infrastructures will result in increased need for inspection and integrity services and higher demand for independent, third-party inspectors capable of navigating these complicated requirements. The current energy downturn has impacted some of our customers.   However, most of our clients are investment–grade, well-capitalized companies that have long lead time projects requiring our services in addition to the ongoing maintenance and integrity work on their aging pipelines.    Our business is not immune to the downturn, however, we believe that we can continue to grow organically by acquiring new customers and additional work from existing customers.  We continue to grow our business development team to pursue these opportunities.
 
Optimize existing SWD assets.  The average age of our SWD facilities was 2.3 years at the end of 2014.  We estimate that we utilized approximately 45% of the aggregate estimated capacity of these facilities for the year ended December 31, 2014.  Our permitted capacity is much higher than our estimated capacity.  We are seeking to increase the utilization of our existing SWD facilities by attracting new volumes from existing customers and by developing new customer relationships including pipelines.  In 2012, only one pipeline was directly connected to our SWD facilities.  Today we have six pipelines connected to our facilities. Because many of the costs of constructing and operating an SWD facility are either upfront capital costs or fixed costs, we expect that increased utilization of our existing SWD facilities over time will lead to increased gross margin and operating cash flow in W&ES. The current downturn in the energy industry will place pressure on both the volumes we process and the prices we are able to charge.
 
Increase the number of pipelines connected to our SWD facilities.  As more oil and natural gas producers focus on improving operational safety and reducing liability, carbon footprint, road damage and the total transportation cost associated with trucking saltwater, we anticipate that they will increasingly prefer to utilize pipeline systems to transport their saltwater directly to SWD facilities.  We intend to purchase or construct, whether alone or in joint ventures, saltwater pipeline systems that connect producers to our SWD facilities or newly developed SWD facilities.  We continue to focus on increasing pipeline water delivered to our facilities. Our 2014 pipeline water volumes increased 68% from 2013.  As a percentage of total water volume, pipeline water was 10% in 2013 and was 17% of total water volume in 2014.  We will continue to focus on these pipeline opportunities.
 
4

 
Leverage customer relationships in both of our business segments.  We intend to pursue new strategic development opportunities with oil and natural gas producing customers that increase the utilization of our assets and lead to cross-selling opportunities between our two business segments.  Many customers of W&ES also own gathering systems, storage facilities, gas plants, compression stations, and other pipeline assets to which we can offer pipeline inspection and integrity services.  In North Dakota, new inspection rules have been proposed in the legislature that may benefit PI&IS.  In addition, we intend to enhance our relationships with our customers in PI&IS by broadening the services we provide, including expanding our ultrasonic nondestructive examination services and potentially offering hydro testing and nitrogen services.  By cross-selling our service offerings and adding complementary service offerings, we believe that we can further integrate into our customers’ operations and increase our profitability and distributable cash flow.
 
Pursue strategic, accretive acquisitions.  We intend to pursue accretive acquisitions that will complement both W&ES and PI&IS.  Both of our business segments operate in industries that are fragmented, giving us the opportunity to make strategic and accretive acquisitions.  We exercised important discipline in 2014 and avoided overpaying for acquisitions.   We remain optimistic that some good opportunities will present themselves in the 2nd half of 2015.  We plan to expand W&ES by seeking water and solid acquisition opportunities in existing and additional high-growth resource plays throughout the U.S. that will diversify our customer base with a particular focus on pipeline opportunities directly with E&P customers, like our December 2014 SWD facility acquisition.  In addition, provided certain opportunities fit with our strategic plan of expanding our business, we intend to grow PI&IS by acquiring other strategic pipeline service companies that will allow us to broaden the suite of services we offer our existing customers.  In addition, we expanded our PI&IS ownership in February 2015 by acquiring the remaining 49.9% of the TIR Entities not previously owned by the Partnership.
 
Our Business Segments
 
Our business is operated in two segments:  (1) Water and Environmental Services (“W&ES”) and (2) Pipeline Inspection and Integrity Services (“PI&IS”). Our IRS private letter ruling (“PLR”) also includes other lines of business.  Our long term goal continues to be focused on diversifying the Partnership into other attractive lines of business including but not limited to traditional midstream activities, production chemicals, remote monitoring of energy infrastructure, etc. in addition to the continued build out of our segments.
 
W&ES Segment

Overview.  Through W&ES, which specializes in water and environmental services, we own and operate ten SWD facilities, eight of which are in the Bakken Shale region of the Williston Basin in North Dakota and two of which are in the Permian Basin in west Texas.  One of the North Dakota facilities was acquired effective December 1, 2014 and is connected to a pipeline with a large public E&P company’s production.  In addition to owning and operating the ten SWD facilities, we manage three other SWD facilities that we also built for third parties in the Bakken Shale region through CES LLC, one of which is 25% owned.  W&ES is comprised of the operations of CEP LLC and its Predecessor.
 
Operations.  W&ES currently generates revenue by providing the following services:

· Flowback water management.  We dispose of flowback water produced from hydraulic fracturing operations during the completion of oil and natural gas wells.  Fracturing fluids, including a significant amount of water, are originally injected into the well during the completion process and are partially recovered as flowback water.  When it is removed, this flowback water contains salt, chemicals and residual oil.  The drilling and completion phase typically occurs during the first 30 to 90 days following commencement of production of the life of a well.  The oil and natural gas producer typically either transports the flowback water to one of our SWD facilities by truck or contracts with a trucking company for transport.  Once the water is received at the SWD facility, we treat the water through a combination of separation tanks, gun barrels and chemical processes, store as necessary prior to injection and then inject into the SWD well at depths of at least 4,000 feet.  Like produced water, we assess the composition of flowback water in our facilities so that we can maximize oil separation and treat the water to maximize the life of our equipment and the wellbore.  We believe our approach to scientifically and methodically filtering and treating the flowback water prior to injecting it into our wells helps extend the life of our wells and furthers our reputation as an environmentally conscious service provider.
 
5

 
Produced water management. We dispose of naturally occurring water that is extracted during the oil and natural gas production process.  This produced water is generated during the entire lifecycle of each oil and natural gas well.  While the level of hydrocarbon production declines over the life of a well, the amount of saltwater produced may decline more slowly or in some cases, may even increase over time.  The oil and natural gas producer separates the produced water from the production stream and either transports it to one of our SWD facilities by truck or pipeline or contracts with a trucking company to transport it to one of our SWD facilities.  Once we receive the water at one of our SWD facilities, we filter and treat the water and then inject it into the SWD well at depths of at least 4,000 feet.  We also maintain the ability to store saltwater pending injection.  All of our existing facilities were constructed using completion techniques consistent with current industry practices.  We periodically sample, test and assess produced water to determine its chemistry so that we can properly treat the water with the appropriate chemicals that maximize oil separation and the life of the well.
 
Byproduct sales. Before we inject flowback and/or produced water into an SWD well, we separate the residual oil from the saltwater stream.  We then store the residual oil in our tanks and sell it to third-parties.
 
Management of existing SWD facilities.  In addition to the SWD facilities we own or lease, we own a 51.0% interest in CES LLC, a management and development company that manages three additional SWD facilities in North Dakota. Our responsibilities in managing an SWD facility typically include operations, billing, collections, insurance, maintenance, repairs and, in some cases, sales and marketing.  We are compensated for management of these facilities generally based on the gross revenue of the facilities.
 
The majority of our disposed saltwater volumes are derived from produced water that is generated throughout the life of the oil or natural gas well.  For the years ended December 31, 2014 and 2013, produced water represented approximately 82% and 75%, respectively, of our total barrels of disposed water.  This differentiates us from many competitors that focus on flowback and the associated skim oil revenue.  As a region matures and the predominant activity shifts from drilling and completion of wells to production, our facilities continue to experience demand for ongoing processing of waste produced over the life of the wells.

Each of our SWD facilities are open 365 days per year.  Our locations in North Dakota currently include onsite offices and sleeping quarters for our employees while they are on call.  In Texas, we have an office and housing for management at our Pecos, Texas facility.  We supplement our operations with various automated technologies to improve their efficiency and safety.  We have installed 24-hour digital video monitoring and recording systems at each facility.  These systems allow us to track operations and unloading as well as identifying the identity of customers at our facilities.  We believe that our commitment to operating our facilities with sophisticated technology and automation contributes to our enhanced operating margins and provides our customers with increased safety and regulatory compliance.  In the future, we anticipate that some of our SWD facilities will be run through technological automation with off-site monitoring and control. Our facilities have been inspected and approved by several of our public E&P companies that have stringent approval standards and field audits performed by their EHS groups.

The amount of saltwater disposed in our SWD facilities decreased slightly from 19.7 million barrels for the year ended December 31, 2013 to 19.1 million barrels for the year ended December 31, 2014, a decline of approximately 3% driven primarily by increased competition.   Numerous new facilities opened during 2014 that compete for business with our locations.
 
6

As of December 31, 2014, we had an aggregate of approximately 115,000 barrels of maximum daily disposal capacity in the following SWD facilities, all of which were built using completion techniques consistent with current industry practices and utilizing well depths of at least 5,000 feet with injection intervals beginning at least 4,000 feet beneath the surface.  Our permitted capacity is much higher.
 
Location
 
County
 
In-service Date
 
Leased or Owned (3)
Tioga, ND
 
Williams
 
June 2011
 
Owned
Manning, ND
 
Dunn
 
Dec. 2011
 
Owned
Grassy Butte, ND
 
McKenzie
 
May 2012
 
Leased
New Town, ND (1)
 
Mountrail
 
June 2012
 
Leased
Pecos, TX (1)
 
Reeves
 
July 2012
 
Owned
Williston, ND
 
Williams
 
Aug. 2012
 
Owned
Stanley, ND
 
Mountrail
 
Sept. 2012
 
Owned
Orla, TX (1)
 
Reeves
 
Sept. 2012
 
Owned
Belfield, ND
 
Billings
 
Oct. 2012
 
Leased
Watford City, ND (2)
 
McKenzie
 
May 2013
 
Leased
Arnegard, ND (1)
 
McKenzie
 
August 2014
 
Leased
 
  (1) Currently receives piped water.
  (2) We own 51.0% of CES, a management and development company that owns a 25.0% non-controlling interest in this SWD facility.
 
(3)
Certain SWD facilities are constructed on land leased under long term arrangements.

In addition to the above properties, we also manage two other SWD facilities in the Bakken Shale region.
 
PI&IS

Overview.  We believe that PI&IS is a leading provider of independent inspection and integrity services to the pipeline industry.  We provide services for pipelines, gathering systems, local distribution systems, equipment and facilities to our well established customer base.  We provide inspection and integrity services to oil and natural gas producers, public utility companies and other pipeline operators that are required by law to inspect their gathering systems, storage facilities, infrastructure, distribution systems and pipelines.  Our approximately 85 pipeline inspection and integrity customers include oil and natural gas producers, pipeline owners and operators and public utility companies throughout North America.  For the year ended December 31, 2014 and for the period from June 26, 2013 through December 31, 2013, our Canadian operations generated $0.6 and $0.1 million, respectively, of the operating income attributable to PI&IS, representing less than 5% of the total PI&IS operating income in both years.
 
PI&IS offers independent inspection services for the following facilities and equipment:
 
 
·
Transmission pipelines (oil, gas and liquids);

 
·
Oil and natural gas gathering systems;

 
·
Pump and compressor stations;

 
·
Storage facilities and terminals; and
 
 
·
Gas distribution systems.
 
Operations. Oil and natural gas producers, public utility companies and other pipeline operators are required by federal and state law and regulation to inspect their pipelines and gathering systems on a regular basis in order to protect the environment and ensure the public safety.
 
7

 
At the beginning of an engagement, our personnel meet with the customer to determine the scope of the project and related staffing needs.  We then develop a customized, detailed staffing plan utilizing our proprietary database of more than 12,000 professionals.  Our inspectors have significant industry experience and are certified to meet the qualification requirements of both the customer and the Pipeline and Hazardous Materials Safety Administration (“PHMSA”).  As the industry continues to adopt new technology, demand has increased for inspectors with greater technical skills and computer proficiencies.  Our customers require inspectors to undergo specific training prior to performing inspection work on their projects.  We utilize the National Center for Construction Education and Research and Veriforce training curricula to train and evaluate employees, along with other resources.  In addition to assignment-specific training, welding inspectors and coating inspectors also must meet special certification requirements.  During the year ended December 31, 2014 and the period from June 26, 2013 through December 31, 2013, we employed or engaged an average of 1,535 and 1,706 inspectors, respectively, in the U.S. and Canada.  Through CF Inspection, a nationally approved Diverse Business Enterprise (woman owned business), in which we own a 49% interest, we intend to provide services to current and future customers, including public utilities that have incentives to contract with minority and other diverse business enterprises.
 
Our scope of services include the following:

  · Project coordination (construction or maintenance coordination for in-line pipeline inspection projects);

  · Staking services (marking a dig site for surveyed anomalies);

  · Pig tracking services (mapping and tracking of third-party pipeline cleaning and inspection units, called pigs);

  ·
Maintenance inspection (third-party pipeline periodic inspection to comply with PHMSA regulations);

  · Construction inspection (third-party new construction inspection / oversight on behalf of owner);

  · Ultrasonic nondestructive examination services (using high-frequency sound waves to detect pipeline imperfections); and

  · Related data management services.

Principal Customers

W&ES
 
W&ES customers are oil and natural gas exploration and production companies, including majors and independents, trucking companies and third-party purchasers of residual oil operating in the regions that we serve.  In the years ended December 31, 2014 and 2013, we had approximately 206 and 228 customers, respectively, in W&ES.  Our ten largest customers generated approximately 60%, 55% and 73% of W&ES revenue for the years ended December 31, 2014, 2013 and 2012, respectively.  For the year ended December 31, 2014, there was one customer that generated 10% or more of W&ES revenue. There were no customers for the year ended December 31, 2013 that generated 10% or more of W&ES segment revenues.  Two customers each accounted for more than 10% of the segment revenues for the year ended December 31, 2012.
 
PI&IS
 
Customers of PI&IS are principally oil and natural gas producers, pipeline owners and operators and public utility or local distribution companies with infrastructure in North America.  During the years ended December 31, 2014 and 2013, PI&IS had approximately 85 customers.  The five largest customers in this segment generated approximately 65% and 71% of our segment revenue for the year ended December 31, 2014 and for the period from June 26, 2013 through December 31, 2013, respectively.  For the year ended December 31, 2014, we had three customers that individually accounted for more than 10% of segment revenues.  For the period from June 26, 2013 through  December 31, 2013, two pipeline inspection and integrity services customers accounted for more than 10% of our segment revenue.
 
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Competition

W&ES
 
The oilfield waste treatment, water and environmental services, and disposal business is highly competitive with relatively low barriers to entry.  During the last year, competitors opened a number of new locations around our existing facilities based upon anticipated new drilling activity prior to the downturn in November 2014.  Our competition consists primarily of smaller regional companies that utilize a variety of disposal methods and generally serve specific geographical markets.  In addition, we face competition from other large oil field service companies that also own trucking operations and our customers, who may have the option of using internal disposal methods instead of outsourcing to us or another third-party disposal company.  We believe that the principal competitive factors in our businesses include gaining and maintaining customer approval of treatment and SWD facilities, location of facilities in relation to customer activity, reputation, safety record, reliability of services, track record of environmental & regulatory compliance, customer service, insurance and price.
 
PI&IS
 
The pipeline inspection and integrity business is highly competitive.  PI&IS’ competition consists primarily of three types of companies: independent energy inspection firms, engineering and construction firms, and diversified inspection service firms.  Diversified inspection firms may inspect, for example, electric and nuclear facilities in addition to pipelines.  We believe that the principal competitive factors in our business include gaining and maintaining customer approval to service their pipelines and gathering systems, the ability to recruit and retain qualified experienced inspectors with multiple skills and non-destructive examination experience, safety record, insurance, the level of inspector training provided, reputation, dependability of services, customer service and price.
 
Seasonality

W&ES
 
The overall operations and financial performance of our Bakken Shale operations are impacted by seasonality.  The volume of saltwater that we handle in the Bakken Shale region of the Williston Basin in North Dakota tends to be lower in the winter due to heavy snow and cold temperatures, and in the spring due to heavy rains and muddy conditions that may lead to road restrictions and weight limits that can impact business.  The amount of residual oil is also less prevalent and more difficult to separate from the saltwater during the winter months when the outside temperature is lower.  Seasonality is not typically a major factor in the Permian Basin in west Texas, however, this last winter saw more ice and snow than normal leading to reduced activity as reported by a number of large E&P companies operating in the region.
 
PI&IS

Inspection and integrity work varies depending upon the geographic location of our customers.  As we expand our relationships with public utility commissions in California and other locations with moderate climates, the seasonality of our inspection and integrity business is expected to decline.  The third and fourth quarters are historically the most active for our pipeline inspection services as our customers focus on completing projects by year end.  In addition, our Canadian customers use inspection services the most during the fourth and first quarters of the year when the tundra is frozen.  We believe our presence across various regions in the U.S. and our presence in Canada helps mitigate the seasonality of our business.

Regulation of the Industry

Environmental and Occupational Health and Safety Matters

Our operations and the operations of our customers are subject to numerous federal, state and local environmental laws and regulations relating to worker health and safety, the discharge of materials and environmental protection.  These laws and regulations may, among other things, require the acquisition of permits for regulated activities; govern the amounts and types of substances that may be released into the environment in connection with our operations; restrict the way we handle or dispose of wastes; limit or prohibit our or our customers’ activities in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; require investigatory and remedial actions to mitigate pollution conditions caused by our current or former operations; and impose specific standards addressing worker protections.  Numerous governmental agencies issue regulations to implement and enforce these laws, for which compliance is often costly and difficult.  The violation of these laws and regulations may result in the denial or revocation of permits, issuance of corrective action orders, assessment of administrative and civil penalties and even criminal prosecution.
 
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We believe that we are in compliance with current applicable environmental and occupational health and safety laws and regulations.  However, these rules and regulations are constantly evolving at the federal, state, and local level. Further, we do not anticipate that compliance with existing environmental and occupational health and safety laws and regulations will have a material effect on our Consolidated Financial Statements.  While we may occasionally receive citations from environmental regulatory agencies for minor violations, such citations occur in the ordinary course of our business and are not material to our operations.  However, it is possible that substantial costs for compliance or penalties for non-compliance may be incurred in the future.  It is also possible that other developments, such as the adoption of stricter environmental laws, regulations and enforcement policies, could result in additional costs or liabilities that we cannot currently quantify.  Moreover, changes in environmental laws could limit our customers’ businesses or encourage our customers to handle and dispose of oil and natural gas wastes in other ways, which, in either case, could reduce the demand for our services and adversely impact our business.  For example, as a result of regulations issued in March 2014, all waste haulers transporting produced water in North Dakota must possess a valid permit for transporting solid waste from the North Dakota Department of Health to legally transport such waste. Texas already required the same.
 
The following is a summary of the more significant existing environmental and occupational health and safety laws and regulations to which our business operations and the operations of our customers are subject and for which compliance in the future may have a material adverse impact on our financial position, results of operations, or future cash flows.

Hazardous substances and wastes.  Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, solid wastes, hazardous wastes and petroleum hydrocarbons.  These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed.  For instance, the Comprehensive Environmental Response Compensation and Liability Act, or CERCLA and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment.  We may handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.  Under such laws, we could be required to remove previously disposed substances and wastes (including substances disposed of or released by prior owners or operators) or remediate contaminated property (including groundwater contamination, whether from prior owners or operators or other historical activities or spills).  These laws may also require us to conduct natural resource damage assessments and pay penalties for such damages.  It is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants into the environment.  These laws and regulations may also expose us to liability for our acts that were in compliance with applicable laws at the time the acts were performed.

Petroleum hydrocarbons and other substances arising from oil and natural gas-related activities have been disposed of or released on or under many of our sites.  At some of our facilities, we have conducted and continue to conduct monitoring or remediation of known soil and groundwater contamination.  We will continue to perform such monitoring and remediation of known contamination, including any post remediation groundwater monitoring that may be required, until the appropriate regulatory standards have been achieved.  These monitoring and remediation efforts are usually overseen by state environmental regulatory agencies.  We estimate that we will incur costs of less than $0.1 million over the next one to three years in connection with continued monitoring and remediation of known contamination at our facilities.
 
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In the future, we may also accept for disposal solids that are subject to the requirements of federal Resource, Conservation and Recovery Act, or RCRA, and comparable state statutes.  While RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes.  Most Exploration & Production (“E&P”) waste is exempt from stringent regulation as a hazardous waste under RCRA.  None of our facilities are currently permitted to accept hazardous wastes for disposal, and we take precautions to help ensure that hazardous wastes do not enter or are not disposed of at our facilities.  Some wastes handled by us that currently are exempt from treatment as hazardous wastes may in the future be designated as “hazardous wastes” under RCRA or other applicable statutes.  For example, in September 2010, a nonprofit environmental group filed a petition with the EPA requesting reconsideration of the RCRA E&P waste exemption.  To date, the EPA has not taken any action on the petition.  If the RCRA E&P waste exemption is repealed or modified, we could become subject to more rigorous and costly operating and disposal requirements.

We are required to obtain permits for the disposal of E&P waste as part of our operations.  The construction, operation and disposal operations are generally regulated at the state level.  These regulations vary widely from state to state.  State permits can restrict pressure, size and location of disposal operations, impose limits on the types and amount of waste a facility may receive and the overall capacity of a waste disposal facility.  States may add additional restrictions on the operations of a disposal facility when a permit is renewed or amended.  As these regulations change, our permit requirements could become more stringent and may require material expenditures at our facilities or impose significant restraints or financial assurances on our operations.

