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

Form 10-K
 
(MARK ONE)
 
x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended December 31, 2013
 
o 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
(State or other jurisdiction of incorporation or organization)
61-1721523
(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: None
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o  No x
 
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 o  No x
 
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 o No x
 
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 x Noo
 
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.  x
 
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 o
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 o  No x
 
As of June 28, 2013, the last business day of the registrant's most recently completed second fiscal quarter, the registrant's equity was not listed on any domestic exchange or over-the-counter market. The registrant's common units began trading on the New York Stock Exchange on January 15, 2014.
 
As of March 27, 2014, the registrant had 5,913,000 common units and 5,913,000 subordinated units outstanding.
 

 
DOCUMENTS INCORPORATED BY REFERENCE:  None.
 


Table of Contents
 
 
 
Page
 
 
Item 1.
3
Item 1A.
15
Item 1B.
49
Item 2.
49
Item 3.
50
Item 4.
50
 
 
 
 
 
Item 5.
50
Item 6.
53
Item 7.
56
Item 7A.
72
Item 8.
73
Item 9.
73
Item 9A.
73
Item 9B.
73
 
 
 
 
 
Item 10.
74
Item 11.
79
Item 12.
85
Item 13.
87
Item 14.
94
 
 
 
 
 
Item 15.
96
 
176


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.
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. Except as otherwise stated in this Annual Report, all common and subordinated unit ownership interests are stated as of January 21, 2014, the closing date of our IPO.
 
References to:
 
· our general partner” refers to Cypress Energy Partners GP, LLC;
 
· Cypress Holdings” refers to Cypress Energy Holdings, LLC, the indirect owner of our general partner and the indirect owner of 22.8% of our outstanding common units and 94.8% of our subordinated units (excluding units owned by members of our management);
 
· CEM” refers to Cypress Energy Management, LLC, which is a wholly owned subsidiary of our general partner that performs certain administrative and management functions for our partnership;
 
· Cypress LLC” refer to Cypress Energy Partners, LLC which became our wholly owned subsidiary at the closing of our IPO;
 
· CEP TIR” refers to Cypress Energy Partners — TIR, LLC, a subsidiary owned by Cypress Holdings, and an owner of 11.4% of our outstanding common units, 11.4% of our subordinated units and a 36.2% ownership interest in the TIR entities;
 
· CES” refers to Cypress Energy Services, LLC, our 51.0% owned subsidiary that performs management services for 11 SWD facilities in North Dakota, seven of which we own and the remaining four of which are owned by third parties;
 
· Cypress LLC Predecessor” or “Predecessor” refers to, the predecessor for accounting purposes of Cypress LLC, which represents the seven North Dakota limited liability companies we acquired from SBG Energy Services, LLC and collectively comprise our predecessor for accounting purposes;
 
· TIR” refer to the Tulsa Inspection Resources, LLC;
 
· TIR Canada” refer to Tulsa Inspection Resources — Canada ULC;
 
· TIR entities” refer collectively to TIR, TIR Canada, TIR Foley and TIR NDE each of which are our indirect subsidiaries and are 50.1% owned by our partnership, 36.2% owned by CEP TIR, 10.6% owned by Charles C. Stephenson, Jr. and 3.1% owned by Cynthia Field;
 
· TIR Foley” refers to Foley Inspection Services ULC;
 
· TIR NDE” refers to Tulsa Inspection Resources — Nondestructive Examination, LLC; and
2

CAUTIONARY STATEMENTS 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 Operation” 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
 
Cypress Energy Partners, L.P. was formed on September 19, 2013 to provide saltwater disposal and other water and environmental services to U.S. onshore oil and natural gas producers and trucking companies and to provide independent pipeline inspection and integrity services to producers and pipeline companies. As of December 31, 2013, Cypress Energy Holdings II, LLC (“Holdings II”) owned 100% of the limited partner interest in the Partnership, a 100% interest in our general partner and 100% of the member interest in Cypress LLC. Holdings II is owned 100% by Cypress Holdings. The Partnership had no operating activities for the period from inception through December 31, 2013 outside of costs incurred in relation to our new credit agreement and our initial public offering.
 
On January 21, 2014, the Partnership completed its IPO. At the closing of the IPO, Holdings II conveyed its 100% member interest in Cypress LLC to the Partnership in exchange for (a) an aggregate 47.8% interest in the Partnership (0.4% was subsequently conveyed to certain members of management), and (b) the right to receive the proceeds of the IPO. Also, affiliates of Holdings II, directly or indirectly conveyed an aggregate 50.1% interest in the TIR entities to the Partnership in exchange for an aggregate 11.4% ownership in the Partnership. The Partnership subsequently conveyed its interest in the TIR entities to Cypress LLC.  
 
In our Water and Environmental Services segment, which is comprised of the historical operations of Cypress LLC, we own and operate nine saltwater disposal, or SWD facilities, seven 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 four other SWD facilities in the Bakken Shale region. Our customers are oil and natural gas exploration and production companies and trucking companies operating in the regions that we serve. We generate segment revenue primarily by treating produced water and flowback water and injecting them into our SWD facilities. Our segment results are driven primarily by the volumes of produced water and flowback 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 flowback and produced water. We have acquired and, in some cases, expanded recently constructed, high-capacity SWD facilities that are in close proximity to existing producing wells and expected future drilling sites, thereby making our facilities economically attractive options to our current and future customers. Through our 51.0% ownership interest in CES, we also generate segment revenue from fees associated with managing SWD facilities. Prior to the contribution of Cypress LLC to the Partnership, but subsequent to December 31, 2013, Cypress LLC indirectly distributed its 100% member interest in four limited liability companies to Cypress Holdings. One of the distributed entities, SBG Sheridan Facility LLC, contains the assets and liabilities of an SWD facility that is currently not operational. The historical operating results of these distributed entities are included in the historical financial results of Cypress LLC presented herein but will not be included in the Partnership financial results subsequent to the IPO. 
 
In our Pipeline Inspection and Integrity Services segment, which is comprised of the historical operations of the TIR entities, including the 49.9% interests in those entities currently not owned by us, we provide independent inspection and integrity services to various energy, public utility and pipeline companies. The inspectors in this segment perform a variety of 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 this segment are driven primarily by the number and type of inspectors performing services for the TIR entities’ 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 Cypress Holdings, which is owned by Charles C. Stephenson, Jr., various family trusts and a company controlled by our Chairman and Chief Executive Officer, Peter C. Boylan III. Cypress 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. Mr. Boylan has extensive executive management experience with public and private companies and currently serves as a director of two public companies, MRC Global Inc. and BOK Financial Inc., with significant energy, oil and natural gas customers. As the owners of our general partner and the direct or indirect owners of approximately 58.8% of our outstanding limited partner interests, Cypress Holdings and its affiliates have a strong incentive to support and promote the successful execution of our business plan.
 
Business Strategies
 
Our principal business objective is to increase the quarterly cash distributions that we pay to our unitholders over time. We expect to achieve this objective through the following business strategies:
 
· Capitalize on compelling industry fundamentals.
 
· Water and environmental services.  We believe that the water and environmental services market offers attractive long-term growth fundamentals and we intend to continue to position ourselves as a high quality operator of SWD facilities. Over the last few years there has been an increase in the amount of flowback and produced water being disposed in the U.S. This increase has primarily been driven by an increase in the total number of wells drilled and the average length of wells in the U.S. onshore market, each of which generally has resulted in increased use of fracturing fluids in the completion process. We intend to capitalize on the increased demand for removal, treatment, storage and disposal of flowback and produced water by continuing to position ourselves as a trusted provider of safe, high-quality water and environmental services.
 
 
 
· Pipeline inspection and integrity services.  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. 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.
 
· Optimize existing assets.   All of our SWD facilities have been constructed since June 2011. We estimate that we were using approximately 40% of the aggregate estimated capacity of these facilities for the year ended December 31, 2013. 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. 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 our Water and Environmental Services segment.
 
· Increase the number of pipelines connecting 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.
4

· Leverage customer relationships in both 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 our Water and Environmental Services segment also own gathering systems and other pipeline assets to which we can offer pipeline inspection and integrity services. In addition, we intend to enhance our relationships with our customers in our Pipeline Inspection and Integrity Services segment by broadening the services we provide, including expanding our ultrasonic nondestructive examination services and potentially offering aerial inspection services and right of way management services. By cross-selling our service offerings and adding complementary service offerings, we believe that we can further integrate our business segments 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 our Water and Environmental Services segment and our Pipeline Inspection and Integrity segment. Both of our business segments operate in industries that are fragmented, giving us the opportunity to make strategic and accretive acquisitions. We plan to expand our existing Water and Environmental Services segment by seeking acquisitions in existing and additional high-growth resource plays throughout the U.S. that will diversify our customer base. In addition, we intend to grow our Pipeline Inspection and Integrity Services segment by acquiring additional ownership interests in the TIR entities and other pipeline inspection companies. Cypress Holdings has granted us a right of first offer to acquire all or a portion of its remaining ownership interests in the TIR entities, should it choose to sell such interests. The consummation and timing of any such acquisition will depend upon, among other things, Cypress Holdings’ willingness to offer additional ownership interests for sale and its and our ability to obtain any necessary consents, the determination that the acquisition is appropriate for our business at that particular time, our ability to agree on mutually acceptable terms of purchase, including price, and our ability to obtain financing on acceptable terms.
 
Our Business Segments
 
We operate our business in two segments, Water and Environmental Services and Pipeline Inspection and Integrity Services.
 
Water and Environmental Services Segment
 
Overview. Through our Water and Environmental Services segment, which specializes in water and environmental services, we own and operate nine SWD facilities, seven 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. In addition, CES owns a 25% interest in another SWD facility in the Bakken Shale region which we are also under contract to manage through CES. We also manage three other SWD facilities. We are currently working toward obtaining permits for additional facilities at some of our existing and new locations. Our Water and Environmental Services segment is comprised of the historical business of Cypress LLC.
 
Operations. Our Water and Environmental Services segment currently generates revenue by offering the following services:
 
· Flowback water management. We dispose of flowback water produced from hydraulic fracturing operations during the completion of 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. Today, 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 we receive the water at one of our SWD facilities, we treat the water through a combination of separation tanks, gun barrels and chemical processes, store it as necessary prior to injection and then inject it 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 consist of well bores drilled since spring 2011 and 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 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, a management and development company that manages 11 SWD facilities in North Dakota, one SWD facility that is owned by Cypress Holdings and two third-party facilities. 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 based on the gross revenue of the facilities.
 
· Construction management of new SWD facilities. We acted as the construction manager for one third-party SWD facility, which we began managing once the construction was complete. All of these managed facilities are located in North Dakota. Our responsibilities as the construction manager typically include acting as a general contractor to oversee the design and construction of the SWD facility and in some cases assisting with the permitting process. We are compensated for our construction management services based on an agreed-upon fixed fee.
 
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 year ended December 31, 2013, produced water represented approximately 75% of our total barrels of disposed water. 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 well.
 
Each of our SWD facilities is currently operated 24 hours per day, 365 days per year. Our locations in North Dakota currently include onsite offices and housing for the employees. 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 the identity of customers upon arrival 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.
 
The amount of saltwater disposed in our SWD facilities has increased from 0.6 million barrels for the three months ended September 30, 2011 (the first full quarter of operations) to 5.1 million barrels for the three months ended December 31, 2013.
6

As of December 31, 2013, we 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
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

(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.

In addition to the above properties we own or lease, we also manage three other SWD facilities in the Bakken Shale region.
 
Pipeline Inspection and Integrity Services Segment
 
Overview. We believe that through our ownership of the TIR entities we are a leading provider of independent inspection and integrity services to the pipeline industry. We provide services for the pipelines, gathering systems, local distribution systems, equipment and facilities of 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, distribution systems and pipelines. The TIR entities’ 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, 2013, $372 thousand of the operating income attributable to our Pipeline Inspection and Integrity Services segment was generated by Foley and TIR Canada, the entities that form our Canadian operations.
 
The TIR entities offer 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 PHMSA. As the industry continues to adopt new technology, demand has increased for inspectors with greater technical skill and computer proficiency. 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 three months ended December 31, 2013, we employed or engaged an average of 1,745 inspectors in the U.S. and Canada, up approximately 51.2% and 143.7% from the three months ended December 31, 2012 and December 31, 2011, respectively. We intend to form a strategic relationship with CF Inspection LLC, a minority qualified supplier controlled by Cynthia Field, to potentially provide services to current and future customers, including public utilities, that have incentives to contract with minority qualified businesses.
 
Our scope of services includes 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 Pipeline and Hazardous Materials Safety Administration 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
 
Water and Environmental Services Customers
 
Our water and environmental services 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 2013, we had approximately 228 customers in our Water and Environmental Services segment. Our ten largest customers generated approximately 73% of our Water and Environmental Services segment revenue for the years ended December 31, 2012 and 55% of Water and Environmental Services revenue for the year ended December 31, 2013.  There were no individual customers that generated 10% or more of our Water and Environmental Services segment revenue for the year ended December 31, 2013. Two customers, Power Fuels, Inc. and Oxy USA, Inc. accounted for more than 10% of the combined revenues of Cypress LLC and the Predecessor for the year ended December 31, 2012.
 
Pipeline Inspection and Integrity Services Customers
 
Customers. Customers in the Pipeline Inspection and Integrity Services segment 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 year ended December 31, 2013, the TIR entities had 85 customers. The five largest customers in this business segment generated approximately 60% of our segment revenue for the years ended December 31, 2012 and 68% of segment revenue for December 31, 2013. For the years ended December 31, 2012 and December 31, 2013, the following three pipeline inspection and integrity services customers accounted for more than 10% of our revenue, on a combined basis: DCP Midstream, Enbridge Energy Partners and Enterprise Product Partners.
8

Competition
 
Water and Environmental Services Competition
 
The oilfield waste treatment, water and environmental services, and disposal business is highly competitive. 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; reliability of services; track record of environmental compliance; customer service; and price.
 
