As filed with the Securities and Exchange Commission on November 19, 2013

Registration No. 333-192328

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

Amendment No. 1
to
Form S-1
REGISTRATION STATEMENT

UNDER
THE SECURITIES ACT OF 1933

Cypress Energy Partners, L.P.

(Exact name of Registrant as Specified in Its Charter)


Delaware	1389	61-1721523
(State or Other Jurisdiction of Incorporation or Organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)

5727 S. Lewis Avenue, Suite 500
Tulsa, Oklahoma 74105
(918) 748-3900

(Address, Including Zip Code, and Telephone Number, including Area Code, of Registrant’s Principal Executive Offices)

G. Les Austin
Vice President and Chief Financial Officer
Cypress Energy Partners, L.P.
5727 S. Lewis Avenue, Suite 500
Tulsa, Oklahoma 74105
(918) 748-3900

(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent for Service)

Copies to:


Ryan J. Maierson Latham & Watkins LLP 811 Main Street, Suite 3700 Houston, Texas 77002 (713) 546-5400		Joshua Davidson Hillary H. Holmes Baker Botts L.L.P. 910 Louisiana Street Houston, Texas 77002 (713) 229-1234

Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.

If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. o

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

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 o
Non-accelerated filer x (Do not check if a smaller reporting company)		Smaller reporting company o

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

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The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

Subject to completion, dated November 19, 2013

PRELIMINARY PROSPECTUS

Common Units

Representing Limited Partner Interests

[GRAPHIC MISSING]

Cypress Energy Partners, L.P.

This is our initial public offering. We are offering common units. We intend to apply to list our common units on the New York Stock Exchange under the symbol “CELP.”

Prior to this offering, there has been no public market for our common units. We currently estimate that the initial public offering price will be between $ and $ . We are an “emerging growth company” as that term is used in the Jumpstart Our Business Startups Act, or JOBS Act.

You should consider the risks we have described in “Risk Factors” beginning on page 19.

These risks include the following:

•

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.

•

On a pro forma basis, we would not have had sufficient cash available for distribution to pay the full minimum quarterly distribution on all of our units for the year ended December 31, 2012 or the twelve months ended September 30, 2013.

•

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 and increased regulation of drilling and production, could have a material adverse effect on our results of operations.

•

The working capital needs of TIR are substantial, which will reduce our borrowing capacity for other purposes and reduce our cash available for distribution.

•

Our business is dependent upon the willingness of our customers to outsource their waste management activities and pipeline inspection and integrity activities.

•

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

•

Unitholders have very limited voting rights and, even if they are dissatisfied, cannot remove our general partner without its consent.

•

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service, or 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.

•

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.


	Per Common Unit	Total
Initial public offering price	$	$
Underwriting discounts and commissions (1)	$	$
Proceeds to Cypress Energy Partners, L.P., before expenses	$	$

(1)

Excludes an aggregate structuring fee equal to 0.50% of the gross proceeds of this offering payable to Raymond James & Associates, Inc., Robert W. Baird & Co. Incorporated and Stifel, Nicolaus & Company, Incorporated. Please read “Underwriting.”

The underwriters may also purchase up to an additional common units from us at the public offering price, less the underwriting, to cover over-allotments, if any, within 30 days from the date of this prospectus.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The underwriters expect to deliver the common units on or about , 2013


RAYMOND JAMES		BAIRD		STIFEL

The date of this prospectus is , 2013

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PROSPECTUS SUMMARY			1
Overview			1
Business Strategies			2
Competitive Strengths			3
Our Assets and Operations			4
Our Relationship with Cypress Holdings			5
Risk Factors			5
The Restructuring Transactions			5
Organizational Structure After the Restructuring Transactions			6
Management of Cypress Energy Partners, L.P.			8
Principal Executive Offices and Internet Address			8
Summary of Conflicts of Interest and Duties			8
Our Emerging Growth Company Status			9
The Offering			10
Summary Historical and Pro Forma Financial Data and Operating Data			15
RISK FACTORS			19
Risks Related to Our Business			19
Risks Inherent in an Investment in Us			42
Tax Risks			51
USE OF PROCEEDS			57
CAPITALIZATION			58
DILUTION			59
CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS			61
General			61
Our Minimum Quarterly Distribution			63
Unaudited Pro Forma Distributable Cash Flow for the Year Ended December 31, 2012, and the Twelve Months Ended September 30, 2013			65
Cypress Energy Partners, L.P. Pro Forma Operating Data			66
Cypress Energy Partners, L.P. Unaudited Pro Forma Distributable Cash Flow			67
Estimated Distributable Cash Flow for the Year Ending December 31, 2014			69
Cypress Energy Partners, L.P. Estimated Distributable Cash Flow			71
Assumptions and Considerations			74
PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS			78
Distributions of Available Cash			78
Operating Surplus and Capital Surplus			79
Capital Expenditures			81
Subordinated Units and Subordination Period			82
Distributions of Available Cash From Operating Surplus During the Subordination Period			83
Distributions of Available Cash From Operating Surplus After the Subordination Period			84
General Partner Interest and Incentive Distribution Rights			84
Percentage Allocations of Available Cash from Operating Surplus			85
General Partner’s Right to Reset Incentive Distribution Levels			85
Distributions from Capital Surplus			88
Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels			88
Distributions of Cash Upon Liquidation			89

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SELECTED HISTORICAL AND PRO FORMA COMBINED FINANCIAL DATA			92
Non-GAAP Financial Measures			95
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			98
Overview			98
How We Generate Revenue			98
How We Evaluate Our Operations			98
Results Presented and Factors Affecting the Comparability of the Historical Financial Results of the CEP Successor with the SBG Predecessor and of our Future Results			101
CEP Successor Nine Months Ended September 30, 2013 Compared to SBG Predecessor Nine Months Ended September 30, 2012			103
SBG Predecessor’s Year Ended December 31, 2012 Compared to SBG Predecessor’s Period from June 1, 2011 (Inception) to December 31, 2011			104
Liquidity and Capital Resources			105
Off-Balance Sheet Arrangements			111
Qualitative and Quantitative Disclosures About Market Risk			111
Critical Accounting Policies and Estimates			111
INDUSTRY			115
Overview of Water and Environmental Services Industry			115
Overview of Pipeline Inspection and Integrity Services Industry			121
BUSINESS			128
Overview			128
Business Strategies			129
Competitive Strengths			130
Our Business Segments			132
Our History			137
Our Relationship with Cypress Holdings			138
Employees			138
Competition			138
Seasonality			139
Insurance			139
Environmental and Occupational Health and Safety Matters			140
Headquarters			145
Legal Proceedings			145
MANAGEMENT			146
Management of Cypress Energy Partners, L.P.			146
Directors and Executive Officers of Cypress Energy Partners GP, LLC			147
Board Leadership Structure			150
Board Role in Risk Oversight			150
Compensation of Our Officers and Directors			151
Director Compensation			153
Equity Compensation Plans			154
SECURITY OWNERSHIP AND CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			158
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS			160
Distributions and Payments to Our General Partner and Its Affiliates			160
Agreements Governing the Restructuring Transactions			161
Agreements with Affiliates			162
Procedures for Review, Approval and Ratification of Related Person Transactions			164

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CONFLICTS OF INTEREST AND DUTIES			165
Conflicts of Interest			165
Duties of the General Partner			171
DESCRIPTION OF THE COMMON UNITS			175
The Units			175
Transfer Agent and Registrar			175
Transfer of Common Units			175
OUR PARTNERSHIP AGREEMENT			177
Organization and Duration			177
Purpose			177
Capital Contributions			177
Voting Rights			177
Limited Liability			179
Issuance of Additional Securities			180
Amendment of Our Partnership Agreement			180
Merger, Consolidation, Conversion, Sale or Other Disposition of Assets			182
Termination and Dissolution			183
Liquidation and Distribution of Proceeds			183
Withdrawal or Removal of Our General Partner			184
Transfer of General Partner Interest			185
Transfer of Ownership Interests in Our General Partner			185
Transfer of Incentive Distribution Rights			185
Change of Management Provisions			185
Limited Call Right			186
Redemption of Ineligible Holders			186
Meetings; Voting			187
Status as Limited Partner			187
Indemnification			187
Reimbursement of Expenses			188
Books and Reports			188
Right to Inspect Our Books and Records			189
Registration Rights			189
Exclusive Forum			189
UNITS ELIGIBLE FOR FUTURE SALE			190
Rule 144			190
Our Partnership Agreement and Registration Rights			190
Lock-up Agreements			191
Registration Statement on Form S-8			191
MATERIAL FEDERAL INCOME TAX CONSEQUENCES			192
Partnership Status			193
Limited Partner Status			194
Tax Consequences of Unit Ownership			194
Tax Treatment of Operations			201
Disposition of Common Units			202
Uniformity of Units			204
Tax-Exempt Organizations and Other Investors			205
Administrative Matters			206
Recent Legislative Developments			209
State, Local and Other Tax Considerations			209

iii

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INVESTMENT IN CYPRESS ENERGY PARTNERS, L.P. BY EMPLOYEE BENEFIT PLANS			210
UNDERWRITING			212
Option to Purchase Additional Common Units			212
Discounts and Expenses			213
Indemnification			213
Lock-Up Agreements			213
Stabilization			213
Relationships			214
Discretionary Accounts			214
Directed Unit Program			214
Listing			215
Determination of Initial Offering Price			215
Electronic Prospectus			215
FINRA Conduct Rules			215
Notice to Prospective Investors in the EEA			215
Notice to Prospective Investors in the United Kingdom			216
Notice to Prospective Investors in Switzerland			217
Notice to Prospective Investors in Germany			217
Notice to Prospective Investors in the Netherlands			217
VALIDITY OF THE COMMON UNITS			218
EXPERTS			218
WHERE YOU CAN FIND ADDITIONAL INFORMATION			218
FORWARD-LOOKING STATEMENTS			219
INDEX TO FINANCIAL STATEMENTS			F-1
APPENDIX A: Form of First Amended and Restated Agreement of Limited Partnership of Cypress Energy Partners, L.P.			A-1
APPENDIX B: Glossary of Terms			B-1

You should rely only on the information contained in this prospectus or in any free writing prospectus we may authorize to be delivered to you. We have not, and the underwriters have not, authorized any other person to provide you with information different from that contained in this prospectus and any free writing prospectus. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should not assume that the information contained in this prospectus is accurate as of any date other than the date on the front cover of this prospectus.

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. Please read “Risk Factors” and “Forward-Looking Statements.”

Industry and Market Data

The data included in this prospectus regarding the industries in which we operate, including descriptions of trends in the market and our position and the position of our competitors within our industries, is based on a variety of sources, including independent publications, government publications, information obtained from customers, distributors, suppliers and trade and business organizations and publicly available information, as well as our good faith estimates, which have been derived from management’s knowledge and experience in the industry in which we operate. Although we have not independently verified the accuracy or completeness of the third-party information included in this prospectus, we believe that the third-party sources are reliable and that the third-party information included in this prospectus or in our estimates is accurate and complete.

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Commonly Used Defined Terms

Unless the context otherwise requires, references in this prospectus to “Cypress Energy Partners, L.P.,” “our partnership,” “we,” “our,” “us,” or like terms, when used in an historical context or in the present tense, refer to Cypress Energy Partners, LLC, our successor for accounting purposes, together with TIR (as defined below). When used in the future tense, “we,” “our” and “us” refer to Cypress Energy Partners, L.P. and its subsidiaries.

References to:

•

“our general partner” refer to Cypress Energy Partners GP, LLC;

•

“Cypress Holdings” refer to Cypress Energy Holdings, LLC, the indirect owner of our general partner and the indirect owner of % of our outstanding common units;

•

“CEM” refer 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;

•

“CEP Successor” or “Cypress LLC” refer to Cypress Energy Partners, LLC, our successor for financial accounting purposes, which will become our wholly owned subsidiary at the closing of this offering;

•

“CES” refer 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 are third-party SWD facilities;

•

“SBG Predecessor” refer to Cypress Energy Partners Predecessor, 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 U.S. operations of Tulsa Inspection Resources, Inc., which will become “Tulsa Inspection Resources, LLC,” our subsidiary at the closing of this offering that will be 50.1% owned by our partnership and 49.9% owned indirectly by Cypress Holdings; and

•

“TIR Parent” refer to Tulsa Inspection Resources, Inc., which historically owned TIR.

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PROSPECTUS SUMMARY

This summary highlights selected information contained elsewhere in this prospectus. You should carefully read the entire prospectus, including “Risk Factors” and the historical and unaudited pro forma condensed combined financial statements and related notes included elsewhere in this prospectus before making an investment decision. Unless otherwise indicated, the information in this prospectus assumes (1) an initial public offering price of $ per common unit (the mid-point of the price range set forth on the cover of this prospectus) and (2) that the underwriters do not exercise their option to purchase additional common units. You should read “Risk Factors” beginning on page 19 for more information about important factors that you should consider before purchasing our common units. We have provided definitions for some of the terms we use to describe our business and industry and other terms used in this prospectus in the “Glossary of Terms” beginning on page B-1 of this prospectus.

Cypress Energy Partners, L.P.

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. We also provide independent pipeline inspection and integrity services to producers and pipeline companies. In both of these business segments, we work closely with our customers to help them comply with increasingly complex and strict environmental and safety rules and regulations and reduce their operating costs.

•

In our Water and Environmental Services segment, which is comprised of the historical operations of the SBG Predecessor and the CEP Successor, 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 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. We generate revenue in our Water and Environmental Services segment primarily by treating produced water and flowback water and injecting them 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. 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 revenue from fees associated with managing SWD facilities.

On a pro forma basis after giving effect to this offering and the related restructuring transactions described below under “Summary — The Restructuring Transactions,” for the year ended December 31, 2012 and the nine months ended September 30, 2013, respectively, we generated $9.5 million and $11.4 million in gross margin in our Water and Environmental Services segment. For the nine months ended September 30, 2013, we disposed of an average of approximately 53,000 barrels of water per day, approximately 75% of which was produced water. For the month ended September 30, 2013, we operated our SWD wells at approximately 42% of aggregate estimated capacity.

•

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pipeline companies. TIR’s inspectors 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, maintenance and repair projects. Our results in the Pipeline Inspection and Integrity Services segment are driven primarily by the number and type of inspectors performing services for TIR’s customers and the fees TIR charges for those services, which depend on the nature and duration of the project.

On a pro forma basis after giving effect to this offering and the related restructuring transactions, for the year ended December 31, 2012 and the nine months ended September 30, 2013, respectively, TIR, in which we will own a 50.1% interest, generated $18.0 million and $21.5 million in gross margin in our Pipeline Inspection and Integrity Services segment. For the year ended December 31, 2012 and the nine months ended September 30, 2013, TIR employed an average of 788 and 1,252 inspectors, respectively.

Business Strategies

Our principal business objective is to increase the quarterly cash distributions that we pay to our unitholders over time while maintaining the ongoing stability of our business. 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 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 the U.S. was installed decades ago and is therefore more susceptible to failure and requires more frequent inspections. We believe that increasingly stringent 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.

•

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•

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.

•

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 ultrasonic nondestructive examination services, 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.

•

Competitive Strengths

We believe that we are well-positioned to successfully execute our business strategies because of the following competitive strengths:

•

High-quality and high-capacity SWD facilities located in active oil and natural gas producing regions. Our Water and Environmental Services segment’s operations are currently located in two of the most active oil and natural gas producing regions in the U.S., the Bakken Shale region of the Williston Basin in North Dakota and the Permian Basin in west Texas. Substantially all of the wells now being completed in these regions utilize hydraulic fracturing and generate a significant amount of both flowback and produced water needing disposal.

•

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•

Commitment and ability to provide services throughout the long life of our customers’ assets. The water and environmental services that we provide are integral to our customers’ operations through the life of the well. The ongoing management of produced water generated from producing wells can last several decades, and, in some cases, the amount of produced water increases as the well ages. In addition, to remain in regulatory compliance and operate safely, pipelines and gathering systems require inspections, repairs and maintenance over their lives, including more frequent inspections, repairs and maintenance as they age. We believe that this long-term demand will result in relatively stable and predictable cash flows and help solidify our role as an integrated part of our customers’ production or midstream operations.

•

Focus on regulatory compliance and safety in our operations. We perform internal audits of our existing SWD facilities using third-party safety consultants and have a comprehensive environmental performance and safety compliance approach. We strive to achieve environmental and regulatory compliance “best practices” across all of our facilities and services, and we believe that our strong safety and environmental record increases the demand for our services among producers who seek providers that meet their strict requirements. Many of our facilities have been chosen by our customers after they complete thorough reviews of our facility and operations, which we believe further solidifies our reputation for safety and regulatory excellence. Additionally, we believe customers select TIR based on its experience, reputation and comprehensive approach to safety, compliance and training.

•

Management team with significant experience and industry connections. Our senior management team has substantial experience working with public companies, and the senior operational team of TIR has an average of approximately 20 years of experience in the energy industry. Our management team has significant experience in identifying, evaluating and completing strategic acquisitions. In addition, our management team has developed strong business relationships with key industry participants throughout the U.S. We believe that their knowledge of the industry, relationships within the industry and experience in identifying, evaluating and completing acquisitions will provide us opportunities to execute our strategies successfully and to grow through strategic and accretive acquisitions that complement or expand our existing operations.

Our Assets and Operations

Water and Environmental Services segment. As of September 30, 2013, we had an aggregate of approximately 135,500 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
Green River, 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.

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Pipeline Inspection and Integrity Services segment. During the three months ended September 30, 2013, TIR employed an average of 1,529 inspectors, up approximately 70% and 145% from the three months ended September 30, 2012 and September 30, 2011, respectively. TIR’s 46 pipeline inspection and integrity customers include oil and natural gas producers, pipeline owners and operators and public utility companies, and TIR provides inspection and integrity services to these customers throughout the U.S.

TIR’s 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); and

•

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

Our Relationship with Cypress Holdings

All of the equity interests in our general partner will be owned by Cypress Holdings, which is owned by Charles C. Stephenson, Jr., various family trusts and a company controlled by our 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 owner of our general partner and the direct or indirect owner of approximately % of our outstanding common units, Cypress Holdings has a strong incentive to support and promote the successful execution of our business plan.

Risk Factors

An investment in our common units involves risks associated with our business, our partnership structure and the tax characteristics of our common units. You should carefully consider the risks described in “Risk Factors” and the other information in this prospectus before investing in our common units.

The Restructuring Transactions

We were formed in September 2013 by Cypress Holdings 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. We believe these services will provide stable and predictable cash flows.

At or prior to the closing of this offering, each of the following transactions will occur:

•

certain affiliates of TIR, including Cypress Energy Partners — TIR, LLC, will convey their aggregate 50.1% interest in TIR to us in exchange for common units and subordinated units;

•

Cypress Holdings will indirectly convey to us its interests in Cypress LLC, which will become our operating subsidiary, except that Cypress Holdings will retain the assets and liabilities associated with Cypress LLC’s SWD facility in Sheridan County, Montana, and a

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related-party receivable and permit associated with the construction of a potential new SWD facility, in exchange for common units, subordinated units and $ million in proceeds of this offering to reimburse it for certain capital expenditures incurred with respect to Cypress LLC;

•

Cypress Energy Partners GP, LLC will maintain its 0.0% non-economic general partner interest in us and will receive our incentive distribution rights;

•

we will issue common units to the public ( common units if the underwriters exercise their option to purchase additional common units in full) and will use the net proceeds of this offering to distribute $ million to a wholly owned subsidiary of Cypress Holdings as reimbursement of certain capital expenditures it incurred with respect to assets contributed to us and to pay transaction expenses related to our credit facilities; and

•

we will enter into an omnibus agreement with Cypress Holdings and certain of its affiliates, including our general partner. Please read “Certain Relationships and Related Party Transactions — Agreements with Affiliate.”

We refer to these transactions collectively as the “restructuring transactions.”

The number of common units to be issued to Cypress Holdings includes common units that will be issued at the expiration of the underwriters’ option to purchase additional common units, assuming that the underwriters do not exercise the option. Any exercise of the underwriters’ option to purchase additional common units would reduce the common units shown as issued to Cypress Holdings by the number to be purchased by the underwriters in connection with such exercise. If and to the extent the underwriters exercise their option to purchase additional common units, the number of common units purchased by the underwriters pursuant to any exercise will be sold to the public, and any remaining common units not purchased by the underwriters pursuant to any exercise of the option will be issued to a wholly owned subsidiary of Cypress Holdings at the expiration of the option period for no additional consideration. We will distribute to Cypress Holdings any net proceeds from the exercise of the underwriters’ option to purchase additional common units from us.

Organizational Structure After the Restructuring Transactions

After giving effect to the transactions described above, assuming the underwriters’ option to purchase additional common units from us is not exercised, our units will be held as follows:


Public common units	%
Units held by affiliates
Common units held by Cypress Holdings (1)	%
Common units held by Cypress Energy Partners — TIR, LLC	%
Common units held by Long-Term Incentive Plan Participants		%
Subordinated units held by Cypress Holdings (1)	%
Subordinated units held by Cypress Energy Partners — TIR, LLC	%
General partner interest	0.0	%
Total	100.0	%

(1)

Includes units held by a wholly owned subsidiary of Cypress Holdings ( % of common units and % of subordinated units), certain members of management ( % of common units and % of subordinated units) and owners of Cypress Holdings and TIR ( % of common units and % of subordinated units).

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The following simplified diagram depicts our organizational structure after giving effect to the restructuring transactions described above.

[GRAPHIC MISSING]

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Management of Cypress Energy Partners, L.P.

We are managed and operated by the board of directors and executive officers of Cypress Energy Partners GP, LLC, our general partner. Cypress Holdings is the sole owner of our general partner and has the right to appoint the entire board of directors of our general partner, including the independent directors appointed in accordance with the listing standards of the New York Stock Exchange, or the NYSE. Unlike shareholders in a publicly traded corporation, our unitholders will not be entitled to elect our general partner or the board of directors of our general partner. For more information about the directors and executive officers of our general partner, please read “Management — Directors and Executive Officers of Cypress Energy Partners GP, LLC.”

Under our omnibus agreement through , we will pay our general partner a fixed annual fee (paid in quarterly installments) of $3.0 million per year for providing us with certain corporate overhead services, including for certain executive management services by certain officers of our general partner and compensation expense for all employees required to manage and operate our business. This fee also includes the incremental general and administrative expenses we expect to incur as a result of being a publicly traded partnership and will be subject to increase in future periods. Please read “Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Omnibus Agreement.”

Principal Executive Offices and Internet Address

Our principal executive offices are located at 5727 S. Lewis Avenue, Suite 500, Tulsa, Oklahoma 74105, and our telephone number is (918) 748-3900. Following the completion of this offering, our website will be located at www. .com. We expect to make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission, or the SEC, available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

Summary of Conflicts of Interest and Duties

Under our partnership agreement, our general partner has a contractual duty to manage us in a manner it believes is in the best interests of our partnership and unitholders. However, because our general partner is a wholly owned subsidiary of Cypress Holdings, the officers and directors of our general partner have a duty to manage the business of our general partner in a manner that is in the best interests of Cypress Holdings. As a result of this relationship, conflicts of interest may arise in the future between us and our unitholders, on the one hand, and our general partner and its affiliates, including Cypress Holdings, on the other hand. For example, our general partner will be entitled to make determinations that affect the amount of cash distributions we make to the holders of common units, which in turn has an effect on whether our general partner receives incentive cash distributions. In addition, our general partner may determine to manage our business in a way that directly benefits Cypress Holdings’ businesses, rather than indirectly benefitting Cypress Holdings solely through its ownership interests in us. We expect that any future decision by Cypress Holdings in this regard will be made on a case-by-case basis. However, all of these actions are permitted under our partnership agreement and will not be a breach of any duty (fiduciary or otherwise) of our general partner. For a more detailed description of the conflicts of interest and fiduciary duties of our general partner, please read “Conflicts of Interest and Duties.”

Delaware law provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the duties (including fiduciary duties) otherwise owed by the general partner to limited partners and the partnership. As permitted by Delaware law, our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing the duties of the general partner and contractual methods of resolving conflicts of interest. The effect of these provisions is to restrict the remedies available to unitholders for actions that might otherwise

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constitute breaches of our general partner’s fiduciary duties. Our partnership agreement also provides that affiliates of our general partner, including Cypress Holdings and its affiliates, are permitted to compete with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement, and pursuant to the terms of our partnership agreement each holder of common units consents to various actions and potential conflicts of interest contemplated in our partnership agreement that might otherwise be considered a breach of fiduciary or other duties under Delaware law. Please read “Conflicts of Interest and Duties —
Duties of the General Partner” for a description of the duties imposed on our general partner. For a description of our other relationships with our affiliates, please read “Certain Relationships and Related Party Transactions.”

Our Emerging Growth Company Status

As a company with less than $1.0 billion in revenue during its last fiscal year, we qualify as an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012, or the JOBS Act. As an emerging growth company, we may, for up to five years, take advantage of specified exemptions from reporting and other regulatory requirements that are otherwise applicable generally to public companies. These exemptions include:

•

the presentation of only two years of audited financial statements and only two years of related Management’s Discussion and Analysis of Financial Condition and Results of Operations;

•

exemption from the auditor attestation requirement on the effectiveness of our system of internal control over financial reporting;

•

exemption from the adoption of new or revised financial accounting standards until they would apply to private companies;

•

exemption from compliance with any new requirements adopted by the Public Company Accounting Oversight Board requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer; and

•

reduced disclosure about executive compensation arrangements.

We are permitted to take advantage of these provisions until we are no longer an emerging growth company, which will occur on the earliest of (i) the last day of the fiscal year following the fifth anniversary of this offering, (ii) the last day of the fiscal year in which we have more than $1.0 billion in annual revenue, (iii) the date on which we have more than $700.0 million in market value of our common units held by non-affiliates or (iv) the date on which we issue more than $1.0 billion of non-convertible debt over a three-year period.

We have elected to take advantage of all of the applicable JOBS Act provisions, except that we will elect 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).

Accordingly, the information that we provide you may be different than what you may receive from other public companies in which you hold equity interests.

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The Offering

Common units offered to the public by us

common units, or common units if the underwriters exercise in full their option to purchase additional common units from us.

Units outstanding after this offering

common units and subordinated units, representing a % and limited partner interest in us, respectively. If and to the extent the underwriters exercise their option to purchase additional common units, the number of common units purchased by the underwriters pursuant to any exercise will be sold to the public. Any common units not purchased by the underwriters pursuant to their exercise of the option will be issued to a wholly owned subsidiary of Cypress Holdings at the expiration of the option period for no additional consideration. Accordingly, the exercise of the underwriters’ option will not affect the total number of common units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units. Our general partner will own a 0.0% non-economic general partner interest in us.

Use of proceeds

We expect to receive net proceeds of approximately $ million from the sale of common units offered by this prospectus based on the initial public offering price of $ per common unit (the mid-point of the price range set forth on the cover of this prospectus), after deducting underwriting discounts and structuring fees but before estimated offering expenses.

We intend to use the net proceeds of this offering to distribute $ million to a wholly owned subsidiary of Cypress Holdings as reimbursement for certain capital expenditures it incurred with respect to assets contributed to us and to pay transaction expenses related to our credit facilities.

If the underwriters exercise their option to purchase additional common units in full, the additional net proceeds to us would be approximately $ million. The net proceeds from any exercise by the underwriters of their option to purchase additional common units from us will be distributed to a wholly owned subsidiary of Cypress Holdings.

Cash distributions

We intend to make a minimum quarterly distribution of $ per unit ($ on an annualized basis) to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner. We refer to this cash as “available cash.” Our ability to pay the minimum quarterly distribution is subject to various restrictions and other factors described in more detail under the caption “Cash Distribution Policy and Restrictions on Distributions.”

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For the quarter in which this offering closes, we will pay a prorated distribution on our units covering the period from the completion of this offering through December 31, 2013, based on the actual length of that period.

In general, we will pay any cash distributions we make each quarter in the following manner:

•

first, to the holders of common units, until each common unit has received a minimum quarterly distribution of $ plus any arrearages from prior quarters;

•

second, to the holders of subordinated units, until each subordinated unit has received a minimum quarterly distribution of $ ; and

•

third, to all unitholders, pro rata, until each unit has received a distribution of $ .

If cash distributions to our unitholders exceed $ per unit in any quarter, our general partner will receive, increasing percentages, up to 50.0%, of the cash we distribute in excess of that amount. We refer to these distributions as “incentive distributions.” In certain circumstances, our general partner, as the initial holder of our incentive distribution rights, has the right to reset the target distribution levels described above to higher levels based on our cash distributions at the time of the exercise of this reset election. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

If we do not have sufficient available cash from operations, we may, but are under no obligation to, borrow funds to pay the minimum quarterly distribution to our unitholders.

The amount of distributable cash flow 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 % of the aggregate minimum quarterly distribution on our subordinated units for that period. The amount of distributable cash flow we generated during the twelve months ended September 30, 2013 on a pro forma basis would have been sufficient to pay 100% of the aggregate minimum quarterly distribution on all common units and % of the aggregate minimum quarterly distribution on our subordinated units for that period. Please read “Cash Distribution Policy and Restrictions on Distributions — Unaudited Pro Forma Distributable Cash Flow for the Year Ended December 31, 2012, and the Twelve Months Ended September 30, 2013.”

We believe, based on our financial forecast and related assumptions included in “Cash Distribution Policy and Restrictions on Distributions — Estimated Distributable Cash Flow for the Year Ending December 31, 2014,” that we will have sufficient available cash to pay the aggregate

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minimum quarterly distribution of $ million on all of our common units and subordinated units for the year ending December 31, 2014. However, we do not have a legal obligation to pay distributions at our minimum quarterly distribution rate or at any other rate except as provided in our partnership agreement, and there is no guarantee that we will make quarterly cash distributions to our unitholders. Please read “Cash Distribution Policy and Restrictions on Distributions.”

Subordinated units

Cypress Holdings, Cypress Energy Partners — TIR, LLC and certain of their affiliates will initially own all of our subordinated units. The principal difference between our common units and subordinated units is that for any quarter during the subordination period, the subordinated units will not be entitled to receive any distribution until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages.

Conversion of subordinated
units

The subordination period will end on the first business day after the date that we have earned and paid at least (1) $ (the minimum quarterly distribution on an annualized basis) on each outstanding common unit and subordinated unit for each of three consecutive, non-overlapping four quarter periods ending on or after , , or (2) $ (150.0% of the annualized minimum quarterly distribution) on each outstanding common unit and subordinated unit and the related distributions on the incentive distribution rights for any four-quarter period immediately preceding that date, in each case provided there are no arrearages on our common units at that time.

The subordination period also will end upon the removal of our general partner other than for cause if no subordinated units or common units held by the holders of subordinated units or their affiliates are voted in favor of that removal.

When the subordination period ends, each outstanding subordinated unit will convert into a common unit on a one-for-one basis, and all common units will no longer be entitled to arrearages. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — Subordinated Units and Subordination Period.”

Issuance of additional units

Our partnership agreement authorizes us to issue an unlimited number of additional units without the approval of our unitholders. Please read “Units Eligible for Future Sale” and “Our Partnership Agreement — Issuance of Additional Securities.”

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Limited voting rights

Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business. Our unitholders will have no right to elect our general partner or its directors on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 66 2/3% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon consummation of this offering, Cypress Holdings will own an aggregate of % of our common and subordinated units (or % of our common and subordinated units, if the underwriters exercise their option to purchase additional common units in full). This will give Cypress Holdings the ability to prevent the removal of our general partner. Please read “Our Partnership Agreement — Voting Rights.”

Limited call right

If at any time our general partner and its affiliates own more than 80.0% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a price equal to the greater of (1) the average of the daily closing price of our common units over the 20 trading days preceding the date that is three business days before notice of exercise of the call right is first mailed and (2) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. Please read “Our Partnership Agreement — Limited Call Right.”

Estimated ratio of taxable income to distributions

We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending , you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be % or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $ per unit, we estimate that your average allocable federal taxable income per year will be no more than approximately $ per unit. Thereafter, the ratio of allocable taxable income to cash distributions to you could substantially increase. Please read “Material Federal Income Tax Consequences — Tax Consequences of Unit Ownership — Ratio of Taxable Income to Distributions” for the basis of this estimate.

Material federal income tax consequences

For a discussion of the material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read “Material Federal Income Tax Consequences.”

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Directed unit program

At our request, the underwriters have reserved for sale, at the initial public offering price, up to % of the common units being offered by this prospectus for sale to employees, consultants, directors, director nominees and executive officers of our general partner, directors of Cypress Holdings and certain other key employees of Cypress Holdings and select individuals who may be able to assist us in developing our business. We do not know if these persons will choose to purchase all or any portion of these reserved common units, but any purchases they do make will reduce the number of common units available to the general public. Please read “Underwriting — Directed Unit Program.”

Exchange listing

We intend to apply to list our common units on the New York Stock Exchange under the symbol “CELP.”

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Summary Historical and Pro Forma Financial Data and Operating Data

The following table should be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical and pro forma financial statements and accompanying notes included elsewhere in this prospectus. The financial data included in this prospectus may not be indicative of our future results of operations, financial position and cash flows.

We were formed in September 2013 and do not have historical financial operating results. Therefore, in this prospectus, we present the historical financial statements and data of the SBG Predecessor, which consists of seven North Dakota limited liability companies that were formed in 2011 and 2012, and which we collectively refer to as our predecessor for financial accounting purposes, for the period from June 1, 2011 (Inception) through December 31, 2012. We also present historical financial statements and data of the CEP Successor, which is our successor for financial accounting purposes, for the period from March 15, 2012 (Inception) through December 31, 2012 and for the nine months ended September 30, 2013.

Set forth below is the following financial data:

•

summary historical financial data as of December 31, 2011 and 2012 and for the period from June 1, 2011 (Inception) through December 31, 2011 and the year ended December 31, 2012 of the SBG Predecessor, which have been derived from the audited consolidated financial statements of the SBG Predecessor that are included elsewhere in this prospectus;

•

summary historical financial data as of December 31, 2012 and for the period from March 15, 2012 (Inception) through December 31, 2012 of the CEP Successor, which have been derived from the audited consolidated financial statements of the CEP Successor that are included elsewhere in this prospectus;

•

summary condensed unaudited historical financial data as of September 30, 2012 and for the nine months ended September 30, 2012 of the SBG Predecessor, which have been derived from the unaudited condensed consolidated financial statements of the SBG Predecessor that are included elsewhere in this prospectus;

•

summary condensed unaudited historical financial data as of September 30, 2013 and for the nine months ended September 30, 2013 of the CEP Successor, which have been derived from the unaudited condensed consolidated financial statements of the CEP Successor that are included elsewhere in this prospectus; and

•

pro forma condensed combined financial data as of September 30, 2013 and for the nine months ended September 30, 2013 and for the year ended December 31, 2012 of Cypress Energy Partners, L.P., which have been derived from our unaudited pro forma condensed combined financial statements that are included elsewhere in this prospectus.

We do not provide summary historical financial data for (i) TIR, in which we will receive a 50.1% interest at the closing of this offering, or in TIR Parent, or (ii) four newly constructed EPA Class II SWD facilities, or, collectively, the Moxie Assets, prior to their acquisition by us from Moxie Disposal Systems, LLC and Peach Energy Services, LLC, on December 4, 2012. For historical financial data for the Moxie Assets for the period ended December 3, 2012, please read the audited “Statement of Revenues and Direct Operating Expenses of Assets Purchased by Cypress Energy Partners, LLC From Moxie Disposal Systems, LLC and Peach Energy Services, LLC from July 1, 2012 (Inception) through December 3, 2012” and the accompanying notes, which are included elsewhere in this prospectus. For historical financial data for TIR Parent for the years ended December 31, 2011 and 2012 and for the nine months ended September 30, 2012 and 2013, please read the audited and unaudited historical consolidated financial statements of TIR Parent and the accompanying notes, and Note 5 to Unaudited Pro Forma Condensed Combined Financial Statements, which are included elsewhere in this prospectus.

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The pro forma adjustments have been prepared as if the transactions described below had taken place on September 30, 2013, in the case of the pro forma balance sheet, or as of January 1, 2012, in the case of the pro forma condensed combined statement of operations for the year ended December 31, 2012 and for the nine months ended September 30, 2013.

These transactions include:

•

the retention by Cypress Holdings of the assets and liabilities associated with the CEP Successor’s SWD facility in Sheridan County, Montana and a related-party receivable and permit associated with the construction of a potential new SWD facility;

•

the contribution to us of the CEP Successor and a 50.1% interest in TIR in exchange for the issuance by us of common units and subordinated units, representing an aggregate % limited partner interest, to Cypress Holdings and its affiliates;

•

the issuance by us of the incentive distribution rights to our general partner; and

•

the issuance by us of common units to the public in this offering, representing a % limited partner interest in us, the receipt by us of approximately $ million in net proceeds from this offering and the application of such net proceeds as described in “Use of Proceeds.”

The pro forma financial information does not include the results of operations from CES because prior to our acquisition of the business it was not operated for profit and incurred a number of expenses no longer associated with the business. In addition, the pro forma financial information does not include any incremental expenses for being a publicly traded partnership that we estimate will be $2.0 million per year or the effect of the annual $3.0 million fee payable to our general partner for the provision of certain corporate overhead expenses allocated to us by Cypress Holdings. The pro forma financial information should not be considered as indicative of the historical results we would have had as a stand-alone partnership or the results we will have after this offering.

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The following table includes the non-GAAP financial measure Adjusted EBITDA. We define Adjusted EBITDA as our net income, plus interest expense, depreciation and amortization expense, income tax expense and impairment loss related to an SWD facility retained by Cypress Holdings, less a gain on the reversal of a contingent liability related to the SBG acquisition. For reconciliations of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with U.S. generally accepted accounting principles, or “GAAP,” please read “Selected Historical and Pro Forma Condensed Combined Financial Data — Non-GAAP Financial Measures.”


	SBG Predecessor									CEP Successor						Pro Forma Cypress Energy Partners, L.P.
	Period from June 1 (Inception) through December 31, 2011			Year Ended December 31, 2012			Nine Months Ended September 30, 2012			Period from March 15 (Inception) through December 31, 2012 (1)			Nine Months Ended September 30, 2013			Year Ended December 31, 2012		Nine Months Ended September 30, 2013
	(in thousands, except per unit and operational data)
Income Statement Data
Revenues	$	2,944		$	12,203		$	9,182		$	619		$	16,665		$	200,633	$	246,930
Gross margin		2,441			8,541			6,872			310			11,239			27,540		32,838
General and administrative expense		138			477			241			2,056			2,427			10,054		13,290
Impairment loss		—			—			—			—			4,375			—		—
Depreciation and amortization expense		123			1,398			839			99			3,066			3,124		4,173
Operating income (loss)		2,180			6,666			5,792			(1,845	)		1,371			14,362		15,375
Interest expense, net		35			111			82			—			—			4,001		3,266
Net income (loss)	$	2,162		$	6,595		$	5,746		$	(1,845	)	$	12,581		$	10,152	$	23,017
Less:
Net income attributable to non-controlling interests																$	1,167	$	2,109
Net income (loss) attributable to Cypress Energy Partners, L.P.																$	8,985	$	20,908
Basic earnings per common unit
Basic earnings per subordinated unit
Diluted earnings per common unit
Diluted earnings per subordinated unit
Balance Sheet Data (Period End)
Total assets	$	14,476		$	27,588		$	27,297		$	85,342		$	85,452
Total debt		2,798			2,314			2,395			—			—
Membership/Partnership equity		9,265			24,769			22,094			71,651			83,910
Cash Flows Data
Cash flows from operating activities	$	1,106		$	7,246		$	7,033		$	(2,244	)	$	7,512
Cash flows from investing activities		(10,860	)		(15,236	)		(13,421	)		(70,670	)		(2,278	)
Cash flows from financing activities		9,901			8,425			6,241			73,496			(681	)

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	SBG Predecessor						CEP Successor					Pro Forma Cypress Energy Partners, L.P.
	Period from June 1 (Inception) through December 31, 2011		Year Ended December 31, 2012		Nine Months Ended September 30, 2012		Period from March 15 (Inception) through December 31, 2012 (1)			Nine Months Ended September 30, 2013		Year Ended December 31, 2012		Nine Months Ended September 30, 2013
	(in thousands, except per unit and operational data)
Other Financial Data
Adjusted EBITDA (2)	$	2,320	$	8,104	$	6,667	$	(1,746	)	$	8,812	$	17,531	$	19,549
Adjusted EBITDA attributable to Cypress Energy Partners, L.P. (2)												$	12,320	$	14,268
Capital Expenditures (3)	$	10,860	$	15,236	$	13,421	$	70,670		$	2,278
Ratio of total debt to Adjusted EBITDA
Operational Data
Total barrels of saltwater disposed (in thousands)		1,641		8,674		6,226		551			14,489		10,962		14,489
Average revenue per barrel	$	1.79	$	1.41	$	1.47	$	1.12		$	1.15	$	1.34	$	1.14
Average number of inspectors													788		1,252
Average revenue per inspector (per week)												$	4,542	$	4,601

(1)

During the period from its inception through the date of its acquisition of the SBG Predecessor on December 31, 2012, the CEP Successor had no significant assets or operations.

(2)

For a definition of Adjusted EBITDA and a reconciliation to net income and to net cash provided by (used in) operating activities, please read “Selected Historical and Pro Forma Condensed Combined Consolidated Financial and Operating Data — Non-GAAP Financial Measures.”

(3)

We historically did not make a distinction between maintenance and expansion capital expenditures; however, for the purposes of the presentation of “Unaudited Pro Forma Distributable Cash Flow for the Year Ended December 31, 2012, and the Twelve Months Ended September 30, 2013,” we have estimated that approximately $0.7 million and $0.4 million of these capital expenditures were maintenance capital expenditures for both the year ended December 31, 2012 and the twelve months ended September 30, 2013, respectively. Please read “Cash Distribution Policy and Restrictions on Distributions — Unaudited Pro Forma Distributable Cash Flow for the Year Ended December 31, 2012, and the Twelve Months Ended September 30, 2013.”

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RISK FACTORS

Investing in our common units involves a high degree of risk. You should carefully consider the risks described below with all of the other information included in this prospectus before deciding to invest in our common units. Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. If any of the following risks actually occur, they may materially harm our business and our financial condition and results of operations. In that case, we might not be able to pay distributions on our common units, the trading price of our common units could decline, and you could lose part or all of your investment in us.

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 $ per unit per quarter, or $ per unit on an annualized basis, we will require available cash of approximately $ million per quarter, or $ million per year, based on the number of common and subordinated units to be outstanding immediately after completion of this offering. 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;

•

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;

•

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 interest in TIR held by our affiliate;

•

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, 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;

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•

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.

For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read “Cash Distribution Policy and Restrictions on Distributions.”

We must generate approximately $ million of cash available for distribution to pay the aggregate minimum quarterly distributions for four quarters on all units that will be outstanding immediately following this offering. 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 % 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 twelve months ended September 30, 2013 on a pro forma basis would have been sufficient to pay 100% of the aggregate minimum quarterly distribution on all common units, and % 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 “Cash Distribution Policy and Restrictions on Distributions.” 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.

The assumptions underlying the forecast of cash available for distribution that we include in “Cash Distribution Policy and Restrictions on Distributions” are inherently uncertain and are subject to significant business, economic, financial, regulatory, weather and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.

The forecast of cash available for distribution set forth in “Cash Distribution Policy and Restrictions on Distributions” includes our forecasted results of operations, Adjusted EBITDA and cash available for distribution for the year ending December 31, 2014. The forecast has been prepared by management, and we have not received an opinion or report on it from our or any other independent auditor. Our assumptions underlying the forecast include, among other things, an increase in our revenues based on the higher utilization and expansion of our existing SWD facilities, increasing regulation of SWD wells and pipeline integrity, an increase in the revenue generated by TIR based on the expansion of its pipeline and integrity services, an increase in the level of drilling activity and producing wells in the regions in which we operate that results in more saltwater being delivered to our SWD facilities, increased sales of our residual oil and increased management fees for managing third-party SWD facilities. The assumptions underlying the forecast are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks. If we do not achieve the forecasted results, 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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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 1,778 rigs in October 2013. 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 75% of our revenue in our Water and Environmental Services Segment for the nine months ended September 30, 2013; therefore a future significant decrease in drilling activity could have an adverse effect on our revenue and profitability.

Our customers’ willingness to engage in drilling and production of oil and natural gas depends largely upon prevailing industry conditions that are influenced by numerous factors over which our management has no control, such as:

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the supply of and demand for oil and natural gas;

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

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

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

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the discovery rates of new oil and natural gas reserves;

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available pipeline and other transportation capacity;

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

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

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domestic and worldwide economic conditions;

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contractions in the credit market;

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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;

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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;

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

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

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

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

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

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technical advances affecting energy consumption;

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

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

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the impact of changing regulations and environmental and safety rules and policies.

The working capital needs of TIR are substantial, which will reduce our borrowing capacity for other purposes and reduce our cash available for distribution.

TIR has substantial working capital needs throughout the year as it pays its inspectors on a weekly basis but typically receives payment from its customers 45 to 90 days after the services have been performed. TIR Parent has historically borrowed under its factoring facility, and TIR will continue to make borrowings under this facility to fund these working capital needs. These borrowings will reduce the amount of credit available for other uses, such as 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 factoring 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 TIR do not typically enter into long-term contracts with customers. While we and TIR each frequently operate under master services agreements with customers that set forth the terms on which we and TIR will provide services, customers operating under these agreements typically have the ability to terminate their relationship with us and TIR 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 68% of our Water and Environmental Services segment revenue for the year ended December 31, 2012 and 56% of segment revenue for the nine months ended September 30, 2013. In addition, one of our water and environmental services customers, BS&W Solutions, LLC, accounted for 25% of our segment revenue for the year ended December 31, 2012. Our five largest customers of our Pipeline Inspection and Integrity Services segment accounted for approximately 71% of our segment revenue for the year ended December 31, 2012 and 74% of segment revenue for the nine months ended September 30, 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 year ended December 31, 2012 and the nine months ended September 30, 2013, on a pro forma basis. 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. It is possible that the states, counties and cities in which we operate our water and environmental

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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.

A significant increase in fuel 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.

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 nine months ended September 30, 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, and the historical financial and operating data presented in this prospectus may not be representative of our future results.

The SBG Predecessor’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 TIR. As a result, we have provided only limited financial and operating data regarding the consolidated business that we will operate following this offering. 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 the SBG Predecessor and the CEP Successor 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

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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 associated with rapid growth and expansion.

We have grown rapidly since our inception in 2012, primarily through acquisitions. Since our inception through September 30, 2013, we have acquired two businesses and an equity interest in TIR. 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:

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organizational challenges common to large, expansive operations;

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administrative burdens;

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limitations with systems and technology;

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safety and training;

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ability to recruit, train and retain personnel and managers;

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ability to obtain permits for expanded operations;

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access to debt and equity capital on attractive terms; and

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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 and its affiliates are 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

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projects, they may not be completed on schedule or at all or at the budgeted cost. Furthermore, we will not receive any material increases in revenues until after completion of the project although we will have to pay financing and construction costs during the construction period. As a result, new SWD facilities may not be able to attract enough demand for water and environmental services to achieve our expected investment return, which could materially adversely affect our results of operations and financial condition and our ability in the future to make distributions to our unitholders.

Our ability to acquire assets from 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 in the future, including acquiring the remaining 49.9% investment in TIR. The consummation and timing of any future acquisitions of these assets will depend upon, among other things, Cypress Holdings’ 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 Cypress Holdings is 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 if, and when, Cypress Holdings offers such assets for sale, and our decision will not be subject to unitholder approval. Please read “Certain Relationships and Related Party Transactions — Agreements Governing the Restructuring Transactions.”

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

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

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

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outbid by competitors; or

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for any other reason.

If we are unable to make acquisitions from Cypress Holdings 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:

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

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the assumption of unknown liabilities;

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limitations on rights to indemnity from the seller;

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mistaken assumptions about the overall costs of equity or debt;

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

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integrating business operations or unforeseen regulatory issues;

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unforeseen difficulties operating in new geographic areas; and

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customer or key personnel losses at the acquired businesses.

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

We conduct a portion of our operations through two 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.

CES is a joint venture with an affiliate of SBG Energy Services, LLC, in which we own 51.0%. We may also enter into other joint venture arrangements with third parties in the future. SBG Energy Services, LLC and the minority third-party owners of TIR have, and these third parties may have, obligations that are important to the success of the joint venture, 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 joint venture partner in CES and minority third-party owners of TIR have to satisfy their perspective 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 arrangement for CES may involve risks not otherwise present without a partner, including, for example:

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

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

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

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

Our TIR arrangement may involve other risks related to the minority third-party owners.

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. See “Certain Relationships and Related Party Transactions — Agreements Governing the Restructuring Transactions — Cypress Energy Services Joint Venture.”

We will be required to generate sufficient cash to service our indebtedness.

Our outstanding long-term debt, under which TIR is the borrower, will impose significant cash interest payment obligations on us following the closing of this offering and, accordingly, we will have to generate significant cash flow from operating activities to fund our debt service obligations. We cannot assure you that we will maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness. See “Management's Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”

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Restrictions in our credit facilities could adversely affect our business, financial condition, results of operations, ability to make cash distributions to our unitholders and the value of our units.

Our credit facilities, under which TIR is the borrower, limit TIR’s ability to, among other things:

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incur or guarantee additional debt;

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make distributions on or redeem or repurchase units;

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make certain investments and acquisitions;

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make capital expenditures;

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incur certain liens or permit them to exist;

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enter into certain types of transactions with affiliates;

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enter into hedging transactions;

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merge or consolidate with another company; and

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transfer, sell or otherwise dispose of assets.

Our credit facilities also contain covenants requiring TIR to maintain certain financial ratios. TIR’s ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that it will meet those ratios and tests.

The provisions of our credit facilities 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. Our funds available for operations, future business opportunities and cash distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt. 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 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 you 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 existing or future debt agreements, including the Asset Purchase Agreement, which we refer to as the factoring facility, and the 2009 and 2010 Loan Agreements, which we refer to as the mezzanine facilities. Our credit facilities restrict TIR’s ability to dispose of assets and use the proceeds from the disposition. TIR 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 credit facilities could result in a default or an event of default that could enable our 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 our debt is accelerated, defaults under our 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 their 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.

At the closing of this offering, after giving pro forma effect to this offering and the related restructuring transactions, we will have $ million of indebtedness under our credit facilities, under which TIR is the borrower. Following this offering, we will have the ability to incur

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additional debt, subject to limitations in our credit facilities. Our degree of leverage could have important consequences to us, including the following:

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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;

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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;

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

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

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

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

We own and operate SWD facilities in North Dakota and Texas, each with its own regulatory program for addressing the handling, treatment, recycling, and disposal of saltwater. We are also required to comply with federal laws and regulations governing our operations. These environmental laws and regulations require that we, among other things, obtain permits and authorizations prior to the development and operation of waste treatment and storage facilities and in connection with the disposal and transportation of certain types of waste. The applicable regulatory agencies strictly monitor waste handling and disposal practices at all of our facilities. For many of our sites, we are required under applicable laws, regulations, and/or permits to conduct periodic monitoring, company-directed testing and third-party testing. Any failure to comply with such laws, regulations, or permits may result in suspension or revocation of necessary permits and authorizations, civil or criminal liability and imposition of fines and penalties, which could adversely impact our operations and revenues and ability to continue to provide oilfield water and environmental services to our customers.

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 September 30, 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, 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

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some cases oil and natural gas producers, to oppose SWD permits. Any such limitations or requirements could limit the water and environmental services we provide to our customers, or make such services more expensive to provide, which could have a material adverse effect on our financial position, results of operations, cash flows and our ability to make cash distributions to our unitholders.

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

In most states, our customers are required to obtain permits from one or more governmental agencies in order to perform drilling and completion activities and to operate pipeline and gathering systems. Such permits are typically issued by state agencies, but federal and local governmental permits may also be required. The requirements for such permits vary depending on the location where such drilling and completion, and pipeline and gathering, activities will be conducted. As with all governmental permitting processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit to be issued, and the conditions that may be imposed in connection with the granting of the permit. Recently, moratoriums on the issuance of permits for certain types of drilling and completion activities have been imposed in some areas, such as New York. Some of our customers’ drilling and completion activities may also take place on federal land or Native American lands, requiring leases and other approvals from the federal government or Native American tribes to conduct such drilling and completion activities. In some cases, federal agencies have cancelled proposed leases for federal lands and refused or delayed required approvals. Consequently, our customers’ operations in certain areas of the U.S. may be interrupted or suspended for varying lengths of time, causing a loss of revenue to us and adversely affecting our results of operations in support of those customers.

In the future we may face increased obligations relating to the closing of our SWD facilities and may be required to provide an increased level of financial assurance to guaranty the appropriate closure activities occur for an SWD facility.

Obtaining a permit to own or operate an SWD facility generally requires us to establish performance bonds, letters of credit or other forms of financial assurance to address clean up and closure obligations at our SWD facilities. In particular, the regulatory agencies of the two states in which we operate require us to post letters of credit in connection with the operation of our SWD facilities. As we acquire additional SWD facilities or expand our existing SWD facilities, these obligations will increase. Additionally, in the future regulatory agencies may require us to increase the amount of our closure bonds at existing SWD facilities. We have accrued approximately $9 thousand on our balance sheet related to our future closure obligations of our SWD facilities, as of September 30, 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

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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. The Safe Drinking Water Act, or SDWA, regulates the underground injection of substances through the Underground Injection Control, or 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 by 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.

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 by 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. 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.

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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 prohibit 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 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. Such laws and regulations include the federal Resource, Conservation and Recovery Act, or RCRA, the Comprehensive Environmental Response Compensation and Liability Act, or CERCLA, the Clean Water Act, SDWA, the Clean Air Act, or CAA, the Oil Pollution Act of 1990, or OPA, and the Occupational Safety and Health Act, or OSHA, and analogous state laws. 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. 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, EPA published final rules that establish new air emission controls for oil and natural gas production and natural gas processing operations under the CAA. 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. 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 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.

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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 may impose strict, joint and several liabilities in connection with releases of regulated substances into the environment. Therefore, in some situations we could be exposed to liability as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, third parties.

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

In particular, the RCRA, which governs the disposal of solid and hazardous waste, currently exempts certain E&P wastes from classification as hazardous wastes. In recent years, proposals have been made to rescind this exemption from RCRA. For example, in September 2010 an environmental group filed a petition with the EPA requesting reconsideration of this RCRA exemption. To date, the EPA has not taken any action on the petition. If the exemption covering E&P wastes is repealed or modified, or if the regulations interpreting the rules regarding the treatment or disposal of this type of waste were changed, our operations could face significantly more stringent regulations, permitting requirements, and other restrictions, which could have a material adverse effect on our business.

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 a fixed $3.0 million per year. 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 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 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.

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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 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 either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. These allowances would be expected to escalate significantly in cost over time.

In addition, in December 2009, the EPA determined that emissions of carbon dioxide, methane and certain other GHGs endanger public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the CAA. The EPA has already adopted two sets of rules regulating GHG emissions under the CAA, one of which requires a reduction in emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources, both of which became effective in January 2011. The EPA’s rules relating to emissions of GHGs from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent the EPA from implementing or requiring state environmental agencies to implement the rules. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified GHG emission sources in the U.S., including oil and natural gas producer operations, on an annual basis. Additionally, on September 20, 2013, the EPA proposed New Source Performance Standards for Greenhouse Gas emissions from Electric Utility Generating Units. 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.

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. The designation of previously unidentified endangered or threatened species under such laws may affect our and our customers’ operations.

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For example, the federal government is considering listing the greater sage-grouse 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.

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 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. For instance, the fiberglass storage tank of one of the facilities owned by SBG’s entity in which we

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own an interest was not protected against lightning strikes and was struck by lightning in June 2013 and damaged. 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. Some of our other facilities are still without such protection systems. 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.

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.

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. Although it is not possible at this time to predict the final outcome of the EPA's study or the requirements of any additional federal or state legislation or regulation regarding hydraulic fracturing, management of drilling fluids or well integrity requirements, any new federal or state restrictions imposed on such activities in areas in which we conduct business could significantly increase our operating, capital and compliance costs as well as delay our ability to develop oil and natural gas reserves. In addition to increased regulation of our business, we may also experience an increase in litigation seeking damages as a result of heightened public concerns related to air quality, water quality, and other environmental impacts.

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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.

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

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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 margins for our Pipeline Inspection and Integrity Services segment could decrease if the demand for our inspectors decrease, if our safety record declines, 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 TIR may not be obtainable on terms acceptable to us or, if obtained, may not be obtained on terms consistent with current practices, in which case our revenue and profitability could decline. We also cannot ensure that the parties from whom we lease, license or otherwise occupy the land on which certain of our facilities are situated, or the parties from whom we lease certain of our equipment, will renew our current leases, licenses or other occupancy agreements upon their expiration on commercially reasonable terms or at all. Any such failure to honor the terms of the leases or licenses or renew our current leases or licenses could have a material adverse effect on our financial position, results of operations and cash flows.

We may be unable to attract and retain a sufficient number of skilled and qualified workers.

The delivery of our water and environmental services and products requires personnel with specialized skills and experience who can perform physically demanding work. The saltwater

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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 TIR’s 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, our 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 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:

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

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loss of electricity or power;

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

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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;

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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;

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road restrictions;

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labor difficulties;

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malfunctions in automated control systems at the facilities;

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disruptions in the supply of saltwater to our facilities;

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

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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 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 expense 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 systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating our operational systems. In addition, dependence upon automated systems may further increase the risk that operational system flaws, employee tampering or manipulation of those systems will result in losses that are difficult to detect.

Due to technology advances, we have become more reliant on technology to help increase efficiency in our business. We use computer programs to help run our financial and operations processes, and this may subject our business to increased risks. Any future cyber security attacks that affect our facilities, communications systems, our customers or any of our financial data could

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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.

Prior to this offering, we have not been required to file reports with the SEC. Upon the completion of this offering, we will become subject to the public reporting requirements of the Exchange Act. We prepare our financial statements in accordance with GAAP, but our internal accounting controls may not currently meet all standards applicable to companies with publicly traded securities. 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 will require us, among other things, 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 firms, 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 will 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 TIR 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 credit facilities.

Although we will be required to disclose changes made in our internal control over financial reporting on a quarterly basis, we will be required to assess the effectiveness of our controls annually. However, for as long as we are an “emerging growth company” under the recently enacted 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. See “Summary — Our Emerging Growth Company Status.” 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

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adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders. In addition, we may not realize the benefits we anticipate from the implementation of our enterprise-wide information system.

Risks Inherent in an Investment in Us

Our general partner and its affiliates, including 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.

Following the offering, Cypress Holdings will own a 0.0% non-economic partner interest and a % limited partner interest in us (or % if the underwriters’ option to purchase additional common units is exercised in full) and will own and control our general partner and will 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:

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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;

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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;

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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;

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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;

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

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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;

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our general partner will determine the amount and timing of many of our cash expenditures, whether a cash expenditure is classified as an expansion capital 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

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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;

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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;

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our partnership agreement permits us to classify up to $ 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;

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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;

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our general partner intends to limit its liability regarding our contractual and other obligations;

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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;

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

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

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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 “Certain Relationships and Related Party Transactions — Agreements Governing the Restructuring Transactions — Omnibus agreement” and “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

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

Our partnership agreement replaces our general partner’s fiduciary duties to holders of our common units with contractual standards governing its duties.

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:

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how to allocate corporate opportunities among us and its affiliates;

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whether to exercise its limited call right;

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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;

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

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whether to elect to reset target distribution levels;

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

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

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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 — Duties of the General Partner.”

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.

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:

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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;

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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;

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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 fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

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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.”

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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 an administrative fee of $750,000 quarterly through for the provision of certain general and administrative expenses. This fee is subject to increase for inflation and to increase, 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. After , 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.

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 will own sufficient units upon completion of the offering 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. At closing, our general partner and its affiliates will own % of the common units and subordinated units (or % if the underwriters’ option to purchase additional common units is exercised in full) (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 or wanton 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

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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.

We may issue additional units without unitholder approval, which would dilute your 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:

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

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

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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;

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the ratio of taxable income to distributions may increase;

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

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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:

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management of our business may no longer reside solely with our current general partner; and

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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.

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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.

After the completion of this offering, assuming that the underwriters do not exercise their option to purchase additional common units, our general partner and its affiliates will hold common units and 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. Please read “Units Eligible for Future Sale.” 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.

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. Consequently, Cypress Holdings and other affiliates of our general partner may acquire, construct or dispose of additional SWD facilities, pipeline integrity or inspection assets or other assets in the future without any obligation to offer us the opportunity to purchase any of those assets. 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 general partner has a limited call right that may require you to sell your 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, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. At the completion of this offering and assuming the underwriters’ option to purchase additional common units from us is not exercised, our general partner and its affiliates will own approximately % 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 , 2014), assuming no additional issuances of common units by us (other than upon the conversion of the subordinated units) and the underwriters’ option to purchase additional common units from us is not exercised, our general partner and its affiliates will own approximately % of our outstanding common units

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(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. For additional information about our general partner’s call right, please read “Our Partnership Agreement — Limited Call Right.”

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 you 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.

There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. The price of our common units may fluctuate significantly, and you could lose all or part of your investment.

Prior to this offering, there has been no public market for our common units. After this offering, there will be only publicly traded common units. Cypress Holdings through a wholly owned subsidiary and its affiliates will own common units and subordinated units, representing an aggregate % limited partner interest in us (or % if the underwriters’ option to purchase additional common units is exercised in full). We do not know the extent to which investor interest will lead to the development of an active trading market or how liquid that market might be. You may not be able to resell your common units at or above the initial public offering price. 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.

The initial public offering price for the common units offered hereby will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units may decline below the initial public offering price.

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 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

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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. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — General Partner’s Right to Reset Incentive Distribution Levels.”

We will incur increased costs as a result of being a publicly traded partnership.

We have no history operating as 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 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. We have included $2.0 million of estimated annual incremental costs associated with being a publicly traded partnership in our financial forecast included elsewhere in this prospectus. However, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate.

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

We intend to apply to list our common units on the NYSE. Because we will be 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. Please read “Management — Management of Cypress Energy Partners, L.P.”

You will experience immediate and substantial dilution in net tangible book value of $ per common unit.