In the course of our operations, some of our equipment may be exposed to naturally occurring radiation associated with oil and natural gas deposits, and this exposure may result in the generation of wastes containing naturally occurring radioactive materials, or NORM.  NORM wastes exhibiting trace levels of naturally occurring radiation in excess of established state standards are subject to special handling and disposal requirements, and any storage vessels, piping and work area affected by NORM may be subject to remediation or restoration requirements.  It is possible that we may incur costs or liabilities associated with elevated levels of NORM.

Safe Drinking Water Act.  Our underground injection operations are subject to the Safe Drinking Water Act, or SDWA, as well as analogous state laws and regulations.  Under the SDWA, the EPA established the Underground Injection Control, or UIC, program, which established the minimum program requirements for state and local programs regulating underground injection activities.  The UIC program includes requirements for permitting, testing, monitoring, record keeping and reporting of injection well activities, as well as a prohibition against the migration of fluid containing any contaminant into underground sources of drinking water.  State regulations require us to obtain a permit from the applicable regulatory agencies to operate our underground injection wells.  We believe that we have obtained the necessary permits from these agencies for our underground injection wells and that we are in compliance with permit conditions and state rules and regulations.  Although we monitor the injection process of our wells, any leakage from the subsurface portions of the injection wells could cause degradation of fresh groundwater resources, potentially resulting in suspension of our UIC permit, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource and imposition of liability by third-parties for property damages and personal injuries.  In addition, storage of residual crude oil collected as part of the saltwater injection process prior to sale could impose liability on us in the event that the entity to which the oil was transferred fails to manage and, as necessary, dispose of residual crude oil in accordance with applicable environmental and occupational health and safety laws.

Our customers are subject to these same regulations.  While these largely result in their needing our services, some waste regulations could have the opposite effect.  For instance, some states, including Texas, have considered laws mandating the recycling of flowback and produced water.  If such laws are passed, our customers may divert some saltwater to recycling operations that may have otherwise been disposed of at our facilities.

Oil Pollution Act of 1990.  The Oil Pollution Act of 1990, or OPA, as amended, establishes strict liability for owners and operators of facilities that are the site of a release of oil into waters of the U.S.  The OPA also imposes ongoing requirements on owners or operators of facilities that handle certain quantities of oil, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill.  We handle oil at many of our facilities, and if a release of oil into the waters of the U.S. occurred at one of our facilities, we could be liable for cleanup costs and damages under the OPA.
 
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Water discharges.  The federal Water Pollution Control Act, referred to as the Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters as well as waters of the U.S. and impose requirements affecting our ability to conduct activities in waters and wetlands.  Pursuant to the Clean Water Act and analogous state laws, permits must be obtained to discharge pollutants into state waters or waters of the U.S., and permits or coverage under general permits must also be obtained to authorize discharges of storm water runoff from certain types of industrial facilities, including many of our facilities.  The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit.  Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon storage tank spill, rupture or leak.  Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions.  Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.  We believe that compliance with existing permits and regulatory requirements under the Clean Water Act and state counterparts will not have a material adverse effect on our business.  Future changes to permits or regulatory requirements under the Clean Water Act, however, could adversely affect our business.

Endangered species.  The federal Endangered Species Act, or ESA, restricts activities that may affect endangered or threatened species or their habitats.  Many states also have analogous laws designed to protect endangered or threatened species.  We believe we are in compliance with the ESA and similar statutes.  However, the designation of previously unidentified endangered or threatened species could indirectly cause us to incur additional costs or cause our or our customers’ operations to become subject to operating restrictions or bans or limit future development activity in affected areas.
 
For example, the federal government is considering listing the greater sage-grouse as an endangered species whose natural habitats coincide with some of our areas of operation and the areas of operation of some of our customers.  The lesser prairie-chicken was listed as threatened in March 2014.  As part of conservation efforts to preserve that species, a coalition of state governments, NGOs and industry developed the Lesser Prairie-Chicken Range-Wide Conservation Plan.  Additionally, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the Fish and Wildlife Service is required to make a determination on the listing of more than 250 species as endangered or threatened under the ESA by the end of the Fish and Wildlife Service’s 2017 fiscal year.
 
To the extent these species, or other species that live in the areas where our operations and our customers’ operations are conducted, are listed under the ESA or similar state laws, this could limit our ability to expand our operations and facilities or could force us to incur material additional costs.  Moreover, listing such species under the ESA or similar state laws could indirectly, but materially, affect our business by imposing constraints on our customers’ operations, including the curtailment of new drilling or a refusal to allow a new pipeline to be constructed.

Air emissions.  Some of our operations also result in emissions of regulated air pollutants.  The Clean Air Act, or CAA, and analogous state laws require permits for and impose other restrictions on facilities that have the potential to emit substances into the atmosphere above certain specified quantities or in a manner that could adversely affect environmental quality.  Failure to obtain a permit or to comply with permit requirements could result in the imposition of substantial administrative, civil and even criminal penalties.  We do not believe that any of our operations are subject to CAA permitting or regulatory requirements for major sources of air emissions, but some of our facilities could be subject to state “minor source” air permitting requirements and other state regulatory requirements for air emissions.
 
Our customers’ operations may be subject to existing and future CAA permitting and regulatory requirements that could have a material effect on their operations.  The EPA approved new CAA rules requiring additional emissions controls and practices for oil and natural gas production wells, including wells that are the subject of hydraulic fracturing operations.  EPA’s rule package requires new standards on all hydraulically-fractured wells constructed or re-fractured after January 1, 2015.  The rules also establish new emission requirements for compressors, controllers, dehydrators, storage tanks, natural gas processing and certain other equipment used in the hydraulic fracturing process.  These rules may increase the costs to our customers of developing and producing hydrocarbons, and as a result, may have an indirect and adverse effect on the amount of oilfield waste delivered to our facilities by our customers.
 
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Climate change.  In response to certain scientific studies suggesting that emissions of greenhouse gases, or GHGs, including carbon dioxide and methane, are contributing to the warming of the Earth’s atmosphere and other climatic conditions, the U.S. Congress has considered adopting legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap-and-trade programs.  Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants or major producers of fuels, such as refineries and natural gas processing plants, to acquire and surrender emission allowances that correspond to their annual emissions of GHGs.  The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved.  As the number of GHG emission allowances declines each year, the cost or value of such allowances is expected to escalate significantly.

On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane, and other GHGs, present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climate changes.  These findings served as a statutory prerequisite for EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the Clean Air Act.  EPA has adopted two sets of related rules, one of which regulates emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources of emissions such as power plants or industrial facilities.  The EPA finalized the motor vehicle rule in April 2010 and it became effective January 2011.  The EPA adopted the stationary source rule, also known as the “Tailoring Rule,” in May 2010, and it also became effective January 2011.  Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including NGLs fractionators and local natural gas / distribution companies, beginning in 2011, for emissions occurring in 2010.  More recently, in November 2010, the EPA expanded its existing GHG reporting rule to include onshore and offshore oil and natural gas production and onshore processing, transmission, storage and distribution facilities, which may include certain of our facilities, beginning in 2012 for emissions occurring in 2011.  Additionally, in September 2013, the EPA published New Source Performance Standards for Greenhouse Gas emissions from Electric Utility Generating Units and a proposed rule in June 2014 limiting GHG emissions from existing coal-fired power plants. As a result of this continued regulatory focus, future GHG regulations of the oil and natural gas industry remain a possibility.

Although it is not possible at this time to estimate how potential future laws or regulations addressing GHG emissions would impact our business, either directly or indirectly, any future federal or state laws or implementing regulations that may be adopted to address GHG emissions in areas where we operate could require us or our customers to incur increased operating costs.  Regulation of GHGs could also result in a reduction in demand for and production of oil and natural gas, which would result in a decrease in demand for our services.  We cannot predict with any certainty at this time how these possibilities may affect our operations, but effects could be materially adverse.

Hydraulic fracturing.  We do not conduct hydraulic fracturing operations, but we do provide treatment and disposal services with respect to the fluids used and wastes generated by our customers in such operations, which are often necessary to drill and complete new wells and maintain existing wells.  Hydraulic fracturing involves the injection of water, sand or other proppants and chemicals under pressure into target geological formations to fracture the surrounding rock and stimulate production.  Recently, there has been increased public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies or the alleged link between the fluid injection associated with hydraulic fracturing and seismic activity, and proposals have been made to enact separate federal, state and local legislation that would increase the regulatory burden imposed on hydraulic fracturing.  The SDWA regulates the underground injection of substances through the UIC program and exempts hydraulic fracturing from the definition of “underground injection.”  The U.S. Congress has in recent legislative sessions considered legislation to amend the SDWA, including legislation that would repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process.  The U.S. Congress may consider similar SDWA legislation in the future.

In addition, EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and published draft permitting guidance in May 2012 addressing the performance of such activities using diesel fuels in those states where EPA is the permitting authority.  Also, in November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing and the agency currently plans to issue a Notice of Proposed Rulemaking that would seek public input on the design and scope of such disclosure regulations.  Further, On October 21, 2011, the EPA announced its intention to propose federal Clean Water Act regulations in 2014 governing wastewater discharges from hydraulic fracturing and certain other natural gas operations.  In addition, the U.S. Department of the Interior (“DOI”) published a revised proposed rule on May 16, 2013 that would update existing regulation of hydraulic fracturing activities on federal lands, including requirements for disclosure, well bore integrity and handling of flowback water.  DOI is expected to issue the final rule in 2015.
 
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Presently, hydraulic fracturing is regulated primarily at the state level, typically by state oil and natural gas commissions and similar agencies.  Several states, including Texas and North Dakota, where we conduct our water and environmental services business, have either adopted or proposed laws and/or regulations to require oil and natural gas operators to disclose chemical ingredients and water volumes used to hydraulically fracture wells, in addition to more stringent well construction and monitoring requirements.  The chemical ingredient information is generally available to the public via online databases including fracfocus.org, and this may bring more public scrutiny to hydraulic fracturing operations.

The EPA is conducting a study of the potential impacts of hydraulic fracturing activities on drinking water.  The EPA issued a Progress Report in December 2012, and a final draft is yet to be published for peer review and public comment.  As part of this study, the EPA requested that certain companies provide them with information concerning the chemicals used in the hydraulic fracturing process.  This study and other studies that may be undertaken by the EPA or other governmental authorities, depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise.  If new federal, state or local laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could result in delays, eliminate certain drilling and injection activities and make it more difficult or costly for our customers to perform fracturing.  Any such regulations limiting or prohibiting hydraulic fracturing could reduce oil and natural gas exploration and production activities by our customers and, therefore, adversely affect our business.  Such laws or regulations could also materially increase our costs of compliance and doing business by more strictly regulating how hydraulic fracturing wastes are handled or disposed.

Occupational Safety and Health Act.  We are subject to the requirements of the Occupational Safety and Health Act, or OSHA and comparable state laws that regulate the protection of employee health and safety.  OSHA’s hazard communications 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.  These laws and regulations are subject to frequent changes.  Failure to comply with these laws could lead to the assertion of third-party claims against us, civil and/or criminal fines and changes in the way we operate our facilities that could have an adverse effect on our financial position.
 
Seismic Activity.    Some individuals and companies have linked seismic activity with both hydraulic fracturing and SWD facilities.  In Oklahoma, a substantial number of seismic events have been blamed on saltwater disposal and SWD facilities.   We do not currently operate any SWD facilities in Oklahoma.   The Oklahoma Corporation Commission has been investigating and evaluating any potential impact SWD facilities may have on seismic activity.   We believe that it is prudent to avoid building SWD facilities near known fault lines that may become lubricated with substantial volumes of saltwater.   Some industry experts believe this lubrication helps avoid major seismic activity that would likely otherwise occur.

Employees
 
The Partnership does not have any employees.  All of the employees that conduct our business are employed by affiliates of our general partner, but we sometimes refer to these individuals in this report as our employees.  We are managed and operated by the directors and officers of our general partner.  All of our executive management personnel are employees of CEM LLC or another affiliate of Holdings, and devote the portion of their time to our business and affairs that is required to manage and conduct our operations.  As of December 31, 2014 and 2013, that entity employed 15 and ten people, respectively, who provide direct support for our operations, none of whom are covered by collective bargaining agreements.  Under the terms of our amended and restated omnibus agreement, we reimburse CEM LLC for the provision of various general and administrative services incurred for our benefit, for direct expenses incurred by CEM LLC on our behalf and for expenses allocated to us as a result of our becoming a public entity.  In addition, PI&IS does not have any employees.  All of the employees that conduct the PI&IS business do it through CEM TIR, providing the necessary personnel resources to PI&IS.  PI&IS employed or engaged 1,147 and 1,476 inspectors as of December 31, 2014 and 2013, respectively, of which 1,131 and 1,397 were employed directly by CEM TIR. The inspectors not employed by CEM TIR are contractors engaged in our Canadian operations. The number of employees in the PI&IS group vary month to month and project to project.   The Tulsa headquarters group of PI&IS consists of approximately 70 employees who are also employed by CEM TIR.  Virtually all of our inspector employees are billable to clients and they work in the field on client assets and infrastructure including, but not limited to, pipelines.
 
We also had a co-employment relationship between CEM LLC and a third-party management company that employed nine and ten people as of December 31, 2014 and 2013, respectively, working at our SWD facilities in west Texas.  The co-employment arrangement was terminated in January 2015 and all employees are now employed solely by CEM LLC.  CEM LLC also owns a 51% interest in CEM-BO, which provides staff for our North Dakota SWD facility operations.  As of December 31, 2014 and 2013, CEM-BO employed approximately 39 and 41 employees, respectively.  We pay CEM LLC and CEM-BO a management fee to compensate them for the cost of the Texas and North Dakota employees, benefits and various other services provided to us.
 
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Insurance Matters

Our customers require that we maintain certain minimum levels of insurance and evaluate our insurance coverage as part of the initial and ongoing approval process they require to use our services to treat and dispose of their waste.  We carry a variety of insurance coverages for our operations.  However, our insurance may not be sufficient to cover any particular loss or may not cover all losses, and losses not covered by insurance would increase our costs.  Also, insurance rates have been subject to wide fluctuation, and changes in coverage could result in less coverage, increases in cost or higher deductibles and retentions.

The SWD and the pipeline inspection and integrity businesses can be dangerous, involving unforeseen circumstances such as environmental damage from leaks, spills or vehicle accidents.  To address the hazards inherent in W&ES, our insurance coverage includes business, auto liability, commercial general liability, employer’s liability, environmental and pollution and other coverage.  To address the hazards inherent in PI&IS, insurance coverage includes employer’s liability, auto liability, employee benefits liabilities, and contractor’s pollution and other coverage.  Coverage for environmental and pollution-related losses is subject to significant limitations and are commonly provided for exclusion on such policies.
 
Available Information

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (the “Exchange Act”) are made available free of charge on our website at www.cypressenergy.com as soon as reasonably practicable after these reports have been electronically filed with, or furnished to, the SEC.  These documents are also available on the SEC’s website at www.sec.gov, or a unitholder may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.  No information from either the SEC’s website or our website is incorporated herein by reference.
 
ITEM 1A. RISK FACTORS

Unitholders should consider carefully the following risk factors together with all of the other information included in this Annual Report on Form 10-K and our other reports filed with the SEC before investing in our common units. If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, the trading price of our common units could decline and a unitholder could lose all or part of their investment.

Risks Related to Our Business

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cash reimbursement to our general partner and its affiliates to enable us to pay our minimum quarterly distributions to holders of our units.
 
In order to pay the minimum quarterly distribution of $0.3875 per unit per quarter, or $1.55 per unit on an annualized basis, we will require available cash of approximately $4.6 million per quarter, or $18.3 million per year, based on the number of common and subordinated units outstanding as of March 25, 2015. We may not have sufficient available cash from operating surplus each quarter to enable us to pay the minimum quarterly distribution. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
 
· the fees we charge, and the margins we realize, from W&ES, as well as PI&IS;

· the volume of saltwater we handle in W&ES and the number and types of projects conducted by PI&IS;

· the amount of residual oil we are able to separate and sell from the saltwater we receive that can be impacted by the quality and price of the oil;

· the cost of achieving organic growth in current and new markets;
 
 
·
our ability to make acquisitions of other SWD facilities and pipeline inspection companies;
 
· the level of competition from other companies;

· governmental regulations, including changes in governmental regulations, in our industry;
 
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· prevailing economic and market conditions; and

· weather and natural disasters, lightning, seismic activity, vandalism and acts of terror.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:

· the level of capital expenditures we make;

· the cost of acquisitions;

· the level of our operating costs and expenses and the performance of our various facilities, inspectors and staff;

· our debt service requirements and other liabilities;

· fluctuations in our working capital needs;

· our ability to borrow funds and access capital markets;

· restrictions contained in our debt agreements;

· the amount of cash reserves established by our general partner; and

· other business risks affecting our cash levels.
 
We would not have had sufficient cash available for distribution to pay the full minimum quarterly distribution on all of our units for the years ended December 31, 2012 or 2013.
 
We must generate approximately $18.3 million of cash available for distribution to pay the aggregate minimum quarterly distributions for four quarters on all units outstanding as of March 25, 2015. The amount of cash available for distribution that we generated during the year ended December 31, 2012 on a pro forma basis would have been sufficient to pay 100% of the aggregate minimum quarterly distribution on all common units, and 16.4% of the aggregate minimum quarterly distributions on our subordinated units for that period. In addition, the amount of cash available for distribution that we generated during the year ended December 31, 2013 on a pro forma basis would have been sufficient to pay 100% of the aggregate minimum quarterly distribution on all common units, and 54.2% of the aggregate minimum quarterly distributions on our subordinated units for that period. Our ability to pay the minimum quarterly distribution is subject to various restrictions and other factors described in more detail under “Item 5 – Market for Registration’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities – Our Cash Distribution Policy.” If we are not able to generate additional cash for distribution to our unitholders in future periods, we may not be able to pay the full minimum quarterly distribution or any amount on our common or subordinated units, in which event the market price of our common units may decline materially.
 
We serve customers who are involved in drilling for, producing and transporting oil and natural gas. Adverse developments affecting the oil and natural gas industry or drilling activity, including sustained low natural gas prices, a decline in oil or natural gas liquids prices, reduced demand for oil and natural gas products, adverse weather conditions, and increased regulation of drilling and production, could have a material adverse effect on our results of operations.

W&ES depends on our oil and natural gas customers’ willingness to make operating and capital expenditures to develop and produce oil and natural gas in the United States. A reduction in drilling activity generally results in decreases in the volumes of new flowback and produced water generated, which adversely impacts our revenues. Therefore, if these expenditures decline, our business is likely to be adversely affected.
 
The level of activity in the oil and natural gas exploration and production industry in the U.S. has been volatile. According to the Baker Hughes oil and gas drilling rig count, the U.S. weekly aggregate rig count reached an all-time high of 4,530 rigs in December 1981 and a post-1942 low of 488 rigs in April 1999. From January 2010 through February 2015, the aggregate U.S. weekly rig count has remained above 1,220 rigs, reaching a peak of 2,026 rigs in November 2011 and declining to 1,267 rigs in February 2015. In the fourth quarter of 2014 and continuing into 2015, the price of crude oil has dropped substantially. If crude oil prices do not recover, or take longer to recover than anticipated, exploration and production companies in the regions we conduct W&ES may reduce capital spending on maintaining or growing production. W&ES constitutes approximately 6% of our revenue for the year ended December 31, 2014. Therefore, a continued decrease in drilling activity or hydraulic fracking could have an adverse effect on our revenue and profitability.
 
Our customers’ willingness to engage in drilling and production of oil and natural gas depends largely upon prevailing industry conditions that are influenced by numerous factors over which our management has no control, such as:
 
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· the supply of and demand for oil and natural gas;

· the level of prices, and expectations about future prices, of oil and natural gas;

· the cost of exploring for, developing, producing and delivering oil and natural gas, including fracturing services;

· the expected rate of decline of current oil and natural gas production;

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

· available pipeline and other transportation capacity;

· lead times associated with acquiring equipment and products and availability of personnel;

· weather conditions, including hurricanes, tornadoes, earthquakes, wildfires, drought or man-made disasters that can affect oil and natural gas operations over a wide area, as well as local weather conditions such as unusually cold winters in the Bakken Shale region of the Williston Basin in North Dakota that can have a significant impact on drilling activity in that region;

· domestic and worldwide economic conditions;

· contractions in the credit market;

· political instability in certain oil and natural gas producing countries;

· the continued threat of terrorism and the impact of military and other action, including military action in the Middle East or other parts of the world;

· governmental regulations, including income tax laws or government incentive programs relating to the oil and natural gas industry and the policies of governments regarding the exploration for and production and development of their oil and natural gas reserves;

· the level of oil production by non-OPEC countries and the available excess production capacity within OPEC;

· oil refining capacity and shifts in end-customer preferences toward fuel efficiency;

· potential acceleration in the development, and the price and availability, of alternative fuels;

· the availability of water resources for use in hydraulic fracturing operations;

· public pressure on, and legislative and regulatory interest in, federal, state, and local governments to ban, stop, significantly limit or regulate hydraulic fracturing operations;

· technical advances affecting energy consumption;

· the access to and cost of capital for oil and natural gas producers;

· merger and divestiture activity among oil and natural gas producers; and

· the impact of changing regulations and environmental and safety rules and policies.
 
The working capital needs of the PI&IS segment are substantial, which will reduce our borrowing capacity for other purposes and reduce our cash available for distribution.
 
PI&IS has substantial working capital needs throughout the year as we pay the majority of our inspectors on a weekly basis, but typically receive payment from our customers 45 to 90 days after the services have been performed. We intend to make borrowings under our credit facility to fund the working capital needs of PI&IS, and these borrowings will reduce the amount of credit available for other uses, such as working capital for our water disposal business, acquisitions and growth projects, and increase interest expense, thereby reducing cash available for distribution to our unitholders. Any cash generated from operations used to fund working capital needs will also reduce cash available for distribution to our unitholders. Additionally, if we experience any delays in payment by our pipeline inspection and integrity services customers, we may be subject to significant and rapid increases in our working capital needs that could require us to make further borrowings under our revolving credit facility or impact our ability to pay our minimum quarterly distributions.
 
