UNITED STATES SECURITIES AND EXCHANGE COMMISSION   

WASHINGTON, D.C. 20549

 

FORM 10-K

 

(MARK ONE)

 

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

 

For the fiscal year ended December 31, 2019

 

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

 

FOR THE TRANSITION PERIOD FROM________ TO_______

 

Commission File No. 001-36260

 

CYPRESS ENVIRONMENTAL PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

 

Delaware		61-1721523
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

 

5727 South Lewis Avenue, Suite 300
Tulsa, Oklahoma		74105
(Address of principal executive offices)		(Zip Code)

 

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

 

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

 

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Units	CELP	New York Stock Exchange

 

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

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐   No ☒

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒   No ☐

 

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

 

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

 

Large accelerated filer ☐

Accelerated filer ☐

Non-accelerated filer ☐

Smaller reporting company ☒

Emerging growth company ☐

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

 

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

 

The aggregate market value of the registrant’s Common Units Representing Limited Partner Interests held by non-affiliates computed by reference to the price at which the limited partner units were last sold as of June 30, 2019 was $31,438,258.

 

As of March 10, 2020, the registrant had 12,177,902 common units outstanding.

 

DOCUMENTS INCORPORATED BY REFERENCE: NONE

 

 

 

Table of Contents

		Page
PART I
Item 1.	Business	7
Item 1A.	Risk Factors	19
Item 1B.	Unresolved Staff Comments	48
Item 2.	Properties	49
Item 3.	Legal Proceedings	49
Item 4.	Mine Safety Disclosures	50
PART II
Item 5.	Market for Our Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	50
Item 6.	Selected Financial Data	53
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	58
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	81
Item 8.	Financial Statements and Supplementary Data	83
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	116
Item 9A.	Controls and Procedures	116
Item 9B.	Other Information	117
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	117
Item 11.	Executive Compensation	121
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	125
Item 13.	Certain Relationships, Related Transactions and Director Independence	127
Item 14.	Principal Accounting Fees and Services	131
PART IV
Item 15.	Exhibits and Financial Statement Schedules	132
Item 16.	Summary	135
	Signatures	136

 

 

GLOSSARY OF TERMS

 

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

 

“Dig site”	The location where pipeline maintenance occurs by excavating the ground above the pipeline.
“Environmental Services”	Our Water and Environmental Services business segment.
“Flowback water”	The fluid that returns to the surface during and for the weeks following the hydraulic fracturing process.
“Gun barrel”	A settling tank used for treating oil where oil and brine are separated only by gravity segregation forces.
“Hydraulic fracturing”	The process of pumping fluids, mixed with granular proppant, into a geological formation at pressures sufficient to create fractures in the hydrocarbon-bearing rock.
“Hydrotesting”	A process in which pressure vessels such as pipelines and fuel tanks can be tested for strength and leaks by filling the vessel with a liquid and pressurizing the vessel to the specified test pressure.
“In-line inspection”	An inspection technique used to assess the integrity of pipelines from inside of the pipe.
“IPO”	Our initial public offering of common units representing limited partner interests in us.
“Injection intervals”	The part of the injection zone in which the well is screened or in which the waste is otherwise directly emplaced.
“Natural gas liquids”	The combination of ethane, propane, butane, isobutene and natural gasolines that, when removed from natural gas, become liquid under various levels of higher pressure and lower temperature.
“OPEC”	The Organization of Petroleum Exporting Countries.
“Pig tracking”	The locating, mapping and monitoring of the in-line inspection pig.
“Pipeline & Process Services”	Our Pipeline & Process Services business segment.
“Pipeline Inspection”	Our Pipeline Inspection business segment.

“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 water treatment process.
“Separation tank”	A cylindrical or spherical vessel used to separate oil, gas and water from the total fluid stream produced by a well.
“Settling tank”	A non-circulating storage tank where gravitational segregation forces separate liquids from solids.
“Staking”	The process of marking the location where pipeline maintenance will occur.