The assumed initial public offering price of $ per common unit (the midpoint of the price range set forth on the cover page of this prospectus) exceeds our pro forma net tangible book value of $ per unit. Based on the assumed initial public offering price of $ per common unit, you will incur immediate and substantial dilution in pro forma net tangible book value of

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$ per common unit. This dilution results primarily because the assets contributed by Cypress Holdings are recorded in accordance with GAAP at their historical cost, and not their fair value. Please read “Dilution.”

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.

Your 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. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency were to determine that:

•

we were conducting business in a state but had not complied with that particular state’s partnership statute; or

•

your 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.

For a discussion of the implications of the limitations of liability on a unitholder, please read “Our Partnership Agreement — Limited Liability.”

Tax Risks

In addition to reading the following risk factors, please read “Material Federal Income Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

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.

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

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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 you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you 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 you. 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. Please read “Material Federal Income Tax Consequences — Partnership Status.” 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.

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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 expressed in this prospectus 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 your 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. Please read “Material Federal Income Tax Consequences — Disposition of Common Units — Recognition of Gain or Loss” for a further discussion of the foregoing.

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 you are a tax-exempt entity or a non-U.S. person, you should consult a tax advisor before investing in our common units.

TIR conducts activities that may not generate qualifying income, and we may choose 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 would 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. For a discussion of qualifying income, please read “Material Federal Income Tax Consequences — Partnership Status.” Latham & Watkins LLP is unable to opine as to the qualifying nature of the income generated by certain portions of TIR’s operations. Consequently, we are in the process of requesting a ruling from the IRS upon which, if granted, we may rely with respect to the qualifying nature of such income. In an attempt to ensure that 90% or

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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. If the IRS is unwilling or unable to provide a favorable ruling in a timely manner with respect to our income from these operations, it may be necessary for us to elect to treat this subsidiary as a corporation for federal income tax purposes. Currently, these operations represent approximately % of our total gross income.

This future corporate subsidiary would be subject to corporate-level tax, which reduces the cash available for distribution to us and, in turn, to our unitholders. If the IRS were to successfully assert that any corporate subsidiary has more tax liability than we anticipate or legislation were enacted that increased the corporate tax rate, our cash available for distribution to our unitholders would be further reduced.

We 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 will adopt 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 you. Latham & Watkins LLP is unable to opine as to the validity of such filing positions. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. Please read “Material Federal Income Tax Consequences — Tax Consequences of Unit Ownership — Section 754 Election” for a further discussion of the effect of the depreciation and amortization positions we will adopt.

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. Latham & Watkins LLP has not rendered an opinion with respect to whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations. Please read “Material Federal Income Tax Consequences — Disposition of Common Units — Allocations Between Transferors and Transferees.”

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

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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. Latham & Watkins LLP has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to effect a short sale of common units; therefore, our unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.

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.

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

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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. Please read “Material Federal Income Tax Consequences — Disposition of Common Units — Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.

As a result of investing in our common units, you 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 your 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. Please consult your tax advisor.

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USE OF PROCEEDS

We expect to receive net proceeds of approximately $ million from the sale of common units offered by this prospectus, based on an assumed initial public offering price of $ per common unit (the mid-point of the price range set forth on the cover of the prospectus), after deducting underwriting discounts, structuring fees and estimated offering expenses. Our estimate assumes the underwriters’ option to purchase additional common units from us is not exercised. We expect to use the net proceeds of approximately $ million, after deducting underwriting discounts, commissions and a structuring fee, to distribute $ million to a wholly owned subsidiary of Cypress Holdings as reimbursement for certain capital expenditures it incurred with respect to assets contributed to us and to pay transaction expenses related to our credit facilities.

If and to the extent the underwriters exercise their option to purchase additional common units, the number of common units purchased by the underwriters pursuant to such exercise will be issued to the public and the remainder of the additional common units, if any, will be issued to a wholly owned subsidiary of Cypress Holdings. Any such common units issued to Cypress Holdings will be issued for no additional consideration. If the underwriters exercise in full their option to purchase additional common units from us, we expect to receive net proceeds of approximately $ million, after deducting underwriting discounts and structuring fees. We will use any net proceeds from the exercise of the underwriters’ option to purchase additional common units from us to make a distribution to a wholly owned subsidiary of Cypress Holdings. Any common units not purchased by the underwriters pursuant to their exercise of the option will be issued to a wholly owned subsidiary of Cypress Holdings at the expiration of the option period for no additional consideration.

An increase or decrease in the initial public offering price of $1.00 per common unit would cause the net proceeds from the offering, after deducting underwriting discounts, structuring fees and offering expenses, to increase or decrease by $ million.

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CAPITALIZATION

The following table shows cash and cash equivalents and capitalization as of September 30, 2013:

•

on an historical basis with respect to the CEP Successor;

•

on an as adjusted basis to give effect to our acquisition of a 50.1% equity interest in TIR; and

•

on a pro forma basis with respect to Cypress Energy Partners to give effect to the pro forma adjustments described in our unaudited pro forma condensed combined financial statements included elsewhere in this prospectus, including this offering and the application of the net proceeds of this offering in the manner described under “Use of Proceeds” and the other restructuring transactions described under “Prospectus Summary — The Restructuring Transactions.”

This table is derived from, should be read together with and is qualified in its entirety by reference to the historical combined financial statements and the accompanying notes and the unaudited pro forma condensed combined financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”


As of September 30, 2013	CEP Successor Historical		CEP Successor As Adjusted (1)		Cypress Energy Partners, L.P. Pro Forma (2)
	(in thousands)
Cash and Cash Equivalents	$	5,135	$	14,374	$
Long-term Debt:
Mezzanine facilities		—	$	20,463	$	20,463
Factoring facility		—		37,758		37,758
Total long-term debt (including current maturities)		—	$	58,221	$	58,221
Member’s/Partners’ Equity (3):
CEP Successor member’s equity		83,910
Limited Partners’ Units (3):
Common units — public		—
Common units — Cypress Holdings and Cypress Energy Partners — TIR, LLC and affiliates (3)		—
Subordinated units — Cypress Holdings and Cypress Energy Partners — TIR, LLC and affiliates		—
Total member’s/partners’ equity		—
Non-controlling interest
Total equity		83,910
Total capitalization	$		$		$

(1)

Represents CEP Successor Historical, as adjusted for the historical operations of TIR.

(2)

Assumes the mid-point of the price range set forth on the cover of this prospectus.

(3)

Assumes the underwriters’ option to purchase additional common units from us is not exercised.

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DILUTION

Dilution is the amount by which the offering price per common unit in this offering will exceed the pro forma net tangible book value per unit after the offering. On a pro forma basis as of September 30, 2013, after giving effect to the offering of common units and the application of the related net proceeds, and assuming the underwriters’ option to purchase additional common units is not exercised, our net tangible book value was approximately $ million, or $ per unit. Purchasers of common units in this offering will experience substantial and immediate dilution in pro forma net tangible book value per common unit for financial accounting purposes, as illustrated in the following table.


Assumed initial public offering price per common unit (1)		$
Pro forma net tangible book value per unit before the offering (2)	$
Decrease in net tangible book value per unit attributable to purchasers in the offering
Less: Pro forma net tangible book value per unit after the offering (3)
Immediate dilution in net tangible book value per common unit to purchasers in the offering (4)(5)		$

(1)

The mid-point of the price range set forth on the cover of this prospectus.

(2)

Determined by dividing the number of units ( common units and subordinated units) to be issued to the general partner and its affiliates for their contribution of assets and liabilities to us into the pro forma net tangible book value of the contributed assets and liabilities, of $ million.

(3)

Determined by dividing the number of units to be outstanding after this offering ( common units and subordinated units) and the application of the related net proceeds into our pro forma net tangible book value, after giving effect to the application of the net proceeds of this offering, of $ million.

(4)

If the initial public offering price were to increase or decrease by $1.00 per common unit, then dilution in net tangible book value per common unit would equal $ and $ , respectively.

(5)

Because the total number of units outstanding following this offering will not be impacted by any exercise of the underwriters’ option to purchase additional common units and any net proceeds from such exercise will not be retained by us, there will be no change to the dilution in net tangible book value per common unit to purchasers in the offering due to any such exercise of the option.

The following table sets forth the number of units that we will issue and the total consideration contributed to us by the general partner and its affiliates in respect of their units and by the purchasers of common units in this offering upon consummation of the transactions contemplated by this prospectus.


	Units Acquired				Total Consideration
	Number	%			Amount	%
	(in thousands)
General partner and its affiliates (1)(2)(3)				%	$			%
Public common unitholders				%				%
Total			100.0	%	$		100.0	%

(1)

Upon the consummation of the transactions contemplated by this prospectus, common units and subordinated units will be owned by our general partner and its affiliates, including Cypress Holdings, and LTIP Participants.

(2)

Assumes the underwriters’ option to purchase additional common units from us is not exercised.

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(3)

The assets contributed by Cypress Holdings and its affiliates were recorded at historical cost in accordance with GAAP. Book value of the consideration provided by Cypress Holdings and its affiliates, as of September 30, 2013, after giving effect to the application of the net proceeds in this offering, was as follows:


		(in thousands)
Book value of net assets contributed		$
Less:
Distribution from net proceeds of this offering
Total consideration		$

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CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

The following discussion of our cash distribution policy should be read in conjunction with the specific assumptions included in this section. In addition, “Forward-Looking Statements” and “Risk Factors” should be read for information regarding statements that do not relate strictly to historical or current facts and regarding certain risks inherent in our business.

For additional information regarding our historical and pro forma results of operations, please refer to our historical combined financial statements and the accompanying notes and the unaudited pro forma condensed combined financial statements and the accompanying notes included elsewhere in this prospectus.

General

Rationale for Our Cash Distribution Policy

Our partnership agreement requires that we distribute all of our available cash quarterly. This requirement forms the basis of our cash distribution policy and reflects a basic judgment that our unitholders will be better served by distributing our available cash rather than retaining it, because, among other reasons, we believe we will generally finance any expansion capital expenditures from external financing sources. Under our current cash distribution policy, we intend to make a minimum quarterly distribution to the holders of our common units and subordinated units of $ per unit, or $ per unit on an annualized basis, to the extent we have sufficient available cash after the establishment of cash reserves and the payment of costs and expenses, including the payment of expenses to our general partner. However, other than the requirement in our partnership agreement to distribute all of our available cash each quarter, we have no legal obligation to make quarterly cash distributions in this or any other amount, and our general partner has considerable discretion to determine the amount of our available cash each quarter. In addition, our general partner may change our cash distribution policy at any time, subject to the requirement in our partnership agreement to distribute all of our available cash quarterly. Generally, our available cash is our (1) cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves and (2) cash on hand resulting from working capital borrowings made after the end of the quarter. Because we are not subject to an entity-level federal income tax, we expect to have more cash to distribute than would be the case if we were subject to federal income tax. If we do not generate sufficient available cash from our operations, we may, but are under no obligation to, borrow funds to pay the minimum quarterly distribution to our unitholders.

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy

Although our partnership agreement requires that we distribute all of our available cash quarterly, there is no guarantee that we will make quarterly cash distributions to our unitholders at our minimum quarterly distribution rate or at any other rate, and we have no legal obligation to do so. Our current cash distribution policy is subject to certain restrictions, as well as the considerable discretion of our general partner in determining the amount of our available cash each quarter. The following factors will affect our ability to make cash distributions, as well as the amount of any cash distributions we make:

•

Our cash distribution policy will be subject to restrictions on cash distributions under our credit facilities, under which TIR is the borrower, and other debt agreements we may enter into in the future. Our credit facilities contain covenants requiring TIR to maintain certain financial ratios and restricting TIR’s ability to incur indebtedness, make distributions, make investments and engage in certain other partnership actions, including making cash distributions while an event of default has occurred and is continuing under the facility, notwithstanding our cash distribution policy. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Our Credit Facilities.”

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•

The amount of cash that we distribute and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. Specifically, our general partner will have the authority to establish cash reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment of or increase in those reserves could result in a reduction in cash distributions from levels we currently anticipate pursuant to our stated cash distribution policy. Any decision to establish cash reserves made by our general partner in good faith will be binding on our unitholders.

•

While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to make cash distributions, may be amended. During the subordination period our partnership agreement may not be amended without the approval of our public common unitholders, except in a limited number of circumstances when our general partner can amend our partnership agreement without any unitholder approval. For a description of these limited circumstances, please read “Our Partnership Agreement — Amendment of Our Partnership Agreement — No Unitholder Approval.” However, after the subordination period has ended, our partnership agreement may be amended with the consent of our general partner and the approval of a majority of the outstanding common units, including common units owned by our general partner and its affiliates. At the closing of this offering, Cypress Holdings will own indirectly our general partner and will indirectly own an aggregate of approximately % of our outstanding common units and % subordinated units (assuming no exercise of the underwriters’ option to purchase additional common units).

•

Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, or the Delaware Act, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets.

•

We may lack sufficient cash to pay distributions to our unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating and maintenance or general and administrative expenses, principal and interest payments on our debt, tax expenses, working capital requirements and anticipated cash needs. Our available cash is directly impacted by our cash expenses necessary to run our business and will be reduced dollar-for-dollar to the extent such uses of cash increase. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — Distributions of Available Cash.”

•

Our ability to make cash distributions to our unitholders depends on the performance of our subsidiaries and their ability to distribute cash to us. The ability of our subsidiaries to make cash distributions to us may be restricted by, among other things, the provisions of future indebtedness, applicable state partnership and limited liability company laws and other laws and regulations.

•

If and to the extent our available cash materially declines from quarter to quarter, we may elect to change our current cash distribution policy and reduce the amount of our quarterly distributions in order to service or repay our debt or fund expansion capital expenditures.

To the extent that our general partner determines not to distribute the full minimum quarterly distribution on our common units with respect to any quarter during the subordination period, the common units will accrue an arrearage equal to the difference between the minimum quarterly distribution and the amount of the distribution actually paid on the common units with respect to that quarter. The aggregate amount of any such arrearages must be paid on the common units before any distributions of available cash from operating surplus may be made on the subordinated units and before any subordinated units may convert into common units. The subordinated units will not accrue any arrearages. Any shortfall in the payment of the minimum quarterly distribution on the common units with respect to any quarter during the subordination period may decrease

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the likelihood that our quarterly distribution rate would increase in subsequent quarters. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — Subordinated Units and Subordination Period.”

Our Ability to Grow is Dependent on Our Ability to Access External Expansion Capital

Our partnership agreement requires us to distribute all of our available cash to our unitholders on a quarterly basis. As a result, we expect that we will rely primarily upon our cash reserves and external financing sources, including borrowings under our credit facilities and the issuance of debt and equity securities, to fund future acquisitions and other expansion capital expenditures. We do not have any commitment from Cypress Holdings to provide any capital to us following this offering. To the extent we are unable to finance growth with external sources of capital, the requirement in our partnership agreement to distribute all of our available cash and our current 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 businesses that reinvest all of their available cash to expand ongoing operations. Our credit facilities, under which TIR is the borrower restrict TIR’s ability to incur additional debt, including through the issuance of debt securities. Please read “Risk Factors — Risks Related to Our Business — Restrictions in our credit facilities could adversely affect our business, financial condition, results of operations, ability to make cash distributions to our unitholders and the value of our units.” To the extent we issue additional units, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our cash distributions per unit. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to our common units, 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. If we incur additional debt (under our credit facilities or otherwise) to finance our growth strategy, we will have increased interest expense, which in turn will reduce the available cash that we have to distribute to our unitholders. Please read “Risk Factors — Risks Related to Our Business — Our existing and future debt level may limit our flexibility to obtain financing and to pursue other business opportunities.”

Our Minimum Quarterly Distribution

Upon the consummation of this offering, our partnership agreement will provide for a minimum quarterly distribution of $ per unit for each whole quarter, or $ per unit on an annualized basis. Our ability to make cash distributions at the minimum quarterly distribution rate will be subject to the factors described above under “Cash Distribution Policy and Restrictions on Distributions — General — Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.” Quarterly distributions, if any, will be made within 45 days after the end of each calendar quarter to holders of record on or about the first day of each such month in which such distributions are made. We will adjust the amount of our first distribution for the period from the closing of this offering through December 31, 2013, based on the actual length of the period.

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The amount of available cash needed to pay the minimum quarterly distribution on all of our common units and subordinated units to be outstanding immediately after this offering for one quarter and on an annualized basis (assuming no exercise and full exercise of the underwriters’ option to purchase additional common units) is summarized in the table below:

No Exercise of Option to Purchase
Additional Common Units

Full Exercise of Option to Purchase
Additional Common Units

Aggregate Minimum
Quarterly Distributions

Number of
Units

One
Quarter

Annualized
(Four
Quarters)

Number of
Units

One
Quarter

Annualized
(Four
Quarters)

(in millions)

Publicly held common units

Common units held by Cypress Holdings and its affiliates and Cypress Energy Partners — TIR, LLC

Subordinated units held by Cypress Holdings and its affiliates and Cypress Energy Partners — TIR, LLC

LTIP participants common units

Total

Our general partner will initially hold all of the incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 50.0%, of the cash we distribute in excess of $ per unit per quarter.

During the subordination period, before we make any quarterly distributions to our subordinated unitholders, our common unitholders are entitled to receive payment of the full minimum quarterly distribution for such quarter plus any arrearages in distributions of the minimum quarterly distribution from prior quarters. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — Subordinated Units and Subordination Period.” We cannot guarantee, however, that we will pay distributions on our common units at our minimum quarterly distribution rate or at any other rate in any quarter.

Although holders of our common units may pursue judicial action to enforce provisions of our partnership agreement, including those related to requirements to make cash distributions as described above, our partnership agreement provides that any determination made by our general partner in its capacity as our general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by the Delaware Act or any other law, rule or regulation or at equity. Our partnership agreement provides that, in order for a determination by our general partner to be made in “good faith,” our general partner must subjectively believe that the determination is in the best interests of our partnership. In making such determination, our general partner may take into account the totality of the circumstances or the totality of the relationships between the parties involved, including other relationships or transactions that may be particularly favorable or advantageous to us. Please read “Conflicts of Interest and Duties.”

The provision in our partnership agreement requiring us to distribute all of our available cash quarterly may not be modified without amending our partnership agreement; however, as described above, the actual amount of our cash distributions for any quarter is subject to fluctuations based on the amount of cash we generate from our business, the amount of reserves our general partner establishes in accordance with our partnership agreement and the amount of available cash from working capital borrowings.

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Additionally, our general partner may reduce the minimum quarterly distribution and the target distribution levels if legislation is enacted or modified that results in our becoming taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes. In such an event, the minimum quarterly distribution and the target distribution levels may be reduced proportionately by the percentage decrease in our available cash resulting from the estimated tax liability we would incur in the quarter in which such legislation is effective. The minimum quarterly distribution will also be proportionately adjusted in the event of any distribution, combination or subdivision of common units in accordance with the partnership agreement, or in the event of a distribution of available cash from capital surplus. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels.” The minimum quarterly distribution is also subject to adjustment if the holder(s) of the incentive distribution rights (initially only our general partner) elect to reset the target distribution levels related to the incentive distribution rights. In connection with any such reset, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution amount per common unit for the two quarters immediately preceding the reset. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — General Partner’s Right to Reset Incentive Distribution Levels.”

In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our annualized minimum quarterly distribution of $ per unit for the year ending December 31, 2014. In those sections, we present two tables, consisting of:

•

“Unaudited Pro Forma Distributable Cash Flow,” in which we present the amount of distributable cash flow we would have generated on a pro forma basis for the year ended December 31, 2012, and the twelve months ended September 30, 2013, derived from our unaudited pro forma condensed combined financial statements that are included in this prospectus, as adjusted to give pro forma effect to this offering and the related restructuring transactions; and

•

“Estimated Distributable Cash Flow for the Year Ending December 31, 2014,” in which we provide our estimated forecast of our ability to generate sufficient distributable cash flow to support the payment of the minimum quarterly distribution on all units for the year ending December 31, 2014.

Unaudited Pro Forma Distributable Cash Flow for the Year Ended December 31, 2012, and
the Twelve Months Ended September 30, 2013

If we had completed the transactions contemplated by this prospectus on January 1, 2012, our unaudited pro forma distributable cash flow generated for the year ended December 31, 2012 would have been approximately $10.2 million. This amount would have been sufficient to pay 100.0% of the aggregate minimum quarterly distribution on our common units during the period, and % of the aggregate minimum quarterly distribution on our subordinated units during that period.

If we had completed the transactions contemplated by this prospectus on October 1, 2012, our unaudited pro forma distributable cash flow generated for the twelve months ended September 30, 2013, would have been approximately $14.9 million. This amount would have been sufficient to pay 100.0% of the aggregate minimum quarterly distribution on our common units during that period, and % of the aggregate minimum quarterly distribution on our subordinated units during that period.

We based the pro forma adjustments upon currently available information and specific estimates and assumptions. The pro forma amounts below do not purport to present our results of operations had the transactions contemplated in this prospectus actually been completed as of the dates indicated. In addition, distributable cash flow is primarily a cash accounting concept, while our unaudited pro forma condensed combined financial statements have been prepared on an accrual basis. As a result, you should view the amount of pro forma distributable cash flow only as a general indication of the amount of distributable cash flow that we might have generated had we been formed in prior periods.

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The pro forma amounts described below are based on the following pro forma operating data for the periods indicated:

Cypress Energy Partners, L.P.
Pro Forma Operating Data


	Year Ended December 31, 2012		Twelve Months Ended September 30, 2013
Total barrels of saltwater disposed (in thousands)		10,962		18,679
Average revenue per barrel	$	1.34	$	1.16
Average number of inspectors		788		1,194
Average revenue per inspector, per week	$	4,542	$	4,689

The following table illustrates, on a pro forma basis, for the year ended December 31, 2012 and the twelve months ended September 30, 2013, the amount of cash that would have been available for distribution to our unitholders, assuming that this offering and the other restructuring transactions contemplated in this prospectus had been consummated at the beginning of each such period. The adjustments presented below give effect to this offering and the related transactions. The following table does not include the results of operations from Cypress Energy Services, LLC because prior to our acquisition of the business it was not operated for profit and incurred a number of expenses no longer associated with the business. In addition, the results of operations of Cypress Energy Services are immaterial to our business as a whole, on a historical basis. Certain of the adjustments are explained in further detail in the footnotes.

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Cypress Energy Partners, L.P.
Unaudited Pro Forma Distributable Cash Flow


	Year Ended December 31, 2012		Twelve Months Ended September 30, 2013
	(in thousands, except for per unit)
Revenues
Water and environmental services revenue	$	14,645	$	21,575
Pipeline inspection and integrity services revenue		185,988		291,058
Total revenues		200,633		312,633
Costs of sales and services
Costs of saltwater disposal sales		5,136		7,829
Costs of inspection services		167,957		263,695
Total costs of sales and services		173,093		271,524
Gross margin		27,540		41,109
Operating costs and expenses:
General and administrative expenses (1)		10,054		16,914
Depreciation and amortization expenses		3,124		5,292
Pro forma operating income		14,362		18,903
Interest expense, net (2)		4,001		4,630
Other income (expense), net (3)		45		4
Income before income taxes		10,406		14,277
Income tax expense		254		466
Pro forma net income		10,152		13,811
Less:
Pro forma net income attributable to non-controlling interests in TIR (4)		1,167		2,510
Pro forma net income attributable to Cypress Energy Partners, L.P.	$	8,985	$	11,301
Adjustments to reconcile pro forma net income attributable to Cypress Energy Partners, L.P. to pro forma Adjusted EBITDA attributable to Cypress Energy Partners, L.P. :
Add:
Depreciation and amortization expense attributable to controlling interests		2,191		4,412
Income tax expense attributable to controlling interests		127		253
Interest expense attributable to controlling interests (6)		1,017		888
Pro forma Adjusted EBITDA attributable to Cypress Energy Partners, L.P. (5)	$	12,320	$	16,854
Adjustments to reconcile pro forma Adjusted EBITDA attributable to Cypress Energy Partners, L.P. to pro forma distributable cash flow attributable to Cypress Energy Partners, L.P. :
Less:
Cash interest expense (6)		1,017		888
Cash taxes paid		127		253
Maintenance capital expenditures (7)		650		435
Expansion capital expenditures (7)		65,601		67,445
Incremental publicly traded partnership expenses (8)		1,345		1,336
Incremental interest expense cost associated with borrowings for expansion capital expenditures		—		74
Add:
Equity contribution for expansion capital expenditures (9)		65,601		65,601
Excess corporate overhead benefit (10)		1,035		1,036
Borrowings for expansion capital expenditures (11)		—		1,844
Pro forma distributable cash flow of Cypress Energy Partners, L.P.	$	10,216	$	14,904

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	Year Ended December 31, 2012	Twelve Months Ended September 30, 2013
	(in thousands, except for per unit)
Implied Cash Distribution at the Minimum Quarterly Distribution Rate:
Annualized minimum quarterly distribution per unit
Distributions to public common unitholders
Distributions to Cypress Holdings and affiliates – common units
Distributions to Cypress Holdings and affiliates – subordinated units
Distributions to LTIP participants
Total Distributions to Unitholders and General Partner
Excess (shortfall)
Percent of minimum quarterly distribution payable to common unitholders
Percent of minimum quarterly distribution payable to subordinated unitholders

(1)

For the year ended December 31, 2012 and the twelve months ended September 30, 2013, general and administrative expenses included $0.4 million and $1.6 million, respectively, attributable to our Water and Environmental Services segment, $7.6 million and $13.2 million, respectively, attributable to the Pipeline Inspection and Integrity Services segment and a $2.1 million annual administrative services fee payable to our general partner for the provision of certain corporate overhead expenses allocated to us by overhead Cypress Holdings. These general and administrative expenses amount excludes expenses related to the retention of an SWD well in Sheridan County, Montana and a related-party receivable and permit associated with the construction of a potential new facility and incremental expenses for being a publicly traded partnership that we estimate will be $2.0 million per year. Under our omnibus agreement our general partner will charge us an annual fixed fee of $3.0 million, which will include $2.0 million in incremental expenses that we expect to incur as a result of being a publicly traded partnership. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Operating Expenses — General and administrative” for a discussion of our obligation to pay for only up to $3.0 million of corporate overhead expenses plus the general and administrative expenses attributable to our two segments.

(2)

Reflects assumed interest expense, including the amortization of deferred financing costs, associated with our credit facilities. This amount includes an interest credit to us. The non-controlling interest holders in TIR will be charged a fee that will equal the interest expense TIR would have paid to incur $10 million in incremental borrowings under the mezzanine facilities to purchase the non-controlling interest holders’ interest in TIR. Pursuant to the omnibus agreement, we will reduce distributions to the non-controlling interest holders in TIR by $0.7 million, and we will record such reduced interest payment as a credit against our interest expense. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Our Credit Facilities” and Note 2 to our unaudited pro forma condensed combined financial statements included elsewhere in this prospectus.

(3)

Excludes $11.25 million in other income in the twelve months ended September 30, 2013 associated with gain on the reversal of contingent consideration. The gain resulted from our determination that no contingent consideration would be earned or paid to SBG Energy Services, LLC in connection with our acquisition of assets from that entity on December 2012.

(4)

Represents net income attributable to the non-controlling holders’ 49.9% indirect ownership interest in TIR.

(5)

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(6)

Reflects payment by non-controlling interest holders in TIR of the interest credit, discussed in note (2) above.

(7)

Historically, we have not made a distinction between maintenance capital expenditures and expansion capital expenditures. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — Capital Expenditures.” Reflects expansion capital expenditures of $65.6 million for the acquisitions of the SBG Predecessor and certain SWD facilities from Moxie Disposal Systems, LLC and Peach Energy Services, LLC for the year ended December 31, 2012.

(8)

Reflects the $2.0 million of incremental general and administrative expenses attributable to operating as a publicly traded partnership. Pursuant to the omnibus agreement, we will be responsible for $1.3 million of these incremental expenses for the year ended December 31, 2012 and the twelve months ended September 30, 2013, with the remainder allocated to the owners of the 49.9% non-controlling interest in TIR based on the relative gross margin allocation of our two segments.

(9)

Reflects $65.6 million for the acquisitions of the SBG Predecessor and certain SWD facilities from Moxie Disposal Systems, LLC and Peach Energy Services, LLC for the year ended December 31, 2012.

(10)

Reflects the portion of corporate overhead expenses for which the general partner will be responsible pursuant to the omnibus agreement. For the year ended December 31, 2012 and September 30, 2013, corporate overhead expenses were $2.0 million and $2.0 million, respectively, which amounts would have been reduced to $1.0 million for each period pursuant to the omnibus agreement.

(11)

Reflects amounts financed by operating cash flows historically but that would have been financed by borrowings under our mezzanine facilities.

Estimated Distributable Cash Flow for the Year Ending December 31, 2014

We forecast that our estimated cash available for distribution for the year ending December 31, 2014 will be approximately $20.6 million. This amount would exceed by $ million the amount needed to pay the total annualized minimum quarterly distribution of $ million on all of our common and subordinated units for the year ending December 31, 2014.

We do not, as a matter of course, make public projections as to future operations, earnings or other results. However, management has prepared the forecast of estimated cash available for distribution and related assumptions and considerations set forth below to substantiate our belief that we will have sufficient cash available for distribution to allow us to pay the total annualized minimum quarterly distribution on all of our outstanding common and subordinated units for the year ending December 31, 2014. This forecast is a forward-looking statement and should be read together with the historical and pro forma condensed combined financial statements and the accompanying notes included elsewhere in this prospectus, as well as “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The accompanying prospective financial information was not prepared with a view toward complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, is substantially consistent with those guidelines and was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the assumptions on which we base our belief that we can generate the minimum estimated cash available for distribution necessary to pay the total annualized minimum quarterly distribution on all of our outstanding common and subordinated units for the year ending December 31, 2014. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.

The prospective financial information included in this prospectus has been prepared by, and is the responsibility of, our management. Neither our independent auditors, nor any other independent registered public accounting firms, have examined, compiled nor performed any procedures with respect to the accompanying prospective financial information and, accordingly,

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neither our independent registered public accounting firm, nor any other independent registered public accounting firms, express an opinion or any other form of assurance with respect thereto. The reports of our independent auditors included in this prospectus relate to the CEP Successor and the SBG Predecessor’s historical financial information. It does not extend to the prospective financial information and should not be read to do so.

When considering our financial forecast, you should keep in mind the risk factors and other cautionary statements under “Risk Factors.” Any of the risks discussed in this prospectus, to the extent they are realized, could cause our actual results of operations to vary significantly from those that would enable us to generate the minimum estimated cash available for distribution necessary to pay the total annualized minimum quarterly distribution on all of our outstanding common and subordinated units for the year ending December 31, 2014. We are providing the forecast of estimated cash available for distribution and related assumptions set forth below to supplement the historical and pro forma condensed combined financial statements in support of our expectation that we will have sufficient cash available for distribution to allow us to pay the total annualized minimum quarterly distribution on all of our outstanding common and subordinated units for the year ending December 31, 2014. Please read below under “Cash Distribution Policy and Restriction on Distributions — Assumptions and Considerations” for further information as to the assumptions we have made for the financial forecast.

We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast to reflect events or circumstances after the date of this prospectus. Therefore, the statement that we believe that we will have sufficient cash available for distribution to allow us to pay the total annualized minimum quarterly distribution on all of our outstanding common and subordinated units for the year ending December 31, 2014, should not be regarded as a representation by us, the underwriters or any other person that we will make such distributions. Therefore, you are cautioned not to place undue reliance on this information.

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Cypress Energy Partners, L.P.
Estimated Distributable Cash Flow



	Forecasted
	Three Months Ending								Year Ending
	March 31, 2014		June 30, 2014		September 30, 2014		December 31, 2014		December 31, 2014
	(in thousands, except for operational and per unit data)

Total barrels of saltwater disposed (in thousands)		5,421		5,672		5,820		5,850		22,763
Average revenue per barrel	$	1.11	$	1.09	$	1.07	$	1.05	$	1.08
Average number of inspectors		1,106		1,337		1,554		1,428		1,356
Average revenue per inspector (per week)	$	4,648	$	4,753	$	4,936	$	4,892	$	4,821
Revenues
Water and environmental services revenue	$	5,992	$	6,166	$	6,245	$	6,137	$	24,540
Pipeline inspection and integrity services revenue		66,809		82,595		99,702		90,845		339,951
Total revenues		72,801		88,761		105,947		96,982		364,491
Costs of sales and services
Costs of saltwater disposal sales		1,655		1,876		1,645		1,634		6,810
Costs of inspection services		60,847		74,654		90,162		81,988		307,651
Total costs of sales and services		62,502		76,530		91,807		83,622		314,461
Gross margin		10,299		12,231		14,140		13,360		50,030
Operating costs and expenses:
General and administrative expenses (1)	$	4,247	$	4,263	$	4,268	$	4,269	$	17,047
Depreciation and amortization expenses		1,491		1,491		1,491		1,489		5,962
Operating income		4,561		6,477		8,381		7,602		27,021
Interest expense, net		942		1,050		1,135		1,097		4,224
Other income, net		51		50		48		46		195
Income before income taxes		3,670		5,477		7,294		6,551		22,992
Income tax expense		54		145		327		324		850
Net income	$	3,616	$	5,332	$	6,967	$	6,227	$	22,142
Less:
Net income attributable to non-controlling interests in TIR and CES (2)		487		1,423		2,135		1,827		5,872
Net income attributable to Cypress Energy Partners, L.P.	$	3,129	$	3,909	$	4,832	$	4,400	$	16,270
Adjustments to reconcile net income attributable to Cypress Energy Partners, L.P. to estimated Adjusted EBITDA attributable to Cypress Energy Partners, L.P. (3):
Add:
Depreciation and amortization attributable to controlling interests		1,254		1,255		1,255		1,254		5,018
Income tax expense attributable to controlling interests		34		80		171		170		455
Interest expense attributable to controlling interest (4)		279		345		384		362		1,370
Estimated Adjusted EBITDA attributable to Cypress Energy Partners, L.P.	$	4,696	$	5,589	$	6,642	$	6,186	$	23,113

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	Forecasted
	Three Months Ending								Year Ending
	March 31, 2014		June 30, 2014		September 30, 2014		December 31, 2014		December 31, 2014
	(in thousands, except for operational and per unit data)
Adjustments to reconcile estimated Adjusted EBITDA attributable to Cypress Energy Partners, L.P. to estimated distributable cash flow attributable to Cypress Energy Partners, L.P.
Less:
Cash interest expense (4)		279		345		384		362		1,370
Cash taxes paid		34		80		171		170		455
Maintenance capital expenditures (5)		175		175		175		175		700
Expansion capital expenditures		—		—		—		—		—
Add:
Borrowings for expansion capital expenditures		—		—		—		—		—
Estimated distributable cash flow of Cypress Energy Partners, L.P.	$	4,208	$	4,989	$	5,912	$	5,479	$	20,588
Implied Cash Distribution at the Minimum Quarterly Distribution Rate:
Annualized minimum quarterly distribution per unit
Distributions to public common unitholders
Distributions to Cypress Holdings and affiliates – common units
Distributions to Cypress Holdings and affiliates – subordinated units
Distributions to LTIP participants
Total Distributions to Unitholders and General Partner
Excess of distributable cash flow attributable to controlling interests over total annualized minimum quarterly distributions

(1)

For the year ending December 31, 2014, general and administrative expenses will include $1.6 million attributable to the Water and Environmental Services segment, $12.4 million attributable to the Pipeline Inspection and Integrity Services segment and a $3.0 million annual administrative fee payable to our general partner for the provision of certain corporate overhead expenses allocated to us by Cypress Holdings. Pursuant to the omnibus agreement, this $3.0 million includes $2.0 million in estimated annual cash expense we expect to incur as a result of being 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. Pursuant to the omnibus agreement, $0.6 million of this corporate overhead expense attributed to our operating as a publicly traded partnership will be allocated to the owners of the 49.9% non-controlling interest in TIR based on the relative gross margin contribution of our two segments.

(2)

Represents net income attributable to the 49.9% non-controlling holders’ ownership interest in TIR and 49.0% non-controlling ownership interest in CES.

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(3)

For a definition of Adjusted EBITDA, a reconciliation of Adjusted EBITDA to net income and to net cash provided by (used in) operating activities and a reconciliation of Adjusted EBITDA attributable to Cypress Energy Partners, L.P. to net income attributable to Cypress Energy Partners, L.P., please read “Selected Historical and Pro Forma Condensed Combined Financial Data — Non-GAAP Financial Measures.”

(4)

Reflects assumed interest expense, including the amortization of deferred financing costs associated with our credit facilities. This amount includes an incremental interest charge payable to us. The non-controlling interest holders in TIR will be charged a fee that will equal the interest expense TIR would have paid on its pro forma indebtedness prior to this offering. Pursuant to the omnibus agreement, we will reduce distributions to the non-controlling interest holders in TIR by $0.7 million, and we will record such reduced interest payment as a credit against our interest expense. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Our Credit Facilities” and Note 2 to our unaudited pro forma condensed combined financial statements included elsewhere in this prospectus.

(5)

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Assumptions and Considerations

The forecast has been prepared by and is the responsibility of our management. Our forecast reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take during the year ending December 31, 2014. Our forecast assumes that our margins during the forecast period will increase at a rate consistent with historical margins generated during the year ended December 31, 2012 and the twelve months ended September 30, 2013. While the assumptions disclosed in this prospectus are not all-inclusive, the assumptions listed are those that we believe are significant to our forecasted results of operations. We believe we have a reasonable objective basis for these assumptions. We believe our actual results of operations will approximate those reflected in our forecast, but we can give no assurance that our forecasted results will be achieved. There will likely be differences between our forecast and the actual results, and those differences could be material. If the forecast is not achieved, we may not be able to pay cash distributions on our common units at the minimum distribution rate or at all.

Water and Environmental Services Revenue

We forecast that our total saltwater disposal revenues for the year ending December 31, 2014 will be approximately $24.5 million, as compared to approximately $14.6 million and $21.6 million, in each case on a pro forma basis, for the year ended December 31, 2012 and the twelve months ended September 30, 2013, respectively. Our forecast is based primarily on the following assumptions:

•

We forecast total barrels of saltwater disposed to be 22.8 million for the year ending December 31, 2014, as compared to the 17.0 million barrels for the year ended December 31, 2012 and 18.7 million barrels for the twelve months ended September 30, 2013 on a pro forma basis assuming all of our SWD facilities had been operating from the beginning of each of these periods, calculated by annualizing their actual disposal volumes during prior periods. The anticipated increase in volumes will be primarily due to recent sales efforts, including the completion of arrangements for piped water to increase volumes from existing customers in the Bakken and Permian regions.

•

We forecast revenue per barrel of saltwater disposed to be approximately $1.08 for the year ending December 31, 2014, as compared to approximately $1.34 for the year ended December 31, 2012 and approximately $1.16 for the twelve months ended September 30, 2013, in each case on a pro forma basis. We expect competition in the saltwater disposal industry to increase in the Bakken and Permian regions, and in turn to incur pricing pressures to maintain existing volumes or compete for incremental volumes. The forecasted revenue per barrel decrease is also attributable to an increasing percentage of our disposed water being produced water, which can have a lower per barrel disposal price in some markets, including the Bakken region. We forecast that produced water revenues will increase more than 22% for the year ending December 31, 2014 compared to the twelve months ended September 30, 2013, while flowback water revenues will decrease approximately 22% during the same periods. In the Permian region, we are not experiencing, and do not forecast, differential pricing between flowback and produced water.

•

We forecast revenue from CES for managing third-party SWD facilities for the year ending December 31, 2014, which contributes to the increase in revenues in the forecast period. We had no such revenues for the year ended December 31, 2012, as we began managing third-party SWD facilities in 2013. In addition, we generate revenue from the sale of residual oil recovered during the saltwater treatment process. For the twelve months ended September 30, 2013, our revenue from sales of residual oil was approximately 25% of total revenue in our Water and Environmental Services segment. We forecast this percentage of revenues from the sale of residual oil for the year ending December 31, 2014 will be consistent with this historical period.

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Pipeline Inspection and Integrity Services Revenue

We forecast that our revenue for the year ending December 31, 2014 will be approximately $340.0 million, as compared to approximately $186.0 million and $291.1 million for the year ended December 31, 2012 and the twelve months ended September 30, 2013, respectively. Our revenue forecast is based primarily on the following assumptions:

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We estimate that we will employ an average of 1,356 inspectors during the year ending December 31, 2014, as compared with 788 and 1,194 for the year ended December 31, 2012 and twelve months ended September 30, 2013, respectively. This increase in employed inspectors is expected to result from continuing the 2013 market share growth we have recently experienced with our largest customer, while also employing additional inspectors with new and existing customers. We employed 1,604 inspectors as of September 30, 2013.

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We estimate that our average weekly revenue per inspector will be approximately $4,821 during the year ending December 31, 2014, compared to $4,542 and $4,689 for the year ended December 31, 2012 and the twelve months ended September 30, 2013, respectively. We have applied our historical average profit margin markup to the forecast period.

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Our largest customer is expected to employ an average of approximately 388 inspectors, or approximately 29% of our total inspector headcount, during the year ending December 31, 2014, compared to an average of approximately 148, or approximately 19% of total inspector headcount, and 293, or approximately 25% of the total inspector headcount, for the year ended December 31, 2012 and the twelve months ended September 30, 2013, respectively. This expected growth results from the customer’s decision to consolidate their inspection vendors to a core group of preferred suppliers. We already have experienced a meaningful increase in our number of inspectors serving this customer as a result of this business decision. Our forecast reflects our expectation that this customer will continue to utilize the number of inspectors it currently utilizes from us.

Cost of Saltwater Disposal Sales

We forecast that our cost of sales will be approximately $6.8 million for the year ending December 31, 2014, as compared to approximately $5.1 million for the year ended December 31, 2012 and approximately $7.8 million for the twelve months ended September 30, 2013. Cost of sales relates to the saltwater disposal segment and primarily includes the cost of labor and benefits, repairs and maintenance, utilities and residual oil expenses. The increase in cost of sales for the forecasted period as compared to the pro forma year ended December 31, 2012, is attributable to the addition of four wells acquired on December 4, 2012 and increasing volumes at several SWD wells. The decrease in cost of sales for the forecasted period as compared to the pro forma twelve months ended September 30, 2013 is primarily attributable to facility improvements and repairs in relation to added SWD facilities that occurred in the first six months of 2013.

Cost of Inspection Services

We forecast our cost of services will be approximately $307.7 million, or 90.5% of service revenue, for the year ending December 31, 2014, as compared with $168.0 million, or 90.3% of service revenue and $263.7 million, or 90.6% of service revenue, for the year ended December 31, 2012 and the twelve months ended September 30, 2013, respectively. Cost of services primarily includes the payroll and payroll related costs of our inspectors including wages, employer taxes, workers compensation costs and reimbursements paid to the inspectors including per diem, mileage and with other reimbursement items. Cost of services also includes certain third-party inspector safety and training costs that are directly related to qualifying our inspectors to work on specific job assignments along with other minor costs directly associated with the employment of our inspectors.

Our cost of services, as a percentage of service revenue, differs for each customer as each inspector pay structure and profit margin markup is different. Changes in cost of services, as a percentage of service revenue, typically result from a change in the customer mix of quantity of inspectors employed. In addition, cost of services, as a percentage of service revenues, can also be

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impacted from the varying activity of inspectors that are paid on an hourly or daily basis, as our profit margin markup is only tied to their work hours. The percentage can also be impacted by the volume of expense reimbursements our inspectors receive as these items are typically passed on to the customer without a profit margin markup and could be in excess of 35.0% of our total revenues.

Depreciation and Amortization

We forecast depreciation and amortization expense to be approximately $6.1 million (inclusive of $0.1 million included in costs of inspection services) for the year ending December 31, 2014, as compared to approximately $3.2 million (inclusive of $0.1 million included in cost of inspection services) for the year ended December 31, 2012 and approximately $5.4 million (inclusive of $0.1 million included in cost of inspection services) for the twelve months ended September 30, 2013, in each case on a pro forma basis. The increase in depreciation and amortization expense is primarily a result of the additional SWD facilities owned and depreciated during the forecast period, compared to the number of SWD facilities we owned and depreciated during the year ended December 31, 2012 and the twelve months ended September 30, 2013.

General and Administrative

We forecast general and administrative expenses to be approximately $17.0 million for the year ending December 31, 2014, as compared to approximately $10.1 million for the year ended December 31, 2012, and approximately $16.9 million for the twelve months ended September 30, 2013. The forecasted general and administrative expenses are comprised of $1.6 million attributable to our Water and Environmental Services segment (which relate to royalty expenses, management fees, legal fees and other expenses for operation of our SWD wells), $12.4 million attributable to our Pipeline Inspection and Integrity Services segment and a $3.0 million annual administrative fee that will be charged to us by our general partner for the provision of certain corporate overhead expenses. This fee includes the $2.0 million of incremental general and administrative expenses we expect to incur as a result of operating as a publicly traded partnership. Pursuant to the omnibus agreement, $0.6 million of the corporate overhead expense attributable to our operating as a publicly traded partnership will be allocated to the owners of the 49.9% non-controlling interest in TIR based on a relative gross margin allocation of our two segments.

We estimate the corporate overhead expenses, including the $2.0 million of incremental expenses attributable to operating as a publicly traded partnership would have been $ , though this amount will be fixed at $3.0 million pursuant to the omnibus agreement for the year ending December 31, 2014.

Interest Expense

We forecast interest expense of approximately $4.2 million for the year ending December 31, 2014, as compared to approximately $4.0 million for the year ended December 31, 2012 and approximately $4.6 million for the twelve months ended September 30, 2013, in each case on a pro forma basis. A 100 basis point change in the interest rate on each facility would increase our interest expense by $0.5 million. This interest rate also includes an interest credit to us. The non-controlling interest holders in TIR will be charged a fee that will equal the interest expense TIR would have paid to incur $10 million incremental borrowings under the mezzanine facilities to purchase interests held by minority holders in TIR Parent. Pursuant to the omnibus agreement, we will reduce distributions to the non-controlling interest holders in TIR by $0.7 million, and we will record such reduced interest payment as a credit against our interest expense.

Capital Expenditures

We estimate that total capital expenditures for the year ending December 31, 2014 will be $0.7 million, compared to $66.3 million and $67.9 million for the year ended December 31, 2012 and the twelve months ended September 30, 2013, respectively. Our estimate is based on the following assumptions:

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We estimate that maintenance capital expenditures for the year ending December 31, 2014 will total $0.7 million. This compares to $0.7 million for the year ended December 31, 2012 and $0.4 million for the twelve months ended September 30, 2013, respectively. The $0.7 million in estimated maintenance capital expenditures consists of $0.3 million in repairs to mechanical equipment related to operation of the SWD wells and various replacement equipment for our Pipeline and Integrity Services segment expected to be incurred during the forecast period as well as $0.4 million for maintenance capital expenditures on certain of our assets that will need extensive repairs during their useful lives after the forecast period.

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Although we may make acquisitions in the future, we currently have no budgeted expansion capital expenditures related to acquisitions for the year ending December 31, 2014, as we cannot be certain that we will be able to identify attractive acquisition opportunities or, if identified, that we will be able to negotiate acceptable purchase agreements. Our expansion capital expenditures were $65.6 million and $67.4 million for the year ended December 31, 2012 and the twelve months ended September 30, 2013, respectively.

Financing

Our pro forma financial data and our forecast assumes that TIR will assume, as borrower, the following credit facilities as of the closing date:

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$50 million factoring facility, which bears interest at LIBOR plus 4.00%; and

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mezzanine facilities, which bear interest at a blended rate of 14.69%, and which we intend to amend at the closing of this offering to upsize the facilities to $ million, which will allow for an incremental $ million in borrowings to support future growth, none of which excess availability will be drawn during the forecast period.

Regulatory, Industry, Environmental and Economic Factors

Our forecast for the year ending December 31, 2014 is based on the following significant assumptions related to regulatory, industry, environmental and economic factors:

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No new federal, state or local regulation of the saltwater disposal industry, and no new interpretation of existing regulations, that will be materially adverse to our business.

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Continued federal regulatory focus on operators of gathering, transmission and distribution pipelines.

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Continued progress by the pipeline industry to expand existing infrastructure to reach new production areas and new customer locations.

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No loss of significant customers or market share with top customers.

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No new competition entering the market with reduced pricing which would pressure us to change our profit margin markups within our master service agreements with our pipeline inspection and integrity customers.

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No increased payroll costs associated with employer taxes, benefit costs, including the effects of the recent Patient Protection and Affordable Care Act, workers compensation insurance, or other employment cost increases that would impact our gross profit dollars and percentages.

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No major adverse change in the saltwater disposal industry or the pipeline inspection and integrity industry, or in market, insurance or general economic conditions.

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No major adverse environmental, fires, natural disasters, loss of power, vandalism or material issues with our pumps, well bores or storage facilities.

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PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

Distributions of Available Cash

General

Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending December 31, 2013, we distribute all of our available cash to unitholders of record on the applicable record date. We will adjust the amount of our distribution for the period from the completion of this offering through December 31, 2013, based on the actual length of the period.

Definition of Available Cash

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

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less, the amount of cash reserves established by our general partner to:

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provide for the proper conduct of our business (including, but not limited to, reserves for our future capital expenditures, future acquisitions and anticipated future debt service requirements);

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comply with applicable law, any of our or our subsidiaries’ debt instruments or other agreements; or

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provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for distributions if the effect of the establishment of such reserves will prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter);

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plus, if our general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter.

The purpose and effect of the last bullet point above is to allow our general partner, if it so decides, to use cash from working capital borrowings made after the end of the quarter but on or before the date of determination of available cash for that quarter to pay distributions to unitholders. Under our partnership agreement, working capital borrowings are generally borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners and with the intent of the borrower to repay such borrowings within twelve months with funds other than from additional working capital borrowings.

Intent to Distribute the Minimum Quarterly Distribution

Under our current cash distribution policy, we intend to make a minimum quarterly distribution to the holders of our common units and subordinated units of $ per unit, or $ per unit on an annualized basis, to the extent we have sufficient available cash after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to our general partner. However, there is no guarantee that we will pay the minimum quarterly distribution on our units in any quarter. The amount of distributions paid under our cash distribution policy and the decision to make any distribution will be determined by our general partner, taking into consideration the terms of our partnership agreement. Please read “Management’s Discussion and Analysis of Financial Condition and

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Results of Operations — Liquidity and Capital Resources — Our Credit Facilities” for a discussion of the restrictions included in our credit facilities that may restrict our ability to make distributions.

General Partner Interest and Incentive Distribution Rights

Our general partner will own a 0.0% non-economic partner interest in us.

Our general partner will hold incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50.0%, of the available cash we distribute from operating surplus (as defined below) in excess of $ per unit per quarter. The aggregate maximum distribution of 50.0% does not include any distributions that our general partner or its affiliates may receive on common or subordinated units that they own. Please read “— General Partner Interest and Incentive Distribution Rights” for additional information.

Operating Surplus and Capital Surplus

General

All cash distributed to unitholders will be characterized as either being paid from “operating surplus” or “capital surplus.” We treat distributions of available cash from operating surplus differently than distributions of available cash from capital surplus.

Operating Surplus

We define operating surplus as:

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$ million (as described below); plus

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all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions (as defined below), provided that cash receipts from the termination of a commodity hedge or interest rate hedge prior to its specified termination date shall be included in operating surplus in equal quarterly installments over the remaining scheduled life of such commodity hedge or interest rate hedge; plus

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working capital borrowings made after the end of a quarter but on or before the date of determination of operating surplus for that quarter; plus

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cash distributions (including incremental distributions on incentive distribution rights) paid in respect of equity issued, other than equity issued in this offering, 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 or expansion of a capital asset and ending on the earlier to occur of the date the capital asset commences commercial service and the date that it is abandoned or disposed of; less

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all of our operating expenditures (as defined below) after the closing of this offering; less

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the amount of cash reserves established by our general partner to provide funds for future operating expenditures; less

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all working capital borrowings not repaid within twelve months after having been incurred, or repaid within such 12-month period with the proceeds of additional working capital borrowings.

As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders and is not limited to cash generated by operations. For example, it includes a provision that will enable us, if we choose, to distribute as operating surplus up to $ million of cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including, as described above, certain cash distributions on

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equity interests in operating surplus will be to increase operating surplus by the amount of any such cash distributions. As a result, we may also distribute as operating surplus up to the amount of any such cash that we receive from non-operating sources.

The proceeds of working capital borrowings increase operating surplus and repayments of working capital borrowings are generally operating expenditures (as described below) and thus reduce operating surplus when repayments are made. However, if working capital borrowings, which increase operating surplus, are not repaid during the twelve-month period following the borrowing, they will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowings are in fact repaid, they will not be treated as a further reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.

We define interim capital transactions as (1) borrowings, refinancings or refundings of indebtedness (other than working capital borrowings, like those under our factoring facility and items purchased on open account or for a deferred purchase price in the ordinary course of business) and sales of debt securities, (2) sales of equity securities, and (3) sales or other dispositions of assets, other than sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business and sales or other dispositions of assets as part of normal asset retirements or replacements.

We define operating expenditures as all of our cash expenditures, including, but not limited to, taxes, reimbursements of expenses of our general partner and its affiliates, officer, director and employee compensation, debt service payments, payments made in the ordinary course of business under interest rate hedge contracts and commodity hedge contracts (provided that payments made in connection with the termination of any interest rate hedge contract or commodity hedge contract prior to the expiration of its settlement or termination date specified therein will be included in operating expenditures in equal quarterly installments over the remaining scheduled life of such interest rate hedge contract or commodity hedge contract and amounts paid in connection with the initial purchase of a rate hedge contract or a commodity hedge contract will be amortized over the life of such rate hedge contract or commodity hedge contract), maintenance capital expenditures (as discussed in further detail below), and repayment of working capital borrowings; provided, however, that operating expenditures will not include:

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repayments of working capital borrowings where such borrowings have previously been deemed to have been repaid (as described above);

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payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness other than working capital borrowings;

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expansion capital expenditures;

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payment of transaction expenses (including taxes) relating to interim capital transactions;

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distributions to our partners;

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repurchases of partnership interests (excluding repurchases we make to satisfy obligations under employee benefit plans); or

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any other expenditures or payments using the proceeds of this offering that are described in “Use of Proceeds.”

Capital Surplus

Capital surplus is defined in our partnership agreement as any distribution of available cash in excess of our cumulative operating surplus. Accordingly, except as described above, capital surplus would generally be generated by:

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borrowings other than working capital borrowings;

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sales of our equity and debt securities;

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sales or other dispositions of assets, other than inventory, accounts receivable and other assets sold in the ordinary course of business or as part of ordinary course retirement or replacement of assets; and

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capital contributions received.

Characterization of Cash Distributions

All available cash distributed by us on any date from any source will be treated as distributed from operating surplus until the sum of all available cash distributed by us since the closing of this offering equals the operating surplus from the closing of this offering through the end of the quarter immediately preceding that distribution. As described above, operating surplus, as defined in our partnership agreement, includes certain components, including a $ million cash basket, that represent non-operating sources of cash. Any available cash distributed by us in excess of our cumulative operating surplus will be deemed to be capital surplus under our partnership agreement. Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering. We do not anticipate that we will make any distributions from capital surplus.

Capital Expenditures

We distinguish between maintenance capital expenditures and expansion capital expenditures. Maintenance capital expenditures are cash expenditures (including expenditures for the construction or development of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain, over the long-term, our operating capacity or operating income. Maintenance capital expenditures do not include normal repairs and maintenance, which are expensed as incurred, or significant replacement capital expenditures, as described in detail in the next paragraph. Examples of maintenance capital expenditures are expenditures to refurbish and replace pumps, tubing, packers, pipelines and storage facilities to extend the life of the assets and to address environmental laws and regulations. These expenditures are capitalized and depreciated over their estimated useful life. Given the nature of our business, we expect that our maintenance capital expenditures will be reasonably predictable in the near-term, and we do not expect the amount of our actual maintenance capital expenditures to differ substantially from period to period. However, in the long-term, because our maintenance capital expenditures can be irregular, the amount of our actual maintenance capital expenditures may increase significantly when our SWD facilities will require scheduled maintenance, which could cause similar fluctuations in the amounts of operating surplus, adjusted operating surplus and cash available for distribution to our unitholders. Our general partner has determined to set aside cash for future maintenance capital expenditures on certain of our assets that will need extensive repairs during their useful lives, which we anticipate will total $0.7 million during the year ending December 31, 2014.

Expansion capital expenditures are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating capacity or operating income over the long-term. Examples of expansion capital expenditures include the acquisition of equipment, or the construction, development or acquisition of additional SWD facilities, well bores, pipeline, pumps, electrical capacity or storage capacity, to the extent such capital 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 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. Because expansion capital expenditures include interest payments (and related fees) on debt incurred to finance all or a portion of the construction of a capital asset in respect of a period that (l) begins when we enter into a binding obligation to commence construction of a capital improvement and (2) ends on the earlier to occur of the date any such capital asset

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commences commercial service and the date that it is abandoned or disposed of, such interest payments also do not reduce operating surplus. Capital expenditures that are made in part for maintenance capital purposes and in part for expansion capital purposes will be allocated as maintenance capital expenditures or expansion capital expenditures by our general partner.

Capital expenditures that are made in part for maintenance capital purposes and in part for expansion capital purposes will be allocated as maintenance capital expenditures or expansion capital expenditures by our general partner.

Subordinated Units and Subordination Period

General

Our partnership agreement provides that, during the subordination period (which we define below), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $ per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that, during the subordination period, there will be available cash to be distributed on the common units.

Determination of Subordination Period

Except as described below, the subordination period will begin on the closing date of this offering and will extend until the first business day following the distribution of available cash in respect of any quarter beginning after , 2016, that each of the following tests are met:

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distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded $ (the annualized minimum quarterly distribution), for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

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the adjusted operating surplus (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of $ (the annualized minimum quarterly distribution) on all of the outstanding common units and subordinated units during those periods on a fully diluted basis; and

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there are no arrearages in payment of the minimum quarterly distribution on the common units.

Early Termination of the Subordination Period

Notwithstanding the foregoing, the subordination period will automatically terminate on the first business day following the distribution of available cash in respect of any quarter, beginning with the quarter ending , 2014, that each of the following tests are met:

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distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded $ (150.0% of the annualized minimum quarterly distribution), plus the related distributions on the incentive distribution rights, for the four-quarter period immediately preceding that date;

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the adjusted operating surplus (as defined below) generated during the four-quarter period immediately preceding that date equaled or exceeded the sum of (1) $ (150.0% of the

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annualized minimum quarterly distribution) on all of the outstanding common units and subordinated units during that period on a fully diluted basis and (2) the corresponding distributions on the incentive distribution rights; and

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there are no arrearages in payment of the minimum quarterly distributions on the common units.

Expiration upon Removal of the General Partner

In addition, if the unitholders remove our general partner other than for cause:

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the subordinated units held by any person will immediately and automatically convert into common units on a one-for-one basis, provided (1) neither such person nor any of its affiliates voted any of its units in favor of the removal and (2) such person is not an affiliate of the successor general partner;

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if all of the subordinated units convert pursuant to the foregoing, all cumulative common unit arrearages on the common units will be extinguished and the subordination period will end; and

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our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.

Expiration of the Subordination Period

When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will thereafter participate pro rata with the other common units in distributions of available cash.

Adjusted Operating Surplus

Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net increase in working capital borrowings and net drawdowns of reserves of cash established in prior periods. Adjusted operating surplus for a period consists of:

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operating surplus generated with respect to that period (excluding any amounts attributable to the item described in the first bullet under the caption “— Operating Surplus and Capital Surplus — Operating surplus” above); less

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any net increase in working capital borrowings with respect to that period; less

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any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus

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any net decrease in working capital borrowings with respect to that period; plus

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any net decrease made in subsequent periods to cash reserves for operating expenditures initially established with respect to that period to the extent such decrease results in a reduction in adjusted operating surplus in subsequent periods; plus

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any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

Distributions of Available Cash From Operating Surplus During the Subordination Period

We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

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first, 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;

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second, 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;

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third, to the subordinated unitholders, pro rata, until we distribute for each outstanding subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

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thereafter, in the manner described in “— General Partner Interest and Incentive Distribution Rights” below.

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

Distributions of Available Cash From Operating Surplus After the Subordination Period

We will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

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first, to all unitholders, pro rata, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and

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thereafter, in the manner described in “— General Partner Interest and Incentive Distribution Rights” below.

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

General Partner Interest and Incentive Distribution Rights

Our partnership agreement provides that our general partner will own a 0.0% non-economic general partner interest in us, which does not entitle it to receive cash distributions. However, our general partner may in the future own common units or other equity interest in us and will be entitled to receive distributions on such interests.

Incentive distribution rights represent the right to receive an increasing percentage (15.0%, 25.0% and 50.0%) 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 our partnership agreement.

The following discussion assumes that that our general partner continues to own the incentive distribution rights and that we do not issue any additional classes of equity securities.

If for any quarter:

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we have distributed available cash from operating surplus to the common unitholders and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

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

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first, to all unitholders, pro rata, until each unitholder receives a total of $ per unit for that quarter (the “first target distribution”);

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second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives a total of $ per unit for that quarter (the “second target distribution”);

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third, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until each unitholder receives a total of $ per unit for that quarter (the “third target distribution”); and

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thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.

Percentage Allocations of Available Cash from Operating Surplus

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner, as the initial holder of our incentive distribution rights, based on the specified target distribution levels. The amounts set forth under “Marginal percentage interest in distributions” are the percentage interests of our unitholders and our general partner in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total quarterly distribution per unit target amount” until available cash we distribute reaches the next target distribution level, if any. The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below assume that there are no arrearages on common units.