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Our business is dependent upon the willingness of our customers to outsource their waste management activities and pipeline inspection and integrity activities.

Our business is largely dependent on the willingness of customers to outsource the treatment of their water and environmental services and pipeline inspection and integrity activities. Currently, many oil and natural gas producing companies own and operate waste treatment, recovery and SWD facilities, and some producers recycle saltwater on-site. In addition, most oilfield operators, including many of our customers, have numerous abandoned wells that could be licensed for use in the disposition of internally generated waste and third-party waste in competition with us. Additionally, technologies may be developed that could be used by our customers to recycle saltwater and to recover oil through oilfield waste processing. Furthermore, some pipeline owners and operators currently inspect and perform integrity activities on their own pipeline systems using the same techniques and technologies that we use, as well as others that we currently do not employ, such as pigging and aerial surveys. Our current customers could decide to process and dispose of their waste internally or inspect and perform integrity activities on their own pipeline systems, either of which could have a material adverse effect on our financial position, results of operations, cash flows and our ability to make cash distributions to our unitholders.

Our markets are highly competitive, and competition could adversely impact our financial position, results of operations, demand for services, cash flows or our ability to make required payments on debt outstanding.

We have many competitors in W&ES and PI&IS. Other companies offer similar third-party saltwater disposal or pipeline inspection and integrity services in our primary markets. Some of our customers also compete with us in the treatment and disposal sector by offering such services to other oil and natural gas companies. Our customers regularly evaluate the best combination of value and price from competing alternatives and new technologies and can move between alternatives or, in some cases, develop their own alternatives with relative ease. This competition influences the prices we charge and requires us to control our costs aggressively and maximize efficiency in order to maintain acceptable operating margins; however, we may be unable to do so and remain competitive on a cost-for-service basis. In addition, existing and future competitors may develop or offer services or new technologies that have pricing, location or other advantages over the services we provide, including a lower cost of capital.

We do not enter into long-term contracts with our customers, which subjects us to renewal or termination risks.

We do not typically enter into long-term contracts with customers. While we frequently operate under master services agreements with customers that set forth the terms on which we will provide services, customers operating under these agreements typically have the ability to terminate their relationship with us at any time at their sole discretion by ceasing to deliver saltwater to our SWD facilities or by choosing to not use us to provide pipeline inspection and integrity management services. Therefore, there is a heightened risk that our customers may decide not to dispose of their saltwater disposal through us or use our inspection and integrity services. The failure of customers to continue to use our services could adversely affect our operations, financial condition and ability to make cash distribution to our unitholders.

We depend on a limited number of customers for a substantial portion of our revenues. The loss of, or a material nonpayment by, our key customers could adversely affect our results of operations, financial condition and ability to make cash distributions to our unitholders.
 
Our ten largest customers generated approximately 78% and 80% of our consolidated revenue for the year ended December 31, 2014 and the period from June 26, 2013 through December 31, 2013. There were three customers that accounted for more than 10% of revenues for the year ended December 31, 2014; Enbridge Energy Partners, Enterprise Products Partners and Plains All America Pipeline.  For the period from June 26, 2013 through December 31, 2013, Enbridge Energy Partners and Enterprise Products Partners each individually made up more than 10% of consolidated revenues of PI&IS.  Revenues from these customers resulted from inspection operations, which are activities conducted by our PI&IS segment.  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.
 
Disruptions in the transportation services of trucking companies transporting saltwater could adversely affect our results of operations and cash available for distribution to our unitholders.

We primarily depend on trucking companies to transport saltwater to our SWD facilities. In recent years, certain states, including North Dakota and Texas, and counties have increased enforcement of weight limits on trucks used to transport raw materials on their public roads. Also, as a result of regulations issued in March of 2014, all waste haulers transporting produced water in North Dakota must possess a valid permit for transporting solid waste from the North Dakota Department of Health to legally transport such wastes. It is possible that the states, counties and cities in which W&ES may modify their laws to further reduce truck weight limits, or impose curfews or other restrictions on the use of roadways. Such legislation and enforcement efforts could result in delays in transporting saltwater to our SWD facilities and increased costs to transport saltwater to our facilities, which may either increase our operating costs or reduce the amount of saltwater transported to our SWD facilities. This could decrease our operating margins or amounts of saltwater disposed at our SWD facilities and thereby affect our results of operations and cash available for distribution.
 
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A significant increase in fuel or insurance prices may adversely affect the transportation costs of our trucking company customers, which could result in a decrease in the rates for our saltwater and environmental services they would be willing to pay.

Fuel is a significant operating expense for our trucking customers, and a significant increase in fuel prices will result in increased transportation costs to them. The price and supply of fuel is unpredictable and fluctuates based on events such as geopolitical developments, supply and demand for oil and natural gas, actions by oil and natural gas producers, war and unrest in oil producing countries and regions, regional production patterns and weather concerns. A significant increase in fuel prices could drive down the prices our trucking company customers would be willing to pay, which would reduce our revenues and impact our ability to make distributions to our unitholders. Insurance is a significant operating expense for our trucking customers, and a significant increase in insurance prices or decrease in availability of coverage results in increased transportation costs to them.

Volumes of residual oil recovered during the saltwater water treatment process can vary. Any significant reduction in residual oil content in the water we treat, or the price we achieve for residual oil sales, will affect our recovery of residual oil and, therefore, our profitability.
 
Approximately 22% of our revenue for the year ended December 31, 2014 in W&ES was derived from sales of residual oil recovered during the saltwater treatment process. Our ability to recover sufficient volumes of residual oil is dependent upon the residual oil content in the saltwater we treat, which is, among other things, a function of water type, chemistry, source and temperature. Generally, where outside temperatures are lower, there is less residual oil content and separation is more difficult. Thus, our residual oil recovery during the winter season is lower than our recovery during the summer season in North Dakota. Additionally, residual oil content will decrease if, among other things, producers begin recovering higher levels of residual oil in saltwater prior to delivering such saltwater to us for treatment. Also, the revenues we derive from sales of residual oil are subjected to fluctuations in the price of oil. Any reduction in residual crude oil content in the saltwater we treat or the prices we realize on our sales of residual oil could materially and adversely affect our profitability.
 
Our business may be difficult to evaluate because we have a limited period of historical financial and operating data.
 
CEP LLC’s historical results for 2012 represents the results of only one of the water and environmental services companies we have acquired. The results of the other water and environmental services company that we acquired are only shown since the end of 2012. Furthermore, our full 2012 and the period prior to June 26, 2013 historical financial and operating data does not include PI&IS. As a result, we have provided only limited financial and operating data regarding the consolidated business that we operate. The historical financial and operating results of our business may be materially different from our future financial and operating results. Our future results will depend on our ability to efficiently manage our integrated operations and execute our business strategy. Our historical financial performance and that of CEP LLC should not be considered reliable indicators of our future performance.

In addition, we face challenges and uncertainties in financial and operational planning as a result of the limited access to historical data regarding volumes of oilfield waste treated and related sales and pricing. Our first facilities were opened during 2011, and other companies in the SWD industry do not regularly release historical data related to their SWD facilities. This limited data may make it more difficult for us and our investors to evaluate our business and prospects and to forecast our future operating results.

We are vulnerable to the potential difficulties, expenses and uncertainties associated with rapid growth and expansion.

We have grown rapidly since our inception in 2012, primarily through acquisitions in both of our segments. We believe that our future success depends on our ability to manage the rapid growth that we have experienced and the demands from increased responsibility on our management personnel. The following factors could present difficulties to us:

· organizational challenges common to large, expansive operations;

· administrative burdens;

· impact of the Affordable Care Act and employee insurance;

· limitations with systems and technology;

· safety and training;

· ability to recruit, train and retain personnel and managers;

· ability to obtain permits for expanded operations;

· access to debt and equity capital on attractive terms; and

· long lead times associated with acquiring equipment and building any new facilities.
 
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Our operating results could be adversely affected if we do not successfully manage these potential difficulties.

Our ability to grow in the future is dependent on our ability to access external growth capital.

We will distribute all of our available cash after expenses and prudent operating reserves to our unitholders. We expect that we will rely primarily upon external financing sources, including borrowings under our credit facilities and the issuance of debt and equity securities, to fund growth capital expenditures. However, we may not be able to obtain equity or debt financing on terms favorable to us, or at all. To the extent we are unable to efficiently finance growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we distribute all of our available cash, we may not grow as quickly as businesses that reinvest their available cash to expand ongoing operations. Furthermore, Holdings is under no obligation to fund our growth. To the extent we issue additional units in connection with the financing of other growth capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per-unit distribution level. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of borrowings or other debt by us to finance our growth strategy would result in interest expense, which in turn would affect the available cash that we have to distribute to our unitholders.

Our utilization of existing capacity, expansion of existing SWD facilities and construction or purchase of new SWD facilities may not result in revenue increases and will be subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our operations and financial condition.

A portion of our strategy to grow and increase distributions to unitholders is dependent on our ability to utilize available capacity at our existing facilities, expand existing SWD facilities and construct or purchase new SWD facilities. The construction of a new SWD facility or the extension, renovation or expansion of an existing SWD facility, such as by connecting the SWD facility to pipeline systems, involves numerous business, competitive, regulatory, environmental, political and legal uncertainties, most of which are beyond our control. If we undertake these projects, they may not be completed on schedule or at all or at the budgeted cost. Furthermore, we will not receive any material increases in revenues until after completion of the project although we will have to pay financing and construction costs during the construction period. As a result, new SWD facilities may not be able to attract enough demand for water and environmental services to achieve our expected investment return, which could materially adversely affect our results of operations and financial condition and our ability in the future to make distributions to our unitholders.

Our ability to acquire assets from Holdings or third parties is subject to risks and uncertainty. If we are unable to make acquisitions on economically acceptable terms, our future growth would be limited, and any acquisitions we may make may reduce, rather than increase, our cash flows and ability to make distributions to unitholders. Furthermore, we may not realize the benefits from or successfully integrate any acquisitions.

A portion of our strategy to grow our business and increase distributions to unitholders is dependent on our ability to make acquisitions that result in an increase in cash we generate on a per unit basis. The acquisition component of our strategy is based, in large part, both on our expectation of continuing consolidation in the industries in which we operate and our ability to acquire interests in additional assets from Holdings.

Holdings is developing or seeking to purchase several water and environmental services assets and facilities that may be suitable to our operations in the future. We expect to have the opportunity to make acquisitions directly from Holdings and its affiliates in the future. The consummation and timing of any future acquisitions of these assets will depend upon, among other things, Holdings’ and its affiliates’ willingness to offer these assets for sale, our ability to negotiate acceptable purchase agreements and commercial agreements with respect to the assets and our ability to obtain financing on acceptable terms. We can offer no assurance that we will be able to successfully consummate any future acquisitions with Holdings and its affiliates, and Holdings and its affiliates are under no obligation to accept any offer that we may choose to make. In addition, certain of these assets may require substantial capital expenditures in order to maintain compliance with applicable regulatory requirements or otherwise make them suitable for our commercial needs. For these or a variety of other reasons, we may decide not to acquire these assets from Holdings and its affiliates if, and when, Holdings and its affiliates offers such assets for sale, and our decision will not be subject to unitholder approval.

Additionally, we may not be able to make accretive acquisitions from third parties if we are:

unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts;

unable to obtain financing for these acquisitions on economically acceptable terms;

outbid by competitors; or

for any other reason.

 If we are unable to make acquisitions from Holdings and its affiliates or third parties, our future growth and ability to increase distributions will be limited. Furthermore, even if we do consummate acquisitions that we believe will be accretive, they may in fact result in a decrease in cash flow.
 
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Any acquisition involves potential risks, including, among other things:

· mistaken assumptions about disposal capacity, number and quality of inspectors, revenues and costs, cash flows, capital expenditures and synergies;

· the assumption of unknown liabilities;

· limitations on rights to indemnity from the seller;

· mistaken assumptions about the overall costs of equity or debt;

· the diversion of management’s attention from other business concerns;

· integrating business operations or unforeseen regulatory issues;

· unforeseen new regulations;

· unforeseen difficulties operating in new geographic areas; and

· customer or key personnel losses at the acquired businesses.

If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

We conduct a portion of our operations through entities that we partially own, which subjects us to additional risks that could have a material adverse effect on our financial condition and results of operations.

We own a 51.0% interest in CES LLC, an arrangement with an affiliate of SBG Energy Services, LLC. We may also enter into other arrangements with third parties in the future. SBG Energy Services, LLC has, and other third parties in future arrangements may have, obligations that are important to the success of the arrangement, such as the obligation to pay their share of capital and other costs of these partially owned entities. The performance of these third-party obligations, including the ability of our current partners to satisfy their respective obligations, is outside our control. If these parties do not satisfy their obligations under the arrangements, our business may be adversely affected.

Our joint venture arrangements, including CES LLC, may involve risks not otherwise present without a partner, including, for example:

· our CES LLC partner shares certain blocking rights over transactions between CES LLC and its affiliates, including us;

· our partner may take actions contrary to our instructions or requests or contrary to our policies or objectives;

· although we control CES LLC, we owe contractual duties to CES LLC and its respective other owners, which may conflict with our interests and the interests of our unitholders; and

· disputes between us and our partner may result in delays, litigation or operational impasses.

The risks described above or any failure to continue our joint venture or to resolve disagreements with our third-party partners could adversely affect our ability to transact the business that is the subject of such business, which would, in turn, negatively affect our financial condition, results of operations and ability to distribute cash to our unitholders.

Restrictions in our credit agreement could adversely affect our business, financial condition, results of operations, ability to make cash distributions to our unitholders and the value of our units.
 
On December 24, 2013, we entered into our $120 million credit agreement, which we used to replace the TIR Entities’ existing revolving credit facility and mezzanine facilities. On October 21, 2014, the Credit Agreement was amended to increase the aggregate availability under the Credit Agreement from $120 million to $200 million.  CEP-TIR and TIR LLC are also co-borrowers and co-guarantors under our credit agreement. Our credit agreement limits our ability to, among other things:
 
· incur or guarantee additional debt;

· make certain investments and acquisitions;

· incur certain liens or permit them to exist;
 
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· alter our line of business;

· enter into certain types of transactions with affiliates;

· merge or consolidate with another company; and

· transfer, sell or otherwise dispose of assets.

The credit agreement also contains certain covenants requiring us to maintain certain financial ratios. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure unitholders that it would meet those ratios and tests.

The provisions of our new and future credit agreements may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. For example, our funds available for operations, future business opportunities and cash distributions to unitholders may be reduced by that portion of our cash flow required to make interest payments on our debt. Our ability to service our debt may depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We cannot assure unitholders that we would be able to take any of these actions, that these actions would be successful and permit us to meet our scheduled debt service obligations or satisfy our capital requirements, or that these actions would be permitted under the terms of our credit agreement or future debt agreements. Our new and future debt documents restrict our ability to dispose of assets and use the proceeds from the disposition. We may not be able to consummate those dispositions or to obtain the proceeds which we could realize from them and these proceeds may not be adequate to meet any debt service obligations then due. In addition, a failure to comply with the provisions of our new or future credit facilities could result in a default or an event of default that could enable its lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of its debt is accelerated, defaults under its other debt instruments, if any, may be triggered, and our assets may be insufficient to repay such debt in full, and the holders of our units could experience a partial or total loss of our investment. Please read “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources” for additional information about our credit facilities.

Our existing and future debt levels may limit our flexibility to obtain financing and to pursue other business opportunities.
 
As of December 31, 2014, we had $77.6 million of indebtedness outstanding under our credit agreement. In February 2015, we borrowed an additional $52.6 million to acquire the remaining non-controlling interest in the TIR Entities. We will have the ability to incur additional debt, subject to limitations in our credit agreement. Our degree of leverage could have important consequences to us, including the following:
 
· our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

· our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt;

· we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

· our flexibility in responding to changing business and economic conditions may be limited.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms or at all.

Our business could be adversely impacted if we are unable to obtain or maintain the regulatory permits required to develop and operate our facilities and to dispose of certain types of waste.

We own and operate SWD facilities in North Dakota and Texas, each with its own regulatory program for addressing the handling, treatment, recycling and disposal of saltwater. We are also required to comply with federal laws and regulations governing our operations. These environmental laws and regulations require that we, among other things, obtain permits and authorizations prior to the development and operation of waste treatment and storage facilities and in connection with the disposal and transportation of certain types of waste. The applicable regulatory agencies strictly monitor waste handling and disposal practices at all of our facilities. For many of our sites, we are required under applicable laws, regulations, and/or permits to conduct periodic monitoring, company-directed testing and third-party testing. Any failure to comply with such laws, regulations, or permits may result in suspension or revocation of necessary permits and authorizations, civil or criminal liability and imposition of fines and penalties, which could adversely impact our operations and revenues and ability to continue to provide oilfield water and environmental services to our customers.
 
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In addition, we may experience a delay in obtaining, be unable to obtain, or suffer the revocation of required permits or regulatory authorizations, which may cause us to be unable to serve customers, interrupt our operations and limit our growth and revenue. As of December 31, 2014, we have the required state and federal permits across the two states where we operate our SWD facilities. Regulatory agencies may impose more stringent or burdensome restrictions or obligations on our operations when we seek to renew or amend our permits. For example, permit conditions may limit the amount or types of waste we can accept, pressures, require us to make material expenditures to upgrade our facilities, implement more burdensome and expensive monitoring or sampling programs, or increase the amount of financial assurance that we provide to cover future facility closure costs. Moreover, nongovernmental organizations or the public may elect to protest the issuance or renewal of our permits on the basis of developmental, environmental or aesthetic considerations, which protests may contribute to a delay or denial in the issuance or reissuance of such permits. It is not uncommon for local property owners or, in some cases oil and natural gas producers, to oppose SWD permits. Any such limitations or requirements could limit the water and environmental services we provide to our customers, or make such services more expensive to provide, which could have a material adverse effect on our financial position, results of operations, cash flows and our ability to make cash distributions to our unitholders.
 
Delays in obtaining permits by our customers for their 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 to operate pipeline and gathering systems. Such permits are typically issued by state agencies, but federal and local governmental permits may also be required. The requirements for such permits vary depending on the location where such drilling and completion, and pipeline and gathering, 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 that may be imposed in connection with the granting of the permit. Recently, moratoriums on the issuance of permits for certain types of drilling and completion activities have been imposed in some areas, such as New York. Some of our customers’ drilling and completion activities may also take place on federal land or Native American lands, requiring leases and other approvals from the federal government or Native American tribes to conduct such drilling and completion activities. In some cases, federal agencies have cancelled proposed leases for federal lands and refused or delayed required approvals. Consequently, our customers’ operations in certain areas of the U.S. may be interrupted or suspended for varying lengths of time, causing a loss of revenue to us and adversely affecting our results of operations in support of those customers.

In the future we may face increased obligations relating to the closing of our SWD facilities and may be required to provide an increased level of financial assurance to guaranty the appropriate closure activities occur for an SWD facility.
 
Obtaining a permit to own or operate an SWD facility generally requires us to establish performance bonds, letters of credit or other forms of financial assurance to address clean up and closure obligations at our SWD facilities. In particular, the regulatory agencies of the two states in which we operate require us to post letters of credit in connection with the operation of our SWD facilities. As we acquire additional SWD facilities or expand our existing SWD facilities, these obligations will increase. Additionally, in the future, regulatory agencies may require us to increase the amount of our closure bonds at existing SWD facilities. We have accrued approximately $33 thousand on our balance sheet related to our future closure obligations of our SWD facilities as of December 31, 2014. However, actual costs could exceed our current expectations, as a result of, among other things, federal, state or local government regulatory action, increased costs charged by service providers that assist in closing SWD facilities and additional environmental remediation requirements. Increased regulatory requirements regarding our existing or future SWD facilities, including the requirement to pay increased closure and post-closure costs or to establish increased financial assurance for such activities could substantially increase our operating costs and cause our available cash that we have to distribute to our unitholders to decline.
 
Changes in laws or government regulations regarding hydraulic fracturing could increase our customers’ costs of doing business, limit the areas in which our customers can operate and reduce oil and natural gas production by our customers, which could adversely impact our business.

We do not conduct hydraulic fracturing operations, but we do provide treatment and disposal services with respect to the fluids used and wastes generated by our customers in such operations, which are often necessary to drill and complete new wells and maintain existing wells. Hydraulic fracturing involves the injection of water, sand or other proppants and chemicals under pressure into target geological formations to fracture the surrounding rock and stimulate production. Recently, there has been increased public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies, and proposals have been made to enact separate federal, state and local legislation that would increase the regulatory burden imposed on hydraulic fracturing. SDWA regulates the underground injection of substances through the UIC program and exempts hydraulic fracturing from the definition of “underground injection.” Congress has in recent legislative sessions considered legislation to amend the SDWA including legislation that would repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. The U.S. Congress may consider similar SDWA legislation in the future.
 
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In addition, the EPA, has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and published draft permitting guidance in May 2012 addressing the performance of such activities using diesel fuels in those states where EPA is the permitting authority. Also, in November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing and the agency currently plans to issue a Notice of Proposed Rulemaking that would seek public input on the design and scope of such disclosure regulations. Further, on October 21, 2011, the EPA announced its intention to propose federal Clean Water Act regulations governing wastewater discharges from hydraulic fracturing and certain other natural gas operations. In addition, the DOI published a revised proposed rule on May 16, 2013 that would update existing regulation of hydraulic fracturing activities on federal lands, including requirements for disclosure, well bore integrity and handling of flowback water. The DOI is expected to issue the final rule in 2015.