 

 

NAMES OF ENTITIES

 

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

 

References to:

 

	●	“Brown” refers to Cypress Brown Integrity, LLC, a 51% owned subsidiary of CEP LLC;
	●	“CEM LLC” refers to Cypress Environmental Management, LLC, a wholly owned subsidiary of the General Partner;

	●	“CEM TIR” refers to Cypress Environmental Management – TIR, LLC, a wholly owned subsidiary of CEM LLC;

	●	“CEP LLC” refers to Cypress Environmental Partners, LLC, a wholly owned subsidiary of the Partnership;

	●	“CEP-TIR” refers to Cypress Energy Partners – TIR, LLC, a former indirect subsidiary of Holdings, and an owner of 1,346,800 common units representing 11% of our outstanding common units as of December 31, 2019, and an owner of a 36% interest in the TIR Entities prior to the sale of its interests to the Partnership effective February 1, 2015;

	●	“CF Inspection” refers to CF Inspection Management, LLC, owned 49% by TIR-PUC and consolidated under generally accepted accounting principles by TIR-PUC. CF Inspection is 51% owned, managed and controlled by Cynthia A. Field, an affiliate of Holdings and a Director of our General Partner;

●

“General Partner” refers to Cypress Environmental Partners GP, LLC, a subsidiary of Cypress Environmental GP Holdings, LLC;

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

	●	“Holdings II” refers to Cypress Energy Holdings II, LLC, the owner of 5,610,549 common units representing 46% of our outstanding common units as of March 10, 2020;

	●	“Partnership” refers to the registrant, Cypress Environmental Partners, L.P.;

	●	“TIR Entities” refer collectively to TIR LLC; TIR-Canada, TIR-NDE, TIR-PUC and CF Inspection;
	●	“TIR-NDE” refers to Tulsa Inspection Resources – Nondestructive Examination, LLC, a former wholly-owned subsidiary of CEP LLC (TIR-NDE has since been merged into TIR LLC);

 

 

	●	“TIR-Canada” refers to Tulsa Inspection Resources – Canada, ULC, a wholly owned subsidiary of TIR LLC;

	●	“TIR LLC” refers to Tulsa Inspection Resources, LLC, a wholly owned subsidiary of CEP LLC;

	●	“TIR-PUC” refers to Tulsa Inspection Resources – PUC, LLC, a subsidiary of TIR LLC that has elected to be treated as a corporation for U.S. federal income tax purposes.

 

CAUTIONARY REMARKS REGARDING FORWARD LOOKING STATEMENTS

 

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

 

PART I

 

ITEM 1.

BUSINESS

 

Overview

 

Cypress Environmental Partners, L.P. (formerly Cypress Energy Partners, L.P.) (“we”, “us”, “our”, the “Partnership”) is a Delaware limited partnership formed on September 19, 2013. Our suite of services includes inspection, testing, recycling, survey, water treatment, and other environmental services that help our customers protect people, property, infrastructure, and the environment with a focus on safety and sustainability. We work closely with our customers to help them protect the environment, property, and people. Our services also help our clients comply with increasingly complex federal and state environmental and safety rules and regulations. The substantial majority of our environmental services are required services under various federal and state laws. Trading of our common units began January 15, 2014 on the New York Stock Exchange under the symbol “CELP”.

 

Our business is organized into three reportable segments: (1) Pipeline Inspection Services (“Pipeline Inspection”), comprising the TIR Entities’ operations, (2) Pipeline & Process Services (“Pipeline & Process Services”), made up of Brown’s operations and (3) Water and Environmental Services (“Environmental Services”), constituting water treatment activities in our water treatment entities.  Other potential lines of business outlined in U.S. Treasury Regulations and our Internal Revenue Service (“IRS”) private letter ruling (“PLR”) would allow us to further diversify our business lines and activities.

 

The Pipeline Inspection segment generates revenue primarily by providing essential environmental services including inspection and integrity services on a variety of infrastructure assets including midstream pipelines, gathering systems, and distribution systems. Services include nondestructive examination, in-line inspection support, pig tracking, survey, data gathering, and supervision of third-party contractors. Our results in this segment are driven primarily by the number of inspectors that perform services for our customers and the fees that we charge for those services, which depend on the type, skills, technology, equipment, and number of inspectors used on a particular project, the nature of the project, and the duration of the project. The number of inspectors engaged on projects is driven by the type of project, prevailing market rates, the age and condition of customers’ assets including pipelines, gas plants, compression stations, storage facilities, and gathering and distribution systems including the legal and regulatory requirements relating to the inspection and maintenance of those assets. We also bill our customers for per diem charges, mileage, and other reimbursement items. Revenue and costs in this segment may be subject to seasonal variations and interim activity may not be indicative of yearly activity, considering that many of our customers develop yearly operating budgets and enter into contracts with us during the winter season for work to be performed during the remainder of the year. Additionally, inspection work throughout the United States during the winter months (especially in the northern states) may be hampered or delayed due to inclement weather.