	Total Quarterly Distribution per Unit Target Amount			Marginal Percentage Interest in Distributions
	Total Quarterly Distribution per Unit Target Amount			Unitholders			Incentive Distribution Rights
Minimum Quarterly Distribution		$			100.0	%		0.0	%
First Target Distribution		above $	up to $		100.0	%		0.0	%
Second Target Distribution		above $	up to $		85.0	%		15.0	%
Third Target Distribution		above $	up to $		75.0	%		25.0	%
Thereafter		above $			50.0	%		50.0	%

General Partner’s Right to Reset Incentive Distribution Levels

Our general partner, as the initial holder of our incentive distribution rights, has the right under our partnership agreement, subject to certain conditions, to elect to relinquish the right to receive incentive distribution payments based on the initial target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and target distribution levels upon which the incentive distribution payments to our general partner would be set. If our general partner transfers all or a portion of the incentive distribution rights in the future, then the holder or holders of a majority of our incentive distribution rights will be entitled to exercise this right. The following discussion assumes that our general partner holds all of the incentive distribution rights at the time that a reset election is made. Our general partner’s right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions payable to our general partner are based may be exercised, without approval of our unitholders or the conflicts committee, at any time when there are no subordinated units outstanding, we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distributions for each of the four consecutive fiscal quarters immediately preceding such time and the amount of each such distribution did not exceed adjusted operating surplus for such quarters. If our general partner and its affiliates are not the holders of a majority of the incentive distribution rights at the time an election is made to reset the minimum quarterly distribution amount and the target distribution levels, then the proposed reset will be subject to the prior written concurrence of the general partner that the conditions described above have been satisfied. The reset minimum quarterly distribution amount and target distribution levels will be higher than the minimum quarterly distribution amount and the target distribution levels prior to the reset such that our general partner will not receive any incentive distributions under the reset target distribution levels until cash distributions per unit following this event increase as described below. We anticipate that our general partner would exercise this reset right in order to facilitate

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acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made to our general partner.

In connection with the resetting of the minimum quarterly distribution amount and the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution payments based on the target distributions prior to the reset, our general partner will be entitled to receive a number of newly issued common units based on a predetermined formula described below that takes into account the “cash parity” value of the average cash distributions related to the incentive distribution rights received by our general partner for the two quarters immediately preceding the reset event as compared to the average cash distributions per common unit during that two-quarter period.

The number of common units that our general partner (or the then-holder of the incentive distribution rights, if other than our general partner) would be entitled to receive from us in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels then in effect would be equal to the quotient determined by dividing (x) the average aggregate amount of cash distributions received by our general partner in respect of its incentive distribution rights during the two consecutive fiscal quarters ended immediately prior to the date of such reset election by (y) the average of the aggregate amount of cash distributed per common unit during each of these two quarters.

Following a reset election, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (which amount we refer to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to be correspondingly higher such that we would distribute all of our available cash from operating surplus for each quarter thereafter as follows:

•

first, to all unitholders, pro rata, until each unitholder receives an amount equal to % of the reset minimum quarterly distribution for that quarter;

•

second, % to all unitholders, pro rata, and % to our general partner, until each unitholder receives an amount per unit equal to 125.0% of the reset minimum quarterly distribution for the quarter;

•

third, % to all unitholders, pro rata, and % to our general partner, until each unitholder receives an amount per unit equal to 150.0% of the reset minimum quarterly distribution for the quarter; and

•

thereafter, % to all unitholders, pro rata, and % to our general partner.

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner at various cash distribution levels (1) pursuant to the cash distribution provisions of our partnership agreement in effect at the completion of this offering, as well as (2) following a hypothetical reset of the minimum quarterly distribution and target distribution levels based on the assumption that the average quarterly cash distribution amount per common unit during the two fiscal quarters immediately preceding the reset election was $ .


	Quarterly Distribution per Unit Prior to Reset			Marginal percentage Interest in Distributions						Quarterly Distribution per Unit following Hypothetical Reset
	Quarterly Distribution per Unit Prior to Reset			Unitholders			Incentive Distribution Rights
Minimum Quarterly Distribution		$			100.0	%		0.0	%		$
First Target Distribution		above $	up to $		100.0	%		0.0	%		above $		up to $ (1	)
Second Target Distribution		above $	up to $		85.0	%		15.0	%		above $ (1	)	up to $ (2)

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	Quarterly Distribution per Unit Prior to Reset			Marginal percentage Interest in Distributions						Quarterly Distribution per Unit following Hypothetical Reset
	Quarterly Distribution per Unit Prior to Reset			Unitholders			Incentive Distribution Rights
Third Target Distribution		above $	up to $		75.0	%		25.0	%		above $ (2	)	up to $ (3	)
Thereafter		above $			50.0	%		50.0	%		above $ (3	)

(1)

This amount is % of the hypothetical reset minimum quarterly distribution.

(2)

This amount is % of the hypothetical reset minimum quarterly distribution.

(3)

This amount is % of the hypothetical reset minimum quarterly distribution.

The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and our general partner, including in respect of incentive distribution rights, based on an average of the amounts distributed for the two quarters immediately prior to the reset. The table assumes that immediately prior to the reset there would be common units outstanding and the average distribution to each common unit would be $ per quarter for the two consecutive non-overlapping quarters prior to the reset.

Quarterly Distribution per Unit Prior to Reset

Cash Distributions to Public Common Unitholders Prior to Reset

Cash Distribution to General Partner Prior to Reset

Total Distributions

Common Units

Incentive Distribution Rights

Total

Minimum Quarterly Distribution

First Target Distribution

above $

up to $

Second Target Distribution

above $

up to $

Third Target Distribution

above $

up to $

Thereafter

above $

The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and the general partner, including in respect of incentive distribution rights, with respect to the quarter after the reset occurs. The table reflects that, as a result of the reset, there would be common units outstanding and that the average distribution to each common unit would be $ . The number of common units issued as a result of the reset was calculated by dividing (x) as the average of the amounts received by the general partner in respect of its incentive distribution rights for the two consecutive non-overlapping quarters prior to the reset as shown in the table above, by (y) the average of the cash distributions made on each common unit per quarter for the two consecutive non-overlapping quarters prior to the reset as shown in the table above, or $ .

Quarterly Distribution per Unit after Reset

Cash Distributions to Public Common Unitholders after Reset

Cash Distribution to General Partner after Reset

Total Distributions

Common Units

Incentive Distribution Rights

Total

Minimum Quarterly Distribution

First Target Distribution

above $

up to $

Second Target Distribution

above $

up to $

Third Target Distribution

above $

up to $

Thereafter

above $

Our general partner will be entitled to cause the minimum quarterly distribution amount and the target distribution levels to be reset on more than one occasion, provided that it may not make a reset election except at a time when it has received incentive distributions for the immediately

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preceding four consecutive fiscal quarters based on the highest level of incentive distributions that it is entitled to receive under our partnership agreement.

Distributions from Capital Surplus

How Distributions from Capital Surplus will be Made

We will make distributions of available cash from capital surplus, if any, in the following manner:

•

first, to all unitholders, pro rata, until we distribute for each common unit that was issued in this offering, an amount of available cash from capital surplus equal to the initial public offering price in this offering;

•

second, to all unitholders, pro rata, until we distribute for each common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the outstanding common units; and

•

thereafter, as if they were from operating surplus.

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

Effect of a Distribution from Capital Surplus

Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the “unrecovered initial unit price.” Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution after any of these distributions are made, the effects of distributions of capital surplus may make it easier for our general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

Once we distribute capital surplus on a unit issued in this offering in an amount equal to the initial unit price, we will reduce the minimum quarterly distribution and the target distribution levels to zero. Then, after distributing an amount of capital surplus for each common unit equal to any unpaid arrearages of the minimum quarterly distributions on outstanding common units, we will then make all future distributions from operating surplus, with 50.0% being paid to the unitholders, pro rata and 50.0% to the holder of our incentive distribution rights.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, we will proportionately adjust:

•

the minimum quarterly distribution;

•

target distribution levels;

•

the unrecovered initial unit price; and

•

the arrearages per common unit in payment of the minimum quarterly distribution on the common units.

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50.0% of its initial level, and each subordinated unit would be split into two

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subordinated units. We will not make any adjustment by reason of the issuance of additional units for cash or property (including additional common units issued under any compensation or benefit plans).

In addition, if legislation is enacted or if the official interpretation of existing law is modified by a governmental authority, so that we become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels for each quarter may be reduced by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter (reduced by the amount of the estimated tax liability for such quarter payable by reason of such legislation or interpretation) and the denominator of which is the sum of available cash for that quarter (reduced by the amount of the estimated tax liability for such quarter payable by reason of such legislation or interpretation) plus our general partner’s estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference may be accounted for in subsequent quarters.

Distributions of Cash Upon Liquidation

General

If we dissolve in accordance with our partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and our general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of our general partner.

Manner of Adjustments for Gain

The manner of the adjustment for gain is set forth in our partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to our partners in the following manner:

•

first, to the common unitholders, pro rata, until the capital account for each common unit is equal to the sum of:

(1)

the unrecovered initial unit price;

(2)

the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and

(3)

any unpaid arrearages in payment of the minimum quarterly distribution;

•

second, to the subordinated unitholders, pro rata, until the capital account for each subordinated unit is equal to the sum of:

(1)

the unrecovered initial unit price; and

(2)

the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;

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•

third, to all unitholders, pro rata, until we allocate under this paragraph an amount per unit equal to:

(1)

the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less

(2)

the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed to the unitholders, pro rata, for each quarter of our existence;

•

fourth, % to all unitholders, pro rata, and % to our general partner, until we allocate under this paragraph an amount per unit equal to:

(1)

the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less

(2)

the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed % to the unitholders, pro rata, and % to our general partner for each quarter of our existence;

•

fifth, % to all unitholders, pro rata, and % to our general partner, until we allocate under this paragraph an amount per unit equal to:

(1)

the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less

(2)

the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that we distributed % to the unitholders, pro rata, and % to our general partner for each quarter of our existence; and

•

thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.

The percentages set forth above are based on the assumption that our general partner has not transferred its incentive distribution rights and that we do not issue additional classes of equity securities.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the fourth bullet point above will no longer be applicable.

Manner of Adjustments for Losses

If our liquidation occurs before the end of the subordination period, after making allocations of loss to the unitholders in a manner intended to offset in reverse order the allocations of gains that have previously been allocated, we will generally allocate any loss to our unitholders in the following manner:

•

first, to the holders of subordinated units in proportion to the positive balances in their capital accounts until the capital accounts of the subordinated unitholders have been reduced to zero; and

•

second, to the holders of common units in proportion to the positive balances in their capital accounts until the capital accounts of the common unitholders have been reduced to zero.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

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Adjustments to Capital Accounts

Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for tax purposes, unrecognized gain resulting from the adjustments to the unitholders in the same manner as we allocate gain upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we generally allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner that results, to the extent possible, in the partners’ capital account balances equaling the amount that they would have been if no earlier positive adjustments to the capital accounts had been made. In contrast to the allocations of gain, and except as provided above, we generally will allocate any unrealized and unrecognized loss resulting from the adjustments to capital accounts upon the issuance of additional units to the unitholders based on their respective percentage ownership of us. In this manner, prior to the end of the subordination period, we generally will allocate any such loss equally with respect to our common and subordinated units. If we make negative adjustments to the capital accounts as a result of such loss, future positive adjustments resulting from the issuance of additional units will be allocated in a manner designed to reverse the prior negative adjustments, and special allocations will be made upon liquidation in a manner that results, to the extent possible, in our unitholders’ capital account balances equaling the amounts they would have been if no earlier adjustments for loss had been made.

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SELECTED HISTORICAL AND PRO FORMA CONDENSED COMBINED FINANCIAL DATA

We were formed in September 2013 and do not have historical financial operating results. Therefore, in this prospectus, we present the historical financial statements and data of the SBG Predecessor, which consists of seven North Dakota limited liability companies that were formed in 2011 and 2012, and which we collectively refer to as our predecessor for financial accounting purposes, for the period from June 1, 2011 (Inception) through December 31, 2012. We also present historical financial statements and data of Cypress Energy Partners, LLC, which we refer to as our successor for financial accounting purposes, for the period from March 15, 2012 (Inception) through December 31, 2012 and for the nine months ended September 30, 2013.

Set forth below is the following financial data:

•

selected historical financial data as of December 31, 2011 and 2012 and for the period from June 1, 2011 (Inception) through December 31, 2011 and the year ended December 31, 2012 of the SBG Predecessor, which have been derived from the audited consolidated financial statements of the SBG Predecessor that are included elsewhere in this prospectus;

•

selected historical financial data as of December 31, 2012 and for the period from March 15, 2012 (Inception) through December 31, 2012 of the CEP Successor, which have been derived from the audited consolidated financial statements of the CEP Successor that are included elsewhere in this prospectus;

•

selected condensed unaudited historical financial data as of September 30, 2012 and for the nine months ended September 30, 2012 of the SBG Predecessor, which have been derived from the unaudited condensed consolidated financial statements of the SBG Predecessor that are included elsewhere in this prospectus;

•

selected condensed unaudited historical financial data as of September 30, 2013 and for the nine months ended September 30, 2013 of the CEP Successor, which have been derived from the unaudited condensed consolidated financial statements of the CEP Successor that are included elsewhere in this prospectus; and

•

We do not provide selected historical financial data for (i) TIR, in which we will receive a 50.1% interest at the closing of this offering, or in TIR Parent, (ii) the acquisition of the Moxie Assets prior to December 4, 2012. For historical financial data for the Moxie Assets for the period ended December 3, 2012, please read the audited “Statement of Revenues and Direct Operating Expenses of Assets Purchased by Cypress Energy Partners, LLC From Moxie Disposal Systems, LLC and Peach Energy Services, LLC from July 1, 2012 (Inception) through December 3, 2012” and the accompanying notes, which are included elsewhere in this prospectus. For historical financial data for TIR Parent for the years ended December 31, 2011 and 2012 and for the nine months ended September 30, 2012 and 2013, please read the audited and unaudited historical consolidated financial statements of TIR Parent and the accompanying notes, and Note 5 to Unaudited Pro Forma Condensed Combined Financial Statements, which are included elsewhere in this prospectus.

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These transactions include:

•

the retention by Cypress Holdings of the assets and liabilities associated with the CEP Successor's SWD facility in Sheridan County, Montana and a related-party receivable and permit associated with the construction of a potential new SWD facility;

•

the issuance by us of the incentive distribution rights to our general partner; and

•

The pro forma financial information does not include the results of operations from CES because prior to our acquisition of the business it was not operated for profit and incurred a number of expenses no longer associated with the business. In addition, the pro forma financial information does not include any incremental expenses for being a publicly traded partnership that we estimate will be $2.0 million per year. The pro forma financial information should not be considered as indicative of the historical results we would have had as a stand-alone partnership or the results we will have after this offering.

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The following table includes the non-GAAP financial measure Adjusted EBITDA. We define Adjusted EBITDA as our net income, plus interest expense, depreciation and amortization expense, income tax expense, and impairment loss related to an SWD facility retained by Cypress Holdings, less a gain on the reversal of a contingent liability related to the SBG acquisition. For reconciliations of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP, please read “— Non-GAAP Financial Measures.”


	SBG Predecessor									CEP Successor						Pro Forma Cypress Energy Partners, L.P.
	Period from June 1 (Inception) through December 31, 2011			Year Ended December 31, 2012			Nine Months Ended September 30, 2012			Period from March 15 (Inception) through December 31, 2012 (1)			Nine Months Ended September 30, 2013			Year Ended December 31, 2012		Nine Months Ended September 30, 2013
	(in thousands, except per unit and operational data)
Income Statement Data
Revenues	$	2,944		$	12,203		$	9,182		$	619		$	16,665		$	200,633	$	246,930
Gross margin		2,441			8,541			6,872			310			11,239			27,540		32,838
General and administrative expense		138			477			241			2,056			2,427			10,054		13,290
Impairment loss		—			—			—			—			4,375			—		—
Depreciation and amortization expense		123			1,398			839			99			3,066			3,124		4,173
Operating income (loss)		2,180			6,666			5,792			(1,845	)		1,371			14,362		15,375
Interest expense, net		35			111			82			—			—			4,001		3,266
Net income (loss)	$	2,162		$	6,595		$	5,746		$	(1,845	)	$	12,581		$	10,152	$	23,017
Less:
Net income (loss) attributable to non-controlling interests in TIR																$	1,167	$	2,109
Net income (loss) attributable to Cypress Energy Partners, L.P.																$	8,985	$	20,908
Basic earnings per common unit
Basic earnings per subordinated unit
Diluted earnings per common unit
Diluted earnings per subordinated unit
Balance Sheet Data Period End
Total assets	$	14,476		$	27,588		$	27,297		$	85,342		$	85,452
Total debt		2,798			2,314			2,395			—			—
Membership/Partnership Equity		9,265			24,769			22,094			71,651			83,910
Cash Flows Data
Cash flows from operating activities	$	1,106		$	7,246		$	7,033		$	(2,244	)	$	7,512
Cash flows from investing activities		(10,860	)		(15,236	)		(13,421	)		(70,670	)		(2,278	)
Cash flows from financing activities		9,901			8,425			6,241			73,496			(681	)
Other Financial Data
Adjusted EBITDA (2)	$	2,320		$	8,104		$	6,667		$	(1,746	)	$	8,812		$	17,531	$	19,549
Adjusted EBITDA attributable to Cypress Energy Partners, L.P. (2)																$	12,320	$	14,268
Operational Data
Total barrels of saltwater disposed (in thousands)		1,641			8,674			6,226			551			14,489			10,962		14,489
Average revenue per barrel	$	1.79		$	1.41		$	1.47		$	1.12		$	1.15		$	1.34		1.14
Average number of inspectors																	788		1,252

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SBG Predecessor

CEP Successor

Pro Forma
Cypress Energy
Partners, L.P.

Period from
June 1
(Inception)
through
December 31,
2011

Year Ended
December 31,
2012

Nine Months
Ended
September 30,
2012

Period from
March 15
(Inception)
through
December 31,
2012 (1)

Nine Months
Ended
September 30,
2013

Year Ended
December 31,
2012

Nine Months
Ended
September 30,
2013

(in thousands, except per unit and operational data)

Average revenue per inspector (per
week)

4,542

4,601

(1)

During the period from its inception through the date of its acquisition of the SBG Predecessor on December 31, 2012, the CEP Successor had no significant assets or operations.

(2)

For a definition of Adjusted EBITDA and a reconciliation to net income and to net cash provided by (used in) operating activities, please read “— Non-GAAP Financial Measures.”

Non-GAAP Financial Measures

We define Adjusted EBITDA as net income, plus interest expense, depreciation and amortization expenses, income tax expense, impairment loss related to an SWD facility retained by Cypress Holdings, less gain on the reversal of a contingent liability related to the SBG acquisition. 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.

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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.


	SBG Predecessor									CEP Successor						Pro Forma Cypress Energy Partners, L.P.
	Period from June 1 (Inception) through December 31, 2011			Year Ended December 31, 2012			Nine Months Ended September 30, 2012			Period from March 15 (Inception) through December 31, 2012 (1)			Nine Months Ended September 30, 2013			Year Ended December 31, 2012		Nine Months Ended September 30, 2013
	(in thousands)
Reconciliation of Adjusted EBITDA to Net Income (Loss)
Net Income (loss)	$	2,162		$	6,595		$	5,746		$	(1,845	)	$	12,581		$	10,152	$	23,017
Add:
Interest expense		35			111			82			—			—			4,001		3,266
Depreciation and amortization		123			1,398			839			99			3,066			3,124		4,173
Impairment loss		—			—			—			—			4,375			—		—
Income tax expense		—			—			—			—			40			254		343
Less:
Gain on reversal of contingent consideration		—			—			—			—			11,250			—		11,250
Adjusted EBITDA	$	2,320		$	8,104		$	6,667		$	(1,746	)	$	8,812		$	17,531	$	19,549
Reconciliation of Adjusted EBITDA Attributable to Cypress Energy Partners, L.P. to Net Income Attributable to Cypress Energy Partners, L.P.
Net Income Attributable to Cypress Energy Partners, L.P.																$	8,985	$	20,908
Add:
Interest Expense attributable to Cypress Energy Partners, L.P.																	1,017		920
Depreciation and Amortization attributable to Cypress Energy Partners, L.P.																	2,191		3,498
Income Tax Expense attributable to Cypress Energy Partners, L.P.																	127		192
Less:
Gain on Reversal of Contingent Consideration attributable to Cypress Energy Partners, L.P.																	—		11,250
Adjusted EBITDA attributable to Cypress Energy Partners, L.P. (2)																$	12,320	$	14,268
Reconciliation of Adjusted EBITDA to Net Cash Provided by (used in) Operating Activities
Cash flows from operating activities	$	1,106		$	7,246		$	7,033		$	(2,244	)	$	7,512
Changes in accounts receivable		(1,638	)		(219	)		(521	)		(741	)		(500	)

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	SBG Predecessor									CEP Successor						Pro Forma Cypress Energy Partners, L.P.
	Period from June 1 (Inception) through December 31, 2011			Year Ended December 31, 2012			Nine Months Ended September 30, 2012			Period from March 15 (Inception) through December 31, 2012 (1)			Nine Months Ended September 30, 2013			Year Ended December 31, 2012	Nine Months Ended September 30, 2013
	(in thousands)
Changes in inventory, prepaid expenses and other assets		(125	)		(353	)		(416	)		(12	)		109
Changes in accounts payable and accrued liabilities		584			(175	)		1,385			255			(869	)
Interest expense		(35	)		(111	)		(82	)		—			—
Income tax expense		—			—			—			—			(40	)
Adjusted EBITDA	$	2,320		$	8,104		$	6,667		$	(1,746	)	$	8,812

(1)

During the period from its inception through the date of its acquisition of the SBG Predecessor on December 31, 2012, the CEP Successor had no significant assets or operations.

(2)

Pro forma Adjusted EBITDA attributable to Cypress Energy Partners, L.P. reflects total pro forma Adjusted EBITDA less pro forma Adjusted EBITDA attributable to noncontrolling interest in TIR. Pro forma Adjusted EBITDA attributable to noncontrolling interest in TIR comprises the pro forma total net income or TIR attributable to the minority owners, reduced for (i) the proportionate share of depreciation and amortization expenses allocable to the minority owners, (ii) the proportionate share of interest expense allocable to the minority owners, plus additional interest charges allocable to the minority owners, and (iii) the proportionate share of income tax expense allocable to the minority owners, adjusted for the effect of the allocation of the additional interest charges. For more information about the additional interest charges allocable to the minority owners of TIR, please read Note 2 to our Unaudited Pro Forma Condensed Combined Financial Statements included elsewhere in this prospectus.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion of our financial condition and results of operations in conjunction with the audited and unaudited financial statements and related notes and the unaudited pro forma condensed combined financial statements and related notes included elsewhere in this prospectus. Among other things, those financial statements include more detailed information regarding the basis of presentation for the following information. You should also review the “Risk Factors” section of this prospectus for a discussion of important factors that could cause actual results to differ materially from historical results or the results described in or implied by the forward-looking statements.

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 the SBG Predecessor and the CEP Successor, 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. Our Water and Environmental Services segment is comprised of the historical business of the CEP Successor. Through our Pipeline Inspection and Integrity Services segment, we provide independent pipeline inspection and integrity services to various energy, public utility and pipeline companies. In both of these business segments, we work closely with our customers to help them comply with increasingly complex and strict environmental and safety rules and regulations applicable to production and pipeline operations and reduce their operating costs.

How We Generate Revenue

We generate revenue in 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 interest in TIR, we 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, 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 TIR’s customers and the fees that TIR charges 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.

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:

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•

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.

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 TIR’s 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

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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-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.

General and administrative. The SBG Predecessor’s 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 will charge us an annual fixed fee of $3.0 million for the provision of certain corporate overhead expenses, which fee will increase beginning in . This fee is subject to increase for inflation and to increase, 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. After , in lieu of the fixed 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.

Included in this fixed 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 corporate overhead expenses are not reflected in our historical or our pro forma condensed combined financial statements but will be included in our annual fixed $3.0 million fee payable pursuant to the omnibus agreement. For the year ending December 31, 2014, pursuant to the omnibus agreement, $0.6 million of this corporate overhead expense attributable to our operating as a publicly traded partnership will be allocated to the owners of the 49.9% non-controlling interest in TIR based on a relative gross margin allocation of our two segments. Included in the fixed 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 addition, we expect to incur general and administrative expenses of $1.6 million attributable to our Water and Environmental Services segment (which relate to royalty expenses, management fees, legal fees and other expenses for operation of our SWD wells) for the year ending December 31, 2014 and $12.4 million attributable to our Pipeline Inspection and Integrity Services segment (which relate to TIR’s expenses for its employees and its headquarters) for the year ending December 31, 2014.

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

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basis. We estimate our assets have useful lives ranging from three years to 39 years. The facilities, wells and equipment constitute 93.0% of our assets as of December 31, 2012 and September 30, 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 impairment expense related to an SWD facility retained by Cypress Holdings, less a gain on the reversal of a contingent liability related to the SBG acquisition. Although we have not quantified distributable cash flow on a historical basis, after the closing of this offering 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 measures used by management and by external users of our financial statements, such as investors, commercial banks and research analysts, to assess:

•

our operating performance as compared to those of other providers of similar services, without regard to financing methods, historical cost basis or capital structure;

•

the ability of our assets to generate sufficient cash flow to support our indebtedness and make distributions to our partners;

•

the viability of capital expenditure projects and the overall rates of return on alternative investment opportunities;

•

our ability to incur and service debt and fund capital expenditures; and

•

the viability of acquisitions and other capital expenditure projects and the rates of return on various investment opportunities.

Adjusted EBITDA and distributable cash flow are not financial measures presented in accordance with GAAP. We believe that the presentation of these non-GAAP financial measures will provide useful information to investors in assessing our financial condition and results of operations. Net income is the GAAP measure most directly comparable to Adjusted EBITDA. The GAAP measure most directly comparable to distributable cash flow is net cash provided by operating activities. Our non-GAAP financial measures should not be considered as alternatives to the most directly comparable GAAP financial measure. Each of these non-GAAP financial measures has important limitations as an analytical tool because it excludes some but not all items that affect the most directly comparable GAAP financial measure. You should not consider 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 “Selected Historical and Pro Forma Condensed Combined Financial Data — Non-GAAP Financial Measures.”

Results Presented and Factors Affecting the Comparability of the Historical Financial
Results of the CEP Successor with the SBG Predecessor and of our Future Results

The SBG Predecessor’s inception date was June 1, 2011, and the CEP Successor’s inception date was March 15, 2012. The CEP Successor acquired the SBG Predecessor on December 31, 2012. The CEP Successor incurred costs associated with its formation and acquisition activities but had

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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. Cypress Holdings indirectly acquired a 20.1% ownership interest in TIR in June 2013 and an additional % ownership interest on , 2013. Therefore, the financial and operating data for 2011 discussed below represents the SBG Predecessor’s operations from June 1, 2011 through December 31, 2011 and the financial and operating data for 2012 discussed below represents the SBG Predecessor’s operations from January 1, 2012 through December 31, 2012. The financial and operating data for the nine months ended September 30, 2012 discussed below represents the SBG Predecessor’s operations from January 1, 2012 through September 30, 2012 and the financial and operating data for the nine months ended September 30, 2013 discussed below represents the CEP Successor’s operations, which includes the SBG Predecessor and the Moxie Assets, from January 1, 2013 through September 30, 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:

•

The financial and operating results discussed below do not include TIR or our Pipeline Integrity and Inspection Services segment. For historical financial data for TIR Parent for the year ended December 31, 2012 and for the period from January 1, 2013 to September 30, 2013, please read the audited and unaudited historical consolidated financial statements of TIR Parent and the accompanying notes, which are included elsewhere in this prospectus. For historical financial data for TIR for the year ended December 31, 2012 and for the period from January 1, 2013 to September 30, 2013, please read the audited and unaudited historical pro forma condensed combined financial statements, which are located elsewhere in this prospectus. The financial data for TIR is presented on a consolidated basis; however, we will own only a 50.1% interest in TIR.

•

The financial data for 2012 reflects that CEP Successor had no operations until its acquisition of the Moxie Assets on December 3, 2012. For historical financial data for the Moxie Assets for the year ended December 31, 2012, which are limited to revenues less direct operating expenses, please read the audited “Statement of Revenues and Direct Operating Expenses of Assets Purchased by Cypress Energy Partners, LLC From Moxie Disposal Systems, LLC and Peach Energy Services, LLC from the period from July 1, 2012 (Inception) through December 3, 2012” and the accompanying notes, which are included elsewhere in this prospectus.

•

The financial and operating data presented below does not include management services that will be performed by CES in which we will own a 51.0% interest.

•

Historical results of SBG Predecessor and CEP Successor include results of an SWD facility located in Sheridan County, Montana and a permit relating to a potential SWD facility that will not be included in our assets. In addition, historical results of CEP Successor for the nine months ended September 30, 2013 include an impairment charge relating to that facility.

•

The SBG 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.

•

Interest expense excludes interest expense of TIR. We will own a 50.1% interest in TIR upon the closing of this offering, which will cause us to incur interest expense under TIR’s amended credit facilities.

•

General and administrative expenses of the SBG 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

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of a larger business. Operating expenses associated with the CEP Successor’s headquarters office, primarily consisting of management salaries and general and administrative expenses, are not reflected in the results of the SBG Predecessor.

•

The corporate administrative services fees, including the $2.0 million of general and administrative expenses attributable to operating as a publicly traded partnership, will be charged to us by the general partner at a $3.0 million fixed fee per year. There was no fixed fee on such expenses in the historical results periods presented.

•

Initially, we anticipate incurring approximately $2.0 million of 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. These incremental general and administrative expenses, which are not reflected in our historical or our pro forma condensed combined financial statements, will be included in the annual fixed $3.0 million fee payable by us to our general partner pursuant to the omnibus agreement. A portion of this expense will be allocated to the owners of the 49.9% non-controlling interest in TIR based on the relative gross margin contribution of our two segments. Our future general and administrative expense will also include compensation expense associated with the Cypress Energy Partners, L.P. 2013 Long-Term Incentive Plan.

CEP Successor Nine Months Ended September 30, 2013 Compared to
SBG Predecessor Nine Months Ended September 30, 2012

Total Revenues

The CEP Successor’s revenues were $16.7 million for the nine months ended September 30, 2013, compared to the SBG Predecessor’s $9.2 million for the same period of 2012, an increase of 81.5%. The overall increase in saltwater disposal revenues was primarily driven by an increase in saltwater disposal volumes from 6.2 million barrels for the nine months ended September 30, 2012 to 14.5 million barrels for the same period in 2013. This increase in saltwater disposal volumes was associated with the addition of five wells between the comparable periods, which was offset somewhat by a decline in average pricing across the wells from $1.47 per barrel of disposed saltwater for the first nine months of 2012 to $1.15 for the same period 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 with lower average pricing relative to the Bakken wells due to regional market differences and lower operating expenses. The revenues also reflected an increase in residual oil revenues from the nine months ended September 30, 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.

Costs of Sales

The CEP Successor’s costs of sales were $5.4 million for the nine months ended September 30, 2013, compared to the SBG Predecessor’s $2.3 million for the same period of 2012, for an increase of 134.8%. This increase was primarily attributable to only five wells being operational during the nine months ended September 30, 2012. Incremental costs of sales attributable to wells not in operation at September 30, 2012 were $3.1 million.

Depreciation and Amortization Expenses

The CEP Successor's depreciation and amortization expenses were $3.1 million for the nine months ended September 30, 2013, compared to the SBG Predecessor's $0.8 million for the same period in 2012, an increase of 287.5%. Depreciation and amortization for the CEP Successor increased primarily as a result of its having more SWD wells and a higher depreciable basis in the SWD wells included in the prior period following its acquisition of the SBG Predecessor.

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General and Administrative

The CEP Successor’s general and administrative expenses were $2.4 million for the nine months ended September 30, 2013, compared to the SBG Predecessor’s $0.2 million for the same period in 2012. The increase was primarily attributable to an increase in variable expenses of $0.9 million associated with operating additional SWD facilities, including property leases, insurance and general supplies, as well as an increase in expenses associated with the CEP Successor’s activities of $1.3 million. The increase in the CEP Successor’s activities was attributable primarily to an increase in professional services of $0.9 million incurred primarily in relation to legal and accounting services. In addition, the CEP Successor incurred costs of $0.4 million primarily related to management fees and an office lease.

Net Income

The CEP Successor recorded net income of approximately $12.6 million for the nine months ended September 30, 2013, compared to the SBG Predecessor’s $5.7 million for the same period in 2012, an increase of 121.1%. This increase in net income was the result of the $11.3 million gain recorded for the reversal of contingent consideration from the SBG acquisition on December 31, 2012, higher segment gross margin from the increased number of well sites, offset by a $4.4 million impairment loss recorded on one of its SWD facilities and higher operating expenses, primarily depreciation and amortization and general and administrative expenses associated with the expanded operations offset by higher segment gross margin from the increased number of SWD wells.

Adjusted EBITDA and Gross Margin

The CEP Successor recorded Adjusted EBITDA and gross margin of $8.8 million and $11.2 million, respectively, for the nine months ended September 30, 2013 compared to the SBG Predecessor’s $6.7 million and $6.9 million, respectively, for the same period in 2012. This increase in Adjusted EBITDA and gross margin was the result of the increased number of SWD wells offset by higher operating expenses, primarily general and administrative expenses. Adjusted EBITDA is a financial measure not presented in accordance with GAAP. For a definition of Adjusted EBITDA and a reconciliation to net income and to net cash provided by (used in) operating activities, please read “Selected Historical and Pro Forma Condensed Combined Consolidated Financial and Operating Data — Non-GAAP Financial Measures.”

SBG Predecessor’s Year Ended December 31, 2012 Compared to
SBG Predecessor’s Period from June 1, 2011 (Inception) to December 31, 2011

Total Revenues

The SBG Predecessor’s revenues were $12.2 million for the year ended December 31, 2012, compared to the SBG Predecessor’s $2.9 million for the period from June 1, 2011 to December 31, 2011, an increase of 320.7%. The overall increase in saltwater disposal revenues was primarily driven by a 443.8% 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 21.2% 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

The SBG Predecessor’s costs of sales were $3.7 million for the year ended December 31, 2012, compared to the SBG Predecessor’s $0.5 million for the period from June 1, 2011 to December 31, 2011, an increase of 640.0%. The increase is primarily attributable to higher employment costs, repairs and maintenance and utility costs associated with operating the four additional SWD facilities.

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Depreciation Expense

The depreciation expense was $1.4 million for the SBG Predecessor’s year ended December 31, 2012, compared to $0.1 million for the period from June 1, 2011 to December 31, 2011, an increase of 1,300.0%. 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

The SBG Predecessor’s general and administrative expenses were $0.5 million for the year ended December 31, 2012, compared to the SBG Predecessor’s $0.1 million for the period from June 1, 2011 to December 31, 2011, an increase of 400.0%. The increase was primarily attributable to the operation of four additional SWD facilities.

Net Income

The SBG Predecessor’s net income was $6.6 million for the year ended December 31, 2012, compared to the SBG Predecessor’s $2.2 million for the period from June 1, 2011 to December 31, 2011, an increase of 200.0%. 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.

Adjusted EBITDA and Gross Margin

The SBG Predecessor recorded Adjusted EBITDA and gross margin of $8.1 million and $8.5 million, respectively, for the period from June 1, 2011 to December 31, 2012, compared to the SBG Predecessor’s $2.3 million and $2.4 million, respectively, for the period from June 1, 2011 to December 31, 2011. This increase in Adjusted EBITDA and gross margin was the result of the opening of four additional SWD facilities and having a full year of operations for the two SWD facilities in operations at December 31, 2011, offset by their corresponding costs of sales, general and administrative and other expenses. Adjusted EBITDA is a financial measure not presented in accordance with GAAP. For a definition of Adjusted EBITDA and a reconciliation to net income and to net cash provided by (used in) operating activities, please read “Selected Historical and Pro Forma Condensed Combined Consolidated Financial and Operating Data — Non-GAAP Financial Measures.”

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 TIR are substantial. Please read “Risk Factors — Risks Related to Our Business — The working capital needs of TIR 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 facilities and the issuance of debt and equity securities. However, we cannot assure you that we will be able to raise additional funds on desired or favorable terms or at all.

Since the acquisition of our initial assets in December 2012, the CEP Successor’s sources of liquidity have included cash generated from operations and equity investments by Cypress Holdings, the owner of our general partner.

Following the closing of this offering, we expect our sources of liquidity to include:

•

cash generated from operations;

•

borrowings under our $50 million factoring facility, under which we will have $ million available for borrowings at the closing of this offering;

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•

borrowings under our mezzanine facilities, under which we will have $ million available for borrowings at the closing of this offering after giving effect to an amendment with TIR Capital Partners, LLC to upsize the facilities to $ million, which we expect will become effective at the closing of this offering; and

•

issuances of debt and equity securities.

We believe that the cash generated from these sources will be sufficient to allow us to meet our requirements for working capital and capital expenditures for the foreseeable future.

Working Capital

Working capital is the amount by which trade accounts receivable, prepaid expenses and other current assets exceed the sum of accounts payable, accrued expenses, income taxes payable and other current liabilities and is a measure of our ability to pay our liabilities as they become due. Our working capital was $8.2 million at September 30, 2013, compared to $1.9 million at December 31, 2012 and a deficit of $1.0 million at December 31, 2011.

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 by the SBG Predecessor from its inception in June 2011 to December 31, 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 $6.3 million increase in working capital from December 31, 2012 to September 30, 2013 was primarily a result of the following factors:

•

our operations at September 30, 2013 were more extensive than at December 31, 2012;

•

accounts receivable at September 30, 2013 were $3.1 million, or $0.5 million more than the $2.6 million accounts receivable balance at December 31, 2012 based upon increased revenues; and

•

cash at September 30, 2013 was $5.1 million, or $4.5 million more than the $0.6 million cash balance at December 31, 2012 based upon increased cash from operations.

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 TIR inspectors. TIR has substantial working capital needs throughout the year as it pays its inspectors on a weekly basis but typically receives payment from its customers 45 to 90 days after the services have been performed. TIR Parent has historically borrowed under its factoring facility, and TIR will continue to make borrowings under this facility, to fund these working capital needs, which reduces 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 TIR are substantial, which could require us to seek additional financing that we may not be able to obtain on satisfactory terms, or at all.”

Cash Flows

The following table reflects cash flows for the applicable periods:


	SBG Predecessor						SBG Predecessor			CEP Successor
	Year Ended December 31,						Nine Months Ended September 30,
	2011			2012			2012			2013
	(in thousands)
Net cash provided by (used in):
Operating Activities	$	1,106		$	7,246		$	7,033		$	7,512
Investing Activities	$	(10,860	)	$	(15,236	)	$	(13,421	)	$	(2,278	)
Financing Activities	$	9,901		$	8,425		$	6,241		$	(681	)

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CEP Successor Nine Months Ended September 30, 2013 Compared to SBG Predecessor Nine Months Ended September 30, 2012

Operating Activities. Net cash provided by operating activities was $7.5 million for the nine months ended September 30, 2013, compared to $7.0 million for the same period in 2012. This increase in cash provided by operating activities was primarily a result of our owning five additional SWD wells in 2013 than compared to 2012.

Investing Activities. Net cash used in investing activities was $2.3 million for nine months ended September 30, 2013, compared to $13.4 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 or acquisition in 2013.

Financing Activities. Net cash used in financing activities was $0.7 million for the nine months ended September 30, 2013, compared to net cash provided by financing activities of $6.2 million for the same period in 2012, primarily as a result of equity financings incurred by the SBG Predecessor in 2012 to fund the construction of SWD facilities that were not incurred by the SBG Predecessor in 2013. This decrease in cash provided by financing activities was primarily a result of the absence of SWD facility construction activity in 2013.

SBG Predecessor Year Ended December 31, 2012 Compared to SBG 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 only two operating SWD facilities on December 31, 2011 with operating results for only seven months, as compared to six SWD facilities on December 31, 2012 with operating results for the full year.

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 the SBG Predecessor investing activities than in 2011.

Capital Requirements

The Water and Environmental Services segment of the business has certain 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 expected obsolescence of our existing saltwater disposal systems. 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.

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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

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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 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.

Our historical accounting records did not differentiate between maintenance and expansion capital expenditures. We have budgeted $0.7 million in capital expenditures for the year ending December 31, 2014.

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 mezzanine facilities, the issuance of additional partnership units or debt offerings.

The Pipeline Inspection and Integrity Services segment of the business requires only limited capital expenditures, the primary of which relates to purchases of office equipment.

Our Credit Facilities

The following is a discussion of the existing credit facilities of TIR Parent. Upon closing of the restructuring transactions described under “Prospectus Summary — The Restructuring Transactions,” the credit facilities will be amended and become obligations of TIR, which will be our 50.1% owned subsidiary.

Mezzanine facilities

On March 12, 2009, TIR Parent entered into a $17 million mezzanine loan agreement with Triangle Mezzanine Fund, LLLP and the lenders party thereto, or the 2009 mezzanine facility. The 2009 mezzanine facility, as amended, has a maturity date of June 1, 2015 and currently has an interest rate of 14.0%. As part of the 2009 mezzanine facility, TIR Parent issued lenders warrants to acquire a number of shares in TIR Parent, or mezzanine warrants, representing an aggregate of 23.0% of the fully diluted capital stock of TIR Parent.

On July 8, 2010, TIR Parent entered into a $2.8 million mezzanine loan agreement with Triangle Mezzanine Fund, LLLP and the lender parties thereto, or the 2010 mezzanine facility. The 2010 mezzanine facility, as amended, has a maturity date of June 1, 2015 and currently has an interest rate of 17.50%. We refer the 2009 mezzanine facility and the 2010 mezzanine facility, as amended, collectively as our “mezzanine facilities.” Pursuant to the terms of the 2010 mezzanine facility and the Lien Subordination Agreement among TIR Parent, Triangle Mezzanine Fund, LLLP and the other lenders of the mezzanine facilities, dated as of July 8, 2010, the indebtedness under the 2010 mezzanine facility is subordinated to the 2009 mezzanine facility.

The mezzanine facilities collectively contain (i) financial covenants, including net funded leverage ratios of 4.15:1.00, fixed charges ratios of 1.20:1.00, capital expenditures limits, minimum EBITDA thresholds and subordinated debt leverage ratios of 2.65:1.00, (ii) customary covenants, including restrictions on TIR Parent’s ability to: (a) incur additional indebtedness; (b) make certain investments, loans or advances; (c) make distributions to shareholders; (d) repurchase shares; or (e) enter into a merger or sale of its property or assets, including the sale or transfer of interests in its subsidiaries; and (iii) repayment charges equal to 1% and 3% of the principal prepaid under the 2009 mezzanine facility and 2010 mezzanine facility, respectively, if we repay these facilities prior to the maturity date.

The events that constitute an Event of Default as defined in the mezzanine facilities include: (i) payment defaults; (ii) misrepresentations; (iii) breaches of covenants; (iv) cross-default and cross-acceleration to certain other indebtedness; (v) adverse judgments against TIR Parent in excess of a specified amount; (vi) changes in control; (vii) loss of permits; (viii) failure to perform under a

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material agreement; (ix) certain insolvency events; and (x) assertion of certain environmental claims. Effective October 11, 2013, the parties to the mezzanine facilities amended the change of control provision in the agreements to permit Cypress Holdings, indirectly through Cypress Energy Partners — TIR, LLC, to acquire shares in TIR Parent above the 50% change of control threshold. At December 31, 2012 and September 30, 2013, TIR Parent was in compliance with the mezzanine facilities’ covenants.

As of December 31, 2012 and September 30, 2013, TIR Parent had an aggregate $19.4 million and $19.6 million, respectively, in debt outstanding under the mezzanine facilities.

On November 7, 2013, the lenders of the mezzanine facilities irrevocably assigned and sold to TIR Capital Partners, LLC, or TIR Capital, all of the lenders’ rights and obligations under the mezzanine facilities, and TIR Capital irrevocably purchased and assumed all of such rights and obligations for approximately $20 million relating to the principal, accrued and unpaid interest and repayment charges associated with the mezzanine facilities. TIR Capital is owned jointly by our Chief Executive Officer, Peter C. Boylan III, and one of our director nominees, Charles C. Stephenson, Jr. See “Certain Relationships and Related Party Transactions — Agreements with Affiliates.”

Factoring facility

On February 29, 2012 TIR Parent entered into a factoring facility with Wells Fargo Bank, National Association, or as amended, the factoring facility. Under the factoring facility, Wells Fargo Bank, National Association, or Wells Fargo, purchases qualifying accounts receivables and advances 90.0% of the face value of the accepted accounts receivables to TIR Parent. The aggregate maximum amount of advances under the factoring facility is $50.0 million, and TIR Parent pays interest on all outstanding advances at the annualized rate of LIBOR plus 4.0%, or Canadian Dealer Offer Rate plus 4.55% for advances on the accounts receivables of its Canadian subsidiaries, and an annual facility fee of $0.25 million. Wells Fargo has the discretion to reduce the maximum amount of advances and to reduce the percentage rate of the advance given in exchange for the accounts receivables. The interest rate charged on outstanding advances may also be increased if Wells Fargo’s cost of funds increases.

After collecting on a purchased receivable, Wells Fargo deducts the advance already paid on the receivable, the interest accrued on the advance and transfers any remaining amounts to TIR Parent. TIR Parent’s obligations under the factoring facility are secured by a senior secured interest in nearly all assets of TIR Parent and Tulsa Inspection Resources — Nondestructive Examination, Inc. and in the accounts receivables of Tulsa Inspection Resources — Canada, Inc. and Foley Inspection Services, Inc. The maturity date of the factoring facility is February 28, 2015. Except for certain terminations attributable to Wells Fargo exercising its discretion to modify terms, TIR must pay a termination fee equal to 0.5% of the aggregate maximum amount of advances if termination of the factoring facility occurs after April 11, 2014 or 1.5% if termination occurs on or before such date.

The factoring facility contains (i) financial covenants, including a net funded leverage ratio of 4.20:1.00, fixed charges ratio of 1.20:1.00, capital expenditures limits, minimum EBITDA thresholds and a subordinated debt leverage ratio of 2.70:1.00; (ii) customary covenants, including restrictions on TIR Parent’s ability to incur additional indebtedness or sell accounts receivables unless first rejected by Wells Fargo and (iii) covenants on the delivery and quality of the accounts receivables.

The events that constitute an event of termination include: (i) payment defaults; (ii) misrepresentations; (iii) breaches of covenants; (iv) default, termination, or breach of certain other indebtedness agreements; (v) adverse judgments against TIR Parent in excess of a specified amount; (vi) changes in control; (vii) failure to repurchase any account receivable where a defense to payment is asserted; (viii) default of a guarantor on its guaranty; (ix) certain insolvency events;

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and (x) violation of certain provisions of the Employee Retirement Income Security Act of 1974. At December 31, 2012 and September 30, 2013, TIR Parent was in compliance with the factoring facility’s covenants.

As of December 31, 2012 and September 30, 2013, TIR Parent had an aggregate $27.0 million and $45.0 million, respectively, in debt outstanding under the factoring facility.

Upon the closing of this offering, we and Wells Fargo intend to enter into an amendment to the factoring facility, which shall provide for the contribution of TIR into the Partnership, the elimination of security interests or collateral owed by the subsidiaries of TIR Parent that will not get contributed to the Partnership and approve to upsizing of the mezzanine facilities. The amended factoring facility is expected to mature in March 2015 and will continue to be subject to the same interest rates and facility fees described above.

Credit Risk and Customer Concentration

We are subject to risks of loss resulting from nonpayment or nonperformance by our customers to which we provide services. Our ten largest customers generated approximately 68% of our Water and Environmental Services segment revenue for the year ended December 31, 2012 and 56% of segment revenue for the nine months ended September 30, 2013. In addition, one of our water and environmental services customers, BS&W Solutions, LLC, accounted for 25% of our segment revenue for the year ended December 31, 2012. Our five largest customers of our Pipeline Inspection and Integrity Services segment accounted for approximately 71% of our segment revenue for the year ended December 31, 2012 and 74% of segment revenue for the nine months ended September 30, 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 year ended December 31, 2012 and the nine months ended September 30, 2013, on a pro forma condensed combined basis. We examine the creditworthiness of third-party customers to whom we extend credit and manage our exposure to credit risk through credit analysis, credit approval, credit limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees. TIR does not charge its customers interest on their respective accounts receivable.

A significant percentage of the gross margin in each of our segments is also attributable to these customers. If one or more of these customers were to default on their payment obligations, we may not be able to replace any of these customers in a timely fashion, on favorable terms or at all. In any of these situations, our segment gross margin and cash flows and our ability to make cash distributions to our unitholders may be adversely affected. We expect our exposure to concentrated risk of non-payment or non-performance to continue as long as we remain substantially dependent on a relatively small number of customers for a substantial portion of our segment gross margin.

Contractual obligations

A summary of the CEP Successor’s contractual obligations and other commitments, as of December 31, 2012, is shown in the table below. This table does not reflect contractual obligations, including indebtedness, of TIR Parent, or our expected borrowings under our credit facilities at the closing of this offering. As of September 30, 2013, pro forma for our acquisition of a 50.1% equity interest in TIR, we had outstanding indebtedness of $20.5 million under the TIR Parent mezzanine facilities due 2015 and of $37.8 million under our factoring facility.


	Total		Less Than 1 Year		1 – 3 Years		3 – 5 Years		More Than 5 Years
	(in thousands)
Long-term debt	$	—	$	—	$	—	$	—	$	—
Lease obligations	$	665	$	81	$	170	$	170	$	244
Total	$	665	$	81	$	170	$	170	$	244

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Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Qualitative and Quantitative Disclosures About Market Risk

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.

Interest Rate Risk

We currently have no exposure to changes in interest rates as we have no indebtedness associated with a credit facility. We anticipate that at the closing of this offering, at which point we will be the controlling holder of TIR, we may implement swap or cap structures to mitigate our exposure to interest rate risk associated with the mezzanine facilities and the factoring facility.

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.

Impact of Seasonality

Results of operations in our Water and Environmental Services segment and our Pipeline Inspection and Integrity Services segment can be affected by seasonality. The volumes of saltwater that we handle in the Bakken Shale region of the Williston Basin in North Dakota, where we own seven of our nine SWD facilities, tend to be lower in the winter due to heavy snow and cold temperatures and in the spring due to heavy rains and muddy conditions. 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. The second and third quarters also tend to be the most active quarters for our Pipeline Inspection and Integrity Services segment because weather conditions in some regions in which our customers maintain pipeline assets make it difficult to inspect those assets during the winter months; however, our geographic diversity and recent expansion in more temperate climates help reduce the effects of seasonality on our Pipeline Inspection and Integrity Services segment.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to select appropriate accounting policies and to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenue and expenses. See “Note 2 — Summary of Significant Accounting Policies,” in the CEP Successor Consolidated Financial Statements, 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.

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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.

Our recorded identifiable intangible assets primarily include the estimated value assigned to non-compete agreements 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 market 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, 2012, the CEP Successor had $33.9 million of goodwill recorded in conjunction with past business combinations. Under the accounting rules for goodwill, this intangible asset is not amortized. Instead, goodwill 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 our Water and Environmental Services and Pipeline Inspection and Integrity operating segments are the appropriate reporting units for testing goodwill impairment.

For the period ended September 30, 2013, a facility that was acquired from our SBG Predecessor (the SWD facility in Sheridan County, Montana) began experiencing excess operating pressures indicating the possibility of an operational malfunction. Disposal activities were suspended at the facility during the second quarter until the issue was identified and repaired. We determined that this facility was impaired and we recorded a $4.4 million impairment charge. Due to this impairment charge, and our evaluation of the actual performance of the SBG Predecessor wells forecast for 2013, we determined that there was the possibility that our goodwill may be impaired. Accordingly, we performed step one of the goodwill impairment test which is to compare the fair value of our reporting units to its carrying amounts and determined goodwill had not been impaired.

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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.

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 September 30, 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. If our estimates of future cash flows are 7% to 11% lower than those used to calculate fair value a step two impairment analysis of our goodwill could be required. If a step two impairment analysis is performed, it is reasonably possible that we could have a partial or full impairment of our goodwill balance.

Depreciation Methods, Estimated Useful Lives of Property and Impairment of Property and Equipment

Depreciation expense represents the systematic and rational write-off of the cost of the CEP Successor’s 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. The CEP Successor depreciates its 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 the CEP Successor to make assumptions regarding the useful economic lives and residual values of its assets. At the time the CEP Successor acquires and places its property and equipment in service, the CEP Successor develops assumptions about such lives and residual values that it believes are reasonable; however, circumstances may develop that could require the CEP Successor to change these assumptions in future periods, which would change its depreciation expense amounts prospectively. We currently use a life of 15 years for tangible and intangible drilling costs, 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

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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.

Due to our Sheridan well experiencing excess operating pressures indicating the possibility of an operational malfunction and continued decline in disposal prices as a result of increased competition, we assessed the Sheridan well for impairment using estimates of future cash flows. 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. As a result, we recognized $4.4 million of impairment charges in the period ended September 30, 2013.

The fair value of the Sheridan well was based on expected future cash flows, which utilized volumes determined based on expected drilling activity in the area around the Sheridan well, a discounted rate reflected of rates needed to be competitive in the area of the well, oil volumes from water volumes based on historical relationships between water volumes and oil volumes, expected operational expenses based on our historical experience, and routine capital expenditures. We also considered the cost to correct the mechanical issues. These expected cash flows were then discounted using a discount rate representing our cost of capital.

In addition to those long-lived assets described above for which impairment charges were recorded, other facilities were reviewed for which no impairment charge was required. These 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. For other SWD wells reviewed, but for which impairment charges were not recorded, we estimate that approximately three facilities with a net book value of $14.5 million could be at risk for impairment if water disposal rates decline by approximately 11% to 12%, on average.

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. We are, however, 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. Currently % of our income is non-qualifying.

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INDUSTRY

Overview of Water and Environmental Services Industry

Various waste byproducts are generated during drilling and completion of, and production from, crude oil and natural gas wells, and an array of federal and state rules and regulations mandate that these byproducts be disposed of in an environmentally safe manner. We currently focus on the disposal of flowback and produced water waste fluids (collectively referred to in the industry as “saltwater”), which includes brinish fluids returned to the surface during a well’s completion and production phases. The timely disposal of these fluids is required by oil and natural gas exploration and production companies, or producers, during the lifespan of their producing oil and natural gas wells and with each new oil and natural gas well drilled and completed.

The most common method of saltwater disposal is to transport the flowback and produced water to facilities that treat and dispose of the wastewater. We are not directly engaged in the trucking of saltwater but own and operate SWD facilities. Key considerations for us and other SWD facility operators in determining the location of facilities include: the location of existing and expected drilling and production activity; the number, size and financial strength of associated producers; the geological characteristics of the area; access to power infrastructure and roads or pipelines for transportation; and the ability to obtain the necessary permits to conduct operations. We also consider the ratio of water to hydrocarbon, or the water cut, the water decline curve, the expected lifespan of the SWD facility based on the waste streams being disposed and the presence of competing SWD services providers.

The diagram below illustrates the use and disposal of water during the oil and natural gas drilling, completion and production phases.

[GRAPHIC MISSING]

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The Role of Hydraulic Fracturing

The oil and natural gas industry has disposed of wastewater streams generated during its drilling, completion and production phases for decades, including the use of subsurface injection since the 1930s. Over the last several years, the application of hydraulic fracturing has significantly increased fresh water usage in well stimulation and volumes of saltwater recovered from oil and natural gas wells. This growth has led to an increase in the number of SWD facilities required to support existing production and new drilling and completion activity.

Hydraulic fracturing is a well stimulation process that utilizes large volumes of pressurized water combined with fracturing chemical additives and sand or alternative proppant to crack open previously impenetrable rock to release hydrocarbons. When the pressure exceeds the rock strength, the fractures in the rock formation open or extend up to several hundred feet, thereby increasing the flow of oil and natural gas into the wellbore. The proppant holds the fractures in the shale rock formation open when the pressure is released, which allows hydrocarbons and water to flow up to the surface.

According to Spears & Associates, almost every U.S. onshore oil and natural gas wells completed during 2012 utilized hydraulic fracturing techniques. While hydraulic fracturing commonly is associated with the initial completion of a new well, hydraulic fracturing techniques can be reapplied during the life of the well to restimulate the initially targeted hydrocarbon-bearing formations or to stimulate additional hydrocarbon-bearing formations. This generally leads to additional saltwater requiring disposal.

Flowback and Produced Water

Oil and natural gas operations produce two primary types of saltwater waste streams:

•

Flowback water is the fluid that returns to the surface during and for the weeks following the hydraulic fracturing process. Based on an April 2010 study by the University of North Dakota, the volume of water used in the hydraulic fracturing of a new horizontal well in the Bakken Shale region of the Williston Basin in North Dakota ranged from 0.5 million to 3.0 million gallons with between 17.0% and 47.0% of this water returning to the surface as flowback water within ten days of applying hydraulic fracturing, with the remainder of the injected water returning to the surface at a later date or absorbed in the formation. A June 2011 report of the University of Texas at Austin estimated that 0.2 million to 1.6 million gallons of water are typically used in the hydraulic fracturing process of a new well in the Permian Basin region. A November 2012 presentation by the U.S. Department of Interior Bureau of Reclamation indicates that hydraulic fracturing in the U.S. utilizes 0.5 million to more than ten million gallons of water per well fracturing event.

Flowback water consists largely of the water injected into the oil and natural gas wells during the hydraulic fracturing process but also includes clays, fracturing chemical additives, dissolved metal ions and total dissolved solids. At some point, the water recovered from an oil and natural gas well makes a transition from flowback water to produced water for the remaining life of the oil and natural gas well. The transition point can be difficult to discern but is often identified by the chemical composition and weight of the recovered water and the rate of return. Flowback water generally has a higher flow over a matter of weeks while produced water has a lower flow over the lifespan of the well. The impurities and variable nature of flowback water can make it more challenging to treat and dispose than produced water, potentially increasing the operating expenditures and maintenance capital expenditures of an SWD facility versus those incurred with produced water. As a result, the market-driven price for disposing of flowback water can be higher than that of produced water (as is the case currently in the Bakken Shale region), although a barrel of flowback water often contains a higher volume

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of residual oil than found in a barrel of produced water, which can be a revenue source and offset the need for differential per barrel pricing between flowback and produced water.

•

Produced water is naturally occurring water found in hydrocarbon-bearing formations that flows to the surface along with oil and natural gas. Produced water has high levels of total dissolved solids and leaches out minerals from the formation including barium, calcium, iron and magnesium. Produced water also can contain dissolved hydrocarbons such as methane, ethane and propane, and, like flowback water, requires proper treatment and disposal. The volume of produced water generated during oil and natural gas production can differ depending on formation characteristics, well design, use of enhanced recovery techniques and the age of the well.

Produced water is the largest waste byproduct by volume associated with oil and natural gas production, with the amount of produced water relative to hydrocarbon varying based upon the region and geological formation. A September 2009 study by the Argonne National Laboratory estimated that in 2007, the U.S. onshore oil and natural gas industry produced approximately 1.3 billion barrels of oil, 21.3 trillion cubic feet of natural gas and 20.3 billion barrels of produced water. Per the Argonne study, the majority of this produced water was reinjected for enhanced hydrocarbon recovery (e.g., waterfloods) with virtually all of the remaining produced water (or more than 7.1 billion barrels) injected subsurface for disposal at an SWD facility.

Produced water is typically generated, and saltwater disposal services are required, for the life of an oil and natural gas well, which can span multiple decades. Produced water can represent up to 98.0% of the fluid brought up from U.S. onshore wells nearing the end of their productive lives. Global Water forecasts growth in produced water volumes as shown in the following chart.

Produced Water Volume Forecast to 2025

[GRAPHIC MISSING]

Source: Department of Interior Presentation. Produced Water Management for Oil and Gas Operations.

Saltwater Disposal Facilities

The primary methods for handling flowback and produced water include:

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U.S. Environmental Protection Agency (EPA) Class II SWD wells, where flowback and produced water are treated and injected subsurface;

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evaporation pits, where the water is evaporated at the surface; and

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recycling facilities, where flowback and produced water are treated in a manner that some portion of the water can be recycled for future fracturing processes or other beneficial uses.

In all cases, the flowback and produced water must be processed and disposed of in a manner consistent with applicable environmental regulations. The manner in which the disposal process is performed is dictated in part by local regulations that can vary from region to region or state to state. As a result of these regulatory requirements and the level of expertise required to properly process and dispose of saltwater, producers are requiring increased compliance expertise and operational experience from their service providers.

The most common method for handling flowback and produced water is through an SWD facility that injects the water subsurface at depths that are substantially deeper than the drinking water supply. We follow this approach, providing saltwater disposal services through our nine owned SWD facilities and four other managed SWD facilities.

SWD facilities serving the oil and natural gas industry typically include offload facilities, filtration systems, settling tanks, storage tanks, pumps, an injection well and associated equipment to separate residual oil from the wastewater and inject the wastewater deep underground into geologic formations approved by governmental agencies. Injection wells are regulated by the EPA’s Underground Injection Control program as Class II injection wells. Class II injection wells are approved for the injection of saltwater associated with oil and natural gas production. The EPA currently estimates that there are approximately 144,000 Class II injection wells in operation in the U.S., of which approximately 20% are SWD injection wells. The remaining 80% of the Class II injection wells are primarily enhanced recovery wells.

While all SWD facilities are categorized as EPA Class II injection wells, the characteristics of an SWD facility can vary based on a number of important factors, including:

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proximity to existing and expected oil and natural gas production;

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maximum formation injection capacity, including its permeability and porosity;

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the presence of high-capacity pumps onsite for injection;

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location and ingress and egress, including access to right of way for piping and highways and roads for trucking, as well as truck weight limits and night curfews;

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power availability;

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presence of personnel and/or video monitoring at the facility;

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spill containment and other protection systems; and

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oil separation and storage systems.

SWD facilities are generally owned by (i) producers with dedicated disposal facilities for their own produced water and (ii) third-party service providers who accept wastewater from the area’s various producing oil and natural gas wells at their SWD facilities, or commercial SWD facilities.

Ownership in the saltwater disposal industry is fragmented. For example, data available from the Texas Railroad Commission lists over 900 operators owning approximately 2,500 commercial SWD wells in Texas with the largest operator having 73 SWD wells and several hundred operators owning only a single SWD well.

Transportation of Saltwater

There are two primary methods of transporting saltwater from oil and natural gas well location to an SWD facility.

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Trucking is the primary method of transporting saltwater and often is the only feasible method of transporting flowback water, as producers often need to dispose of saltwater before pipeline infrastructure can be built. Trucking has the advantages of lower capital

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costs for the producer compared to pipelines and the ability to access multiple SWD facilities. However, operating expenses associated with trucking (such as labor and fuel costs), costs of complying with various local regulations, insurance and costs related to road repairs and accidents can be significant. Trucking rates may be particularly higher in newer basins with fewer trucking alternatives than in more established basins with more trucking competitors. We do not provide trucking services to the producers.