Presently, hydraulic fracturing is regulated primarily at the state level, typically by state oil and natural gas commissions and similar agencies. Several states, including Texas and North Dakota, where we conduct our water and environmental services business, have either adopted or proposed laws and/or regulations to require oil and natural gas operators to disclose chemical ingredients and water volumes used to hydraulically fracture wells, in addition to more stringent well construction and monitoring requirements. The chemical ingredient information is generally available to the public via online databases including fracfocus.org, and this may bring more public scrutiny to hydraulic fracturing operations. In addition, some local governments, most recently in Colorado, have passed or adopted ordinances and other laws that severely restrict and in some instances totally ban the practice within these jurisdictions.

The EPA is conducting a study of the potential impacts of hydraulic fracturing activities on drinking water. The EPA issued a Progress Report in December 2012 and a final draft report that compiles the results of various research projects is expected to be released in 2015 for peer review and public comment. As part of this study, the EPA requested that certain companies provide them with information concerning the chemicals used in the hydraulic fracturing process. This study or other studies that may be undertaken by the EPA or other governmental authorities, depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise. If new federal, state or local laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could result in delays, eliminate certain drilling and injection activities and make it more difficult or costly for our customers to perform fracturing. Any such regulations limiting or prohibiting hydraulic fracturing could reduce oil and natural gas exploration and production activities by our customers and, therefore, adversely affect our business. Such laws or regulations could also materially increase our costs of compliance and doing business by more strictly regulating how hydraulic fracturing wastes are handled or disposed.

Oil and natural gas producers’ operations, especially those using hydraulic fracturing, are substantially dependent on the availability of water. Restrictions on the ability to obtain water may incentivize water recycling efforts by oil and natural gas producers which would decrease the volume of saltwater delivered to our SWD facilities.

Water is an essential component of oil and natural gas production during the drilling, and in particular, hydraulic fracturing, process. However, the availability of suitable water supplies may be limited for oil and natural gas producers due to reasons such as prolonged drought. For example, according to the Lower Colorado River Authority, during 2011, Texas experienced the lowest inflows of water of any year in recorded history. As a result of this severe drought, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supply. In response to continuing drought conditions in 2014 and 2013, the Texas Legislature considered a number of bills that would have mandated recycling of flowback and produced water and/or prohibits recyclable water from being disposed of in wells. If oil and natural gas producers in Texas are unable to obtain water to use in their operations from local sources they may be incentivized to recycle and reuse saltwater instead of delivering such saltwater to our Texas SWD facilities (or in other states that adopt similar programs). Similarly, mandatory recycling programs could reduce the amount of materials sent to us for treatment and disposal. Any such limits or mandates could adversely affect our business and results of operations.

Increased attention to seismic activity associated with hydraulic fracturing and underground disposal could result in additional regulations and adversely impact demand for our services.
 
There exists a growing concern that the injection of saltwater and other fluids into belowground disposal wells triggers seismic activity in certain areas. Recent seismic events have been observed in some areas where deep well fluid injection of drilling or hydraulic fracturing saltwater has taken place. Some scientists believe the increased seismic activity may result from deep well fluid injection of drilling or hydraulic fracturing saltwater.  Some states, including Texas, Oklahoma and Ohio, have promulgated rules or guidance in response to these concerns.  In Texas, the Texas Railroad Commission (“TRC”) published a final rule in October 2014 governing permitting or re-permitting of disposal wells that will require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the TRC may deny, modify, suspend or terminate the permit application or existing operating permit for that well. These new seismic permitting requirements applicable to disposal wells impose more stringent permitting requirements and are likely to result in added costs to comply or, perhaps, may require alternative methods of disposing of salt water and other fluids, which could delay production schedules and also result in increased costs. Similar rules may be expected to be promulgated by the Oklahoma Corporation Commission (OCC). The OCC recently posted guidance for wells injecting into the Arbuckle formation. OCC is watching for indications that salt water injection may be contributing to significant seismic events and has recently temporarily shut in another producer's water disposal well due to a nearby 4.0 magnitude earthquake. Additional regulatory measures designed to minimize or avoid damage to geologic formations may be imposed to address such concerns.
 
We and our customers may incur significant liability under, or costs and expenditures to comply with, environmental and worker health and safety regulations, which are complex and subject to frequent change.

Our and our customer’s operations are subject to stringent federal, state, provincial and local laws and regulations relating to, among other things, protection of natural resources, wetlands, endangered species, the environment, worker health and safety, waste management, waste disposal, and transportation of waste and other materials. In the U.S., such laws and regulations include the RCRA, CERCLA, the Clean Water Act, SDWA, CAA, OPA, and OSHA, and analogous state laws. In Canada, industrial and natural resource extraction is currently subject to environmental regulations pursuant to a variety of provincial and federal legislation. Both federal and provincial governments can and do exercise regulatory responsibilities. Principal federal legislation includes the Canadian Environmental Assessment Act, the Fisheries Act, the Prosperity Act, the Canadian Environmental Protection Act, the Transportation of Dangerous Goods Act, and the Hazardous Products Act. The majority of industrial and natural resource extraction activities occur in Western Canada and Ontario where we currently operate, as well as in Quebec and Newfoundland and Labrador. The principal provincial laws and regulations which affect where we currently operate include, in Alberta, the Alberta Land Stewardship Act, the Environmental Protection and Enhancement Act, and the Climate Change and Emissions Management Act. In British Columbia, these include the Environmental Management Act, the Environmental Assessment Act, the Oil and Gas Activities Act, the Environmental Protection and Management Regulation, the Carbon Tax Act, the Greenhouse Gas Reduction (Cap and Trade) Act, and the Oil and the Water Protection Act. In Saskatchewan, these include the Oil and Gas Conservation Act, and the Management and Reduction of Greenhouse Gasses Act. In Ontario, the principal provincial laws include the Environmental Protection Act, the Green Energy Act, the Ontario Water Resources Act and the Environmental Assessment Act. These laws and regulations may impose numerous obligations that are applicable to our and our customer’s operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our or our customers’ operations, the imposition of specific standards addressing worker protection, and the imposition of substantial liabilities and remedial obligations for pollution or contamination resulting from our and our customer’s operations.
 
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These laws and regulations may impose numerous obligations that are applicable to our and our customer’s operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our or our customers’ operations, the imposition of specific standards addressing worker protection, and the imposition of substantial liabilities and remedial obligations for pollution or contamination resulting from our and our customer’s operations.
 
Compliance with this complex array of laws and regulations is difficult and may require us to make significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licenses or authorizations, civil liability for, among other things, pollution damage and the imposition of material fines. Our customers’ operations may be subject to existing and future CAA permitting and regulatory requirements that could have a material effect on their operations. For example, on August 16, 2012, the EPA published final rules that establish new air emission controls for oil and natural gas production and natural gas processing operations under the CAA and/or Canadian climate change control. The EPA’s rule package requires new standards on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules also establish new emission requirements for compressors, controllers, dehydrators, storage tanks, natural gas processing and certain other equipment used in the hydraulic fracturing process. In Canada, Alberta’s Climate Change and Emissions Management Act as well as British Columbia’s Greenhouse Gas Reduction (Cap and Trade) Act impose requirements to reduce emission intensity, and in the case of the Greenhouse Gas Reduction (Cap and Trade) Act, impose absolute caps on greenhouse gas emissions. Saskatchewan’s Management and Reduction of Greenhouse Gases Act aims to adopt a goal of a 20% reduction in greenhouse gas emissions from 2006 levels by 2020. Certain other provinces including British Columbia, Manitoba and Ontario are parties to the Western Climate Initiative, which has established a goal to reduce greenhouse gas emissions in the region by 15% below 2005 levels, by 2020. Given the evolving nature of the debate related to climate control and control of greenhouse gases, compliance with these rules could result in significant costs to our customers, which may have an indirect adverse impact on our business.

Numerous governmental authorities, such as the EPA, and analogous state and provincial agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly corrective actions or costly pollution control measures. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our and our customer’s operations. Under the terms of our amended and restated omnibus agreement, Holdings will indemnify us for certain potential claims, losses and expenses relating to environmental matters and associated with the operation of the assets contributed to us and occurring before the closing date of our IPO. However, the liability of Holdings for these indemnification obligations is subject to a $350,000 deductible. Moreover, our assets constitute a substantial portion of Holdings’ assets, and Holdings has not agreed to maintain any cash reserve to fund any indemnification obligations under our amended and restated omnibus agreement. In addition, changes in environmental laws occur frequently, and any such changes that result in more stringent and costly requirements would not be covered by the environmental indemnity and could have a material adverse effect on our operations or financial position.
 
Our operations also pose risks of environmental liability due to leakage, migration, releases or spills from our operations to surface or subsurface soils, surface water or groundwater. Some environmental laws and regulations in both the U.S. and Canada may impose strict, joint and several liabilities in connection with releases of regulated substances into the environment. Therefore, in some situations we could be exposed to liability as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, third parties.

Laws protecting the environment generally have become more stringent over time. We expect this trend to continue, which could lead to material increases in our costs for future environmental compliance and remediation, and could adversely affect our operations by restricting the way in which we treat and dispose of exploration and production, or E&P, waste or our ability to expand our business.

In particular, the RCRA, which governs the disposal of solid and hazardous waste, currently exempts certain E&P wastes from classification as hazardous wastes. In recent years, proposals have been made to rescind this exemption from RCRA. For example, in September 2010 an environmental group filed a petition with the EPA requesting reconsideration of this RCRA exemption. To date, the EPA has not taken any action on the petition. If the exemption covering E&P wastes is repealed or modified, or if the regulations interpreting the rules regarding the treatment or disposal of this type of waste were changed, our operations could face significantly more stringent regulations, permitting requirements, and other restrictions, which could have a material adverse effect on our business.
 
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The effect of changes to healthcare laws in the United States may materially increase the healthcare costs attributable to us and, to the extent we are responsible for those increased costs, negatively impact our financial results.

The Patient Protection and Affordable Care Act as well as other healthcare reform legislation considered by federal and state legislators could significantly impact our business. These health care reform laws require employers such as us, to provide health insurance for all qualifying employees or pay penalties for not providing coverage. We cannot predict the effects this legislation or any future state or federal healthcare legislation or regulation will have on our business because of the breadth and complexity of the legislation and because many of the rules, reforms and regulations required to implement these laws have not yet been adopted. However, we expect this legislation to materially increase the employee healthcare and other related costs attributable to us to the extent we become responsible for the full amount of our entire general and administrative services under our amended and restated omnibus agreement, which currently limits our corporate general and administrative services to an annual administrative fee of $4.04 million, as adjusted for inflation. As the provisions of this legislation are phased in over time, the resulting changes to our healthcare cost structure and any inability to effectively modify our programs and operations in response to this legislation could have a material adverse effect on our business, financial conditions and results of operations.

We could incur significant costs in cleaning up contamination that occurs at our facilities.

Petroleum hydrocarbons, saltwater, and other substances and wastes arising from E&P related activities have been disposed of or released on or under many of our sites. At some of our facilities, we have conducted and may continue to conduct monitoring, and we will continue to perform such monitoring and remediation of known contamination until the appropriate regulatory standards have been achieved. These monitoring and remediation efforts are usually overseen by state environmental regulatory agencies. Costs for such remediation activities may exceed estimated costs, and there can be no assurance that the future costs will not be material. It is possible that we may identify additional contamination in the future, which could result in additional remediation obligations and expenses, which could be material.

We and our customers may be exposed to certain regulatory and financial risks related to climate change.

In response to certain scientific studies suggesting that emissions of GHGs, including carbon dioxide and methane, are contributing to the warming of the Earth’s atmosphere and other climatic conditions, the U.S. Congress has considered adopting legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap-and-trade programs. Most of these cap-and-trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. These allowances would be expected to escalate significantly in cost over time.

In addition, in December 2009, the EPA determined that emissions of carbon dioxide, methane and certain other GHGs endanger public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the CAA. The EPA has already adopted two sets of rules regulating GHG emissions under the CAA, one of which requires a reduction in emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources, both of which became effective in January 2011. The EPA’s rules relating to emissions of GHGs from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent the EPA from implementing or requiring state environmental agencies to implement the rules. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified GHG emission sources in the U.S., including oil and natural gas producer operations, on an annual basis. Additionally, on September 20, 2013, the EPA proposed New Source Performance Standards for Greenhouse Gas emissions from Electric Utility Generating Units and issued the proposed Clean Power Plan in June 2014 that would, among other things, limit GHG emissions from existing coal-fired power plants. These actions represent increased government regulation of climate change-related issues and GHG emissions. We cannot predict which areas, if any, the EPA may choose to regulate with respect to GHG emissions next.

Although it is not possible at this time to estimate how potential future laws or regulations addressing GHG emissions would impact our business, either directly or indirectly, any future federal, state or local laws or implementing regulations that may be adopted to address GHG emissions in areas where we operate could require us or our customers to incur increased operating costs. Regulation of GHGs could also result in a reduction in demand for and production of oil and natural gas, which would result in a decrease in demand for our services. We cannot predict with any certainty at this time how these possibilities may affect our operations, but effects could be materially adverse.

Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for the oil or natural gas produced by our customers or otherwise cause us to incur significant costs in preparing for or responding to those effects.

Certain plant or animal species could be designated as endangered or threatened, which could limit our ability to expand some of our existing operations or limit our customers’ ability to develop new oil and natural gas wells.

ESA restricts activities that may affect endangered or threatened species or their habitats. Many states also have analogous laws designed to protect endangered or threatened species. The designation of previously unidentified endangered or threatened species under such laws may affect our and our customers’ operations.
 
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For example, the federal government is considering listing the greater sage-grouse, a species whose natural habitats coincide with some of our areas of operation and the areas of operation of some of our customers. Currently, greater sage-grouse are found in Washington, Oregon, Idaho, Montana, North Dakota, eastern California, Nevada, Utah, western Colorado, South Dakota and Wyoming. The U.S. Fish and Wildlife Service, or “Service”, has concluded that the greater sage-grouse warrants protection under the ESA; however, the Service has determined that proposing the species for protection is precluded by the need to take action on other species facing more immediate and severe extinction threats. As a result, the greater sage-grouse will be placed on the list of species that are candidates for ESA protection. The lesser prairie-chicken, which currently occupies a five-state range that includes Texas, New Mexico, Oklahoma, Kansas and Colorado was also listed as threatened in March 2014. The Service will review the status of these species annually, as it does with all candidate species, and will propose the species for protection when funding and workload priorities for other listing actions allow. Additionally, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the Service is required to make a determination on the listing of more than 250 species as endangered or threatened under the ESA by the end of the Service’s 2017 fiscal year. Another species, the dunes sagebrush lizard, which is found only in the active and semi-stable shinnery oak dunes of southeastern New Mexico and adjacent portions of Texas, was a candidate species for listing under the ESA by the Service for many years. On June 13, 2012, however, the Service declined to list the species as endangered under the ESA, and it is no longer a candidate species. Nevertheless, the species remains listed as endangered by the New Mexico Department of Game and Fish, and thus is subject to certain protections under New Mexico state law.

We have customers in New Mexico, Texas, Oklahoma, Wyoming and North Dakota that have operations within the habitat of the greater sage-grouse and the lesser prairie-chicken, and our own operations are strategically located in proximity to our customers. To the extent these species, or other species that live in the areas where our operations and our customers’ operations are conducted, are listed under the ESA or similar state laws, this could limit our ability to expand our operations and facilities or could force us to incur material additional costs. Moreover, listing such species under the ESA or similar state laws could indirectly but materially affect our business by imposing constraints on our customers’ operations.
 
We must comply with worker health and safety laws and regulations at our facilities and in connection with our operations and failure to do so could result in significant liability and/or fines and penalties.

Our activities are subject to a wide range of national, state and local occupational health and safety laws and regulations. These health and safety laws are subject to change, as are the priorities of those who enforce them. Failure to comply with these health and safety laws and regulations could lead to third-party claims, criminal and regulatory violations, civil fines and changes in the way we operate our facilities, which could increase the cost of operating our business and have a material adverse effect on our financial position, results of operations and cash flows and our ability to make cash distributions to our unitholders. Our safety and compliance record is important to our clients and can materially impact our business.

Changes in the provincial royalty rates and drilling incentive programs in Canada could decrease the oil and gas exploration and pipeline activities in Canada, which could adversely affect the demand for our pipeline inspection services.

Certain provincial governments collect royalties on the production from lands owned by the government of Canada. These fiscal royalty regimes are reviewed and adjusted from time to time by the respective provincial governments for appropriateness and competitiveness. Any increase in the royalty rates assessed by, or any decrease in the drilling incentive programs offered by, a provincial government could negatively affect the drilling activity and the need for pipelines and gathering systems, which could adversely affect the demand for our pipeline inspection services.

Our business involves many hazards, operational risks and regulatory uncertainties, some of which may not be fully covered by insurance. If a significant accident or event occurs for which we are not adequately insured or if we fail to recover all anticipated insurance proceeds for significant accidents or events for which we are insured, our operations and financial results could be adversely affected.

Risks inherent to our industry, such as equipment defects, vehicle accidents, explosions, earthquakes, lightning strikes and incidents related to the handling of fluids and wastes, can cause personal injury, loss of life, suspension of operations, damage to formations, damage to facilities, business interruption and damage to or destruction of property, equipment and the environment. We use fiberglass tanks at our SWD facilities because fiberglass is less corrosive than other materials traditionally utilized. These tanks are, however, more prone to lighting strikes than traditional tanks, as a result of fiberglass’ tendency to store static electricity. The lightning protection systems we employ may not succeed in preventing lightning from damaging a facility. The risks associated with these types of accidents could expose us to substantial liability for personal injury, wrongful death, property damage, pollution and other environmental damages. The frequency and severity of such incidents will affect operating costs, insurability and relationships with customers, employees and regulators. In particular, our customers may elect not to purchase our services if they view our safety record as unacceptable, which could cause us to lose customers and substantial revenues.

Our insurance coverage may be inadequate to cover our liabilities. For instance, while our insurance policies apply to and cover costs imposed on us by retroactive changes in governmental regulations, the costs we incur as a result of such regulatory changes cannot be known in advance and may exceed our coverage limitations. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable and commercially justifiable and insurance may not continue to be available on terms as favorable as our current arrangements. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations and cash flows. In some cases, electrical storms can damage facility motors or electronics, and it may not be possible to prove to the insurance carrier that such storm caused the damage. We do not carry business interruption insurance on our SWD facilities and as a result, could suffer a significant loss in revenue that could impact our ability to pay distributions on our units.
 
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Accidents or incidents related to the handling of hydraulic fracturing fluids, saltwater or other wastes are covered by our insurance against claims made for bodily injury, property damage or environmental damage and clean-up costs stemming from a sudden and accidental pollution event, provided that we report the event within 30 days after its commencement. The coverage applies to incidents the company is legally obligated to pay resulting from pollution conditions caused by covered operations. We may not have coverage if the operator is unaware of the pollution event and unable to report the “occurrence” to the insurance company within the required time frame. Although we have coverage for gradual, long-term pollution events at certain locations, this coverage does not extend to all places where we may be located or where we may do business. We also may have liability exposure if any pipelines or gathering systems transporting water to our SWD facilities develop a leak depending upon the terms of the contracts.

A failure by our employees to follow applicable procedures and guidelines or on-site accidents could have a material adverse effect on our business.

We require our employees to comply with various internal procedures and guidelines, including an environmental management program and worker health and safety guidelines. The failure by our employees to comply with our internal environmental, health and safety guidelines could result in personal injuries, property damage or non-compliance with applicable governmental laws and regulations, which may lead to fines, remediation obligations or third-party claims. Any such fines, remediation obligations, third-party claims or losses could have a material adverse effect on our financial position, results of operations and cash flows. In addition, on-site accidents can result in injury or death to our or other contractors’ employees or damage to our or other contractors’ equipment and facilities and damage to other people, truck drivers, area residents and property. Any fines or third-party claims resulting from any such on-site accidents could have a material adverse effect on our business.
 
In addition, while an inspector is performing pipeline inspection or integrity services for TIR LLC, the inspector is considered an employee of TIR LLC and is eligible for workers’ compensation claims if the inspector is injured or killed while working for TIR LLC. As the inspectors generally travel to and from projects in their own vehicles, TIR LLC may be responsible for workers compensation claims or third-party claims arising out of vehicle accidents, which could negatively affect our results of operation.
 
Our ability to retain existing customers and attract new business is dependent on many factors, including our ability to demonstrate that we can reliably and safely operate our business and stay current on constantly changing rules, regulations, training, and laws. Existing and potential customers consider the safety record of their service providers to be of high importance in their decision to engage third-party servicers. If one or more accidents were to occur at one of our operating sites, or pipelines or gathering systems we inspect, the affected customer may seek to terminate or cancel its use of our facilities or services and may be less likely to continue to use our services. In addition, it is possible that we will experience numerous or particularly severe accidents in the future, causing our safety record to deteriorate. This may be more likely as we continue to grow, if we experience high employee turnover or labor shortage, or add inexperienced personnel. In addition, we could be subject to liability for damages as a result of such accidents and could incur penalties or fines for violations of applicable safety laws and regulations.

Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas and our customers’ drilling and production activities, and therefore the amount of drilling and production waste provided to us for treatment and disposal. Management cannot predict the impact of the changing demand for oil and natural gas services and products, and any major changes may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Due to our lack of asset and geographic diversification, adverse developments in the areas in which we are located could adversely impact our financial condition, results of operations and cash flows and reduce our ability to make distributions to our unitholders.
 
Our SWD facilities are located exclusively in North Dakota and Texas. This concentration could disproportionately expose us to operational, economic and regulatory risk in these areas. Additionally, our SWD facilities currently comprise ten owned and three other managed facilities. Any operational, economic or regulatory issues at a single facility could have a material adverse impact on us. Due to the lack of diversification in our assets and the location of our assets, adverse developments in the our markets, including, for example, transportation constraints, adverse regulatory developments, or other adverse events at one of our SWD facilities, could have a significantly greater impact on our financial condition, results of operations and cash flows than if we were more diversified.
 