 

The Pipeline & Process Services segment (formerly our Integrity Services segment) generates revenue primarily by providing essential environmental services including hydrotesting, chemical cleaning, water transfer and recycling, pumping, pigging, flushing, filling, dehydration, caliper runs, ILI tool run support, nitrogen purging, and drying services. We also provide customers with test documentation and records retention services. We generally charge our customers in this segment on a fixed-bid basis, depending on the size and length of the pipeline being tested, the complexity of services provided, and the utilization of our work force and equipment. Our results in this segment are driven primarily by the number of field personnel that perform services for our customers and the fees that we charge for those services, which depend on the type and number of field personnel used on a particular project, the type of equipment used and the fees charged for the utilization of that equipment, and the nature and duration of the project.

 

The Environmental Services segment owns and operates nine (9) water treatment facilities with ten (10) EPA Class II injection wells in the Bakken shale region of the Williston Basin in North Dakota. These water treatment facilities are connected to twelve (12) pipeline gathering systems, including two (2) that we developed and own. We specialize in the treatment, recovery, separation, and disposal of waste byproducts generated during the lifecycle of an oil and natural gas well to protect the environment and our drinking water. All of the facilities utilize specialized equipment and remote monitoring to minimize the facilities’ downtime and increase the facilities’ efficiency for peak utilization. We also sell recovered oil, receive fees for pipeline transportation of water, and receive fees from a partially-owned facility for management and staffing services.

 

 

Our Relationship with Cypress Energy Holdings, LLC

 

All of the equity interests in our general partner are indirectly owned by Holdings and its affiliates. Holdings is owned by Charles C. Stephenson, Jr.; entities related to Mr. Stephenson’s family; Cynthia A. Field; a company controlled by our Chairman, Chief Executive Officer and President, Peter C. Boylan III; Henry Cornell; and a company controlled by Mr. Cornell.  Holdings’ owners bring substantial industry relationships and specialized, value-creation capabilities that we believe 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 also the retired Chairman of Premier Natural Resources, a private oil and natural gas exploration and production company that he co-founded.  Mr. Boylan has extensive executive management experience with public and private companies and also has extensive public company directorship experience. As the owners of our general partner and the direct or indirect owners of 64% of our outstanding common units and all of our outstanding preferred units, Holdings and its affiliates have a strong alignment of interests with our noncontrolling unitholders.

 

Business Strategies

 

Our principal business objective is to build a diversified partnership providing essential environmental services that will allow us, over time, to incrementally increase the quarterly cash distributions that we pay to our unitholders. We pursue the following business strategies:

 

	●	Pipeline Inspection.  We intend to continue to position ourselves as a trusted provider of high-quality essential inspection services. Over the last few years, new laws have been enacted in the U.S. that, in the future, will require operators to undertake more frequent and more extensive inspections of their pipeline assets. These requirements are not tied to the current state of the oil and gas industry as a whole. Additionally, a significant portion of the pipeline infrastructure in North America was installed decades ago and is therefore more susceptible to degradation requiring more frequent inspections. We believe that increasingly stringent U.S. federal and state laws and regulations and aging pipeline infrastructures will result in increased need for inspection and integrity services and higher demand for independent, third-party inspectors capable of navigating these complicated requirements. Most of our clients are large public companies that have long lead time projects that require our services regardless of the state of the current economy. Our clients also require ongoing maintenance and integrity work on their aging pipelines. Our business is not immune to economic changes in the energy industry; however, we believe that we can continue to grow organically by acquiring new customers and additional work from existing customers. We continue to grow our business development team to pursue these and other opportunities.
	●	Pipeline & Process Services.  We experienced significant improvements in our utilization rates in this segment in 2019. Improvements were due in part to increasing demand and in part to improved business development efforts. During 2018, we opened a new office in Odessa, Texas, to better serve the growing Permian basin market.  In addition, we added several industry veterans to our management team in order to further enhance our image and grow the segment. In early 2019, we opened a new location in the Houston market to help us take advantage of the growing work in the industry.  We plan to continue to focus on the potential synergies that may develop between this segment and our other business segments. We continue to enjoy an excellent reputation in the industry and continue to bid on a substantial amount of new work.

	●	Environmental Services.  We intend to maintain our position as a high-quality operator of water treatment facilities. We continue to look for pipeline opportunities with exploration and production (“E&P”) companies that will secure water for our water treatment facilities. We remain an approved vendor for many prestigious E&P companies that demand very high standards from their vendors. Although the oil and gas industry can be cyclical in nature, our current business strategy is to derive a significant portion of our volume and revenue from existing wells. We intend to capitalize on the continued demand for removal, treatment, storage and disposal of flowback and produced water by positioning ourselves as a trusted, dependable provider of safe, high-quality water and environmental services to our customers.