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Pipeline (also called gathering system) is an alternative method for transporting saltwater from the well location to the SWD facility. The initial capital costs to build the infrastructure for piping saltwater are greater than the capital costs of transporting the saltwater by truck, but the operating expenses to the producer after the pipeline is constructed can be significantly lower, and the net economics over the lifespan of the well can be substantially superior, especially for long-lived oil and natural gas wells. According to the April 2010 study by the University of North Dakota, transportation costs in the Williston Basin accounted for 56.0% to 84.0% of the producers’ total water handling costs. Piping produced water is increasingly being pursued by many producers to reduce their carbon footprint and contingent liability exposure in addition to lowering the operating costs associated with transporting water. We do have pipelines into some of our SWD facilities and are pursuing additional opportunities with producers.

Saltwater Disposal Customers and Contractual Arrangements

There are primarily two classes of customers for commercial SWD facilities:

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Producers that contract directly with the SWD facility operator to ensure that the saltwater associated with their operations, which is transported by pipeline or trucking companies, is injected into a nearby facility that meets the producer’s environmental and safety criteria; and

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Trucking Companies hired by producers to transport saltwater associated with the producers’ operations to commercial SWD facilities.

Some producers obtain permits to own and operate private SWD facilities for their own saltwater or may otherwise enter into an arrangement to use a commercial SWD facility. Commercial SWD facilities are open to the public via trucking or pipeline and are able to take flowback and produced water from any source. Commercial SWD facilities typically charge customers a fee per barrel of saltwater to be disposed, which fees can vary between flowback and produced water depending on the competitive dynamics, content and operating costs specific to a geographic region. In addition, commercial SWD facilities may generate revenue from the sale of residual oil that is separated from the saltwater before injection. Generally speaking, flowback water contains more residual oil than produced water, unless the producer has put in place processes for removing residual oil prior to its being transported for disposal.

Trends in the U.S. Saltwater Disposal Industry

We believe that the following trends will positively impact the demand for U.S. saltwater disposal services:

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Increasing levels of U.S. oil and natural gas production. Completed oil and natural gas wells historically have produced consistent levels of hydrocarbon and saltwater streams over the life of the well, which may span several decades. The level and type of U.S. drilling and completion activity in recent years has resulted in an increase in the volumes of oil and natural gas production in the U.S. onshore market. According to the U.S. Energy Information Administration, or EIA, crude oil and marketed natural gas production in the continental United States excluding the Gulf of Mexico has grown from 10.2 MMboe per day in 2000 to 15.4 MMboe per day in 2012, an increase of 51.0%, and is expected to increase to 17.3 MMboe per day for 2014. Generally, growing oil and natural gas production has an associated growing volume of saltwater streams that either needs to be reinjected, recycled or disposed.

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U.S. Crude Oil And Marketed Natural Gas Production
In Lower 48 States Excluding Gulf of Mexico

[GRAPHIC MISSING]

Source: U.S. Energy Information Administration’s (EIA) Petroleum Supply Monthly and Natural Gas Monthly, July 2013. Converts millions of cubic feet of natural gas to barrels of oil equivalent at 6:1.

The EIA also forecasts oil and natural gas production growth in both of our saltwater disposal markets, the Bakken Shale region of the Williston Basin in North Dakota and the Permian Basin in West Texas. We believe that rising oil and natural gas production requires incremental long-term saltwater disposal services, particularly as it relates to produced water.


Hydrocarbon Liquids Production	2012		Projected 2013		Projected 2014
	(million barrels per day)
Permian Basin Production		1.18		1.29		1.37
Williston Basin Production		0.72		0.95		1.13

Source: U.S. Energy Information Administration (EIA), February 2013.

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Increasing volumes of water utilized for drilling and completion. Greater volumes of water are being used in the U.S. as a result of the application of hydraulic fracturing techniques, which significantly increases the volume of associated flowback water. As an example, a study by the Texas Water Development Board in 2013 found that the total water use for hydraulic fracturing in Texas more than doubled from 2008 to 2011. While average U.S. onshore rig count has decreased since 2012, drilling and completion efficiencies have resulted in increasing average well lengths and a growing number of average fracturing stages per well, which in turn are requiring greater volumes of water to be utilized per well.


All U.S. Onshore	2010		2011		2012		Projected 2013		Projected 2014
Wells Drilled		38,300		44,200		47,700		48,100		49,100
Footage Drilled (Millions)		258.3		328.0		365.8		380.8		402.8
Average Footage per Well		6,744		7,421		7,669		7,917		8,204

Source: Spears & Associates, Drilling and Production Outlook, September 2013. Includes all U.S. onshore.

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Increasing capital needs driving outsourcing to independent service companies like us. Since the early 1990s, many producers, including ConocoPhillips, Marathon, XTO and Endeavor Energy, have spun off or outsourced their oil and natural gas gathering, transportation, compression and processing needs as they focus their operations and capital spending on oil and natural gas exploration, development and production. We believe that this trend could extend to the saltwater disposal industry, providing us with increased opportunities to gather (or pipe), treat and dispose of the producers’ saltwater.

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Increasing public and regulatory scrutiny driving outsourcing to independent service companies like us. Ongoing public and regulatory scrutiny of the oil and natural gas industry, as well as the inability of producers to train and retain in-house expertise, can be a further driver of outsourcing by producers of saltwater gathering, treatment and disposal services. Violations of environmental laws and regulations can generate substantial fines and significant negative publicity. We believe that this will generate increased long-term demand as producers concentrate on core operations and determine that it is more cost effective to manage compliance with an increasingly complex set of regulatory requirements over multiple basins and regulatory jurisdictions through an experienced independent company like us.

Overview of Pipeline Inspection and Integrity Services Industry

The increasing complexity of mandatory pipeline integrity programs, together with increased governmental rules and regulations, has led many pipeline operators to outsource inspection and integrity services to independent service providers that have a proven track record of performance. Independent inspectors assist the pipeline operators with performing multiple tasks associated with documentation and project oversight of their asset integrity programs and related construction, inspection, maintenance and repair activities. Independent inspectors generally operate as an extension of the pipeline operators’ management and employees where additional experienced personnel are needed to perform pipeline inspection and integrity services.

Pipeline Inspection

The interstate oil and natural gas pipeline inspection industry is regulated and governed by the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration, or PHMSA. According to PHMSA’s Annual Report Mileage Summary, there are more than 2.3 million miles of transmission and distribution pipelines in the U.S. carrying natural gas and petroleum and refined petroleum products. There also are millions of miles of gathering systems connecting oil and natural gas wells to pipelines, natural gas plants, storage terminals and other transportation or storage facilities as well as additional pipelines and gathering systems under construction. Every mile of pipeline is susceptible to risks such as internal and external corrosion, cracking, third-party damage and manufacturing flaws. To mitigate the risk of environmental damage and enhance public safety, government regulation mandates that pipeline operators assess the safety and integrity of their pipeline infrastructure on a recurring basis.

PHMSA guidelines identify the minimum standards for evaluating the integrity and safety of pipeline assets and facilities by requiring certain periodic inspections.

Integrity Management

Due to the impact of PHMSA regulations and oversight, the potential fines for non-compliance at both federal and state levels and the excessive unplanned costs associated with spill remediation, all of which can negatively impact a pipeline’s performance, pipeline operators are compelled to develop and implement comprehensive integrity management programs. An integrity management program is a set of safety management, analytical, operations, and maintenance processes that are implemented to assure that operators provide protection for locations where a pipeline failure could have significant adverse consequences. An integrity management plan should also specifically address “high consequence areas,” or HCAs. HCAs include those areas that are unusually sensitive to environmental damage, that cross a navigable waterway or that have high population density.

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The elements of an integrity management program include:

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maintaining full documentation of the pipeline infrastructure for the lifespan of the asset;

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identifying all locations where a pipeline failure might impact an HCA;

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developing a risk-based plan to conduct integrity assessments on the portions of the pipeline that could affect an HCA;

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integrating the assessment results with other relevant information to improve the understanding of the pipe’s condition;

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repairing defects identified through the integrated analysis of the assessment results;

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conducting a risk analysis to identify the most significant pipeline threats in segments that can affect HCAs (for example, pipe defects, corrosion and excavation-induced damage);

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identifying additional measures to address the most significant pipeline threats, including actions to prevent and mitigate releases and can go beyond repairing the discovered defects;

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evaluating regularly all information about the pipeline and its location-specific integrity threats to determine when future assessments should be performed and what methods should be selected to conduct those assessments;

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documenting compliance with PHMSA and other government or regulatory authorities; and

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evaluating periodically the effectiveness of the integrity management program and identifying improvements to enhance the level of protection, generating safety programs and emergency response plans and communicating a set of best practices to personnel involved in the construction, operation, maintenance and repair of its pipeline infrastructure.

Inspection and Integrity Services

The diagram below illustrates an array of inspection and integrity services that may be provided to operators of pipelines and related assets.

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In-line Inspection. Pipeline inspection primarily applies non-destructive examination, or NDE, methods to ensure asset integrity. NDE is the examination of pipeline assets without impacting the future usefulness of the assets. The examination method also allows for minimum operational interruption of the assets undergoing inspection.

A common device used in the NDE of pipeline infrastructure is a pipeline inspection gadget, or pig. A pig is a cylindrical device that is introduced into the pipeline and is transported through the pipe typically without interrupting operations. Pigs perform a variety of functions inside the pipe, including debris and condensate cleaning, plugging, product separation, hydrotesting, dewatering and inspection. Inspecting pigs, referred to as in-line inspection pigs, or smart pigs, contain testing devices and collect information while traveling through the pipeline.

Pig inspection can take days to weeks depending on the length and condition of the pipeline being inspected. While the pig is traveling through the pipeline, inspectors must track the location of the pig and catalog data from the pig. The results of pig testing are used by the pipeline operator to determine anomalies and sections of the pipeline targeted to undergo further examination.

[GRAPHIC MISSING]

Pig running through pipeline.

Other Non-Destructive Examination (NDE) Inspection. In addition to pigging, modern NDE incorporates a variety of inspection methods performed by skilled personnel to test for structural flaws. These inspection methods may include: visual and optical testing (including aerial flyover), radiography, magnetic particle testing, ultrasonic testing, penetrant testing, electromagnetic testing, leak testing and acoustic emission testing. Skilled technicians are used to perform these types of NDE inspection of pipeline assets, as many methods use high specification machinery.

Data and Integrity Program Management Services. Smart pigs and other NDE inspection methods generate large quantities of data that need to be maintained, integrated and evaluated as part of the pipeline operators’ integrity management program. Independent inspectors can assist pipeline operators in maintaining data and generating documentation relating to the operators’ integrity management program and the associated construction, operation, inspection, maintenance, repair and regulatory compliance activities.

Staking Services. The locations along the pipeline where the pig identifies potential anomalies must be marked with stakes in preparation of additional testing or maintenance work. Inspectors mark the locations with an above ground marker consisting of a steel pin and survey lathe. The inspector also records the GPS coordinates of the location. The stakes are used by the pipeline operator to establish dig sites along the pipeline route to carry out the necessary maintenance work. Once a maintenance plan is formulated, the pipeline operator will hire a specialized construction team to begin the maintenance program.

Construction and Repair Management. Inspectors will work with pipeline operators’ management and employees to supervise all stages of construction and repair projects to ensure industry and regulatory standards are met. An inspector’s role in construction and repair oversight can include:

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Dig site excavation oversight and documentation;

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Defect assessments and mapping/surveying, including corrosion, dents, third-party damage, stress corrosion cracking, lamination, ultrasonic and NDE oversight;

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Repair documentation, including recoat, sleeve (permanent or temporary) or pipe replacement; and

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Documentation gathering and report assimilation, including client reports, photographs, defect rubbings (permanent record of repaired defect), safety meetings and PHMSA mandated records that must be kept for the life of the pipeline.

Regulation. PHMSA has authority over pipeline safety for interstate lines and retains responsibility for enforcement. However, PHMSA can designate a state to act as its agent in the inspection of interstate lines. Additionally, certain Federal statutes specifically allow states to assume responsibility for most regulation of intrastate pipelines through an annual certification. To do so, states must adopt regulations that are consistent with existing federal regulations.

Pursuant to the Natural Gas Pipeline Safety Act of 1968, or NGPSA, and the Hazardous Liquid Pipeline Safety Act of 1979, or HLPSA, as amended by the Pipeline Safety Act of 1992, or PSA, the Accountable Pipeline Safety and Partnership Act of 1996, or APSA, the Pipeline Safety Improvement Act of 2002, or PSIA, the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, or the PIPES Act, and the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011, or the 2011 Pipeline Safety Act, the Department of Transportation, or DOT, through the PHMSA, regulates pipeline safety and integrity. Among other items, these regulations require the operators of covered pipelines to:

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perform ongoing assessments of pipeline integrity;

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identify and characterize applicable threats to pipeline segments that could impact an HCA;

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improve data collection, integration and analysis;

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repair and remediate the pipeline as necessary; and

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implement preventive and mitigating actions.

In 2010, serious pipeline incidents focused the attention of Congress and the public on pipeline safety. Legislative proposals were introduced in Congress to strengthen PHMSA’s enforcement and penalty authority, and expand the scope of its oversight. On January 3, 2012, the 2011 Pipeline Safety Act was signed into law. The 2011 Pipeline Safety Act amends the NGPSA and HLPSA in a number of significant ways, including:

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authorizing PHMSA to assess higher penalties for violations of its regulations;

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significantly limiting the applicability of a “grandfather clause” which effectively provided exemptions from certain testing and inspection requirements for natural gas pipelines constructed before 1970;

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requiring PHMSA to adopt appropriate regulations within two years requiring the use of automatic or remote-controlled shutoff valves on new or rebuilt pipeline facilities and to perform a study on the application of such technology to existing pipeline facilities in HCAs;

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requiring operators of pipelines to verify maximum allowable operating pressure and report violations within five days;

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requiring PHMSA to study and report on the adequacy of soil cover requirements in HCAs; and

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requiring PHMSA to evaluate in detail whether integrity management requirements should be expanded to pipeline segments outside of HCAs (where the requirements currently apply).

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On August 13, 2012, PHMSA published a proposed rulemaking consistent with the 2011 Pipeline Safety Act that, once finalized, will increase the maximum administrative civil penalties for violation of the pipeline safety laws and regulations after January 3, 2012 to $200,000 per violation per day, with a maximum of $2,000,000 for a related series of violations. In addition, PHMSA published a final rule in May 2011 expanding pipeline safety requirements, including added reporting obligations and integrity management standards to certain rural low-stress hazardous liquid pipelines that were not previously regulated in such manner. On August 25, 2011, PHMSA published an advanced notice of proposed rulemaking regarding changes to gas transmission pipeline regulation which considered, among other items, strengthening integrity management plan requirements and expanding the definition of HCAs to bring more pipeline mileage under integrity management, and strengthening and expanding other requirements related to valve spacing, corrosion control, and underground gas storage caverns. PHMSA has also published advanced notices of proposed rulemaking to solicit comments on the need for additional changes to its safety regulations, including whether to extend the integrity management requirements to additional types of facilities, such as gathering pipelines and related facilities. PHMSA recently published an advisory bulletin providing guidance on verification of records related to pipeline maximum allowable operating pressure, which could result in additional pressure testing of pipelines or the reduction of maximum operating pressures. PHMSA has also issued guidance stating that it will focus near-term enforcement efforts on recordkeeping and integrity management, following recommendations by the National Transportation Safety Board.

We believe this climate of increasingly stringent regulation and the significant increase in penalties for violations of safety requirements embodied in the 2011 Pipeline Safety Act will cause pipeline operators to increase the number and types of pipeline inspections they conduct, and thereby increase demand for third-party inspection and integrity services.

Customers and Sources of Revenue. Independent inspection and integrity services providers have a diverse customer base that is largely dictated by the current regulatory environment. Key customer groups include:

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Midstream pipeline companies. Traditional midstream companies own and operate the pipeline networks and associated facilities that connect hydrocarbon producing regions with refiners, distributors and terminal users. Midstream companies are historically the largest consumers of independent inspection and integrity services and work closely with inspectors to maintain annual inspection programs to ensure assets remain in compliance.

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Oil and natural gas exploration and production companies, or producers. Oil and natural gas producers often control the gathering system associated with its producing wells and are responsible for maintaining recurring inspection programs to meet regulatory compliance. Pipe used in gathering systems has a smaller diameter than mainline pipeline systems, and prior to the Pipeline Transportation Safety Improvement Act of 2011, were subject to less scrutiny than larger diameter pipeline assets.

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Local Distribution Companies, or LDCs, and Public Utility Companies, or PUCs. LDCs and PUCs operate and maintain the infrastructure associated with localized distribution of public services, including natural gas, to residential, commercial, industrial and government end-users. LDCs and PUCs represent a small but growing component of independent inspection and integrity services customer base, as recent high profile accidents involving infrastructure maintained by LDCs and PUCs has increased independent oversight of recurring inspection programs.

Customers typically pay the independent provider a fee consisting of a daily or hourly rate for the provider’s inspection and integrity services 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 a per diem for inspectors’ other expenses. Generally, reimbursable and per diem expenses are invoiced to customers by service providers at cost (without any profit margin). Some customers

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agree to pay the inspector seven days per week and others only pay six days per week despite the fact they are in the field near the jobsite and away from their permanent residence.

Pipeline Inspection and Integrity Services Industry Trends

We believe that the following trends will increase the demand for pipeline inspection and integrity services:

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Growing oil and natural gas infrastructures. Increasing U.S. oil and natural gas production requires commensurate investment in infrastructure to process and transport the oil and natural gas from producing regions to end markets.

The Interstate Natural Gas Association of America, or INGAA, has estimated that an average of 1,400 miles of mainline natural gas transmission pipeline, 800 miles of oil transmission pipeline, 500 miles of NGL transmission pipeline, 16,500 miles of natural gas gathering lines and 550 miles of natural gas laterals connecting power plants, processing facilities and storage fields will be constructed per annum from 2012 through 2035, for a total investment in oil and natural gas infrastructure in North America of more than $200 billion.

The increase in oil and natural gas infrastructure investment will result in higher spending on inspection and integrity services as the incremental pipeline infrastructure will be subject to regulatory oversight and mandatory inspection programs.

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Aging pipeline and related infrastructures. According to the INGAA, more than 60.0% of all active U.S. pipeline infrastructure was installed more than four decades ago. Aging pipeline infrastructure is more susceptible to failures such as external corrosion, rain/flood damage, excavation damage, manufacturing defects, component defects, weld defects and stress corrosion cracking.

Percentage of Pipe Mileage Installed By Decade

[GRAPHIC MISSING]

Source: INGAA, November 2012.

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Increased regulatory oversight. Owners and operators of pipelines and related infrastructure assets face increasingly stringent government regulations and safety requirements. Failure to meet these standards can result in a higher level of scrutiny by regulators, reduced volumes of activity and lost revenue, significant financial liabilities in the forms of fines, higher insurance premiums and damage payouts, tarnished corporate brand value and, in some cases, civil and criminal liability. As a result, owners and

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operators are seeking highly reliable independent service providers with a proven track record of providing inspection and integrity services on a broad basis to assist them in meeting the increasingly stringent regulations and safety requirements.

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BUSINESS

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. We also provide independent pipeline inspection and integrity services to producers and pipeline companies. In both of these business segments, we work closely with our customers to help them comply with increasingly complex and strict environmental and safety rules and regulations and reduce their operating costs.

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On a pro forma basis after giving effect to this offering and the related restructuring transactions, for the year ended December 31, 2012 and the nine months ended September 30, 2013, respectively, we generated $9.5 million and $11.4 million in gross margin in our Water and Environmental Services segment. For the nine months ended September 30, 2013, we disposed of an average of approximately 53,000 barrels of water per day, approximately 75% of which was produced water. For the month ended September 30, 2013, we operated our SWD wells at approximately 42% of estimated aggregate capacity.

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In our Pipeline Inspection and Integrity Services segment, which is comprised of the historical operations of TIR, including the 49.9% interest not being contributed to us, we provide independent inspection and integrity services to various energy, public utility and pipeline companies. TIR’s inspectors 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, maintenance and repair projects. Our results in the Pipeline Inspection and Integrity Services segment are driven primarily by the number and type of inspectors performing services for TIR’s customers and the fees TIR charges for those services, which depend on the nature and duration of the project.

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Business Strategies

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Capitalize on compelling industry fundamentals.

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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. Additionally, we believe that increasingly complex environmental and safety rules and regulations and a focus by oil and natural gas producers on their core operations and capital deployment contribute to producers increasingly outsourcing their water management needs. 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.

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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. U.S. oil and natural gas producers, public utility and local distribution companies and midstream pipeline operators are required by federal and state laws to have adopted comprehensive compliance programs in order to inspect their pipeline assets on a regular basis in order to protect the environment and ensure the public safety. Over the last few years, new laws have been enacted 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 the U.S. was installed decades ago and is therefore more susceptible to failure and requires more frequent inspections. We believe that increasingly stringent 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. In addition, customers are concentrating on their core operations and finding it more cost efficient to manage compliance needs through third-party, expert service providers.

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Optimize existing assets. All of our SWD facilities have been constructed since June 2011. We estimate that we were using approximately 42% of the aggregate estimated capacity of these facilities for the month ended September 30, 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 will lead to increased gross margin and operating cash flow in our Water and Environmental Services segment. New oil and natural gas wells that are actively being drilled near our existing SWD facilities will generate additional flowback water upon completion and produced water for the lives of those new producing wells. We believe that capturing these new volumes will significantly enhance our profitability and distributable cash flow.

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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

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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. Three of our SWD facilities currently receive piped produced water from producers, and one producer is in the process of building pipelines to our SWD facilities. We expect this new pipeline to begin delivering saltwater into our SWD facility the first quarter of 2014. We are also in the process of negotiating for the construction of several additional systems. We believe that development of these pipeline connections will further integrate us with the operations of producing customers and enhance our ability to serve their increasing water and environmental needs.

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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. We also plan to invest capital to acquire and construct more SWD facilities and related service assets in the regions where we currently operate. Our track record in the oil and natural gas industry and role as manager of third-party SWD facilities provides us with additional opportunities to grow our relationships with customers and other SWD facility owners, which we believe may provide additional acquisition opportunities. In addition, we intend to grow our Pipeline Inspection and Integrity Services segment by acquiring additional ownership interests in TIR 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 interest in TIR. 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.

Competitive Strengths

We believe that we are well-positioned to successfully execute our business strategies because of the following competitive strengths:

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High-quality and high-capacity SWD facilities located in active oil and natural gas producing regions. Our Water and Environmental Services segment’s operations are currently located in two of the most active oil and natural gas producing regions in the U.S., the Bakken Shale region of the Williston Basin in North Dakota and the Permian Basin in west Texas. Substantially all of the wells now being completed in these regions utilize hydraulic fracturing and generate a significant amount of both flowback and

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produced water needing disposal. We strategically position our water and environmental services assets in these regions close to oil and natural gas wells that we believe, based on our thorough research and analysis, will generate significant amounts of saltwater. Additionally, because we own the land for the majority of our SWD facilities, we do not incur royalty fees or face lease renewal risks on these facilities, which provides us with an advantage over competitors that lease the land for their SWD facilities. Finally, in most locations we own more land than required to operate the SWD facilities. This provides us the opportunity to add additional SWD wells at our existing facilities should demand in the area require additional storage capacity.

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Independent pipeline inspection and integrity business that serves some of the largest pipeline customers in the U.S. Our pipeline inspection and integrity services customers include some of the largest pipeline companies in the U.S., including DCP Midstream, Enbridge Energy Partners and Enterprise Products Partners. TIR provides its customers throughout the U.S. with inspectors that have the experience, training, certifications and other attributes that are most appropriate to the customer’s specific needs on a job-by-job basis. Due to our extensive customer relationships, TIR is able to attract qualified inspectors by offering attractive compensation and benefits and a more stable work environment with a larger number of projects than smaller competitors. This advantage is evident in the long-term nature of the customer relationships in this segment. For example, TIR has customers that date to its founding ten years ago. We believe the benefits of the long-term customer relationships are enhanced as TIR’s familiarity with its customers’ assets and specific service needs reduce a customer’s likelihood of switching to a new service provider.

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Focus on regulatory compliance and safety in our operations. We perform internal audits of our existing SWD facilities using third-party safety consultants and have a comprehensive environmental performance and safety compliance approach. We strive to achieve environmental and regulatory compliance “best practices” across all of our facilities and services, and we believe that our strong safety and environmental record increases the demand for our services among producers who seek providers that meet their strict requirements. Many of our facilities have been chosen by our customers after they complete thorough reviews of our facility and operations, which we believe further solidifies our reputation for safety and regulatory excellence. Additionally, we believe customers select TIR based on its experience, reputation and comprehensive approach to safety, compliance and training. We expect our reputation, along with our experience, safety and regulatory compliance record and quality of service offered, to facilitate strong long-term relationships with our saltwater disposal customers.

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U.S. We believe that their knowledge of the industry, relationships within the industry and experience in identifying, evaluating and completing acquisitions will provide us opportunities to execute our strategies successfully and to grow through strategic and accretive acquisitions that complement or expand our existing operations.

Our Business Segments

We operate our business in two segments, Water and Environmental Services and Pipeline Inspection and Integrity Services. On a pro forma basis after giving effect to this offering and the related restructuring transactions described under “Summary — The Restructuring Transactions,” for the year ended December 31, 2012 and the nine months ended September 30, 2013, respectively, we generated $9.5 million and $11.4 million in gross margin in our Water and Environmental Services segment, and TIR, in which we will own a 50.1% interest, generated $18.0 million and $21.5 million in gross margin in our Pipeline Inspection and Integrity Services segment.

Water and Environmental Services

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. We also manage four other SWD facilities and own a majority interest in our affiliate that owns a 25.0% non-controlling interest in one of these SWD facilities. We have obtained all necessary permits for an additional SWD facility in Prairie Lakes, North Dakota and are currently working toward obtaining permits for additional facilities at some of our existing locations. Our Water and Environmental Services segment is comprised of the historical business of the CEP Successor.

Operations. Our Water and Environmental Services segment currently generates revenue by offering the following services:

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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.

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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

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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.

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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.

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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, including one in which CES owns a 25.0% non-controlling interest, 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.

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Construction management of new SWD facilities. We currently act as the construction manager for one third-party SWD facility, which we will also manage once the construction is 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, which contributes to our relatively stable and predictable cash flows. For the nine months ended September 30, 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 by our employees. Our locations in North Dakota currently include onsite offices and housing for our employees. In Texas, we have an office and housing for management at our Pecos, Texas facility. We supplement our manned operations with various automated technologies to improve their efficiency and safety. We either have or are currently installing 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.

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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 September 30, 2013.

[GRAPHIC MISSING]

(a)

Only one month of operations.

Areas of operation. Our owned and leased facilities are located in the Bakken Shale region of the Williston Basin in North Dakota and the Permian Basin in west Texas.

As of September 30, 2013, we had an aggregate of approximately 135,500 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
Green River, 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, which owns a 25.0% non-controlling interest in this SWD facility.

In addition, we intend to construct or acquire SWD facilities in new locations of high-growth resource plays throughout the U.S. In evaluating possible locations for new SWD facilities, we consider a number of factors, including the location of existing and expected drilling and production activity; the presence of competing SWD services providers; the number, size and financial strength of associated producers; the geological characteristics of the area; access to

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power infrastructure and roads or pipelines for transportation; and the ability to obtain the necessary permits to conduct operations. The locations on which we actually drill or acquire new SWD wells will ultimately depend upon the availability of capital, regulatory approvals, costs, actual drilling results and other factors. See “Risk Factors — Risks Related to Our Business — Our ability to grow in the future is dependent on our ability to access external growth capital.”

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 the first nine months of 2013, we had approximately 210 customers in our Water and Environmental Services segment. Our ten largest customers generated approximately 68% of our Water and Environmental Services segment revenue for the year ended December 31, 2012 and 56% of water and environmental services revenue for the nine months ended September 30, 2013.

Contracts. Many oil and natural gas producers choosing providers of sensitive environmental services engage in rigorous screening, which may include site inspections, and the process may take three to six months. We have been approved by companies such as Royal Dutch Shell, Occidental Petroleum and ExxonMobil.

Once we are approved by a customer, we enter into a master services agreement with them, if they so require. Under these agreements, the customer is not committed to deliver a particular volume of water to our SWD facilities or pay us a fixed fee. Rather, the agreements set forth the terms on which we will handle the water that the customer chooses to deliver to us, billing and approval requirements, insurance requirements and the payments we will receive for our services. We are typically paid a per barrel fee for the treatment and disposal of saltwater streams. As long as we remain competitive on service and price, we believe the risk of a customer ceasing to deliver us water for disposal is mitigated by several key characteristics of our business, particularly the proximity of our facilities to the region’s well sites, the lack of suitable alternative providers and facilities, the time and expense associated with the inspection and approval process that some of our customers require prior to utilizing the services of an environmental solutions service provider and our track record as the environmental solutions provider of choice for many of our customers.

Pricing of saltwater disposal varies by the type of saltwater, method of transport and disposal and location. Currently, we are focused on the disposal of flowback and produced water, and we are paid on a per barrel basis that varies based on competitive dynamics and operating costs of each regional market. We currently receive higher prices per barrel for flowback water than produced water in North Dakota, and roughly equivalent per barrel prices for flowback and produced water in the Permian Basin. The Permian Basin is a more developed basin with large quantities of oil and natural gas wells that have been producing for many years and offers a larger labor pool and fewer weather-related issues than North Dakota. We expect that as a particular market matures, differential pricing for flowback and produced water will be replaced with flat per barrel fees for both types of saltwater.

Our subsidiary CES manages four SWD facilities in North Dakota that we do not own pursuant to management services agreements. Under these agreements, CES supervises and manages the development and day-to-day operations of SWD wells, as well as assists in operational issues, such as training, and developing and implementing a marketing plan. These agreements have five or ten-year terms and will automatically renew for an additional five or ten-year term. CES is generally paid a monthly fee equal to the greater of a percentage of gross revenue or a fixed dollar amount. CES is also reimbursed by the SWD well owner for services provided by CES’s on-site SWD well manager as well as other staff based on an average hourly rate, including overtime. CES generally does not assume any liabilities associated with or incident to the operation of the SWD well except in the case of negligence or deliberate misconduct.

Pipeline Inspection and Integrity Services

Overview. We believe that through our ownership of TIR we are a leading provider of independent inspection and integrity services to pipeline industry. TIR provides services for the

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pipelines, gathering systems, local distribution systems, equipment and facilities of its well established customer base. We provide inspection and integrity services to U.S. 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. TIR’s approximately 46 pipeline inspection and integrity customers include oil and natural gas producers, pipeline owners and operators and public utility companies throughout the U.S.

TIR offers independent inspection services for the following facilities and equipment:

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Transmission pipelines (oil, gas and liquids);

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Oil and natural gas gathering systems;

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Pump and compressor stations;

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Storage facilities and terminals; and

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Gas distribution systems.

Operations. U.S. 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.

At the beginning of an engagement, TIR’s personnel meet with the customer to determine the scope of the project and related staffing needs. TIR then develops a customized, detailed staffing plan utilizing its proprietary database of more than 8,000 professionals. TIR’s inspectors generally 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. TIR’s customers require inspectors to undergo specific training prior to performing inspection work on their projects. TIR utilizes 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. Through the three months ended September 30, 2013, TIR employed an average of 1,529 inspectors, up approximately 70% and 145% from the three months ended September 30, 2012 and September 30, 2011, respectively.

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TIR’s scope of services includes the following;

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

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

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

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

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

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 the continental U.S. During the three months ended September 30, 2013, TIR had 46 customers. The five largest customers in this business segment generated approximately 71% of our segment revenue for the year ended December 31, 2012 and 74% of segment revenue for the nine months ended September 30, 2013. For the year ended December 31, 2012 and the nine months ended September 30, 2013, the following three pipeline inspection and integrity services customers accounted for more than 10% of our revenue, on a pro forma condensed combined basis: DCP Midstream, Enbridge Energy Partners and Enterprise Product Partners.

Contracts. We typically enter into master services contracts with our pipeline and integrity customers. Pursuant to our master services agreements, TIR’s customers typically pay TIR a fee comprised of a daily or hourly rate (plus a profit margin) for its pipeline inspection service personnel. The daily or hourly rate depends upon the inspector’s skills, certifications and years of experience and is paid six or seven days per week, depending upon the customer. Pursuant to the master services agreements, the customers also reimburse certain expenses of the inspectors, including mileage for travel to the project, and pay the inspector’s per diem expense. These reimbursable and per diem expenses are passed on to the customers at cost. Under applicable accounting rules, we include the customer’s reimbursement of these expenses in our revenue and expenses, which has the effect of diluting our gross margin. The service personnel typically travel to projects in their own vehicles. While performing work on a project, an inspector is an employee of TIR, and they are covered under our insurance programs. Although TIR pays its inspectors on a weekly basis, its invoices are not paid until 30 to 90 days following the provision of services. In order to fund its inspectors, TIR requires substantial working capital, for which it has obtained a factoring facility secured by its accounts receivable. TIR historically has had no bad debt expense and has the ability to place a lien on a customer’s pipeline assets in the event the customer fails to pay for rendered services. TIR historically has not charged interest on past due invoices or require collateral by its customers. In excess of 35.0% of TIR’s revenue is attributable to per diem and other reimbursement expenses for which there is no associated gross margin.

Our History

Through the acquisition of the assets and operations that comprise Cypress Energy Partners, LLC and our acquisition of a 50.1% interest in and control of TIR, we created a business providing water and environmental services and pipeline inspection and integrity services to the U.S. energy industry.

Cypress Energy Partners, LLC was founded in 2012 and commenced field operations in the Bakken region of the Williston Basin in North Dakota through our acquisition of various divisions of SBG Energy Services, LLC, or SBG, in December 2012. Through SBG, we acquired: (i) six newly constructed EPA Class II SWD facilities (five of which will be contributed to us at the close of this offering); (ii) one SWD facility permit; (iii) right to acquire a majority interest and all of SBG Disposal Management, LLC that includes a 25.0% interest in an additional managed SWD facility under construction; and (iv) certain other contractual rights under an omnibus option agreement,

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as discussed under “Certain Relationships and Related Party Transactions — Agreements with Affiliates — SBG Omnibus Agreement.” In December 2012, we acquired four newly constructed EPA Class II SWD facilities from Moxie Disposal Systems, LLC, and Peach Energy Services, LLC in two in North Dakota and two in west Texas.

In June 2013, Cypress Holdings and its affiliates acquired control of TIR Parent and currently own 50.25% on a fully diluted basis. Cypress Holdings intends to acquire the remaining interest in TIR Parent prior to the closing of this offering and to contribute 50.1% of that interest of TIR to us at the closing of the offering. With more than 1,400 professional certified inspectors currently deployed, we believe that TIR is the largest provider of independent inspectors to the pipeline industry. TIR was founded in 2003.

Our Relationship with Cypress Holdings

Employees

We do not have any 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 September 30, 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 will 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. Please read “Certain Relationships and Related Party Transactions — Agreements Governing the Restructuring Transactions — Omnibus Agreement.” In addition, as of September 30, 2013, TIR employed 1,604 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. Following the completion of this offering, CEM will be party to a joint venture with SBG Energy Services, LLC pursuant to which CEM will own a 51.0% equity interest in Cypress Energy Partners – Bakken Operations, LLC, or Bakken Operations, and SBG Energy Services will own the remaining 49.0% equity interest. As of September 30, 2013, Bakken Operations employed approximately 44 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.

Competition

Water Management 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

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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 disposal 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. TIR’s 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

Our 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. Seasonality is not a major factor in the Permian Basin in West Texas.

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 PUCs in California and other locations with moderate climates, the seasonality of our inspection and integrity business will decline. The second and third quarters tend to be the most active quarters for our pipeline inspection services because weather conditions in some regions in which our customers maintain pipeline assets make it difficult to inspect those assets during the winter months. We believe our presence across various regions in the U.S. 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.

Insurance

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

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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.

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.

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.

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, 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

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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.

We also accept for disposal solid that are subject to the requirements of 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 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 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.

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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 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.

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 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

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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.

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 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.

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 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

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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, 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.” 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, 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 by 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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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 by 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 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.

Headquarters

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 10,650 square feet of general office space at its corporate headquarters. The lease expires on June 30, 2018 unless terminated earlier under certain circumstances specified in our lease. TIR Parent also leases space located at Anahuac, Texas, Bakersfield, California, Mountain House, California and Calgary, Alberta. The combined square feet of these general office space leases approximates 12,000 square feet. These leases expires at varying dates on between May 31, 2015 and July 31, 2017, unless terminated earlier under certain circumstances specified in our leases.

Legal Proceedings

From time to time we may be involved in litigation relating to claims arising out of our operations in the normal course of business. We are not currently party to any legal proceedings that we believe would have a material adverse effect on our financial position, results of operations or cash flows.

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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.

Following the closing of this offering, we expect that our general partner will have at least four directors. Cypress Holdings will appoint all members to the board of directors of our general partner. In accordance with the NYSE’s phase-in rules, we will have one independent director on the date that our common units are first listed on the NYSE and three independent directors within one year of that date. We anticipate that our board of directors will determine that John T. McNabb II is independent under the independence standards of the NYSE.

Neither we nor our subsidiaries have any employees. 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 prospectus as our employees.

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 will have 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 will have an audit committee comprised of at least three directors who meet the independence and experience standards established by the NYSE and the Exchange Act. Our general partner initially may rely on the phase-in rules of the NYSE and the SEC with respect to the independence of our audit committee. Those rules permit our general partner to have an audit committee that has one independent member by the date our common units are first listed on the NYSE, a majority of independent members within 90 days thereafter and all independent members within one year thereafter. In connection with his appointment to the board, we expect that John T. McNabb II will serve as a member and chairman of our audit committee. 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

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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.

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. In connection with his appointment to the board of directors, we expect that John T. McNabb II will serve as a member and chairman of the conflict 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, director nominees and executive officers of our general partner.


Name	Age	Position with Cypress Energy Partners GP, LLC
Peter C. Boylan III	49	Chairman of the Board, President and Chief Executive Officer
G. Les Austin	47	Vice President and Chief Financial Officer
Richard 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
John T. McNabb II	69	Director Nominee
Phil Gisi	53	Director Nominee
Charles C. Stephenson, Jr.	78	Director Nominee

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

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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.

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.

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 Carson is Vice President and General Counsel, having served in that capacity since September 2013. Mr. Carson also currently serves as a director, officer and shareholder of Gable & Gotwals, an Oklahoma law firm, where he practices securities, corporate finance, transactional and environmental law, primarily for clients in the energy industry, including several master limited partnerships. Mr. Carson intends to resign his position as director, officer and shareholder of Gable & Gotwals on January 1, 2014 in order to serve our Partnership in a full-time capacity. 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

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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 of Controller and Chief Accounting Officer of Cypress Energy Partners GP, LLC, having served in that capacity since September 2013. Mr. LaBass has served VP Controller and Chief Accounting Officer 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.

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.

John T. McNabb II is a director nominee to the board of Cypress Energy Partners GP, LLC, and will be appointed to the board prior to the close of this offering and will serve as Chairman of our audit and conflicts committees. 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 seven 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 suit him to serve as a director.

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Phil Gisi is a director nominee to the board of Cypress Energy Partners GP, LLC, and will be appointed to the board at the close of this offering. Mr. Gisi has served as a director of Cypress LLC since the acquisition of SBG 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 EdgewoodVista 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 ND. 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.

Charles C. Stephenson, Jr. is a director nominee to the board of Cypress Energy Partners GP, LLC, and will be appointed to the board at the close of this offering. 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 also 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.

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.

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Compensation of Our Officers and Directors

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 employs all of 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. See “Our Partnership Agreement — Reimbursement of Expenses.” However, we sometimes refer to the employees and officers of our general partner as our employees and officers in this prospectus.

This executive compensation disclosure provides an overview of the executive compensation program for our named executive officers identified below for 2012, during which we had limited operating activities. For the year ended December 31, 2012, our named executive officers, or our NEOs, who were our only executive officers during 2012 and as of December 31, 2012 were:

•

Peter C. Boylan III, our President and Chief Executive Officer; and

•

G. Les Austin, our Vice President and Chief Financial Officer.

Summary Compensation Table For 2012

The following table sets forth certain information with respect to the compensation paid to our NEOs for the year ended December 31, 2012.


Name and Principal Position	Year		Salary		Unit Awards			All Other Compensation			Total
Peter C. Boylan III President and Chief Executive Officer		2012	$	187,500		—		$	18,983 (2	)	$	206,483
G. Les Austin Senior Vice President and Chief Financial Officer		2012	$	43,750	$	200,000 (1	)		—		$	243,750

(1)

Represents an award of Class C Units in Cypress LLC granted to Mr. Austin in connection with his commencement of employment in 2012. 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 6 to the Consolidated Financial Statements of Cypress LLC for the year ended December 31, 2012, included elsewhere in this prospectus.

(2)

Represents cash payments provided for healthcare premiums for Mr. Boylan in 2012. These payments were made in lieu of our providing any health or welfare benefits during 2012.

Narrative Disclosure to Summary Compensation Table and Additional Narrative Disclosure

Elements of the compensation program. Due to our limited operating history in 2012, compensation for our NEOs was limited to base salary and an initial equity award granted to Mr. Austin. Neither of our NEOs was eligible for an annual bonus or received any other compensation items in, 2012.

Base compensation for 2012. 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 base salary increases since their commencement of employment with us. However, following the consummation of this offering, we anticipate that our NEOs will be eligible for periodic salary increases and that their salaries may be increased from

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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:


Name and Principal Position	Current Base Salary
Peter C. Boylan III President and Chief Executive Officer	$	250,000
G. Les Austin Vice President and Chief Financial Officer	$	175,000

Discretionary long-term equity incentive award. 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. In connection with this offering, the Class C Units in Cypress LLC will be converted in common and subordinated units in us on an equivalent value basis, based on the per unit price in this offering. Based on the midpoint of pricing range set forth on the cover page of this prospectus, Mr. Austin’s Class C Units would convert into approximately common and subordinated units in us. The Class C units were, and the common and subordinated units into which the Class C Units will be converted, will be subject to a five year vesting schedule, with one third of the units vesting on the each of the third, fourth and fifth anniversaries of the date the Class C Units were initially granted.

For additional information regarding the common and subordinated units in us expected to be held by our executive officers immediately following the consummation of this offering, see the discussion and tables below under the heading “Security Ownership and Certain Beneficial Owners and Management.”

In anticipation of our initial public offering, we intend to adopt 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 “Our 2013 Long-Term Incentive Plan” below.

Outstanding Equity Awards at December 31, 2012

The following table provides information regarding the outstanding and unvested Class C Units in Cypress LLC held by Mr. Austin as of December 31, 2012. None of our NEOs held any option awards that were outstanding as of December 31, 2012.


	Unit Awards
Name	Number of Units That Have not Vested (#)			Market Value of Units That Have Not Vested ($) (3)
Peter C. Boylan III (1)		—			—
G. Les Austin.		20,000 (2	)	$	200,000

(1)

Mr. Boylan held no unvested equity awards as of December 31, 2012. As our Co-Founder, he owns part of Cypress Holdings.

(2)

Represents the number of Class C Units in Cypress LLC, which are scheduled to vest in three equal annual installments on each of October 1, 2015, 2016 and 2017. The units will be converted on an equivalent value basis into common and subordinated units in us.

(3)

Amount shown reflects an estimate of the fair value of the Class C Units as of December 31, 2012, as determined by our general partner.

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 this offering.

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The terms of Mr. Austin’s award of Class C Units provides that in the event of a change in control of Cypress LLC, his units would become fully vested, effective as of immediately prior to such change in control. Following the consummation of this offering and the conversion of these units into common and subordinated units in us, Mr. Austin’s units will vest in full upon a change in control of us or our general partner.

Executive compensation following the consummation of this offering. Following the consummation of this offering, 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 intend to provide a basic benefits package available to all full-time employees, which will include a 401(k) plan and medical, dental, disability and life insurance. 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, 2012, 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.

Following the consummation of this offering, 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. Following the consummation of this offering, 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.

Although the terms of our expected director compensation program have not yet been determined, we expect such compensation may consist of the following:

•

an annual cash retainer of $25,000, payable quarterly,

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•

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, and

•

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,

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.

Equity Compensation Plans

Our 2013 Long-Term Incentive Plan

Our general partner intends to adopt the LTIP 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 that are currently expected to be included in 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 common units, 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, such as TIR). 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

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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.

Unit options and unit appreciation rights. The LTIP may also permit the grant of options covering common units. Unit options represent the right to purchase a number of common units at a specified exercise price. Unit appreciation rights represent the right to receive the appreciation in the value of a number of common units over a specified exercise price, either in cash or in common units. Unit options and unit appreciation rights may be granted to such eligible individuals and with such terms as the administrator of the LTIP may determine, consistent with the LTIP; however, a unit option or unit appreciation right must have an exercise price equal to at least the fair market value of a common unit on the date of grant.

Unit awards. Awards covering common units may be granted under the LTIP with such terms and conditions, including restrictions on transferability, as the administrator of the LTIP may establish.

Profits interest units. Awards granted to grantees who are partners, or granted to grantees in anticipation of the grantee becoming a partner or granted as otherwise determined by the administrator, may consist of profits interest units. The administrator will determine the applicable vesting dates, conditions to vesting and restrictions on transferability and any other restrictions for profits interest awards.

Other unit-based awards. The LTIP may also permit the grant of “other unit-based awards,” which are awards that, in whole or in part, are valued or based on or related to the value of a common unit. The vesting of an other unit-based award may be based on a participant’s continued service, the achievement of performance criteria or other measures. On vesting or on a deferred basis upon specified future dates or events, an other unit-based award may be paid in cash and/or in units (including restricted units), or any combination thereof as the administrator of the LTIP may determine.

Source of common units. Common units to be delivered with respect to awards may be newly-issued units, common units acquired by us or our general partner in the open market, common units already owned by our general partner or us, common units acquired by our general partner directly from us or any other person or any combination of the foregoing.

Certain transactions. The administrator of the LTIP will have broad discretion to equitably adjust the provisions of the LTIP and the terms and conditions of existing and future awards, including with respect to the aggregate number and type of units subject to the LTIP and awards granted pursuant to the LTIP, to prevent the dilution or enlargement of intended benefits and/or facilitate necessary or desirable changes in the event of certain transactions and events affecting our units, such as unit splits, mergers, acquisitions, consolidations and other extraordinary transactions. In the case of certain events or changes in capitalization that could result in additional compensation expense to us or our general partner if adjustments to awards with respect to such event were discretionary, then equitable adjustments will be non-discretionary. The

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administrator of the LTIP may also provide for the acceleration, cash-out, termination, assumption, substitution or conversion of awards in the event of certain unusual or nonrecurring events or transactions.

Amendment or termination of long-term incentive plan. The administrator of the LTIP, at its discretion, may terminate the LTIP at any time with respect to the common units for which a grant has not previously been made. The administrator of the LTIP also has the right to alter or amend the LTIP or any part of it from time to time or to amend any outstanding award made under the LTIP, provided that no change in any outstanding award may be made that would materially impair the vested rights of the participant without the consent of the affected participant or result in taxation to the participant under Section 409A of the Code.

Conversion of equity awards in connection with this offering. Prior to consummation of this offering, Cypress LLC granted equity-based awards to certain of our key employees, other than our named executive officers, which awards were generally intended to provide for the grantees to share in the future equity appreciation of Cypress LLC. The awards are all currently unvested and will vest in three equal installments on the third, fourth and fifth anniversaries of the respective grant dates. In connection with the consummation of this offering, these awards will be assumed by us and will converted on an equivalent value basis into phantom units with corresponding distribution equivalent rights in us and will be considered for all purposes to have been granted under the LTIP. The number of phantom units and distribution equivalent rights that will be issued in respect of these awards will be determined generally based upon the initial public offering price per unit in this offering. Based on the midpoint of the range set forth on the cover page of this prospectus, the total number of phantom units (with distribution equivalent rights) to be issued in connection with the conversion of these awards in connection with this offering is expected to be approximately .

TIR’s 2013 Equity Incentive Plan

In connection with the acquisition by Cypress Holdings of TIR Parent, TIR Parent has adopted the TIR Parent 2013 Equity Incentive Plan, or the “TIR Plan,” the purpose of which is to enhance TIR Parent’s ability to attract, retain and motivate selected employees, consultants and directors of TIR Parent through the granting of equity-based compensation awards in TIR Parent. The material terms of and important information relating to the TIR Plan are summarized below.

Eligibility and administration. Employees, consultants and directors of TIR and its affiliates who provide services with respect to TIR will be eligible to receive awards under the TIR Plan. The board of directors of TIR will administer the TIR Plan unless it chooses to delegate such authority consistent with applicable law. Subject to the express terms and conditions of the TIR Plan, the plan administrator has the authority to make all determinations and interpretations under the TIR Plan, prescribe all forms for use with the plan and adopt, amend and/or rescind rules for the administration of the TIR Plan. The plan administrator also sets the terms and conditions of all awards under the TIR Plan, including any vesting and vesting acceleration conditions.

Awards and award limitations. Initially, the aggregate number of TIR shares available for issuance pursuant to awards granted under the TIR Plan will represent approximately 5.0% of the total outstanding equity interests in TIR. TIR shares which are forfeited, expire or lapse for any reason, or are settled for cash without the delivery of shares will again be available for issuance under the TIR Plan to the extent of such forfeiture, expiration, lapse or cash settlement.

The TIR Plan provides for the grant of stock options (including non-qualified stock options, or NQSOs, and incentive stock options, or ISOs), restricted stock, dividend equivalents, restricted stock units and other stock-based awards, however, TIR has not previously granted any awards under the TIR Plan other than non-qualified options. Awards under the TIR Plan are generally set forth in award agreements, which detail the terms and conditions of the awards, including any applicable vesting and payment terms and post-termination exercise limitations. In connection

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with the consummation of this offering, TIR is being converted to a limited liability company and awards under the TIR Plan will be adjusted to cover common units in TIR in connection with such conversion.

Outstanding awards under the TIR Plan. As of , 2013, there were outstanding non-qualified options to purchase approximately shares in TIR, which represents approximately % of the total outstanding equity interests in TIR. These options were granted with an exercise price generally equal to the per share price at which Cypress Holdings initially acquired control of TIR in June 2013 and will vest over a period of time following such acquisition.

Amendment and termination. TIR’s board of directors may terminate amend or modify the TIR Plan at any time and from time to time, provided that no amendment of the TIR Plan may materially and adversely affect any then outstanding award without the consent of the affected Participant. The TIR Plan will automatically expire and terminate on the tenth anniversary of its adoption by TIR. Any award that is outstanding on the expiration date of the TIR Plan will remain in force according to the terms of the TIR Plan and the applicable award agreement.

Certain transactions. The plan administrator of the TIR Plan has broad discretion to equitably adjust the provisions of the TIR Plan and the terms and conditions of existing and future awards under the TIR Plan, including with respect to the aggregate number and type of shares or equity interests subject to the TIR Plan and awards granted pursuant to the TIR Plan, in each case to prevent the dilution or enlargement of intended benefits and/or to facilitate necessary or desirable changes in the event of certain transactions and events affecting TIR’s equity interests, such as equity dividends or distributions, equity splits, mergers, acquisitions, consolidations and other corporate transactions or other unusual or non-recurring events or transactions, such as, for example, a sale or transfer of equity interests in TIR by or among TIR’s equity holders. In connection with these types of transactions, the plan administrator of the TIR Plan may provide for the acceleration, cash-out, termination, assumption, substitution or conversion of awards into awards of an acquiror or successor or an affiliate. The types of transactions where these adjustments or substitutions may occur will include, for example, a future acquisition by us of additional equity interests in TIR from Cypress Holdings or another holder. We expect that, in the event we acquire additional equity interests in TIR, the board of directors of our general partner and the plan administrator of the TIR Plan may provide for the conversion of outstanding awards under the TIR Plan and shares remaining available for issuance under the TIR Plan into awards in us and relating to our common units granted under our LTIP, in each case in accordance with the substitution and assumption provisions of our LTIP and the TIR Plan. The number of common units in us that would be issued or issuable in connection with or as a result of such assumption and substitution would be based on the number of shares or other equity interests in TIR then issuable pursuant to awards previously granted or remaining available to be granted under the TIR Plan, as adjusted to reflect the difference in fair market value between one equity interest in TIR and one common unit in us as of the date of such assumption and substitution. For additional information regarding the assumption and substitution provisions of our LTIP, please read “— Equity Compensation Plans — Our 2013 Long-Term Incentive Plan — Substitute Awards.”

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SECURITY OWNERSHIP AND CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of units of Cypress Energy Partners, L.P. that will be issued upon the consummation of this offering and the related restructuring transactions and held by beneficial owners of 5.0% or more of the units, by each director, director nominee and named executive officer of Cypress Energy Partners GP, LLC, our general partner, and by all directors, director nominees and executive officers of our general partner as a group, assuming the underwriters’ option to purchase additional common units from us is not exercised. The percentage of units beneficially owned is based on a total of common units and subordinated units outstanding immediately following this offering.

The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. In computing the number of common units beneficially owned by a person and the percentage ownership of that person, common units subject to options or warrants held by that person that are currently exercisable or exercisable within 60 days of , 2013, if any, are deemed outstanding, but are not deemed outstanding for computing the percentage ownership of any other person. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.

The following table does not include any common units that directors, director nominees and executive officers of our general partner may purchase in this offering through the directed unit program described under “Underwriting.”

Name of Beneficial Owner

Common Units to be Beneficially Owned

Percentage of Common Units to be Beneficially Owned

Subordinated Units to be Beneficially Owned

Percentage of Subordinated Units to be Beneficially Owned

Percentage of Total Common Units and Subordinated Units to be Beneficially Owned

Cypress Energy Holdings, LLC (1)

Cypress Energy Partners — TIR, LLC (2)

Peter C. Boylan III

G. Les Austin

Richard Carson

Jeff English

Don LaBass

Jim Dowdy

John T. McNabb II

Phil Gisi

Charles C. Stephenson, Jr.

All directors, director nominees and executive officers as a group (consisting of 8 persons)

An asterisk indicates that person or entity owns less than one percent.

(1)

Cypress Energy Holdings, LLC owns 100.0% of Cypress Holdings II, LLC, which owns 100.0% of our general partner. Following this offering, Cypress Energy Holdings, LLC will own, indirectly through its ownership of Cypress Holdings II, LLC, % of our common units and of our subordinated units. The following table sets forth the beneficial ownership of Cypress Energy Holdings, LLC after this offering:

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Name of Beneficial Owner	Voting Ratio (a)
Cynthia A. Field Trust (b)		37.4	%
Charles C. Stephenson, Jr.		28.0	%
CEP Capital Partners, LLC		25.0	%
Lawrence D. Field, Jr. Trust – 2007 (b)		1.6	%
Alex S. Field Trust – 2007 (b)		1.6	%
Andrew M. Field Trust – 2007 (b)		1.6	%
Corry C. Stephenson Trust – 2007 (b)		1.6	%
Kelly C. Stephenson Trust – 2007 (b)		1.6	%
Julie A. Stephenson Trust – 2007 (b)		1.6	%

(a)

Cypress Energy Holdings, LLC is managed by a — member board of directors consisting of . The election of each director requires the affirmative vote of members representing at least a majority of the voting ratio of Cypress Energy Holdings and the concurrence of CEP Capital.

(b)

Voting rights of the trust are exercised by Cynthia A. Field, as trustee.

(2)

Cypress Energy Holdings, LLC owns 100.0% of Cypress Energy Investments, LLC, which owns 100.0% of Cypress Energy Partners — TIR, LLC.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

After this offering, the general partner and its affiliates will own common units and subordinated units, representing a % limited partner interest in us. If the underwriters’ option to purchase additional common units is exercised in full, our general partner and its affiliates will own common units and subordinated units, representing a % limited partner interest in us. In addition, our general partner will own a 0.0% non-economic general partner interest in us.

Distributions and Payments to Our General Partner and Its Affiliates

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the formation, ongoing operation, and liquidation of Cypress Energy Partners, L.P. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.

Formation Stage

The consideration received by our general partner and its affiliates prior to or in connection with this offering for the contribution of the assets and liabilities
to us

•

common units (or common units if the underwriters’ option to purchase additional common units is exercised in full);

•

subordinated units;

•

0.0% non-economic general partner interest;

•

the incentive distribution rights; and

•

a cash payment of approximately $ million from the proceeds of this offering.

Operational Stage

Distributions of available cash to our general partner and its affiliates

We will generally make cash distributions to the unitholders pro rata, including Cypress Holdings, as holder of an aggregate of common units and subordinated units. In addition, if distributions exceed the minimum quarterly distribution and target distribution levels, the incentive distribution rights held by our general partner will entitle our general partner to increasing percentages of the distributions, up to % of the distributions above the highest target distribution level.

Assuming we generate sufficient distributable cash flow to support the payment of the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner and its affiliates would receive an annual distribution of approximately $ million on their common units and subordinated units (or $ million if the underwriters exercise in full their option to purchase additional common units from us).

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Payments to our general partner and its affiliates

Under our partnership agreement, we are required 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. Except to the extent specified under our omnibus agreement, our general partner determines the amount of these expenses and such determinations must be made in good faith under the terms of our partnership agreement. Under our omnibus agreement, we will reimburse our general partner a fixed $3.0 million fee for expenses incurred by it and their respective affiliates in providing certain corporate overhead services to us, including the provision of executive management services by certain officers of our general partner. These reimbursable expenses also include an allocable portion of the compensation and benefits of employees and executive officers of other affiliates of our general partner who provide services to us. Please read “— Agreements Governing the Restructuring Transactions — Omnibus Agreement” below and “Management — Compensation of Our Officers and Directors.”

Withdrawal or removal of our general partner

If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. Please read “Our Partnership Agreement — Withdrawal or Removal of Our General Partner.”

Liquidation Stage

Liquidation

Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

Agreements Governing the Restructuring Transactions

We and other parties will enter into the various agreements that will affect the restructuring transactions, including the vesting of assets in, and the assumption of liabilities by, us and our subsidiaries, and the application of the proceeds of this offering. While not the result of arm’s-length negotiations, we believe the terms of all of our initial agreements with Cypress Holdings will be, and specifically intend the rates to be, generally no less favorable to either party than those that could have been negotiated with unaffiliated parties with respect to similar services. All of the transaction expenses incurred in connection with these transactions, including the expenses associated with transferring assets into our subsidiaries, will be paid for with the proceeds of this offering.

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Omnibus Agreement

In conjunction with the closing of this offering, we will enter into an omnibus agreement with our general partner and Cypress Holdings. Pursuant to the omnibus agreement, Cypress Holdings will grant us a right of first offer to acquire certain of its assets should Cypress Holdings desire to sell them, including the remaining interests in TIR held by Cypress Holdings and its affiliates. In addition, we will have a right of first offer to purchase certain assets that Cypress Holdings may purchase or construct in the future, including assets it may acquire from SBG. Additionally, the omnibus agreement will provide that our general partner has the sole responsibility for providing certain personnel necessary to conduct our operations, whether through directly hiring employees or by obtaining the services of personnel employed by its subsidiary CEM, its affiliates or others. Under the omnibus agreement, our general partner will provide certain general and administrative services for us in exchange for a fixed fee of $3.0 million per year during the term of the omnibus agreement.

Contribution Agreement

In connection with the closing of this offering, we will enter into a contribution agreement with Cypress Holdings and certain of its subsidiaries that will effect the restructuring transactions described under “Summary — The Restructuring Transactions,” including the transfer of Cypress LLC to us and the use of the net proceeds of this offering.

Agreements with Affiliates

Relationships with SBG

One of our director nominees, Phil Gisi, is also a director and executive officer of SBG and SBG Disposal LLC, affiliates of SBG. As discussed below, we have commercial arrangements with SBG, SBG Disposal LLC and Rud Transportation LLC, and we believe the terms of these transactions are similar to what would have been obtained from an unaffiliated third party.

SBG Management Services Agreement

On December 31, 2012, Cypress Holdings, acting through one of its subsidiaries, entered into a management services agreement with SBG Disposal LLC. Pursuant to this agreement, SBG Disposal LLC will provide day-to-day oversight, management, development, construction and operations of the seven SWD facilities we acquired from SBG Energy Services, LLC. SBG Disposal LLC will contribute this agreement to CES, which is owned 49.0% by SBG Disposal LLC. All personnel providing such services will generally be employees of SBG Disposal LLC or those of its subcontractors. This agreement has a five year term that will automatically renew for 90 day periods unless terminated by either party with written notice. SBG Disposal LLC will be paid a monthly fee equal to 4.75% of gross revenues in addition to reimbursable expenses such as direct staffing expenses and supplies. Generally, each party to the agreement will indemnify the other party from losses resulting from the death or personal injury of its own employees, unless caused by the negligence or breach of duty of the other party. Furthermore, SBG Disposal LLC will be required to pay for and maintain worker’s compensation insurance, commercial general liability insurance, business automobile insurance, and umbrella/excess liability insurance, each with minimum coverage amounts.

SBG Option Agreement

On December 31, 2012, Cypress Holdings, acting through one of its subsidiaries, entered into an option agreement with SBG. Pursuant to this agreement, SBG, the sole member of SBG Disposal, LLC, granted Cypress Holdings the option to purchase 51.0% of the membership interest in SBG Disposal, LLC for $500,000. In lieu of exercising this option to purchase membership interest in SBG Disposal, LLC, we decided to enter into a joint venture with SBG Disposal, LLC, as described below.

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Cypress Energy Services Joint Venture

In November 2013, CEP Successor became a party to a joint venture with SBG Energy Services, LLC pursuant to which it owns a 51.0% equity interest in CES and SBG Energy Services owns the remaining 49.0% equity interest. Pursuant to the joint venture agreement, SBG Disposal, LLC contributed its fixed assets, including a 25.0% non-controlling interest in an SWD facility in Watford City, North Dakota and five management services agreements related to its management of 11 SWD facilities in North Dakota, seven of which we own. In exchange, SBG received its 49.0% membership interest in CES, $500,000 and the termination of our option to acquire 51.0% membership interest in SBG Disposal, LLC under the option agreements discussed above. Effective October 1, 2013, CES assumed the management of the 11 SWD facilities previously managed by SBG Disposal, LLC. Phil Gisi, our director nominee, is a co-founder and controlling owner of SBG Energy Services.