New technology, including those involving recycling of saltwater or the replacement of water in fracturing fluid, may hurt our competitive position.

The saltwater disposal industry is subject to the introduction of new waste treatment and disposal techniques and services using new technologies including those involving recycling of saltwater, some of which may be subject to patent protection. As competitors and others use or develop new technologies or technologies comparable to ours in the future, we may lose market share or be placed at a competitive disadvantage. For example, some companies have successfully used propane as the fracturing fluid instead of water. Further, we may face competitive pressure to implement or acquire certain new technologies at a substantial cost. Some of our competitors may have greater financial, technical and personnel resources than we do, which may allow them to gain technological advantages or implement new technologies before we can. Additionally, we may be unable to implement new technologies or products at all, on a timely basis or at an acceptable cost. New technology could also make it easier for our customers to vertically integrate their operations or reduce the amount of waste produced in oil and natural gas drilling and production activities, thereby reducing or eliminating the need for third-party disposal. Limits on our ability to effectively use or implement new technologies may have a material adverse effect on our business, financial condition and results of operations.
 
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Technology advancements in connection with alternatives to hydraulic fracturing could decrease the demand for our SWD facilities.

Some oil and natural gas producers are focusing on developing and utilizing non-water fracturing techniques, including those utilizing propane, carbon dioxide or nitrogen instead of water. If our producing customers begin to shift their fracturing techniques to waterless fracturing in the development of their wells, our saltwater disposal services could be materially impacted as these wells would not produce flowback water. In particular, our SWD facilities in west Texas could be negatively affected by these new technologies, as the drought conditions of west Texas make fracturing with materials other than water attractive alternatives.

We may be unable to ensure that customers will continue to utilize our services or facilities and pay rates that generate acceptable margins for us.

We cannot ensure that customers will continue to pay rates that generate acceptable margins for us. Our margins for W&ES could decrease if the volume of saltwater processed and disposed of by our customers’ decreases or if we are unable to increase the rates charged to correspond with increasing costs of operations. Our revenues and profitability for PI&IS could decrease if the demand for our inspectors decrease, if our safety record declines and we are unable to obtain affordable insurance, if we are unable to recruit and retain qualified inspectors or if we are unable to increase the daily and hourly rates charged to correspond with increasing costs of operations. In addition, new agreements for our services in both of these business segments entered into by us may not be obtainable on terms acceptable to us or, if obtained, may not be obtained on terms consistent with current practices, in which case our revenue and profitability could decline. We also cannot ensure that the parties from whom we lease, license or otherwise occupy the land on which certain of our facilities are situated, or the parties from whom we lease certain of our equipment, will renew our current leases, licenses or other occupancy agreements upon their expiration on commercially reasonable terms or at all. Any such failure to honor the terms of the leases or licenses or renew our current leases or licenses could have a material adverse effect on our financial position, results of operations and cash flows.

We may be unable to attract and retain a sufficient number of skilled and qualified workers.
 
The delivery of our water and environmental services and products requires personnel with specialized skills and experience who can perform physically demanding work. The saltwater disposal industry has experienced a high rate of employee turnover as a result of the volatility of the oilfield service industry and the demanding nature of the work, and workers may choose to pursue employment in fields that offer a less demanding work environment. In addition, PI&IS is dependent on the TIR Entities’ specialized inspectors, who must undergo specific training prior to performing inspection services.

Our ability to be productive and profitable will depend upon our ability to employ and retain skilled workers. In addition, our ability to expand our operations depends in part on our ability to increase the size of our skilled labor force. The demand for skilled workers is high, and the supply is limited. A significant increase in the wages paid by competing employers or the unionization of groups of our employees could result in a reduction of our skilled labor force, increases in the wage rates that we must pay, or both. In addition, the U.S. customers in PI&IS could choose to hire TIR LLC’s inspectors directly. If any of these events were to occur, our capacity and profitability could be diminished and our growth potential could be impaired.
 
Our ability to operate our business effectively could be impaired if affiliates of our general partner fail to attract and retain key management personnel.

We depend on the continuing efforts of our executive officers and other key management personnel, all of whom are employees of affiliates of our general partner. Additionally, neither we nor our subsidiaries have employees. CEM LLC and its affiliates are responsible for providing the employees and other personnel necessary to conduct our operations. All of the employees that conduct our business are employed by affiliates of our general partner, including our President and Chief Executive Officer, Peter C. Boylan III, and our Vice President and Chief Financial Officer, G. Les Austin. The loss of any member of our management or other key employees could have a material adverse effect on our business. Consequently, our ability to operate our business and implement our strategies will depend on the continued ability of affiliates of our general partner to attract and retain highly skilled management personnel with industry experience. Competition for these persons is intense. Given our size, we may be at a disadvantage, relative to our larger competitors, in the competition for these personnel. We may not be able to continue to employ our senior executives and other key personnel or attract and retain qualified personnel in the future, and our failure to retain or attract our senior executives and other key personnel could have a material adverse effect on our ability to effectively operate our business.
 
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Our business would be adversely affected if we or our customers experience significant interruptions.
 
We are dependent upon the uninterrupted operations of our SWD facilities for the processing of saltwater, as well as the operations of third-party facilities, such as our oil and natural gas producing customers, for uninterrupted demand of our water and environmental services. Any significant interruption at these facilities or inability to transport products to or from the third-party facilities to our SWD facilities for any reason would adversely affect our results of operations, cash flow and ability to make distributions to our unitholders. Operations at our facilities and at the facilities owned or operated by our customers could be partially or completely shut down, temporarily or permanently, as the result of any number of circumstances that are not within our control, such as:

· catastrophic events, including hurricanes, seismic activity such as earthquakes, lightning strikes, fires and floods;

· loss of electricity or power;

· explosion, breakage, loss of power, accidents to machinery, storage tanks or facilities;

· leaks in packers and tubing below the surface, failures in cement or casing or ruptures in the pipes, valves, fittings, hoses, pumps, tanks, containment systems or houses that lead to spills or employee injuries;

· environmental remediation;

· pressure issues that limit or restrict our ability to inject water into the disposal well or limitations with the injection zone formation and its permeability or porosity that could limit or prevent disposal of additional fluids;

· labor difficulties;

· malfunctions in automated control systems at the facilities;

· disruptions in the supply of saltwater to our facilities;

· failure of third-party pipelines, pumps, equipment or machinery; and

· governmental mandates, restrictions or rules and regulations.

In addition, there can be no assurance that we are adequately insured against such risks. As a result, our revenue and results of operations could be materially adversely affected.

The seasonal nature of the oilfield service industry in Canada may negatively affect us and our customers.

In Canada, the level of activity in the oilfield services industry is influenced by seasonal weather patterns. As warm weather returns in the spring, the winter’s frost comes out of the ground (commonly referred to as “spring break up”) rendering many secondary roads incapable of supporting heavy loads, and as a result road bans are implemented prohibiting heavy loads from being transported in certain areas. As a result, the movement of the heavy equipment required for drilling and well servicing activities is restricted and the level of activity of our Canadian operations and the operations of our customers are consequently reduced.

The amount of cash we have available for distribution to holders of our common and subordinated units depends primarily on our cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in which we record net income.

The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by depreciation, amortization, impairment loss and other non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.

Increases in interest rates could adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes, and our ability to make cash distributions at our intended levels.

Interest rates may increase in the future. As a result, interest rates on our credit facilities or future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price will be impacted by our level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue equity or incur debt for acquisitions or other purposes and to make cash distributions at our intended levels.
 
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A failure in our operational and communications systems, loss of power, natural disasters, or cyber security attacks on any of our facilities, or those of third-parties, may adversely affect our financial results.

Our business is dependent upon our operational systems to process a large amount of data and a substantial number of transactions. 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 or financial 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 will result in losses that are difficult to detect.

Due to technology advances, we have become more reliant on technology to help increase efficiency in our business. We use computer programs to help run our financial and operations processes, and this may subject our business to increased risks. Any future cyber security attacks that affect our facilities, communications systems, our customers or any of our financial data could have a material adverse effect on our business. In addition, cyber-attacks on our customer and employee data may result in a financial loss and may negatively impact our reputation. We do not maintain specialized insurance for possible liability resulting from a cyber-attack on our assets that may shut down all or part of our business. Third-party systems on which we rely could also suffer operational system failure. Any of these occurrences could disrupt our business, result in potential liability or reputational damage or otherwise have an adverse effect on our financial results.

If we fail to develop or maintain an effective system of internal controls, we may not be able to report our financial results accurately or prevent fraud, which would likely have a negative impact on the market price of our common units.
 
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and to operate successfully as a publicly traded partnership. Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, or “Section 404”. For example, Section 404 requires, among other things, us to annually review and report on, and (except as described below) our independent registered public accounting firm to attest to, the effectiveness of our internal controls over financial reporting. Any failure to develop, implement or maintain effective internal controls or to improve our internal controls could harm our operating results or cause us to fail to meet our reporting obligations. Given the difficulties inherent in the design and operation of internal controls over financial reporting, we can provide no assurance as to our, or our independent registered public accounting firm’s conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404. Ineffective internal controls could subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units. We currently utilize two distinct accounting systems for our business, one for the TIR Entities and one for the remainder of our business. We may experience difficulties consolidating these accounting systems, or may be delayed in implementing our plan to consolidate these systems, and any such difficulties or delay may impact our ability to timely file reports with the SEC and/or to comply with the covenants under our current and future credit facilities.
 
We are required to disclose changes made in our internal control over financial reporting on a quarterly basis, and we are required to assess the effectiveness of our controls annually. However, for as long as we are an “emerging growth company” under the Jumpstart Our Business Startups Act of 2012, or the JOBS Act, our independent registered public accounting firm will not be required to attest to the effectiveness of our internal controls over financial reporting pursuant to Section 404. We could be an emerging growth company for up to five years following the closing of our IPO. Even if we conclude that our internal controls over financial reporting are effective, our independent registered public accounting firm may issue a report that is qualified if it is not satisfied with our controls or the level at which our controls are documented, designed, operated or reviewed, or if it interprets the relevant requirements differently from us.

A sustained failure of our information technology systems could adversely affect our business.

An enterprise-wide information system will be developed and integrated into our operations. If our information technology systems are disrupted due to problems with the integration of our information system or otherwise, we may face difficulties in generating timely and accurate financial information. Such a disruption to our information technology systems could have an adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders. In addition, we may not realize the benefits we anticipate from the implementation of our enterprise-wide information system.

Risks Inherent in an Investment in Us
 
Our general partner and its affiliates, including Holdings, have conflicts of interest with us and limited fiduciary duties to us and our unitholders, and they may favor their own interests to our detriment and that of our unitholders. Additionally, we have no control over the business decisions and operations of Holdings, and Holdings is under no obligation to adopt a business strategy that favors us.

Holdings and its affiliates own a 58.8% limited partner interest in us and own and control our general partner and appoint all of the officers and directors of our general partner. Although our general partner has a duty to manage us in a manner that is in the best interests of our partnership and our unitholders, the directors and officers of our general partner also have a fiduciary duty to manage our general partner in a manner that is in the best interests of its owner, Holdings. Conflicts of interest may arise between Holdings and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates, including Holdings, over the interests of our common unitholders. These conflicts include, among others, the following situations:
 
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neither our partnership agreement nor any other agreement requires Holdings to pursue a business strategy that favors us or utilizes our assets, which could involve decisions by Holdings to invest in competitors, pursue and grow particular markets, or undertake acquisition opportunities for itself. Holdings’ directors and officers have a fiduciary duty to make these decisions in the best interests of Holdings;

our general partner is allowed to take into account the interests of parties other than us, such as Holdings, in resolving conflicts of interest;

Holdings may be constrained by the terms of its debt instruments from taking actions, or refraining from taking actions, that may be in our best interests;
 
our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limiting our general partner’s liabilities and restricting the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty;

except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;

our general partner will determine the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of cash reserves, each of which can affect the amount of cash that is distributed to our unitholders;

expenditure, which would not reduce operating surplus, or a maintenance capital expenditure, which would reduce our operating surplus, and whether to set aside cash for future maintenance capital expenditures on certain of our assets that will need extensive repairs during their useful lives. This determination can affect the amount of available cash from operating surplus that is distributed to our unitholders and to our general partner, the amount of adjusted operating surplus generated in any given period and the ability of the subordinated units to convert into common units;

our general partner will determine which costs incurred by it are reimbursable by us;

our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period;

our partnership agreement permits us to classify up to $10.0 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or to our general partner in respect of the general partner interest or the incentive distribution rights;

our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

our general partner intends to limit its liability regarding our contractual and other obligations;
 
our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if it and its affiliates own more than 80.0% of the common units;

our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates;

our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and

our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner, which we refer to as our conflicts committee, or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

Under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers, directors and owners. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders. Please read “Item 13 – Certain Relationships and Related Party Transactions – Conflicts of Interest and Duties.”
 
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Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

Our partnership agreement requires that we distribute all of our available cash to our unitholders. As a result, we expect to rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. Therefore, to the extent we are unable to finance our growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we will distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement, and we do not anticipate there being limitations in our indebtedness, on our ability to issue additional units, including units ranking senior to our common units as to distributions or in liquidation or that have special voting rights and other rights, and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such additional units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may reduce the amount of cash that we have available to distribute to our unitholders.

Our partnership agreement replaces our general partner’s fiduciary duties to holders of our common units with contractual standards governing its duties.
 
Our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, free of any duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing. This provision entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

· how to allocate corporate opportunities among us and its affiliates;

· whether to exercise its limited call right;

· whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the board of directors of our general partner;

· how to exercise its voting rights with respect to the units it owns;

· whether to elect to reset target distribution levels;

· whether to transfer the incentive distribution rights or any units it owns to a third party; and

· whether or not to consent to any merger, consolidation or conversion of the partnership or amendment to the partnership agreement.

By purchasing a common unit, a unitholder is treated as having consented to the provisions in our partnership agreement, including the provisions discussed above. Please read “Item 13 – Certain Relationships and Related Party Transactions – Conflicts of Interest and Duties.”

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements so that counterparties to such agreements have recourse only against our assets and not against our general partner or its assets or any affiliate of our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained terms that are more favorable without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.
 
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Our partnership agreement restricts the remedies available to holders of our common and subordinated units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement:

· provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the determination or the decision to take or decline to take such action was in the best interests of our partnership, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

· provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith;

· provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in intentional fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful; and

· provides that our general partner will not be in breach of its obligations under our partnership agreement or its fiduciary duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is approved in accordance with, or otherwise meets the standards set forth in, our partnership agreement.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, our partnership agreement provides that any determination by our general partner must be made in good faith, and that our conflicts committee and the board of directors of our general partner are entitled to a presumption that they acted in good faith. In any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Please read “Item 13 – Certain Relationships and Related Party Transactions – Conflicts of Interest and Duties.”
 
Cost reimbursements and fees due to Holdings for services provided to us or on our behalf following the expiration of our amended and restated omnibus agreement could be substantial and will reduce our cash available for distribution to our unitholders.
 
Pursuant to our amended and restated omnibus agreement, prior to making any distributions to our unitholders, we will pay Holdings a quarterly administrative fee of $1.01 million for the provision of certain general and administrative expenses. This fee is subject to increase by an amount equal to the producer price index plus one percent or, with the concurrence of the conflicts committee, in the event of an expansion of our operations, including through acquisitions or internal growth. The amount of this fee is below the amount we would expect to reimburse the general partner for such services in the absence of the fee. In the event of termination of our amended and restated omnibus agreement, in lieu of the quarterly fee, we will be required by our partnership agreement to reimburse Holdings and its affiliates for all costs and expenses that they incur on our behalf for managing and controlling our business and operations, at which time we expect our payment for these services to increase. This increase may be substantial. Our partnership agreement provides that Holdings will determine in good faith the expenses that are allocable to us. Furthermore, Holdings and its affiliates will allocate other expenses related to our operations to us and may provide us other services for which we will be charged fees as determined by Holdings. Payments to Holdings and its affiliates following the expiration of our amended and restated omnibus agreement could be substantial and will reduce the amount of cash we have available to distribute to unitholders.

Unitholders have very limited voting rights and, even if they are dissatisfied, they cannot remove our general partner without its consent.
 
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. For example, unlike holders of stock in a public corporation, unitholders will not have “say-on-pay” advisory voting rights. Unitholders did not elect our general partner or the board of directors of our general partner and will have no right to elect our general partner or the board of directors of our general partner on an annual or other continuing basis. The board of directors of our general partner is chosen by the member of our general partner, which is a wholly owned subsidiary of Holdings. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which our common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
 
The unitholders will be unable initially to remove our general partner without its consent because our general partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding common units and subordinated units voting together as a single class is required to remove our general partner. Holdings and its affiliates own 58.8% of the common units and subordinated units (excluding common units purchased by certain of our officers, directors and other affiliates in our IPO). Also, if our general partner is removed without cause during the subordination period and common units and subordinated units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically be converted into common units, and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests.
 
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“Cause” is narrowly defined under our partnership agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud or willful misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of our general partner because of the unitholders’ dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the termination of the subordination period and conversion of our subordinated units to common units.

Furthermore, unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20.0% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees, and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.

Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.
 
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of Holdings to transfer its membership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own choices.
 
We may issue additional units without unitholder approval, which would dilute unitholders’ existing ownership interests.

At any time, we may issue an unlimited number of general partner interests or limited partner interests of any type without the approval of our unitholders and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such general partner interests or limited partner interests. Further, there are no limitations in our partnership agreement on our ability to issue equity securities that rank equal or senior to our common units as to distributions or in liquidation or that have special voting rights and other rights. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

· our existing unitholders’ proportionate ownership interest in us will decrease;

· the amount of cash we have available to distribute on each unit may decrease;

· because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

· the ratio of taxable income to distributions may increase;

· the relative voting strength of each previously outstanding unit may be diminished; and

· the market price of our common units may decline.
 
The issuance by us of additional general partner interests may have the following effects, among others, if such general partner interests are issued to a person who is not an affiliate of Holdings:
 
· management of our business may no longer reside solely with our current general partner; and

· affiliates of the newly admitted general partner may compete with us, and neither that general partner nor such affiliates will have any obligation to present business opportunities to us.

Holdings or its unitholders, directors or officers may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.

Holdings and CEP-TIR hold 1,344,650 common units and 5,612,699 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and may convert earlier under certain circumstances. Additionally, we have agreed to provide Holdings and CEP-TIR with certain registration rights under applicable securities laws. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.
 
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Our general partner’s discretion in establishing cash reserves may reduce the amount of cash we have available to distribute to unitholders.

Our partnership agreement requires our general partner to deduct from operating surplus the cash reserves that it determines are necessary to fund our future operating expenditures. In addition, the partnership agreement permits the general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party, or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash we have available to distribute to unitholders.

Affiliates of our general partner, including, but not limited to, Holdings, may compete with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us.

Neither our partnership agreement nor our amended and restated omnibus agreement will prohibit Holdings or any other affiliates of our general partner from owning assets or engaging in businesses that compete directly or indirectly with us. Under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to our general partner or any of its affiliates, including Holdings. Any such entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Moreover, except for the obligations set forth in our amended and restated omnibus agreement, neither Holdings nor any of its affiliates have a contractual obligation to offer us the opportunity to purchase additional assets from it, and we are unable to predict whether or when such an offer may be presented and acted upon. As a result, competition from Holdings and other affiliates of our general partner could materially and adversely impact our results of operations and distributable cash flow.

Our right of first offer on certain of Holdings’ assets is subject to risks and uncertainty, and ultimately we may not acquire any of those assets.

Our amended and restated omnibus agreement provides us with a right of first offer on certain assets owned by and ownership interests held by Holdings and its subsidiaries that they decide to sell during the five-year period following the closing of our IPO. The consummation and timing of any acquisition by us of the assets covered by our right to first offer will depend upon, among other things, our ability to reach an agreement with Holdings on price and other terms and our ability to obtain financing on acceptable terms. Accordingly, we can provide no assurance whether, when or on what terms we will be able to successfully consummate any future acquisitions pursuant to our right of first offer, and Holdings is under no obligation to accept any offer that we may choose to make or to enter into any commercial agreements with us. For these or a variety of other reasons, we may decide not to exercise our right of first offer when we are permitted to do so, and our decision will not be subject to unitholder approval. In addition, our right of first offer may be, upon a change of control of our general partner, or by agreement between us and Holdings, terminated by Holdings at any time after it no longer controls our general partner.

Our general partner has a limited call right that may require our unitholders to sell their common units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80.0% of our then-outstanding common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on unitholders’ investment. Unitholders may also incur a tax liability upon a sale of their units. Holdings and its affiliates own approximately 22.7% of our common units (excluding any common units purchased by certain of our officers, directors and other affiliates in our IPO). At the end of the subordination period, assuming no additional issuances of common units by us (other than upon the conversion of the subordinated units), our general partner and its affiliates will own approximately 58.8% of our outstanding common units (excluding any common units purchased by certain of our officers, directors and other affiliates in our IPO) and therefore would not be able to exercise the call right at that time.

Unitholders may have to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Transferees of common units are liable for the obligations of the transferor to make contributions to the partnership that are known to the transferee at the time of the transfer and for unknown obligations if the liabilities could be determined from our partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

The price of our common units may fluctuate significantly, and unitholders could lose all or part of their investment.

There are only 4,312,500 publicly traded common units held by our public unitholders. Holdings and CEP-TIR own 1,344,650 common units and 5,612,699 subordinated units, representing an aggregate 58.8% limited partner interest in us. We do not know how liquid our trading market might be. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.
 
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Our general partner, or any transferee holding incentive distribution rights, may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights, without the approval of our conflicts committee or the holders of our common units. This could result in lower distributions to holders of our common units.