Pipeline Inspection and Integrity Services Competition
 
The pipeline inspection and integrity business is highly competitive. The TIR entities’ 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, the level of inspector training provided, reputation, dependability of services, customer service and price.
 
Seasonality
 
Water and Environmental Services Seasonality
 
The overall operations and financial performance of our Bakken Shale operations are impacted by seasonality. The volumes 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, the intensity of the 2013-2014 winter has impacted our business operations more than typical winters.
 
Pipeline Inspection and Integrity Services Seasonality
 
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 should 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 the most inspection services during the fourth and first quarters 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. Customers in the independent inspection and integrity service industry typically pay the independent provider a fee consisting of a daily or hourly rate for the pipeline inspection service personnel. The daily or hourly rate generally depends upon the inspector’s skills, certifications and years of experience. The customers also normally reimburse certain expenses of the inspectors, including mileage for travel to the project, and pay the inspector’s per diem expense.
 
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 operations or attributable to 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 substantial compliance with current applicable environmental and occupational health and safety laws and regulations. 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 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.
 
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 capital expenditures, results of operations, or financial position.
 
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, and 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 $25,000 over the next one to three years in connection with continued monitoring and remediation of known contamination at our facilities.
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We 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 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 substantial compliance with permit conditions and state rules. 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, our sales of residual crude oil collected as part of the saltwater injection process 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 substantial 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, the dunes sage lizard and the lesser prairie chicken, endangered species whose natural habitats coincide with some of our areas of operation and the areas of operation of some of our customers. 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 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. 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. In addition, the EPA has continued to adopt GHG regulations of other industries, such as the March 2012 proposed GHG rule restricting future development of 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, recycling 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 cause 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 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 revised proposed rule was subject to an extended 90-day public comment period, which ended on August 23, 2013.
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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, 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 anticipated in 2014 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.
 
Employees
 
We do 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 will be employees of CEM, or another affiliate of Cypress Holdings, and will devote the portion of their time to our business and affairs that is required to manage and conduct our operations. As of December 31, 2013, that entity employed ten people who will provide direct support for our operations, none of whom are covered by collective bargaining agreements. Under the terms of the omnibus agreement, we reimburse CEM for the provision of various general and administrative services for our benefit, for direct expenses incurred by CEM on our behalf and for expenses allocated to us as a result of our becoming a public entity. In addition, as of December 31, 2013, the TIR entities employed or engaged 1,476 inspectors.
 
We also have a co-employment relationship between CEM and a third-party management company that employs approximately 10 people working at our SWD facilities in west Texas. CEM is party to a joint venture with SBG Energy Services, LLC pursuant to which CEM owns a 51.0% equity interest in Cypress Energy Partners – Bakken Operations, LLC, or Bakken Operations, and SBG Energy Services, LLC owns the remaining 49.0% equity interest. As of December 31, 2013, Bakken Operations employed approximately 41 employees, representing the staff of our North Dakota SWD facilities. We pay Bakken Operations a management fee to compensate it for the cost of the 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 saltwater disposal 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 our saltwater disposal business, 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 our pipeline inspection and integrity businesses, TIR’s 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 ($0.3014 for the pro-rata period from the closing of our IPO on January 21, 2014 through March 31, 2014), or $1.55 per unit on an annualized basis ($1.4639 for the pro-rata period from the closing of our IPO on January 21, 2014 through December 31, 2014), we will require available cash of approximately $4.6 million per quarter ($3.6 million for the pro-rata period from the closing of our IPO on January 21, 2014 through March 31, 2014), or $18.3 million per year ($17.3 million for the pro-rata period from the closing of our IPO on January 21, 2014 through December 31, 2014), based on the number of common and subordinated units outstanding after completion of our IPO. 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 our Water and Environmental Services Segment, as well as our Pipeline Inspection and Integrity Services segment;
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· the volume of saltwater we handle in our Water and Environmental Services segment and the number and types of projects conducted by our Pipeline Inspection and Integrity Services segment;
 
· 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, including the remaining interests in the TIR entities held by our affiliates;
 
· the level of competition from other companies;
 
· governmental regulations, including changes in governmental regulations, in our industry;
 
· 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 the date of our IPO ($17.3 million for the pro-rata period from the closing of our IPO on January 21, 2014 through December 31, 2014). 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 the caption “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.
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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.
 
Our Water and Environmental Services segment 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 October 2013, the aggregate U.S. weekly rig count has remained above 1,220 rigs, reaching a peak of 2,026 rigs in August 2008 and declining to 1,809 rigs in March 2014. Recently, there have been significant fluctuations in global crude oil prices, and there have been prolonged declines in natural gas prices. Treatment and disposing of saltwater constituted approximately 73% of our revenue in our Water and Environmental Services Segment for the year ended December 31, 2013; therefore a future significant 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:
 
· 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;
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· 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 TIR entities are substantial, which will reduce our borrowing capacity for other purposes and reduce our cash available for distribution.
 
The TIR entities have substantial working capital needs throughout the year as they pay our inspectors in the U.S. on a weekly basis and in Canada on a bi-weekly basis but typically receive payment from their 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 the TIR entities, 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.
 
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.
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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 the Water and Environmental Services and Pipeline Inspection and Integrity Services segments of our business. 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 and the TIR entities do not typically enter into long-term contracts with customers. While we and the TIR entities each frequently operate under master services agreements with customers that set forth the terms on which we and the TIR entities will provide services, customers operating under these agreements typically have the ability to terminate their relationship with us and the TIR entities 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 73% of our Water and Environmental Services segment revenue (based on the combined revenues of Cypress LLC and the Predecessor) for the year ended December 31, 2012 and 55% of segment revenue for the year ended December 31, 2013. In addition, two of our water and environmental services customers, Power Fuels, Inc. and Oxy USA, Inc. each accounted for more than 10% of our segment revenue for the year ended December 31, 2012. There were no customers that accounted for more than 10% of revenues for the year ended December 31, 2013. Our five largest customers of our Pipeline Inspection and Integrity Services segment accounted for approximately 60% of our segment revenue for the years ended December 31, 2012 and 68% of segment revenue for December 31, 2013. In addition, three of our pipeline inspection and integrity services customers, DCP Midstream, Enbridge Energy Partners and Enterprise Products Partners, each accounted for more than 10% of our revenue for the years ended December 31, 2012 and December 31, 2013. 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 we operate our water and environmental services business 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 will affect our recovery of residual oil and, therefore, our profitability.
 
Approximately 25% of our revenue for the year ended December 31, 2013 in our Water and Environmental Services segment 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.
 
Cypress LLC’s historical results for 2011 and 2012 represent 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 historical and operating data does not include our Pipeline Integrity and Inspection Services segment or any ownership in the TIR entities. 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 Cypress 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.
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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.
 
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, Cypress 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.
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Our ability to acquire assets from Cypress 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 Cypress Holdings.
 
Cypress 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 Cypress Holdings and its affiliates in the future, including acquiring the remaining 49.9% interests in the TIR entities. The consummation and timing of any future acquisitions of these assets will depend upon, among other things, Cypress 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 Cypress Holdings and its affiliates, and Cypress 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 Cypress Holdings and its affiliates if, and when, Cypress 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 Cypress 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.
 
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;
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· 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 substantial 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, an arrangement with an affiliate of SBG Energy Services, LLC, and a 50.1% interest in each of the TIR entities, an arrangement with an entity owned by Cypress Holdings. We may also enter into other arrangements with third parties in the future. SBG Energy Services, LLC and CEP TIR and the other minority owners of the TIR entities have, 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 the TIR entities and CES, may involve risks not otherwise present without a partner, including, for example:
 
· our CES partner shares certain blocking rights over transactions between CES 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 the TIR entities and CES, we owe contractual duties to the TIR entities, CES and their 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 TIR’s existing revolving credit facility and mezzanine facilities. CEP TIR and TIR 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;
 
· alter our line of business;
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· 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 “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, 2013, we had $75.0 million of indebtedness outstanding under our credit agreement. 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.
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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.
 
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, 2013, 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. In August 2012, one saltwater disposal company withdrew its application to drill an SWD well in Helena, Texas five months after local residents formally protested the permit application to the Texas Railroad Commission. 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.
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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 $9 thousand on our balance sheet related to our future closure obligations of our SWD facilities, as of December 31, 2013. 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, recycling 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.
 
In addition, the Environmental Protection Agency, or 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 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 revised proposed rule was presently subject to an extended 90-day public comment period, which ended on August 23, 2013.
 
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, 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.
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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 anticipated in 2014 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. In addition, 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. Additional regulatory measures designed to minimize or avoid damage to geologic formations may be imposed to address such concerns. 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 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.
 
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. 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 the omnibus agreement, Cypress 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 Cypress Holdings for these indemnification obligations is subject to a $350,000 deductible. Moreover, our assets constitute a substantial portion of Cypress Holdings’ assets, and Cypress Holdings has not agreed to maintain any cash reserve to fund any indemnification obligations under the 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.
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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.
 
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 the omnibus agreement, which currently limits our corporate general and administrative services to an annual administrative fee of $4.0 million.  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.
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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. 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.
 
For example, the federal government is considering listing the greater sage-grouse and the dunes sagebrush lizard, 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, is also on the list as a candidate species for protection under the ESA. 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.
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We have customers in New Mexico, Texas, Oklahoma, Wyoming and North Dakota that have operations within the habitat of the greater sage-grouse, the dunes sage brush lizard 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.  Furthermore, such protection systems are no guarantee that lightning will not strike and damage 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, the inspector is considered an employee of TIR and is eligible for workers’ compensation claims if the inspector is injured or killed while working for TIR. As the inspectors generally travel to and from projects in their own vehicles, TIR 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.
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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 nine owned and four 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 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.
 
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 our Water and Environmental Services segment 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 our Pipeline Inspection and Integrity Services segment 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 and the TIR entities 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.
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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, our Pipeline Inspection and Integrity segment 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 our Pipeline Inspection and Integrity Services segment could choose to hire TIR’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, all of whom are employees of affiliates of our general partner. Additionally, neither we nor our subsidiaries have employees. CEM 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.
 
Our business would be adversely affected if we or our customers experienced 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;
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· 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.
 
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.
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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 our independent registered public accounting firm to attest to, the effectiveness of our internal controls over financial reporting. We must comply with Section 404 (except for the requirement for an auditor’s attestation report, as described below) beginning with our fiscal year ending December 31, 2014. 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 recently enacted 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. Even if we conclude that the 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.
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Risks Inherent in an Investment in Us
 
Our general partner and its affiliates, including Cypress 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 Cypress Holdings, and Cypress Holdings is under no obligation to adopt a business strategy that favors us.
 
Cypress Holdings and its affiliates own a 63.6% 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, Cypress Holdings. Conflicts of interest may arise between Cypress 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 Cypress Holdings, over the interests of our common unitholders. These conflicts include, among others, the following situations:
 
· neither our partnership agreement nor any other agreement requires Cypress Holdings to pursue a business strategy that favors us or utilizes our assets, which could involve decisions by Cypress Holdings to invest in competitors, pursue and grow particular markets, or undertake acquisition opportunities for itself. Cypress Holdings’ directors and officers have a fiduciary duty to make these decisions in the best interests of Cypress Holdings;
 
· our general partner is allowed to take into account the interests of parties other than us, such as Cypress Holdings, in resolving conflicts of interest;
 
· Cypress 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;
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· 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 “Conflicts of Interest and Duties.”
 
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.
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Our partnership agreement replaces our general partner’s fiduciary duties to holders of our common units with contractual standards governing its duties.
 
Delaware law provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to limited partners and the partnership, provided that partnership agreements may not eliminate the implied contractual covenant of good faith and fair dealing. This implied covenant is a judicial doctrine utilized by Delaware courts in connection with interpreting ambiguities in partnership agreements and other contracts, and does not form the basis of any separate or independent fiduciary duty in addition to the express contractual duties set forth in our partnership agreement. Under the implied contractual covenant of good faith and fair dealing, a court will enforce the reasonable expectations of the partners where the language in the partnership agreement does not provide for a clear course of action.
 
As permitted by Delaware law, 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 “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 “Conflicts of Interest and Duties.”
 
Cost reimbursements and fees due to our general partner for services provided to us or on our behalf following the expiration of the omnibus agreement could be substantial and will reduce our cash available for distribution to our unitholders.
 
Pursuant to the omnibus agreement, prior to making any distributions to our unitholders, we will pay our general partner a quarterly administrative fee of $1.0 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 the omnibus agreement, in lieu of the quarterly fee, we will be required by our partnership agreement to reimburse our general partner 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 our general partner will determine in good faith the expenses that are allocable to us. Furthermore, our general partner 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 our general partner. Payments to our general partner and its affiliates following the expiration of the omnibus agreement could be substantial and will reduce the amount of cash we have available to distribute to unitholders.
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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 Cypress 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.  Our general partner and its affiliates own 63.6% of the common units and subordinated units (excluding common units purchased by certain of our officers, directors and other affiliates under our directed unit program). 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.
 
“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 unites 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 Cypress 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.
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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 Cypress 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.
 
Cypress 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.
 
Our general partner and its controlled affiliates 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 Cypress Holdings 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.
 
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.
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Affiliates of our general partner, including, but not limited to, Cypress 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 omnibus agreement will prohibit Cypress 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 Cypress 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 the omnibus agreement, neither Cypress 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 Cypress 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 Cypress Holdings’ assets is subject to risks and uncertainty, and ultimately we may not acquire any of those assets.
 