SBG Omnibus Option Agreement

On December 31, 2012, Cypress Holdings, acting through one of its subsidiaries, entered into an omnibus option agreement with SBG and its owners, including Philip Gisi. Pursuant to this agreement, Cypress Holdings has the first right to negotiate with the owners of SBG if they decide to sell the membership interest in SBG. The agreement also provides Cypress Holdings with the first right to negotiate with SBG if SBG decides to sell any of the following assets:

•

its membership interest in Rud Transportation LLC, a wholly owned subsidiary of SBG that owned 25 tractor and trailers engaged in hauling water to and from producers in North Dakota, which grew to our 75 tractor and trailers, as of September 30, 2013; and

•

all of SBG’s right to any water pipeline construction, development or acquisition opportunity.

•

all of SBG’s interest in its gas and diesel wholesale venture.

We also acquired the right to purchase certain other assets that we do not anticipate exercising.

The first rights to negotiate described above continue in each case until December 31, 2017. Pursuant to the omnibus option agreement, the option price to purchase the first 5.0% of SBG is $10 per membership unit of SBG. In addition, the option price to purchase the first 5.0% of any of the other assets set forth in the omnibus option agreement is set at 5.0% of the actual cost the owners of such asset expended to acquire the asset. In addition, the omnibus option agreement provides Cypress Holdings with a right of first refusal to match the terms on which SBG intends to sell one of the above-listed assets to a third party if Cypress Holdings is unable to reach an agreement to buy that asset from SBG in the first instance. Please see Note 3 to Consolidated Financial Statements of Cypress Energy Partners, LLC for the year ended December 31, 2012 for further information regarding the options discussed above, as well as the other options under the omnibus option agreement that we do not anticipate exercising.

Assignment and Assumption Agreements

On November 7, 2013, the lenders of the mezzanine facilities irrevocably assigned and sold to TIR Capital Partners, LLC, or TIR Capital, all of the lenders’ rights and obligations under the mezzanine facilities, and TIR Capital irrevocably purchased and assumed all of such rights and obligations for approximately $20 million. Upon the closing of this offering, TIR will be required to pay TIR Capital, as the new lender under the mezzanine facilities, approximately $ of monthly interest arising from the two facilities, based on an outstanding balance of $ . TIR Capital is owned jointly by our Chief Executive Officer, Peter C. Boylan III, and one of our director nominees, Charles C. Stephenson, Jr.

Mr. Boylan’s Sharing Interest in Cypress Holdings

In connection with the formation of Cypress Holdings, as a co-founder, Mr. Boylan, our President and Chief Executive Officer was issued a limited liability company interest in

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Cypress Holdings, based upon his arms’ length negotiation with Charles C. Stephenson, Jr., the other co-founder of Cypress Holdings. The terms of Mr. Boylan’s limited liability company interest provide that Mr. Boylan will initially receive a 5.0% sharing interest in the profits and losses of Cypress Holdings and in any distributions made by Cypress holdings in respect of its equity securities, which sharing interest shall increase to 25.0% effective on the earlier of April 1, 2015 or the occurrence of certain events or transactions relating to our business or to Mr. Boylan’s employment with us, which events include an initial public offering of our equity securities. As a result, Mr. Boylan’s sharing interest in Cypress Holdings will be increased to 25.0% in connection with the consummation of this offering.

Procedures for Review, Approval and Ratification of Related Person Transactions

The board of directors of our general partner will adopt a related party transactions policy in connection with the closing of this offering that will provide that the board of directors of our general partner or its authorized committee will review on at least a quarterly basis all related person transactions that are required to be disclosed under SEC rules and, when appropriate, initially authorize or ratify all such transactions. In the event that the board of directors of our general partner or its authorized committee considers ratification of a related person transaction and determines not to so ratify, the code of business conduct and ethics will provide that our management will make all reasonable efforts to cancel or annul the transaction.

The related party transactions policy will provide that, in determining whether or not to recommend the initial approval or ratification of a related person transaction, the board of directors of our general partner or its authorized committee should consider all of the relevant facts and circumstances available, including (if applicable) but not limited to: (1) whether there is an appropriate business justification for the transaction; (2) the benefits that accrue to us as a result of the transaction; (3) the terms available to unrelated third-parties entering into similar transactions; (4) the impact of the transaction on a director’s independence (in the event the related person is a director, an immediate family member of a director or an entity in which a director or an immediate family member of a director is a partner, shareholder, member or executive officer); (5) the availability of other sources for comparable products or services; (6) whether it is a single transaction or a series of ongoing, related transactions; and (7) whether entering into the transaction would be consistent with the code of business conduct and ethics.

The related party transactions policy described above will be adopted in connection with the closing of this offering, and as a result the transactions described above were not reviewed under such policy.

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CONFLICTS OF INTEREST AND DUTIES

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates on the one hand, and us and our unaffiliated limited partners, on the other hand. The directors and executive officers of our general partner have fiduciary duties to manage our general partner in a manner that is in the best interests of its owners. At the same time, our general partner has a fiduciary duty to manage us in a manner that is in the best interests of our partnership.

Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or any other partner, on the other, our general partner will resolve that conflict. Our general partner may seek the approval of such resolution from the conflicts committee of the board of directors of our general partner or from our unitholders, but is not required to do so. There is no requirement under our partnership agreement that our general partner seek the approval of the conflicts committee or our unitholders for the resolution of any conflict, and, under our partnership agreement, our general partner may decide to seek such approval or resolve a conflict of interest in any other way permitted by our partnership agreement, as described below, in its sole discretion. The board of directors of our general partner will decide whether to refer a matter to the conflicts committee or to our unitholders on a case-by-case basis. In determining whether to refer a matter to the conflicts committee or to our unitholders for approval, the board of directors of our general partner will consider a variety of factors, including the nature of the conflict, the size and dollar amount involved, the identity of the parties involved and any other factors the board of directors deems relevant in determining whether it will seek approval from the conflicts committee or our unitholders. Whenever the board of directors of our general partner makes a determination to refer or not to refer any potential conflict of interest to the conflicts committee for approval or to seek or not to seek unitholder approval, the general partner is acting in its individual capacity, which means that it may act free of any duty or obligation whatsoever to us or our unitholders and will not be required to act in good faith or pursuant to any other standard or duty imposed by our partnership agreement or under applicable law, other than the implied contractual covenant of good faith and fair dealing. For a more detailed discussion of the duties applicable to our general partner, as well as the implied contractual covenant of good faith and fair dealing, please read “— Duties of the General Partner.”

Our general partner will not be in breach of its obligations under our partnership agreement or its duties to us or our unitholders if the resolution of the conflict is:

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approved by the conflicts committee, which our partnership agreement defines as “special approval”;

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approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;

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on terms no less favorable to us than those generally being provided to or available from unrelated third-parties; or

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fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.

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. If our general partner does not seek approval from the conflicts committee or our unitholders and our general partner’s board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the

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board of directors 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. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the conflicts committee of our general partner’s board of directors may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to subjectively believe that he is acting in a manner that is in the best interests of the partnership or that the determination or other action meets the specified standard, for example, a transaction on terms no less favorable to us than those generally being provided to or available from unrelated third-parties, or is “fair and reasonable” to us. In taking such action, such person may take into account the totality of the circumstances or the totality of the relationships between the parties involved, including other relationships or transactions that may be particularly favorable or advantageous to us. If that person has the required subjective belief, then the decision or action will be conclusively deemed to be in good faith for all purposes under our partnership agreement.

It is possible, but we believe it is unlikely, that our general partner would approve a matter that the conflicts committee has previously declined to approve or declined to recommend that the full board of directors approve. If the conflicts committee does not approve or does not recommend that the full board of directors approve a matter that has been presented to it, then, unless the board of directors of our general partner has delegated exclusive authority to the conflicts committee, the board of directors of our general partner may subsequently approve the matter. In such a case, although the matter will not have received “special approval” under our partnership agreement, the board of directors of our general partner could still determine that the resolution of the conflict of interest satisfied another standard under our partnership agreement, for example, that the resolution was on terms no less favorable to us than those generally being provided to or available from unrelated third-parties or was fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us. Please read “Management — Management of Cypress Energy Partners, L.P. — Conflicts Committee” for information about the conflicts committee of our general partner’s board of directors.

Conflicts of interest could arise in the situations described below, among others.

Affiliates of our general partner, including Cypress Holdings and its affiliates, may compete with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us.

Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner (or as general partner of another company of which we are a partner or member) or those activities incidental to its ownership of interests in us. However, affiliates of our general partner, including Cypress Holdings and its affiliates, are not prohibited from engaging in other businesses or activities, including those that might compete 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 its executive officers, directors and Cypress Holdings and its affiliates. 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. Therefore, Cypress Holdings and its affiliates may compete with us for acquisition opportunities and may own an interest in entities that compete with us.

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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.

Our partnership agreement contains provisions that reduce and modify the standards to which our general partner would otherwise be held by state fiduciary duty law. 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 duty or obligation to us and our unitholders, other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the parties where language in our partnership agreement does not provide for a clear course of action. When acting in its individual capacity, our general partner is entitled 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 or any limited partner. Examples of decisions that our general partner may make in its individual capacity include the allocation of corporate opportunities among us and our affiliates, the exercise of its limited call right, its voting rights with respect to the units it owns and its registration rights, and its determination whether or not to consent to any merger, consolidation or conversion of the partnership or amendment to our partnership agreement.

Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, and limits our general partner’s liabilities and the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty under applicable Delaware law.

In addition to the provisions described above, our partnership agreement contains provisions that restrict the remedies available to our limited partners for actions that might constitute breaches of fiduciary duty under applicable Delaware law. For example, our partnership agreement:

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permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. When acting in its individual capacity, our general partner is entitled to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us or any limited partner. Examples of decisions that our general partner may make in its individual capacity include: (1) how to allocate business opportunities among us and its other affiliates; (2) whether to exercise its limited call right; (3) how to exercise its voting rights with respect to the units it owns; (4) whether to sell or otherwise dispose of units or other partnership interests that it owns; (5) whether to elect to reset target distribution levels; (6) whether to consent to any merger or consolidation of the partnership or amendment to our partnership agreement; and (7) whether to refer or not to refer any potential conflict of interest to the conflicts committee for special approval or to seek or not to seek unitholder approval;

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provides that the general partner will have no liability to us or our limited partners for decisions made in its capacity as a general partner so long as such decisions are made in good faith;

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generally provides that in a situation involving a transaction with an affiliate or other conflict of interest, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of another conflict of interest is not approved by our public common unitholders or the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest is either on terms no less favorable to us than those generally being provided to or available from unrelated third-parties or is “fair and reasonable” to us, considering the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us, then it will be presumed that in making its decision, the board of directors of our

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general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us challenging such decision, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption; and

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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 or directors, as the cases may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful.

By purchasing a common unit, a common unitholder will be deemed to have agreed to become bound by the provisions in our partnership agreement, including the provisions discussed above.

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

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval, on such terms as it determines to be necessary or appropriate to conduct our business including, but not limited to, the following:

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the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into our securities, and the incurring of any other obligations;

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the purchase, sale or other acquisition or disposition of our securities, or the issuance of additional options, rights, warrants and appreciation rights relating to our securities;

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the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets;

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the negotiation, execution and performance of any contracts, conveyances or other instruments;

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the distribution of our cash;

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the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

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the maintenance of insurance for our benefit and the benefit of our partners;

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the formation of, or acquisition of an interest in, the contribution of property to, and the making of loans to, any limited or general partnership, joint venture, corporation, limited liability company or other entity;

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the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity, otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense, the settlement of claims and litigation;

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the indemnification of any person against liabilities and contingencies to the extent permitted by law;

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the making of tax, regulatory and other filings, or the rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets;

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the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner; and

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the composition of our directors and executive officers.

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Our partnership agreement provides that our general partner must act in good faith when making decisions on our behalf in its capacity as our general partner, and our partnership agreement further provides that in order for a determination to be made in good faith, our general partner must subjectively believe that the determination is in the best interests of our partnership. In making such determination, our general partner may take into account the totality of the circumstances or the totality of the relationships between the parties involved, including other relationships or transactions that may be particularly favorable or advantageous to us. When our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act free of any duty or obligation to us or our limited partners, other than the implied contractual covenant of good faith and fair dealing. Please read “Our Partnership Agreement — Voting Rights” for information regarding matters that require unitholder approval.

Actions taken by our general partner may affect the amount of cash available for distribution to unitholders or accelerate the right to convert subordinated units.

The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:

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the amount and timing of asset purchases, entry into joint ventures, other growth projects and sales;

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cash expenditures;

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borrowings;

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the issuance of additional units; and

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the creation, reduction or increase of reserves in any quarter.

Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner and the ability of the subordinated units to convert into common units.

In addition, our general partner may use an amount, initially equal to $ million, which would not otherwise constitute available cash from operating surplus, in order to permit the payment of cash distributions on its units and incentive distribution rights. All of these actions may affect the amount of cash distributed to our unitholders and our general partner and may facilitate the conversion of subordinated units into common units. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of:

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enabling our general partner or its affiliates to receive distributions on any subordinated units held by them or the incentive distribution rights; or

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accelerating the expiration of the subordination period.

For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our partnership agreement permits us to borrow working capital funds, which would enable us to make this distribution on all outstanding units. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — Subordinated Units and Subordination Period.”

Our partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may not borrow funds from us, or our operating company and its operating subsidiaries.

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We will reimburse our general partner and its affiliates for expenses.

We will reimburse our general partner and its affiliates, including CEM and Cypress Holdings, for costs incurred in managing and operating us. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in good faith, and it will charge on a fully allocated cost basis for services provided to us. Our omnibus agreement with Cypress Holdings also addresses our payment of annual amounts to, and our reimbursement of, our general partner and its affiliates for these costs and services. Please read “Certain Relationships and Related Party Transactions.”

Contracts between us, on the one hand, and our general partner and its affiliates, on the other hand, will not be the result of arm’s-length negotiations.

Our partnership agreement allows our general partner to determine, in good faith, any amounts to pay itself or its affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Our general partner will determine, in good faith, the terms of any arrangements or transactions entered into after the close of this offering. While neither our partnership agreement nor any of the other agreements, contracts, and arrangements between us and our general partner and its affiliates are or will be the result of arm’s-length negotiations, we believe the terms of all of our initial agreements with our general partner and its affiliates will be, and specifically intend the rates to be, generally no less favorable to either party than those that could have been negotiated with unaffiliated parties with respect to similar services. Similarly, agreements, contracts or arrangements between us and our general partner and its affiliates that are entered into following the closing of this offering will not be required to be negotiated on an arm’s-length basis, although, in some circumstances, our general partner may determine that the conflicts committee may make a determination on our behalf with respect to such arrangements.

Our general partner and its affiliates will have no obligation to permit us to use any facilities or assets of our general partner and its affiliates, except as may be provided in contracts entered into specifically for such use. There is no obligation of our general partner and its affiliates to enter into any contracts of this kind.

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

Common units are subject to our general partner’s limited call right.

Our general partner may exercise its right to call and purchase common units, as provided in our partnership agreement, or may assign this right to one of its affiliates or to us. Our general partner may use its own discretion, free of any duty or liability to us or our unitholders, in determining whether to exercise this right. As a result, a common unitholder may have to sell his common units at an undesirable time or price. Please read “Our Partnership Agreement — Limited Call Right.”

Common unitholders will have no right to enforce obligations of our general partner and its affiliates under agreements with us.

Any agreements between us, on the one hand, and our general partner and its affiliates, on the other hand, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

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Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

The attorneys, independent registered public accounting firm and others who perform services for us have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or our conflicts committee and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.

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 our conflicts committee or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

Our general partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled 50.0% for each of the prior four consecutive calendar quarters and the amount of each 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 cash distributions at the time of the exercise of the reset election. Furthermore, our general partner has the right to transfer all or any portion of the 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. Following a reset election by our general partner, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per unit for the two calendar quarters immediately preceding the reset election (such amount is referred to as 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.

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; however, it is possible that our general partner could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our general partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our general partner may be experiencing, or may expect to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued common units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for the general partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then current business environment. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued common units to our general partner in connection with resetting the target distribution levels related to our general partner’s incentive distribution rights. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — General Partner Interest and Incentive Distribution Rights.”

Duties of the General Partner

The Delaware Act 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

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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 our partnership agreement does not provide for a clear course of action.

As permitted by the Delaware Act, our partnership agreement contains various provisions replacing the fiduciary duties that might otherwise be owed by our general partner with contractual standards governing the duties of our general partner and contractual methods of resolving conflicts of interest. We have adopted these provisions to allow our general partner or its affiliates to engage in transactions with us that would otherwise be prohibited by state-law fiduciary standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because the board of directors of our general partner has duties to manage our general partner in a manner that is in the best interests of its owners in addition to the best interests of our partnership. Without these provisions, our general partner’s ability to make decisions involving conflicts of interest would be restricted. These provisions enable our general partner to take into consideration the interests of all parties involved in the proposed action. These provisions also strengthen the ability of our general partner to attract and retain experienced and capable directors. These provisions disadvantage the common unitholders because they restrict the rights and remedies that would otherwise be available to such unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third-parties in addition to our interests when resolving conflicts of interest. The following is a summary of the fiduciary duties imposed on general partners of a limited partnership by the Delaware Act in the absence of partnership agreement provisions to the contrary, the contractual duties of our general partner contained in our partnership agreement that replace the fiduciary duties that would otherwise be imposed by Delaware laws on our general partner and the rights and remedies of our unitholders with respect to these contractual duties:

State law fiduciary duty standards

Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present unless such transactions were entirely fair to the partnership.

Partnership agreement modified standards

Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in good faith, meaning that it subjectively believed that the decision was in the best interests of our partnership, and our general partner will not be subject to any other standard under our partnership agreement or applicable law, other than the implied contractual covenant of good faith and fair dealing. If our general partner has the required subjective belief, then the decision or action will be conclusively deemed to be in good faith for all purposes under our

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partnership agreement. In taking such action, our general partner may take into account the totality of the circumstances or the totality of the relationships between the parties involved, including other relationships or transactions that may be particularly favorable or advantageous to us. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act free of any duty or obligation to us or our limited partners, other than the implied contractual covenant of good faith and fair dealing. These standards reduce the obligations to which our general partner would otherwise be held. Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a vote of unitholders or that are not approved by our conflicts committee must be: on terms no less favorable to us than those generally being provided to or available from unrelated third-parties; or “fair and reasonable” to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us). 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. If our general partner does not seek approval from our conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the board of directors, which may include board members affected by the conflict of interest, acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us challenging such approval, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which our general partner would otherwise be held.

In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that our general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful.

Rights and remedies of unitholders

The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to

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do so is not likely to succeed. These actions include actions against a general partner for breach of its fiduciary duties, if any, or of the partnership agreement.

By purchasing our common units, each common unitholder automatically agrees to be bound by the provisions in our partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

Under our partnership agreement, we must indemnify our general partner and its officers, directors and managers, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful. We also must provide this indemnification for criminal proceedings when our general partner or these other persons acted with no knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it met the requirements set forth above. To the extent that these provisions purport to include indemnification for liabilities arising under the Securities Act of 1933, or the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and therefore unenforceable. Please read “Our Partnership Agreement — Indemnification.”

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DESCRIPTION OF THE COMMON UNITS

The Units

The common units represent limited partner interests in us. The holders of common units, along with the holders of subordinated units, are entitled to participate in partnership distributions and are entitled to exercise the rights and privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units in and to partnership distributions, please read this section and “Cash Distribution Policy and Restrictions on Distributions.” For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read “Our Partnership Agreement.”

Transfer Agent and Registrar

Duties

will serve as the registrar and transfer agent for our common units. We will pay all fees charged by the transfer agent for transfers of common units, except the following that must be paid by our unitholders:

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surety bond premiums to replace lost or stolen certificates, or to cover taxes and other governmental charges in connection therewith;

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special charges for services requested by a holder of a common unit; and

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other similar fees or charges.

Unless our general partner determines otherwise in respect of some or all of any classes of our partnership interests, our partnership interests will be evidenced by book entry notation on our partnership register and not by physical certificates.

There will be no charge to our unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their respective stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or Removal

The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

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automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement;

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represents and warrants that the transferee has the right, power, authority and capacity to enter into our partnership agreement; and

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gives the consents, waivers and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and this offering.

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Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and transferable according to the laws governing the transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred common units.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the common unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

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OUR PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

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with regard to distributions of available cash, please read “Provisions of Our Partnership Agreement Relating to Cash Distributions”;

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with regard to the duties of our general partner, please read “Conflicts of Interest and Duties”;

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with regard to the transfer of common units, please read “Description of the Common Units — Transfer of Common Units”; and

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with regard to allocations of taxable income and taxable loss, please read “Material Federal Income Tax Consequences.”

Organization and Duration

Our partnership was organized in September 2013, and will have a perpetual existence unless terminated pursuant to the terms of our partnership agreement.

Purpose

Our purpose under the partnership agreement is limited to any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law; provided that our general partner shall not cause us to engage, directly or indirectly, in any business activity that our general partner determines would be reasonably likely to cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than the business of providing water and environmental services and pipeline inspection and integrity services, our general partner has no current plans to do so and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of our partnership or our limited partners, other than the implied contractual covenant of good faith and fair dealing. Our general partner is authorized in general to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “— Limited Liability.”

Voting Rights

The following is a summary of the unitholder vote required for the matters specified below. Matters that require the approval of a “unit majority” require:

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during the subordination period, the approval of a majority of the outstanding common units, excluding those common units held by our general partner and its affiliates, and a majority of the outstanding subordinated units, voting as separate classes; and

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after the subordination period, the approval of a majority of the outstanding common units.

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In voting their common units and subordinated units, our general partner and its affiliates will have no duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners, other than the implied contractual covenant of good faith and fair dealing.

Issuance of additional units

No approval rights.

Amendment of our partnership agreement

Certain amendments may be made by the general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “— Amendment of Our Partnership Agreement.”

Merger of our partnership or the sale of all or substantially all of our assets

Unit majority. Please read “— Merger, Consolidation, Conversion, Sale or Other Disposition of Assets.”

Dissolution of our partnership

Unit majority. Please read “— Termination and Dissolution.”

Continuation of our business upon dissolution

Unit majority. Please read “— Termination and Dissolution.”

Withdrawal of the general partner

Under most circumstances, the approval of unitholders holding at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of the general partner prior to , 2023, in a manner which would cause a dissolution of our partnership. Please read “— Withdrawal or Removal of Our General Partner.”

Removal of the general partner

Not less than 66 2/3% of the outstanding units, voting as a single class, including units held by our general partner and its affiliates. Please read “— Withdrawal or Removal of Our General Partner.”

Transfer of the general partner interest

Our general partner may transfer all, but not less than all, of its general partner interest in us without a vote of our unitholders to an affiliate or another person in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets to, such person. The approval of a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to , 2023. Please read “— Transfer of General Partner Interest.”

Transfer of incentive distribution rights

Our general partner may transfer any or all of its incentive distribution rights to an affiliate or another person without a vote of our unitholders. Please read “— Transfer of Incentive Distribution Rights.”

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Reset of incentive distribution levels

No approval right.

Transfer of ownership interests in our general partner

No approval right. Please read “— Transfer of Ownership Interests in Our General Partner.”

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that it otherwise acts in conformity with the provisions of our partnership agreement, its liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital it is obligated to contribute to us for its common units plus its share of any undistributed profits and assets. If it were determined, however, that the right, or exercise of the right of, by the limited partners as a group:

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to remove or replace our general partner;

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to approve some amendments to our partnership agreement; or

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to take other action under our partnership agreement;

constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us who reasonably believe that a limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their limited partner interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership, except that the fair value of property that is subject to a liability for which the recourse of creditors is limited is included in the assets of the limited partnership only to the extent that the fair value of that property exceeds that liability. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of its assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to it at the time it became a limited partner and that could not be ascertained from the partnership agreement.

Our subsidiaries conduct business in several states and we may have subsidiaries that conduct business in other states in the future. Maintenance of our limited liability as a member of our operating company may require compliance with legal requirements in the jurisdictions in which our operating company conducts business, including qualifying our subsidiaries to do business there.

Limitations on the liability of members or limited partners for the obligations of a limited liability company or limited partnership have not been clearly established in many jurisdictions. If, by virtue of our ownership interests in our operating subsidiaries or otherwise, it were determined that we were conducting business in any state without compliance with the applicable

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limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Issuance of Additional Securities

Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.

It is possible that we will fund acquisitions through the issuance of additional common units, subordinated units or other partnership interests. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership interests may dilute the value of the interests of the then-existing holders of common units in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, as determined by our general partner, may have special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity interests, which may effectively rank senior to the common units.

Our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership interests whenever, and on the same terms that, we issue those interests to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of the general partner and its affiliates, including such interest represented by common units and subordinated units, that existed immediately prior to each issuance. The other holders of common units will not have preemptive rights to acquire additional common units or other partnership interests.

Amendment of Our Partnership Agreement

General

Amendments to our partnership agreement may be proposed only by our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any duty or obligation whatsoever to us or our limited partners, including any duty to act in the best interests of us or the limited partners, other than the implied contractual covenant of good faith and fair dealing. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments

No amendment may be made that would, among other actions:

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enlarge the obligations of any limited partner without its consent, unless such is deemed to have occurred as a result of an amendment approved by at least a majority of the type or class of limited partner interests so affected; or

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enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without its consent, which consent may be given or withheld at its option.

The provisions of our partnership agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 90.0% of the outstanding units voting together as a single class (including units owned by our general partner and its affiliates). Upon the completion of this offering, excluding common units purchased by officers, directors and director nominees of our general partner and Cypress Holdings under our directed unit program, our general partner and its affiliates will own approximately % of the outstanding common and subordinated units (or % of the outstanding common and subordinated units if the underwriters exercise in full their option to purchase additional common units from us).

No Unitholder Approval

Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:

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a change in our name, the location of our principal office, our registered agent or our registered office;

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the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

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a change that our general partner determines to be necessary or appropriate to qualify or continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor any of our subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

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an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents or trustees, from in any manner, being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, each as amended, whether or not substantially similar to plan asset regulations currently applied or proposed by the U.S. Department of Labor;

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an amendment that our general partner determines to be necessary or appropriate in connection with the authorization or issuance of additional partnership interests;

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any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

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an amendment effected, necessitated or contemplated by a merger agreement or plan of conversion that has been approved under the terms of our partnership agreement;

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any amendment that our general partner determines to be necessary or appropriate to reflect and account for the formation by us of, or our investment in, any corporation, partnership or other entity, in connection with our conduct of activities permitted by our partnership agreement;

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a change in our fiscal year or taxable year and any other changes that our general partner determines to be necessary or appropriate as a result of such change;

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mergers with, conveyances to or conversions into another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the merger, conveyance or conversion other than those it receives by way of the merger, conveyance or conversion; or

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any other amendments substantially similar to any of the matters described in the clauses above.

In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partner if our general partner determines that those amendments:

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do not adversely affect in any material respect the limited partners considered as a whole or any particular class of partnership interests as compared to other classes of partnership interests;

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are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

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are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed or admitted to trading;

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are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or

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are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

Opinion of Counsel and Unitholder Approval

For amendments of the type not requiring unitholder approval, our general partner will not be required to obtain an opinion of counsel to the effect that an amendment will not affect the limited liability of any limited partner under Delaware law. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90.0% of the outstanding units voting as a single class unless we first obtain such an opinion of counsel.

In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of partnership interests in relation to other classes of partnership interests will require the approval of at least a majority of the type or class of partnership interests so affected. Any amendment that would reduce the percentage of units required to take any action, other than to remove our general partner or call a meeting of unitholders, must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the percentage sought to be reduced. Any amendment that would increase the percentage of units required to remove our general partner must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than 90.0% of outstanding units. Any amendment that would increase the percentage of units required to call a meeting of unitholders must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute at least a majority of the outstanding units.

Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

A merger, consolidation or conversion of our partnership requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interest of us or the limited partners, other than the implied contractual covenant of good faith and fair dealing.

In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions. Our general partner may, however, mortgage, pledge, hypothecate, or grant a security interest in all or substantially all of our assets without that approval. Our general partner may also sell any or all of our assets under a foreclosure or other realization upon those

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encumbrances without that approval. Finally, our general partner may consummate any merger with another limited liability entity without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in an amendment to our partnership agreement requiring unitholder approval, each of our units will be an identical unit of our partnership following the transaction and the partnership interests to be issued by us in such merger do not exceed 20.0% of our outstanding partnership interests immediately prior to the transaction.

If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, our general partner has received an opinion of counsel regarding limited liability and tax matters, and our general partner determines that the governing instruments of the new entity provide the limited partners and our general partner with the same rights and obligations as contained in our partnership agreement. The unitholders are not entitled to dissenters’ rights of appraisal under our partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

Termination and Dissolution

We will continue as a limited partnership until dissolved and terminated under our partnership agreement. We will dissolve upon:

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the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal followed by approval and admission of a successor;

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the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;

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the entry of a decree of judicial dissolution of our partnership; or

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there being no limited partners, unless we are continued without dissolution in accordance with the Delaware Act.

Upon a dissolution under the first clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:

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the action would not result in the loss of limited liability of any limited partner; and

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neither our partnership nor any of our subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue.

Liquidation and Distribution of Proceeds

Upon our dissolution, unless we are continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate to, liquidate our assets and apply the proceeds of the liquidation as described in “Provisions of Our Partnership Agreement Relating to Cash Distributions — Distributions of Cash Upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

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Withdrawal or Removal of Our General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to , 2023, without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after , 2023, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days’ written notice to the limited partners if at least 50.0% of the outstanding units are held or controlled by one person and its affiliates other than our general partner and its affiliates. In addition, our partnership agreement permits our general partner in some instances to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read “— Transfer of General Partner Interest” and “— Transfer of Incentive Distribution Rights.”

Upon voluntary withdrawal of our general partner by giving notice to the other partners, the holders of a unit majority may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period after that withdrawal, the holders of a unit majority agree to continue our business by appointing a successor general partner. Please read “— Termination and Dissolution.”

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66 2/3% of our outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units, voting as a separate class, and subordinated units, voting as a separate class. The ownership of more than 33 1/3% of the outstanding units by our general partner and its affiliates would give them the practical ability to prevent our general partner’s removal. At the closing of this offering, excluding common units purchased by certain of our officers, directors and other affiliates under our directed unit program, our general partner and its affiliates will own % of the outstanding common and subordinated units (or % of the outstanding common and subordinated units if the underwriters exercise in full their option to purchase additional common units from us).

Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of that removal:

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the subordination period will end, and all outstanding subordinated units will immediately and automatically convert into common units on a one-for-one basis;

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any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

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our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests as of the effective date of its removal.

In the event of removal of our general partner under circumstances where cause exists or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the

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option to require the successor general partner to purchase the general partner interest of the departing general partner and its incentive distribution rights for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner will become a limited partner and its general partner interest and its incentive distribution rights will automatically convert into common units pursuant to a valuation of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.

Transfer of General Partner Interest

Except for transfer by our general partner of all, but not less than all, of its general partner interest to (1) an affiliate of our general partner (other than an individual), or (2) another entity as part of the merger or consolidation of our general partner with or into such entity or the transfer by our general partner of all or substantially all of its assets to such entity, our general partner may not transfer all or any part of its general partner interest to another person prior to , 2023, without the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the transferee must assume, among other things, the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement, and furnish an opinion of counsel regarding limited liability and tax matters.

Our general partner and its affiliates may at any time transfer units to one or more persons, without unitholder approval, except that they may not transfer subordinated units to us.

Transfer of Ownership Interests in Our General Partner

At any time, Cypress Holdings and its affiliates may sell or transfer all or part of their membership interest in our general partner, to an affiliate or third party without the approval of our unitholders.

Transfer of Incentive Distribution Rights

At any time, our general partner may sell or transfer its incentive distribution rights to an affiliate or third party without the approval of the unitholders.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove Cypress Energy Partners GP, LLC as our general partner or otherwise change our management. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20.0% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates or any transferees of that person or group who are notified by our general partner that they will not lose their voting rights or to any person or group who acquires the units with the prior approval of the board of directors of our general partner. Please read “— Withdrawal or Removal of Our General Partner.”

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Limited Call Right

If at any time our general partner and its affiliates own more than 80.0% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of such class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10, but not more than 60, days’ written notice.

The purchase price in the event of this purchase is the greater of:

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the highest cash price paid by either our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and

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the current market price calculated in accordance with our partnership agreement as of the date three business days before the date the notice is mailed.

As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read “Material Federal Income Tax Consequences — Disposition of Common Units.”

Redemption of Ineligible Holders

In order to avoid any material adverse effect on the maximum applicable rates that can be charged to customers by our subsidiaries on assets that are subject to rate regulation by FERC or analogous regulatory body, the general partner at any time can request a transferee or a unitholder to certify or re-certify:

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that the transferee or unitholder is an individual or an entity subject to United States federal income taxation on the income generated by us; or

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that, if the transferee unitholder is an entity not subject to United States federal income taxation on the income generated by us, as in the case, for example, of a mutual fund taxed as a regulated investment company or a partnership, all the entity's owners are subject to United States federal income taxation on the income generated by us.

Furthermore, in order to avoid a substantial risk of cancellation or forfeiture of any property, including any governmental permit, endorsement or other authorization, in which we have an interest as the result of any federal, state or local law or regulation concerning the nationality, citizenship or other related status of any unitholder, our general partner may at any time request unitholders to certify as to, or provide other information with respect to, their nationality, citizenship or other related status.

The certifications as to taxpayer status and nationality, citizenship or other related status can be changed in any manner our general partner determines is necessary or appropriate to implement its original purpose.

If a unitholder fails to furnish the certification or other requested information with 30 days or if our general partner determines, with the advice of counsel, upon review of such certification or other information that a unitholder does not meet the status set forth in the certification, we will have the right to redeem all of the units held by such unitholder at the market price as of the date three days before the date the notice of redemption is mailed.

The purchase price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Any such promissory note will bear interest at the rate of 5.0% annually and be payable in three equal annual installments of principal and accrued interest, commencing one

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year after the redemption date. Further, the units will not be entitled to any allocations of income or loss, distributions or voting rights while held by such unitholder.

Meetings; Voting

Except as described below regarding a person or group owning 20.0% or more of any class of units then outstanding, record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.

Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or, if authorized by our general partner, without a meeting if consents in writing describing the action so taken are signed by holders of the number of units that would be necessary to authorize or take that action at a meeting where all limited partners were present and voted. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20.0% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage. The units representing the general partner interest are units for distribution and allocation purposes, but do not entitle our general partner to any vote other than its rights as general partner under our partnership agreement, will not be entitled to vote on any action required or permitted to be taken by the unitholders and will not count toward or be considered outstanding when calculating required votes, determining the presence of a quorum, or for similar purposes.

Each record holder of a unit has a vote according to its percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “— Issuance of Additional Securities.” However, if at any time any person or group, other than our general partner and its affiliates, a direct transferee of our general partner and its affiliates or a transferee of such direct transferee who is notified by our general partner that it will not lose its voting rights, acquires, in the aggregate, beneficial ownership of 20.0% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum, or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and its nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units as a single class. Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Status as Limited Partner

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission is reflected in our register. Except as described under “— Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions.

Indemnification

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

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our general partner;

•

any departing general partner;

•

any person who is or was an affiliate of our general partner or any departing general partner;

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any person who is or was a director, officer, managing member, manager, general partner, fiduciary or trustee of us or our subsidiaries, an affiliate of us or our subsidiaries or any entity set forth in the preceding three bullet points;

•

any person who is or was serving as director, officer, managing member, manager, general partner, fiduciary or trustee of another person owing a fiduciary duty to us or any of our subsidiaries at the request of our general partner or any departing general partner or any of their affiliates, excluding any such person providing, on a fee-for-service basis, trustee, fiduciary of custodial services; and

•

any person designated by our general partner because such person’s status, service or relationship expose such person to potential claims or suits relating to our or our subsidiaries’ business and affairs.

Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We will purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against such liabilities under our partnership agreement.

Any expenses incurred by an indemnified person in connection with any indemnification will be advanced by us.

Reimbursement of Expenses

Our partnership agreement requires us to reimburse our general partner and its affiliates for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine in good faith the expenses that are allocable to us. The expenses for which we are required to reimburse our general partner are not subject to any caps or other limits. Please read “Certain Relationships and Related Party Transactions — Agreements Governing the Restructuring Transactions — Omnibus Agreement.”

Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for financial reporting purposes on an accrual basis. For fiscal and tax reporting purposes, our fiscal year is the calendar year.

We will mail or make available to record holders of common units, within 105 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent registered public accounting firm. Except for our fourth quarter, we will also mail or make available summary financial information within 50 days after the close of each quarter.

We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every

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unitholder will receive information to assist him in determining its federal and state tax liability and filing its federal and state income tax returns, regardless of whether he supplies us with information.

Right to Inspect Our Books and Records

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to its interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at its own expense, have furnished to him:

•

a current list of the name and last known address of each record holder;

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copies of our partnership agreement and our certificate of limited partnership and all amendments thereto; and

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certain information regarding the status of our business and financial condition.

Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner determines is not in our best interests or that we are required by law or by agreements with third-parties to keep confidential. Our partnership agreement limits the right to information that a limited partner would otherwise have under Delaware law.

Registration Rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other partnership interests proposed to be sold by our general partner or any of its affiliates, other than individuals, or their assignees if an exemption from the registration requirements is not otherwise available. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions. Please read “Units Eligible for Future Sale.”

Exclusive Forum

Our partnership agreement will provide that the Court of Chancery of the State of Delaware shall be the exclusive forum for any claims, suits, actions or proceedings (1) arising out of or relating in any way to our partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of our partnership agreement or the duties, obligations or liabilities among our partners, or obligations or liabilities of our partners to us, or the rights or powers of, or restrictions on, our partners or us), (2) brought in a derivative manner on our behalf, (3) asserting a claim of breach of a duty owed by any of our, or our general partner’s, directors, officers, or other employees, or owed by our general partner, to us or our partners, (4) asserting a claim against us arising pursuant to any provision of the Delaware Act or (5) asserting a claim against us governed by the internal affairs doctrine. Although we believe this provision benefits us by providing increased consistency in the application of Delaware law in the types of lawsuits to which it applies, the provision may have the effect of discouraging lawsuits against our directors and officers. The enforceability of similar choice of forum provisions in other companies’ certificates of incorporation or similar governing documents have been challenged in legal proceedings, and it is possible that, in connection with any action, a court could find the choice of forum provisions contained in our partnership agreement to be inapplicable or unenforceable in such action.

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UNITS ELIGIBLE FOR FUTURE SALE

After the sale of the common units offered by this prospectus and assuming that the underwriters do not exercise their option to purchase additional common units, our general partner and its affiliates will hold an aggregate of common units and subordinated units (or common units and subordinated units if the underwriters exercise their option to purchase additional units in full). All of the subordinated units will convert into common units at the end of the subordination period. All of the common units and subordinated units held by our general partner and its affiliates are subject to lock-up restrictions described below. The sale of these units could have an adverse impact on the price of the common units or on any trading market that may develop.

Rule 144

The common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, other than any units purchased in this offering by officers, directors and other affiliates of our general partner under our directed unit program, which will be subject to the lock-up restrictions described below. None of the directors or officers of our general partner own any common units prior to this offering; however, they may purchase common units through the directed unit program or otherwise. Additionally, any common units owned by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

•

1.0% of the total number of the common units outstanding, which will equal approximately units immediately after this offering; or

•

the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.

At the closing of this offering, the following common units will be restricted and may not be resold publicly except in compliance with the registration requirements of the Securities Act, Rule 144 or otherwise.

•

common units owned by our general partner and its affiliates; and

•

any units acquired by our general partner or any of its affiliates, including the directors and executive officers of our general partner under the directed unit program.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his common units for at least six months (provided we are in compliance with the current public information requirement) or one year (regardless of whether we are in compliance with the current public information requirement), would be entitled to sell those common units under Rule 144 without regard to the volume limitations, manner of sale provisions and notice requirements of Rule 144.

Our Partnership Agreement and Registration Rights

Our partnership agreement provides that we may issue an unlimited number of limited partner interests of any type without a vote of the unitholders. Any issuance of additional common units or other limited partner interests would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read “Our Partnership Agreement — Issuance of Additional Securities.”

Under our partnership agreement, our general partner and its affiliates, other than individuals, have the right to cause us to register under the Securities Act and applicable state securities laws

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the offer and sale of any units that they hold. Subject to the terms and conditions of our partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any common units or other limited partner interests to require registration of any of these common units or other limited partner interests and to include any of these common units in a registration by us of other common units, including common units offered by us or by any unitholder. Our general partner and its affiliates will continue to have these registration rights for two years after it ceases to be our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors, and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts. Our general partner and its affiliates also may sell their common units or other limited partner interests in private transactions at any time, subject to compliance with applicable laws.

Lock-up Agreements

Our general partner’s executive officers and directors, our general partner, Cypress Holdings and certain other affiliates have agreed that for a period of 180 days from the date of this prospectus they will not, without the prior written consent of Raymond James & Associates, Inc., Robert W. Baird & Co. Incorporated and Stifel, Nicolaus & Company, Incorporated, dispose of or hedge any common units or any securities convertible into or exchangeable for our common units. Participants in our directed unit program who purchase $ or more of common units under the program will be subject to similar restrictions for a period of days from the date of this prospectus. Please read “Underwriting” for a description of these lock-up provisions.

Registration Statement on Form S-8

We intend to file a registration statement on Form S-8 under the Securities Act following this offering to register all common units issued or reserved for issuance under the LTIP. We expect to file this registration statement as soon as practicable after this offering. Common units covered by the registration statement on Form S-8 will be eligible for sale in the public market, subject to applicable vesting requirements and the terms of applicable lock-up agreements described above.

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MATERIAL FEDERAL INCOME TAX CONSEQUENCES

This section is a discussion of the material tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the U.S. and, unless otherwise noted in the following discussion, is the opinion of Latham & Watkins LLP, counsel to our general partner and us, insofar as it relates to legal conclusions with respect to matters of U.S. federal income tax law. This section is based upon current provisions of the Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”), existing and proposed Treasury regulations promulgated under the Internal Revenue Code (the “Treasury Regulations”) and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to Cypress Energy Partners, L.P. and our operating subsidiaries.

The following discussion does not comment on all federal income tax matters affecting us or our unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the U.S. and has only limited application to corporations, estates, entities treated as partnerships for U.S. federal income tax purposes, trusts, nonresident aliens, U.S. expatriates and former citizens or long-term residents of the United States or other unitholders subject to specialized tax treatment, such as banks, insurance companies and other financial institutions, tax-exempt institutions, foreign persons (including, without limitation, controlled foreign corporations, passive foreign investment companies and non-U.S. persons eligible for the benefits of an applicable income tax treaty with the United States), IRAs, real estate investment trusts (REITs) or mutual funds, dealers in securities or currencies, traders in securities, U.S. persons whose “functional currency” is not the U.S. dollar, persons holding their units as part of a “straddle,” “hedge,” “conversion transaction” or other risk reduction transaction, and persons deemed to sell their units under the constructive sale provisions of the Code. In addition, the discussion only comments to a limited extent on state, local and foreign tax consequences. Accordingly, we encourage each prospective unitholder to consult his own tax advisor in analyzing the state, local and foreign tax consequences particular to him of the ownership or disposition of common units and potential changes in applicable tax laws.

No ruling has been requested from the IRS regarding our characterization as a partnership for tax purposes. Instead, we will rely on opinions of Latham & Watkins LLP. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and for incentive distributions to our general partner and, thus, will be borne indirectly by our unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

All statements as to matters of federal income tax law and legal conclusions with respect thereto, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Latham & Watkins LLP and are based on the accuracy of the representations made by us.

For the reasons described below, Latham & Watkins LLP has not rendered an opinion with respect to the following specific federal income tax issues: (i) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales”); (ii) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “— Disposition of Common Units — Allocations Between Transferors and Transferees”) and (iii) whether our method for taking into account Section 743 adjustments is

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sustainable in certain cases (please read “— Tax Consequences of Unit Ownership — Section 754 Election” and “— Uniformity of Units”).

Partnership Status

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable to the partnership or the partner unless the amount of cash distributed to him is in excess of the partner’s adjusted basis in his partnership interest. Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90.0% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the exploration, development, mining or production, processing, refining, transportation, storage and marketing of crude oil, natural gas and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than % of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Latham & Watkins LLP is of the opinion that at least 90.0% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income may change from time to time.

The IRS has made no determination as to our status or the status of our operating subsidiaries for federal income tax purposes. Instead, we will rely on the opinion of Latham & Watkins LLP on such matters. It is the opinion of Latham & Watkins LLP that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below that:

•

We will be classified as a partnership for federal income tax purposes; and

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Each of our operating subsidiaries will be treated as a partnership or will be disregarded as an entity separate from us for federal income tax purposes.

In rendering its opinion, Latham & Watkins LLP has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Latham & Watkins LLP has relied include:

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Neither we nor any of the operating subsidiaries has elected or will elect to be treated as a corporation; and

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For each taxable year, more than 90.0% of our gross income has been and will be income of the type that Latham & Watkins LLP has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code.

We believe that these representations have been true in the past and expect that these representations will continue to be true in the future.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation should

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be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

If we were treated as an association taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as taxable dividend income, to the extent of our current and accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in his common units, or taxable capital gain, after the unitholder’s tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

The discussion below is based on Latham & Watkins LLP’s opinion that we will be classified as a partnership for federal income tax purposes.

Limited Partner Status

Unitholders of Cypress Energy Partners, L.P. will be treated as partners of Cypress Energy Partners, L.P. for federal income tax purposes. Also, unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units will be treated as partners of Cypress Energy Partners, L.P. for federal income tax purposes.

A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales.”

Income, gains, losses or deductions would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These holders are urged to consult their tax advisors with respect to the tax consequences to them of holding common units in Cypress Energy Partners, L.P. The references to “unitholders” in the discussion that follows are to persons who are treated as partners in Cypress Energy Partners, L.P. for federal income tax purposes.

Tax Consequences of Unit Ownership

Flow-Through of Taxable Income

Subject to the discussion below under “— Tax Consequences of Unit Ownership — Entity-Level Collections” we will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether we make cash distributions to him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. The income we allocate to unitholders will generally be taxable as ordinary income. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.

Treatment of Distributions

Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder’s tax basis generally will be considered to be gain from the sale or exchange of the

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common units, taxable in accordance with the rules described under “— Disposition of Common Units.” Any reduction in a unitholder’s share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution by us of cash to that unitholder. To the extent our distributions cause a unitholder’s “at-risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “— Tax Consequences of Unit Ownership — Limitations on Deductibility of Losses.”

A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. This deemed distribution may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture and/or substantially appreciated “inventory items,” each as defined in the Internal Revenue Code, and collectively, “Section 751 Assets.” To that extent, the unitholder will be treated as having been distributed his proportionate share of the Section 751 Assets and then having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income, which will equal the excess of (i) the non-pro rata portion of that distribution over (ii) the unitholder’s tax basis (often zero) for the share of Section 751 Assets deemed relinquished in the exchange.

Ratio of Taxable Income to Distributions

We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the year ending December 31, , will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be % or less of the cash distributed with respect to that period. Thereafter, we anticipate that the ratio of allocable taxable income to cash distributions to the unitholders will increase. Our estimate is based upon many assumptions regarding our business operations, including assumptions as to our revenues, capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct.

The actual ratio of allocable taxable income to cash distributions could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units. For example, the ratio of allocable taxable income to cash distributions to a purchaser of common units in this offering will be higher, and perhaps substantially higher, than our estimate with respect to the period described above if:

•

gross income from operations exceeds the amount required to make minimum quarterly distributions on all units, yet we only distribute the minimum quarterly distributions on all units; or

•

we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.

Basis of Common Units

A unitholder’s initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his

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share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to our general partner to the extent of the general partner’s “net value” as defined in regulations under Section 752 of the Internal Revenue Code, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

Limitations on Deductibility of Losses

The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder, estate, trust, or corporate unitholder (if more than 50.0% of the value of the corporate unitholder’s stock is owned directly or indirectly by or for five or fewer individuals or some tax- exempt organizations) to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than his tax basis. A common unitholder subject to these limitations must recapture losses deducted in previous years to the extent that distributions cause his at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction to the extent that his at-risk amount is subsequently increased, provided such losses do not exceed such common unitholder’s tax basis in his common units. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any loss previously suspended by the at-risk limitation in excess of that gain would no longer be utilizable.

In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by (i) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (ii) any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder’s at-risk amount will increase or decrease as the tax basis of the unitholder’s units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

In addition to the basis and at-risk limitations on the deductibility of losses, the passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or a unitholder’s investments in other publicly traded partnerships, or the unitholder’s salary, active business or other income. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive loss limitations are applied after other applicable limitations on deductions, including the at-risk rules and the basis limitation.

A unitholder’s share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

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Limitations on Interest Deductions

The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

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interest on indebtedness properly allocable to property held for investment;

•

interest expense attributed to portfolio income; and

•

the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment or (if applicable) qualified dividend income. The IRS has indicated that the net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.

Entity-Level Collections

If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or our general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction

In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among the unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or incentive distributions are made to our general partner, gross income will be allocated to the recipients to the extent of these distributions. If we have a net loss, that loss will be allocated to the unitholders in accordance with their percentage interests in us.

Specified items of our income, gain, loss and deduction will be allocated to account for (i) any difference between the tax basis and fair market value of our assets at the time of this offering and (ii) any difference between the tax basis and fair market value of any property contributed to us by the general partner and its affiliates (or by a third party) that exists at the time of such contribution, together referred to in this discussion as the “Contributed Property.” The effect of these allocations, referred to as Section 704(c) Allocations, to a unitholder purchasing common units from us in this offering will be essentially the same as if the tax bases of our assets were equal to their fair market values at the time of this offering. In the event we issue additional common units or engage in certain other transactions in the future, “reverse Section 704(c) Allocations,” similar to the Section 704(c) Allocations described above, will be made to the general partner and all of our unitholders immediately prior to such issuance or other transactions to account for the difference between the “book” basis for purposes of maintaining capital accounts and the fair

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market value of all property held by us at the time of such issuance or future transaction. In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “Book-Tax Disparity,” will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has “substantial economic effect.” In any other case, a partner’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:

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his relative contributions to us;

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the interests of all the partners in profits and losses;

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the interest of all of the partners in cash flow; and

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the rights of all of the partners to distributions of capital upon liquidation.

Latham & Watkins LLP is of the opinion that, with the exception of the issues described in “— Tax Consequences of Unit Ownership — Section 754 Election” and “— Disposition of Common Units — Allocations Between Transferors and Transferees,” allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.

Treatment of Short Sales

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

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any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;

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any cash distributions received by the unitholder as to those units would be fully taxable; and

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while not entirely free from doubt, all of these distributions would appear to be ordinary income.

Because there is no direct or indirect controlling authority on the issue relating to partnership interests, Latham & Watkins LLP has not rendered an opinion regarding the tax treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and loaning their units. The IRS has previously announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please also read “— Disposition of Common Units — Recognition of Gain or Loss.”

Alternative Minimum Tax

Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26.0% on the first $179,500 of alternative

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minimum taxable income in excess of the exemption amount and 28.0% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.

Tax Rates

Beginning on January 1, 2013, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 39.6% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than twelve months) of individuals is 20.0%. Such rates are subject to change by new legislation at any time.

In addition, a 3.8% Medicare tax, or NIIT, on certain net investment income earned by individuals, estates and trusts applies for taxable years beginning after December 31, 2012. For these purposes, net investment income generally includes a unitholder’s allocable share of our income and gain realized by a unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (1) the unitholder’s net investment income and (2) the amount by which the unitholder’s modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if the unitholder is married and filing separately) or $200,000 (in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (1) undistributed net investment income and (2) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins. Recently, the U.S. Department of the Treasury and the IRS issued proposed Treasury Regulations that provide guidance regarding the NIIT. Although the proposed Treasury Regulations are effective for taxable years beginning after December 31, 2013, taxpayers may rely on the proposed Treasury Regulations for purposes of compliance until the effective date of the final regulations. Prospective unitholders are urged to consult with their tax advisors as to the impact of the NIIT on an investment in our common units.

Section 754 Election

We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS unless there is a constructive termination of the partnership. Please read “— Disposition of Common Units — Constructive Termination.” The election will generally permit us to adjust a common unit purchaser’s tax basis in our assets, or its inside basis, under Section 743(b) of the Internal Revenue Code to reflect his purchase price. This election does not apply with respect to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, the inside basis in our assets with respect to a unitholder will be considered to have two components: (i) his share of our tax basis in our assets, or common basis, and (ii) his Section 743(b) adjustment to that basis.

We will adopt the remedial allocation method as to all our properties. Where the remedial allocation method is adopted, the Treasury Regulations under Section 743 of the Internal Revenue Code require a portion of the Section 743(b) adjustment that is attributable to recovery property that is subject to depreciation under Section 168 of the Internal Revenue Code and whose book basis is in excess of its tax basis to be depreciated over the remaining cost recovery period for the property’s unamortized Book-Tax Disparity. Under Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150.0% declining balance method. Under our partnership agreement, our general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these and any other Treasury Regulations. Please read “— Uniformity of Units.”

We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax

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Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as non-amortizable to the extent attributable to property which is not amortizable. This method is consistent with the methods employed by other publicly traded partnerships but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read “— Uniformity of Units.” A unitholder’s tax basis for his common units is reduced by his share of our deductions (whether or not such deductions were claimed on an individual’s income tax return) so that any position we take that understates deductions will overstate the common unitholder’s basis in his common units, which may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “— Disposition of Common Units — Recognition of Gain or Loss.” Latham & Watkins LLP is unable to opine as to whether our method for taking into account Section 743 adjustments is sustainable for property subject to depreciation under Section 167 of the Internal Revenue Code or if we use an aggregate approach as described above, as there is no direct or indirect controlling authority addressing the validity of these positions. Moreover, the IRS may challenge our position with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of the units. If such a challenge were sustained, the gain from the sale of units might be increased without the benefit of additional deductions.

A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally, a built-in loss or a basis reduction is substantial if it exceeds $250,000.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

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Tax Treatment of Operations

Accounting Method and Taxable Year

We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than twelve months of our income, gain, loss and deduction. Please read “— Disposition of Common Units — Allocations Between Transferors and Transferees.”

Initial Tax Basis, Depreciation and Amortization

The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to (i) this offering will be borne by our general partner and its affiliates, and (ii) any other offering will be borne by our general partner and all of our unitholders as of that time. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction.”

To the extent allowable, we may elect to use the depreciation and cost recovery methods, including bonus depreciation to the extent available, that will result in the largest deductions being taken in the early years after assets subject to these allowances are placed in service. Please read “— Uniformity of Units.” Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction” and “— Disposition of Common Units — Recognition of Gain or Loss.”

The costs we incur in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts and commissions we incur will be treated as syndication expenses.

Valuation and Tax Basis of Our Properties

The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

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Disposition of Common Units

Recognition of Gain or Loss

Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us that in the aggregate were in excess of cumulative net taxable income for a common unit and, therefore, decreased a unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held for more than twelve months will generally be taxed at the U.S. federal income tax rate applicable to long-term capital gains. However, a portion of this gain or loss, which will likely be substantial, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other “unrealized receivables” or to “inventory items” we own. The term “unrealized receivables” includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations. Both ordinary income and capital gain recognized on a sale of units may be subject to the NIIT in certain circumstances. Please read “— Tax Consequences of Unit Ownership — Tax Rates.”

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling discussed above, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, he may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

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Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

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a short sale;

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an offsetting notional principal contract; or

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a futures or forward contract;

in each case, with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees

In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Internal Revenue Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations as there is no direct or indirect controlling authority on this issue. The U.S. Department of the Treasury and the IRS has issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations; however, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued. Accordingly, Latham & Watkins LLP is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee unitholders because the issue has not been finally resolved by the IRS or the courts. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferor and transferee unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations. A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter through the month of disposition but will not be entitled to receive that cash distribution.

Notification Requirements

A unitholder who sells any of his units is generally required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of units who purchases units from another unitholder is also generally required to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we

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are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the U.S. and who effects the sale or exchange through a broker who will satisfy such requirements.

Constructive Termination

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 12-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.

Uniformity of Units

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.” We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets.

Please read “— Tax Consequences of Unit Ownership — Section 754 Election.” To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are

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otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. In either case, and as stated above under “— Tax Consequences of Unit Ownership — Section 754 Election,” Latham & Watkins LLP has not rendered an opinion with respect to these methods. Moreover, the IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below to a limited extent, may have substantially adverse tax consequences to them. If you are a tax-exempt entity or a non- U.S. person, you should consult your tax advisor before investing in our common units. Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to it.

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the U.S. because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, our quarterly distribution to foreign unitholders will be subject to withholding at the highest applicable effective tax rate. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a foreign corporation that owns units will be treated as engaged in a U.S. trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30.0%, in addition to regular federal income tax, on its share of our earnings and profits, as adjusted for changes in the foreign corporation’s “U.S. net equity,” that is effectively connected with the conduct of a U.S. trade or business. That tax may be reduced or eliminated by an income tax treaty between the U.S. and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

A foreign unitholder who sells or otherwise disposes of a common unit will be subject to U.S. federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the foreign unitholder. Under a ruling published by the IRS, interpreting the scope of “effectively connected income,” a foreign unitholder would be considered to be engaged in a trade or business in the U.S. by virtue of the U.S. activities of the partnership, and part or all of that unitholder’s gain would be effectively connected with that unitholder’s indirect U.S. trade or business. Moreover, under the Foreign Investment in Real Property Tax Act, a foreign common unitholder generally will be subject to U.S. federal income tax upon the sale or disposition of a common unit if (i) he owned (directly or constructively applying certain attribution rules) more than 5.0% of our common units at any time during the five-year period ending on the date of such disposition and (ii) 50.0% or more of the fair market value of all of our assets consisted of U.S. real property interests at any time during the shorter of the period during which such unitholder held the common units or the five-year period

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ending on the date of disposition. Currently, more than 50.0% of our assets consist of U.S. real property interests and we do not expect that to change in the foreseeable future. Therefore, foreign unitholders may be subject to federal income tax on gain from the sale or disposition of their units.

Administrative Matters

Information Returns and Audit Procedures

We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Latham & Watkins LLP can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. Our partnership agreement names our general partner as our Tax Matters Partner.

The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1.0% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1.0% interest in profits or by any group of unitholders having in the aggregate at least a 5.0% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Additional Withholding Requirements

Withholding taxes may apply to certain types of payments made to “foreign financial institutions” (as specially defined in the Internal Revenue Code) and certain other non-U.S. entities. Specifically, a 30.0% withholding tax may be imposed on interest, dividends and other fixed or determinable annual or periodical gains, profits and income from sources within the United States, or FDAP Income, or gross proceeds from the sale or other disposition of any property of a type which can produce interest or dividends from sources within the United States, or Gross Proceeds, paid to a foreign financial institution or to a “non-financial foreign entity” (as specially defined in the Internal Revenue Code), unless (i) the foreign financial institution

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undertakes certain diligence and reporting, (ii) the non-financial foreign entity either certifies it does not have any substantial U.S. owners or furnishes identifying information regarding each substantial U.S. owner or (iii) the foreign financial institution or non-financial foreign entity otherwise qualifies for an exemption from these rules. If the payee is a foreign financial institution and is subject to the diligence and reporting requirements in clause (i) above, it must enter into an agreement with the U.S. Treasury requiring, among other things, that it undertake to identify accounts held by certain U.S. persons or U.S.-owned foreign entities, annually report certain information about such accounts, and withhold 30.0% on payments to noncompliant foreign financial institutions and certain other account holders.

These rules generally will apply to payments of FDAP Income made on or after July 1, 2014 and to payments of relevant Gross Proceeds made on or after January 1, 2017. Thus, to the extent we have FDAP Income or Gross Proceeds after these dates that are not treated as effectively connected with a U.S. trade or business (please read “— Tax-Exempt Organizations and Other Investors”), unitholders who are foreign financial institutions or certain other non-US entities may be subject to withholding on distributions they receive from us, or their distributive share of our income, pursuant to the rules described above.

Prospective investors should consult their own tax advisors regarding the potential application of these withholding provisions to their investment in our common units.

Nominee Reporting

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

(1)

the name, address and taxpayer identification number of the beneficial owner and the nominee;

(2)

whether the beneficial owner is:

(a)

a person that is not a U.S. person;

(b)

a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

(c)

a tax-exempt entity;

(3)

the amount and description of units held, acquired or transferred for the beneficial owner; and

(4)

specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from dispositions.

Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1,500,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-Related Penalties

An additional tax equal to 20.0% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

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For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10.0% of the tax required to be shown on the return for the taxable year or $5,000 ($10,000 for most corporations). The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

(1)

for which there is, or was, “substantial authority”; or

(2)

as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to “tax shelters,” which we do not believe includes us, or any of our investments, plans or arrangements.

A substantial valuation misstatement exists if (a) the value of any property, or the adjusted basis of any property, claimed on a tax return is 150.0% or more of the amount determined to be the correct amount of the valuation or adjusted basis, (b) the price for any property or services (or for the use of property) claimed on any such return with respect to any transaction between persons described in Internal Revenue Code Section 482 is 200.0% or more (or 50.0% or less) of the amount determined under Section 482 to be the correct amount of such price, or (c) the net Internal Revenue Code Section 482 transfer price adjustment for the taxable year exceeds the lesser of $5 million or 10.0% of the taxpayer’s gross receipts. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 200.0% or more than the correct valuation or certain other thresholds are met, the penalty imposed increases to 40.0%. We do not anticipate making any valuation misstatements.

In addition, the 20.0% accuracy-related penalty also applies to any portion of an underpayment of tax that is attributable to transactions lacking economic substance. To the extent that such transactions are not disclosed, the penalty imposed is increased to 40.0%. Additionally, there is no reasonable cause defense to the imposition of this penalty to such transactions.

Reportable Transactions

If we were to engage in a “reportable transaction,” we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2.0 million in any single year, or $4.0 million in any combination of six successive tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read “— Administrative Matters — Information Returns and Audit Procedures.”

Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following additional consequences:

•

accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “— Administrative Matters — Accuracy-Related Penalties”;

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•

for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability; and

•

in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any “reportable transactions.”

Recent Legislative Developments

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. Please read “— Partnership Status.” 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.

State, Local and Other Tax Considerations

In addition to federal income taxes, you likely will be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. 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. We may also own property or do business in other jurisdictions in the future. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “— Tax Consequences of Unit Ownership — Entity-Level Collections.” Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent states, localities and foreign jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult his own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as U.S. federal tax returns, that may be required of him. Latham & Watkins LLP has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.