Our general partner has the right, at any time units are outstanding and it has received distributions on its incentive distribution rights at the highest level to which it is entitled (50.0%) for each of the prior four consecutive fiscal quarters and the amount of such distribution did not exceed the adjusted operating surplus for such quarter, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution, and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units equal to that number of common units that would have entitled their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in such two quarters. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive distributions based on the initial target distribution levels. This risk could be elevated if our incentive distribution rights have been transferred to a third party. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that they would have otherwise received had we not issued new common units in connection with resetting the target distribution levels. Additionally, our general partner has the right to transfer all or any portion of our incentive distribution rights at any time, and such transferee shall have the same rights as the general partner relative to resetting target distributions if our general partner concurs that the tests for resetting target distributions have been fulfilled.

The NYSE does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.

Our common units trade on the NYSE. Because we are a publicly traded limited partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Additionally, any future issuance of additional common units or other securities, including to affiliates, will not be subject to the NYSE’s shareholder approval rules that apply to a corporation. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements.

The incentive distribution rights of our general partner may be transferred to a third party without unitholder consent.
 
Our general partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rights to a third party but retains its general partner interest, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its incentive distribution rights. For example, a transfer of incentive distribution rights by our general partner could reduce the likelihood that Holdings, which owns our general partner, will sell or contribute additional assets to us, as Holdings would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.
 
A unitholder’s liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. A unitholder could be liable for any and all of our obligations as if a unitholder were a general partner if a court or government agency were to determine that unitholders’ right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.
 
Tax Risks

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, then our cash available for distribution to our unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes.

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. A change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
 
37

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35.0%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions or credits would flow through to a unitholder. Because a tax would be imposed upon us as a corporation, our cash available for distribution to a unitholder would be substantially reduced. Therefore, if we were treated as a corporation for federal income tax purposes, there would be a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution levels may be adjusted to reflect the impact of that law on us.

If we were subjected to a material amount of additional entity-level taxation by individual states, counties or cities, it would reduce our cash available for distribution to our unitholders.

Changes in current state, county or city law may subject us to additional entity-level taxation by individual states, countries or cities. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to a unitholder. Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to entity-level taxation, the minimum quarterly distribution amount and the target distribution levels may be adjusted to reflect the impact of that law on us.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
 
The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, members of Congress and the President propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships, including the elimination of partnership tax treatment for publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for federal income tax purposes. We are unable to predict whether any such changes will ultimately be enacted. However, it is possible that a change in law could affect us, and any such changes could negatively impact the value of an investment in our common units.
 
Our unitholders’ share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.

Because a unitholder will be treated as a partner to whom we will allocate taxable income that could be different in amount than the cash we distribute, a unitholder’s allocable share of our taxable income will be taxable to it, which may require the payment of federal income taxes and, in some cases, state and local income taxes, on its share of our taxable income even if it receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we take, and the IRS’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner, because the costs will reduce our cash available for distribution to our unitholders and for incentive distributions to our general partner.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If our unitholders sell common units, they will recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of their allocable share of our net taxable income decrease their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to the unitholder if it sells such common units at a price greater than its tax basis in those common units, even if the price received is less than its original cost. Furthermore, a substantial portion of the amount realized on any sale of unitholders’ common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of cash received from the sale.
 
38

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file federal income tax returns and pay tax on their share of our taxable income. If a unitholder is a tax-exempt entity or a non-U.S. person, such unitholder should consult a tax advisor before investing in our common units.

The TIR Entities conduct activities that may not generate qualifying income, and we conduct these activities in a separate subsidiary that is treated as a corporation for U.S. federal income tax purposes. Corporate federal income tax paid by this subsidiary reduces our cash available for distribution.

In order to maintain our status as a partnership for U.S. federal income tax purposes, 90% or more of our gross income in each tax year must be qualifying income under Section 7704 of the Internal Revenue Code. To ensure that 90% or more of our gross income in each tax year is qualifying income, we currently conduct the portion of our business related to these operations in a separate subsidiary that is treated as a corporation for U.S. federal income tax purposes. We estimate that these operations will represent approximately 9% of the combined gross margin of the PI&IS segment for 2015.

This corporate subsidiary will be subject to corporate-level tax, which reduces the cash available for distribution to us and, in turn, to our unitholders. If the IRS were to successfully assert that any corporate subsidiary has more tax liability than we anticipate or legislation were enacted that increased the corporate tax rate, our cash available for distribution to our unitholders would be further reduced.
 
We are in the process of requesting a ruling from the IRS upon which, if granted, we may rely with respect to the qualifying nature of the income from certain activities conducted by TIR LLC. If we do not obtain a favorable ruling from IRS, we will be required to continue to conduct these activities in a subsidiary that is treated as a corporation for U.S. federal income tax purposes and is subject to corporate-level income taxes.
 
We are in the process of requesting a ruling from the IRS upon which, if granted, we may rely with respect to the qualifying nature of the income from certain activities conducted by TIR LLC. If the IRS is unwilling or unable to provide a favorable ruling with respect to such income, we will continue to be subject to corporate-level tax on the revenues generated by such activities. Conversely, if the IRS does provide a favorable ruling, we may choose to conduct such activities in the future in a tax pass-through entity. Such restructuring may result in a significant, one-time tax liability and other costs, which will reduce our cash available for distribution.

We treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury regulations promulgated under the Internal Revenue Code and referred to as “Treasury Regulations.” A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to a unitholder. It also could affect the timing of these tax benefits or the amount of gain from unitholders’ sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to unitholders’ tax returns.

We prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred.

The use of this proration method may not be permitted under existing Treasury Regulations. However, the U.S. Treasury Department has issued proposed regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of those common units. If so, he would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of the loaned common units, he may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income.

We will adopt certain valuation methodologies and monthly conventions for federal income tax purposes that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner for purposes of determining our incentive distributions. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between our general partner, in its capacity as holder of our incentive distribution rights, and certain of our unitholders.
 
39

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

The sale or exchange of 50.0% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50.0% or more of the total interests in our capital and profits within a twelve month period. For purposes of determining whether the 50.0% threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead we would be treated as a new partnership for federal income tax purposes. If treated as a new partnership, we must make new tax elections, including a new election under Section 754 of the Internal Revenue Code, and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has announced a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests publicly traded partnership technical termination relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.

As a result of investing in our common units, a unitholder may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or control property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently own property or conduct business in many states, most of which impose an income tax on individuals, corporations and other entities. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal income tax. It is each unitholder’s responsibility to file all federal, state and local tax returns. Unitholders should consult their tax advisors.

ITEM 1B. UNRESOLVED STAFF COMMENTS

Not Applicable.
 
40

ITEM 2. PROPERTIES

Our Properties

As of December 31, 2014, W&ES had an aggregate of approximately 115,000 barrels of maximum daily disposal capacity in the following SWD facilities, all of which were built since June 2011 with new well bores, using completion techniques consistent with current industry practices and utilizing well depths of at least 5,000 feet and injection intervals beginning at least 4,000 feet beneath the surface:

Location
 
County
 
In-service Date
 
Leased or Owned (3)
Tioga, ND
 
Williams
 
June 2011
 
Owned
Manning, ND
 
Dunn
 
Dec. 2011
 
Owned
Grassy Butte, ND
 
McKenzie
 
May 2012
 
Leased
New Town, ND (1)
 
Mountrail
 
June 2012
 
Leased
Pecos, TX (1)
 
Reeves
 
July 2012
 
Owned
Williston, ND
 
Williams
 
Aug. 2012
 
Owned
Stanley, ND
 
Mountrail
 
Sept. 2012
 
Owned
Orla, TX (1)
 
Reeves
 
Sept. 2012
 
Owned
Belfield, ND
 
Billings
 
Oct. 2012
 
Leased
Watford City, ND (2)
 
McKenzie
 
May 2013
 
Leased
Arnegard, ND (1)
 
McKenzie
 
August 2014
 
Leased
 
(1)
Currently receives piped water.
(2) We own 51.0% of CES, a management and development company that owns a 25.0% non-controlling interest in this SWD facility.
(3) Some facilities are constructed on land that is leased under long term arrangements.

In addition to the above properties, we also manage two other SWD facilities in the Bakken Shale region.
 
Our corporate headquarters are located at 5727 S. Lewis Avenue, Suite 500, Tulsa, Oklahoma 74105.  We lease 7,279 square feet of general office space at our corporate headquarters.  The lease expires in February 2018 unless terminated earlier under certain circumstances specified in our lease.

ITEM 3. LEGAL PROCEEDINGS
 
Stuart v. TIR

In July 2014, a group of former minority shareholders of Tulsa Inspection Resources, Inc. (“TIR Inc.”), formerly an Oklahoma corporation, filed a civil action in the United States District Court for the Northern District of Oklahoma against TIR LLC, members of TIR LLC, and certain affiliates of TIR LLC’s members.  TIR LLC is the successor in interest to TIR Inc., resulting from a merger between the entities that closed in December 2013 (the “TIR Merger”).  The former shareholders in TIR Inc. claim that they did not receive sufficient value for their shares in the TIR Merger and are seeking rescission of the TIR Merger or, alternatively, compensatory and punitive damages.  The Partnership is not named as a defendant in this civil action.  TIR LLC and the other defendants have been advised by counsel that the action lacks merit.  In addition, the Partnership anticipates no disruption in its business operations related to this action.

Fenley v. TIR LLC
 
On February 2, 2015, a former inspector for TIR LLC filed a putative collective action lawsuit alleging that TIR LLC failed to pay a class of workers overtime in compliance with the Fair Labor Standards Act (“FLSA”) titled Fenley v. TIR LLC in the United States District Court for the District of Kansas.  The plaintiff alleges he was a non-exempt employee of TIR and that he and other potential class members were not paid overtime in compliance with the FLSA. The plaintiff seeks to proceed as a collective action and to receive unpaid overtime and other monetary damages, including attorney’s fees. On February 24, 2015, TIR LLC filed a Motion to Dismiss this case, based upon improper venue.  We have retained counsel with experience in cases of this nature and intend to vigorously defend this litigation.

From time to time, we are subject to legal proceedings and claims that arise in the ordinary course of business.  Like other organizations, our operations are subject to extensive and rapidly changing federal and state environmental, health and safety and other laws and regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities.

We are not a party to any other material pending or overtly threatened legal or governmental proceedings, other than proceedings and claims that arise in the ordinary course and are incidental to our business.
 
ITEM 4. MINE SAFETY DISCLOSURES

Not Applicable.
 
41

PART II.
 
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common units are listed on the NYSE under the symbol “CELP.”
 
Our common units began trading on January 15, 2014, at an initial offering price of $20.00 per common unit.  Prior to that time, there was no public market for our common units.  On December 31, 2014, the closing price for the common units was $14.30 per unit and there were approximately 3,750 unitholders of record and beneficial owners (held in street name) of the Partnership’s common units.

We have also issued 5,913,000 subordinated units, for which there is no established public trading market. 5,612,699 of the subordinated units are effectively held by Holdings and its controlled affiliates, either directly or indirectly through its ownership of CEP-TIR.  The remaining 300,301 subordinated units are held directly by certain beneficial owners and management.
 
The high and low trading prices for our common units and distribution paid per unit by quarter were as follows:

    2014  
Quarter Ended
 
High
   
Low
   
Distribution (a)
 
March 31
 
$
26.00
   
$
19.55
   
$
0.301389
(b)
June 30
   
24.97
     
21.65
     
0.396844
 
September 30
   
25.78
     
22.22
     
0.406413
 
December 31
   
24.93
     
11.54
     
0.406413
 
 
(a) Represents declared distributions associated with each respective quarter.  Distributions were declared and paid within 45 days following the close of each quarter in accordance with our cash distribution policy.
(b) Reflects a prorated portion of the targeted minimum quarterly cash distribution of $0.3875 for the period from the closing of the Partnership’s IPO on January 21, 2014 through March 31, 2014.

Our Cash Distribution Policy

Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date.  We intend to continue to make cash distributions to unitholders on a quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors.

Definition of Available Cash

Available cash, for any quarter, consists of all cash and cash equivalents on hand at the end of that quarter:

· less, the amount of cash reserves established by our general partner at the date of determination of available cash for the quarter to:
 
· provide for the proper conduct of our business, which could include, but is not limited to, amounts reserved for capital expenditures, working capital and operating expenses;
 
 
comply with applicable law, any of our debt instruments or other agreements; or
 
· provide funds for distributions to our unitholders (including our general partner) for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for the payment of future distributions unless it determines that the establishment of reserves will not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for such quarter);

· plus, if our general partner so determines, all or a portion of cash on hand on the date of determination of available cash for the quarter, including cash on hand resulting from working capital borrowings made after the end of the quarter.
 
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During Subordination Period

Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter in the following manner during the subordination period:

· first, 100.0% to the common unitholders, pro rata, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;
· second, 100.0% to the common unitholders, pro rata, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;
· third, 100.0% to the subordinated unitholders, pro rata, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and
· thereafter, in the manner described in “General Partner Interest and Incentive Distribution Rights” below.
 
The preceding discussion is based on the assumptions that we do not issue additional classes of equity securities.  Unless earlier terminated pursuant to the terms of our partnership agreement, the subordination period will extend until the first business day of any quarter beginning after December 31, 2016, that the Partnership meets the financial tests set forth in the Partnership Agreement, but may end sooner if the Partnership meets additional financial tests.

After Subordination Period

Our partnership agreement requires that after the subordination period, we make distributions of available cash from operating surplus for any quarter in the following manner:

· first, 100.0% to all unitholders, pro rata, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and
· thereafter, in the manner described in “General Partner Interest and Incentive Distribution Rights” below.

The preceding discussion is based on the assumptions that we do not issue additional classes of equity securities.

General Partner Interest and Incentive Distribution Rights

Incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved.  Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in the partnership agreement.

The following discussion assumes there are no arrearages on common units and that our general partner continues to own the incentive distribution rights.

If for any quarter:

· we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and
· we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, our partnership agreement requires that we distribute any additional available cash from operating surplus for that quarter among the unitholders and the general partner in the following manner:

· first, 100.0% to all unitholders, pro rata, until each unitholder receives a total of $0.445625 per unit for that quarter (the “first target distribution”);
· second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives a total of $0.484375 per unit for that quarter (the “second target distribution”); and
· third, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until each unitholder receives a total of $0.581250 per unit for that quarter (the “third target distribution”); and
· thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.
 
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Securities Authorized for Issuance under Equity Compensation Plans
 
See “Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters” for information regarding our equity compensation plans as of December 31, 2014.
 
Unregistered Sales of Equity Securities

None not previously reported on a current report on Form 8-K.

Issuer Purchases of Equity Securities

None.

ITEM 6. SELECTED FINANCIAL DATA

The following table should be read together with “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical financial statements and accompanying notes included in “Item 8 – Financial Statements and Supplementary Data.”

On January 21, 2014, we completed the initial public offering (“IPO”) of our limited partner common units.  In connection with the IPO, Holdings II, a wholly-owned subsidiary of Holdings, conveyed a 100% interest in CEP LLC.  Prior to its contribution to the Partnership, CEP LLC distributed to Holdings its interest in four subsidiaries.  In addition to CEP LLC, affiliates of Holdings contributed 50.1% of their interest in the TIR Entities.  The Partnership then subsequently conveyed this 50.1% interest to CEP LLC.  We have recast prior period financial data and information of Cypress Energy Partners, L.P. to reflect CEP LLC’s distribution of its four subsidiaries to Holdings, which were originally acquired on December 31, 2012, and to reflect the conveyance of CEP LLC and the TIR Entities to the Partnership at the closing of our IPO, as if the contribution of CEP LLC had occurred as of March 15, 2012 and the contribution of the TIR Entities had occurred as of June 26, 2013, the date affiliated members of the Partnership acquired a controlling interest in the TIR Entities.
 
There is a lack of comparability for the information presented for our Predecessor for 2012 as it includes the activity of the four subsidiaries distributed to Holdings prior to the contribution of CEP LLC to the Partnership and does not reflect the fair value of assets and liabilities recorded by the Partnership when the Predecessor was acquired by CEP LLC (see Note 4 to the Consolidated Financial Statements).
 
The following table also presents Adjusted EBITDA, which we use in evaluating the performance and liquidity of our business.  This financial measure is not calculated or presented in accordance with generally accepted accounting principles, or GAAP.  We explain this measure below and reconcile it to net income and net cash from operating activities, its most directly comparable financial measures calculated and presented in accordance with GAAP.
 
44

   
Cypress Energy Partners, L.P.
   
Predecessor (3)
 
   
Year
Ended
December
31, 2014
   
Year
Ended
December
31, 2013 (1)
   
Period
from
March 15
(Inception)
through
December
31, 2012
(2)
   
Year
Ended
December
31, 2012
   
Period
from June 1
(Inception)
through
December
31, 2011
 
  Recast Recast
   
(in thousands, except operational data)
 
Income Statement Data
                   
Revenues
 
$
404,418
   
$
249,133
   
$
619
   
$
12,203
   
$
2,944
 
Costs of services
   
355,355
     
213,690
     
309
     
3,662
     
503
 
Gross margin
   
49,063
     
35,443
     
310
     
8,541
     
2,441
 
General and administrative expense
   
21,321
     
12,467
     
2,056
     
477
     
138
 
    Depreciation, amortization and accretion
6,345
5,164
99
   
1,398
123
Impairments
   
32,546
     
4,131
     
-
     
-
     
-
 
Operating income (loss)
   
(11,149
)
   
13,681
     
(1,845
)
   
6,666
     
2,180
 
Interest expense, net
   
3,208
     
4,000
     
-
     
111
     
35
 
Offering costs
   
446
     
1,376
     
-
     
-
     
-
 
Net income (loss)
   
(15,179
)
   
4,355
     
(1,845
)
   
6,595
     
2,162
 
Net income attributable to non-controlling interests
   
4,973
     
22
     
-
     
-
     
-
 
Net income (loss) attributable to partners/controlling interests
   
(20,152
)
   
4,333
     
-
     
-
     
-
 
Balance Sheet Data - Period End
                                       
Total assets
 
$
189,842
   
$
240,590
   
$
79,990
   
$
27,588
   
$
14,476
 
Long-term debt
   
77,600
     
75,000
     
-
     
2,314
     
2,798
 
Total parent net investment and owners' equity
   
100,428
     
135,547
     
77,746
     
24,769
     
9,265
 
Cash Flows Data
                                       
Cash flows from operating activities
 
$
13,016
   
$
7,154
   
$
(2,244
)
 
$
7,246
   
$
1,106
 
Cash flows from investing activities
   
(2,286
)
   
5,779
     
(65,613
)
   
(15,236
)
   
(10,860
)
Cash flows from financing activities
   
(16,030
)
   
13,363
     
68,341
     
8,425
     
9,901
 
Cash distributions per unit (subsequent to IPO) (4)
   
1.51
     
-
     
-
     
-
     
-
 
Capital expenditures
   
2,286
     
4,329
     
65,613
     
15,236
     
10,860
 
Other financial data
                                       
Adjusted EBITDA
 
$
28,499
   
$
23,110
   
$
(1,746
)
 
$
8,104
   
$
2,320
 
Adjusted EBITDA attributable to partners/controlling interests
   
19,841
     
23,079
     
(1,746
)
   
8,104
     
2,320
 
Operational data
                                       
Total barrels of saltwater disposed (in thousands)
   
19,066
     
19,541
     
551
     
8,674
     
1,641
 
Average revenue per barrel
 
$
1.18
   
$
1.14
   
$
1.12
   
$
1.41
   
$
1.79
 
Average number of inspectors
   
1,535
     
1,706
     
-
     
-
     
-
 
Average revenue per inspector per week
 
$
4,771
   
$
4,952
     
-
     
-
     
-
 
 
(1)
Activity for the year ended December 31, 2013 includes operations of PI&IS from the June 26, 2013 acquisition date through the end of the year.
(2)
During the period from its inception through the date of its acquisition of the Predecessor on December 31, 2012, CEP LLC had no significant assets or operations.
(3) Includes activities of certain entities that were not contributed to the Partnership.
(4) Includes February 2015 distribution related to the quarter ended December 31, 2014.
 
45

Non-GAAP Financial Measures

We define Adjusted EBITDA as net income, plus interest expense, depreciation and amortization expenses, income tax expense, offering costs, impairments, and non-cash allocated expenses, less the gain on the reversal of contingent consideration.  Adjusted EBITDA is used as a supplemental financial measure by management and by external users of our financial statements, such as investors and commercial banks, to assess:
 
 
the financial performance of our assets without regard to the impact of financing methods, capital structure or historical cost basis of our assets;
 
 
the viability of capital expenditure projects and the overall rates of return on alternative investment opportunities;
 
 
our ability to incur and service debt and fund capital expenditures;
 
 
the ability of our assets to generate cash sufficient to make debt payments and to make distributions; and
 
 
our operating performance as compared to those of other companies in our industry without regard to the impact of financing methods and capital structure.
 
We believe that the presentation of Adjusted EBITDA will provide useful information to investors in assessing our financial condition and results of operations.  Net income is the GAAP measure most directly comparable to Adjusted EBITDA.  Adjusted EBITDA should not be considered an alternative to net income.  Because Adjusted EBITDA may be defined differently by other companies in our industry, our definitions of Adjusted EBITDA may not be comparable to a similarly titled measure of other companies, thereby diminishing their utility.  As a result, Adjusted EBITDA may not be comparable to similarly titled measures of other companies.
 
46

The following table presents a reconciliation of net income (loss) to Adjusted EBITDA, as applicable, for each of the periods indicated.
 
   
Cypress Energy Partners, L.P.
   