Our omnibus agreement provides us with a right of first offer on certain assets owned by and ownership interests held by Cypress 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 Cypress 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 Cypress 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 Cypress Holdings, terminated by Cypress 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. Our general partner and its affiliates own approximately 22.8% of our common units (excluding any common units purchased by certain of our officers, directors and other affiliates under our directed unit program). At the end of the subordination period (which could occur as early as December 31, 2014), 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 under our directed unit program) 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.
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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. Cypress Holdings through a wholly owned subsidiary and its controlled affiliates 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.
 
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.
 
We will incur increased costs as a result of being a publicly traded partnership.
 
As a publicly traded partnership, we will incur significant legal, accounting and other expenses. In addition, the Sarbanes-Oxley Act of 2002 and related rules subsequently implemented by the SEC and the NYSE have required changes in the corporate governance practices of publicly traded companies. We expect these rules and regulations to increase our legal and financial compliance costs and to make these activities more time-consuming and costly. For example, as a result of becoming a publicly traded partnership, we are required to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our publicly traded partnership reporting requirements and our general partner will maintain director and officer liability insurance under a separate policy. It is possible that our incremental costs of being a publicly traded partnership will be higher than we currently estimate. This incremental public company cost will initially be included in a $4.0 million annual administrative fee we will pay our general partner for providing us with certain partnership overhead services; however, in the event of termination of the omnibus agreement, we will be required by our partnership agreement to reimburse our general partner and its affiliates for all costs and expenses that they incur on our behalf for managing and controlling our business and operations, which we expect would be greater than $4.0 million. In addition, the $4.0 million annual administrative fee will be subject to an increase by an annual amount equal to the producer price index plus one percent.
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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 Cypress Holdings, which owns our general partner, will sell or contribute additional assets to us, as Cypress 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.
45

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 propose and consider substantive changes to the existing federal income tax laws that affect 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.
46

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 conclusions of our counsel or 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 our counsel’s conclusions or the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of our counsel’s conclusions or 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.
 
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, a unitholder should consult a tax advisor before investing in our common units.
 
TIR conducts activities that may not generate qualifying income, and we intend to conduct these activities in a separate subsidiary that will be treated as a corporation for U.S. federal income tax purposes. Corporate federal income tax paid by this subsidiary will reduce 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. In an attempt to ensure that 90% or more of our gross income in each tax year is qualifying income, we currently intend to conduct the portion of our business related to these operations in a separate subsidiary that will be treated as a corporation for U.S. federal income tax purposes. We estimate that these operations will represent approximately 8% of the combined gross margin of the TIR entities in the future.
 
This corporate subsidiary will be subject to corporate-level tax, which will reduce 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.
47

We will 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. 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 will 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, and, accordingly, our counsel is unable to opine as to the validity of this method. 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 will adopt. 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.
48

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 initially expect to 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. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units. Unitholders should consult their tax advisors.
 
ITEM 1B.
UNRESOLVED STAFF COMMENTS
 
Not Applicable.
 
ITEM 2.
PROPERTIES
 
Our Properties
 
In our Water and Environmental Services segment, as of December 31, 2013, we had an aggregate of approximately 115 thousand 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:
49

Location
 
County
 
In-service Date
 
Leased or Owned
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

(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.
 
In addition to the above properties we own or lease, we also manage three other SWD facilities in the Bakken Shale region, one of which is owned by Cypress Holdings.
 
We do not own or lease any significant properties in our Pipeline Inspection and Integrity Services segment.
 
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.
 
TIR’s corporate headquarters are located at 4111 S. Darlington Ave., Suite 1000, Tulsa, Oklahoma 74135. TIR leases 12,909 square feet of general office space at its corporate headquarters. A lease for 2,255 square feet expired on February 28, 2014, and TIR currently occupies on a month-to-month basis while working with the landlord on an extension of the term of such lease. The remaining lease expires on June 30, 2018 unless terminated earlier under certain circumstances specified in our lease.
 
ITEM 3.
LEGAL PROCEEDINGS
 
From time to time, we are subject to legal proceedings and claims that arise in the ordinary course of business. Like other partnerships, 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.
 
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.”
 
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 March 27, 2014, the closing price for the common units was $21.87 per unit and there were approximately five unitholders of record of the Partnership’s common units. The number of unit holders was computed based on the number of record holders at March 27, 2014. This number does not include unitholders whose units are held in trust by other entities. The actual number of unitholders is greater than the number of holders of record.
50

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 Cypress 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.
 
Cash Distributions to Unitholders
 
We intend 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.
 
Our Cash Distribution Policy
 
Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending March 31, 2014, we distribute all of our available cash to unitholders of record on the applicable record date. We will prorate the minimum quarterly distribution payable in respect of the quarter ending March 31, 2014 for the period from January 21, 2014 (the date of the closing of our IPO) through March 31, 2014.
 
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.
 
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.
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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 March 27, 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.”
 
We were formed in September 2013 and our historical financial operating results primarily reflect costs associated with our initial public offering. Therefore, we present the historical financial statements and data of Cypress LLC and our Predecessor.  Set forth below is the following financial data:
 
•selected historical financial data as of and for the year ended December 31, 2013 and as of December 31, 2012 and for the period from March 15, 2012 (Inception) through December 31, 2012 of Cypress LLC, and selected historical financial data for the period from June 1, 2011 (Predecessor Inception) through December 31, 2011 and the year ended December 31, 2012 of the Predecessor, which have been derived from the audited consolidated financial statements of Cypress Energy Partners, LLC that are included in “Item 8 – Financial Statements and Supplementary Data.”
 
We do not provide selected historical financial data for the TIR entities, in which we received a 50.1% interest in each at the closing of our IPO. For historical financial data for the TIR entities please read the audited combined financial statements of the Tulsa Inspection Resources Entities as of and for the year ended December 31, 2013 and the audited consolidated financial statements of Tulsa Inspection Resources, Inc. as of and for the years ended December 31, 2012 and 2011 included in “Item 8 – Financial Statements and Supplementary Data.”
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.
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Cypress LLC
   
Predecessor
 
 
 
Year Ended December 31, 2013
   
Period from March 15 (Inception) through December 31, 2012 (1)
   
Year Ended December 31, 2012
   
Period from June 1 (Inception) through December 31, 2011
 
 
 
(in thousands, except operational data)
 
Income Statement Data
 
   
   
   
 
Revenues
 
$
22,392
   
$
619
   
$
12,203
   
$
2,944
 
Costs of sales
   
7,643
     
309
     
3,662
     
503
 
Gross margin
   
14,749
     
310
     
8,541
     
2,441
 
General and administrative expense
   
3,334
     
2,056
     
477
     
138
 
Depreciation and amortization expense
   
4,084
     
99
     
1,398
     
123
 
Operating income (loss)
   
(473
)
   
(1,845
)
   
6,666
     
2,180
 
Interest expense, net
   
-
     
-
     
111
     
35
 
Net income (loss)
   
10,764
     
(1,845
)
   
6,595
     
2,162
 
Net income attributable to non-controlling interests
   
22
     
-
     
-
     
-
 
Net income attributable to controlling interests
   
10,742
     
(1,845
)    
6,595
     
2,162
 
Balance Sheet Data - Period End
                               
Total assets
 
$
81,865
   
$
85,342
   
$
27,588
   
$
14,476
 
Total debt
   
-
     
-
     
2,314
     
2,798
 
Member’s equity
   
79,645
     
71,651
     
24,769
     
9,265
 
Cash Flows Data
                               
Cash flows provided by (used in) operating activities
 
$
10,368
   
$
(2,244
)
 
$
7,246
   
$
1,106
 
Cash flows provided by (used in) investing activities
   
(3,140
)
   
(70,670
)
   
(15,236
)
   
(10,860
)
Cash flows provided by (used in) financing activities
   
(3,467
)
   
73,496
     
8,425
     
9,901
 
Other financial data
                               
Adjusted EBITDA
 
$
11,456
   
$
(1,746
)
 
$
8,104
   
$
2,320
 
Adjusted EBITDA attributable to controlling interests
   
11,425
     
(1,746
)
   
8,104
     
2,320
 
Capital expenditures
   
3,140
     
70,670
     
15,236
     
10,860
 
Operational data
                               
Total barrels of saltwater disposed (in thousands)
   
19,666
     
551
     
8,674
     
1,641
 
Average revenue per barrel
 
$
1.14
   
$
1.12
   
$
1.41
   
$
1.79
 

(1) During the period from its inception through the date of its acquisition of the Predecessor on December 31, 2012, Cypress LLC had no significant assets or operations.
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Non-GAAP Financial Measures

We define Adjusted EBITDA as net income, plus interest expense, depreciation and amortization expenses, income tax expense and impairments related to SWD facilities, one of which was retained by Cypress Holdings, less the gain on the reversal of a contingent liability related to the acquisition of the Cypress LLC Predecessor. 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 as presented below may not be comparable to similarly titled measures of other companies.
 
The following table presents a reconciliation of Adjusted EBITDA to net income (loss) and net cash provided by (used in) operating activities, as applicable, for each of the periods indicated.
55

 
 
Cypress LLC
   
Predecessor
 
 
 
Year Ended December 31, 2013
   
Period from March 15 (Inception) through December 31, 2012 (1)
   
Year Ended December 31, 2012
   
Period from June 1 (Inception) through December 31, 2011
 
 
 
(in thousands)
 
Reconciliation of Adjusted EBITDA to Net Income (Loss)
 
   
   
   
 
Net Income (loss)
 
$
10,764
   
$
(1,845
)
 
$
6,595
   
$
2,162
 
Add:
                               
Interest expense
   
-
     
-
     
111
     
35
 
Depreciation and amortization
   
4,084
     
99
     
1,398
     
123
 
Impairments
   
7,804
     
-
     
-
     
-
 
Income tax expense
   
54
     
-
     
-
     
-
 
Less:
                               
Gain on reversal of contingent consideration
   
11,250
     
-
     
-
     
-
 
Adjusted EBITDA
 
$
11,456
   
$
(1,746
)
 
$
8,104
   
$
2,320
 
 
Reconciliation of Adjusted EBITDA Attributable to Controlling Interest to Net Income Attributable to Controlling Interest (2)
                               
Net income attributable to controlling interest $ 10,742
     Add:
        Depreciation and amortization attributable to controlling interest 4,075
        Impairments attributable to controlling interest 7,804
        Income tax expense attributable to controlling interest 54
     Less:
        Gain on reversal of contingent consideration attributable to controlling interest 11,250
Adjusted EBITDA attributable to controlling interest  $ 11,425
 
Reconciliation of Adjusted EBITDA to Net Cash Provided by (Used in) Operating Activities
                               
Cash flows provided by (used in) operating activities
 
$
10,368
   
$
(2,244
)
 
$
7,246
   
$
1,106
 
Changes in accounts receivable
   
(549
)
   
(741
)
   
(219
)
   
(1,638
)
Changes in inventory, prepaid expenses and other assets
   
(47
)
   
(12
)
   
(353
)
   
(125
)
Changes in accounts payable and accrued liabilities
   
(408
)
   
255
     
(175
)
   
584
 
Interest expense
   
-
     
-
     
(111
)
   
(35
)
Income tax expense
   
(54
)    
-
     
-
     
-
 
Other
(30 ) -     - -
Adjusted EBITDA
 
$
11,456
   
$
(1,746
)
 
$
8,104
   
$
2,320
 

(1) During the period from its inception through the date of its acquisition of the Predecessor on December 31, 2012, the Cypress LLC had no significant assets or operations.
(2) There were no non controlling interests prior to October 1, 2013.
 
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.  Because we were formed in September 2013 and our historical financial operating results primarily reflect costs incurred associated with our IPO, we present the historical financial statements and discussion and analysis of Cypress LLC, including its Predecessor, and of the TIR entities on a combined basis.   At the closing of our IPO on January 21, 2014, Cypress LLC and a 50.1% interest in the TIR entities were contributed to us and became our Water and Environmental Services segment and our Pipeline Inspection and Integrity Services segment, respectively.  On June 26, 2013, Cypress Holdings indirectly acquired a controlling interest in the TIR entities.  The contribution of the TIR entities will be treated for accounting purposes as a combination of entities under common control and the results of the TIR entities will be included in our financial statements for periods subsequent to June 26, 2013.  Accordingly, the operating results and discussion and analysis for the TIR entities is for the period from June 26, 2013 through December 31, 2013.  The financial information for Cypress LLC and the TIR entities included in “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations” should be read in conjunction with the audited financial statement of Cypress Energy Partners, LLC as of December 31, 2013 and 2012 and for the years ended December 31, 2013, 2012 and 2011 and the audited combined financial statements of the Tulsa Inspection Resources Entities as of and for the year ended December 31, 2013 and the audited consolidated financial statements of Tulsa Inspection Resources, Inc. as of and for the years ended December 31, 2012 and 2011 included in “Item 8 – Financial Statements and Supplementary Data.”
56

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 Statements 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 to U.S. onshore oil and natural gas producers and trucking companies. Through our Water and Environmental Services segment, which is comprised of the historical operations of Cypress LLC and its Predecessor, we own and operate nine SWD facilities, seven 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 four other SWD facilities in the Bakken Shale region. Our Water and Environmental Services segment customers are oil and natural gas exploration and production companies and trucking companies operating in the regions that we serve. Through our Pipeline Inspection and Integrity Services segment, we provide independent pipeline inspection and integrity services to various energy, public utility and pipeline companies.  The Pipeline Inspection and Integrity Services segment is comprised of the operations of the TIR entities since Cypress Holdings obtained control on June 26, 2013. 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 will generate revenue in our Water and Environmental Services segment primarily by treating flowback and produced water and injecting the saltwater into our SWD facilities. Our results in the Water and Environmental Services segment are driven primarily by the volumes of produced water and flowback 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 flowback and produced water. Through our 51.0% ownership interest in CES we also generate revenue managing SWD facilities for a fee.