 

	●	Optimize existing water treatment assets. The average age of our water treatment facilities was 7.3 years at the end of 2019.  We estimate that we utilized approximately 38% of the aggregate annual capacity (35.3 million barrels per year) of these facilities in 2019, evidencing capacity for growth without additional capital expenditures. We are seeking to increase the utilization of our existing water treatment facilities by attracting new volumes from existing customers and by developing new customer relationships, including pipelines. In 2012, only one pipeline was directly connected to our water treatment facilities. We currently have ten pipelines connected to four of our water treatment facilities.  Because many of the costs of constructing and operating a water treatment facility are either upfront capital costs or fixed costs, we expect that increased utilization of our existing water treatment facilities would lead to increased operating cash flow in the Environmental Services segment.
	●	Increase the number of pipelines connected to our water treatment 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 the trucking of saltwater, we anticipate that producers may increasingly prefer to utilize pipeline systems to transport their saltwater directly to water treatment facilities. We continue to focus on increasing pipeline water delivered to our facilities. As a percentage of total water volume, pipeline water was 41%, 45% and 46% in 2019, 2018, and 2017, respectively. We will continue to focus on potential pipeline opportunities.
	●	Leverage customer relationships in 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 business segments. Many customers of the Environmental Services segment also own gathering systems, storage facilities, gas plants, compression stations, and other pipeline assets to which we can offer pipeline inspection and integrity services. In addition, we intend to enhance our relationships with our customers in the Pipeline Inspection segment by broadening the services we provide to our customers, including expanding our ultrasonic nondestructive examination services. By cross-selling our service offerings and adding complementary service offerings, we believe that we can further integrate into our customers’ operations and increase our profitability and distributable cash flow.
	●	Pursue strategic, accretive acquisitions.  In 2018, our sponsor, Holdings completed two acquisitions to further broaden our collective suite of environmental services. Importantly, these acquisitions also provided entry into the municipal water industry, whereby we can offer our traditional inspection services, including corrosion and nondestructive testing services, as well as in-line inspection (“ILI”). We remain excited about entering the ILI industry with next generation 5G ultra high-resolution magnetic flux leakage ILI technology called EcoVision UHD, capable of helping pipeline owners and operators better manage the integrity of their assets in both the municipal water and energy industries.

 

 

Our Business Segments

Our business operates in three reportable segments: (1) Pipeline Inspection Services (“Pipeline Inspection”), comprising the TIR Entities’ operations, (2) Pipeline & Process Services, made up of Brown’s operations, and (3) Water and Environmental Services (“Environmental Services”), consisting of water treatment activities. U.S. Treasury Regulations and our IRS private letter ruling (“PLR”) allows for expansion into other lines of business. Our long-term goals continue to be diversifying the Partnership into other attractive lines of business and expanding our customer base within our existing lines of business.

 

Pipeline Inspection  

 

Overview. The Pipeline Inspection segment is a leading provider of independent inspection, integrity, and non-destructive examination services to energy and utility industries. We inspect and test infrastructure assets including pipelines, gathering and distribution systems, storage facilities, gas plants, refineries, petrochemical facilities, LNG facilities, compression stations, and pumping stations. Our mission is to provide quality environmental services, in a safe, professional, ethical, and cost-effective manner that can be tailored to add value for our clients throughout the life of their assets. We have also entered into a consolidated joint venture with CF Inspection, a nationally-qualified woman-owned inspection firm. CF Inspection allows us to offer various services to clients that require the services of an approved Women’s Business Enterprise (“WBE”), as CF Inspection is certified as a Women’s Business Enterprise by the Supplier Clearinghouse in California and as a National Women’s Business Enterprise by the Women’s Business Enterprise National Council. We own 49% of CF Inspection and Cynthia A. Field, an affiliate of Holdings and a Director of our General Partner, owns the remaining 51% of CF Inspection. In 2019, CF Inspection, which is part of the Pipeline Inspection segment, represented approximately 3.3% of the Pipeline Inspection segment’s consolidated revenue.

 

Operations. Oil and natural gas producers, public utility companies, and other pipeline operators are required by federal and state law and regulation to inspect their pipelines and gathering systems on a regular basis in order to protect the environment and ensure public safety. At the beginning of an engagement, our personnel meet with the customer to determine the scope of the project and determine related staffing needs. We then develop a customized, detailed staffing plan, utilizing our proprietary database of professionals. Our inspectors have significant industry experience and are certified to meet the qualification requirements of both the customer and the Pipeline and Hazardous Materials Safety Administration (“PHMSA”). As the industry continues to adopt new technology, demand has increased for inspectors with greater technical skills and computer proficiencies. Our customers require inspectors to undergo specific training prior to performing inspection work on their projects. We utilize the National Center for Construction Education and Research and Veriforce training curricula to train and evaluate employees, along with other resources. In addition to assignment-specific training, welding inspectors and coating inspectors also must meet special certification requirements.