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INVESTMENT IN CYPRESS ENERGY PARTNERS, L.P. BY EMPLOYEE BENEFIT PLANS

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and the restrictions imposed by Section 4975 of the Internal Revenue Code and provisions under any federal, state, local, non-U.S. or other laws or regulations that are similar to such provisions of the Internal Revenue Code or ERISA, collectively, “Similar Laws.” For these purposes the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs or annuities established or maintained by an employer or employee organization, and entities whose underlying assets are considered to include “plan assets” of such plans, accounts and arrangements, collectively, “Employee Benefit Plans.” Among other things, consideration should be given to:

•

whether the investment is prudent under Section 404(a)(1)(B) of ERISA and any other applicable Similar Laws;

•

whether in making the investment, the plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA and any other applicable Similar Laws;

•

whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please read “Material Federal Income Tax Consequences — Tax-Exempt Organizations and Other Investors”; and

•

whether making such an investment will comply with the delegation of control and prohibited transaction provisions of ERISA, the Internal Revenue Code and any other applicable Similar Laws.

The person with investment discretion with respect to the assets of an Employee Benefit Plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit Employee Benefit Plans from engaging, either directly or indirectly, in specified transactions involving “plan assets” with parties that, with respect to the Employee Benefit Plan, are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code unless an exemption is available. A party in interest or disqualified person who engages in a non-exempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and the Internal Revenue Code. In addition, the fiduciary of the ERISA plan that engaged in such a non-exempt prohibited transaction may be subject to penalties and liabilities under ERISA and the Internal Revenue Code.

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary should consider whether the Employee Benefit Plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our general partner would also be a fiduciary of such Employee Benefit Plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code, ERISA and any other applicable Similar Laws.

The U.S. Department of Labor regulations and Section 3(42) of ERISA provide guidance with respect to whether, in certain circumstances, the assets of an entity in which Employee Benefit Plans acquire equity interests would be deemed “plan assets.” Under these rules, an entity’s assets would not be considered to be “plan assets” if, among other things:

(a)

the equity interests acquired by the Employee Benefit Plan are publicly offered securities — i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, are freely transferable and are registered under certain provisions of the federal securities laws;

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(b)

the entity is an “operating company,”— i.e., it is primarily engaged in the production or sale of a product or service, other than the investment of capital, either directly or through a majority-owned subsidiary or subsidiaries; or

(c)

there is no significant investment by “benefit plan investors,” which is defined to mean that less than 25.0% of the value of each class of equity interest, disregarding any such interests held by our general partner, its affiliates and certain other persons, is held generally by Employee Benefit Plans.

Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in (a) and (b) above. The foregoing discussion of issues arising for employee benefit plan investments under ERISA and the Internal Revenue Code is general in nature and is not intended to be all inclusive, nor should it be construed as legal advice. In light of the serious penalties imposed on persons who engage in prohibited transactions or other violations, plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA, the Internal Revenue Code and other Similar Laws.

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UNDERWRITING

Raymond James & Associates, Inc., Robert W. Baird & Co. Incorporated and Stifel, Nicolaus & Company, Incorporated are acting as representatives of each of the underwriters named below. Subject to the terms and conditions set forth in an underwriting agreement among us and the underwriters, we have agreed to sell to the underwriters, and each of the underwriters has agreed, severally and not jointly, to purchase from us the number of common units set forth opposite its name below:


Underwriters		Number of Common Units
Raymond James & Associates, Inc.
Robert W. Baird & Co. Incorporated
Stifel, Nicolaus & Company, Incorporated





Total

The underwriting agreement provides that the obligations of the underwriters to purchase and accept delivery of the common units offered by this prospectus are subject to approval by their counsel of legal matters and to certain other customary conditions set forth in the underwriting agreement.

The underwriters are obligated to purchase and accept delivery of all of the common units offered by this prospectus, if any of the units are purchased, other than those covered by the option to purchase additional common units described below.

The underwriters propose to offer the common units directly to the public at the public offering price indicated on the cover page of this prospectus and to various dealers at that price less a concession not in excess of $ per unit. If all of the common units are not sold at the public offering price, the underwriters may change the public offering price and other selling terms. The common units are offered by the underwriters as stated in this prospectus, subject to receipt and acceptance by them. The underwriters reserve the right to reject an order for the purchase of the common units in whole or in part.

Option to Purchase Additional Common Units

We have granted the underwriters an option, exercisable for 30 days after the date of this prospectus, to purchase, from time to time, in whole or in part, up to an aggregate of additional common units at the public offering price less the underwriting discounts set forth on the cover page of this prospectus. If the underwriters exercise this option, each underwriter, subject to certain conditions, will become obligated to purchase its pro rata portion of these additional units based on the underwriters’ percentage purchase commitment in this offering as indicated in the table above. Any common units not purchased by the underwriters pursuant to their exercise of the option will be issued to a wholly owned subsidiary of Cypress Holdings at the expiration of the option period for no additional consideration.

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Discounts and Expenses

The following table shows the amount per common unit and total underwriting discounts we will pay to the underwriters. The amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional common units.

Per Unit

No Exercise

Full Exercise

Initial public offering price

Underwriting discounts

Proceeds (before expenses) to us

We will pay Raymond James & Associates, Inc., Robert W. Baird & Co. Incorporated and Stifel, Nicolaus & Company, Incorporated a structuring fee equal to % of the gross proceeds of this offering ($ million or $ million if the option to purchase additional units is exercised in full) for evaluation, analysis and structuring of the partnership. This structuring fee will compensate Raymond James & Associates, Inc., Robert W. Baird & Co. Incorporated and Stifel, Nicolaus & Company, Incorporated at the closing of this offering for providing advice regarding the capital structure of our partnership, the terms of the offering, the terms of our partnership agreement and the terms of certain other agreements between us and our affiliates.

The other expenses of this offering that are payable by us are estimated to be $ million (exclusive of underwriting discounts and structuring fee).

Indemnification

We and our general partner and certain of its affiliates have agreed to indemnify the underwriters against various liabilities that may arise in connection with this offering, including liabilities under the Securities Act for errors or omissions in this prospectus or the registration statement of which this prospectus is a part. However, we will not indemnify the underwriters if the error or omission was the result of information the underwriters supplied in writing for inclusion in this prospectus or the registration statement.

Lock-Up Agreements

Subject to specified exceptions, we, our general partner, executive officers and directors of our general partner, certain affiliates of our general partner and certain individuals who purchase common units in our directed unit program have agreed with the underwriters, for a period of 180 days after the date of this prospectus, not to offer, sell, contract to sell or otherwise dispose of or transfer any common units or any securities convertible into or exchangeable for common units without the prior written consent of Raymond James & Associates, Inc., Robert W. Baird & Co. Incorporated and Stifel, Nicolaus & Company, Incorporated. These agreements also preclude any hedging collar or other transaction designed or reasonably expected to result in a disposition of common units or securities convertible into or exercisable or exchangeable for common units. The representatives may, in their discretion and at any time without notice, release all or any portion of the securities subject to these agreements. The representatives do not have any present intent or any understanding to release all or any portion of the securities subject to these agreements.

Stabilization

Until this offering is completed, rules of the SEC may limit the ability of the underwriters and various selling group members to bid for and purchase the common units. As an exception to these rules and in accordance with Regulation M under the Exchange Act, the underwriters may engage in activities that stabilize, maintain or otherwise affect the price of the common units in order to facilitate the offering of the common units, including:

•

short sales;

•

syndicate covering transactions;

•

imposition of penalty bids; and

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•

purchases to cover positions created by short sales.

Stabilizing transactions may include making short sales of common units, which involve the sale by the underwriters of a greater number of common units than it is required to purchase in this offering and purchasing common units from us by exercising the underwriters option to purchase additional common units or in the open market to cover positions created by short sales. Short sales may be “covered” shorts, which are short positions in an amount not greater than the underwriters’ option to purchase additional common units referred to above, or may be “naked” shorts, which are short positions in excess of that amount.

Each underwriter may close out any covered short position either by exercising its option to purchase additional common units, in whole or in part, or by purchasing common units in the open market after the distribution has been completed. In making this determination, each underwriter will consider, among other things, the price of common units available for purchase in the open market compared to the price at which the underwriter may purchase common units pursuant to their option to purchase additional common units.

A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchased in this offering. To the extent that the underwriters create a naked short position, they will purchase common units in the open market to cover the position after the pricing of this offering.

The underwriters also may impose a penalty bid on selling group members. This means that if the underwriters purchase common units in the open market in stabilizing transactions or to cover short sales, the underwriters can require the selling group members that sold those common units as part of this offering to repay the selling concession received by them.

As a result of these activities, the price of the common units may be higher than the price that otherwise might exist in the open market. If the underwriters commence these activities, they may discontinue them without notice at any time. The underwriters may carry out these transactions on the NYSE or otherwise.

Relationships

The underwriters and their affiliates may provide in the future investment banking, financial advisory or other financial services for us and our affiliates, for which they may receive advisory or transaction fees, as applicable, plus out-of-pocket expenses, of the nature and in amounts customary in the industry for these financial services.

Discretionary Accounts

The underwriters may confirm sales of the common units offered by this prospectus to accounts over which they exercise discretionary authority but do not expect those sales to exceed 5.0% of the total common units offered by this prospectus.

Directed Unit Program

At our request, the underwriters have reserved up to % of the common units being offered by this prospectus (excluding the common units that may be issued upon the underwriters’ exercise of their option to purchase additional common units) for sale at the initial public offering price to employees, consultants, directors, director nominees and executive officers of our general partner, as well as directors, certain other key employees and persons associated with Cypress Holdings. The sales will be made by Raymond James & Associates, Inc. through a directed unit program. It is not certain if these persons will choose to purchase all or any portion of these reserved units, but any purchases they make will reduce the number of common units available for sale to the general public. Any reserved units not so purchased will be offered by the underwriters to the general public on the same basis as the other common units offered by this prospectus. The individuals eligible to participate in the directed unit program must commit to purchase no later

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than before the opening of business on the day following the date of this prospectus. We, our general partner and certain of its affiliates have agreed to indemnify Raymond James & Associates, Inc. and the underwriters against certain liabilities and expenses in connection with the directed unit program, including liabilities under the Securities Act in connection with the sale of the reserved units and for the failure of any participant to pay for its common units.

Listing

We intend to apply to list the common units on the NYSE under the symbol “CELP.” In connection with the listing of our common units on the NYSE, the underwriters will undertake to sell round lots of 100 units or more to a minimum of 400 beneficial owners.

Determination of Initial Offering Price

Prior to this offering, there has been no public market for the common units. Consequently, the initial public offering price for the common units will be determined by negotiations among us and the underwriters. The primary factors to be considered in determining the initial public offering price will be:

•

estimates of distributions to our unitholders;

•

overall quality of our properties and operations;

•

industry and market conditions prevalent in our industry;

•

the information set forth in this prospectus and otherwise available to the representatives; and

•

the general conditions of the securities markets at the time of this offering.

Electronic Prospectus

A prospectus in electronic format may be available on the Internet sites or through other online services maintained by one or more of the underwriters and selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the underwriter or the selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of common units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the underwriters on the same basis as other allocations.

Other than the prospectus in electronic format, the information on any underwriter’s or any selling group member’s website and any information contained in any other website maintained by the underwriters or any selling group member is not part of this prospectus or the registration statement of which this prospectus forms a part, has not been approved or endorsed by us or any underwriters or any selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

FINRA Conduct Rules

Because FINRA is expected to view the common units offered hereby as interests in a direct participation program, this offering is being made in compliance with Rule 2310 of the FINRA Conduct Rules. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

Notice to Prospective Investors in the EEA

In relation to each member state of the European Economic Area that has implemented the Prospectus Directive (each, a relevant member state), other than Germany, with effect from and including the date on which the Prospectus Directive is implemented in that relevant member state

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(the relevant implementation date), an offer of securities described in this prospectus may not be made to the public in that relevant member state other than:

•

to any legal entity which is a qualified investor as defined in the Prospectus Directive;

•

to fewer than 100 or, if the relevant member state has implemented the relevant provision of the 2010 PD Amending Directive, 150, natural or legal persons (other than qualified investors as defined in the Prospectus Directive), as permitted under the Prospectus Directive, subject to obtaining the prior consent of the relevant Dealer or Dealers nominated by the Issuer for any such offer; or

•

in any other circumstances falling within Article 3(2) of the Prospectus Directive;

provided that no such offer of securities shall require us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive.

For purposes of this provision, the expression an “offer of securities to the public” in any relevant member state means the communication in any form and by any means of sufficient information on the terms of the offer and the securities to be offered so as to enable an investor to decide to purchase or subscribe for the securities, as the expression may be varied in that member state by any measure implementing the Prospectus Directive in that member state, and the expression “Prospectus Directive” means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the relevant member state), and includes any relevant implementing measure in each relevant member state. The expression “2010 PD Amending Directive” means Directive 2010/73/EU.

We have not authorized and do not authorize the making of any offer of securities through any financial intermediary on their behalf, other than offers made by the underwriters with a view to the final placement of the securities as contemplated in this prospectus. Accordingly, no purchaser of the securities, other than the underwriters, is authorized to make any further offer of the securities on behalf of us or the underwriters.

Notice to Prospective Investors in the United Kingdom

Our partnership may constitute a “collective investment scheme” as defined by section 235 of the Financial Services and Markets Act 2000 (FSMA) that is not a “recognised collective investment scheme” for the purposes of FSMA (CIS) and that has not been authorised or otherwise approved. As an unregulated scheme, it cannot be marketed in the United Kingdom to the general public, except in accordance with FSMA. This prospectus is only being distributed in the United Kingdom to, and is only directed at:

(1) if our partnership is a CIS and is marketed by a person who is an authorised person under FSMA, (a) investment professionals falling within Article 14(5) of the Financial Services and Markets Act 2000 (Promotion of Collective Investment Schemes) (Exemptions) Order 2001, as amended (the CIS Promotion Order) or (b) high net worth companies and other persons falling within Article 22(2)(a) to (d) of the CIS Promotion Order; or

(2) otherwise, if marketed by a person who is not an authorised person under FSMA, (a) persons who fall within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005, as amended (the Financial Promotion Order) or (b) Article 49(2)(a) to (d) of the Financial Promotion Order; and

(3) in both cases (1) and (2) to any other person to whom it may otherwise lawfully be made (all such persons together being referred to as “relevant persons”).

Our partnership’s common units are only available to, and any invitation, offer or agreement to subscribe, purchase or otherwise acquire such common units will be engaged in only with, relevant persons. Any person who is not a relevant person should not act or rely on this document or any of its contents.

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An invitation or inducement to engage in investment activity (within the meaning of Section 21 of FSMA) in connection with the issue or sale of any common units which are the subject of the offering contemplated by this prospectus will only be communicated or caused to be communicated in circumstances in which Section 21(1) of FSMA does not apply to our partnership.

Notice to Prospective Investors in Switzerland

This prospectus is being communicated in Switzerland to a small number of selected investors only. Each copy of this prospectus is addressed to a specifically named recipient and may not be copied, reproduced, distributed or passed on to third parties. Our common units are not being offered to the public in Switzerland, and neither this prospectus, nor any other offering materials relating to our common units may be distributed in connection with any such public offering. We have not been registered with the Swiss Financial Market Supervisory Authority FINMA as a foreign collective investment scheme pursuant to Article 120 of the Collective Investment Schemes Act of June 23, 2006 (CISA). Accordingly, our common units may not be offered to the public in or from Switzerland, and neither this prospectus, nor any other offering materials relating to our common units may be made available through a public offering in or from Switzerland. Our common units may only be offered and this prospectus may only be distributed in or from Switzerland by way of private placement exclusively to qualified investors (as this term is defined in the CISA and its implementing ordinance).

Notice to Prospective Investors in Germany

This document has not been prepared in accordance with the requirements for a securities or sales prospectus under the German Securities Prospectus Act (Wertpapierprospektgesetz), the German Capital Investment Act (Vermögensanlagengesetz), or the German Investment Act (Investmentgesetz). Neither the German Federal Financial Services Supervisory Authority (Bundesanstalt für Finanzdienstleistungsaufsicht - BaFin) nor any other German authority has been notified of the intention to distribute our common units in Germany. Consequently, our common units may not be distributed in Germany by way of public offering, public advertisement or in any similar manner and this document and any other document relating to the offering, as well as information or statements contained therein, may not be supplied to the public in Germany or used in connection with any offer for subscription of our common units to the public in Germany or any other means of public marketing. Our common units are being offered and sold in Germany only to qualified investors which are referred to in Section 3, paragraph 2 no. 1, in connection with Section 2, no. 6, of the German Securities Prospectus Act, Section 2 no. 4 of the German Capital Investment Act, and in Section 2 paragraph 11 sentence 2 no. 1 of the German Investment Act. This document is strictly for use of the person who has received it. It may not be forwarded to other persons or published in Germany.

The offering does not constitute an offer to sell or the solicitation of an offer to buy our common units in any circumstances in which such offer or solicitation is unlawful.

Notice to Prospective Investors in the Netherlands

Our common units may not be offered or sold, directly or indirectly, in the Netherlands, other than to qualified investors (gekwalificeerde beleggers) within the meaning of Article 1:1 of the Dutch Financial Supervision Act (Wet op het financieel toezicht).

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VALIDITY OF THE COMMON UNITS

The validity of our common units will be passed upon for us by Latham & Watkins LLP, Houston, Texas. Certain legal matters in connection with our common units offered hereby will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas.

EXPERTS

The balance sheet of Cypress Energy Partners, LP as of September 19, 2013 (date of inception); the consolidated financial statements of Cypress Energy Partners, LLC as of December 31, 2012, and for the period from March 15, 2012 (Inception) through December 31, 2012; and the consolidated of financial statements of Cypress Energy Partners Predecessor as of December 31, 2012 and 2011 and for the year ended December 31, 2012 and the period from June 1, 2011 (Inception) through December 31, 2011, appearing in this Prospectus and Registration Statement, have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their reports thereon appearing elsewhere herein, and included in reliance upon such reports given on the authority of such firm as experts in accounting and auditing.

The statement of revenues and direct operating expenses of Assets purchased by Cypress Energy Partners, LLC from Moxie Disposal Systems, LLC and Peach Energy Services, LLC as of December 3, 2012, and for the period from July 1, 2012 (Inception) through December 3, 2012, appearing in this Prospectus and Registration Statement, have been audited by Ernst & Young LLP, independent auditors, as set forth in their report thereon appearing elsewhere herein, and included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The audited financial statements of TIR Parent as of December 31, 2012 and 2011 and for the years then ended, included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent certified public accountants, upon the authority of said firm as experts in accounting and auditing.

WHERE YOU CAN FIND ADDITIONAL INFORMATION

We have filed with the SEC a registration statement on Form S-1 regarding our common units. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common units offered by this prospectus, you may desire to review the full registration statement, including its exhibits and schedules, filed under the Securities Act. The registration statement of which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330.

The SEC maintains a website on the internet at http://www.sec.gov. Our registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC’s website and can also be inspected and copied at the offices of the New York Stock Exchange, Inc., 20 Broad Street, New York, New York 10005.

Upon completion of this offering, we will file with or furnish to the SEC periodic reports and other information. These reports and other information may be inspected and copied at the public reference facilities maintained by the SEC or obtained from the SEC’s website as provided above. Our website on the Internet is located at www. .com and we make our periodic reports and other information filed with or furnished to the SEC available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

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We intend to furnish or make available to our unitholders annual reports containing our audited financial statements and furnish or make available to our unitholders quarterly reports containing our unaudited interim financial information, including the information required by Form 10-Q, for the first three fiscal quarters of each fiscal year.

FORWARD-LOOKING STATEMENTS

Some of the information in this prospectus may contain forward-looking statements. These statements can be identified by the use of forward-looking terminology including “may,” “believe,” “will,” “expect,” “anticipate,” “estimate,” “continue,” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition, or state other “forward-looking” information. These forward-looking statements involve risks and uncertainties. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus. The risk factors and other factors noted throughout this prospectus could cause our actual results to differ materially from those contained in any forward-looking statement.

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INDEX TO FINANCIAL STATEMENTS

CYPRESS ENERGY PARTNERS, L.P.


Introduction			F-3
Unaudited Pro Forma Condensed Combined Balance Sheet as of September 30, 2013			F-5
Unaudited Pro Forma Condensed Combined Statement of Operations for the nine months ended September 30, 2013			F-7
Unaudited Pro Forma Condensed Combined Statement of Operations for the year ended December 31, 2012			F-8
Notes to Unaudited Pro Forma Condensed Combined Financial Statements			F-9
CYPRESS ENERGY PARTNERS PREDECESSOR
Report of Independent Registered Public Accounting Firm			F-17
Consolidated Balance Sheets as of December 31, 2012 and 2011			F-18
Consolidated Statements of Income for the year ended December 31, 2012 and the period from June 1, 2011 (Inception) through December 31, 2011			F-19
Consolidated Statements of Changes in Members’ Equity for the period from June 1, 2011 (Inception) through December 31, 2012			F-20
Consolidated Statements of Cash Flows for the year ended December 31, 2012 and the period from June 1, 2011 (Inception) through December 31, 2011			F-21
Notes to Consolidated Financial Statements			F-22
Unaudited Condensed Consolidated Balance Sheets as of September 30, 2012 and December 31, 2011			F-28
Unaudited Condensed Consolidated Statements of Income for the nine-months ended September 30, 2012 and for the period from June 1, 2011 (Inception) through September 30, 2011			F-29
Unaudited Condensed Consolidated Statements of Cash Flows for the nine-months ended September 30, 2012 and for the period from June 1, 2011 (Inception) through September 30, 2011			F-30
Notes to Unaudited Condensed Consolidated Financial Statements			F-31
CYPRESS ENERGY PARTNERS, LLC
Report of Independent Registered Public Accounting Firm			F-34
Consolidated Balance Sheet as of December 31, 2012			F-35
Consolidated Statements of Operations for the period from March 15, 2012 (Inception) through December 31, 2012			F-36
Consolidated Statement of Changes in Members’ Equity for the period from March 15, 2012 (Inception) through December 31, 2012			F-37
Consolidated Statements of Cash Flows for the period from March 15, 2012 (Inception) through December 31, 2012			F-38
Notes to Consolidated Financial Statements			F-39
Unaudited Condensed Consolidated Balance Sheets as of September 30, 2013 and December 31, 2012			F-50
Unaudited Condensed Consolidated Statements of Operations for the nine-months ended September 30, 2013 and for the period from March 15, 2012 (Inception) through September 30, 2012			F-51

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Unaudited Condensed Consolidated Statements of Cash Flows for the nine-months ended September 30, 2013 and for the period from March 15, 2012 (Inception) through September 30, 2012			F-52
Notes to Unaudited Condensed Consolidated Financial Statements			F-53


ASSETS PURCHASED BY CYPRESS ENERGY PARTNERS, LLC FROM MOXIE DISPOSAL SYSTEMS, LLC AND PEACH ENERGY SERVICES, LLC
Report of Independent Auditors			F-58
Statement of Revenues and Direct Operating Expenses of Assets Purchased by Cypress Energy Partners, LLC From Moxie Disposal Systems, LLC and Peach Energy Services, LLC from period from July 1, 2012 (Inception) through December 3, 2012			F-59
Notes to Statement of Revenues and Direct Operating Expenses of Assets Purchased by Cypress Energy Partners, LLC From Moxie Disposal Systems, LLC and Peach Energy Services, LLC			F-60
TULSA INSPECTION RESOURCES, INC.
Report of Independent Certified Public Accountants			F-62
Consolidated Balance Sheets as of December 31, 2012 and 2011			F-63
Consolidated Statements of Operations and Comprehensive Income for the years ended December 31, 2012 and 2011			F-64
Consolidated Statements of Changes in Stockholders’ Equity for the years ended December 31, 2012 and 2011			F-65
Consolidated Statements of Cash Flows for the years ended December 31, 2012 and 2011			F-66
Notes to Consolidated Financial Statements			F-67
Unaudited Condensed Consolidated Balance Sheets as of September 30, 2013 and December 31, 2012			F-78
Unaudited Condensed Consolidated Statements of Operations and Comprehensive Income for the nine-months ended September 30, 2013 and September 30, 2012			F-79
Unaudited Condensed Statement of Changes in Stockholders’ Equity for the period January 1, 2013 to September 30, 2013			F-80
Unaudited Condensed Consolidated Statements of Cash Flows for the nine-months ended September 30, 2013 and September 30, 2012			F-81
Notes to Unaudited Condensed Consolidated Financial Statements			F-82
CYPRESS ENERGY PARTNERS, L.P. HISTORICAL BALANCE SHEET
Report of Independent Registered Public Accounting Firm			F-89
Balance Sheet as of September 19, 2013 (Inception)			F-90
Notes to Balance Sheet			F-91

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Cypress Energy Partners, L.P.

Unaudited Pro Forma Condensed Combined Financial Statements

Introduction

Set forth below is the unaudited pro forma condensed combined balance sheet as of September 30, 2013 and the unaudited pro forma condensed combined statements of operations for the year ended December 31, 2012 and the nine months ended September 30, 2013 for Cypress Energy Partners, L.P. “Cypress Energy Partners, L.P.,” “we,” “our,” “us” or similar terms refer to Cypress Energy Partners, L.P. and its operating subsidiaries. Prior to the effective date of our initial public offering, we were Cypress Energy Partners, LLC.

Our unaudited pro forma financial statements should be read in conjunction with (i) the audited and unaudited historical financial statements of Cypress Energy Partners, LLC (“CEP Successor”); (ii) the audited and unaudited historical financial statements of Cypress Energy Partners Predecessor (“SBG Predecessor”); (iii) the audited Statement of Revenue and Direct Operating Expenses of Assets Purchased by Cypress Energy Partners, LLC from Moxie Disposal Systems, LLC and Peach Energy Services, LLC (“Moxie”); and (iv) the audited and unaudited historical consolidated financial statements of Tulsa Inspection Resources, Inc. (“TIR Inc.”); in each case as included elsewhere in this prospectus.

Our unaudited pro forma financial statements present the unaudited pro forma condensed combined balance sheet of Cypress Energy Partners, L.P. as of September 30, 2013 after giving pro forma effect to the following transactions described in the notes hereto (the “Transactions”):

•

the retention by Cypress Energy Holdings (“Cypress Holdings”) of the assets and liabilities associated with the CEP Successor's SWD facility in Sheridan County, Montana and a related-party receivable and permit associated with the construction of a potential new SWD facility;

•

the contribution to us of the CEP Successor and a 50.1% interest in the U.S. operations of TIR Inc. (“TIR-US”) in exchange for the issuance by us of common units and subordinated units, representing an aggregate % limited partner interest, to Cypress Holdings and its affiliates;

•

the issuance by us of the incentive distribution rights to our general partner; and

•

Our unaudited pro forma financial statements present the unaudited pro forma condensed combined statement of operations of Cypress Energy Partners, L.P. for the nine months ended September 30, 2013 after giving pro forma effect to the Transactions as if the Transactions occurred on January 1, 2013, and the unaudited pro forma condensed combined balance sheet as of September 30, 2013 after giving pro forma effect to the Transactions as if the Transactions occurred on September 30, 2013. The unaudited pro forma condensed combined statement of operations for the nine months ended September 30, 2013 is based on the unaudited historical statement of operations of Cypress Energy Partners LLC for the nine months ended September 30, 2013 and the

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Cypress Energy Partners, L.P.

Unaudited Pro Forma Condensed Combined Financial Statements

unaudited historical statement of operations of TIR Inc. for the period from January 1, 2013 to September 30, 2013. The unaudited pro forma condensed combined balance sheet for the nine months ended September 30, 2013 is based on the unaudited historical balance sheet of Cypress Energy Partners LLC as of September 30, 2013 and the unaudited historical balance sheet of TIR Inc. as of September 30, 2013, after giving effect to the Transactions as if they had occurred on September 30, 2013. Our unaudited pro forma financial statements do not include the results of operations for Cypress Energy Services, LLC.

Our unaudited pro forma financial statements present the unaudited pro forma condensed combined statement of operations of Cypress Energy Partners, L.P. for the year ended December 31, 2012, after giving pro forma effect to the Transactions as if the Transactions occurred on January 1, 2012. The unaudited pro forma condensed combined statement of operations for the year ended December 31, 2012 is based on the audited statement of income for the Predecessor for the year ended December 31, 2012; the audited statement of operations for the CEP Successor for the period from March 15, 2012 (Inception) to December 31, 2012; the audited Statement of Revenue and Direct Operating Expenses of Assets Purchased by Cypress Energy Partners, LLC from Moxie Disposal Systems, LLC and Peach Energy Services, LLC for the period from July 1, 2012 (Inception) through December 3, 2012 and the audited statement of operations of Tulsa Inspection Resources, Inc. for the year ended December 31, 2012. Beginning December 4, 2012 with regard to Moxie and December 31, 2012 with regard to the SBG Predecessor, these Acquisitions are reflected in the audited and unaudited historical financial statements of Cypress Energy Partners, LLC.

The Statement of Revenue and Direct Operating Expenses of Assets Purchased by Cypress Energy Partners, LLC from Moxie Disposal Systems, LLC and Peach Energy Services, LLC referred to above varies from a complete income statement in accordance with U.S. generally accepted accounting principles in that it does not reflect certain expenses that were incurred in connection with the ownership and operation of the assets purchased by Cypress Energy Partners, LLC from Moxie Disposal Systems, LLC and Peach Energy Services, LLC (the “Acquired Assets”), including, but not limited to, general and administrative expenses, interest expenses, and federal and state income tax expenses. These costs were not separately allocated to the Acquired Assets in the accounting records of Moxie Disposal Systems, LLC. In addition, the allocations, if made using historical general and administrative structures and tax burdens, would not produce allocations that would be indicative of the historical performance of the Acquired Assets had they been our facilities due to the differing size, structure, operations, and accounting policies of Moxie Disposal Systems, LLC and us. The accompanying statement also does not include provisions for depreciation, amortization, and accretion expense associated with asset retirement obligations, as such amounts would not be indicative of the costs that we will incur upon the allocation of the purchase price paid for the Acquired Assets.

As a result, these unaudited pro forma condensed combined financial statements are not indicative of our operations on a go forward basis because they necessarily exclude various operating expenses related to the Moxie assets.

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Cypress Energy Partners, L.P.

Unaudited Pro Forma Condensed Combined Financial Statements

Cypress Energy Partners, LP
Unaudited Pro Forma Condensed Combined Balance Sheet
As of September 30, 2013
(In Thousands)


	Historical CEP Successor		Adjusted Historical TIR-US (1)		Pro Forma Adjustments Amount				Pro Forma
Assets
Current assets:
Cash and cash equivalents	$	5,135	$	9,239	$	(68	)	(a)	$
								(b)
								(c)
								(c)
								(c)
								(d)
								(d)
								(e)
Trade accounts receivable		3,126		54,213		(3	)	(a)		57,336
Related-party accounts receivable		410		6,466		—		(a)		410
						(6,466	)	(b)
Affiliate accounts receivable		359		111		—				470
Other current assets		698		496		(74	)	(a)		1,120
Total current assets		9,728		70,525
Property and equipment, at cost:
Property and equipment		44,478		803		(376	)	(a)		44,905
Less: accumulated depreciation		2,900		75		(5	)	(a)		2,970
Total property and equipment		41,578		728		(371	)			41,935
Goodwill and other intangible assets, net		34,146		53,532				(c)		87,678
								(c)
Note due from subsidiary		—		3,903		(3,903	)	(b)		—
Other noncurrent assets		—		31						31
Total assets	$	85,452	$	128,719	$				$
Liabilities and equity
Current liabilities:
Accounts payable	$	638	$	600	$	(1	)	(a)	$	1,237
Accrued payroll and other		476		17,772		(6	)			18,242
Taxes payable		—		802		(802	)	(b)		—
Related-party payables		419		—		—		(a)		419
Obligation under factoring agreement		—		37,758				(c)
								(c)
Deferred tax liability, current		—		40		(40	)	(b)		—
Total current liabilities		1,533		56,972
Notes payable		—		20,463				(c)
Asset retirement obligations		9		—		(1	)	(a)		8
Deferred tax liability, noncurrent		—		86		(86	)	(b)		—


Total liabilities		1,542		77,521

(1)

Represents historical operations of Tulsa Inspection Resources, Inc. adjusted to remove operations not contributed to us.

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Cypress Energy Partners, L.P.

Unaudited Pro Forma Condensed Combined Financial Statements
(In Thousands)


	Historical CEP Successor		Adjusted Historical TIR-US		Pro Forma Adjustments Amount				Pro Forma
Total parent equity		83,910		51,198		(524	)	(a)
		—		—		1,104		(b)
								(b)
						(3,903	)	(b)
						(6,466	)	(b)
Limited partner interests
Common units								(d)
Subordinated units
General partner and affiliates:
Common units								(b)
Subordinated units								(b)


		—		—				(b)
Noncontrolling interest		—		—				(b)
Total equity		83,910		51,198
Total liabilities and equity	$	85,452	$	128,719	$				$

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Cypress Energy Partners, L.P.

Unaudited Pro Forma Condensed Combined Financial Statements
(In Thousands)

Cypress Energy Partners, LP
Unaudited Pro Forma Condensed Combined Statement of Operations
For the Nine Months Ended September 30, 2013


	Historical CEP Successor		Adjusted Historical TIR-US			Pro Forma Adjustments Amount				Pro Forma
Revenues	$	16,665	$	230,425		$	(160	)	(a)	$	246,930
Costs of sales		5,426		—			(271	)	(a)		5,155
Costs of services		—		208,937			—				208,937
Gross margin		11,239		21,488			111				32,838
Operating costs and expense:
General and administrative		2,427		10,905			(42	)	(a)		13,290
Impairment loss		4,375		—			(4,375	)	(a)		—
Depreciation and amortization		3,066		1,353			(246	)	(a)		4,173
Operating income		1,371		9,230			4,774				15,375
Nonoperating income (expense):
Interest expense, net		—		(3,257	)		(9	)	(c)		(3,266	)
Other, net		11,250		1			—				11,251
Income before income taxes		12,621		5,974			4,765				23,360
Income tax expense		40		2,427			(2,124	)	(b)		343
Net income		12,581		3,547			6,889				23,017
Net income attributable to noncontrolling interests in TIR		—		—			2,109		(b)(f)		2,109
Net income attributable to Cypress Energy Partners, L.P.	$	12,581	$	3,547		$	4,780			$	20,908
General partner’s interest in net income attributable to Cypress Energy Partners, LP
Limited partner’s interest in net income attributable to Cypress Energy Partners, LP
Common units
Subordinated units
Net income per limited partner unit
Common units
Subordinated units
Weighted average number of limited partner units outstanding (basic and diluted)
Common units
Subordinated units

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Cypress Energy Partners, L.P.

Unaudited Pro Forma Condensed Combined Financial Statements

Cypress Energy Partners LP
Unaudited Pro Forma Condensed Combined Statement of Operations
For the Year Ended December 31, 2012
(In Thousands)



	Historical
	Year ended December 31, 2012			Period from March 15, 2012 (Inception) – December 31, 2012			Period from July 1, 2012 – December 3, 2012		Adjusted Historical TIR-US			Pro Forma Adjustments Amount				Pro Forma
	SBG Predecessor			CEP Successor			Moxie		Adjusted Historical TIR-US			Pro Forma Adjustments Amount				Pro Forma
Revenues	$	12,203		$	619		$	3,180	$	185,988		$	(1,357	)	(a)	$	200,633
Costs of sales		3,662			309			1,789		—			(624	)	(a)		5,136
Costs of services		—			—			—		167,957			—				167,957
Gross margin		8,541			310			1,391		18,031			(733	)			27,540
Operating expense:
General and administrative		477			2,056			—		7,593			(72	)	(a)		10,054
Depreciation and amortization		1,398			99			—		1,870			(243	)	(a)		3,124
Operating income		6,666			(1,845	)		1,391		8,568			(418	)			14,362
Nonoperating income (expense):
Interest expense, net		(111	)		—			—		(4,271	)		18		(a)		(4,001	)
													363		(c)
Other, net		40			—			—		5			—				45
Income (loss) before income taxes		6,595			(1,845	)		1,391		4,302			(37	)			10,406
Income tax expense		—			—			—		1,731			(1,477	)	(b)		254
Net income		6,595			(1,845	)		1,391		2,571			1,440				10,152
Net income attributable to noncontrolling interests in TIR		—			—			—		—			1,167		(b)(f)		1,167
Net income attributable to Cypress Energy Partners, L.P.	$	6,595		$	(1,845	)	$	1,391	$	2,571		$	273			$	8,985
General partner’s interest in net income attributable to Cypress Energy Partners, LP
Limited partner’s interest in net income attributable to Cypress Energy Partners, LP
Common units
Subordinated units
Net income per limited partner unit
Common units
Subordinated units
Weighted average number of limited partner units outstanding (basic and diluted)
Common units
Subordinated units

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Cypress Energy Partners, L.P.

Notes to Unaudited Pro Forma Condensed Combined Financial Statements

1. Basis of Presentation

See “Introduction” for more information regarding the basis of presentation for our unaudited pro forma financial statements.

2. Pro Forma Adjustments and Assumptions

The following adjustments have been made as if the Transactions had taken place at January 1, 2012 in the case of the pro forma statement of operations and on September 30, 2013 in the case of the pro forma balance sheet.

(a) Reflects the retention of an SWD well in Sheridan County, Montana and a related-party receivable and permit associated with the construction of a potential new facility.

(b) Reflects transactions associated with Cypress Holding’s contribution of a 50.1% interest in the U.S. operations of TIR Inc. to us as follows:

•

The reversal of taxes payable and deferred tax balances as a result of the conversion of TIR-US to a pass-through entity for federal income tax purposes immediately prior to our initial public offering. The income tax liability and expense associated with the conversion TIR-US from a taxable entity to a pass through entity for federal income tax purposes is not reflected in these pro forma financial statements.

•

The distribution of related-party receivables due to TIR-US from affiliated entities that will not be contributed to us.

•

The issuance by Cypress Energy Partners, L.P. of common units and subordinated units to Cypress Holdings and $ in cash as partial consideration for Cypress Holdings’ the contribution of a 50.1% interest in TIR-US.

•

Cash distributions to Cypress Holdings of $ million as partial consideration for the contribution of a 50.1% interest TIR-US.

•

Amortization of intangibles of TIR-US not included in the historical financial statements of TIR-US.

•

Adjustment to reflect the non-controlling interest in TIR-US.

•

Entry into an amendment to our $50 million factoring facility and an amendment to upsize our mezzanine facilities to $ million, with aggregate borrowings of $ million under our amended factoring facility and $ million under our upsized mezzanine facilities at the closing of this offering.

•

Payment of closing costs associated with amending TIR Inc.’s existing credit facilities totaling $ .

•

Write-off of existing deferred financing costs.

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Cypress Energy Partners, L.P.

Notes to Unaudited Pro Forma Condensed Combined Financial Statements

2. Pro Forma Adjustments and Assumptions – (continued)

•

Reflects the incurrence of indebtedness under our amended factoring facility and mezzanine facilities. The table presents a reconciliation of our historical interest expense to pro forma interest expense adjustment for the year ended December 31, 2012 and nine months ended September 30, 2013.


	Year Ended December 31, 2012			Nine Months Ended September 30, 2013
	(in thousands)
SBG Predecessor historical interest expense	$	111		$	—
Adjusted historical TIR interest expense		4,271			3,257
Pro forma historical interest expense adjustment for retention of an SWD well in Sheridan County, Montana		(18	)		—
Pro forma historical interest expense	$	4,364		$	3,257
Less:
Our amended mezzanine facilities interest		2,909			2,175
Our amended factoring facility interest		714			862
Non-cash interest		378			229
Total pro forma adjusted interest		4,001			3,266
Pro forma interest expense adjustment	$	363		$	(9	)
$4,001	$	3,266
Less: TIR interest attributable to TIR Inc. non-controlling interest at 49.9%		1,996			1,630
Less: TIR incremental interest charge attributable to TIR Inc. non-controlling interest		988			716
Interest expense attributable to controlling interest	$	1,017		$	920

•

Payment of deferred financing cost totaling $ on the new facilities.

(d) Reflects cash proceeds, after deducting underwriting discounts, structuring fees and offering expenses of $ , of approximately from the issuance and sale of common units by Cypress Energy Partners, L.P. at an assumed initial public offering price of $ per unit (the midpoint of the range shown on the cover of this prospectus).

(e) Reflects a distribution to Cypress Holdings with the net proceeds of the offering to reimburse it for capital expenditures it incurred with respect to assets contributed to us.

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TABLE OF CONTENTS

Cypress Energy Partners, L.P.

Notes to Unaudited Pro Forma Condensed Combined Financial Statements

2. Pro Forma Adjustments and Assumptions – (continued)

(f) Reflects the earnings before interest and taxes attributable to the non-controlling interest holders in TIR Inc. The table presents the interest payments attributable to such interest holders under our pro forma indebtedness and the amount of incremental interest charge payable so that they are responsible for the same interest rate as they pay under their existing TIR Inc. indebtedness.


	Year Ended December 31, 2012		Nine Months Ended September 30, 2013
	(in thousands)
TIR Inc. net income attributable to TIR Inc. non-controlling interests at 49.9%	$	4,151	$	4,455
Less: TIR Inc. interest attributable to TIR Inc. non-controlling interests at 49.9%		1,996		1,630
Less: TIR Inc. incremental interest charge attributable to TIR Inc. non-controlling interests		988		716
TIR Inc. net income attributable to non-controlling interests in TIR Inc.	$	1,167	$	2,109

(g) Does not reflect any incremental expenses for being a publicly traded partnership that we estimate will be $2.0 million per year or the payment of the $3.0 million annual fixed fee our general partner will charge us for the provision of certain corporate overhead expenses allocated to us by Cypress Holdings.

3. Non-recurring Charges

The historical statement of operations of the CEP Successor for the nine months ended September 30, 2013 includes an $11.25 million gain on reversal of contingent consideration, which is a non-recurring charge.

The historical statement of operations for TIR-US include a non-recurring charge in general and administrative expenses of $1.4 million associated with a special bonus payment and employee related costs associated with the acquisition of TIR by a subsidiary of Cypress Holdings.

4. Pro Forma Net Income Per Limited Partner Unit

Pro forma net income per limited partner unit is determined by dividing the pro forma net income that would have been allocated, in accordance with the net income allocation provisions of the partnership agreement, to the common and subordinated units expected to be outstanding at the closing of the offering. For purposes of this calculation, we assumed that the minimum quarterly distribution was made to all unitholders during the period presented.

Pro forma Cypress Energy Partners, L.P. earnings per unit was calculated using common and subordinated units. The common and subordinated units represented an aggregate 100% limited partner interest in Cypress Energy Partners, L.P. All units were assumed to have been outstanding since January 1, 2012.

We compute earnings per unit using the two-class method. The two-class method requires that securities that meet the definition of a participating security be considered for inclusion in the computation of basic earnings per unit. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of the partnership agreement, regardless of whether the general partner has discretion over the amount of

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Cypress Energy Partners, L.P.

Notes to Unaudited Pro Forma Condensed Combined Financial Statements

4. Pro Forma Net Income Per Limited Partner Unit – (continued)

distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period.

The two-class method does not impact our overall net income or other financial results; however, in periods in which aggregate net income exceeds our aggregate distributions for such period, it will have the impact of reducing net income per limited partner unit. This result occurs as a larger portion of our aggregate earnings, as if distributed, is allocated to the incentive distribution rights of the general partner, even though we make distributions on the basis of available cash and not earnings. In periods in which our aggregate net income does not exceed our aggregate distributions for such period, the two-class method does not have any impact on our calculation of earnings per limited partner unit.

Basic and diluted pro forma net income per unit are equivalent as there are no dilutive units at the date of closing of the initial public offering of the common units of the Partnership. Pursuant to the partnership agreement, to the extent that the quarterly distributions exceed certain targets, our general partner is entitled to receive certain incentive distributions that will result in more net income proportionately being allocated to our general partner than to the holders of common and subordinated units. The pro forma net income per unit calculations assume that no incentive distributions were made to our general partner because no such distribution would have been paid based upon the pro forma available cash from operating surplus for the periods.

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Cypress Energy Partners, L.P.

Notes to Unaudited Pro Forma Condensed Combined Financial Statements

5. Tulsa Inspection Resources, Inc. Reconciling Tables

The following tables reflect the historical U.S. operations of TIR Inc. as of and for the periods indicated. These tables were derived from, and should be read together with, the audited and unaudited financial statements of TIR Inc. appearing elsewhere in this prospectus.

Tulsa Inspection Resources, Inc.

Unaudited Condensed Reconciliation of the
Consolidated Historical TIR Inc. Balance Sheet to the TIR-US Balance Sheet
As of September 30, 2013
(In Thousands)


	Consolidated Historical TIR Inc.		Less: Non-Contributed Subsidiaries(a)			Historical TIR-US
Assets
Current assets:
Cash and cash equivalents	$	13,123	$	3,884		$	9,239
Trade accounts receivable, net		65,536		11,323			54,213
Related-party accounts receivable		—		(6,466	)		6,466
Deferred tax assets		36		36			—
Due from affiliate		111		—			111
Other current assets		567		71			496
Total current assets		79,373		8,848			70,525
Property and equipment, at cost:
Property and equipment		2,166		675			1,491
Less: accumulated depreciation		964		201			763
Total property and equipment		1,202		474			728
Goodwill and other intangible assets, net		23,392		5,365			18,027
Debt issuance costs		545		22			523
Note due from subsidiary		—		(3,903	)		3,903
Other noncurrent assets		22		11			11
Total assets	$	104,534	$	10,817		$	93,717
Liabilities and equity
Current liabilities:
Accounts payable	$	2,784	$	2,184		$	600
Accrued payroll and other		18,209		437			17,772
Taxes payable		744		(58	)		802
Obligation under factoring agreement		45,165		7,407			37,758
Deferred tax liability, current		—		(40	)		40
Total current liabilities		66,902		9,930			56,972
Notes payable, less current maturities		19,615		—			19,615
Deferred tax liability, noncurrent		1,010		924			86
Total liabilities		87,527		10,854			76,673
Total equity		17,007		(37	)		17,044
Total liabilities and equity	$	104,534	$	10,817		$	93,717

(a)

Accounts for the exclusion of Tulsa Inspection Resources — Nondestructive Examination, Inc., Tulsa Inspection Resources — Canada, Inc. and Foley Inspection Services, Inc.

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Cypress Energy Partners, L.P.

Notes to Unaudited Pro Forma Condensed Combined Financial Statements

5. Tulsa Inspection Resources, Inc. Reconciling Tables – (continued)

Tulsa Inspection Resources, Inc.

Unaudited Adjusted Condensed Reconciliation of
Historical TIR-US Balance Sheet as of September 30, 2013 to
Adjusted Historical TIR-US Balance Sheet
As of September 30, 2013
(In Thousands)


	Historical TIR-US as of September 30, 2013		Purchase Price Adjustments(a)			Adjusted Historical TIR-US
Assets
Current assets:
Cash and cash equivalents	$	9,239	$	—		$	9,239
Trade accounts receivable, net		54,213		—			54,213
Related-party receivables		6,466		—			6,466
Due from affiliate		111		—			111
Other current assets		496		—			496
Total current assets		70,525		—			70,525
Property and equipment, at cost:
Property and equipment		1,491		(688	)		803
Less: accumulated depreciation		763		(688	)		75
Total property and equipment		728		—			728
Goodwill and other intangible assets, net		18,027		35,505			53,532
Debt issuance costs		523		(503	)		20
Note due from subsidiary		3,903		—			3,903
Other noncurrent assets		11		—			11
Total assets	$	93,717	$	35,002		$	128,719
Liabilities and equity
Current liabilities:
Accounts payable	$	600	$	—		$	600
Accrued payroll and other		17,772		—			17,772
Taxes payable		802		—			802
Obligation under factoring agreement		37,758		—			37,758
Deferred tax liabilities, current		40		—			40
Total current liabilities		56,972		—			56,972
Notes payable, less current maturities		19,615		848			20,463
Deferred tax liability, noncurrent		86		—			86
Total liabilities		76,673		848			77,521
Total equity		17,044		34,154			51,198
Total liabilities and equity	$	93,717	$	35,002		$	128,719

(a)

Represents the purchase price adjustment attributable to the change of control of TIR Inc. on June 26, 2013 and net activity through September 30, 2013.

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Cypress Energy Partners, L.P.

Notes to Unaudited Pro Forma Condensed Combined Financial Statements

5. Tulsa Inspection Resources, Inc. Reconciling Tables – (continued)

Tulsa Inspection Resources, Inc.

Unaudited Condensed Reconciliation of Consolidated
Historical TIR Inc. Statement of Operations to TIR-US
For the Year Ended December 31, 2012
(In Thousands)


	Consolidated Historical TIR Inc.			Less: Non-Contributed Subsidiaries (a)			Historical TIR-US
Revenues	$	233,803		$	47,815		$	185,988
Costs of services		211,404			43,447			167,957
Gross margin		22,399			4,368			18,031
Operating expense:
General and administrative		10,528			2,935			7,593
Depreciation and amortization		2,438			568			1,870
Operating income		9,433			865			8,568
Nonoperating income (expense)
Interest expense		(4,956	)		(685	)		(4,271	)
Other, net		6			1			5
Income before income taxes		4,483			181			4,302
Income tax expense		(1,821	)		(90	)		(1,731	)
Net income	$	2,662		$	91		$	2,571

(a)

Accounts for the exclusion of Tulsa Inspection Resources — Nondestructive Examination, Inc., Tulsa Inspection Resources — Canada, Inc. and Foley Inspection Services, Inc.

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Cypress Energy Partners, L.P.

Notes to Unaudited Pro Forma Condensed Combined Financial Statements

5. Tulsa Inspection Resources, Inc. Reconciling Tables – (continued)

Unaudited Condensed Reconciliation of
Consolidated Historical TIR Inc. Statement of Operations
to TIR-US
For the Nine Months Ended September 30, 2013
(In Thousands)


	Consolidated Historical TIR Inc.			Less: Non-Contributed Subsidiaries(a)			Adjustments to TIR-U.S.			Adjusted Historical TIR-U.S.
Revenues	$	267,977		$	37,552		$	—		$	230,425
Costs of services		243,000			34,063			—			208,937
Gross margin		24,977			3,489			—			21,488
Operating costs and expense:
General and administrative		13,784			2,879			—			10,905
Depreciation and amortization		1,820			390			(77	)		1,353
Operating income		9,373			220			77			9,230
Interest expense, net		(3,803	)		(325	)		221			(3,257	)
Other, net		2			1			—			1
Income (loss) before income taxes		5,572			(104	)		298			5,974
Income tax expense		2,350			(77	)		—			2,427
Net income (loss)	$	3,222		$	(27	)	$	298		$	3,547

(a)

Accounts for the exclusion of Tulsa Inspection Resources — Nondestructive Examination, Inc., Tulsa Inspection Resources — Canada, Inc. and Foley Inspection Services, Inc.

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Members
Cypress Energy Partners, LLC

We have audited the accompanying consolidated balance sheets of Cypress Energy Partners Predecessor, as of December 31, 2012 and 2011, and the related consolidated statements of income, changes in members’ equity, and cash flows for the year ended December 31, 2012, and for the period from June 1, 2011 (Inception) through December 31, 2011. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Cypress Energy Partners Predecessor at December 31, 2012 and 2011, and the consolidated results of its operations and its cash flows for the year ended December 31, 2012, and for the period from June 1, 2011 (Inception) through December 31, 2011, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Tulsa, Oklahoma
September 12, 2013

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Cypress Energy Partners Predecessor

Consolidated Balance Sheets


	December 31
	2012		2011
	(in thousands)
Assets
Current assets:
Cash and cash equivalents	$	582	$	147
Accounts receivable		1,856		1,638
Prepaid expenses		61		12
Inventory		88		22
Other current assets		329		91
Total current assets		2,916		1,910
Property and equipment, at cost:
Property and equipment		26,192		12,689
Less: accumulated depreciation		1,520		123
Total property and equipment		24,672		12,566
Total assets	$	27,588	$	14,476
Liabilities and members’ equity
Current liabilities:
Accounts payable	$	399	$	2,370
Accrued liabilities		101		41
Current portion of long-term debt		557		529
Total current liabilities		1,057		2,940
Asset retirement obligations		5		2
Long-term debt		1,757		2,269
Total liabilities		2,819		5,211
Members’ equity:
Members’ equity interest – 101,900 and 99,900 units authorized and outstanding		24,769		9,265
Total liabilities and members’ equity	$	27,588	$	14,476

See accompanying notes.

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Cypress Energy Partners Predecessor

Consolidated Statements of Income


	Year Ended December 31 2012			June 1, 2011 (Inception) Through December 31 2011
	(in thousands)
Revenues	$	12,203		$	2,944
Cost of sales		3,662			503
Gross margin		8,541			2,441
Operating costs and expenses:
Depreciation and accretion		1,398			123
General and administrative		477			138
Operating income		6,666			2,180
Nonoperating income (expense):
Interest and other income		40			17
Interest expenses		(111	)		(35	)
Total nonoperating expense		(71	)		(18	)
Net income	$	6,595		$	2,162

See accompanying notes.

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Cypress Energy Partners Predecessor

Consolidated Statements of Changes in Members’ Equity
For Period From June 1, 2011 (Inception) Through December 31, 2012


	Equity
	Units		Amount
			(in thousands)
Balance, June 1, 2011 (Inception)		—	$	—
Capital contributions – A units		99,900		100
Net advances from members		—		7,003
Net income		—		2,162
Balance, December 31, 2011		99,900		9,265
Capital contributions – A units		2,000		2
Net advances from members		—		8,907
Net income		—		6,595
Balance, December 31, 2012		101,900	$	24,769

See accompanying notes.

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Cypress Energy Partners Predecessor

Consolidated Statements of Cash Flows


	Year Ended December 31 2012			June 1, 2011 (Inception) Through December 31 2011
	(in thousands)
Operating activities
Net income	$	6,595		$	2,162
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and accretion		1,398			123
Changes in assets and liabilities:
Accounts receivable		(219	)		(1,638	)
Inventory, prepaid expenses, and other assets		(353	)		(125	)
Accounts payable and accrued liabilities		(175	)		584
Net cash provided by operating activities		7,246			1,106
Investing activities
Capital expenditures		(15,236	)		(10,860	)
Net cash used in investing activities		(15,236	)		(10,860	)
Financing activities
Proceeds from issuance of debt		—			2,900
Repayments of debt		(484	)		(102	)
Net advances from members		8,907			7,003
Contributions of members’ equity		2			100
Net cash provided by financing activities		8,425			9,901
Net increase in cash and cash equivalents		435			147
Cash and cash equivalents, beginning of period		147			—
Cash and cash equivalents, end of period	$	582		$	147
Non-cash items:
Accounts payable excluded from capital expenditures	$	91		$	1,828

See accompanying notes.

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Cypress Energy Partners Predecessor

Notes to Consolidated Financial Statements
December 31, 2012

1. Organization and Operations

Cypress Energy Partners Predecessor comprises seven North Dakota limited liability companies (collectively, the Company) that were formed in 2011 and 2012, with the first being formed on June 1, 2011 (Inception) for the purpose of providing environmental services in the fluids management business for the oil and natural gas industry. On December 31, 2012, Cypress Energy Partners, LLC entered into agreements to acquire 100% of the outstanding units of the Company.

The Company operates and constructs commercial salt water disposal wells (SWDs) throughout the Williston basin in the United States. All of the Company’s facilities are built with redundant equipment, full-time attendants, and remote monitoring to minimize downtime and increase efficiency for peak utilization. These facilities also contain sophisticated oil skimming processes that remove any remaining oil from water delivered to the sites.

2. Summary of Significant Accounting Policies

Principles of Consolidation

The consolidated financial statements include the accounts of the Company. All intercompany accounts and transactions have been eliminated in consolidation.

Cash and Cash Equivalents

The Company considers all investments purchased with initial maturities of three months or less to be cash equivalents. Cash equivalents consist primarily of investments in highly liquid securities. The carrying amounts of cash and cash equivalents reported in the balance sheets approximate fair value.

The Company’s cash balances at December 31, 2012 and 2011, are insured by the Federal Deposit Insurance Corporation (FDIC) up to $250 thousand per financial institution. At times, cash balances may be in excess of the FDIC insurance limit.

Use of Estimates in the Preparation of Financial Statements

The preparation of the Company’s consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

Areas requiring the use of assumptions, judgments, and estimates relate to the amount of expected future cash flows used in determining possible impairments of long-lived assets and future retirement obligations. Certain estimates are inherently imprecise and may change as future information becomes available.

Property and Equipment

Property and equipment consist of land and improvements, buildings, furniture, fixtures and equipment, computer and office equipment, and Company-owned vehicles. The Company records property and equipment at cost. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repairs are expensed as incurred. Depreciation for these assets is computed using the straight-line method over estimated useful lives. Upon retirement or disposition of assets, the costs and related accumulated depreciation are removed from the accounts with the resulting gain or losses, if any, reflected in results of operations.

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Cypress Energy Partners Predecessor

Notes to Consolidated Financial Statements
December 31, 2012

2. Summary of Significant Accounting Policies – (continued)

Property and equipment consist of the following, recorded at cost, as of December 31:


	2012			2011
	(in thousands)
Land	$	562		$	321
Land improvements (depreciable lives – 15 years)		3,102			1,334
Buildings (depreciable lives – 39 years)		1,368			385
Facilities, wells, and equipment (depreciable lives – 9 to 15 years)		21,140			4,797
Construction in process		20			5,852
		26,192			12,689
Less accumulated depreciation		(1,520	)		(123	)
Net property and equipment	$	24,672		$	12,566

Revenue Recognition

Water disposal and oil revenues are recognized when there is persuasive evidence that an arrangement exists, delivery has occurred or services have been rendered, the seller’s price to the buyer is fixed or determinable, and collectability is reasonably assured. Water disposable revenues are based on the Company’s published or negotiated water disposal rates. Customers deliver water to be disposed to facilities and revenue is recognized when actual volumes of water are disposed. Oil disposal revenues are determined based on published rates based on the quality of the oil sold and are recognized when actual volumes of oil are skimmed and delivered to the customer, the quality of oil is determined, and the collectability is reasonably assured.

Accounts Receivable

The Company disposes of water for its customers and sells oil to various customers. Amounts are considered past due after 30 days. The Company determines accounts receivable allowances based on management’s assessment of the creditworthiness of the customers and other collection actions. The Company did not record an allowance at December 31, 2012 or 2011, nor did the Company record any bad debt expense for the year ended December 31, 2012, or for the period from Inception through December 31, 2011. The Company charges interest on past-due balances.

Inventory

Inventory consists of miscellaneous supplies that are removed on a FIFO basis as they are used. The Company’s inventory was $88 thousand and $22 thousand at December 31, 2012 and 2011, respectively.

Income Taxes

The Company evaluates uncertain tax positions for recognition and measurement in the financial statements. To recognize a tax position, the Company determines whether it is more likely than not that the tax positions will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the financial statements. The amount of tax benefit recognized with respect to any

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Cypress Energy Partners Predecessor

Notes to Consolidated Financial Statements
December 31, 2012

2. Summary of Significant Accounting Policies – (continued)

tax position is measured as the largest amount of benefit that is greater than 50% likely of being realized upon settlement. The Company had no uncertain tax positions that required recognition in the financial statements at December 31, 2012 or 2011. Any interest or penalties would be recognized as a component of income tax expense.

Concentration of Credit Risk

The Company’s water disposal and oil revenues are derived from a variety of customers, including both trucking and exploration and production companies. The Company’s accounts receivable are from oil and gas companies and individually owned trucking companies. Our ten largest customers generated approximately 78% and 96% of our revenues for the years ended December 31, 2012 and for the period from June 1, 2011 (Inception) through December 31, 2011, respectively. For the year ended December 31, 2012, the Company had two customers, Power Fuels, Inc. and Oxy USA, Inc., that represented 22% and 16% of the Company’s consolidated revenues, respectively. For the period from June 1, 2011 (inception) through December 31, 2011, the Company had one customer, Hess Corporation, that represented 66% of the Company’s consolidated revenues. If one or more of these customers were to default on their payment obligations, we may not be able to replace any of these customers in a timely fashion, on favorable terms, or at all. Management believes that any credit risk imposed by a concentration in producers and trucking companies in the oil and natural gas industry is offset by the creditworthiness of the Company’s customer base.

Environmental

The Company is subject to extensive federal, state, and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require the Company to mitigate the environmental effects of disposal activities such as the release of petroleum or salt water at various sites. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are accrued when known and estimable. The Company currently has no recorded liabilities for environmental assessments or remediation.

Asset Retirement Obligation

The Company has obligations under its lease agreements and state and federal regulations to remove equipment and restore land at the end of its salt water disposal operations. Accounting standards require that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made and that the associated asset retirement costs be part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related wells and equipment is charged to expense through depreciation. Changes in the liability due to passage of time are recognized as accretion expense and a corresponding increase in the carrying amount of the liability. The Company recognizes asset retirement obligations for its salt water disposal operations at the end of the month of acquisition or when disturbance of the ground occurs during the construction of a well. Such obligations consist of future costs, net of recoverable salvage value of tangible equipment, to plug and abandon the salt water disposal wells when the wells permanently cease operations.

The Company estimates the fair value of the asset retirement obligation (ARO) based on discounted cash flow projections using numerous estimates, assumptions, and judgments regarding such factors as the existence of a legal obligation for an ARO; amounts and timing of settlements; the credit-adjusted, risk-free rate to be used; and inflation rates.

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Cypress Energy Partners Predecessor

Notes to Consolidated Financial Statements
December 31, 2012

2. Summary of Significant Accounting Policies – (continued)

The activity for the year ended December 31, 2012, and the period from Inception through December 31, 2011, is as follows:


	2012		2011
	(in thousands)
Asset retirement obligations, beginning of period	$	2	$	—
Liabilities incurred – constructed wells		3		2
Accretion expense		—		—
Asset retirement obligations, end of period	$	5	$	2

Fair Value of Financial Instruments

The carrying amounts reported in the balance sheet for cash, accounts receivable, and accounts payable approximate their fair values.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are reported at fair value on a nonrecurring basis in the Company’s consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:

Impairments of Long-Lived Assets

The Company reviews its property and equipment for impairment whenever events or changes in circumstances indicate, in the judgment of the Company’s management, that a decline in the recoverability of their carrying value may have occurred. Assets are grouped for impairment purposes at each facility, which includes the well and supporting equipment and infrastructure, as this represents the lowest level of cash flows associated with the asset group. When an indicator of impairment has occurred, the Company compares its estimate of undiscounted cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. If the estimate of undiscounted cash flows is less than the carrying value of the asset group, the Company determines the amount of the impairment recognized in the financial statements by estimating the fair value of the assets using a discounted cash flow model and recording a loss for the amount by which the carrying value exceeds the estimated fair value. The Company had no impairment of long-lived assets at December 31, 2012 or 2011.