Predecessor
 
   
Year Ended
December 31,
2014
   
Year Ended
December 31,
2013 (1)
   
Period from
March 15
(Inception)
through
December 31,
2012 (2)
   
Year Ended
December 31,
2012
 
 
Recast
 
   
(in thousands)
 
Reconciliation of Net Income (Loss) to Adjusted EBITDA
               
Net income (loss)
 
$
(15,179
)
 
$
4,355
   
$
(1,845
)
 
$
6,595
 
Add:
                               
Interest expense
   
3,208
     
4,000
     
-
     
111
 
Depreciation, amortization and accretion
   
6,513
     
5,261
     
99
     
1,398
 
Impairments
   
32,546
     
4,131
     
-
     
-
 
Income tax expense
   
468
     
15,237
     
-
     
-
 
Offering costs
   
446
     
1,376
     
-
     
-
 
Non-cash allocated expenses
   
497
     
-
     
-
     
-
 
Less:
                               
Gain on reversal of contingent consideration
   
-
     
11,250
     
-
     
-
 
Adjusted EBITDA
 
$
28,499
   
$
23,110
   
$
(1,746
)
 
$
8,104
 
                                 
Adjusted EBITDA attributable to
                               
non-controlling interests
   
8,658
       31                  
Adjusted EBITDA attributable to partners / controlling interests
 
$
19,841
   
$
 23,079                  
                                 
Adjusted EBITDA attributable to general partner
   
1,651
                         
Adjusted EBITDA attributable to limited partners
 
$
18,190
                         
 
(1)
Activity for the year ended December 31, 2013 includes operations of PI&IS from the June 26, 2013 acquisition date through the end of the year. Also, because Holdings and other affiliates owned 100% of the TIR Entities, there is no adjusted EBITDA attributable to non-controlling interests for the year ended December 31, 2013 associated with the TIR Entities.
(2)
During the period from its inception through the date of its acquisition of the Predecessor on December 31, 2012, CEP LLC had no significant assets or operations.
 
47

The following table presents a reconciliation of net income (loss) and net cash provided by (used in) operating activities to Adjusted EBITDA, as applicable, for each of the periods indicated.

Reconciliation of Net Cash Provided by (Used in) Operating Activities to Adjusted EBITDA
 
Year Ended December 31, 2014
   
Year Ended December 31, 2013(1)
   
Period from March 15 (Inception) through December 31, 2012 (2)
    
Predecessor
Year Ended December 31, 2012
 
 
Recast
Recast
   
(in thousands)
 
Cash flows provided by (used in) operating activities
 
$
13,016
   
$
7,154
   
$
(2,244
)
 
$
7,246
 
Changes in accounts receivable
   
(6,650
)
   
8,793
     
741
     
(219
)
Changes in inventory, prepaid expenses and other assets
   
933
     
(283
)
   
12
     
(353
)
Changes in accounts payable and accrued liabilities
   
2,964
     
1,910
     
(255
)
   
(175
)
Change in income taxes payable
   
15,612
     
(15,816
)
   
-
     
-
 
Interest expense (excluding non-cash amortization)
   
2,494
     
2,781
     
-
     
(111
)
Offering costs
   
446
     
1,376
     
-
     
-
 
Income tax expense
   
468
     
15,237
     
-
     
-
 
Stock compensation
   
(785
)
   
(90
)
   
-
      
-
 
Other
   
1
     
2,048
     
-
      
-
 
Adjusted EBITDA
 
$
28,499
   
$
23,110
   
$
(1,746
)
 
$
8,104
 
 
(1) Activity for the year ended December 31, 2013 includes operations of PI&IS from the June 26, 2013 acquisition date through the end of the year.
(2) During the period from its inception through the date of its acquisition of the Predecessor on December 31, 2012, CEP LLC had no significant assets or operations.
 
48

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 contains a discussion of our business, including a general overview of our properties, our results of operations, our liquidity and capital resources, and our quantitative and qualitative disclosures about market risk.  At the closing of our IPO on January 21, 2014, CEP LLC and a 50.1% interest in the TIR Entities were contributed to us and became our Water and Environmental Services (“W&ES”) segment and our Pipeline Inspection and Integrity Services (“PI&IS”) segment, respectively.   These contributions were treated for accounting purposes as a combination of entities under common control and the results of CEP LLC are included as if the contributions had occurred as of March 15, 2012 and the results of the TIR Entities were included in our financial statements for periods subsequent to June 26, 2013, the date Holdings acquired a controlling interest.
 
The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance.  The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control, including among other things, the risk factors discussed in “Item 1A.  Risk Factors” of this Annual Report on Form 10-K.  Our actual results could differ materially from those discussed in these forward-looking statements.  Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil and natural gas, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this Annual Report on Form 10-K, all of which are difficult to predict.  In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.  See “Cautionary Remarks Regarding Forward-Looking Statements” in the front of this Annual Report on Form 10-K.

Overview

We are a growth-oriented master limited partnership that provides saltwater disposal and other water and environmental services and pipeline inspection and integrity services.  Through W&ES, we own and operate ten SWD facilities, eight of which are in the Bakken Shale region of the Williston Basin in North Dakota and two of which are in the Permian Basin in west Texas.  We also manage three other SWD facilities in the Bakken Shale region, one of which we have a 25% ownership interest.  W&ES customers are oil and natural gas exploration and production companies and trucking companies operating in the regions that we serve.  Through PI&IS, we provide independent pipeline inspection and integrity services to various energy, public utility and pipeline companies.  In both of these business segments, we work closely with our customers to help them comply with increasingly complex and strict environmental and safety rules and regulations applicable to production and pipeline operations and reduce their operating costs.

How We Generate Revenue

We generate revenue in W&ES primarily by treating flowback and produced water and injecting the saltwater into our SWD facilities.  Our results in W&ES are driven primarily by the volume of water we inject into our SWD facilities and the fees we charge for our services.  These fees are charged on a per barrel basis and vary based on the quantity and type of saltwater disposed, competitive dynamics and operating costs.  In addition, for minimal marginal cost, we generate revenue by selling residual oil we recover from the disposed water.  Through our 51.0% ownership interest in CES LLC, we also generate revenue managing SWD facilities for a fee.

We generate revenue in PI&IS primarily by providing inspection and integrity services on midstream pipelines, gathering systems and distribution systems, including data gathering and supervision of third-party construction, inspection, and maintenance and repair projects.  Our results in PI&IS are driven primarily by the number of inspectors that perform services for our customers and the fees that we charge for those services, which depend on the type and number of inspectors used on a particular project, the nature of the project and the duration of the project.  We bill our customers on a per inspector basis, including per diem charges, mileage and other reimbursement items.
 
How We Evaluate Our Operations

Our management uses a variety of financial and operating metrics to analyze our performance.  We view these metrics as significant factors in assessing our operating results and profitability and intend to review these measurements frequently for consistency and trend analysis.  These metrics include:

saltwater disposal and residual oil volumes in W&ES;
inspector headcount in PI&IS;
operating expenses;
segment gross margin;
Adjusted EBITDA; and
distributable cash flow.

Saltwater Disposal and Residual Oil Volumes

The amount of revenue we generate in W&ES depends primarily on the volume of produced water and flowback water that we dispose for our customers pursuant to published or negotiated rates, as well as the volume of residual oil that we sell pursuant to rates that are determined based on the quality of the oil sold and prevailing oil prices.  Our revenues from produced water, flowback water or residual oil sales are generated pursuant to contracts that are short-term in nature.  Revenues in this segment are recognized when the service is performed and collectability of fees is reasonably assured.  The volumes of saltwater disposed at our SWD facilities are driven by water volumes generated from existing oil and natural gas wells during their useful lives and development drilling and production volumes from the wells located near our facilities.  Producers’ willingness to engage in new drilling is determined by a number of factors, the most important of which are the prevailing and projected prices of oil, natural gas and NGLs, the cost to drill and operate a well, the availability and cost of capital and environmental and governmental regulations.  We generally expect the level of drilling to positively correlate with long-term trends in prices of oil, natural gas and NGLs.  Similarly, oil and natural gas production levels nationally and regionally generally tend to positively correlate with drilling activity.

Approximately 22% and 25% of our segment revenue for the years ended December 31, 2014 and 2013, respectively, in W&ES was derived from sales of residual oil recovered during the saltwater treatment process.  Our ability to recover residual oil is dependent upon the oil content in the saltwater we treat, which is, among other things, a function of water type, chemistry, source and temperature.  Generally, where outside temperatures are lower, oil separation is more difficult.  Thus, our residual oil recovery during the winter season is lower than our recovery during the summer season in North Dakota.  Additionally, residual oil content will decrease if, among other things, producers begin recovering higher levels of residual oil in saltwater prior to delivering such saltwater to us for treatment.

Inspector Headcount

The amount of revenue we generate in PI&IS depends primarily on the number of inspectors that perform services for our customers.  The number of inspectors engaged on projects is driven by the type of project, prevailing market rates, the age and condition of customers’ midstream pipelines, gathering systems and distribution systems and the legal and regulatory requirements relating to the inspection and maintenance of those assets.

Operating Expenses
 
The primary components of our operating expenses that we evaluate include costs of services, general and administrative, and depreciation and amortization.

Costs of services.  We seek to maximize the profitability of our operations in part by minimizing, to the extent appropriate, expenses directly tied to operating and maintaining our assets.  Repair and maintenance costs, employee-related costs, residual oil disposal costs and utilities expenses are the primary cost of services components in W&ES.  These expenses generally remain relatively stable across broad ranges of saltwater disposal volumes but can fluctuate from period to period depending on the mix of activities performed during that period and the timing of these expenses.  We seek to manage our operations and repair and maintenance capital expenditures on our SWD facilities and related assets by scheduling repairs and maintenance over time to avoid significant variability in our maintenance capital expenditures, downtime and minimize their impact on our cash flows.  Employee-or-contractor-related costs and per diem expenses are the primary costs of services components in PI&IS.  These expenses fluctuate from period to period based on the number, type and location of projects on which we are engaged at any given time.
 
General and administrative.  General and administrative expenses include management and overhead payroll, general office expenses, management fees, legal fees and other expenses.
 
Under our amended and restated omnibus agreement, Holdings charges us an annual administrative fee of $4.0 million (payable in equal quarterly installments) for the provision of certain partnership overhead expenses.  This fee is subject to an increase by an annual amount equal to PPI plus one percent or, with the concurrence of the conflicts committee, in the event of an expansion of our operations, including through acquisitions or internal growth.  To the extent that our general partner incurs overhead expenses in excess of our annual administration fee that are attributable to the operations of the Partnership, these expenses are reflected in our Statement of Operations as incremental general and administrative expense and treated as an equity contribution.

Included in this administrative fee are our incremental general and administrative expenses attributable to operating as a publicly traded partnership, such as expenses associated with annual and quarterly SEC reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance; listing on the New York Stock Exchange; independent registered public accounting firm fees; legal fees; investor relations, registrar and transfer agent fees; director and officer liability insurance costs and director compensation, which we estimate to be approximately $2.0 million.  Our partnership agreement provides that Holdings will determine and allocate expenses related to our operations and may provide us other services for which we will be charged fees as determined in good faith.  Payments to Holdings and its affiliates following the expiration of our amended and restated omnibus agreement could be substantial and will reduce the amount of cash we have available to distribute to unitholders.
 
Depreciation and amortization.  Depreciation and amortization expense consists of our estimate of the decrease in value of the assets capitalized in property, plant and equipment as a result of using the assets throughout the year.  Depreciation is recorded on a straight-line basis.  We estimate our assets have useful lives ranging from 3 to 39 years.  The facilities, wells and equipment constituted approximately 82% and 83% of the cost basis of our fixed assets as of December 31, 2014 and 2013 respectively, and have useful lives of 5 to 15 years.

Segment Gross Margin, Adjusted EBITDA and Distributable Cash Flow

We view segment gross margin as one of our primary management tools, and we track this item on a regular basis, both as an absolute amount and as a percentage of revenues compared to prior periods.  We also track Adjusted EBITDA, and we define Adjusted EBITDA as net income, plus interest expense, depreciation and amortization expenses, income tax expense, offering costs, impairments and non-cash allocated expenses, less the gain on the reversal of contingent consideration.  Although we have not quantified distributable cash flow on a historical basis, we intend to use distributable cash flow, which we define as Adjusted EBITDA less net cash interest paid, cash taxes paid and maintenance capital expenditures, to analyze our performance.  Distributable cash flow will not reflect changes in working capital balances, which could be significant as headcount of PI&IS varies from period to period.  Adjusted EBITDA is a non-GAAP, supplemental financial measure used by management and by external users of our financial statements, such as investors, commercial banks and research analysts, to assess:

our operating performance as compared to those of other providers of similar services, without regard to financing methods, historical cost basis or capital structure;
the ability of our assets to generate sufficient cash flow to support our indebtedness and make distributions to our partners;
the viability of capital expenditure projects and the overall rates of return on alternative investment opportunities;
our ability to incur and service debt and fund capital expenditures; and
the viability of acquisitions and other capital expenditure projects and the rates of return on various investment opportunities.
 
Adjusted EBITDA and distributable cash flow are not financial measures presented in accordance with GAAP.  We believe that the presentation of these non-GAAP financial measures will provide useful information to investors in assessing our financial condition and results of operations.  Net income is the GAAP measure most directly comparable to Adjusted EBITDA.  The GAAP measure most directly comparable to distributable cash flow is net cash provided by operating activities.  Our non-GAAP financial measures should not be considered as alternatives to the most directly comparable GAAP financial measure.  Each of these non-GAAP financial measures has important limitations as an analytical tool because it excludes some but not all items that affect the most directly comparable GAAP financial measure.  You should not consider Adjusted EBITDA or distributable cash flow in isolation or as a substitute for analysis of our results as reported under GAAP.  Because Adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

For a further discussion of the non-GAAP financial measures of Adjusted EBITDA and reconciliation of that measure to their most comparable financial measures calculated and presented in accordance with GAAP, please read “Item 6 — Selected Financial Data — Non-GAAP Financial Measures.”

Outlook

W&ES
                                                           
Crude oil prices declined sharply during the six months ended December 31, 2014 (the spot price for NYMEX West Texas Intermediate (“WTI”) crude oil at Cushing, Oklahoma declined from $106.06 per barrel at July 1, 2014 to $53.45 per barrel at December 31, 2014).  Subsequently, WTI has further declined to approximately $47.00 per barrel at March 25, 2015 and Bakken Clearbrook, which trades at a discount to WTI, was trading at approximately $42.00 per barrel.  In our W&ES segment, the market price of crude oil has a direct impact on our revenues associated with the sale of residual oil. It also has an indirect impact on our water disposal volumes and revenues, depending on the reaction of oil and gas producers in the vicinity of our facilities to declining oil and/or gas prices.
                                             
Many producers have announced material and significant cuts in their 2015 capital budgets and drilling activities that would reduce new flowback water and produced water and, although unlikely, could potentially stop production on existing wells, which would have a direct impact on the volumes of disposed water and residual oil recovery at our facilities. The material decline in rig count and new drilling activity in many basins, including the Bakken and the Permian, will lead to lower water volumes, reduced skim oil volumes and pricing pressures. Many of our E&P customers have requested pricing concessions to help them cope with the lower commodity prices. In the majority of the basins in the country, new SWD facilities were developed to support the previous rig counts and activity levels prior to the sharp contraction in activity and commodity prices. These events have led to excess supply relative to current demand in many locations, including the Bakken and the Permian that, in turn, has led to aggressive pricing. We have always focused on produced water vs. flowback water and therefore are less impacted than many competitors. However, we are clearly being impacted on all metrics. We are focused on reducing operating costs and identifying operating efficiencies in an effort to offset the financial impact of declining volumes and prices. Additionally, we continue to focus on piped water opportunities to secure additional long term volumes of produced water for the life of the oil and gas wells’ production. We also manage some third party facilities, who are also being impacted by the facts above leading to lower management fee revenue.
                                                     
PI&IS
                                                        
Demand remains solid for our pipeline inspection and integrity services in a very large market with many customer prospects that we do not currently serve.  We have strengthened our management team and focused on non-destructive testing services as we continue to look at a number of other new lines of business to serve our existing customers.   The majority of our clients are public investment grade companies with long planning cycles leading to healthy backlogs of new long-term projects in addition to maintaining their existing pipeline networks that also require inspection. We have also only begun to penetrate the public utility company (“PUC”) segment of the industry that brings natural gas to homes and businesses. We believe that with increasing regulatory requirements and the aging U.S. and Canadian pipeline infrastructure that the PI&IS business is more insulated from changes in commodity prices in the near term.  A prolonged depression in oil and natural gas prices could lead to a downturn in demand for our services over time.
                                                              
We are aggressively pursuing growth opportunities in both of our business segments through both acquisitions and organic growth.  Additionally, we are continually looking for new talent to strengthen our management team as we continue to grow.
                                            
Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to select appropriate accounting policies and to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenue and expenses.  See “Note 2 — Summary of Significant Accounting Policies” in the audited financial statements included in “Item 8 — Financial Statements and Supplementary Data” for descriptions of our major accounting policies and estimates.  Certain of these accounting policies and estimates involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts would have been reported under different conditions, or if different assumptions had been used.  The following discussions of critical accounting estimates, including any related discussion of contingencies, address all important accounting areas where the nature of accounting estimates or assumptions could be material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change.

As a company with less than $1.0 billion in revenue during its last fiscal year, we qualify as an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012, or the JOBS Act.  As an emerging growth company, we have elected to opt out of the exemption that allows emerging growth companies to extend the transition period for complying with new or revised financial accounting standards (this election is irrevocable).
 
Impairments of Long-Lived Assets

As prescribed by ASC 360-10-05, Property, Plant and Equipment-General Impairment or Disposal of Long-Lived Assets, we assess property, plant and equipment ("PP&E") for possible impairment whenever events or changes in circumstances indicate that the carrying value of the assets may not be recoverable. Such indicators include, among others, the nature of the asset, the projected future economic benefit of the asset, changes in regulatory and political environments and historical and future cash flow and profitability measurements. If the carrying value of an asset exceeds the future undiscounted cash flows expected from the asset, we recognize an impairment charge for the excess of carrying value of the asset over its estimated fair value. Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain matters such as future commodity prices, the effects of inflation on operating expenses and the outlook for national or regional market supply and demand for the services we provide.

For our W&ES segment, we evaluate property and equipment for impairment at the SWD facility level.  Our computations utilize judgments and assumptions that include the undiscounted future cash flows, discounted future cash flows, estimated fair value of the asset, and the current and future economic environment in which the asset is operated.  Significant judgments and assumptions in these assessments include estimates of water disposal rates, disposal volumes, expected capital costs, oil and gas drilling and producing volumes in the markets served, risks associated with the different zones into which saltwater is disposed and our estimate of an applicable discount rate commensurate with the risk of the underlying cash flow estimates.   PP&E is not a significant component of our PI&IS segment.

During the years ended December 31, 2014 and 2013, we identified impairment indicators at some of our SWD facilities and reviewed the associated property and equipment for impairment.  We recognized impairment charges of $12.8 and $3.4 million during the years ended December 31, 2014 and 2013, respectively, for these assets. These impairment reviews utilized inputs generally consistent with those described above.  Judgments and assumptions are inherent in our estimate of future cash flows used to evaluate these assets.  The use of alternate judgments and assumptions could result in the recognition of different levels of impairment charges in the consolidated financial statements. 

An estimate as to the sensitivity to earnings for these periods had we used other assumptions in our impairment reviews and impairment calculations is not practicable, given the broad range of our PP&E and the number of assumptions involved in the estimates. Favorable changes to some assumptions might have avoided the need to impair any assets in these periods, whereas unfavorable changes might have caused an additional unknown number of other assets to become impaired.

Business Combinations and Intangible Assets Including Goodwill

We account for acquisitions of businesses using the acquisition method of accounting.  Accordingly, assets acquired and liabilities assumed are recorded at their estimated fair values at the acquisition date.  The excess of purchase price over fair value of net assets acquired, including the amount assigned to identifiable intangible assets, is recorded as goodwill.  Given the time it takes to obtain pertinent information to finalize acquired companies’ balance sheets, it may be several quarters before we are able to finalize those initial fair value estimates.  Accordingly, it is not uncommon for the initial estimates to be subsequently revised.  The results of operations of acquired businesses are included in the consolidated financial statements from the acquisition date.
 
Identifiable Intangible Assets

Our recorded identifiable intangible assets primarily include customer lists and trademarks and trade names.  Identifiable intangible assets with finite lives are amortized over their estimated useful lives, which is the period over which the asset is expected to contribute directly or indirectly to our future cash flows.  We have no indefinite-lived intangibles other than goodwill.  The determination of the fair value of the intangible assets and the estimated useful lives are based on an analysis of all pertinent factors including (1) the use of widely-accepted valuation approaches, the income approach, or the cost approach, (2) our expected use of the asset, (3) the expected useful life of related assets, (4) any legal, regulatory, or contractual provisions, including renewal or extension periods that would cause substantial costs or modifications to existing agreements, and (5) the effects of demand, competition, and other economic factors.  Should any of the underlying assumptions indicate that the value of the intangible assets might be impaired, we may be required to reduce the carrying value and subsequent useful life of the asset.  If the underlying assumptions governing the amortization of an intangible asset were later determined to have significantly changed, we may be required to adjust the amortization period of such asset to reflect any new estimate of its useful life.  Any write-down of the value or unfavorable change in the useful life of an intangible asset would increase expense at that time.  There were no impairments of identifiable intangible assets during the year ended December 31, 2014.  During the year ended December 31, 2013, the partnership determined that one of its trade names in PI&IS was impaired and recorded an impairment charge of $0.7 million.  The fair value was determined using a discounted cash flow analysis applied to the expected royalty values generated from the use of the trade name.  Management’s estimates of the future royalties associated with the use of the trade name were based on forecasted total revenues.  Actual results could vary which could have further impact on the value of the trade name.
 