Through our 50.1% ownership interests in the TIR entities, we will generate revenue in our Pipeline Inspection and Integrity Services segment 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 the Pipeline Inspection and Integrity Services segment 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 charge our inspectors’ services out to customers on a per project basis, including per diem charges, mileage and other reimbursement items.
57

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 the Water and Environmental Services segment;

inspector headcount in the Pipeline Inspection and Integrity Services segment;

operating expenses;

segment gross margin;

Adjusted EBITDA; and

distributable cash flow.

Saltwater Disposal and Residual Oil Volumes
 
The amount of revenue we generate in our Water and Environmental Services segment 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 published rates that are determined based on the quality of the oil sold. 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 25% of our revenue for the year ended December 31, 2013 in our Water and Environmental Services segment 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.

Inspector Headcount
 
The amount of revenue we generate in our Pipeline Inspection and Integrity Services segment 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 sales or services, general and administrative, and depreciation and amortization.

Costs of sales or 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 sales components in our Water and Environmental Services segment. 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 our Pipeline Inspection and Integrity Services segment. 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.
58

General and administrative. Cypress LLC’s historical general and administrative expenses included expenses related to royalty expenses, management fees, legal fees and other expenses for the operation of our wells.

Under the omnibus agreement, our general partner 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. The amount of this fee is approximately the amount we would expect to reimburse the general partner for such services in the absence of the fee.

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. These incremental partnership overhead expenses are not reflected in our historical financial statements. For the year ending December 31, 2014, pursuant to the omnibus agreement, $1.0 million of this partnership overhead expense attributable to our operating as a publicly traded partnership will be absorbed by Cypress Holdings and affiliates, the owners of the 49.9% non-controlling interests in the TIR entities.  Included in the administrative fee for future general and administrative expenses will be compensation expense associated with the Cypress Energy Partners, L.P. 2013 Long-Term Incentive Plan. In the event of termination of the omnibus agreement, in lieu of the quarterly fee, we will be required by our partnership agreement to reimburse our general partner 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 our general partner will determine in good faith the expenses that are allocable to us. Furthermore, our general partner and its affiliates 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 our general partner. Payments to our general partner and its affiliates following the expiration of the 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 applicable year. Depreciation is recorded on a straight-line basis. We estimate our assets have useful lives ranging from three years to 39 years. The facilities, wells and equipment constituted 91.0% of our assets as of December 31, 2012 and December 31, 2013 and have useful lives of nine 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 and impairments related to SWD facilities, one of which is retained by Cypress Holdings, less a gain on the reversal of a contingent liability related to the acquisition of the Cypress LLC Predecessor. 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 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 our Pipeline Inspection and Integrity Services segment varies 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:
59

 
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 any of 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
 
Our Pipeline Inspection and Integrity Services segment is experiencing increased customer demand for our inspectors, beginning in the fourth quarter of 2013 and continuing throughout the first quarter of 2014. This increased demand has resulted in an increase in the number of inspectors we have employed or engaged during this period. Our Water and Environmental Services segment has been impacted by a more pronounced seasonal reduction in saltwater received at our SWD facilities than during past winters, resulting in our disposing of decreased volumes of salt water, beginning in December of 2013 and continuing through a majority of the first quarter of 2014. We believe these reduced volumes have resulted from factors including our customers’ reduced activities during the severe winter experienced in the geographic area where our Bakken Shale SWD facilities are located, as well as competition in both of the regions in which we operate. While we believe much of the recent decline in our saltwater volumes is weather related and seasonal, we do not have sufficient information to determine whether or how long the trends in either segment will continue. We do not expect that factors underlying these trends will impact the distribution forecast for the year ending December 31, 2014 contained in the IPO prospectus.
 
Results of Operations – Cypress LLC and the Predecessor
 
Results Presented and Factors Affecting the Comparability of the Historical Financial
Results of Cypress LLC and the Predecessor and of our Future Results

The Predecessor’s inception date was June 1, 2011, and Cypress LLC’s inception date was March 15, 2012. Cypress LLC acquired its Predecessor on December 31, 2012.
 
Cypress LLC incurred costs associated with its formation and acquisition activities but had no material operations until its acquisition of four newly constructed EPA Class II SWD facilities from Moxie Disposal Systems, LLC and Peach Energy Services, LLC, or collectively the Moxie Assets, on December 3, 2012. Therefore, the financial and operating data for 2011 discussed below represents the Predecessor’s operations from June 1, 2011 (Inception) through December 31, 2011 and the financial and operating data for 2012 discussed below represents the Predecessor’s operations from January 1, 2012 through December 31, 2012. The financial and operating data for the year ended December 31, 2013 discussed below represents Cypress LLC’s operations from January 1, 2013 through December 31, 2013.
 
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 the reasons described below:
 
· Cypress LLC had no operations until its acquisition of the Moxie Assets on December 3, 2012. Financial data for Cypress LLC for the period from Inception through December 31, 2012, is excluded from the tables below.
 
· The financial and operating data presented below only include management services that are performed by CES, in which we owned a 51.0% interest, for the period of October 1, 2013 through December 31, 2013.
60

· Historical results of Cypress LLC and its Predecessor include results of an SWD facility located in Sheridan County, Montana and a permit relating to a potential SWD facility that was distributed to Cypress Holdings prior to the closing of our IPO. In addition, historical results of Cypress LLC for the year ended December 31, 2013 include an impairment relating to that facility.
 
· Cypress LLC’s Predecessor had one operating SWD facility on June 30, 2011, two operating SWD facilities on December 31, 2011, five SWD facilities on June 30, 2012 and six SWD facilities on December 31, 2012. Financial data for Cypress LLC for the period from inception through December 31, 2012, is excluded from the tables below.
 
· General and administrative expenses of the Predecessor’s SWD facilities represent expenses associated with those assets as stand-alone businesses and may not represent sales and general and administrative expenses we will incur to operate those assets as part of a larger business. Operating expenses associated with Cypress 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 LLC and its Predecessor for the periods indicated.
 
 
 
Cypress LLC Year Ended December 31, 2013
   
Predecessor Year Ended December 31, 2012
   
Change 2013 to 2012
   
Predecessor Period from June 1 (Inception) through December 31, 2011
   
Change 2012 to 2011
 
 
 
(in thousands except per barrel data)
   
 
Income Statement Data
 
   
   
   
   
 
Revenues
 
$
22,392
   
$
12,203
   
$
10,189
   
$
2,944
   
$
9,259
 
Costs of sales
   
7,643
     
3,662
     
3,981
     
503
     
3,159
 
Gross margin
 
$
14,749
   
$
8,541
   
$
6,208
   
$
2,441
   
$
6,100
 
Gross margin %
   
66
%
   
70
%
           
83
%
       
Total barrels of saltwater disposed
   
19,666
     
8,674
     
10,992
     
1,641
     
7,033
 
Average revenue per barrel
 
$
1.14
   
$
1.41
   
$
(0.27
)
 
$
1.79
   
$
(0.38
)

Cypress LLC Year Ended December 31, 2013 Compared to
Predecessor Year Ended December 31, 2012

Total Revenues
 
Cypress LLC’s revenues were $22.4 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 83%. 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 19.7 million barrels for the same period in 2013. This increase in saltwater disposal volumes was associated with the addition of four wells in December 2012, which 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. The revenues also reflected an increase in residual oil revenues from the year ended December 31, 2012 due to the addition of the Moxie Assets located in west Texas, which have historically generated more residual oil sales volumes than our other wells.
61

Costs of Sales
 
Cypress LLC’s costs of sales were $7.6 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 105%. This increase was primarily attributable to only five wells being operational during the majority of the year ended December 31, 2012 as compared to nine wells operating for the majority of 2013. Incremental costs of sales attributable to wells not in operation at December 31, 2012 were $3.4 million.
 
Gross Margin
 
Gross margin was $14.7 million for the year ended December 31, 2013, compared to $8.5 million for the same period of 2012, an increase of $6.2 million or 73%.  The increase in gross margin was primarily driven by the increase in revenue for the same period.  Gross margin as a percentage of total revenues declined to 66% 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 attributable to the fact that most of the wells did not come on line until 2012.
 
Depreciation and Amortization Expenses
 
Cypress LLC's depreciation and amortization expenses were $4.1 million for the year ended December 31, 2013, compared to its Predecessor's $1.4 million for the same period in 2012, an increase of 193%. Depreciation and amortization for Cypress LLC increased primarily as a result of its having more SWD wells and a higher depreciable basis in the SWD wells acquired from the Predecessor on December 31, 2012.
 
General and Administrative Expenses
 
Cypress LLC’s general and administrative expenses were $3.3 million for the year ended December 31, 2013, compared to $0.5 million for its Predecessor for the same period in 2012, an increase of 560%. General and administrative expenses increased by $2.3 million attributable to $0.5 in incremental expenses associated with operating the Moxie wells for a full year and $1.8 million attributable to Cypress LLC corporate office activities.  The increase in the corporate activities was largely attributable to an increase in professional services of $1.2 million incurred primarily in relation to legal and accounting services. The remaining corporate activity costs were associated with corporate salaries of $0.5 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.
 
Net Income
 
Cypress LLC recorded net income of approximately $10.8 million for the year ended December 31, 2013, compared to its Predecessor’s net income of $6.6 million for the same period in 2012, an increase of 62%. Operationally, this increase in net income was primarily the result of higher segment gross margin from the increased number of well sites of $6.2 million offset by higher operating expenses, primarily depreciation and amortization ($2.7 million increase) and general and administrative expenses ($2.8 million increase) associated with the expanded operations. Additionally, net income was impacted by the $11.3 million gain recorded for the reversal of contingent consideration from the acquisition of the Cypress LLC Predecessor on December 31, 2012 offset by $7.8 million in impairments recorded on two of its SWD facilities.
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Predecessor Year Ended December 31, 2012 Compared to
the Predecessor Period from June 1, 2011 (Inception) to December 31, 2011

Total Revenues
 
Revenues were $12.2 million for the year ended December 31, 2012, compared to $2.9 million for the period from June 1, 2011 to December 31, 2011, an increase of 321%. The overall increase in saltwater disposal revenues was primarily driven by a 444% increase in saltwater disposal volumes from 1.6 million barrels for the year ended December 31, 2011 to 8.7 million barrels for the year ended December 31, 2012. This increase in saltwater disposal volumes was associated with the addition of four wells between the comparable periods, which was offset somewhat by a 21% decline in average pricing across the wells from $1.79 per barrel of disposed saltwater for the period from June 1, 2011 to December 31, 2011 to $1.41 for the year ended December 31, 2012. The decline in revenue per barrel was primarily attributable to the decision to reduce pricing in the Bakken Shale region due to competitive pressures and an increase in the mix of produced water volumes.
 
Costs of Sales
 
Costs of sales were $3.7 million for the year ended December 31, 2012, compared to $0.5 million for the period from June 1, 2011 to December 31, 2011, an increase of 640%. The increase is primarily attributable to higher employment costs, repairs and maintenance and utility costs associated with operating the four additional SWD facilities.
 
Gross Margin
 
Gross margin was $8.5 million for the year ended December 31, 2012, compared to $2.4 million for the period from June 1, 2011 to December 31, 2011, an increase of $6.1 million or 254%.  The increase in gross margin was primarily driven by the increase in revenue for the same period.
 
Depreciation Expense
 
The depreciation expense was $1.4 million for the year ended December 31, 2012, compared to $0.1 million for the period from June 1, 2011 to December 31, 2011, an increase of 1,300%. The increase was primarily due to having a full year of depreciation on wells placed in service in 2011 and the addition of four new wells in 2012.
 
General and Administrative Expenses
 
General and administrative expenses were $0.5 million for the year ended December 31, 2012, compared to $0.1 million for the period from June 1, 2011 to December 31, 2011, an increase of 400%. The increase was primarily attributable to the operation of four additional SWD facilities.
 
Net Income
 
Net income was $6.6 million for the year ended December 31, 2012, compared to $2.2 million for the period from June 1, 2011 to December 31, 2011, an increase of 200%. This increase in net income was primarily driven by an increase in revenue associated with the opening of four additional SWD facilities and having a full year of operations for the two SWD facilities in operation at December 31, 2011, offset by their corresponding costs of sales, depreciation expense and general and administrative and other expenses.
63

Combined Results of Operations – Tulsa Inspection Resources Entities
 
The following table summarizes historical combined financial statements information of the TIR entities for the period from June 27, 2013 through December 31, 2013 which represents the operation of the TIR entities from the point in which Cypress Holdings obtained control. This information should be read in conjunction with the audited combined financial statements of the Tulsa Inspection Resources Entities as of and for the year ended December 31, 2013 and the audited consolidated financial statements of Tulsa Inspection Resources, Inc. as of and for the years ended December 31, 2012 and 2011 included in “Item 8 – Financial Statements and Supplementary Data.”
 
 
 
Tulsa Inspection
Resources Entities
 
 
 
Period from June
27, 2013 through
December 31, 2013
 
Income Statement Data
 
 
Revenues
 
$
227,046
 
Costs of services
   
206,344
 
Gross margin
 
$
20,702
 
Operational data
       
Average number of inspectors (per week)
   
1,706
 
Average revenue per inspector (per week)
 
$
4,952
 

Combined Results of Operations for the Tulsa Inspection Resources Entities for the Period from June 27, 2013 through December 31, 2013.
 
Total Revenues
 
Revenues were $226.9 million for the period.  The average weekly inspector headcount for the period was 1,706 resulting in average revenue per inspector of $5,030.
 