 

The U.S. Pipeline and Hazardous Materials Safety Administration (“PHMSA”) recently finalized a rule that significantly revises certain aspects of the hazardous liquid pipeline safety regulations codified at Title 49 Code of Federal Regulations Parts 190-199. Nearly nine years in the making, the final rule is PHMSA’s response to several significant hazardous liquid pipeline accidents that have occurred in recent years, most notably the 2010 crude oil spill near Marshall, Michigan. The final rule also addresses 2011 and 2016 outstanding congressional mandates and U.S. Government Accountability Office recommendations. Effective July 1, 2020, this rule expands requirements to address risks to pipelines outside of environmentally sensitive and populated areas, requiring the performance of periodic integrity assessments and the use of leak detection systems for all regulated hazardous liquids pipelines (except for offshore gathering and regulated rural gathering lines). In addition, the rule makes changes to the integrity management requirements, including revising data integration requirements and emphasizing the use of in-line inspection technology.  The long-term increasing demand for environmental services such as pipeline inspection, integrity services, and water solutions remains strong due to our nation’s aging pipeline infrastructure, and we believe we continue to be well-positioned to capitalize on these opportunities. Our General Partner continues to remain fully aligned with our noncontrolling unitholders, as our General Partner and its affiliates collectively own 76% of our total common and preferred units.  

In recent years, many companies have been active in constructing new energy infrastructure, such as pipelines, gas plants, compression stations, and storage facilities, which has afforded us the opportunity to provide inspection services on large projects. Currently, many energy companies face challenging market conditions, including lower commodity prices, the COVID-19 pandemic, and negative investor sentiment. Most of our customers are well capitalized; however, a combination of these events could significantly reduce their spending on new projects and maintenance, which could afford us less opportunity to generate revenues and profits. We have taken incremental steps to monitor counterparty risks. 

In 2019, 2018, and 2017 we employed an average of 1,485, 1,214 and 1,145 inspectors, respectively, in the U.S. and Canada.

 

Our scope of services include the following:

 

●

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

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

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

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

 

	●	Construction inspection (third-party new construction inspection/oversight on behalf of owner);
	●	Pipeline marker replacement and installation;
	●	Depth of cover and certerline surveys;

	●	Phased Array Ultrasonic Testing, Optical Emission Spectroscopy, Positive Material Identification, and automated metal loss mapping to map and evaluate pipeline imperfections; and

●

Related data management services.

 

Pipeline & Process Services

 

Overview.  The Pipeline & Process Services segment provides hydrostatic testing and related services to the pipeline industry, including major natural gas and petroleum companies, as well as pipeline construction companies. We focus on helping our customers meet regulatory pipeline integrity requirements. Our primary emphasis is on hydrostatic testing projects on new and existing pipelines required to maintain compliance with state and federal regulations. We perform all aspects of pipeline hydrostatic testing including filling, pressure testing, and dewatering. Unique test conditions, such as ultra-high pressure tests and pneumatic or nitrogen testing, are performed on a routine basis as well. We provide services on newly-constructed and existing natural gas and crude oil pipelines.

 

We maintain a fleet of testing equipment capable of supporting requirements for hydrotesting, chemical cleaning, water transfer and recycling, pumping, pigging, flushing, filling, dehydration, caliper runs, ILI tool run support, nitrogen purging, and drying services. We also provide customers with test documentation and records retention services.

 

Operations. Oil and natural gas producers, midstream operators, public utility companies, and other pipeline operators are required by federal and state law to perform routine maintenance on their pipelines and gathering systems on a regular basis. In addition, operators and pipeline construction companies are required to integrity-test newly-constructed pipelines prior to placing the pipelines in service. In our Pipeline & Process Services segment, we contract directly with pipeline owners and with pipeline construction companies to provide testing services. We own and operate our own fill and testing equipment, including specially-designed test trailers. We use a range of fill and pressure equipment to accommodate projects of various sizes. The segment averaged 28, 23 and 20 field technicians performing the testing services in 2019, 2018, and 2017, respectively.