Goodwill
                                                  
At December 31, 2014 and 2013, the Partnership had $55.6 and $75.5 million of goodwill, respectively. Goodwill is not amortized, but is subject to annual reviews on November 1 for impairment at a reporting unit level.  The reporting unit or units used to evaluate and measure goodwill for impairment are determined primarily from the manner in which the business is managed or operated.  A reporting unit is an operating segment or a component that is one level below an operating segment.  In accordance with ASC 350 “Intangibles — Goodwill and Other”, we have assessed the reporting unit definitions and determined that W&ES and PI&IS are the appropriate reporting units for testing goodwill impairment.  The accounting estimate relative to assessing the impairment of goodwill is a critical accounting estimate for each of our reporting segments.
                                               
For our PI&IS reporting unit, we performed a qualitative assessment to determine whether the fair value of the reporting unit was more likely than not to be less than its carrying value.  Our evaluation consisted of assessing various qualitative factors including current and projected future earnings, capitalization, current customer relationships and projects and the impact of lower crude oil prices on our earnings.  The qualitative assessment on this reporting unit indicated the fair value of the reporting unit exceeded the carrying value and the reporting unit was not at risk for a potential goodwill impairment.
 
For our W&ES segment, after giving consideration to certain qualitative factors including trends in the energy industry and recorded impairments of property and equipment, we elected to perform a quantitative goodwill impairment analysis.  We computed the fair value of the reporting unit employing multiple valuation methodologies, including a market approach (market price multiples of comparable companies) and an income approach (discounted cash flow analysis).  This approach is consistent with the requirement to utilize all appropriate valuation techniques as described in ASC 820-10-35-24 “Fair Value Measurements and Disclosures.” Given recent declines in the price of crude oil and the related impact on the valuations of energy related companies, relevant market data was difficult to obtain and was of limited usefulness.  Accordingly, we relied heavily on the use of the income approach for the valuation of the reporting unit.
 
A discounted cash flow analysis requires us to make various assumptions about sales, operating margins, capital expenditures, working capital and growth rates.  These assumptions are based on our budgets, business plans, economic projections, and anticipated future cash flows.  In determining the fair value of our reporting units, we were required to make significant judgments and estimates regarding the impact of anticipated economic factors on our business. The forecast used in this analysis makes certain assumptions about future pricing, volumes and expected maintenance capital expenditures.  Assumptions are also made for a “normalized” perpetual growth rate for periods beyond the long range financial forecast period.  Critical estimates that are used as part of these evaluations include, among other things, the discount rate applied to future earnings reflecting a weighted average cost of capital rate and earnings growth assumptions.  Our estimate of water volumes disposed and revenue per barrel of water disposed are critical assumptions used in our discounted cash flow analysis for our SWD facilities. 
                                               
Our estimates of fair value are sensitive to changes in all of these variables, certain of which relate to broader macroeconomic conditions outside our control.  As a result, actual performance in the near and longer-term could be different from these expectations and assumptions.  This could be caused by events such as strategic decisions made in response to economic and competitive conditions and the impact of economic factors, such as continued increases in oil field development in our customer base.  In addition, some of the inherent estimates and assumptions used in determining fair value of the reporting units are outside the control of management, including commodity prices, interest rates, cost of capital and our credit ratings.  While we believe we have made reasonable estimates and assumptions to calculate the fair value of the reporting units and other intangible assets, it is possible a material change could occur.
 
As a result of our valuation, we determined that the carrying value of the W&ES reporting unit exceeded the fair value of the reporting unit resulting in a goodwill impairment charge of $19.8 million.  The W&ES segment has experienced increased competition in some of the regions in which we operate which has resulted in declining volumes and increased pricing pressure.  The fourth quarter decline in oil prices has intensified competitive pressures and had a direct impact on our revenues.  Many of our customers have announced significantly reduced drilling programs in the Bakken.  The decline in drilling will directly impact the amount of flowback and produced water that we process and dispose.  The energy downturn is also expected to continue to negatively impact our pricing as our customers look for ways to reduce costs.  In addition, as we process lower water volumes, in particular flowback water volumes directly attributable to drilling, we will recover less skim oil.  Lower oil prices will also directly impact revenues as oil sales have historically represented in excess of 20% of our W&ES revenues.
 
Depreciation Methods, Estimated Useful Lives of Property
 
Depreciation expense represents the systematic and rational write-off of the cost of property and equipment, net of residual or salvage value (if any), to the results of operations for the periods the assets are used. We depreciate our property and equipment using the straight-line method, which results in recording depreciation expense evenly over the estimated life of the individual asset. The estimate of depreciation expense requires us to make assumptions regarding the useful economic lives and residual values of our assets. At the time we acquired and placed our property and equipment in service, we developed assumptions about such lives and residual values that we believe are reasonable; however, circumstances may develop that could require us to change these assumptions in future periods, which would change our depreciation expense amounts prospectively. We currently use a life of 15 years for wells and related equipment, which include subsurface well completion and other improvements. We use a life of 9 years for tanks, plumbing and storage tanks and 39 years for buildings. We believe that these lives represent the economic lives of the assets and that substantial capital expenditures would need to be incurred to extend their economic lives. Examples of such circumstances include changes in laws and regulations that limit the estimated economic life of an asset; changes in technology that render an asset obsolete; or changes in expected salvage values. At this time, we do not believe that it is likely that any of these circumstances will occur.
 
Consolidated Results of Operations – Cypress Energy Partners, L.P. and the Predecessor

Factors Impacting Comparability

The historical results of operations for the periods presented may not be comparable, either to each other or to our future results of operations, for reasons described below:

·
At the closing of the IPO, we acquired a 50.1% interest in each of the TIR Entities with Holdings and certain affiliates continuing to hold the remaining 49.9% interest (“Retained Interest”).  The non-controlling interest is reduced by certain interest charges as outlined in our amended and restated omnibus agreement.  The contribution of interests in the TIR Entities to the Partnership has been treated as a reorganization of entities under common control.  Accordingly, the results of operations and assets and liabilities of the TIR Entities are included in the historical financial information of the Partnership for periods from June 26, 2013, the date Holdings obtained control of the TIR Entities.

· The effective date of the acquisition of our 51% ownership of CES LLC was October 1, 2013; accordingly, the financial data presented does not reflect the results of operations of CES LLC prior to that date.

· General and administrative expenses have increased as a result of operating as a publicly traded partnership.  At the closing of the IPO, CEP LLC, the Partnership and other affiliates entered into an omnibus agreement with Holdings.  Among other things, the agreement calls for an annual administrative fee to be paid by the Partnership in the amount of $4.0 million, payable in quarterly installments to Holdings, for providing the Partnership with certain overhead services, including executive management services by certain officers of our General Partner, compensation expense, including stock-based compensation expense for employees required to manage and operate our business as well as the costs of operating a publicly traded partnership, including costs associated with SEC reporting requirements, tax return and Schedule K-1 preparation and distribution, independent registered public accounting firm fees, investor relations activities and registrar and transfer agent fees.

· Interest expense will not be comparable between the periods presented as a result of our credit agreement entered into in December 2013 that resulted in more favorable credit terms as compared to previous periods.  Borrowings under the credit agreement were used to, among other things, refinance outstanding obligations of the TIR Entities which had significantly higher interest rates.   In addition, interest expense for the TIR Entities is only reflected for periods from June 26, 2013 forward.

· CEP LLC had no operations prior to an acquisition completed on December 3, 2012.  Financial data for CEP LLC for the period from Inception through December 31, 2012, is included in a separate column in the tables below.
 
·
The financial statements of the Predecessor include the results of operations of certain limited liability companies that were not contributed to the Partnership.
 
· General and administrative expenses of the Predecessor’s SWD facilities represent expenses associated with those assets as stand-alone businesses and do not represent sales and general and administrative expenses we incurred to operate those assets as part of a larger business. Operating expenses associated with CEP LLC’s headquarters office, primarily consisting of management salaries and general and administrative expenses, are not reflected in the results of its Predecessor.
 
The following table compares the operating results of Cypress Energy Partners, L.P. and its Predecessor for the periods indicated.
 
   
Cypress Energy Partners, L.P.
   
Predecessor
 
   
2014
   
2013 (a)
   
2012
   
2012
 
  Recast    
 
(in thousands)
   
                 
Revenues
 
$
404,418
   
$
249,133
   
$
619
   
$
12,203
 
Costs of services
   
355,355
     
213,690
     
309
     
3,662
 
Gross margin
   
49,063
     
35,443
     
310
     
8,541
 
                                 
Operating costs and expense:
                               
General and administrative
   
21,321
     
12,467
     
2,056
     
477
 
Depreciation, amortization and accretion
   
6,345
     
5,164
     
99
     
1,398
 
Impairments
   
32,546
     
4,131
     
-
     
-
 
Operating (loss) income
   
(11,149
)
   
13,681
     
(1,845
)
   
6,666
 
                                 
Other income (expense):
                               
Interest expense, net
   
(3,208
)
   
(4,000
)
   
-
     
(111
)
Offering costs
   
(446
)
   
(1,376
)
   
-
     
-
 
Gain on reversal of contingent consideration
   
-
     
11,250
     
-
     
-
 
Other, net
   
92
     
37
     
-
     
40
 
Net (loss) income before income tax expense
   
(14,711
)
   
19,592
     
(1,845
)
   
6,595
 
Income tax expense
   
468
     
15,237
     
-
     
-
 
Net (loss) income
   
(15,179
)
   
4,355
   
$
(1,845
)
 
$
6,595
 
                                 
Net income attributable to non-controlling interests
   
4,973
     
22
                 
Net (loss) income attributable to partners / controlling interests
   
(20,152
)
 
$
4,333
                 
                                 
Net income attributable to general partner
   
149
                         
Net loss attributable to limited partners
 
$
(20,301
)
                       

(a) Activity for the year ended December 31, 2013 includes operations of  PI&IS  from the June 26, 2013 acquisition date through the end of the year.

See the detailed discussion of revenues, cost of sales, gross margin, general and administrative expense and depreciation, amortization and accretion by reportable segment below.  See also Note 2 to our Consolidated Financial Statements included in Part II of this Form 10-K for more information about our recasted Consolidated Financial Statements for prior periods.
 
The following is a discussion of significant changes in the non-segment related corporate other income and expenses for the years ended December 31, 2014, 2013 and 2012.
 
Interest expense. Interest expense in 2014 primarily consists of interest on borrowings under our credit agreement entered into in December 2013, as well as amortization of debt issuance costs and unused commitment fees.  Interest expense declined from 2013 to 2014 primarily due to lower interest rates related to the new credit facility entered into in December 2013 as well as the fact that interest expense for the TIR Entities only includes periods subsequent to June 26, 2013, the date they were effectively acquired by affiliates of the Company.  Average debt outstanding for the years ended December 31, 2014 and 2013 was $72.5 million and $62.8 million, respectively.  Average outstanding debt for 2013 only includes the period from June 26, 2013 through December 31, 2013 as the Partnership had no debt outside of the TIR Entities. Interest expense in 2012 represents interest expense associated with the construction of the acquired SWD facilities as incurred by our Predecessor.
 
Offering costs. We incurred costs of $0.4 million and $1.4 million in 2014 and 2013, respectively, primarily for professional services related to our IPO.  There were no offering costs incurred in 2012.

Gain on reversal of contingent consideration. During 2013, the W&ES segment recognized a non-recurring gain of $11.3 million as a result of the reversal of a previously recorded contingent purchase price liability.

Income tax expense.  We believe that we qualify as a partnership for income tax purposes and therefore, generally do not pay income tax.  Rather, each owner reports his or her share of our income or loss on his or her individual tax return.  Income tax expense in 2014 of $0.4 million includes income taxes related to one taxable corporate subsidiary in the United States and two taxable corporate subsidiaries in Canada in our PI&IS segment, as well as business activity, gross margin, and franchise taxes incurred in certain states.  The 2013 income tax expense of $15.2 million is primarily related to the change in legal status of certain of the TIR Entities, whereby they converted from corporate status to partnership status in December 2013 as well as income tax expense related to taxable corporate subsidiaries of the TIR Entities for the period from June 26, 2013 to December 9, 2013, the date of conversion to pass-through status.  The Predecessor did not incur any income taxes.
 
Net income attributable to non-controlling interests.  Non-controlling interests in 2014 include a 49.9% interest in the TIR Entities (effectively our PI&IS segment) that is owned by certain affiliates of Holdings, a 49% interest in one consolidated subsidiary in our W&ES segment, CES LLC, as well as a 51% interest of a subsidiary of TIR LLC, that was created in 2014 and is consolidated for reporting purposes.  The non-controlling interest holders of the TIR Entities are charged directly for certain financing expenses of the Partnership.  These charges are reflected as a direct reduction of their proportionate share of net income. Non-controlling interests in 2013 only include the 49% interest in CES LLC.
 
Segment Operating Results

W&ES

The following table summarizes the operating results of our W&ES segment for the years ended December 31, 2014 and 2013.

   
Years Ended December 31,
 
   
2014
   
% of Revenue
   
(Recast)
2013
   
% of Revenue
   
Change
   
% Change
 
   
(in thousands, except per barrel data)
 
                         
Revenue
 
$
22,416
       
$
22,232
       
$
184
     
1
%
Costs of services
   
8,617
         
7,347
         
1,270
     
17
%
Gross margin
   
13,799
     
62
%
   
14,885
     
67
%
   
(1,086
)
   
(7
)%
General and administrative expense
   
3,587
     
16
%
   
3,292
     
15
%
   
295
     
9
%
Impairments
   
32,546
             
3,429
             
29,117
     
849
%
Depreciation, amortization and accretion
   
3,806
             
3,837
             
(31
)
   
(1
)%
Operating income
 
$
(26,140
)
   
-117
%
 
$
4,327
     
19
%
 
$
(30,467
)
   
(704
)%
Operating Data
                                               
Total barrels of saltwater disposed
   
19,066
             
19,541
             
(475
)
   
(2
)%
Average revenue per barrel disposed (a)
 
$
1.18
           
$
1.14
             
0.04
     
3
%
Revenue variance due to barrels disposed
                                 
$
(541
)
       
Revenue variance due to revenue per barrel
                                   
725
         

(a) Average revenue per barrel disposed is calculated by dividing revenues (which include flowback, produced water, residual oil sales and management fees) by the total barrels of saltwater disposed.
 
Revenue.  The increase of $0.2 million in revenues is primarily due to a $0.7 million positive price variance as the average revenue per barrel disposed increased from $1.14 in 2013 to $1.18 in 2014. This increase was partially offset by a $0.5 million negative volume variance as water volumes disposed decreased from 19.5 million barrels in 2013 to 19.1 million barrels in 2014. The increase in average revenue per barrel disposed is due primarily to higher management fee revenues associated with a full year of operations of CES LLC which was acquired effective December 1, 2013.

Costs of services.  Costs of services increased from 2013 to 2014 due primarily to increased repairs and maintenance expenses related to higher periodic required expenditures as the wells age.  These expenditures primarily include pump repairs and clean out of oil storage and separation tanks.

Gross margin. The decrease in gross margin is mainly caused by higher repair and maintenance expenses in 2014.
                                                     
General and administrative expense. The increase in general and administrative expense is primarily attributable to the allocation of the annual administration fee charged by Holdings under our amended and restated omnibus agreement.  The allocation to W&ES for 2014 was $1.1 million which exceeded 2013 allocated costs by $0.6 million.  In addition, general and administrative expenses increased $0.2 million as a result of having a full year of operations of CES LLC. The increases were partially offset by a reduction of professional service fees of $0.6 million.  The decrease in professional service fees were primarily related to the preparation of our IPO in 2013 that were absent in 2014.
                                    
Impairments.  As a result of the decline in commodity prices and a decline in drilling activity around some of our facilities, we recorded impairment charges during the year ended December 31, 2014 associated with our W&ES segment totaling $32.5 million.  The impairment charge consists of impairments of long lived assets totaling $12.8 million and goodwill impairments totaling $19.8 million. During the year ended December 31, 2013, we recorded an impairment charge at one of our SWD facilities totaling $3.4 million.
                                          
Operating income.  Operating income declined $30.5 million from 2013 primarily due to an increase in impairment charges totaling $29.1 million.  Excluding the impairment charges, segment operating income decreased $1.4 million.  This decline is offset somewhat by higher revenues.
 
The following table summarizes the operating results of our W&ES segment for the years ended December 31, 2013 and 2012.

 
Years Ended December 31,
 
   
(Recast)
2013
   
% of Revenue
   
Predecessor 2012
   
% of Revenue
   
Change
   
% Change
 
   
(in thousands, except per barrel data)
 
                         
Revenue
 
$
22,232
       
$
12,203
       
$
10,029
     
82
%
Costs of services
   
7,347
         
3,662
         
3,685
     
101
%
Gross margin
   
14,885
     
67
%
   
8,541
     
70
%
   
6,344
     
74
%
General and administrative expense
   
3,292
     
15
%
   
477
     
4
%
   
2,815
     
590
%
Impairments
   
3,429
             
-
             
3,429
         
Depreciation, amortization and accretion
   
3,837
             
1,398
             
2,439
     
174
%
Operating income
 
$
4,327
     
19
%
 
$
6,666
     
55
%
 
$
(2,339
)
   
(35
)%
Operating Data:
                                               
Total barrels of saltwater disposed
   
19,541
             
8,674
             
11,677
     
148
%
Average revenue per barrel disposed (a)
 
$
1.14
           
$
1.41
             
(0.41
)
   
(27
)%
Revenue variance due to barrels disposed
                                 
$
18,118
         
Revenue variance due to revenue per barrel
                                   
(8,089
)
       

(a)
Average revenue per barrel disposed calculated by dividing revenues (which include flowback, produced water, residual oil sales and management fees) by the total barrels of saltwater disposed.
                                         
Revenue. W&ES revenues were $22.2 million for the year ended December 31, 2013, compared to its Predecessor’s $12.2 million for the same period of 2012, an increase of 82%. The overall increase in saltwater disposal revenues was primarily driven by an increase in saltwater disposal volumes from 8.7 million barrels for the year ended December 31, 2012 to 19.5 million barrels for the same period in 2013. This increase in saltwater disposal volumes was associated with the fact that only three of six Predecessor wells were operational for the full year of 2012 as the other three came on line at various times throughout the year.  In addition, we acquired four wells in December 2012 that are not reflected in the Predecessor’s results.  The increase in volumes was offset somewhat by a decline in average pricing across the wells from $1.41 per barrel of disposed saltwater for 2012 to $1.14 per barrel in 2013. The decline in revenue per barrel was primarily attributable to our decision to reduce pricing in the Bakken Shale region due to competitive pressures and to the addition of two wells in the Permian Basin which have lower average pricing relative to the Bakken wells due to regional market differences and lower operating expenses.  The Bakken Shale region has differential pricing between flowback and produced water.
                                                   
Costs of Services. W&ES costs of services were $7.3 million for the year ended December 31, 2013, compared to its Predecessor’s costs of sales of $3.7 million for the same period of 2012, an increase of 101%. This increase was primarily attributable to the difference in the number of wells operating between the periods.   Incremental costs of sales attributable to wells not in operation at December 31, 2012 were $3.5 million.

Gross Margin. Gross margin was $14.9 million for the year ended December 31, 2013, compared to $8.5 million for the same period of 2012, an increase of $6.3 million or 74%.  Gross margin as a percentage of total revenues declined to 67% for the year ended December 31, 2013 from 70% for the year ended December 31, 2012.  The decline in gross margin as a percentage of revenue is primarily a result of higher costs of sales attributable to higher repair and maintenance expenses due to the fact that most of the wells did not come on line until 2012 and had minimal repairs and maintenance in the first year of operation, as well as lower average revenue per barrel disposed.
 
General and Administrative Expenses. General and administrative expenses were $3.3 million for the year ended December 31, 2013, compared to $0.5 million for the Predecessor for the same period in 2012, an increase of 590%. General and administrative expenses increased by $2.8 million, primarily attributable to $0.5 in incremental expenses associated with operating our wells acquired on December 3, 2012 for a full year and $1.8 million, attributable to corporate office overhead expenses.  The increase in the corporate activities was largely attributable to an increase in professional services of $1.3 million incurred primarily in relation to legal and accounting services. The remaining corporate activity costs were associated with corporate salaries of $0.4 million that were not included in the 2012 Predecessor results. The general and administrative expenses associated with the Predecessor wells increased $0.5 million due to the variable costs of running the facilities with higher volumes of saltwater disposed primarily associated with the start date of wells that commenced operations in 2012.

Impairments.  During the year ended December 31, 2013, we recorded an impairment charge at one of our SWD facilities totaling $3.4 million.
                                    
Depreciation, Amortization and Accretion Expenses. Depreciation and amortization expenses were $3.8 million for the year ended December 31, 2013, compared to the Predecessor's $1.4 million for the same period in 2012, an increase of 174%. Depreciation and amortization increased primarily as a result of having more SWD wells and a higher depreciable basis in the SWD wells acquired from the Predecessor on December 31, 2012.
                                               
Operating Income. We recorded operating income of approximately $4.3 million for the year ended December 31, 2013, compared to our Predecessor’s operating income of $6.7 million for the same period in 2012, a decrease of 35%. This decrease was primarily the result of higher segment gross margin from the increased number of well sites of $6.3 million offset by higher operating expenses, primarily depreciation and amortization ($2.4 million increase) and general and administrative expenses ($2.8 million increase) associated with the expanded operations, as well as an impairment charge of $3.4 million.
 
PI&IS
 
The following table summarizes the operating results of our PI&IS segment for the year ended December 31, 2014 and the period from June 26, 2013 through December 31, 2013.

   
Years Ended December 31,
 
   
2014
   
% of Revenue
   
2013 (a)
   
% of Revenue
   
Change
   
% Change
 
   
(in thousands, except operating data)
 
                         
Revenue
 
$
382,002
       
$
226,901
       
$
155,101
     
68
%
Costs of services
   
346,738
         
206,343
         
140,395
     
68
%
Gross margin
   
35,264
     
9
%
   
20,558
     
9
%
   
14,706
     
72
%
General and administrative expense
   
17,734
     
5
%