Costs of Services
 
Costs of services were $206.2 million for the year ended December 31, 2013.  Costs of services are primarily driven by the payroll costs associated with the average inspector headcount during the period and to a lesser extent reimbursable expenses associated with the inspectors including per diem, mileage, etc.
 
Gross Margin
 
Gross margin was $20.7 million or 9% of total revenues for the period.
 
Depreciation and Amortization Expense
 
Depreciation expense was $1.3 million for the period.  Net property and equipment was $1.2 million at December 31, 2013 and consists primarily of small equipment.  Amortization expenses primarily reflects amortization associated with the fair value of the TIR entities’ intangible assets.
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General and Administrative Expenses
 
General and administrative expenses were $9.2 million for the period.  General and administrative expenses for the period include recurring expenses associated with administrative personnel, including salaries and related expenses as well as some non-recurring expenses incurred in conjunction with the acquisition by Cypress Holdings.  Change of control bonus payments totaling $1.8 million were made during 2013 along with increased legal and professional fees totaling $0.5 million associated with the change of control and subsequent company conversion to a limited liability company.
 
Net Loss
 
The net loss for the period was $9.6 million.   Net income is driven by total operating income of $10.2 million offset by interest expense of $4.0 million, income tax expense of $15.0 million and an impairment of intangible assets of $0.7 million.  Income tax expense includes taxes of $15.0 million associated with the conversion of Tulsa Inspection Resources, Inc. to a limited liability company effective December 9, 2013.
 
Liquidity and Capital Resources
 
We anticipate that we will continue to make significant growth capital expenditures in the future, including acquiring new SWD facilities or expanding our existing assets and offerings in our current business segments. In addition, the working capital needs of the TIR entities are substantial. Please read “Risk Factors — Risks Related to Our Business — The working capital needs of the TIR entities are substantial”, which could require us to seek additional financing that we may not be able to obtain on satisfactory terms, or at all. Consequently, our ability to develop and maintain sources of funds to meet our capital requirements is critical to our ability to meet our growth objectives. We expect that our future growth capital expenditures will be funded by borrowings under our credit agreement and the issuance of debt and equity securities. However, we may not be able to raise additional funds on desired or favorable terms or at all.
 
Since the acquisition of the Moxie assets in December 2012, Cypress LLC’s sources of liquidity have included cash generated from operations and equity investments by Cypress Holdings, the owner of our general partner.
 
At December 31, 2013, our sources of liquidity included:
 
· cash generated from operations, which resulted in $4.3 million in cash on the balance sheet at December 31, 2013;
 
· borrowings under our credit agreement under which we had $45.0 million available for borrowings at December 31, 2013; and
 
· issuances of equity securities.
 
We believe that the cash generated from these sources will be sufficient to allow us to meet our requirements for minimum quarterly distributions, working capital and capital expenditures for the foreseeable future.
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Cash Flows
 
The following table reflects cash flows for the applicable periods for Cypress LLC and its Predecessor:
 
 
Cypress LLC
   
Predecessor
 
 
 
Year Ended December 31,
 
 
 
2013
   
2012
   
2011
 
Net cash provided by (used in):
 
   
   
 
Operating  Activities
 
$
10,368
   
$
7,246
   
$
1,106
 
Investing Activities
   
(3,140
)
   
(15,236
)
   
(10,860
)
Financing Activities
   
(3,467
)
   
8,425
     
9,901
 
 
 
 
 
 
 

 
For the period from June 27, 2013 through December 31, 2013, the TIR entities, on a combined basis, had a net increase in cash of $12.3 million resulting from cash used in operating and investing activities of $2.5 million and $0.3 million, respectively, offset by cash provided by financing activities of $15.1 million.
 
Cypress LLC Year Ended December 31, 2013 Compared to
the Predecessor Year Ended December 31, 2012
 
Operating Activities. Net cash provided by operating activities was $10.4 million for the year ended December 31, 2013, compared to $7.2 million for the same period in 2012. This increase in cash provided by operating activities was primarily a result of five additional SWD wells in 2013 compared to 2012.
 
Investing Activities. Net cash used in investing activities was $3.1 million for the year ended December 31, 2013, compared to $15.2 million for the same period in 2012. This decrease in cash used in investing activities was primarily a result of the absence of SWD facility construction and acquisition in 2013.
 
Financing Activities. Net cash used in financing activities was $3.5 million for the year ended December 31, 2013, compared to net cash provided by financing activities of $8.4 million for the same period in 2012, primarily as a result of equity financings incurred by the Predecessor in 2012 to fund the construction of SWD facilities that were not incurred in 2013. This decrease in cash provided by financing activities was primarily a result of the absence of SWD facility construction and acquisition activity in 2013.

Predecessor Year Ended December 31, 2012 Compared to
 the Predecessor Year Ended December 31, 2011

Operating Activities. Net cash provided by operating activities was $7.2 million for the year ended December 31, 2012, compared to $1.1 million for the year ended December 31, 2011. This increase in cash provided by operating activities was primarily a result of having two operating SWD facilities on December 31, 2011 with operating results for seven months, compared to six SWD facilities on December 31, 2012.
 
Investing Activities. Net cash used in investing activities was $15.2 million for the year ended December 31, 2012, compared to $10.9 million for the year ended December 31, 2011. This increase in cash used in investing activities was primarily a result of completing construction on four SWD facilities in 2012 compared to the completion of only two SWD facilities in 2011.
 
Financing Activities. Net cash provided by financing activities was $8.4 million for the year ended December 31, 2012, compared to $9.9 million for the year ended December 31, 2011. This decrease in cash provided by financing activities was primarily a result of having more cash flow from operating activities in 2012 to fund investing activities compared to 2011.
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Working Capital
 
Our working capital was $6.6 million at December 31, 2013, compared to $1.9 million at December 31, 2012 and a deficit of $1.0 million at December 31, 2011.
 
The $4.7 million increase in working capital of our Water and Environmental Services segment from December 31, 2012 to December 31, 2013 was primarily a result of the following factors:
 
· our operations at December 31, 2013 were more extensive than at December 31, 2012;
 
· accounts receivable at December 31, 2013 were $3.5 million, or $0.5 million more than the $3.0 million accounts receivable balance at December 31, 2012 based upon increased revenues; and
 
· cash at December 31, 2013 was $4.3 million, or $3.7 million more than the $0.6 million cash balance at December 31, 2012 based upon increased cash from operations.
 
The $2.9 million increase in working capital from December 31, 2011 to December 31, 2012 was primarily a result of the following factors:
 
· the construction of SWD facilities in 2011 led to higher accounts payable at December 31, 2011 of $2.4 million compared to $0.4 million at December 31, 2012; and
 
· cash at December 31, 2011 was $0.1 million compared to $0.6 million at December 31, 2012 due to more SWD wells generating cash flow from operations.
 
The historical working capital analysis above does not address the historic working capital requirements of the TIR entities. In the future, our working capital requirements will be driven in part by a combination of changes in accounts receivable and accounts payable and compensation owed to our inspectors in the U.S. and payments to our inspectors in Canada. The TIR entities have substantial working capital needs throughout the year as they pay their inspectors in the U.S. on a weekly basis and in Canada on a bi-weekly basis but typically receive payment from their customers 45 to 90 days after the services have been performed. We intend to make borrowings under our credit agreement to fund the working capital needs of the TIR entities, and these borrowings will reduce the amount of credit available for other uses, such as acquisitions and growth projects, and increases interest expense, thereby reducing cash flow.  Please read “Risk Factors — Risks Related to Our Business — The working capital needs of the TIR entities are substantial, which could require us to seek additional financing that we may not be able to obtain on satisfactory terms, or at all.”
 
Capital Requirements
 
The Water and Environmental Services segment has capital needs requiring investment for the maintenance of existing SWD facilities and the acquisition or construction and development of new SWD facilities. Our partnership agreement will require that we categorize our capital expenditures as either maintenance capital expenditures or expansion capital expenditures.
 
  Maintenance capital expenditures are those cash expenditures that will enable us to maintain our operating capacity or operating income over the long-term. Maintenance capital expenditures include tankage, workovers, pipelines, pumps and other improvement of existing capital assets, including the construction or development of new capital assets to replace our existing saltwater disposal systems as they become obsolete. Other examples of maintenance capital expenditures are expenditures to repair, refurbish and replace tubing and packers on the SWD well itself to maintain equipment reliability, integrity and safety, as well as to address environmental laws and regulations.
 
  Expansion capital expenditures are those capital expenditures that we expect will increase our operating capacity or operating income over the long-term. Expansion capital expenditures include the acquisition of assets or businesses from Cypress Holdings or third-parties and the construction or development of additional saltwater disposal capacity, to the extent such expenditures are expected to expand our long-term operating capacity or operating income. Expansion capital expenditures include interest payments (and related fees) on debt incurred to finance all or a portion of expansion capital expenditures in respect of the period from the date that we enter into a binding obligation to commence the construction, development, replacement, improvement, automation or expansion of a capital asset and ending on the earlier to occur of the date that such capital improvement commences commercial service and the date that such capital improvement is abandoned or disposed of.
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Our historical accounting records did not differentiate between maintenance and expansion capital expenditures.
 
Our future expansion capital expenditures may vary significantly from period to period based on the investment opportunities available to us. We expect to fund future capital expenditures from cash flow generated from our operations, borrowings under our credit agreement, the issuance of additional partnership units or debt offerings.
 
The current Pipeline Inspection and Integrity Services segment of the business requires only limited capital expenditures, primarily purchases of office equipment.
 
Our Credit Agreement
 
On December 24, 2013, we along with our affiliates Cypress LLC, CEP TIR, and TIR (collectively, the “Borrowers”), entered into a $120 million secured credit agreement with Deutsche Bank and BMO acting as arrangers. The credit agreement matures on December 24, 2016 and consists of a $65.0 million senior secured working capital revolving credit facility and a $55.0 million senior secured acquisition revolving credit facility. Under this credit agreement, which we refer to as our “credit agreement,” Cypress LLC, TIR, and CEP TIR are co-borrowers and co-guarantors with us. CEP TIR’s assets consist only of its 36.2% interests in the TIR entities, and CEP TIR agreed in its operating agreement not to borrow under the credit agreement and not to engage in any business other than owning minority interests in the TIR entities. The credit agreement has an accordion feature that allows us to increase the available revolving borrowings under the facilities by up to an additional $100.0 million, subject to our receiving increased commitments from existing lenders or new commitments from new lenders and the satisfaction of certain other conditions.  At December 31, 2013 we had $30.0 million available under the $55.0 million senior secured acquisition revolving credit facility and $15.0 million available under our $65.0 million senior secured borrowing base revolving credit facility. The obligations under our credit agreement are secured by a first priority lien on substantially all assets of the Borrowers.
 
We used borrowings under our credit agreement to repay and retire the outstanding indebtedness under TIR’s revolving credit facility and mezzanine facilities as well as to fund income tax payments associated with the TIR’s conversion from a taxable corporation to a limited liability company.   We intend to use the remaining borrowing capacity to fund working capital, capital expenditures, acquisitions and for general partnership purposes.
 
All borrowings under the credit agreement bear interest, at our option, at (i) a base rate plus a margin of 1.25% to 2.75% per annum or (“Base Rate Borrowing”) (ii) an adjusted LIBOR rate plus a margin of 2.25% to 3.75% per annum (“LIBOR Borrowings”). The applicable margin is determined based on the combined leverage ratio of the Borrowers, as defined in the credit agreement. At December 31, 2013, the interest rate in effect on outstanding LIBOR Borrowings was 3.14%, calculated as the LIBOR rate of 0.225% plus a margin of 2.92%. There were no Base Rate Borrowings outstanding at December 31, 2013.  Interest on Base Rate Borrowings is payable monthly.  Interest on LIBOR Borrowings is paid upon maturity of the underlying LIBOR contract, but no less often than quarterly.  Commitment fees are charged at a rate of 0.50% on any unused credit and payable monthly. Our credit agreement contains various customary affirmative and negative covenants and restrictive provisions. Our credit agreement also requires maintenance of certain financial covenants, including a combined total adjusted leverage ratio (as defined in our credit agreement) of not more than 4.0 to 1.0 and an interest coverage ratio (as defined in our credit agreement) of not less than 3.0 to 1.0.  At December 31, 2013, our total adjusted leverage ratio was 0.80 to 1.0 and our interest coverage ratio was 4.88 to 1.0.
 
In addition, our credit agreement restricts our ability to make distributions on, or redeem or repurchase, our equity interests, provided, however, that we may make distributions of available cash so long as, both at the time of the distribution and after giving effect to the distribution, no default exists under our credit agreement, the borrowers and the guarantors are in compliance with the financial covenants, the borrowing base (which includes 100% of cash on hand) exceeds the amount of outstanding credit extensions under the working capital revolving credit facility by at least $5.0 million and at least $5.0 million in lender commitments are available to be drawn under the borrowing base revolving credit facility. Our calculated borrowing base was $72.1 million at December 31, 2013 which exceeds our maximum availability under the working capital revolving credit facility. The borrowing base calculation at December 31, 2013 includes $15.0 million of cash that is reserved for the payment of income taxes associated with the conversion of TIR from a taxable entity to a pass through entity for federal income tax purposes which was paid in March 2014. Availability under the acquisition revolving credit facility is not subject to a borrowing base calculation.
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In addition, our credit agreement contains events of default customary for facilities of this nature. Upon the occurrence and during the continuation of an event of default, subject to the terms and conditions of our credit agreement, the lenders may declare any outstanding principal of our credit agreement debt, together with accrued and unpaid interest, to be immediately due and payable and may exercise the other remedies set forth or referred to in our credit agreement.
 
Off-Balance Sheet Arrangements
 
Currently, we do not have any off-balance sheet arrangements.
 