Judgments and assumptions are used in the Company’s estimate of undiscounted future cash flows and an asset’s fair value. These judgments and assumptions include such matters as the estimation of oil and gas drilling and producing volumes in the markets served, risks associated with the different zones into which salt water is disposed, expected future disposal rates and commodity prices, capital expenditures, operating costs, and appropriate discount rates.

3. Debt

In 2011, the Company entered into a series of senior term notes with Starion Financial (the Lenders) totaling $2.9 million (the Notes). Borrowings under the Notes are secured by the assets of the Company, as well as personnel guarantees of the sole member and its sponsor. As of December 31, 2012 and 2011, the outstanding balances on the Notes were $2.3 million and $2.8 million, respectively. Borrowings under the Notes incur interest at a fixed rate of 4.85%, which is due and payable monthly with the principal balance of each of the Notes to be paid over a 60-month period. The annual weighted average interest rate on borrowings outstanding under the Notes at December 31, 2012 and 2011, was 4.85%.

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TABLE OF CONTENTS

Cypress Energy Partners Predecessor

Notes to Consolidated Financial Statements
December 31, 2012

3. Debt – (continued)

The Notes contain covenants that require the Company to, among other things, allow the creditor to file perfected security interests in the properties and maintain proper insurance on the properties. As of December 31, 2012 and 2011, the Company was in compliance with all financial and nonfinancial covenants. If an event of default occurs and is continuing, the Lenders may declare all amounts due under the Notes to be immediately due and payable.

Interest of $111 thousand and $35 thousand was paid during the year ended December 31, 2012, and the period ended December 31, 2011, respectively.

Aggregate maturities of debt at December 31, 2012, were as follows:


	(in thousands)
2013	$	656
2014		656
2015		656
2016		346
	$	2,314

4. Related-Party Transactions

The Company had a net advance from members at December 31, 2012 and 2011, of $15.9 million and $7.0 million, respectively, related to cash held on behalf of the Company in the accounts of its sole member, or subsidiaries of its sole member, net of transactions for the construction of facilities paid on the Company’s behalf. The sole member of the Company or his employees own several entities with which the Company does business, including SBG Energy Services, LLC ($140 thousand in 2012 general and administrative expenses); SBG Disposal LLC ($310 thousand in 2011 employee-related costs and general and administrative expenses and $1.7 million in 2012 employee-related costs and general and administrative expenses); Rud Transportation LLC ($693 thousand in 2012 water disposal revenues and $66 thousand in 2012 construction in process); and Sinkler Energy LLC ($29 thousand in 2012 repair and maintenance expenses).

5. Commitments and Contingencies

The Company has various performance obligations which are secured with short-term security deposits of $311 thousand and $91 thousand in 2012 and 2011 respectively, included in Other current assets on the Consolidated Balance Sheets.

Litigation

The Company has not been involved in any litigation during the year ended December 31, 2012, or the period from June 1, 2011 (Inception) through December 31, 2011.

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Cypress Energy Partners Predecessor

Notes to Consolidated Financial Statements
December 31, 2012

5. Commitments and Contingencies – (continued)

Leases

The Company entered into three land lease agreements on two operating salt water disposal facilities and one salt water disposal facility under construction in connection with the operation of certain facilities. The leases provided for an initial term of 15 years with one 15-year renewal. On December 31, 2012, these leases were renegotiated to provide for a new 15-year term. Lease expense was $23 thousand and $9 thousand in 2012 and 2011, respectively. Minimum annual lease commitments under the current operating leases at December 31, 2012, were as follows:


	(in thousands)
2013	$	23
2014		23
2015		23
2016		23
2017		23
2018 and thereafter		234
Total	$	349

6. Subsequent Events

With the proceeds received from Cypress Energy Partners, LLC as part of the purchase of the Company, the total debt balance of $2.3 million (Note 3) was paid in full. The Company has evaluated subsequent events through September 12, 2013, which is the date these financial statements were available to be issued.

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Cypress Energy Partners Predecessor

Unaudited Condensed Consolidated Balance Sheets
(in thousands)


	September 30, 2012		December 31, 2011
Assets
Current assets:
Cash and cash equivalents	$	—	$	147
Trade accounts receivable		2,159		1,638
Related party receivable		439		—
Prepaid expenses and other current assets		407		103
Inventory		134		22
Total current assets		3,139		1,910
Property and equipment, at cost:
Property and equipment		25,119		12,689
Less: accumulated depreciation		961		123
Total property and equipment		24,158		12,566
Total assets	$	27,297	$	14,476
Liabilities and members' equity
Current liabilities:
Accounts payable	$	2,792	$	2,370
Accrued liabilities		11		41
Current portion long-term debt		551		529
Total current liabilities		3,354		2,940
Asset retirement obligations		5		2
Long-term debt		1,844		2,269
Total liabilities		5,203		5,211
Members' equity:
Members' equity – 99,900 units outstanding		22,094		9,265
Total liabilities and members' equity	$	27,297	$	14,476

See accompanying notes.

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Cypress Energy Partners Predecessor

Unaudited Condensed Consolidated Statements of Income
(in thousands)


	Nine Months Ended September 30, 2012			Period from June 1, 2011 (Inception) through September 30, 2011
Revenues	$	9,182		$	1,218
Costs of sales		2,310			188
Gross margin		6,872			1,030
Operating costs and expense:
Depreciation and amortization		839			26
General and administrative		241			106

Operating income		5,792			898
Nonoperating income (expense)
Other income		36			7
Interest expense		(82	)		(14	)
Total nonoperating expense		(46	)		(7	)
Net income	$	5,746		$	891

See accompanying notes.

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Cypress Energy Partners Predecessor

Unaudited Condensed Consolidated Statements of Cash Flows
(in thousands)


	Nine Months Ended September 30, 2012			Period from June 1, 2011 (Inception) through September 30, 2011
Operating activities
Net income	$	5,746		$	891
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		839			26
Changes in assets and liabilities:
Accounts receivable		(521	)		(715	)
Inventory, prepaid expenses, and other assets		(416	)		(78	)
Accounts payable and accrued liabilities		1,385			227
Net cash provided by/(used in) operating activities		7,033			351
Investing activities
Capital expenditures:
Purchase of other property and equipment		(13,421	)		(4,556	)
Net cash used in investing activities		(13,421	)		(4,556	)
Financing activities
Proceeds from issuance of debt		—			900
Repayment of long-term debt		(403	)		(13	)
Receivable from affiliates		(439	)		—
Contributions from members		7,083			4,046
Net cash provided by financing activities		6,241			4,933
Net increase in cash and cash equivalents		(147	)		728
Cash and cash equivalents, beginning of period		147			—
Cash and cash equivalents, end of period	$	—		$	728
Non-cash items
Accounts payable excluded from capital expenditures	$	833		$	2,140

See accompanying notes.

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TABLE OF CONTENTS

Cypress Energy Partners Predecessor

Notes to Unaudited Condensed Consolidated Financial Statements
September 30, 2012

1. Organization and Operations

Cypress Energy Partners Predecessor consists of seven North Dakota limited liability companies (collectively, the Company) that were formed in 2011 and 2012, with the first being formed on June 1, 2011 (Inception) for the purpose of providing environmental services in the fluids management business for the oil and natural gas industry. On December 31, 2012, Cypress Energy Partners, LLC entered into agreements to acquire 100% of the outstanding units of the Company.

The Company operates and constructs commercial salt water disposal wells (SWDs) throughout the Bakken region of the Williston basin in the United States. All of the Company’s facilities are built with redundant equipment, full-time attendants, and remote monitoring to minimize downtime and increase efficiency for peak utilization. These facilities also contain sophisticated oil skimming processes that remove any remaining oil from water delivered to the sites.

2. Basis of Presentation and Summary of Significant Accounting Policies

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information and pursuant to the rules and regulation of the Securities and Exchange Commission. They do not include all of the information and footnotes required by generally accepted accounting principles in the United States (U.S. GAAP) for complete annual financial statements. The unaudited condensed consolidated financial statements for the nine month period ended September 30, 2012 and for the period from June 1, 2011 (Inception) through September 30, 2011, include all adjustments we believe are necessary for a fair statement of the results for the interim periods. Operating results for the nine month period ended September 30, 2012 are not necessarily indicative of the results that may be expected for the full year ended December 31, 2012. These unaudited condensed consolidated financial statements should be read in conjunction with the Cypress Energy Partners Predecessor audited consolidated financial statements and notes thereto as of December 31, 2012 and 2011 and for the year ended December 31, 2012 and for the period from June 1, 2011 (Inception) through December 31, 2011 (Predecessor Audited Financial Statements).

Significant Accounting Policies

The accounting policies followed by the Company are set forth in Note 2 — Summary of Significant Accounting Policies of the Notes to Consolidated Financial Statements in the Predecessor Audited Financial Statement. There have been no significant changes to these policies during the nine-month period ended September 30, 2012. Below are selected accounting policies.

Principles of Consolidation

The unaudited condensed consolidated financial statements include the accounts of the Company. All intercompany accounts and transactions have been eliminated in consolidation.

Use of Estimates in the Preparation of Financial Statements

The preparation of the Company’s unaudited condensed consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the unaudited condensed consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

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Cypress Energy Partners Predecessor

Notes to Unaudited Condensed Consolidated Financial Statements
September 30, 2012

2. Basis of Presentation and Summary of Significant Accounting Policies – (continued)

Areas requiring the use of assumptions, judgments and estimates relate to the amount of expected future cash flows used in determining possible impairments of property and equipment and future asset retirement obligations. Certain estimates are inherently imprecise and may change as future information becomes available.

Fair Value of Financial Instruments

The carrying amounts reported in the unaudited condensed consolidated balance sheets for cash, accounts receivable, and accounts payable approximate their fair values.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are reported at fair value on a nonrecurring basis in the Company’s unaudited condensed consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:

Impairments of Long-Lived Assets

The Company reviews its property and equipment for impairment whenever events or changes in circumstances indicate, in the judgment of the Company’s management, that a decline in the recoverability of their carrying value may have occurred. Assets are grouped for impairment purposes at each facility, which includes the well and supporting equipment and infrastructure, as this represents the lowest level of cash flows associated with the asset group. When an indicator of impairment has occurred, the Company compares its estimate of undiscounted cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. If the estimate of undiscounted cash flows is less than the carrying value of the group, the Company determines the amount of the impairment recognized in the financial statements by estimating the fair value of the assets using a discounted cash flow model and recording a loss for the amount by which the carrying value exceeds the estimated fair value. The Company had no impairment of long-lived assets at September 30, 2012 or December 31, 2011.

3. Debt

In 2011, the Company entered into a series of senior term notes with Starion Financial (the Lenders) totaling $2.9 million (the Notes). Borrowings under the Notes are secured by the assets of the Company, as well as personnel guarantees of the sole member and its sponsor. As of September 30, 2012 and December 31, 2011, the outstanding balances on the Notes were $2.4 million and $2.8 million, respectively. Borrowings under the Notes incur interest at a fixed rate of 4.85%, which is due and payable monthly with the principal balance of each of the Notes to be paid over a 60-month period. The annual weighted average interest rate on borrowings outstanding under the Notes at September 30, 2012, was 4.85%.

The Notes contain covenants that require the Company to, among other things, allow the creditor to file perfected security interests in the properties and maintain proper insurance on the properties. As of September 30, 2012 and December 31, 2011, the Company was in compliance with all financial and nonfinancial covenants. If an event of default occurs and is continuing, the Lenders may declare all amounts due under the Notes to be immediately due and payable.

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Cypress Energy Partners Predecessor

Notes to Unaudited Condensed Consolidated Financial Statements
September 30, 2012

3. Debt – (continued)

Interest of $82 thousand was paid during the nine month period ended September 30, 2012, and $14 thousand was paid during the period from June 1, 2011 (Inception) through September 30, 2011.

4. Related-Party Transactions

The sole member of the Company or his employees own several entities with which the Company does business, including SBG Energy Services, LLC ($140 thousand in the nine month period ended September 30, 2012 in general and administrative expenses); SBG Disposal LLC ($1.2 million in employee-related costs and general and administrative expenses and $212 thousand in construction in process in the nine month period ended September 30, 2012, and $143 thousand in employee-related costs and general and administrative expenses and $397 thousand in construction in process in the period from June 1, 2011 (Inception) through September 30, 2011); Edgewood Management Group LLC ($3 thousand in construction in process and general and administrative expenses in the nine months ended September 30, 2012 and $118 thousand in construction in process and general and administrative expense for the period from June 1, 2011 (Inception) through September 30, 2011); Edgewood Development Group LLC ($190 thousand in construction in process in the period from June 1, 2011 (Inception) through September 30, 2011); Rud Transportation LLC ($2 thousand in the nine months ended September 30, 2012 in water disposal revenues and $24 thousand in the nine months ended September 30, in construction in process and general and administrative expenses); and Sinkler Energy LLC ($20 thousand in the nine months ended September 30, 2012 in repair and maintenance expenses and construction in process). The Company had accounts payable to SBG Disposal of $1.4 million at September 30, 2012.

5. Commitments and Contingencies

The Company has not been involved in any litigation during the period from June 1, 2011 (Inception) through September 30, 2012.

6. Subsequent Events

With the proceeds received from Cypress Energy Partners, LLC as part of the purchase of the Company, the total debt balance of $2.4 million (Note 3) was paid in full. The Company has evaluated subsequent events through October 30, 2013, which is the date these financial statements were available to be issued.

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Members
Cypress Energy Partners, LLC

We have audited the accompanying consolidated balance sheet of Cypress Energy Partners, LLC, as of December 31, 2012, and the related consolidated statements of operations, changes in members’ equity, and cash flows for the period from March 15, 2012 (Inception) through December 31, 2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Cypress Energy Partners, LLC at December 31, 2012, and the consolidated results of its operations and its cash flows for the period from March 15, 2012 (Inception) through December 31, 2012 in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Tulsa, Oklahoma
June 14, 2013

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Cypress Energy Partners, LLC

Consolidated Balance Sheet
December 31, 2012


	(in thousands)
Assets
Current assets:
Cash and cash equivalents	$	582
Trade accounts receivable		2,598
Related-party accounts receivable		439
Prepaid expenses		221
Inventory		117
Other current assets		468
Total current assets		4,425
Property and equipment, at cost:
Property and equipment		46,853
Less: accumulated depreciation		97
Total property and equipment		46,756
Goodwill		33,877
Other intangible assets, net of amortization of $2 thousand		284
Total assets	$	85,342
Liabilities and members’ equity
Current liabilities:
Accounts payable	$	702
Accrued liabilities		198
Contingent consideration		11,250
Related-party payables		1,534
Total current liabilities		13,684
Asset retirement obligations		7
Total liabilities		13,691
Members’ equity:
Members’ equity – 3,700,050 A units outstanding		71,651
Total liabilities and members’ equity	$	85,342

See accompanying notes.

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Cypress Energy Partners, LLC

Consolidated Statement of Operations
For the Period From March 15, 2012 (Inception) Through December 31, 2012


	(in thousands, except per unit and unit information)
Revenues	$	619
Cost of sales		309
Gross margin		310
Operating costs and expense:
Depreciation and amortization		99
General and administrative		1,094
Acquisition expenses (Note 3)		484
Dead deal expenses		478
Net loss	$	(1,845	)
Basic and diluted net loss per Class A unit	$	(10.89	)
Weighted average number of Class A units		169,466

See accompanying notes.

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Cypress Energy Partners, LLC

Consolidated Statement of Changes in Members’ Equity
For the Period From March 15, 2012 (Inception) Through December 31, 2012


	Class A Units		Changes in Members’ Equity
			(in thousands)
Inception formation		50	$	1
Contributions		169,420		3,388
Contributions held by parent		—		(505	)
Contribution to fund acquisitions (Note 3)		3,530,580		70,612
Net loss		—		(1,845	)
Members’ equity at December 31, 2012		3,700,050	$	71,651

See accompanying notes.

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Cypress Energy Partners, LLC

Consolidated Statement of Cash Flows


	Period from March 15, 2012 (Inception) through December 31, 2012
	(in thousands)
Operating activities
Net loss	$	(1,845	)
Adjustments to reconcile net loss to cash used in operating activities:
Depreciation and amortization		99
Changes in assets and liabilities:
Accounts receivable		(741	)
Inventory, prepaid expenses, and other assets		(12	)
Accounts payable and accrued liabilities		255
Net cash used in operating activities		(2,244	)
Investing activities
Capital expenditures:
Acquisitions (net of $582 thousand of cash acquired)		(70,612	)
Purchase of other property and equipment		(58	)
Net cash used in investing activities		(70,670	)
Financing activities
Contributions from members (net of contributions held by parent)		73,496
Net cash provided by financing activities		73,496
Net increase in cash and cash equivalents		582
Cash and cash equivalents, beginning of period		—
Cash and cash equivalents, end of period	$	582
Non-cash items:
Accounts Payable excluded from capital expenditures	$	145

See accompanying notes.

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Cypress Energy Partners, LLC

Notes to Consolidated Financial Statements
December 31, 2012

1. Organization and Operations

Cypress Energy Partners, LLC is a Delaware limited liability company, which was formed on March 15, 2012 (Inception) as Cypress Energy Partners, LP, and was subsequently renamed on August 15, 2012, for the purpose of providing environmental services in the fluids management business for the oil and natural gas industry. On August 15, 2012, Cypress Energy Holdings, LLC, the sole member of the Cypress Energy Partners, LLC, entered into a Limited Liability Company Agreement for the Company (LLC Agreement).

Cypress Energy Partners, LLC and its wholly owned subsidiaries (collectively, the Company) operate 10 commercial salt water disposal wells (SWDs) throughout the Bakken region of the Williston and Permian basins in the United States. All of the Company’s facilities are built with redundant equipment, full-time attendants, and remote monitoring to minimize downtime and increase efficiency for peak utilization. These facilities also contain sophisticated oil skimming processes that remove any remaining oil from water delivered to the sites.

2. Summary of Significant Accounting Policies

Principles of Consolidation

The consolidated financial statements include the accounts of the Company. All intercompany accounts and transactions have been eliminated in consolidation.

Cash and Cash Equivalents

The Company’s cash balances at December 31, 2012, are insured by the Federal Deposit Insurance Corporation (FDIC) up to $250 thousand per financial institution. At times, cash balances may be in excess of the FDIC insurance limit.

Use of Estimates in the Preparation of Financial Statements

Areas requiring the use of assumptions, judgments, and estimates relate to the amount of expected future cash flows used in determining possible impairments of goodwill, intangible assets, property and equipment, and future asset retirement obligations. Certain estimates are inherently imprecise and may change as future information becomes available.

Property and Equipment

Property and equipment consist of land and improvements, buildings, furniture, fixtures and equipment, computer and office equipment, and vehicles. The Company records property and equipment at cost. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repairs are expensed as incurred. Depreciation for these assets is computed using the straight-line method over estimated useful lives. Upon retirement or disposition of assets, the costs and related accumulated depreciation are removed from the accounts with the resulting gain or losses, if any, reflected in results of operations.

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Cypress Energy Partners, LLC

Notes to Consolidated Financial Statements
December 31, 2012

2. Summary of Significant Accounting Policies – (continued)

Property and equipment consist of the following, recorded at cost, as of December 31, 2012:


	(in thousands)
Land	$	2,165
Land improvements (depreciable lives – 15 years)		3,662
Buildings (depreciable lives – 39 years)		1,855
Facilities, wells, and equipment (depreciable lives – 9 to 15 years)		39,128
Computer and office equipment (depreciable lives – 3 to 5 years)		33
Vehicles (depreciable lives – 5 years)		10
		46,853
Less accumulated depreciation		(97	)
Net property and equipment	$	46,756

Revenue Recognition

Water disposal and oil revenues are recognized when there is persuasive evidence that an arrangement exists, delivery has occurred or services have been rendered, the seller’s price to the buyer is fixed or determinable and collectability is reasonably assured. Water disposal revenues are based on the Company’s published or negotiated water disposal rates. Customers deliver water to be disposed to facilities and revenue is recognized when actual volumes of water are disposed. Oil disposal revenues are determined based on published rates based on the quality of the oil sold and are recognized when actual volumes of oil is skimmed and delivered to the customer and the quality of the oil is determined and collectability is reasonably assured.

Accounts Receivable

The Company disposes of water for its customers and sells oil to various customers. Amounts are considered past due after 30 days. The Company determines accounts receivable allowances based on management’s assessment of the creditworthiness of the customers and other collection actions. The Company did not record an allowance at December 31, 2012, nor did the Company record any bad debt expense for the period from Inception through December 31, 2012. The accounts receivable purchased as part of the SBG Acquisition, included in current assets in the table in Note 3, recorded at fair value amount to $1.9 million at December 31, 2012, and any amounts that subsequently become uncollectible will be an adjustment to the purchase price. The Company charges interest on past-due balances.

Inventory

The Company valued its crude oil inventory purchased as part of the Moxie and SBG Acquisitions (see Note 3) at fair market value net of applicable severance taxes and transportation costs based on average actual sales. The Company values its miscellaneous supplies inventory at cost. Miscellaneous supplies are removed on a FIFO basis and purchased crude oil inventory is removed as it is sold. The Company’s inventory at December 31, 2012, consisted of $88 thousand in miscellaneous supplies and $29 thousand in purchased crude oil.

Income Taxes

The Company is a limited liability company. No provision for income taxes is included in the consolidated financial statements of the Company. Income taxes, if any, for the Company are generally payable by the individual members of the Company. There are no differences between the reported amounts and tax bases of the Company’s assets and liabilities.

The Company evaluates uncertain tax positions for recognition and measurement in the financial statements. To recognize a tax position, the Company determines whether it is more

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Cypress Energy Partners, LLC

Notes to Consolidated Financial Statements
December 31, 2012

2. Summary of Significant Accounting Policies – (continued)

likely than not that the tax positions will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50% likely of being realized upon settlement. The Company had no uncertain tax positions that required recognition in the financial statements at December 31, 2012. Any interest or penalties would be recognized as a component of income tax expense.

Unit-Based Compensation

The cost of employee services received in exchange for equity instruments is measured based on the grant-date fair value of those instruments. That cost is recognized over the requisite service period (often the vesting period) as discussed in Note 6.

Certain members and employees of the Company have been granted incentive units that vest over time and may result in cash payments to the members and employees upon the occurrence of certain payouts defined in the LLC Agreement in conjunction with any merger, sale, or other transaction involving substantially all of the Company’s assets (see Note 6 below). The fair value of such cash payments is measured at the date the incentive units are granted and revalued in each subsequent reporting period. All incentive units granted during the period from Inception through December 31, 2012, were granted and issued effective October 1, 2012, prior to the Company’s acquisition of its predecessor, with $20 thousand in compensation expense recorded during the period from Inception through December 31, 2012.

Concentration of Credit Risk

The Company’s water disposal and oil revenues are derived from a variety of customers, including both trucking and exploration and production companies. The Company’s accounts receivable are from oil and gas companies and individually owned trucking companies. Our ten largest customers generated approximately 68% of our revenues for the period from March 15, 2012 (Inception) through December 31, 2012. One customer, BS&W Solutions, LLC (BS&W) accounted for 25% of our consolidated revenues. BS&W is a trucking company that purchases skim oil they collect from customers such as us and sells to several other oil companies. If one or more of these customers were to default on their payment obligations, we may not be able to replace any of these customers in a timely fashion, on favorable terms, or at all. Management believes that any credit risk imposed by a concentration in producers and trucking companies in the oil and natural gas industry is offset by the creditworthiness of the Company’s customer base.

Environmental

Asset Retirement Obligations

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Cypress Energy Partners, LLC

Notes to Consolidated Financial Statements
December 31, 2012

2. Summary of Significant Accounting Policies – (continued)

the period in which it is incurred if a reasonable estimate of fair value can be made and that the associated asset retirement costs be part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related wells and equipment is charged to expense through the depreciation. Changes in the liability due to passage of time are recognized as accretion expense and a corresponding increase in the carrying amount of the liability. The Company recognizes asset retirement obligations for its salt water disposal operations at the end of the month when disturbance of the ground occurs during the construction of a well. Such obligations consist of future costs, net of recoverable salvage value of tangible equipment, to plug and abandon the salt water disposal wells when the wells permanently cease operations.

The activity for the period from Inception through December 31, 2012, is as follows:


	(in thousands)
Liabilities incurred – acquired wells	$	7
Accretion expense		—
Asset retirement obligations, end of period	$	7

Fair Value of Financial Instruments

The carrying amounts reported in the balance sheet for cash and cash equivalents, accounts receivable, related-party receivables and payables, and accounts payable approximate their fair values.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Impairments of Long-Lived Assets

The Company reviews its property and equipment, goodwill, and intangible assets for impairment whenever events or changes in circumstances indicate, in the judgment of the Company’s management, that a decline in the recoverability of their carrying value may have occurred. Assets are grouped for impairment purposes at each facility, which includes the well and supporting well equipment and infrastructure, as this represents the lowest level of cash flows associated with the asset group. The Company performs its annual goodwill impairment assessment on November 1 each year. When an indicator of impairment has occurred, the Company compares its estimate of undiscounted cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. If the estimate of undiscounted cash flows is less than the carrying value of the asset group, the Company determines the amount of the impairment recognized in the financial statements by estimating the fair value of the assets using a discounted cash flow model and recording a loss for the amount by which the carrying value exceeds the estimated fair value. The Company had no impairment of long-lived assets at December 31, 2012.

Judgments and assumptions are used in the Company’s estimate of undiscounted future cash flows and an asset’s fair value. These judgments and assumptions include such matters as the

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Cypress Energy Partners, LLC

Notes to Consolidated Financial Statements
December 31, 2012

2. Summary of Significant Accounting Policies – (continued)

estimation of oil and gas drilling and producing volumes in the markets served, risks associated with the different zones into which salt water is disposed, expected future disposal rates and commodity prices, capital expenditures, operating costs, and appropriate discount rates.

Business Combinations

Accounting guidance defines a business as consisting of inputs and processes applied to those inputs that have the ability to create outputs.

The Company evaluates all potential acquisitions and changes in control to determine whether it has purchased or acquired control of a business as discussed above. If the acquired or new controlled assets meet the definition of a business it is accounted for as a business combination, otherwise it is accounted for as an asset acquisition. The two transactions discussed in Note 3 below have been accounted for as business combinations.

Net income per unit

Net income per unit is calculated using the two-class method. The two-class method is an earnings allocation method of calculating earnings per unit when a company’s capital structure includes participating securities that have rights to undistributed earnings. The Company’s employees and officers that hold unvested profits interests would be entitled to distributions if the Company were to pay distributions.

The Company’s basic net income per unit is computed by reducing the Company’s net income by the net income allocable to unvested profits interests that have a right to participate in undistributed earnings. The undistributed earnings are allocated based on the relative percentage of the weighted average units of unvested profits interest and the total of the weighted average units outstanding plus the weighted average unvested profit interest units. The basic net income per unit is computed by dividing the net income by the weighted average units outstanding. The Company’s dilutive net income per unit attributable to units is computed by adjusting basic net income per unit by diluted income allocable to unvested profits interest divided by weighted average diluted units outstanding.

3. Acquisitions

Moxie Acquisition

In December 2012, the Company acquired four commercial salt water disposal wells through two agreements for a total purchase price of approximately $23.9 million, subject to customary adjustments. The acquisitions were funded with available cash from initial member equity contributions. Two of the acquired wells are located in the Permian basin, and two wells are located in the Bakken basin. The effective date of the acquisition was December 3, 2012, and the Company took over operations of the wells on December 4, 2012.

SBG Acquisition

In December 2012, the Company acquired 100% of the membership interests in six operating commercial salt water disposal wells, one under-construction commercial salt water disposal well, and an option to acquire a business and various other rights of first refusal to purchase other businesses and assets from SBG Energy Services, LLC (SBG), including (1) a right of first refusal to purchase all or a portion of the then-issued and outstanding limited liability membership interests of SBG Energy Services, LLC; (2) a right of first refusal to purchase all or a portion of the membership interests of GREnergy LLC, which owns a rail spur and warehouse in Bismarck, North Dakota; (3) a right of first refusal to purchase all or a portion of the then-issued and outstanding

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Cypress Energy Partners, LLC

Notes to Consolidated Financial Statements
December 31, 2012

3. Acquisitions – (continued)

limited liability membership interest of Rud Transportation LLC, which owns 25 tractor/trailer units and other equipment; (4) a right of first refusal to purchase all or a portion of SBG’s right, title, and interest in and to any water pipeline construction, development, or acquisition opportunity now or hereafter granted to SBG; (5) a right of first refusal to purchase all or a portion of SBG’s right, title, and interest in and to that certain exclusive, multiyear hot water supply agreement with a customer to purchase and resell water from certain electric generating stations; (6) a right of first refusal to purchase all or a portion of SBG’s right, title, and interest in and to that certain landfill opportunity with a customer related to the development of an unused landfill for disposal of oil field waste; (7) a right of first refusal to purchase all or a portion of SBG’s right, title, and interest in a gas and diesel wholesale venture; and (8) a 51% interest in SBG Disposal, LLC for $500,000, which contains an allocable percentage ownership interest in and to that certain salt water disposal well known as the Arnegard SWD. The Company has assigned a fair value of $225 thousand for this option to purchase 51% of SBG Disposal. With the exception of the option to purchase 51% of SBG Disposal, the options described above are rights of first refusal to purchase businesses that were not yet operational or were not yet mature, therefore we determined that they had no material value. The total purchase price of all the above property and options is approximately $47.3 million, subject to customary adjustments. One of these customary adjustments included the requirement of SBG to include $8.2 million for a series of well improvement and construction reserves, which effectively reduced the purchase price. Any future capital obligations related to these SBG well improvements or new SWD construction projects are the responsibility of the Company. The acquisition was funded with available cash from member equity contributions. All of the acquired wells are located in the Bakken basin. The closing date of the acquisition was December 31, 2012.

The December 2012 acquisitions qualify as business combinations, and, as such, the Company accounted for these acquisitions as business combinations. The Company recorded the assets acquired and liabilities assumed at their estimated fair market values as of the closing dates. The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.

Fair value measurements also utilize the following primary assumptions of market participants. To estimate the fair value of the acquired wells, the Company used a discounted cash flow model and made market assumptions for the estimation of future water to be disposed of due to oil and gas drilling and production volumes in the markets served, risks associated with the different zones into which salt water is disposed, expected future disposal rates and commodity prices, capital expenditures, operating costs, and appropriate discount rates. Due to the unobservable nature of the inputs, these estimates of the commercial salt water disposal wells are considered Level 3 fair value estimates.

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Cypress Energy Partners, LLC

Notes to Consolidated Financial Statements
December 31, 2012

3. Acquisitions – (continued)

The purchase price and assessment of the fair value of the assets acquired and liabilities assumed were as follows:


	Moxie Acquisition		SBG Acquisition		Total
	(in thousands)
Fair value of net assets:
Current assets	$	288	$	2,946	$	3,234
Property and equipment		16,634		30,017		46,651
Related-party notes receivable		—		438		438
Goodwill		6,903		26,974		33,877
Intangible assets		60		225		285
Total assets acquired		23,885		60,600		84,485
Current liabilities		—		500		500
Related-party notes payable		—		1,534		1,534
Contingent consideration due sellers		—		11,250		11,250
Asset retirement obligations		3		5		8
Total liabilities assumed		3		13,289		13,292
Total purchase price	$	23,882	$	47,311	$	71,193

Contingent consideration due to sellers is based upon the acquired assets meeting certain profitability thresholds based upon 2013 actual results. The Company’s best estimate is that the sellers will be due $11.25 million based upon achieving 50% of their maximum possible results by attaining $12.75 million in 2013 EBITDA (earnings before income taxes, depreciation, and amortization). Based upon the agreement, the sellers can earn up to $22.5 million for 2013 EBITDA of $15.0 million or greater and will earn no contingent consideration for 2013 EBITDA of $10.5 million or less. Contingent consideration will be recorded as Class B units as described in Note 4 below and remeasured through earnings at fair value each reporting period.

Intangible assets consist primarily of various 36-month noncompete agreements associated with the Moxie Acquisition to which the Company has assigned a fair value of $60 thousand and an option to purchase a 51% interest in SBG Disposal, LLC, which contains a 25% ownership interest in a salt water disposal well known as the Arnegard SWD. The Company has assigned a fair value of $225 thousand to this option. The noncompete assets will be amortized ratably over the projected competitive life of three years, and the value of the option will be contributed to the purchase of the 51% interest in SBG Disposal, LLC, if executed, or expensed if it expires without exercise.

Goodwill for the Moxie and SBG transactions is measured at cost being the cost in excess of the fair value of identified assets, liabilities, and contingent liabilities. The Company believes the locations, synergies created by combining these entities, and the projected future cash flows of the acquired entities merit the recognition of this asset. Of goodwill, 100% is deductible for tax purposes of our members.

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Cypress Energy Partners, LLC

Notes to Consolidated Financial Statements
December 31, 2012

3. Acquisitions – (continued)

The following summarized pro forma consolidated income statement information for the period from March 15, 2012 (Inception) through December 31, 2012, assumes that the acquisitions of businesses in 2012 referred to above occurred on March 15, 2012. These pro forma results are for comparative purposes only and may not be indicative of the results that would have occurred had these acquisitions been completed on March 15, 2012, or the results that will be attained in the future.


	As Reported			Pro Forma
	(in thousands)
Revenues	$	619		$	13,699
Net (loss) income	$	(1,845	)	$	4,383

4. Fair Value Measurement

The following table presents, by level within the fair value hierarchy, the Company’s financial liabilities measured at fair value on a recurring basis. The carrying values of cash and cash equivalents, trade accounts receivable, related-party receivables, accounts payable, and related-party payables approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.


							Fair Value Measurements Using
	Carrying Amount			Fair Value			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(in thousands)
Assets/(liabilities) at December 31, 2012)
Contingent consideration	$	(11,250	)	$	(11,250	)	$	—	$	—	$	(11,250	)
Liability for profits interest	$	(20	)	$	(20	)	$	—	$	—	$	(20	)

Fair Value Methods

The Company uses the following methods and assumptions in estimating the fair value of its financial instruments:

Contingent Consideration: The contingent consideration represented in the table consists of the Class B units discussed in Note 3 issued of whose value is contingent upon the SBG acquired assets meeting certain profitability thresholds based upon 2013 actual results.

To estimate the disclosed fair value of the contingent consideration, management determined the most likely estimated 2013 operating results for the SBG acquired assets and calculated the amount of contingent consideration that would be due based upon these results. This contingent consideration is reported in the Consolidated Balance Sheet as a liability.

5. Members’ Equity

On March 15, 2012, the Company and its sole member entered into a Limited Liability Company Agreement (the Agreement) whereby the sole member of Company committed $1 thousand in equity contributions for member equity interests in the Company. The sole member committed an additional $74 million throughout the year for additional member equity interests in the Company to fund the acquisitions described in Note 3 above as well as for general corporate

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Cypress Energy Partners, LLC

Notes to Consolidated Financial Statements
December 31, 2012

5. Members’ Equity – (continued)

purposes. All of the sole members’ equity contributions were recorded as Class A units. These Class A units are accounted for as equity and recorded in members’ equity on the balance sheet. At December 31, 2012, $505 thousand in contributions were held by the parent related to cash net of accounts payable for the treasury functions of the Company.

As discussed in Note 3 above, the seller of SBG has a contingent consideration amount that is convertible into Class B units when the amount of the contingent consideration becomes determinable. These Class B units would be converted for a lower amount of shares if all units are subsequently converted into a publicly traded Master Limited Partnership, than they would at the end of the year when EBITDA targets are achieved. These Class B units are accounted for as contingent consideration and recorded as a liability because a variable number of units could be paid out at the time of an initial public filing or at the time of determination at the end of the year; the underlying is the EBITDA targets discussed in Note 3 rather than the fair value of the Company’s shares, and there are provisions in which the units can be converted for cash under certain predefined circumstances.

As discussed in Note 6 below, the Company has issued Class C units in the form of Net Profits Interests to certain employees of the Company. These Class C units have different net profits distribution rights until certain net profits levels are reached, at which time they are treated the same as Class A units. The C units are accounted for as a liability, due to the ability of the holder to convert the units to cash at their discretion, and are included in accrued liabilities on the balance sheet.

6. Equity Compensation

The Company has entered into agreements with certain members for the issuance of “Profits Interests Units” as that term is used in the Internal Revenue Code.

Unit-based compensation related to the grant of Profits Interests Units or the grant of any Subsequent Units, as defined in the Agreement, is determined using an estimated value of the Company’s increases and decreases to each member’s Capital Account. All units granted and issued during the period from Inception through December 31, 2012, were granted and issued on October 1, 2012.

The following table sets forth the grants and forfeitures of Incentive Units during the period from Inception through December 31, 2012:


	2012		Weighted Average Measurement Date Fair Value/Unit
	(in thousands)
Profits interests at the beginning of the year	$	—	$	—
Profits interests granted		40		10.00
Profits interests vested		—		—
Profits interests forfeited		—		—
Profits interests outstanding at December 31, 2012	$	40	$	10.00

These profits interests are recorded at fair value each reporting period, and total compensation expense is recognized over the vesting period (see below). As of December 31, 2012, $20 thousand in compensation expense was recognized.

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Cypress Energy Partners, LLC

Notes to Consolidated Financial Statements
December 31, 2012

6. Equity Compensation – (continued)

The Profits Interests Units vest over a five-year period from the date of grant, with 1/3^rd vesting at the end of the third year, 1/3^rd vesting at the end of the fourth year, and 1/3^rd vesting at the end of the fifth year or will vest in full upon the occurrence of a Fundamental Change, as defined in the Agreement. Profits Interests Units participate in distributions; however, for those distributions related to units not yet vested, the distributions are held in escrow until such time as the underlying units vest. Profits Interests Unit holders must forfeit all unvested Profits Interests Units upon termination of employment and must forfeit all Profits Interests Units (vested and unvested) when the holder voluntarily terminates his or her employment or is terminated with cause as defined in the Agreement. Pursuant to the Agreement, Profits Interests Units capital accounts shall be increased by the allocation to each member of the Company’s income and gain (or items thereof), including, without limitation, income and gain exempt from tax and income and gain described in the Internal Revenue Code.

7. Related-Party Transactions

The Company acquired related-party receivable and related-party payable at December 31, 2012, of $439 thousand and $1.5 million, respectively, as disclosed in Note 3 above. These amounts relate to truck hauling, management fees, insurance, and other miscellaneous costs incurred during the year with SBG-related entities that will be received or paid within one year. Fees and employee costs of $48 thousand were paid to SBG-related entities prior to the sale of the SBG disposal facilities to the Company on December 31, 2012, as described in Note 3 above. The seller of SBG became a board member of the Company effective December 31, 2012, and he or his employees continue to own several entities with which the Company does business, including SBG Disposal LLC, Rud Transportation LLC, and Sinkler Energy LLC.

8. Commitments and Contingencies

Letters of Credit

The Company has various performance obligations which are secured with short-term security deposits of $450 thousand, included in Other current assets on the Consolidated Balance Sheet, and under a $25 thousand letter of credit executed by the members of Cypress Energy Holdings, LLC.

Litigation

The Company has not been involved in any litigation during the period from Inception through December 31, 2012, and did not acquire any known contingent liabilities in connection with the previously discussed acquisitions in Note 3 above.

Leases

The Company entered into three land lease agreements on two operating salt water disposal facilities and one salt water disposal facility under construction in connection with the SBG acquisition discussed in Note 3 above. The leases provided for an initial term of 15 years with one 15-year renewal. The Company also has one office lease in Tulsa, Oklahoma. Current period lease expense was $27 thousand.

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Cypress Energy Partners, LLC

Notes to Consolidated Financial Statements
December 31, 2012

8. Commitments and Contingencies – (continued)

Minimum annual lease commitments under the current office lease and other operating leases at December 31, 2012, for the following years as follows:


	(in thousands)
2013	$	81
2014		85
2015		85
2016		85
2017		85
2018 and thereafter		244
Total	$	665

9. Subsequent Events

The Company has evaluated subsequent events through June 14, 2013, which is the date these financial statements were available to be issued. Subsequent to December 31, 2012, the Company was informed that the Arnegard SWD held by SBG Disposal, for which the Company holds an option to purchase 51%, was struck by lightning and was damaged. The owners of the well have begun rebuilding the facility and expect all costs to be reimbursed through insurance. As a result, the Company does not believe that any adjustment to the valuation of its option is warranted as of December 31, 2012.

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Cypress Energy Partners, LLC

Unaudited Condensed Consolidated Balance Sheets
(in thousands)


	September 30, 2013		December 31, 2012
Assets
Current assets:
Cash and cash equivalents	$	5,135	$	582
Trade accounts receivable		3,126		2,598
Related-party accounts receivable		410		439
Affiliate accounts receivable		359		—
Prepaid expenses and other current assets		569		689
Inventory		129		117
Total current assets		9,728		4,425
Property and equipment, at cost:
Property and equipment		44,478		46,853
Less: accumulated depreciation		2,900		97
Total property and equipment		41,578		46,756
Goodwill		33,877		33,877
Other intangible assets, net of amortization of $15 thousand and $2 thousand, as of September 30 and December 31, respectively		269		284
Total assets	$	85,452	$	85,342
Liabilities and members' equity
Current liabilities:
Accounts payable	$	638	$	702
Accrued liabilities		476		198
Contingent consideration		—		11,250
Related-party payables		419		1,534
Total current liabilities		1,533		13,684
Asset retirement obligations		9		7
Total liabilities		1,542		13,691
Members' equity:
Members' equity – 3,700,000 A units outstanding		83,910		71,651
Total liabilities and members' equity	$	85,452	$	85,342

See accompanying notes.

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Cypress Energy Partners, LLC

Unaudited Condensed Consolidated Statements of Operations
(in thousands, except unit and per unit data)


	Nine Months Ended September 30, 2013		Period from March 15, 2012 (Inception) through September 30, 2012
	Nine Months Ended September 30, 2013
Revenues	$	16,665	$	—
Costs of sales		5,426		—
Gross margin		11,239		—
Operating costs and expense:
Depreciation and amortization		3,066		2
General and administrative		2,427		1,032
Impairment of facility		4,375		—
Operating income (loss)		1,371		(1,034	)
Gain on reversal of contingent consideration		11,250		—
Net income (loss) before income tax expense		12,621		(1,034	)
Income tax expense		40		—
Net income (loss)	$	12,581	$	(1,034	)
Allocation of net income (loss) for calculation of earnings per unit:
Allocation of net income to Class C units		492		—
Allocation of net income (loss) to Class A units	$	12,089		(1,034	)
Basic and diluted net income (loss) per Class A unit	$	3.27	$	(54.24	)
Weighted average number of Class A units		3,700,000		19,065

See accompanying notes.

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Cypress Energy Partners, LLC

Unaudited Condensed Consolidated Statements of Cash Flows
(in thousands)


	Nine Months Ended September 30, 2013			Period from March 15, 2012 (Inception) through September 30, 2012
Operating activities
Net income (loss)	$	12,581		$	(1,034	)
Adjustments to reconcile net income (loss) to cash provided by/(used in) operating activities:
Depreciation and amortization		3,066			2
Impairment of facility		4,375			—
Gain on reversal of contingent consideration		(11,250	)		—
Changes in assets and liabilities:
Accounts receivable		(500	)		—
Inventory, prepaid expenses, and other assets		109			(6	)
Accounts payable and accrued liabilities		(869	)		—
Net cash provided by/(used in) operating activities		7,512			(1,038	)
Investing activities
Capital expenditures:
Purchase of property and equipment		(2,278	)		(33	)
Net cash used in investing activities		(2,278	)		(33	)
Financing activities
Receivable from affiliates		(359	)		—
Contributions from members		(322	)		1,071
Net cash provided by/(used in) financing activities		(681	)		1,071
Net increase in cash and cash equivalents		4,553			—
Cash and cash equivalents, beginning of period		582			—
Cash and cash equivalents, end of period	$	5,135		$	—
Non-cash items:
Accounts payable excluded from capital expenditures	$	113		$	—

See accompanying notes.

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Cypress Energy Partners, LLC

Notes to Unaudited Condensed Consolidated Financial Statements
September 30, 2013

1. Organization and Operations

Cypress Energy Partners, LLC, is a Delaware limited liability company, which was formed on March 15, 2012 (Inception) as Cypress Energy Partners, L.P. and was subsequently renamed on August 15, 2012 for the purpose of providing environmental services in the fluids management business for the oil and natural gas industry. On August 15, 2012, Cypress Energy Holdings, LLC, the sole member of the Company, entered into a Limited Liability Company Agreement for the Company (LLC Agreement).

Cypress Energy Partners, LLC and its wholly owned subsidiaries (collectively, the Company) operate ten commercial salt water disposal wells (SWD’s) throughout the Bakken shale region of the Williston Basin and in the Permian basin in the United States. All of the Company’s facilities are built with redundant equipment, full-time attendants, and remote monitoring to minimize downtime and increase efficiency for peak utilization. These facilities also contain sophisticated oil skimming processes that remove any remaining oil from the water delivered to the sites.

2. Basis of Presentation and Summary of Significant Accounting Policies

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information and pursuant to the rules and regulation of the Securities and Exchange Commission. They do not include all of the information and footnotes required by generally accepted accounting principles in the United States (U.S. GAAP) for complete annual financial statements. The unaudited condensed consolidated financial statements for the nine-month period ended September 30, 2013 and for the period from March 15, 2012 (Inception) through September 30, 2012 include all adjustments we believe are necessary for a fair statement of the results for the interim periods. Operating results for the nine-month period ended September 30, 2013 are not necessarily indicative of the results that may be expected for the full year ended December 31, 2013. These unaudited condensed consolidated financial statements should be read in conjunction with our audited consolidated financial statements and notes thereto as of December 31, 2012 and for the period from March 15, 2012 (Inception) through December 31, 2012.

Significant Accounting Policies

The accounting policies followed by the Company are set forth in Note 2 — Summary of Significant Accounting Policies of the Notes to Consolidated Financial Statements in our 2012 audited financial statements. There have been no significant changes to these policies during the nine-month period ended September 30, 2013. Below are selected accounting policies.

Principles of Consolidation

The condensed consolidated financial statements include the accounts of the Company. All intercompany accounts and transactions have been eliminated in consolidation.

Use of Estimates in the Preparation of Financial Statements

The preparation of the Company’s condensed consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the unaudited condensed consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

Areas requiring the use of assumptions, judgements and estimates relate to the amount of expected future cash flows used in determining possible impairments of goodwill, intangible assets, property & equipment and future asset retirement obligations. Certain estimates are inherently imprecise and may change as future information become available.

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Cypress Energy Partners, LLC

Notes to Unaudited Condensed Consolidated Financial Statements
September 30, 2013

2. Basis of Presentation and Summary of Significant Accounting Policies – (continued)

Fair Value of Financial Instruments

The carrying amounts reported in the unaudited condensed consolidated balance sheets for cash, accounts receivable, and accounts payable approximate their fair values.

3. Contingent Consideration

On December 31, 2012, the Company acquired 100% of the membership interests in six operating commercial salt water disposal wells and other businesses and assets from SBG Energy Services, LLC (SBG). The purchase agreement called for contingent consideration to be paid to the sellers based on the acquired wells meeting certain profitability thresholds in 2013. The Company initially estimated that the sellers would be due $11.25 million based upon achieving 50% of their maximum possible results by attaining $12.75 million in 2013 EBITDA (earnings before income taxes, depreciation and amortization) for the acquired wells. Accordingly, the Company recorded a liability for the contingent consideration totaling $11.25 million.

Based on the actual performance of these wells and the EBITDA forecast for the remainder of the year, the Company estimates that the financial results will be below the minimum threshold for the seller to earn any contingent consideration. Based on the forecasted results, the seller and the Company reached an agreement effective October 30, 2013 to cancel the Class B units issued in conjunction with the transaction. The contingent liability was reversed in full during the second quarter 2013 and is recorded in the unaudited condensed consolidated statements of operations as a gain on reversal of contingent consideration. The EBITDA forecast is considered a Level 3 fair value measurement.

4. Impairment of Long-lived Assets

The Company reviews its property & equipment, goodwill and intangible assets for impairment, whenever events or changes in circumstances indicate, in the judgment of the Company’s management that a decline in the recoverability of their carrying value may have occurred. Assets are grouped for impairment purposes at each facility which includes the SWD well and supporting equipment and infrastructure, as this represents the lowest level of cash flows associated with the asset group. When an indicator of impairment has occurred, the Company compares its estimate of undiscounted cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. If the estimate of undiscounted cash flows is less than of the carrying value of the asset group, the Company determines the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording an impairment for the amount that the carrying value exceeds the estimated fair value.

During 2013, the Company began experiencing excess operating pressures at one of its SWD facilities indicating the possibility of an operational malfunction. Disposal activities were suspended at the facility during the second quarter until the issue can be identified and repaired. In addition to the operational issues, the Company has experienced declining revenues and operational losses at the facility due to decreased oil production in proximity to the facility. As a result of these impairment indicators, the Company compared its estimate of undiscounted future cash flows from the facility to the carrying amount of the long-lived assets of the facility, and

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Cypress Energy Partners, LLC

Notes to Unaudited Condensed Consolidated Financial Statements
September 30, 2013

4. Impairment of Long-lived Assets – (continued)

determined that they were no longer recoverable and were impaired. The Company wrote the assets down from their carrying value of $4.7 million to their estimated fair value of $0.3 million, resulting in an impairment of the facility for $4.4 million. The impairment is recorded as a component of operating loss in the unaudited condensed consolidated statement of operations for the nine-month period ended September 30, 2013.

Fair value was based on expected future cash flows which is a Level 3 input under ASC 820. The cash flows are those expected to be generated by the market participants, discounted at the Company’s estimated cost of capital. Because of the uncertainties surrounding the repair of the facility and the market conditions, including the Company’s ability to generate and maintain sufficient revenues to operate the facility profitably, it is reasonably possible that the estimate of expected future cash flows may change in the near term resulting in the need to adjust our determination of fair value.

5. Fair Value Measurement

The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities measured at fair value on a recurring basis. The carrying values of cash and cash equivalents, accounts receivable, related party receivables, accounts payable and related party payables approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.


					Fair Value Measurements Using
	Carrying Amount		Fair Value		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(in thousands)
Liabilities at September 30, 2013:
Equity compensation liability	$	47	$	47	$	—	$	—	$	47

6. Members’ Equity

Class A Units

On March 15, 2012, the Company and its sole member entered into a Limited Liability Company Agreement (the “Agreement”) whereby the sole member of the Company committed $1 thousand in equity contributions for member equity interests in the Company. The sole member committed an additional $74 million throughout the year for additional member equity interest in the Company to fund acquisitions as well as for general corporate purposes. All of the sole member’s equity contributions were recorded as Class A units. These Class A units are accounted for as equity and recorded in member’s equity on the balance sheet.

Class B Units

As discussed in Note 3 above, all Class B units issued to the seller of SBG were cancelled during the 2^nd quarter 2013.

Class C Units

As discussed in Note 7 below, the Company has issued Class C units in the form of Net Profits Interests to certain employees of the Company. These Class C units have different net profits distribution rights until certain net profits levels are reached, at which time they are treated the same as Class A units.

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Cypress Energy Partners, LLC

Notes to Unaudited Condensed Consolidated Financial Statements
September 30, 2013

6. Members’ Equity – (continued)

Advanced to/Contributions from Parent

The Company provides treasury and accounts payable services for its sole member, Cypress Energy Holdings, LLC (CEH). Amounts paid on behalf of CEH, net of cash transfers from CEH, are treated as advances to CEH as a component of Member’s Equity. Cumulative advances as of September 30, 2013 and December 31, 2012 were $322 thousand and $505 thousand, respectively.

7. Equity Compensation

Certain employees of the Company receive equity-based compensation in the form of Profits Interests Units (as that term is used in the Internal Revenue Code) and Phantom Profits Interests Units, collectively Units, under the terms of the Company’s Long-Term Incentive Plan. The fair value of the awards issued is determined based on the fair market value of the shares at each reporting date. The fair market value of the shares was determined based upon a fair value model of the Company incorporating market based multiples of EBITDA as well as assumptions about future operating cash flows of the Company. The fair value is measured at each reporting period and amortized as compensation expense over the vesting period. For the nine months ended September 30, 2013, the Company recognized $27 thousand in compensation expense related to the Units which is recorded in general and administrative expense in the consolidated statements of operations. The following table sets forth the grants and forfeitures of Units during the period from January 1, 2013 through September 30, 2013:


	Units		Weighted Average September 30, 2013 Fair Value/Unit
	(in thousands)
Units at the beginning of the year		40	$	10.54
Units Granted		93		2.64
Units Vested		—		—
Units Forfeited		20		10.54
Profits Interests Outstanding at September 30, 2013		113	$	4.04

The Units vest over a five-year period from the date of grant, with 1/3^rd vesting at the end of the third year, 1/3^rd at the end of the fourth year and 1/3^rd vesting at the end of the fifth year or will vest in full upon the occurrence of a Fundamental Change, as defined in the Agreement. Profits Interests Units participate in distributions; however, for those distributions related to units not yet vested, the distributions are held in escrow until such time as the underlying units vest.

8. Related-Party Transactions

The Company reimburses Cypress Energy Management, LLC, (“CEM”) and Cypress Energy Holdings, LLC (CEH), affiliated entities, for general and administrative and management labor expenses allocated to us based on the estimated use of such services (Management Fees). The fee includes direct expenses plus an allocation of compensation costs based on employee time expended and other indirect expenses based on estimated usage. Management believes this allocation methodology is a reasonable method of allocating general and administrative expenses and provides for a reasonably accurate depiction of what our general and administrative expenses would be on a stand-alone basis without affiliations with CEM and CEH. During the nine-month period ended September 30, 2013, the Company incurred Management Fees totaling $233 thousand.

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Cypress Energy Partners, LLC

Notes to Unaudited Condensed Consolidated Financial Statements
September 30, 2013

8. Related-Party Transactions – (continued)

The Company also allocates a portion of its general and administrative expenses to an affiliate.

During the nine-month period ended September 30, 2013, the Company incurred $359 thousand in general and administrative expenses that were allocated to the affiliate. The amount due from the affiliate related to the allocations was $359 thousand at September 30, 2013 and is shown in affiliate receivables on the condensed consolidated balance sheet.

The Company has a related-party receivable and related-party payable at December 31, 2012, of $439 thousand and $1.5 million, respectively, from SBG. These amounts relate to truck hauling, management fees, insurance, and other miscellaneous costs incurred during 2012 with SBG-related entities. The balances were settled during the third quarter of 2013.

The seller of SBG became a board member of the Company effective December 31, 2012 and he or his employees continue to own several entities with which the Company does business including SBG Disposal LLC and Rud Transportation LLC. SBG Disposal provides labor services to man the wells in the Bakken region as well as certain accounting, billing and management oversight functions. During the nine-month period ended September 30, 2013, the Company incurred charges from SBG disposal for labor services totaling $2.0 million. As of September 30, 2013, the Company had accounts payable to SBG Disposal for labor services totaling $419 thousand. Fees for labor services totaling $48 thousand were charged to the SBG SWDs prior to the sale of the SWDs to the Company. This amount is included in accounts payable at December 31, 2012. Rud Transportation is a customer of the Company’s SWDs. During the nine-month period ended September 30, 2013, the company recognized revenue totaling $1.3 million, from Rud Transportation. As of September 30, 2013, the Company had accounts receivable from Rud Transportation totaling $410 thousand.

9. Commitments and Contingencies

Letters of Credit

The Company has various performance obligations which are secured with short-term security deposits of $486 thousand, included in prepaid expenses and other current assets on the consolidated balance sheet, and under a $25 thousand letter of credit executed by its sole member Cypress Energy Holdings, LLC.

Litigation

The Company has no outstanding claims or legal actions arising from its business operations.

10. Subsequent Events

The Company has evaluated subsequent events through October 30, 2013, which is the date these financial statements were available to be issued.

Effective October 1, 2013, the Company exercised an option to purchase a 51% interest in certain assets of SBG Disposal. LLC for total cash consideration of $500 thousand. In addition, the Company previously assigned a fair value of $225 thousand to its option to purchase the business. The exercise of the option, along with the purchase price, totaled $725 thousand. The acquisition qualifies as a business combination and will be accounted for under the purchase method of accounting. Accordingly, we will recognize amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values. Fair values will be determined based on Level 3 fair value inputs. Through our 51% interest we obtained control of the assets and will use consolidation accounting recognizing the 49% noncontrolling interest in our consolidated balance sheets and statements of operations.

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Report of Independent Auditors

The Board of Directors and Members
Cypress Energy Partners, LLC

We have audited the accompanying statement of revenues and direct operating expenses (Statement) of assets purchased by Cypress Energy Partners, LLC (the Company) from Moxie Disposal Systems, LLC and Peach Energy Services, LLC (the Acquired Assets) for the period from July 1, 2012 (Inception) through December 3, 2012. This Statement is the responsibility of the Company’s management. Our responsibility is to express an opinion on the Statement based on our audit.

We conducted our audit in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the Statement is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the Statement. An audit also includes assessing the basis of accounting used and significant estimates made by management, as well as evaluating the overall presentation of the Statement. We believe that our audit provides a reasonable basis for our opinion.

The accompanying Statement was prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission as described in Note 1, and is not intended to be a complete presentation of the Acquired Assets’ revenues and expenses.

In our opinion, the Statement referred to above presents fairly, in all material respects, the revenues and direct operating expenses of the Acquired Assets for the period from July 1, 2012 (Inception) through December 3, 2012 in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young, LLP

Tulsa, Oklahoma
July 15, 2013

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Statement of Revenues and Direct Operating Expenses of
Assets Purchased by Cypress Energy Partners, LLC
From Moxie Disposal Systems, LLC and
Peach Energy Services, LLC
From Period From July 1, 2012 (Inception) Through December 3, 2012


	(in thousands)
Revenues	$	3,180
Direct operating expenses		1,789
Revenues in excess of direct operating expenses	$	1,391

See accompanying notes to the statement of revenues and direct operating expenses.

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Notes to Statement of Revenues and Direct Operating Expenses of
Assets Purchased by Cypress Energy Partners, LLC
From Moxie Disposal Systems, LLC and
Peach Energy Services, LLC
December 3, 2012

1. Basis of Presentation

On December 3, 2012, Cypress Energy Partners, LLC (Cypress) purchased four commercial salt water disposal wells located in North Dakota and Texas, along with regulatory and utility cash deposits of $139 thousand, and oil inventory of $149 thousand, from Moxie Disposal Systems, LLC and Peach Energy Services, LLC (the Acquired Assets) for a total of $23.9 million in cash, subject to customary purchase price adjustments. The accompanying statement of revenues and direct operating expenses (the Statement) relates to the operations of the Acquired Assets.

The accompanying Statement varies from a complete income statement in accordance with accounting principles generally accepted in the United States of America in that it does not reflect certain expenses that were incurred in connection with the ownership and operation of the Acquired Assets including, but not limited to, general and administrative expenses, interest expenses, and federal and state income tax expenses. These costs were not separately allocated to the Acquired Assets in the accounting records of Moxie Disposal Systems, LLC. In addition, the allocations, if made using historical general and administrative structures and tax burdens, would not produce allocations that would be indicative of the historical performance of the Acquired Assets had they been Cypress’ facilities due to the differing size, structure, operations, and accounting policies of Moxie Disposal Systems, LLC and Cypress. The accompanying Statement also does not include provisions for depreciation, amortization, and accretion expense associated with asset retirement obligations, as such amounts would not be indicative of the costs that Cypress will incur upon the allocation of the purchase price paid for the Acquired Assets. Furthermore, no balance sheet has been presented for the Acquired Assets because their historical cost and related working capital balances were not segregated or easily obtainable. Accordingly, the accompanying Statement is presented in lieu of the full financial statements required under Item 3-05 of Securities and Exchange Commission (SEC) Regulation S-X.

This Statement is not indicative of the results of operations for the Acquired Assets on a go-forward basis.

2. Summary of Significant Accounting Policies

Revenue Recognition

Total revenues in the accompanying Statement include salt water disposal fees as well as crude oil sold through the skimming process at the facilities. Water disposal and oil revenues are recorded using the sales method. Under this method, the Company recognizes revenues based on actual volumes of water disposed and charged to customers and oil sold to purchasers.

Direct Operating Expenses

Direct operating expenses are recognized when incurred and consist of direct expenses of operating the Acquired Assets. The direct operating expenses include repairs and maintenance, professional and outside services, utilities, property taxes, supplies, bad debt and other field-related expenses.

3. Contingencies

The activities of the Acquired Assets are subject to potential claims and litigation in the normal course of operations. Management does not believe that any liability resulting from any pending or threatened litigation will have a materially adverse effect on the operations or financial results of the Acquired Assets.

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Notes to Statement of Revenues and Direct Operating Expenses of
Assets Purchased by Cypress Energy Partners, LLC
From Moxie Disposal Systems, LLC and
Peach Energy Services, LLC
December 3, 2012

4. Subsequent Events

Management has evaluated subsequent events through July 15, 2013, the date the Statement was available to be issued.

5. Cash Flows (Unaudited)

Cash flow information for operating, investing, and financing activities is not presented because in the accounting records of Moxie Disposal Systems, LLC, the cash flow information applicable to the operations of the Acquired Assets was not segregated. Operating cash flow should have been $1.4 million less any applicable reconciliations to revenues in excess of direct operating expenses, including working capital adjustments. Investing cash flows would have included the costs of constructing the salt water disposal wells. Financing cash flows would have included the methods for paying for the construction of the salt water disposal wells; however, that information is not available for the reasons discussed above.

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Report of Independent Certified Public Accountants

Board of Directors
Tulsa Inspection Resources, Inc.

We have audited the accompanying consolidated financial statements of Tulsa Inspection Resources, Inc. (an Oklahoma corporation) and subsidiaries (“the Company”), which comprise the consolidated balance sheets as of December 31, 2012 and 2011, and the related consolidated statements of operations and comprehensive income, changes in stockholders’ equity, and cash flows for the years then ended, and the related notes to the financial statements.