 

Environmental Services

 

Overview. The Environmental Services segment owns and operates nine (9) water treatment facilities with ten (10) EPA Class II injection wells in the Bakken shale region of the Williston Basin in North Dakota. These water treatment facilities are connected to twelve (12) pipeline gathering systems, including two (2) that we developed and own. We specialize in the treatment, recovery, separation, and disposal of waste byproducts generated during the lifecycle of an oil and natural gas well to protect the environment and our drinking water. During 2019, 93% of our volumes were produced water and 41% of our volumes were delivered via  pipeline. Of the volumes from Arnegard, a 25% owned company, 96% of the volumes were produced water and 69% were delivered via pipeline in 2019. We currently serve approximately 86 customers. All of our facilities utilize specialized equipment and remote monitoring to minimize the facilities’ downtime and increase the facilities’ efficiency for peak utilization. We also sell recovered oil, receive fees for pipeline transportation of water, and receive fees from Arnegard for management and staffing services.

 

 

Operations. The Environmental Services segment currently generates revenue by providing the following services:

 

	●	Flowback water management. We dispose of flowback water produced from hydraulic fracturing operations during the completion of oil and natural gas wells. Fracturing fluids, including a significant amount of water and proppant, are injected into the well during the completion process and are partially recovered as flowback water. E&P companies use water in various formations in order to get higher production yields when the wells are put into production. When it is removed, this flowback water contains sand, salt, chemicals, and residual oil. The oil and natural gas producer typically either transports the flowback water to one of our facilities via pipeline or by truck or contracts with a trucking company for transport. Once the water is received at the water treatment facility, we treat the water through a combination of separation tanks, gun barrels, and chemical processes. The water is then injected into the water treatment well at depths of at least 5,010 feet after recovering the skim oil. We also maintain the ability to store saltwater pending injection. Similar to 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.
	●	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 an 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 at a slower rate or, in some cases, may even increase. The oil and natural gas producer separates the produced water from the production stream and either transports it to one of our water treatment facilities by truck or pipeline, or contracts with a trucking company to transport it to one of our water treatment facilities. Once we receive the water at one of our water treatment facilities, we filter and treat the water and then inject it into the water treatment well at depths of at least 5,010 feet after recovering any skim oil. We also maintain the ability to store saltwater pending injection. All of our existing facilities were constructed using completion techniques consistent with current industry practices. We periodically sample, test, and assess produced water to determine its chemistry so that we can properly treat the water with the appropriate chemicals that maximize oil separation and the life of our wells.
	●	Byproduct sales. Before we inject flowback and/or produced water into a water treatment 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. The residual oil recovery can be significant when substantial drilling and completions occur near our water treatment facilities.
	●	Management of facilities. In addition to the facilities we wholly-own, we manage an additional facility in North Dakota. Our responsibilities in managing this facility typically include operations, billing, collections, insurance, maintenance, repairs, and sales and marketing. We are compensated for the management of this facility based on a percentage of the gross revenue of the facility or a minimum monthly fee.

 

The majority of the water processed at our water treatment facilities are derived from produced water that is generated throughout the life of the oil or natural gas well. In 2019, 2018, and 2017, produced water represented 93%, 94%, and 93%, respectively, of our total barrels of disposed water. This differentiates us from many competitors that focus on flowback 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 wastewater produced over the life of the wells. 

 

Each of our facilities is open every day of the year, with some being open by appointment only. Some of our locations include onsite offices and sleeping quarters. We supplement our operations with various automated technologies to improve their efficiency and safety. We have installed 24-hour digital video monitoring and recording systems at each facility. These systems allow us to track operations and unloading activities, as well as to identify customers present 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.  Our facilities have been inspected and approved by several of our public E&P customers that have stringent approval standards and field audits performed by their Environmental, Health and Safety groups. We have permitted aggregate maximum daily disposal capacity of 96,800 barrels in the following water treatment facilities, all of which were built using completion techniques consistent with current industry practices and utilizing well depths of 5,350 feet to 6,332 feet with injection intervals beginning at least 5,010 feet beneath the surface. Our permitted capacity is much higher.

 

 

Location		County		In-service Date		Leased / Owned (3)
Tioga, ND		Williams		June 2011		Owned
Manning, ND		Dunn		December 2011		Owned
Grassy Butte, ND		McKenzie		May 2012		Leased
New Town, ND (1)		Mountrail		June 2012		Leased
Williston, ND (1)		Williams		August 2012		Owned
Stanley, ND		Mountrail		September 2012		Owned
Belfield, ND		Billings		October 2012		Leased
Watford City, ND (1), (2)		McKenzie		May 2013		Leased
Arnegard, ND (1)		McKenzie		August 2014		Leased

 

(1)		Currently receives piped water.
(2)		We own a 25.0% noncontrolling interest in this facility.
(3)		Some facilities are constructed on land that is leased under long-term arrangements.