Contractual Obligations
 
A summary of Cypress LLC’s and the TIR entities contractual obligations and other commitments, as of December 31, 2013, is shown in the table below. This table includes our contractual obligations under the credit agreement we entered into on December 24, 2013.
 
 
 
Total
   
Less Than
1 Year
   
1 – 3 Years
   
3 – 5 Years
   
More Than
5 Years
 
 
 
(in thousands)
 
Long-term debt
 
$
75,000
   
$
   
$
75,000
   
$
   
$
 
Lease obligations
   
2,511
     
614
     
883
     
452
     
562
 
Total
 
$
77,511
   
$
614
   
$
75,883
   
$
452
   
$
562
 

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 each of 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 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).
 
Business Combinations and Intangible Assets Including Goodwill
 
We account for acquisitions using the purchase 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 the acquired company’s balance sheet, 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.
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Our recorded identifiable intangible assets primarily include the estimated value assigned to non-compete agreements and customer relationships of our Water and Environmental Services segment, and customers lists and an assembled workforce database for our Pipeline and Inspection and Integrity Services segment. 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.
 
At December 31, 2013, Cypress LLC and the TIR entities had $34.8 million and $40.6 of goodwill, respectively, recorded in conjunction with past business combinations. 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 at December 31, 2013, Cypress LLC, TIR, TIR NDE, and the combined Canadian entities, TIR Canada and TIR Foley, are the appropriate reporting units for testing goodwill impairment.
 
The Company computes the fair value of the reporting units 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.” The values ascertained using these methods were weighted to obtain a total fair value. The computations require management to make significant estimates and market participant based assumptions. Critical estimates and market participant based assumptions that are used as part of these evaluations include, among other things, selection of comparable publicly traded companies, the discount rate applied to future earnings reflecting a weighted average cost of capital rate, earnings growth assumptions, and a control premium on the market approach values. Our estimate of water volumes disposed and revenue per barrel of water disposed are critical assumptions used in our discounted cash flow analysis for Cypress LLC. A significant decline in water volumes disposed and / or revenue per barrel disposed across our facilities could result in an impairment of goodwill. Gross margin is a critical assumption used in our discounted cash flow analysis for the TIR entities. Our inability to achieve projected gross margins could result in an impairment of goodwill. Specifically, a decline in projected gross margin of 1% or more for the combined Canadian TIR entities would have resulted in an impairment of goodwill.
 
A discounted cash flow analysis requires us to make various judgmental assumptions about sales, operating margins, capital expenditures, working capital and growth rates. Assumptions about sales, operating margins, capital expenditures and growth rates 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 assumptions used in the period ended December 31, 2013 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.
 
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 oilfield 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 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.
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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 quarterly and annual periods the assets are used. We depreciate our property and equipment using the straight-line method, which results in it 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 nine 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.
 
Impairments of Long-Lived Assets
 
We evaluate our long-lived assets for impairment when we believe events or changes in circumstances indicate that we may not be able to recover the carrying value. 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. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal. The assessment performed indicated a carrying value in excess of those undiscounted cash flows and the well’s calculated fair value.
 
During the year ended December 31, 2013, Cypress LLC identified impairment indicators at two of its facilities and reviewed the associated long-lived assets for impairment.  Cypress LLC recognized impairment charges during the period 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. A decrease in projected revenues of 10% would result in an additional impairment of $133 thousand.
 
Income Taxes
 
As a limited partnership, we are generally not subject to state and federal income tax and would therefore not recognize deferred income tax liabilities and assets for the expected future income tax consequences of temporary differences between financial statement carrying amounts and the related income tax basis. However, the Canadian subsidiaries included in the combined financial statements of the TIR entities are subject to Canadian taxes.  As such these entities apply the liability method of accounting for income taxes.  Under this method, income taxes are provided for all items included in its statement of operations, regardless of the period when such items will be reported for tax purposes.  Deferred taxes are provided for temporary differences, principally relating to depreciation, amortization and provisions for losses.  Management provides a valuation allowance against deferred asset amounts which are not considered more-likely-than-not to be realized.  There was no valuation allowance at December 31, 2013.
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We are also subject to Texas margin tax for certain of our operations, and may recognize deferred income tax liabilities and assets for Texas margin taxes in the future. We are subject to a statutory requirement that our non-qualifying income cannot exceed 10.0% of our total gross income, determined on a calendar year basis under the applicable income tax provisions. If the amount of our non-qualifying income exceeds this statutory limit, we would be taxed as a corporation.
 
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below.
 
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil, natural gas and NGL prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.
 
Commodity Price Risk
 
We are exposed to the impact of market fluctuations in the prices of crude oil in our Water and Environmental Services segment. Both our profitability and our cash flow are affected by volatility in the prices of these commodities. Crude oil prices are impacted by changes in the supply and demand for crude oil, as well as market uncertainty. For a discussion of the volatility of crude oil prices, please read “Risk Factors.” Adverse effects on our cash flow from reductions in crude oil prices could adversely affect our ability to make distributions to unitholders. We do not currently hedge our exposure to crude oil prices.
 
A hypothetical change in commodity prices of 1.0% would result in an increase or decrease of our gross operating margin of approximately $56 thousand.
 
Interest Rate Risk
 
We currently have exposure to changes in interest rates on our indebtedness associated with our credit agreement. We may implement swap or cap structures to mitigate our exposure to interest rate risk; however, we do not currently have any swaps or cap structures in place. As of December 31, 2013, our exposure consists of floating interest rate fluctuations on our outstanding indebtedness under our credit agreement of $75.0 million since there was no interest rate swap effective as of that date. A hypothetical change in interest rates of 1.0% would result in an increase or decrease of our annual interest expense of approximately $0.8 million.
 
The credit markets have recently experienced historical lows in interest rates. As the overall economy strengthens, it is possible that monetary policy will continue to tighten further, resulting in higher interest rates to counter possible inflation. Interest rates on floating rate credit facilities and future debt offerings could be higher than current levels, causing our financing costs to increase accordingly.
 
Counterparty and Customer Credit Risk
 
Our credit exposure generally relates to receivables for services provided. If any significant customer of ours should have credit or financial problems resulting in a delay or failure to repay the amounts they owe to us, this could have a material adverse effect on our business, financial condition, results of operations or cash flows.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
The financial statements starting on page F-1 of this Annual Report; together with the reports of Ernst & Young LLP, our independent registered public accounting firm and Grant Thornton LLP, are incorporated by reference into this Item 8.
 
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
 
None.
 
ITEM 9A. CONTROLS AND PROCEDURES
 
Evaluation of Disclosure Controls and Procedures.
 
As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including the principal executive officer and principal financial officer of our general partner, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of the end of the period covered by this Annual Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including the principal executive officer and principal financial officer of our general partner, as appropriate, to allow timely decisions regarding required disclosure and is recorded,   processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, the principal executive officer and principal financial officer of our general partner have concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of December 31, 2013.  Additionally, we are implementing a quarterly sub-certification process whereby all members of upper management and certain other management will review our filings and confirm their responsibility for, among other things, the effectiveness of key controls in their functional areas and that they are unaware of inaccuracies or omissions in our financial statements.
 
Management’s Report on Internal Control over Financial Reporting
 
This Annual Report does not include management's assessment regarding internal control over financial reporting due to a transition period established by rules of the SEC for new public companies.
 
Attestation Report of the Registered Public Accounting Firm
 
This Report does not include an attestation report of our independent registered public accounting firm due to a transition period established by the rules of the SEC for newly public companies. Pursuant to the recently enacted JOBS Act, our independent registered public accounting firm will not be required to attest to the effectiveness of our internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act of 2002 for up to five years or through such earlier date that we are no longer an “emerging growth company” as defined in the JOBS Act.
 
Changes in Internal Control over Financial Reporting
 
None
 
ITEM 9B. OTHER INFORMATION
 
None.
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PART III
 
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
 
MANAGEMENT
 
Management of Cypress Energy Partners, L.P.
 
We are managed by the executive officers of CEM, which is owned by our general partner and certain of its affiliates. Our general partner is not elected by our unitholders and will not be subject to re-election by our unitholders in the future. Cypress Holdings indirectly owns all of the membership interests in our general partner. Our general partner has a board of directors, and our unitholders are not entitled to elect the directors or directly or indirectly to participate in our management or operations. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, we intend to incur indebtedness that is nonrecourse to our general partner.
 
Our general partner has six directors. Cypress Holdings will appoint all members to the board of directors of our general partner. Pursuant to our general partner's operating agreement, Cypress Holdings appointed to our board of directors (i) Peter C. Boylan III, who has the right to serve as a director as long as CEP Capital Partners, LLC, an entity controlled by Mr. Boylan, is a member of Cypress Holdings and (ii) such other individuals selected by Mr. Boylan that, together with Mr. Boylan, constitute a percentage of the board of directors equal to the percentage of Cypress Holdings that CEP Capital Partners, LLC owns. In his exercise of this right, Mr. Boylan has appointed himself and may appoint others to the board. We have three independent directors who qualify for service on the audit committee. Our board of directors has determined that Henry Cornell, John T. McNabb II, and Stan Lybarger are independent under the independence standards of the NYSE and eligible for service on the audit committee. Despite the fact that Mr. Cornell beneficially owns 2.0% of Cypress Holdings, which together with its controlled affiliates owns approximately 58.8% of our outstanding limited partner interests, the board of directors determined he is independent in that he does not have a current relationship with us that would interfere with the exercise of his independent judgment in carrying out his responsibilities as a director.
 
Our general partner has the sole responsibility 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, but we sometimes refer to these individuals in this report as our employees. Employees of the TIR entities were transferred to an affiliate of our general partner subsequent to the closing of our IPO.
 
Director Independence
 
Although most companies listed on the NYSE are required to have a majority of independent directors serving on the board of directors of the listed company, the NYSE does not require a publicly traded limited partnership like us to have a majority of independent directors on the board of directors of our general partner or to establish a compensation or a nominating and corporate governance committee. We are, however, required to have an audit committee of at least three members within one year of the date our common units are first listed on the NYSE, and all of our audit committee members are required to meet the independence and financial literacy tests established by the NYSE and the Exchange Act.
 
Committees of the Board of Directors
 
The board of directors of our general partner has an audit committee and a conflicts committee, and may have such other committees as the board of directors shall determine from time to time. Each of the standing committees of the board of directors will have the composition and responsibilities described below.
 
Audit Committee
 
Our general partner has an audit committee comprised of three directors who each meet the independence and experience standards established by the NYSE and the Exchange Act. Henry Cornell, John T. McNabb II, and Stan Lybarger serve as members of our audit committee. Stan Lybarger began serving as Chairman of the audit committee upon his appointment on March 5, 2014.  Mr. McNabb served as Chairman prior to that date. Our board of directors has determined that Mr. Lybarger, and Mr. McNabb each have such accounting or related financial management expertise sufficient to qualify as an audit committee financial expert in accordance with Item 407(d) of Regulation S-K. Our audit committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. Our audit committee will have the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. Our audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to our audit committee.
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Conflicts Committee
 
At least two members of the board of directors of our general partner will serve on our conflicts committee to review specific matters that may involve conflicts of interest in accordance with the terms of our partnership agreement.  John T. McNabb II and Stan Lybarger serve as the members of the conflicts committee. Mr. McNabb serves as the Chairman of the conflicts committee. The board of directors of our general partner will determine whether to refer a matter to the conflicts committee on a case-by-case basis. The members of our conflicts committee may not be officers or employees of our general partner or directors, officers, or employees of its affiliates, and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors. In addition, the members of our conflicts committee may not own any interest in our general partner or any interest in us or our subsidiaries other than common units or awards under our incentive compensation plan. If our general partner seeks approval from the conflicts committee, then it will be presumed that, in making its decision, the conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Please read “Conflicts of Interest and Duties.”
 
Directors and Executive Officers of Cypress Energy Partners GP, LLC
 
Directors are elected by Cypress Holdings and hold office until their successors have been elected or qualified or until their earlier death, resignation, removal or disqualification. Executive officers are appointed by, and serve at the discretion of, the board of directors. The following table shows information for the directors and executive officers of our general partner.
 
Name
 
Age
 
Position with Cypress Energy Partners GP, LLC
Peter C. Boylan III
 
50
 
Chairman of the Board, President and Chief Executive Officer
G. Les Austin
 
48
 
Vice President and Chief Financial Officer
Richard M. Carson
 
47
 
Vice President and General Counsel
Jeff English
 
39
 
Vice President of Operations
Don LaBass
 
46
 
Vice President, Controller and Chief Accounting Officer
Jim Dowdy
 
47
 
Vice President of Corporate Development
Henry Cornell
 
57
 
Director
Phil Gisi
 
53
 
Director
Stan Lybarger
 
64
 
Director & Audit Committee Chairman
John T. McNabb II
 
69
 
Director & Conflicts Committee Chairman
Charles C. Stephenson, Jr.
 