Management’s responsibility for the financial statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditor’s responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Tulsa Inspection Resources, Inc. and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.

/s/ Grant Thornton LLP

Tulsa, Oklahoma
March 29, 2013

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Tulsa Inspection Resources, Inc. and Subsidiaries

Consolidated Balance Sheets
December 31, 2012 and 2011


	2012		2011
	(in thousands except share information and par value)
ASSETS
CURRENT ASSETS:
Cash	$	5,044	$	2,459
Restricted cash		—		1,514
Accounts receivable, net		38,466		18,302
Refundable income taxes – Canada		160		—
Prepaid expenses and other		516		324
Total current assets		44,186		22,599
PROPERTY AND EQUIPMENT, net		1,025		848
INTANGIBLE ASSETS, net		24,061		25,979
GOODWILL		1,186		1,161
DEBT ISSUANCE COSTS, net		366		337
OTHER ASSETS		17		58
Total assets	$	70,841	$	50,982
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	1,315	$	1,197
Accrued payroll and other		8,075		3,855
Income taxes payable – US		65		83
Income taxes payable – Canada		—		265
Obligation under factoring agreement		26,592		15,679
Current maturities of notes payable		188		1,169
Current non-compete liability		—		3
Deferred tax liabilities		117		53
Total current liabilities		36,352		22,304
NON-CURRENT LIABILITIES:
Notes payable, less current maturities		19,236		19,064
Deferred tax liability		1,197		446
STOCKHOLDERS’ EQUITY:
Common stock, $1.00 par value; 200 shares authorized; 139 and 130 shares issued; 113 and 101 shares outstanding at December 31, 2012 and 2011, respectively		—		—
Additional paid-in capital		12,197		10,164
Less treasury stock, at cost; 26 and 29 shares at December 31, 2012 and 2011, respectively		—		—
Accumulated other comprehensive income		223		30
Retained earnings (deficit)		1,636		(1,026	)
Total stockholders’ equity		14,056		9,168
Total liabilities and stockholders’ equity	$	70,841	$	50,982

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

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Tulsa Inspection Resources, Inc. and Subsidiaries

Consolidated Statements of Operations
and Comprehensive Income
For the Years Ended December 31, 2012 and 2011


	2012			2011
	(in thousands)
INSPECTION SERVICE REVENUES	$	233,803		$	145,287
COST OF SERVICES		211,404			130,107
GROSS PROFIT		22,399			15,180
GENERAL AND ADMINISTRATIVE EXPENSE		10,528			6,441
DEPRECIATION AND AMORTIZATION EXPENSE		2,438			2,590
OPERATING INCOME		9,433			6,149
OTHER INCOME (EXPENSE):
Interest income (expense), net		(4,956	)		(4,907	)
Other, net		6			14
INCOME BEFORE INCOME TAXES		4,483			1,256
INCOME TAX EXPENSE		(1,821	)		(493	)
NET INCOME	$	2,662		$	763
OTHER COMPREHENSIVE INCOME:
Foreign currency translation adjustment		193			(91	)
		193			(91	)
TOTAL COMPREHENSIVE INCOME	$	2,855		$	672

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

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Tulsa Inspection Resources, Inc. and Subsidiaries

Consolidated Statements of Changes in Stockholders’ Equity
For the Years Ended December 31, 2012 and 2011
(In Thousands)


	Common Stock		Additional Paid-in Capital		Treasury Stock		Accumulated Other Comprehensive Income			Retained (Deficit)/ Earnings			Total Stockholders' Equity
Balance, December 31, 2010	$	—	$	10,072	$	—	$	121		$	(1,789	)	$	8,404
Net income		—		—		—		—			763			763
Stock based compensation		—		92		—		—			—			92
Foreign currency translation adjustment		—		—		—		(91	)		—			(91	)
Balance, December 31, 2011		—		10,164		—		30			(1,026	)		9,168
Net income		—		—		—		—			2,662			2,662
Issuance of shares		—		1,906		—		—			—			1,906
Stock based compensation		—		127		—		—			—			127
Foreign currency translation adjustment		—		—		—		193			—			193
Balance, December 31, 2012	$	—	$	12,197	$	—	$	223		$	1,636		$	14,056

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

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Tulsa Inspection Resources, Inc. and Subsidiaries

Consolidated Statements of Cash Flows
For the Years Ended December 31, 2012 and 2011


	2012			2011
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	2,662		$	763
Adjustments to reconcile net income to net cash provided by (used in) operating activities
Depreciation and amortization		2,569			2,694
Deferred tax benefit (expense)		790			(51	)
Accretion of debt discount		172			172
Interest expense for debt issuance costs		304			132
Stock based compensation		127			92
Changes in assets and liabilities
Accounts receivable		(20,164	)		(3,475	)
Income taxes payable (refundable)		(442	)		567
Prepaid expenses and other		(208	)		51
Accounts payable		371			189
Accrued payroll and benefits		3,967			1,162
Non-compete liability		(3	)		(279	)
Net cash (used in) provided by operating activities		(9,855	)		2,017
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments for the purchase of property and equipment		(470	)		(211	)
Payment for purchase of intangible asset		(63	)		—
Net cash used in investing activities		(533	)		(211	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from factoring agreement		10,878			2,117
Net proceeds from issuance of stock		1,906			—
Principal payments on notes payable		(84	)		(288	)
Payments for debt issuance		(332	)		(40	)
Principal payments on seller financing note		(1,072	)		(852	)
Change in restricted cash		1,514			(798	)
Net cash provided by financing activities		12,810			139
EFFECTS OF EXCHANGE RATES ON CASH		163			(49	)
NET INCREASE IN CASH AND CASH EQUIVALENTS		2,585			1,896
CASH, BEGINNING OF YEAR		2,459			563
CASH, END OF YEAR	$	5,044		$	2,459
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Cash paid for interest and fees	$	4,956		$	4,658
Cash paid for income taxes	$	1,501		$	149

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

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Tulsa Inspection Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements
December 31, 2012 and 2011

A — Description of Business and Basis of Financial Statements

Tulsa Inspection Resources, Inc. (“TIR”), an Oklahoma corporation, along with its subsidiaries, Tulsa Inspection Resources — Nondestructive Examination, Inc. (“TIR-NDE”), an Oklahoma corporation, Tulsa Inspection Resources — Canada, Inc. (“TIR-Canada”) and Foley Inspection Services, Inc. (“Foley”), Canadian corporations, provide inspection services for the construction and maintenance of oil and gas pipelines and related facilities.

On June 30, 2009, TIR-Canada was formed by TIR to expand operations into Canada. On July 8, 2010, Foley was purchased by TIR to further increase the Company’s presence in the Canadian market.

On August 10, 2012, the Company incorporated a new subsidiary, Tulsa Inspection Resources — Nondestructive Examination, Inc. (“TIR-NDE”), an Oklahoma Corporation, to provide nondestructive testing (“NDT”) services to existing and potential customers. These services are performed by certified technicians who use various examination techniques, including ultrasonic testing, to identify and communicate information related to anomalies in the customer’s pipeline or related facilities.

B — Summary of Significant Accounting Policies

1. Principles of Consolidation

The accompanying consolidated financial statements include the accounts of TIR and its wholly owned subsidiaries, TIR-NDE, TIR-Canada and Foley (collectively the “Company”). All intercompany accounts and transactions have been eliminated in consolidation.

2. Cash

Cash consists of cash in interest-bearing checking accounts. Any restrictions to cash are due to factoring agreements and are properly classified.

3. Revenue Recognition

Services are performed under contracts with customers, which may be terminated at any time. Generally, inspection services and Company-provided equipment are billed on a per day basis. Service revenue is recognized when the services are provided and collectability is reasonably assured.

4. Trade Receivables

Trade receivables are carried at original invoice amounts. The Company provides inspection services to relatively few customers. Customer relationships are generally long-term and collection history is excellent. Management assesses the need for an allowance for doubtful accounts by regularly evaluating individual customer receivables and by considering a customer’s financial condition, credit history and current economic conditions. Trade receivables are written off against the allowance when deemed uncollectible. Recoveries of trade receivables previously written off are recorded when received. At December 31, 2012 and 2011, the allowance for doubtful accounts was $47 thousand.

A trade receivable is considered to be past due if any portion of the receivable balance is outstanding past the terms of the invoice. The Company does not typically charge interest on past due trade receivables and does not require collateral for its trade receivables.

The Company routinely factors the majority of its trade receivables to a third party with full recourse (see Note H).

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Tulsa Inspection Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements
December 31, 2012 and 2011

B — Summary of Significant Accounting Policies – (continued)

5. Intangible Assets

The Company evaluates whether events and circumstances have occurred that indicate the remaining estimated useful lives of the intangible assets may warrant revision or that the remaining balance of these assets may not be recoverable. In performing the review for recoverability, the Company estimates the future undiscounted cash flows expected to result from the use of the assets. The amount of the impairment loss, if impairment exists, is calculated based on the excess of the carrying amounts of the assets over their estimated fair value computed using discounted cash flows. No impairment losses were recorded for the years ended December 31, 2012 and 2011.

6. Goodwill

Goodwill represents the excess of cost over fair value of the assets of businesses acquired. Goodwill is evaluated at least annually for impairment by first comparing management’s estimate of the fair value of the reporting unit, or operating segment, with the reporting unit’s carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, a computation of the implied fair value of goodwill would then be compared to its related carrying value. If the carrying value of the reporting unit of goodwill exceeds the implied fair value of goodwill, an impairment loss would be recognized in the amount of the excess. Judgments and assumptions are inherent in our estimate of future cash flows used to determine the reporting unit’s fair value. The use of alternate judgments and/or assumptions could result in a different outcome. There was no impairment recognized in the years ended December 31, 2012 or 2011.

7. Property and Equipment

Property and equipment consisting of field and office equipment are stated at cost, net of accumulated depreciation. Depreciation is computed using the straight-line method over the asset’s estimated useful life. Field equipment depreciation is part of the services delivered to the customer and included in Cost of Services on the consolidated statement of operations.

The estimated useful lives of property and equipment are as follows:


Office equipment		3 - 7 years
Leasehold improvements		Remaining life of the lease
Field equipment		5 - 7 years

8. Income Taxes

The Company applies the asset and liability method of accounting for income taxes. Under this method, income taxes are provided for all items included in the consolidated statements 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 tax assets for amounts which are not considered more-likely-than-not to be realized. There was no valuation allowance at December 31, 2012 or 2011.

The policy of the Company is to reflect interest and penalties related to uncertain tax positions when, and if, they become applicable. The Company has not recognized any potential interest or penalties in the consolidated financial statements as of December 31, 2012 or 2011. The years ending December 31, 2010 through 2012 are open tax years.

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Tulsa Inspection Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements
December 31, 2012 and 2011

B — Summary of Significant Accounting Policies – (continued)

9. Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. Actual results could differ from the estimates and assumptions used.

10. Share Based Compensation

The Company accounts for share-based compensation at fair value. The company records compensation costs for share-based compensation awards over the requisite service period (vesting period). Compensation expense is recognized net of estimated forfeitures. As each award vests, adjustments are made to compensation costs for any difference between estimated forfeitures and the actual forfeitures related to the awards. The fair value of the option awards is determined using the Black-Scholes option pricing model. The Black-Scholes option-pricing model takes into account certain variables, which are explained further in Note M.

11. Reclassifications

Certain items from prior year have been reclassified to conform with current year presentation. The reclassifications did not have a material impact on the financial statements and there was no impact on net income.

C — Acquisitions

On September 4, 2012 the Company executed an Asset Purchase and License Agreement (“Asset Purchase Agreement”) totaling $250 thousand with a newly hired employee to purchase certain intangible assets specific to the NDT industry. The assets purchased included customer lists, patented testing procedures developed by the employee prior to employment and an exclusive license to the use of trademarked NDT equipment registered in the employee’s name. The terms of the Asset Purchase Agreement require payments to be made quarterly (see Note I).

D — Intangible Assets

The Company’s intangible assets represent the estimated fair values of customer contracts and relationships and non-compete agreements. The customer contracts and relationships are being amortized on a straight-line basis over their useful lives of 5 – 15 years. The non-compete agreements are being amortized on a straight-line basis over the life of the respective contracts.

Intangible assets consisted of the following at December 31:


	2012			2011
	(in thousands)
Customer contracts and relationships	$	31,827		$	31,562
Other intangibles		100			—
Non-compete agreements		1,154			1,147
		33,081			32,709
Accumulated amortization		(9,020	)		(6,730	)
	$	24,061		$	25,979

The Company recognized $2.3 million and $2.5 million in amortization expense for the years ended December 31, 2012 and 2011, respectively.

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Tulsa Inspection Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements
December 31, 2012 and 2011

D — Intangible Assets – (continued)

Estimated amortization of intangible assets for the next five years and thereafter is as follows at December 31, 2012:


	(in thousands)
2013	$	2,213
2014		2,162
2015		2,162
2016		2,162
2017		2,162
Thereafter		13,200

E — Accounts Receivable

Accounts receivable consisted of the following at December 31:


	2012			2011
	(in thousands)
Billed	$	36,956		$	18,110
Unbilled		1,491			160
Other		66			79
Less: Allowance for doubtful accounts		(47	)		(47	)
Accounts receivable, net	$	38,466		$	18,302

Unbilled receivables result from inspection services performed and equipment rentals not billed as of the year-end.

F — Property and Equipment

Property and equipment consisted of the following at December 31:


	2012			2011
	(in thousands)
Office equipment	$	583		$	307
Auto		21			21
Leasehold improvements		98			50
Software		374			357
Field equipment		623			490
		1,699			1,225
Less: Accumulated depreciation		(674	)		(377	)
Property and equipment, net	$	1,025		$	848

Depreciation expense totaled $295 thousand and $234 thousand for the years ended December 31, 2012 and 2011, respectively. Field equipment depreciation expense of $131 thousand and $104 thousand were included as part of Cost of Services in 2012 and 2011, respectively.

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Tulsa Inspection Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements
December 31, 2012 and 2011

G — Leases

The Company leases office space under the terms of operating lease agreements. The leases expire from 2014 through 2018. Some leases require stipulated rent increases annually. The Company has the option to extend the lease expiring in 2014 for an additional three years. The Company also leases office equipment under operating lease agreements which expire between 2013 and 2017. The Company recognizes expense on a straight-line basis in equal amounts over the lease term.

Rent expense under the leases totaled $459 thousand and $260 thousand for the years ended December 31, 2012 and 2011, respectively.

Approximate future minimum rentals under these noncancelable operating leases are as follows at December 31, 2012:


	(in thousands)
2013	$	559
2014		522
2015		378
2016		346
2017		211
Thereafter		80

H — Obligation under Factoring Agreement

On April 29, 2010, the Company entered into a $15 million factoring agreement which had an expiration of April 29, 2012. The discount fee was set at 0.85%. The reserve amount was initially set at 5% and remained at 5% through the loan term. The bank required TIR to repurchase all or a portion of receivables from any customer if a minimum payment due on one or more receivables remained unpaid following 120 days after the invoice date.

The bank deposited the proceeds from receivables sold, less a discount fee of 0.85%, to TIR’s operating account. The bank retained 5% of the amounts payable to TIR as a reserve to provide for satisfaction of TIR’s repurchase obligation. The reserve was held in a separate interest-bearing account for the benefit of TIR. The reserve balance was $670 thousand at December 31, 2011, and is classified as restricted cash on the balance sheet. Customer payments were made directly to the bank. The obligation under the factoring agreement at December 31, 2011, was $13.4 million.

The collateral for the factoring agreement consisted of a security interest by the bank in all future accounts receivable excluding the three specific customers listed below and all property and equipment of TIR.

Additionally during August 2011, TIR entered into a new factoring agreement with a financing company for factoring receivables of three specific customers for a term of 6 months. This financing was in addition to the $15 million agreement that existed with the previous bank. The discount fee was set at 1.75%. The reserve amount was initially set at 20% with an additional reserve added during the term of 20% of unvalidated invoices that had been funded.

The financing company deposited the proceeds from receivables sold, less a discount fee of 1.75%, to TIR’s operating account. The financing company retained 20% of the amounts payable to TIR as a reserve to provide for satisfaction of TIR’s repurchase obligation. The reserve balance was $844 thousand at December 31, 2011 and is classified as restricted cash on the balance sheet. Customer payments were made directly to the financing company. The obligation under the factoring agreement at December 31, 2011 was $2.3 million.

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Tulsa Inspection Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements
December 31, 2012 and 2011

H — Obligation under Factoring Agreement – (continued)

On February 29, 2012, the Company entered into a new $25 million factoring agreement with a bank which expires March 1, 2015. This new agreement replaced the two previous factoring agreements. The $25 million agreement is allocated between separate Canadian and U.S. facilities, with the Canadian borrowings limited to no more than $7.5 million of the combined amount. The bank factors the invoices at a 90% advance rate and deposits the funds into the Company’s operating account. The bank charges interest on purchased receivables at an annualized rate of LIBOR plus 4.75% on U.S. invoices and Canadian Dealer Offered Rate (“CDOR”) plus 5.3% on Canadian invoices, for the duration the invoice remains financed. In addition to interest charges, the agreement calls for a facility renewal fee of 0.50% charged annually.

On September 6, 2012, the factoring agreement with the bank was amended to $30 million to support the continued growth of the Company. On October 29, 2012 the Company further amended the agreement to provide a temporary increase to $33 million for the period from October 29, 2012 through January 31, 2013, at which time the facility returned back to $30 million. The obligation under the new factoring agreement at December 31, 2012 was $26.6 million.

The collateral for the US portion of the factoring agreements consists of a senior secured interest in all assets of TIR. The collateral for the Canadian portion of the factoring agreements consists of a senior secured interest in the accounts receivables of Foley and TIR-Canada.

I — Debt

On March 12, 2009, the Company entered into a loan agreement with various lenders for Senior Subordinated Notes (“the Notes”) in the aggregate sum of $17 million due March 12, 2014. The Notes bear interest at 14% annually, and the Company is only required to make monthly interest payments until the Notes mature in 2014. The Notes are secured by substantially all of the assets of the Company after consideration of the Company’s collateral obligations under the factoring agreement discussed in Note H. Additionally, the Company is subject to certain financial covenants. These include a maximum debt to EBITDA ratio (the “Funded Leverage Ratio”), a minimum EBITDA to principal and interest expense ratio (the “Fixed Charge Ratio”), a maximum capital expenditure amount and a minimum EBITDA amount.

On July 8, 2010, the Company signed the First Amendment to the loan agreement. All of the financial covenants were amended and restated beginning the quarter ended June 30, 2010 and a new covenant of a maximum net funded debt to EBITDA ratio (the “Net Funded Leverage Ratio”) was added to the agreement.

On July 8, 2010, the Company entered into a loan agreement with the same group of lenders for a second set of Senior Subordinated Notes (“Senior Subordinated Notes II”) in the aggregate sum of $2.8 million due March 12, 2014. The Notes bear interest at 17.5% annually, and the Company is only required to make monthly interest payments until the Notes mature in 2014. The Notes are secured by substantially all of the assets of the Company after consideration of the Company’s collateral obligations under the factoring agreement discussed in Note H. Additionally, the Company is subject to certain financial covenants. These include a Net Funded Leverage Ratio, a Fixed Charges Ratio, a minimum EBITDA, a maximum subordinated debt to EBITDA ratio (the “Net Subordinated Debt Leverage Ratio”) and a maximum annual capital expenditure amount.

The Company violated the maximum annual capital expenditure covenant during 2012, but obtained a waiver for this violation through the date of this report. The provisions of all other covenants were met by the Company during 2012.

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Notes to Consolidated Financial Statements
December 31, 2012 and 2011

I — Debt – (continued)

The Company issued warrants in connection with the Senior Subordinated Notes and Senior Subordinated Notes II which resulted in a discount on the debt (see Note J). Accretion expense is being recognized over the life of the loan using the effective interest method. The Company recognized accretion expense of $172 thousand and $172 thousand for the years ended December 31, 2012 and 2011, respectively, which is included in interest expense in the consolidated statements of operations and comprehensive income.

On July 8, 2010, the Company entered into a seller financing note in connection with the Foley Acquisition in the sum of $2.2 million Canadian dollars, ($2.1 million US dollars at the date of issuance) (the “Seller Financing Note”). The Seller Financing Note bears interest at 4% annually. The Company made payments on December 31, 2010; July 15, 2011; January 14, 2012; and paid the final balance on July 15, 2012. The Seller Financing Note was secured by substantially all the assets of the Company. This note was subordinate to the Senior Subordinated Notes and Senior Subordinated Notes II.

The Company executed an Asset Purchase Agreement with a new employee on September 4, 2012 totaling $250 thousand (see Note C). The Asset Purchase Agreement specifies four payments of $68 thousand to be paid quarterly beginning December 1, 2012.

Notes payable consisted of the following at December 31:


	2012			2011
	(in thousands)
Note payable to a bank, monthly principal and interest payments of $12 thousand; interest at Chase Prime plus 1.00% (4.25% at December 31, 2011), due November 21, 2012	$	—		$	84
Senior subordinated notes I and II, net of debt discount of $519 thousand and $692 thousand at December 31, 2012 and 2011, respectively		19,236			19,064
Asset Purchase Agreement		188			—
Seller financing note		—			1,050
Other notes payable		—			35
Notes payable		19,424			20,233
Less: current maturities		(188	)		(1,169	)
Notes payable, less current maturities		19,236			19,064

Long-term debt maturities are as follows at December 31, 2012:


	(in thousands)
2013	$	188
2014		19,236
	$	19,424

J — Warrants

In connection with the Senior Subordinated Notes (see Note I) on March 12, 2009, the Company issued warrants to the lenders. The warrants grant the lenders the right to acquire 23.75 shares of common stock of the Company at $0.01 per share. The warrants expire ten years from the date of issuance. The fair value of the warrants was $822 thousand and was determined

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Notes to Consolidated Financial Statements
December 31, 2012 and 2011

J — Warrants – (continued)

using an EBITDA multiple pricing model. The majority shareholder contributed 23.75 shares of stock for the Company to hold in treasury in the event of the exercise of the warrants.

On March 12, 2009 the Company granted the lender conditional warrants that have a three year term, are exercisable at $0.01 per share, and offer the right to acquire five shares of common stock of the Company in the event of a change of control of the Company or a change in the Company’s line of business. The majority shareholder contributed five shares of stock for the Company to hold in treasury in the event of the exercise of the warrants. The warrants expire in increments on the anniversary of issuance until all of the warrants expire on March 12, 2012. It was determined that the fair value related to these warrants would be minimal due to the uncertainty of the occurrence of the events required for them to be exercisable. On March 12, 2012, the remaining conditional warrants expired and the shares held in treasury were returned to the majority shareholder.

In connection with the Senior Subordinated Notes II (see Note I), on July 8, 2010, the Company issued warrants to the lenders. The warrants granted the lenders the right to acquire 2.21 shares of common stock of the Company at $0.01 per share. The warrants expire ten years from the date of issuance. The fair value of the warrants was $155 thousand and was determined using an EBITDA multiple pricing model. The Company added 2.21 shares of stock to hold in treasury in the event of the exercise of the warrants.

K — Concentration of Credit Risk

The Company operates in both the US and Canada in a single line of business as the Company’s customers operate oil and gas pipelines and related facilities. Three of the Company’s customers accounted for approximately 43% of inspection revenue in 2012 and two customers accounted for approximately 24% of the Company’s accounts receivable balance at December 31, 2012. Two of the Company’s customers accounted for approximately 38% of inspection revenue in 2011 and two customers accounted for approximately 32% of the Company’s accounts receivable balance at December 31, 2011.

The Company maintains account balances at certain banks, which are insured by the Federal Deposit Insurance Corporation (“FDIC”) or the Canadian Deposit Insurance Corporation (“CDIC”), depending on the location of the funds. At times, cash balances may be in excess of the FDIC or CDIC insurance limit. The Company does not believe it is exposed to any significant credit risk with respect to its cash balances.

L — Income Taxes

Deferred tax assets and liabilities are composed of the following at December 31, 2012 and 2011:


	2012			2011
	(in thousands)
Current deferred tax assets (liabilities)
Prepaid expenses	$	(136	)	$	(71	)
Allowance for doubtful accounts		19			18
Total	$	(117	)	$	(53	)
Non-current deferred tax assets (liabilities)
Property and equipment	$	(347	)	$	(253	)
Intangible assets		(847	)		(872	)
Other		(3	)		1

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Notes to Consolidated Financial Statements
December 31, 2012 and 2011

L — Income Taxes – (continued)


	2012			2011
	(in thousands)
Canadian NOL		—			14
US NOL		—			664
Total	$	(1,197	)	$	(446	)

Significant components of the income tax provision (benefit) are as follows at December 31, 2012 and 2011:


	2012			2011
	(in thousands)
Current provision:
Federal	$	642		$	—
State		199			195
Canadian		190			307
Total current provision		1,031			502
Deferred provision:
Federal		735			(62	)
State		168			(10	)
Canadian		(113	)		63
Total deferred provision (benefit)		790			(9	)
Income tax provision	$	1,821		$	493

The following table summarizes the differences between the U.S. federal rate and the Company’s effective tax rate for financial statement purposes for the year ended:


	2012			2011
Statutory tax rate		34	%		34	%
State income taxes, net of U.S. federal tax benefit		5	%		8	%
Tax credits and exclusions		2	%		6	%
Other, including Canada income taxes		—			(9	%)
Company’s effective tax rate		41	%		39	%

M — Stock Based Compensation

On January 1, 2011, the Company executed the Stock Option Plan to allow certain stock based compensation to be issued to employees, non-employee directors and contractors. Under the Plan, up to 14 shares of Common Stock may be subject of the awards. At the discretion of the administrator of the Stock Option Plan, employees, non-employee directors and consultants may be granted awards in the form of incentive stock options, non-qualified stock options or restricted shares, any of which may be service, market or performance based awards.

Total recognized compensation expense related to the non-qualified stock options issued was $127 thousand during 2012. The Company recognized tax benefits of $43 thousand associated with this expense during the year. The Company recognizes compensation costs, net of a forfeiture rate, as the options become vested. The non-qualified options granted to employees during 2011 vest over a three year period based on the Company achieving a minimum EBITDA target and the employee continuing to remain employed with the Company, unless a liquidation event occurs, at which time all of the remaining unvested portion of the options outstanding become vested. In

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Notes to Consolidated Financial Statements
December 31, 2012 and 2011

M — Stock Based Compensation – (continued)

addition, if the minimum EBITDA target is missed during the initial three year vesting period, the option vesting target extends out an additional year. All non-qualified options issued expire 10 years from the grant date.

Option activity and changes were as follows:


	2012		2011
Outstanding at January 1		7.0		—
Granted		—		7.0
Exercised		—		—
Forfeited or expired		—		—
Outstanding at December 31		7.0		7.0

As of December 31, 2012, $153 thousand of total unrecognized compensation costs related to share options is expected to be recognized over the next year. The weighted-average grant-date fair value of the options granted during 2011 was $371 thousand. There were no exercise or forfeitures of options by employees during 2011 or 2012.

The Company utilizes the Black-Scholes option pricing model to value the non-qualified options issued. During January 2011, the Company granted 7.0 options to purchase common stock to certain employees. The table below presents the weighted average value and assumptions used in determining each option’s fair value during 2011. Volatility was determined using the calculated method by taking an average of the historical volatility of comparable public companies’ common share price.


	2011
Exercise price	$	—
Weighted average fair value of underlying shares (in thousands)	$	102
Risk-free interest rate		2.74	%
Expected life in years		7
Expected volatility		47.51	%
Expected dividend yield		—

N — Commitments and Contingencies

The Company has employment agreements with certain of its executive officers and other management personnel. The executive employment agreements are effective for a term of two to three years from the commencement date, after which time they will continue on an “at-will” basis. These agreements provide for minimum annual compensation, adjusted for annual increases as authorized by the Board of Directors, as well as eligibility to participate in any incentive stock plans adopted by the Company. Certain agreements provide for severance payments in the event of specified termination of employment. As of December 31, 2012 and 2011, the aggregate commitment for future compensation and severance was $1.8 million and $219 thousand, respectively.

O — Related Party Transaction

The Company has a management agreement with one of the lenders. The Company pays the lender $38 thousand per quarter for management and advisory services. The Company recognized $150 thousand of expense each year for December 31, 2012 and 2011 related to this agreement.

The Company also has a management agreement with the majority shareholder. Under the terms of the agreement, no payments were made to the majority shareholder until the payoff of a

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Notes to Consolidated Financial Statements
December 31, 2012 and 2011

O — Related Party Transaction – (continued)

certain amortizing bank note held by the Company. The Company paid the bank note off on February 29, 2012 and thereafter began making payments to the majority shareholder as outlined in the agreement. The Company recognized $113 thousand of expense under this agreement during 2012.

During 2012, Foley began doing business with Contract Pro, a nonaffiliated Canadian company owned by two Foley employees. Contract Pro offers employment services to specific individuals that do not want to provide services as an independent contractor to Foley. Foley invoices customers for the services of the Contract Pro employees and makes the associated payments to Contract Pro, while keeping a portion of the proceeds. In addition, Contract Pro reimburses Foley for certain services as the company shares the Foley offices. The payments, net of Contract Pro reimbursements, made by Foley to Contract Pro during 2012 totaled $1.4 million.

P — Subsequent Events

Management has evaluated subsequent events through March 29, 2013, the date the financial statements were available to be issued. No subsequent events were identified requiring additional recognition or disclosure in the accompanying consolidated financial statements.

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Condensed Consolidated Balance Sheets
September 30, 2013 and December 31, 2012
Unaudited


	September 30, 2013			December 31, 2012
	(in thousands except share information)
ASSETS
CURRENT ASSETS:
Cash	$	13,123		$	5,044
Accounts receivable, net		65,536			38,466
Refundable income taxes – Canada		—			160
Deferred tax assets		36			—
Due from affiliate		111			—
Prepaid expenses and other		567			516
Total current assets		79,373			44,186
PROPERTY AND EQUIPMENT, net		1,202			1,025
INTANGIBLE ASSETS, net		22,246			24,061
GOODWILL		1,146			1,186
DEBT ISSUANCE COSTS, net		545			366
OTHER ASSETS		22			17
Total assets	$	104,534		$	70,841
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	2,784		$	1,315
Accrued payroll and other		18,209			8,075
Income taxes payable		744			65
Obligation under factoring agreement		45,165			26,592
Current maturities of notes payable		—			188
Deferred tax liabilities		—			117
Total current liabilities		66,902			36,352
NON-CURRENT LIABILITIES:
Notes payable, less current maturities		19,615			19,236
Deferred tax liabilities		1,010			1,197
STOCKHOLDERS’ EQUITY:
Common stock, $1.00 par value; 200 shares authorized; 141 and 139 shares issued; 115 and 113 shares outstanding at September 30, 2013 and December 31, 2012, respectively		—			—
Additional paid-in capital		12,304			12,196
Less treasury stock, at cost; 26 and 26 shares at September 30, 2013 and December 31, 2012, respectively		—			—
Accumulated other comprehensive (loss) income		(156	)		223
Retained earnings		4,859			1,637
Total stockholders’ equity		17,007			14,056
Total liabilities and stockholders’ equity	$	104,534		$	70,841

The accompanying notes are an integral part of these condensed consolidated balance sheets.

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Condensed Consolidated Statements of Operations and Comprehensive Income
For the Nine Months Ended September 30, 2013 and September 30, 2012
Unaudited


	Nine Months Ended September 30, 2013			Nine Months Ended September 30, 2012
	(in thousands)
INSPECTION SERVICE REVENUES	$	267,977		$	160,799
COST OF SERVICES		243,000			145,327
GROSS PROFIT		24,977			15,472
GENERAL AND ADMINISTRATIVE EXPENSE		13,784			7,314
DEPRECIATION AND AMORTIZATION EXPENSE		1,820			1,746
OPERATING INCOME		9,373			6,412
OTHER INCOME (EXPENSE):
Interest (expense), net		(3,803	)		(3,638	)
Other, net		2			5
INCOME BEFORE INCOME TAXES		5,572			2,779
INCOME TAX EXPENSE		(2,350	)		(1,140	)
NET INCOME	$	3,222		$	1,639
OTHER COMPREHENSIVE (LOSS) INCOME:
Foreign currency translation adjustment		(379	)		303
		(379	)		303
TOTAL COMPREHENSIVE INCOME	$	2,843		$	1,942

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

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Condensed Consolidated Statement of Changes in Stockholders’ Equity
For the Period January 1, 2013 to September 30, 2013
Unaudited
(In Thousands)


	Common Stock		Additional Paid-in Capital		Treasury Stock		Accumulated Other Comprehensive Income (Loss)			Retained Earnings		Total Stockholders' Equity
Balance, December 31, 2012	$	—	$	12,196	$	—	$	223		$	1,637	$	14,056
Net income		—		—		—		—			3,222		3,222
Stock based compensation		—		108		—		—			—		108
Foreign currency translation adjustment		—		—		—		(379	)		—		(379	)
Balance, September 30, 2013	$	—	$	12,304	$	—	$	(156	)	$	4,859	$	17,007

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

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Condensed consolidated statements of cash flows
For the Nine Months Ended September 30, 2013 and September 30, 2012
Unaudited


	Nine Months Ended September 30, 2013			Nine Months Ended September 30, 2012
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	3,222		$	1,639
Adjustments to reconcile net income to net cash used in operating activities –
Depreciation and amortization		1,958			1,842
Bad debt expense		396			—
Deferred tax (benefit) expense		(305	)		754
Accretion of debt discount		379			129
Interest expense for debt issuance costs		137			220
Stock option expense		108			95
Changes in assets and liabilities –
Accounts receivable		(27,466	)		(22,673	)
Income taxes payable (refundable)		838			(337	)
Prepaid expenses and other		(56	)		(715	)
Accounts payable		1,469			951
Accrued payroll and benefits		10,134			7,191
Net cash used in operating activities		(9,186	)		(10,904	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments for the purchase of property and equipment		(475	)		(320	)
Net cash used in investing activities		(475	)		(320	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from factoring agreement		18,573			12,488
Net proceeds from issuance of stock		—			1,906
Payments made on behalf of affiliate		(111	)		—
Principal payments on notes payable		(188	)		(84	)
Payments for debt issuance		(316	)		(332	)
Principal payments on seller financing note		—			(1,072	)
Receipt of restricted cash		—			1,514
Net cash provided by financing activities		17,958			14,420
EFFECTS OF EXCHANGE RATES ON CASH		(218	)		215
NET INCREASE IN CASH AND CASH EQUIVALENTS		8,079			3,411
CASH, BEGINNING OF PERIOD		5,044			2,459
CASH, END OF PERIOD	$	13,123		$	5,870
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Cash paid for interest and fees	$	3,287		$	3,290
Cash paid for income taxes	$	1,981		$	724

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

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Notes to Condensed Consolidated Financial Statements
September 30, 2013
(Unaudited)

A — Description of Business and Basis of Financial Statements

After the close of business on June 26, 2013, Cypress Energy Partners-Tulsa Inspection Resources, LLC (“CEP-TIR”), an Oklahoma LLC, acquired 26.45 shares from existing shareholders which, when combined with the ownership of CEP-TIR affiliates, totaled 50.3% of the total outstanding shares and warrants of the Company, representing a change of control in ownership. The Company recorded certain expenses related to the share transaction on June 26, 2013 totaling approximately $1.7 million, including a one-time management bonus liability of approximately $1.6 million. These statements do not reflect push down accounting from CEP-TIR, as we are not a wholly owned subsidiary of CEP-TIR.

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“U.S. GAAP”) for interim financial statements. These financial statements have not been audited by the Company's independent certified public accountants, except that the consolidated balance sheet at December 31, 2012 is derived from audited consolidated financial statements. Accordingly, they do not include all of the information and notes required by U.S. GAAP for complete financial statements. The financial statements reflect all adjustments (all of which are of a normal recurring nature) which are, in the opinion of management, necessary for a fair statement of the results for the interim periods presented. Interim results are not necessarily indicative of the results that may be expected for a full year. Certain disclosures have been condensed in or omitted from these consolidated financial statements. The accompanying unaudited condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto for the year ended December 31, 2012.

B — Summary of Significant Accounting Policies

The accounting policies of the Company are set forth in Note B — Summary of Significant Accounting Policies of the Notes to the December 31, 2012 audited Consolidated Financial Statements. There have been no significant changes to these policies during the nine-month period ended September 30, 2013. Below are selected accounting policies.

1. Principles of Consolidation

The accompanying unaudited condensed consolidated financial statements include the accounts of TIR and its wholly owned subsidiaries, TIR-NDE, TIR-Canada and Foley (collectively the “Company”). All intercompany accounts and transactions have been eliminated in consolidation.

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Notes to Condensed Consolidated Financial Statements
September 30, 2013
(Unaudited)

B — Summary of Significant Accounting Policies – (continued)

2. Income Taxes

The Company applies the asset and liability method of accounting for income taxes. Under this method, income taxes are provided for all items included in the unaudited condensed consolidated statements 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 tax assets for amounts which are not considered more-likely-than-not to be realized.

The policy of the Company is to reflect interest and penalties related to uncertain tax positions when, and if, they become applicable. The Company has not recognized any potential interest or penalties in the unaudited condensed consolidated financial statements as of June 26, 2013. The years ended December 31, 2010 through 2012 are open for review by various tax authorities.

3. Use of Estimates

4. Share Based Compensation

C — Acquisitions

D — Obligation under Factoring Agreement

On February 29, 2012, the Company entered into a factoring agreement with a bank which expires February 28, 2015. The lending agreement is allocated between separate Canadian and U.S. facilities. The bank factors the invoices at a 90% advance rate and deposits the funds into the Company’s operating account. The bank charges interest on purchased receivables at an annualized rate of LIBOR plus 4.75% on U.S. invoices and Canadian Dealer Offered Rate (“CDOR”) plus 5.3% on Canadian invoices, for the duration the invoice remains financed. In addition to interest charges, the agreement calls for a facility renewal fee of 0.50% charged annually.

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Notes to Condensed Consolidated Financial Statements
September 30, 2013
(Unaudited)

D — Obligation under Factoring Agreement – (continued)

On April 14, 2013, our $30 million factoring agreement with the bank was amended to $40 million to support the continued growth of the Company. In addition to the increased facility size, the amendment included changes to the interest rates charged on the purchased receivables, among other changes to the original agreement. The interest rates charged on purchased receivables was reduced to an annualized rate of LIBOR plus 4.00% (4.25% at September 30, 2013) on U.S. invoices and Canadian Dealer Offered Rate (“CDOR”) plus 4.55% (5.83% at September 30, 2013) on Canadian invoices, for the duration the invoice remains financed.

On August 19, 2013, the factoring agreement with the bank was amended to $50 million to support the continued growth of the Company. The obligation under the factoring agreement was $45 million and $27 million at September 30, 2013 and December 31, 2012, respectively.

The collateral for the US portion of the factoring agreements consists of a senior secured interest in all assets of TIR-US. The collateral for the Canadian portion of the factoring agreements consists of a senior secured interest in the accounts receivables of Foley and TIR-Canada.

E — Debt

On March 12, 2009, the Company entered into a loan agreement with various lenders for Senior Subordinated Notes (“Notes I”) in the aggregate sum of $17 million due March 12, 2014. The Notes I bear interest at 14% annually, and the Company is only required to make monthly interest payments until the Notes I mature in 2014. On July 8, 2010, the Company entered into an additional loan agreement with the same group of lenders for a second set of Senior Subordinated Notes (“Notes II”) in the aggregate sum of $2.8 million due March 12, 2014. The Notes II bear interest at 17.5% annually, and the Company is only required to make monthly interest payment until the Notes II mature in 2014. The Notes I and Notes II are secured by substantially all of the assets of the Company.

The Company is subject to certain financial covenants detailed in Notes I and Notes II agreements. These include a Net Funded Leverage Ratio, a Fixed Charges Ratio, a minimum EBITDA, a maximum Subordinated debt to EBITDA ratio (the “Net Subordinated Debt Leverage Ratio”) and a maximum annual capital expenditure amount. The Company violated the maximum annual capital expenditure covenant during 2012, but obtained a waiver for this violation. The provisions of all other financial covenants were met by the Company during 2012 and through September 30, 2013.

The Company executed an Asset Purchase Agreement with a new employee on September 4, 2012 totaling $250 thousand (see Note C). The Asset Purchase Agreement specifies four payments of $63 thousand to be paid quarterly beginning December 1, 2012.

Notes payable consisted of the following at September 30, 2013 and December 31, 2012:


	September 30, 2013		December 31, 2012
	(in thousands)
Senior subordinated notes I and II, net of debt discount of $141 thousand and $520 thousand at September 30, 2013 and December 31, 2012, respectively	$	19,615	$	19,236
Asset purchase agreement		—		188
Notes payable		19,615		19,424
Less: current maturities		—		(188	)
Notes payable, less current maturities	$	19,615	$	19,236

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Notes to Condensed Consolidated Financial Statements
September 30, 2013
(Unaudited)

E — Debt – (continued)


	(in thousands)
Long-term debt maturities are as follows at September 30:
2013	$	—
2014		—
2015		19,615
	$	19,615

The Company issued warrants in connection with the Notes I and Notes II, which have been treated as a discount on the debt (see Note F). Accretion expense is being recognized over the life of the loan using the effective interest method. The Company recognized accretion expense of $379 thousand and $129 thousand for the nine-months ended September 30, 2013 and 2012, respectively, which is included in interest expense in the condensed consolidated statements of comprehensive income.

On October 11, 2013 the Company signed the Seventh Amendment to the loan agreement extending the debt maturity of Notes I and Notes II from March 14, 2014 to June 1, 2015. In addition to the extended maturity, the amendment includes an increase in interest rate on the Notes I from 14.0% to 16.0% effective March 14, 2014 and an increase in interest rate on the Notes II from 17.5% to 19.5% effective March 14, 2014. The amendment also provides the lenders the ability to increase the borrowing rates before the March 14, 2014 date should certain notifications be given to the Company.

F — Warrants

In connection with the Senior Subordinated Notes (see Note E) on March 12, 2009, the Company issued warrants to the lenders. The warrants grant the lenders the right to acquire 23.75 shares of common stock of the Company at $0.01 per share. The warrants expire ten years from the date of issuance. The fair value of the warrants was $822 thousand and was determined using an EBITDA multiple pricing model. The majority shareholder contributed 23.75 shares of stock for the Company to hold in treasury in the event of the exercise of the warrants.

In connection with the Senior Subordinated Notes II (see Note E), on July 8, 2010, the Company issued warrants to the lenders. The warrants granted the lenders the right to acquire 2.21 shares of common stock of the Company at $0.01 per share. The warrants expire ten years from the date of issuance. The fair value of the warrants was $155 thousand and was determined using an EBITDA multiple pricing model. The Company added 2.21 shares of stock to hold in treasury in the event of the exercise of the warrants.

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Tulsa Inspection Resources, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements
September 30, 2013
(Unaudited)

G — Concentration of Credit Risk

The Company operates in both the US and Canada in a single line of business as the Company’s customers operate oil and gas pipelines and related facilities. Three of the Company’s customers accounted for approximately 52% and 45% of inspection revenue for the nine-months ended September 30, 2013 and September 30, 2012, respectively. Two customers accounted for approximately 47% and 24% of the Company’s accounts receivable balance at September 30, 2013 and December 31, 2012, respectively.

H — Income Taxes

Significant components of the income tax provision (benefit) are as follows at September 30, 2013 and September 30, 2012:


	September 30, 2013			September 30, 2012
	(in thousands)
Current provision:
Federal	$	1,629		$	128
State		820			101
Canadian		125			158
Total current provision		2,574			387
Deferred provision:
Federal		(63	)		667
State		(17	)		150
Canadian		(144	)		(64	)
Total deferred provision (benefit)		(224	)		753
Income tax provision	$	2,350		$	1,140

The following table summarizes the differences between the U.S. federal rate and the Company’s effective tax rate for financial statement purposes for the nine months ended:


	September 30, 2013			September 30, 2012
Statutory tax rate		34	%		34	%
State income taxes, net of U.S. federal tax benefits		10	%		5	%
Tax credits and permanent differences		(2	%)		2	%
Other, including Canada income taxes		—			—
Company’s effective tax rate		42	%		41	%

I — Share Based Compensation

On January 1, 2011, the Company executed the Stock Option Plan to allow certain share-based compensation to be issued to employees, non-employee directors and contractors. The total recognized compensation expense related to the non-qualified stock options issued was $108 thousand during the nine months ended September 30, 2013 and $95 thousand during the

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Tulsa Inspection Resources, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements
September 30, 2013
(Unaudited)

I — Share Based Compensation – (continued)

nine months ended September 30, 2012. The Company recognized tax benefits of $42 thousand associated with this expense during the nine-months ended September 30, 2013.

Option grant exercise and forfeiture activities during the periods were as follows:


	September 30, 2013		December 31, 2012
Outstanding at January 1		7.0		7.0
Granted		—		—
Exercised		—		—
Forfeited or expired		—		—
Outstanding at end of period		7.0		7.0

As of September 30, 2013, $45 thousand of total unrecognized compensation costs related to share options is expected to be recognized over the next year. The weighted-average grant-date fair value of the options granted during 2011 was $371 thousand. There were no exercise or forfeitures of options by employees during the periods. The Company utilizes the Black-Scholes option pricing model to value to non-qualified options issued.

J — Commitments and Contingencies

The Company has employment agreements with certain of its executive officers and other management personnel. The executive employment agreements are effective for a term of two to three years from the commencement date, after which time they will continue on an “at-will” basis. These agreements provide for minimum annual compensation, adjusted for annual increases as authorized by the Board of Directors, as well as eligibility to participate in any incentive stock plans adopted by the Company. Certain agreements provide for severance payments in the event of specified termination of employment. As of September 30, 2013, the aggregate commitment for future compensation and severance was 2.0 million.

During September 2013, the Company received resignations from two senior managers at Foley, who were significant contributors to the business growth and operations of Foley and TIR-Canada. The Company is in the process of replacing these senior managers and expects there to be a decline in the business volumes of these subsidiaries during the management transition, but does not expect an impairment to the Company’s assets. In addition, the Company received a demand letter from one of the managers alleging a breach of employment contract which, if substantiated, would entitle the manager to a severance payment of approximately $416 thousand. The Company currently disputes this claim and, as such, has not accrued for the associated severance costs.

K — Related Party Transaction

The Company has a management agreement with one of the lenders. The Company pays the lender $38 thousand per quarter for management and advisory services. The Company recognized $113 thousand of expense in the nine-months ending September 30, 2013 and $113 thousand in the nine-months ended September 30, 2012 related to this agreement.

The Company also has a management agreement with the majority shareholder. Under the terms of the agreement, no payments were made to the majority shareholder until the payoff of a certain amortizing bank note held by the Company. The Company paid the bank note off on February 29, 2012 and thereafter began making payments to the majority shareholder as outlined

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Tulsa Inspection Resources, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements
September 30, 2013
(Unaudited)

K — Related Party Transaction – (continued)

in the agreement. The Company recognized $113 thousand and $75 thousand of expense under this agreement during the nine-months ending September 30, 2013 and September 30, 2012, respectively.

During 2012, Foley and TIR-Canada began doing business with Contract Pro, a nonaffiliated Canadian company owned by two Foley employees. Contract Pro offers employment services to specific individuals that do not want to provide services as an independent contractor to Foley or TIR-Canada. Foley and TIR-Canada invoices customers for the services of the Contract Pro employees and makes the associated payments to Contract Pro, while keeping a portion of the proceeds. In addition, Contract Pro reimburses Foley for certain services as the company shares the Foley offices. The payments, net of Contract Pro reimbursements, made by Foley and TIR-Canada to Contract Pro totaled 1.0 million and $990 thousand during the nine-months ended September 30, 2013 and September 30, 2012, respectively.

L — Subsequent Events

On October 16, 2013, certain members of management executed cashless exercises of two thirds of their vested options, after which the issued shares were subsequently sold to CEP-TIR. The options were exercised net of employee taxes owed of $377 thousand, which the company paid on the employees behalf, and recorded the purchase as treasury shares.

Management has evaluated subsequent events through October 30, 2013, the date the financial statements were available to be issued. No subsequent events were identified requiring additional recognition or disclosure in the accompanying condensed consolidated financial statements other than the option exercise discussed above and the Senior Subordinated Notes amendment disclosed in Note E.

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Members
Cypress Energy Partners, L.P.

We have audited the accompanying balance sheet of Cypress Energy Partners, L.P. (the “Partnership”), as of September 19, 2013 (date of inception). This financial statement is the responsibility of the Partnership’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. We were not engaged to perform an audit of the Partnership’s internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, and evaluating the overall balance sheet presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the balance sheet referred to above present fairly, in all material respects, the financial position of the Partnership at September 19, 2013 (date of inception), in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Tulsa, Oklahoma
September 19, 2013

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Cypress Energy Partners, L.P.

Balance Sheet
as of September 19, 2013 (Inception)


	September 19, 2013 (date of inception)
	(in thousands)
Assets	$	—
Liabilities
Partners’ Capital:
Limited Partners	$	1
General Partner		—
Less: Contribution Receivable from Partners		(1	)
Total Partners’ Capital		—
Total Liabilities and Partners’ Capital	$	—

See accompanying notes.

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Cypress Energy Partners, L.P.

Notes to the Balance Sheet
as of September 19, 2013 (Inception)

1. Nature of Operations

Cypress Energy Partners, L.P. (the “Partnership”) is a Delaware limited partnership formed in September 2013.

In September 19, 2013, Cypress Energy Holdings II, LLC, a Delaware limited liability company (the “Limited Partner”), agreed to contribute $1 thousand to the Partnership in exchange for a 100% limited partner interest. The agreement to contribute has been recorded as a contribution receivable and is reflected in the accompanying balance sheet as a reduction to partners’ capital.

There have been no other transactions involving the Partnership as of September 19, 2013.

The Partnership, pursuant to an initial public offering, intends to sell common units representing limited partnership interests in the Partnership. The Partnership will issue common units and subordinated units to the Limited Partner.

2. Basis of Presentation

This balance sheet has been prepared in accordance with accounting principles generally accepted in the United States. Since the Partnership has had no activity since its inception, separate statements of income, changes in partners’ equity and cash flows have not been presented.

3. Subsequent Events

The Partnership has evaluated events and transactions that occurred subsequent to September 19, 2013 up until the date these financial statements were available to be issued.

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Appendix A

FORM OF

FIRST AMENDED AND RESTATED

AGREEMENT OF LIMITED PARTNERSHIP

OF

CYPRESS ENERGY PARTNERS, L.P.

A Delaware Limited Partnership

Dated as of

, 2013

[To be filed by amendment]

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Appendix B

Glossary of Terms

The terms defined in this section are used throughout this prospectus:

“Above ground marker.” A marker placed in the ground to identify the location where a pipeline requires maintenance as communicated by an inspection pig.

“Class II injection wells.” Wells approved by the EPA for disposal of the fluids associated with the production of oil and natural gas.

“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 proppants, 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.

“Injection intervals.” The part of the injection zone in which the well is screened or in which the waste is otherwise directly emplaced.

“Natural gas liquids (NGLs).” 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.

“Smart pig.” An in-line inspection device pushed through a pipeline to inspect and test for anomalies.

“Staking.” The process of marking the location where pipeline maintenance will occur.

“Water decline curve.” A mathematical plot of the ratio of water to hydrocarbons produced in natural gas wells.

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[GRAPHIC MISSING]

Cypress Energy Partners, L.P.

Common units

Representing limited partner interests

PRELIMINARY PROSPECTUS

RAYMOND JAMES

BAIRD

STIFEL

, 2013

Through and including , 2013 (the 25^th day after the date of this prospectus), federal securities laws may require all dealers that effect transactions in these securities, whether or not participating in this offering, to deliver a prospectus. This requirement is in addition to a dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to an unsold allotment or subscription.

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Part II

Information Not Required in the Prospectus

Item 13. Other expenses of issuance and distribution

Set forth below are the expenses (other than underwriting discounts and commissions) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the Securities and Exchange Commission registration fee, the FINRA filing fee and the NYSE filing fee, the amounts set forth below are estimates.


SEC registration fee	$	11,664.45
FINRA filing fee		11,750
NYSE listing fee		*
Advisory fee		*
Printing and engraving expenses		*
Fees and expenses of legal counsel		*
Accounting fees and expenses		*
Transfer agent and registrar fees		*
Miscellaneous		*
Total	$	*

To be filed by amendment.

Item 14. Indemnification of directors and officers

Cypress Energy Partners, L.P.

Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other persons from and against any and all claims and demands whatsoever. The section of the prospectus entitled “The Partnership Agreement — Indemnification” discloses that we will generally indemnify officers, directors and affiliates of the general partner to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by this reference.

The underwriting agreement to be entered into in connection with the sale of the securities offered pursuant to this registration statement, the form of which will be filed as an exhibit to this registration statement, provides for indemnification of Cypress Energy Partners, L.P. and our general partner, their officers and directors, and any person who controls our general partner, including indemnification for liabilities under the Securities Act.

Cypress Energy Partners, LLC

Subject to any terms, conditions or restrictions set forth in the limited liability company agreement, Section 18-108 of the Delaware Limited Liability Company Act empowers a Delaware limited liability company to indemnify and hold harmless any member or manager or other person from and against any and all claims and demands whatsoever.

Under the amended and restated limited liability agreement of our general partner, in most circumstances, our general partner will indemnify the following persons, to the fullest extent permitted by law, from and against any and all losses, claims, damages, liabilities (joint or several), expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings (whether civil, criminal, administrative or investigative):

•

any person who is or was an affiliate of our general partner (other than us and our subsidiaries);

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•

any person who is or was a member, partner, officer, director, employee, agent or trustee of our general partner or any affiliate of our general partner;

•

any person who is or was serving at the request of our general partner or any affiliate of our general partner as an officer, director, employee, member, partner, agent, fiduciary or trustee of another person; and

•

any person designated by our general partner.

Our general partner will purchase insurance covering its officers and directors against liabilities asserted and expenses incurred in connection with their activities as officers and directors of our general partner or any of its direct or indirect subsidiaries.

Item 16. Exhibits

The following documents are filed as exhibits to this registration statement:


Exhibit number		Description
1.1*		Form of Underwriting Agreement
3.1**		Certificate of Limited Partnership of Cypress Energy Partners, L.P.
3.2*		Form of First Amended and Restated Agreement of Limited Partnership of Cypress Energy Partners, L.P. (included as Appendix A to the Prospectus)
5.1*		Form of opinion of Latham & Watkins LLP as to the legality of the securities being registered
8.1*		Form of opinion of Latham & Watkins LLP relating to tax matters
10.1*		Account Purchase Agreement
10.2*		2009 and 2010 Loan Agreements (Mezzanine Facilities)
10.3*		Form of Contribution, Conveyance and Assumption Agreement
10.4*		Form of Cypress Energy Partners, L.P. 2013 Long-Term Incentive Plan
10.5*		Form of Omnibus Agreement
21.1*		List of Subsidiaries of Cypress Energy Partners, L.P.
23.1		Consent of Ernst & Young LLP
23.2		Consent of Ernst & Young LLP
23.3		Consent of Grant Thornton LLP
23.4*		Consent of Latham & Watkins LLP (contained in Exhibit 5.1)
23.5*		Consent of Latham & Watkins LLP (contained in Exhibit 8.1)
23.6**		Consent of Prospective Director (John T. McNabb II)
23.7**		Consent of Prospective Director (Phil Gisi)
23.8**		Consent of Prospective Director (Charles C. Stephenson, Jr.)
24.1*		Powers of Attorney (to be included on the signature page)

To be filed by amendment.

Previously filed.

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Item 17. Undertakings

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that,

(i)

For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(ii)

For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

The undersigned registrant undertakes to send to each common unitholder, at least on an annual basis, a detailed statement of any transactions with Cypress Holdings or its subsidiaries (including the registrant’s general partner) and of fees, commissions, compensation and other benefits paid, or accrued to Cypress Holdings or its subsidiaries (including the registrant’s general partner) for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

The registrant undertakes to provide to the common unitholders the financial statements required by Form 10-K for the first full fiscal year of operations of the company.

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Signatures

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Tulsa, State of Oklahoma, on November 19, 2013.

Cypress Energy Partners, L.P.

By:

Cypress Energy Partners GP, LLC, its General Partner

By:

/s/ G. Les Austin

G. Les Austin
Vice President and Chief Financial Officer

Pursuant to the requirements of the Securities Act of 1933, as amended this Registration Statement has been signed by the following persons in the capacities and the dates indicated.


Signature	Title	Date

/s/ Peter C. Boylan III Peter C. Boylan III	Chairman of the Board of Directors, Chief Executive Officer and President (Principal Executive Officer) and Director	November 19, 2013
/s/ G. Les Austin G. Les Austin	Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)	November 19, 2013

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Exhibit Index


Exhibit number		Description
1.1*		Form of Underwriting Agreement
3.1**		Certificate of Limited Partnership of Cypress Energy Partners, L.P.
3.2*		Form of First Amended and Restated Agreement of Limited Partnership of Cypress Energy Partners, L.P. (included as Appendix A to the Prospectus)
5.1*		Form of opinion of Latham & Watkins LLP as to the legality of the securities being registered
8.1*		Form of opinion of Latham & Watkins LLP relating to tax matters
10.1*		Account Purchase Agreement
10.2*		2009 and 2010 Loan Agreements (Mezzanine Facilities)
10.3*		Form of Contribution, Conveyance and Assumption Agreement
10.4*		Form of Cypress Energy Partners, L.P. 2013 Long-Term Incentive Plan
10.5*		Form of Omnibus Agreement
21.1*		List of Subsidiaries of Cypress Energy Partners, L.P.
23.1		Consent of Ernst & Young LLP
23.2		Consent of Ernst & Young LLP
23.3		Consent of Grant Thornton LLP
23.4*		Consent of Latham & Watkins LLP (contained in Exhibit 5.1)
23.5*		Consent of Latham & Watkins LLP (contained in Exhibit 8.1)
23.6**		Consent of Prospective Director (John T. McNabb II)
23.7**		Consent of Prospective Director (Phil Gisi)
23.8**		Consent of Prospective Director (Charles C. Stephenson, Jr.)
24.1*		Powers of Attorney (to be included on the signature page)

To be filed by amendment.

Previously filed.

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Registration No. 333-192328

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

Amendment No. 1toForm S-1 REGISTRATION STATEMENT

Cypress Energy Partners, L.P.

5727 S. Lewis Avenue, Suite 500 Tulsa, Oklahoma 74105 (918) 748-3900

G. Les Austin Vice President and Chief Financial Officer Cypress Energy Partners, L.P. 5727 S. Lewis Avenue, Suite 500 Tulsa, Oklahoma 74105 (918) 748-3900

Subject to completion, dated November 19, 2013

PRELIMINARY PROSPECTUS

Common Units

Representing Limited Partner Interests

Cypress Energy Partners, L.P.

TABLE OF CONTENTS

Industry and Market Data

Commonly Used Defined Terms

PROSPECTUS SUMMARY

Cypress Energy Partners, L.P.

Overview

Business Strategies

Competitive Strengths

Our Assets and Operations

Our Relationship with Cypress Holdings

Risk Factors

The Restructuring Transactions

Organizational Structure After the Restructuring Transactions

Management of Cypress Energy Partners, L.P.

Principal Executive Offices and Internet Address

Summary of Conflicts of Interest and Duties

Our Emerging Growth Company Status

The Offering

Summary Historical and Pro Forma Financial Data and Operating Data

RISK FACTORS

Risks Related to Our Business

Risks Inherent in an Investment in Us

Tax Risks

USE OF PROCEEDS

CAPITALIZATION

DILUTION

CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

General

Rationale for Our Cash Distribution Policy

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy

Our Ability to Grow is Dependent on Our Ability to Access External Expansion Capital

Our Minimum Quarterly Distribution

Unaudited Pro Forma Distributable Cash Flow for the Year Ended December 31, 2012, and the Twelve Months Ended September 30, 2013

Cypress Energy Partners, L.P. Pro Forma Operating Data

Cypress Energy Partners, L.P. Unaudited Pro Forma Distributable Cash Flow

Estimated Distributable Cash Flow for the Year Ending December 31, 2014

Cypress Energy Partners, L.P. Estimated Distributable Cash Flow

Assumptions and Considerations

Water and Environmental Services Revenue

Pipeline Inspection and Integrity Services Revenue

Cost of Saltwater Disposal Sales

Cost of Inspection Services

Depreciation and Amortization

General and Administrative

Interest Expense

Capital Expenditures

Financing

Regulatory, Industry, Environmental and Economic Factors

PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS

Distributions of Available Cash

General

Definition of Available Cash

Intent to Distribute the Minimum Quarterly Distribution

General Partner Interest and Incentive Distribution Rights

Operating Surplus and Capital Surplus

General

Operating Surplus

Capital Surplus

Characterization of Cash Distributions

Capital Expenditures

Subordinated Units and Subordination Period

General

Determination of Subordination Period

Early Termination of the Subordination Period

Expiration upon Removal of the General Partner

Expiration of the Subordination Period

Adjusted Operating Surplus

Distributions of Available Cash From Operating Surplus During the Subordination Period

Distributions of Available Cash From Operating Surplus After the Subordination Period

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

Amendment No. 1
to
Form S-1
REGISTRATION STATEMENT

5727 S. Lewis Avenue, Suite 500
Tulsa, Oklahoma 74105
(918) 748-3900

G. Les Austin
Vice President and Chief Financial Officer
Cypress Energy Partners, L.P.
5727 S. Lewis Avenue, Suite 500
Tulsa, Oklahoma 74105
(918) 748-3900

Unaudited Pro Forma Distributable Cash Flow for the Year Ended December 31, 2012, and
the Twelve Months Ended September 30, 2013

Cypress Energy Partners, L.P.
Pro Forma Operating Data

Cypress Energy Partners, L.P.
Unaudited Pro Forma Distributable Cash Flow

Cypress Energy Partners, L.P.
Estimated Distributable Cash Flow

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Results Presented and Factors Affecting the Comparability of the Historical Financial
Results of the CEP Successor with the SBG Predecessor and of our Future Results

CEP Successor Nine Months Ended September 30, 2013 Compared to
SBG Predecessor Nine Months Ended September 30, 2012

SBG Predecessor’s Year Ended December 31, 2012 Compared to
SBG Predecessor’s Period from June 1, 2011 (Inception) to December 31, 2011

U.S. Crude Oil And Marketed Natural Gas Production
In Lower 48 States Excluding Gulf of Mexico