 

Principal Customers

 

Pipeline Inspection

 

Customers of our Pipeline Inspection segment are principally owners and operators of pipelines and other infrastructure and public utility or local distribution companies in North America. In 2019, 2018, and 2017, this segment had approximately 78, 87, and 81 customers, respectively. The five largest customers in this segment generated 65%, 51%, and 53% of our segment revenue in 2019, 2018, and 2017, respectively. In 2019, 2018, and 2017, we had four, two, and three customers, respectively, that individually accounted for more than 10% of segment revenues. A significant percentage of our gross margin is generated from customers with which we have long-term relationships. In 2019, 28% of the gross margin of our Pipeline Inspection segment was generated from customers that we have served for over 10 years, and another 40% was generated from customers we have served for over five years.

 

Pipeline & Process Services

 

Pipeline & Process Services segment customers are primarily pipeline construction companies and pipeline owners. In 2019, 2018, and 2017, this segment had approximately 38, 49, and 51 customers, respectively. Our ten largest customers generated 92%, 78%, and 74% of our total segment revenue in 2019, 2018, and 2017, respectively. In 2019, 2018, and 2017, we had three, two, and two customers, respectively, that individually accounted for more than 10% of segment revenues. In 2019, the majority of our gross margin of our Pipeline & Process Services segment was generated from customers that we have served for over 5 years. 

 

Environmental Services

 

Environmental Services segment customers are oil and natural gas E&P companies, including majors and independents, trucking companies, and third-party purchasers of residual oil operating in the regions that we serve. In the years ended December 31, 2019, 2018, and 2017, this segment had approximately 86, 86, and 95 customers, respectively. Our ten largest customers generated 79%, 68%, and 65% of the Environmental Services revenue in 2019, 2018, and 2017, respectively. In 2019, 2018, and 2017, we had three, two, and one customers, respectively, that individually accounted for more than 10% of segment revenues. The majority of our gross margin of our Environmental Services segment was generated from customers that we have served for over 5 years.

 

Competition

 

Pipeline Inspection

 

The pipeline inspection business is highly competitive. Our 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 and related facilities. We believe that the principal competitive factors in our business include gaining and maintaining customer approval to service their pipelines, facilities and gathering systems, the ability to recruit and retain qualified experienced inspectors with multiple skills and nondestructive examination experience, safety record, insurance, the level of inspector training provided, reputation, dependability of services, customer service, and price.

 

 

Pipeline & Process Services

 

The pipeline and process services business is highly competitive. We believe that the principal competitive factors in our business are customer service, safety, and price. Our competition consists primarily of smaller regional integrity firms and pipeline construction companies that pipeline owners allow to test their own construction and repair work.

 

Environmental Services

 

The Environmental Services business is highly competitive with relatively low barriers of entry. Our competition consists primarily of smaller regional companies that utilize a variety of disposal methods and generally serve specific geographical markets. In addition, we face competition from other large oil field service companies that also own trucking operations and we face competition from our customers, who may have the option of using internal processing methods instead of outsourcing to us or to another third-party company. Many E&P companies also own their own water treatment facilities and water gathering systems, and therefore do not send their produced water to third parties for processing. We believe that the principal competitive differentiating factors in our businesses include gaining and maintaining customer approval of water treatment facilities, location of facilities in relation to customer activity, reputation, safety record, reliability of service, track record of environmental and regulatory compliance, customer service, insurance coverage, and price.

 

Seasonality

 

Pipeline Inspection

 

Inspection work varies depending upon the geographic location of our customers. The second, third, and beginning of the fourth quarters are historically the most active for our pipeline inspection services in the United States as our customers focus on completing projects by year-end. Business has historically been slower in the period from November through March, due to the holiday season, weather, and the budgeting cycles of our customers. We believe our presence across various regions in the U.S. helps mitigate the seasonality of our business. Our public utility operations in California and other locations with moderate climates tend to experience less seasonal volatility.

 

Pipeline & Process Services

 

Since most of the work of the Pipeline & Process Services segment is currently performed in the southern United States, weather does not usually create significant seasonal variations in revenue. Business has historically been slower in the period from November through March, due to the holiday season and the budgeting cycles of our customers.

 

Environmental Services

 

The overall operations and financial performance of our North Dakota operations are affected by seasonality. The volume of water processed in the Bakken Shale region of the Williston Basin in North Dakota tends to be lower in the winter, due to heavy snow and cold temperatures, and in the spring, due to heavy rains and muddy conditions that may lead to road restrictions and weight limits that can impact business. The amount of residual oil is also less prevalent and more difficult to extract during the winter months.