77
 
Director

Peter C. Boylan III is co-founder, President and Chief Executive Officer of Cypress Holdings and Chairman of the Board, President and Chief Executive Officer of Cypress Energy Partners GP, LLC, having served in that capacity since September 2013. Since March 2002, Mr. Boylan has been the Chief Executive Officer of Boylan Partners, LLC, a provider of investment and advisory services. From 1995 to 2004, Mr. Boylan served in a variety of senior executive management positions of various public and private companies controlled by Liberty Media Corporation, including serving as a board member, Chairman, President, Chief Executive Officer, Chief Operating Officer and Chief Financial Officer of several different companies. Mr. Boylan currently serves on the board of directors of publicly traded BOK Financial Corporation, a $27.5 billion regional financial services and bank holding company, and MRC Global Inc., a global industrial supplier of upstream, midstream and downstream sectors of the energy industry. Mr. Boylan has also served on a number of other public and private company boards of directors over the last 20 years. In 2004, after a federal judge dismissed an SEC civil suit filed against Mr. Boylan in the United States District Court for the Central District of California (Western Division), he entered into court ordered mediation with the SEC leading to a civil settlement and a Final Judgment against Mr. Boylan, enjoining him from violating the anti-fraud, books and records and other provisions of the federal securities laws and ordering the payment of $600,000 in disgorgement and civil penalties. Mr. Boylan consented to the entry of the order without admitting or denying any wrongdoing. The Final Judgment and settlement had no officer and director bar. The judgment against Mr. Boylan arose out of a complaint filed against Mr. Boylan and other executive officers by the SEC, alleging that Mr. Boylan and other executive officers violated various provisions of the U.S. securities laws during his tenure as co-president, co-chief operating officer and director of Gemstar-TV Guide International, Inc., or Gemstar, from July 2000 to April 2002. Gemstar indemnified Mr. Boylan for legal fees and expenses.
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Mr. Boylan has extensive corporate senior executive management and leadership experience, and specific expertise with accounting, finance, audit, risk and compensation committee service, intellectual property, corporate development, health care, media, cable and satellite TV, software development, technology, energy and civic and community service. We believe this experience suits Mr. Boylan to serve as Chairman of the Board and Chief Executive Officer.
 
G. Les Austin is Vice President and Chief Financial Officer of Cypress Energy Partners GP, LLC, having served in that capacity since September 2013. Mr. Austin has served as Vice President and Chief Financial Officer of Cypress LLC since October 1, 2012. Mr. Austin served as Senior Vice President, Chief Financial Officer, secretary and treasurer of RAM Energy Resources, Inc. from April 2008 until its sale in February 2012. Mr. Austin served as Vice President Finance and Chief Financial Officer of Matrix Service Company from June 2004 to March 2008. Mr. Austin also served Matrix as Vice President, Accounting and Administration, Vice President of Financial Reporting and Technology, and as Vice President of Financial Planning and Reporting. Mr. Austin served as Vice President of Finance for Flint Energy Construction Company from February 1994 to March 1999. Prior to February 1994, Mr. Austin was an audit manager with Ernst & Young LLP. Mr. Austin received a B.S. in Accounting and Information Technology from Oklahoma State University. He is a Certified Public Accountant and a member of the American Institute of Certified Public Accountants. In addition, Mr. Austin serves as a director on the Advisory Board of Oklahoma State University School of Accounting.
 
Richard M. Carson is Vice President and General Counsel, having served in that capacity since September 2013. Mr. Carson previously served as a director, officer and shareholder of Gable & Gotwals, an Oklahoma law firm, where he practiced securities, corporate finance, transactional and environmental law, primarily for clients in the energy industry, including several master limited partnerships. Prior to joining Gable & Gotwals, from 1999 to 2008, Mr. Carson served in the legal department of The Williams Companies, Inc., where he counseled Williams in regard to securities, corporate finance and environmental matters, particularly relating to Williams’ master limited partnership subsidiaries, Williams Partners L.P., Williams Pipeline Partners L.P., and Williams Energy Partners L.P. (predecessor to Magellan Midstream Partners, L.P.). Mr. Carson began his career in 1991 working in legal, compliance and management roles, primarily in the environmental services industry, before joining Williams. Mr. Carson received a Juris Doctor in 1991 from the University of Oklahoma and a Bachelor of Science from the University of Tulsa’s Honors Program in 1988. Mr. Carson serves on the City of Tulsa’s Ethics Advisory Committee and on the board of directors of Land Legacy, a nonprofit land conservation organization, and he previously served as the Chair of the Oklahoma Bar Association’s Environmental Law Section and the Environmental Auditing Roundtable’s South-Central Region.
 
Jeff English is Vice President of Operations of Cypress Energy Partners GP, LLC, having served in that capacity since September 2013. Mr. English has served as Vice President Operations of Cypress LLC since February 25, 2013. From 2011 to 2013, Mr. English was Vice President of Operations for Bosque Systems, LLC, a water management company with annual revenues of approximately $45 million in 2012, where he managed operations (including health, safety and environmental, construction, compliance) in five regions and three business lines. From 2001 to 2011, Mr. English served as a senior director of operations for Vartec Telecom, a telecom company with annual revenues of $200 million. Prior to that, Mr. English was a senior consultant at Ernst & Young specializing in change management and business process improvement for complex customer relationship management system implementation. Mr. English is a graduate of Baylor University, with a M.A., Business Communication and Southwestern University.
 
Don LaBass is Vice President, Controller and Chief Accounting Officer of Cypress Energy Partners GP, LLC, having served in that capacity since September 2013. Mr. LaBass has served as VP Controller and Chief Accounting Officer of Cypress LLC since July 2013. Mr. LaBass previously served as Senior Vice President and Chief Financial Officer for Cherokee Nation Businesses, or CNB, a diversified tribal holding company whose operations included gaming, manufacturing and professional services. Prior to joining CNB, from 1998 to 2005, Mr. LaBass served in senior financial positions with BOK Financial Corporation as well as Gemstar TV Guide International, Inc. and its Predecessors from 2005 until 2013. Mr. LaBass began his career in 1990 in public accounting with KPMG. Mr. LaBass received a B.B.A. in Accounting from the University of Oklahoma. He is a Certified Public Accountant and a member of the American Institute of Certified Public Accountants. In addition, Mr. LaBass serves on the board of directors of the Eastern Oklahoma Chapter of the American Red Cross.
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Jim Dowdy is Vice President of Corporate Development of Cypress Energy Partners GP, LLC, having served in that capacity since September 2013. Mr. Dowdy has served as VP Corporate Development of Cypress LLC since June 2013. From 1993 to 2013, Mr. Dowdy worked for Samson Resources Company, a private exploration and production company headquartered in Tulsa, Oklahoma. Mr. Dowdy has over 20 years of oil and natural gas acquisition and divestiture experience and has completed numerous oil and natural gas transactions with an aggregate value in excess of $2 billion. Mr. Dowdy received a B.B.A. with a major in finance from Northeastern State University.
 
Henry Cornell has served as a director on the board of Cypress Energy Partners GP, LLC since January 14, 2014. Mr. Cornell was formerly a vice-chairman of the merchant banking division of Goldman Sachs & Co., where he worked for nearly 30 years prior to his retirement in February 2013. Mr. Cornell served on the firm’s corporate, real estate and infrastructure investment committees. He also led Goldman Sachs & Co.’s investment activities in Asia from 1988 - 2000. Prior to joining Goldman Sachs & Co., Mr. Cornell worked at Davis Polk & Wardwell. He currently serves on the board of directors of MRC Global Inc., and is on the international advisory board of Sotheby’s. Mr. Cornell is also the chairman of the board of the Citizens Committee for New York City, a trustee of the Asia Society, a trustee of the Whitney Museum, and a member of the Council on Foreign Relations. Mr. Cornell received his B.A. from Grinnell College in 1976 and his J.D. from New York Law School in 1981.
 
Mr. Cornell’s experience as a vice-chairman of the merchant banking division of Goldman Sachs & Co. and his extensive management experience as a senior partner at Goldman Sachs & Co. qualifies him to serve on our board of directors. We believe Mr. Cornell’s significant prior and current service as a director of public and private companies will suit him to serve as a director.
 
Phil Gisi has served as a director on the board of Cypress Energy Partners GP, LLC since January 14, 2014. Mr. Gisi has served as a director of Cypress LLC since the acquisition of assets from SBG Energy Services, LLC on December 31, 2012. Mr. Gisi is primarily involved in the senior housing and assisted living business and is the owner, President and Chief Executive Officer of Edgewood Group LLC and Edgewood Vista Senior Living, Inc., Grand Forks, North Dakota. These companies develop, own and manage assisted living and memory care communities, employing over 1,800 people in seven states with a capacity of about 2,500 residents in 44 locations. Mr. Gisi was also co-founder, President and Chief Executive Officer of SBG Energy Services, LLC, which provides fluid transportation, water disposal and other services to the oil field industry in western North Dakota. Mr. Gisi currently serves as a board member of Altru Health System in Grand Forks, University of North Dakota, or UND, Alumni Association and UND Foundation, and is a Member of the Alumni Advisory Council of the College of Business and Public Administration at UND.
 
Mr. Gisi’s service as President and Chief Executive Officer of Edgewood, and his extensive experience leading management teams enables him to serve on our board of directors. We believe Mr. Gisi’s significant prior and current service in the water and environmental industry, including his prior service on Cypress LLC’s board, will suit him to serve as director.
 
Stan Lybarger has served as a director on the board of Cypress Energy Partners GP, LLC since March 5, 2014.  Mr. Lybarger retired as president and chief executive officer of BOK Financial, a top 25 US-based bank holding company, on January 1, 2014.  He continues to serve on the board of directors of that corporation. Mr. Lybarger had a 40-year career with BOK Financial.  Mr. Lybarger served as its first president and chief operating officer, in addition to continuing to hold that title for Bank of Oklahoma.  He became the chief executive officer for BOK Financial and Bank of Oklahoma in 1996.  Lybarger earned B.A. and M.B.A. degrees from the University of Kansas, and a Certification from the Stonier Graduate School of Banking at Rutgers University.
 
Mr. Lybarger has also been an industry and community leader for decades and has held leadership positions at a number of organizations, including serving on the Federal Advisory Council (a 12-member council which consults and advises the Federal Reserve Board of Governors in Washington, DC), the Executive Committee of the Financial Institutions Division of the American Bankers Association, Chairman of the Tulsa Stadium Trust, Chairman of the Tulsa Metro Chamber, Chairman of the Oklahoma State Chamber, Chairman of The Oklahoma Business Roundtable, Chairman of Tulsa Area United Way.
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Mr. Lybarger’s experience leading BOK Financial and his deep knowledge and relationships in the energy industry qualifies him to serve on our board of directors. We believe Mr. Lybarger’s prior and current service as a director of public and private companies will suit him to serve as a director.
 
John T. McNabb II has served as a director on the board of Cypress Energy Partners GP, LLC since January 14, 2014 and serves as Chairman of our conflicts committee. Mr. McNabb is Vice Chairman of Investment Banking at Duff & Phelps LP, a global independent provider of financial advisory and investment banking services, a position he assumed on June 30, 2011. Prior to joining Duff & Phelps, he was founder and Chairman of the board of directors of Growth Capital Partners, L.P., an investment and merchant banking firm that provided financial advisory services to middle market companies throughout the United States, for 19 years. Previously, he was a managing director of Bankers Trust New York Corporation and a board member of BT Southwest, Inc., the southwest U.S. merchant banking affiliate of Bankers Trust, from 1989 to 1992. Mr. McNabb started his career, after serving in the U.S. Air Force during the Vietnam conflict, with Mobil Oil in its exploration and production division. He has served on the boards of eight public companies, including Hiland Partners, LP, Warrior Energy Services Corporation, Hugoton Energy Corporation and Vintage Petroleum, Inc. and currently serves as non-executive Chairman of Willbros Group and serves on the board and was formerly lead director of Continental Resources, Inc. Mr. McNabb earned both his undergraduate and MBA degrees from Duke University.
 
Mr. McNabb’s service as a partner in two independent exploration and production companies, and his extensive experience leading management teams and serving as a financial advisor to energy industry companies enables him to chair our conflicts committee with respect to industry matters. We believe Mr. McNabb’s significant prior and current service on the boards of numerous public and private companies, including his prior service in chairing the audit committees of three public companies qualifies him as one of our audit committee financial experts, and his extensive knowledge of the petroleum industry, finance, corporate governance and oversight matters will qualify him to serve as a director.
 
Charles C. Stephenson, Jr. has served as a director on the board of Cypress Energy Partners GP, LLC since January 14, 2014. Since 2006, Mr. Stephenson has served as Chairman of the board of Premier Natural Resources, an independent oil and gas company of which he is also a co-founder. Mr. Stephenson is an owner of Regent Private Capital II LLC and was a co-founder and director of Growth Capital Partners, an investment and merchant banking firm. From 1983 to 2006, Mr. Stephenson worked for Vintage Petroleum, Inc., which he founded and for which he served as Chairman of the board, President and Chief Executive Officer at the time of its sale to Occidental Petroleum in 2006. Mr. Stephenson received a B.S. in petroleum engineering from the University of Oklahoma. Mr. Stephenson is a member of the Society of Petroleum Engineers and has served on the board of the National Petroleum Council.
 
Mr. Stephenson’s experience founding two successful energy companies, and his decades of experience leading management teams and serving as chief executive officer, enables him to serve on our board of directors. We believe Mr. Stephenson’s significant prior and current experience as a senior executive in the energy industry will suit him to serve as director.
 
Board Leadership Structure
 
The chief executive officer of our general partner currently serves as the chairman of the board. The board of directors of our general partner has no policy with respect to the separation of the offices of chairman of the board of directors and chief executive officer. Instead, that relationship is defined and governed by the amended and restated limited liability company agreement of our general partner, which permits the same person to hold both offices. Directors of the board of directors of our general partner are designated or elected by a wholly owned subsidiary of Cypress Holdings. Accordingly, unlike holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business or governance, subject in all cases to any specific unitholder rights contained in our partnership agreement.
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Board Role in Risk Oversight
 
Our corporate governance guidelines will provide that the board of directors of our general partner is responsible for reviewing the process for assessing the major risks facing us and the options for their mitigation. This responsibility will be largely satisfied by our audit committee, which is responsible for reviewing and discussing with management and our registered public accounting firm our major risk exposures and the policies management has implemented to monitor such exposures, including our financial risk exposures and risk management policies
 
Section 16(a) Beneficial Ownership Reporting Compliance
 
Section 16(a) of the Exchange Act requires our general partner’s board of directors and officers, and persons who beneficially own more than 10% of a class of our equity securities registered pursuant to Section 12 of the Exchange Act to file certain reports with the SEC and NYSE concerning beneficial ownership of such securities. However, since we did not complete our IPO until January 21, 2014, Section 16(a) of the Exchange Act did not apply during the year ended December 31, 2013 to our directors, officers and beneficial owners of 10 percent or more of our common units.
 
Corporate Governance
 
The board of directors of our general partner has adopted Corporate Governance Guidelines that outline important policies and practices regarding our governance and a Code of Business Conduct and Ethics that applies to the directors, officers and employees of our general partner and its affiliates and us.
 
We make available free of charge, within the “Corporate Governance” section of our website at ir.cypressenergy.com, the Corporate Governance Guidelines, the Code of Business Conduct and Ethics and our Audit Committee Charter. The information contained on, or connected to, our website is not incorporated by reference into this Annual Report on Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC.
 
ITEM 11.
EXECUTIVE COMPENSATION
 
We are an “emerging growth company” as defined under the JOBS Act. As such, we are permitted to meet the disclosure requirements of Item 402 of Regulation S-K by providing the reduced disclosures required of a smaller reporting company.
 
Compensation Overview
 
Executive Compensation
 
We do not directly employ any of the persons responsible for managing our business. Our general partner, under the direction of its board of directors, or the board, is responsible for managing our operations and CEM employs the employees that operate our business. The compensation payable to the officers of our general partner is paid by CEM and such payments are reimbursed by us. However, we sometimes refer to the employees and officers of our general partner as our employees and officers in this report.
 
This executive compensation disclosure provides an overview of the executive compensation program for our named executive officers identified below for 2013. For the year ended December 31, 2013, our named executive officers, or our NEOs, were:
 
· Peter C. Boylan III, our President and Chief Executive Officer;
 
· G. Les Austin, our Vice President and Chief Financial Officer; and
 
· Richard M. Carson, our Vice President and General Counsel.

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Summary Compensation Table For 2013
 
The following table sets forth certain information with respect to the compensation paid to our NEOs for the years ended December 31, 2013 and December 31, 2012.
 
Name and Principal Position
Year
 
Salary
 
Unit
Awards(1)
 
All Other Compensation(2)
 
Total
 
Peter C. Boylan III
   
2013
   
$
258,420
    $
   
$
28,676
   
$
287,096
 
President and Chief Executive Officer
2012
$
187,500
$
$
18,983
$
206,483
G. Les Austin
   
2013
   
$
175,000
   
    $
   
$
175,000
 
Vice President and Chief Financial Officer
2012
$
 43,750
$
200,000
$
$
243,750
Richard M. Carson
Vice President and General Counsel
   
2013
   
$
44,000
(3)  
$
100,046
    $
   
$
144,046
 

(1) Represents an award of Class C Units in Cypress LLC granted to Mr. Austin and Mr. Carson, in each case in connection with their commencement of employment or service with CEM. The amount shown reflects the grant date fair value of the award, as determined in accordance with FASB ASC Topic 718. For additional information, please see Note 10 to the Consolidated Financial Statements of Cypress LLC for the years ended December 31, 2012 and December 31, 2013, included in Item 8 in this Annual Report.
(2) Represents cash payments provided for healthcare premiums for Mr. Boylan in 2012 and 2013. These payments were made in lieu of our providing any health or welfare benefits during 2012 and 2013.
(3) Mr. Carson commenced service as our Vice President and General Counsel in September 2013 and became a full time employee of CEM on January 1, 2014. The amount shown represents payments made in respect of Mr. Carson’s part-time service with us during 2013 pursuant to an arrangement with Mr. Carson’s former law firm.
 
Narrative Disclosure to Summary Compensation Table and Additional Narrative Disclosure
 
Elements of the compensation program. For 2013, compensation for our NEOs was limited to base salary and an initial equity award granted to Mr. Carson. None of our NEOs were eligible for an annual bonus or received any other compensation items in 2012.
 
Base compensation for 2013. Base salaries for our NEOs were initially set at modest levels, primarily due to our limited operating history at the time such salaries were determined, and none of our executive officers have received any significant base salary increases since their commencement of employment with us and no base salary increases were made since January 1, 2013. However, following the IPO on February 1, 2014, our NEOs were granted salary increases and in the future, their salaries may continue to be increased from time to time to bring them more in line with competitive salaries in our industry. The following table sets forth the current annualized base salary rates for our NEOs:
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Name and Principal Position
 
Current
Base Salary
 
Peter C. Boylan III
President and Chief Executive Officer
 
$
361,066
 
G. Les Austin
Vice President and Chief Financial Officer
 
$
215,000
 
Richard M. Carson
Vice President and General Counsel
 
$
212,500
 

Discretionary long-term equity incentive awards. In December 2012, in connection with his commencement of employment, Mr. Austin, received a one-time award of Class C Units in Cypress LLC, which were intended to allow Mr. Austin to share in the future equity appreciation of Cypress LLC from and after the date of grant of such Class C Units. Mr. Carson received a similar award in connection with his commencement of service in September 2013. The awards vest in three equal annual installments on the third, fourth and fifth anniversary of the grantee’s commencement of service with us, respectively. In connection with our IPO, the Class C Units in Cypress LLC were converted into subordinated units in us on an equivalent value basis, based on the per unit price in our IPO and with the same vesting terms as applied to the Class C Units. Mr. Austin’s award converted into 30,143 subordinated units and Mr. Carson’s award converted into 14,308 subordinated units.
 
In connection with our IPO, we adopted a new long-term equity incentive plan, or the LTIP, under which we expect to make periodic grants of equity and equity-based awards in us to our NEOs and other key employees and other service providers. The LTIP is discussed in more detail under “— Compensation Overview — Our 2013 Long-Term Incentive Plan” below.
 
Outstanding Equity Awards at December 31, 2013
The following table provides information regarding the outstanding and unvested long-term equity incentive awards held by Mr. Austin and Mr. Carson as of December 31, 2013. None of our NEOs held any option awards that were outstanding as of December 31, 2013.
 
 
Unit Awards
Name
Number of Units
That Have not
Vested (#) (2)
 
Market Value of Units
That Have Not
Vested ($) (3)
 
Peter C. Boylan III (1)
   
   
$
 
G. Les Austin
   
30,143
    $
602,860
 
Richard M. Carson
   
14,308
    $
286,160
 

(1) Mr. Boylan held no unvested equity awards as of December 31, 2013. As our co-founder, he owns part of Cypress Holdings.
(2) The awards are scheduled to vest in three equal annual installments on each of October 1, 2015, 2016 and 2017 for Mr. Austin and December 31, 2016, 2017 and 2018 for Mr. Carson. The amount shown represents the number of subordinated units in us into which the awards outstanding at December 31, 2013 converted upon the closing of the initial public offering on January 21, 2014 based upon the initial public offering price of $20.00 per common unit.
(3) Amount shown reflects the per-unit value based upon the IPO price of $20.00 per common unit.
 
Severance and change in control arrangements. None of our NEOs has entered into any employment or severance agreements with our general partner or any of its affiliates, nor do we expect our general partner or one of its affiliates to enter into any customary employment agreements with our executives prior to or in connection with our IPO.
 
The terms of Mr. Austin’s and Mr. Carson’s long-term equity incentive awards provide that in the event of a change in control of Cypress LLC, their awards would become fully vested, effective as of immediately prior to such change in control.
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Following the consummation of our IPO, due to our becoming a public company and our continued growth as an operating company generally, we expect that our compensation policies and practices will evolve and that we may pay elements of compensation to our executives that are not reflected in our historical compensation programs as described above. In particular, we expect that the future compensation of our executive officers will include a significant component of incentive compensation based on our performance. We expect to employ a compensation philosophy that will emphasize pay-for-performance, focused primarily on the ability to increase sustainable quarterly distributions to our unitholders. We expect that pay-for-performance will be based on a combination of our performance and the individual executive officer’s impact on our performance. We believe this pay-for-performance approach will generally align the interests of our executive officers with the interests of our unitholders, and at the same time enable us to maintain a lower level of base overhead in the event our operating and financial performance do not meet our expectations.
 
We will design our executive compensation to attract and retain individuals with the background and skills necessary to successfully execute our business strategies, to motivate those individuals to reach short-term and long-term goals in a way that aligns their interests with the interests of our unitholders, and to reward success in reaching those goals. We expect to use three primary elements of compensation to implement our executive compensation policy: salary, cash bonus, and long-term equity incentive awards. The determination of an executive officer’s cash bonus will reflect his or her relative contribution to achieving or exceeding annual goals. The determination of long-term equity incentive awards will be based on an executive officer’s expected contribution to long-term performance objectives. Long-term equity incentive awards will generally require the continued employment of the recipient during the vesting period, which provides a forfeitable long-term incentive to encourage executive retention.
 
We also provide a basic benefits package available to all full-time employees, which currently includes medical, dental, disability and life insurance and will include a 401(k) plan. We do not expect to maintain a defined benefit pension plan for our executive officers, because we believe such plans primarily reward longevity rather than performance.
 
Director Compensation
 
For the year ended December 31, 2013, our NEOs or other employees who also served as members of the board of directors of our general partner did not receive additional compensation for their service as directors. Additionally, directors who were not officers, employees or paid consultants or advisors of us or our general partner did not receive compensation for their services as directors.
 
Officers, employees or paid consultants or advisors of us or our general partner or its affiliates who also serve as directors will not receive additional compensation for their service as directors. Our independent directors who are not officers, employees or paid consultants or advisors of us or our general partner or its affiliates will receive cash and equity-based compensation for their services as directors.
 
Our expected director compensation program consists of the following:
 
· an annual cash retainer of $25,000,
 
· an additional annual cash retainer of (i) $5,000 for service as the chair of our conflicts committee and (ii) $7,500 for service as the chair of our audit committee,
 
· an annual equity-based award granted under our LTIP, having a value as of the grant date of $25,000. Equity-based awards are initially expected to be subject to vesting in equal annual installments over a period of three years, based upon continued service as an independent director, and
 
Directors will also receive reimbursement for out-of-pocket expenses associated with attending such board or committee meetings and director and officer liability insurance coverage. Each director will be fully indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law.
 
In addition to the compensation described above, John T. McNabb II was awarded one phantom unit under the LTIP for each common unit he purchased in the directed unit program for a total of 7,500 phantom units. The phantom units will vest in three equal annual installments.   Mr. Lybarger will be entitled to the same award if he acquires any common units in the open market. On March 26, 2014, our three independent directors were each awarded 1,135 phantom units as part of their 2014 annual compensation.
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Our 2013 Long-Term Incentive Plan
 
Our general partner adopted the LTIP in connection with our IPO for officers, directors and employees of our general partner or its affiliates, and any consultants, affiliates of our general partner or other individuals who perform services for us. Our general partner may issue our executive officers and other service providers long-term equity based awards under the plan, which awards will be intended to compensate the recipients thereof based on the performance of our common units and their continued employment during the vesting period, as well as align their long-term interests with those of our unitholders. We will be responsible for the cost of awards granted under our LTIP and all determinations with respect to awards to be made under our LTIP will be made by the board of directors of our general partner or any committee thereof that may be established for such purpose or by any delegate of the board of directors or such committee, subject to applicable law, which we refer to as the plan administrator. We currently expect that the board of directors of our general partner or a committee thereof will be designated as the plan administrator. The following description reflects the terms of the LTIP.
 
General. The LTIP will provide for the grant, from time to time at the discretion of the board of directors or any delegate thereof, subject to applicable law, of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards. The purpose of awards under the LTIP is to provide additional incentive compensation to employees providing services to us, and to align the economic interests of such employees with the interests of our unitholders. The LTIP will limit the number of units that may be delivered pursuant to vested awards to 1,182,600 common units or 10% of our current units outstanding, subject to proportionate adjustment in the event of unit splits and similar events. Common units subject to awards that are cancelled, forfeited, withheld to satisfy exercise prices or tax withholding obligations or otherwise terminated without delivery of the common units will be available for delivery pursuant to other awards.
 
Substitute awards. The LTIP will provide that awards may be granted in assumption of, or in substitution for, existing awards in another entity in connection with a merger, consolidation or acquisition by us or one of our affiliates of another entity or the securities or assets of another entity (including in connection with the acquisition by us or one of our affiliates of additional securities of an entity that is an existing affiliate of us). To the extent permitted by applicable law and securities exchange rules, common units issued pursuant to awards that are granted in assumption or, in substitution for such other awards will not be counted against the number of common units available for issuance pursuant to the LTIP.
 
Restricted units and phantom units. A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the forfeiture restrictions lapse and the recipient holds a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or on a deferred basis upon specified future dates or events or, in the discretion of the administrator, cash equal to the fair market value of a common unit. The administrator of the LTIP may make grants of restricted and phantom units under the LTIP that contain such terms, consistent with the LTIP, as the administrator may determine are appropriate, including the period over which restricted or phantom units will vest. The administrator of the LTIP may, in its discretion, base vesting on the grantee’s completion of a period of service or upon the achievement of specified financial objectives or other criteria or upon a change of control (as defined in the LTIP) or as otherwise described in an award agreement.
 
Distributions made by us with respect to awards of restricted units may be subject to the same vesting requirements as the restricted units.
 
Distribution equivalent rights. The administrator of the LTIP, in its discretion, may also grant distribution equivalent rights, either as stand-alone awards or in tandem with other awards. Distribution equivalent rights are rights to receive an amount in cash, restricted units or phantom units equal to all or a portion of the cash distributions made on units during the period an award remains outstanding.
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