 

Regulation of the Industry

 

Environmental and Occupational Health and Safety Matters

 

Our operations and the operations of our customers are subject to numerous federal, state, and local environmental laws and regulations relating to worker health and safety, the discharge of materials, and environmental protection. These laws and regulations may, among other things, require the acquisition of permits for regulated activities; govern the amounts and types of substances that may be released into the environment in connection with our operations; restrict the treatment methods of waste byproducts; limit or prohibit our or our customers’ activities in sensitive areas such as wetlands, wilderness areas, or areas inhabited by endangered or threatened species; require investigatory and remedial actions to mitigate pollution conditions caused by our current or former operations; and impose specific standards addressing worker protections. Numerous governmental agencies issue regulations to implement and enforce these laws, for which compliance is often costly and difficult. The violation of these laws and regulations may result in the denial or revocation of permits, issuance of corrective action orders, assessment of administrative and civil penalties, and even criminal prosecution.

 

 

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. However, these rules and regulations are constantly evolving, and amendments thereto could result in a material effect on our operations and financial position. Further, 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 generally 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 effect on our financial position, results of operations, or future cash flows.

 

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

 

Petroleum hydrocarbons and other substances arising from oil and natural gas-related activities have been disposed of or released on or under many of our sites. At some of our facilities, we have conducted and continue to conduct monitoring or remediation of known soil and groundwater contamination. We will continue to perform such monitoring and remediation of known contamination, including any post remediation groundwater monitoring that may be required, until the appropriate regulatory standards have been achieved. These monitoring and remediation efforts are usually overseen by state environmental regulatory agencies. 

 

In the future, we may also accept for disposal solids that are subject to the requirements of the federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes. While RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation, and disposal of hazardous wastes. Most E&P waste is exempt from stringent regulation as a hazardous waste under RCRA. None of our facilities are currently permitted to accept hazardous wastes for disposal, and we take precautions to help ensure that hazardous wastes do not enter or are not disposed of at our facilities. Some wastes handled by us that currently are exempt from treatment as hazardous wastes may in the future be designated as “hazardous wastes” under RCRA or other applicable statutes. For example, in May 2016, a nonprofit environmental group filed suit in the federal district court for the District of Columbia, seeking a declaratory judgment directing the EPA to review and reconsider the RCRA E&P waste exemption. EPA and the environmental group entered into an agreement that was formalized in a consent decree issued by the U.S. District court for the District of Columbia in December 2016. Under the decree, the EPA was required to propose a rulemaking for revisions of certain of its regulations pertaining to E&P wastes or sign a determination that revision of the regulations is not necessary. After undertaking its review, EPA signed a determination in 2019 concluding that it does not need to regulate E&P wastes, and specifically “drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of oil, gas or geothermal energy,” because the states are adequately regulating E&P wastes under the Subtitle D provisions of RCRA. However, if the RCRA E&P waste exemption is repealed or modified in the future, 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. These regulations vary widely from state to state. State permits can restrict pressure, size, and location of disposal operations, impose limits on the types and amount of waste a facility may receive and the overall capacity of a waste disposal facility. States may add additional restrictions on the operations of a disposal facility when a permit is renewed or amended. As these regulations change, our permit requirements could become more stringent and may require material expenditures at our facilities or impose significant restraints or financial assurances on our operations. In the course of our operations, some of our equipment may be exposed to naturally occurring radiation associated with oil and natural gas deposits, and this exposure may result in the generation of wastes containing Naturally Occurring Radioactive Materials, or NORM. NORM wastes exhibiting trace levels of naturally occurring radiation in excess of established state standards are subject to special handling and disposal requirements, and any storage vessels, piping, and work area affected by NORM may be subject to remediation or restoration requirements.  It is possible that we may incur costs or liabilities associated with elevated levels of NORM.

 

 

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

 

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

 

Oil Pollution Act of 1990. The Oil Pollution Act of 1990, or OPA, as amended, establishes strict liability for owners and operators of facilities that are the site of a release of oil into regulated waters. 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 regulated waters 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 regulated waters and impose requirements affecting our ability to conduct activities in regulated waters and wetlands. Pursuant to the Clean Water Act and analogous state laws, permits must be obtained to discharge pollutants into regulated waters, and permits or coverage under general permits must also be obtained to authorize discharges of storm water runoff from certain types of industrial facilities, including many of our facilities. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Spill prevention, control, and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon storage tank spill, rupture, or leak. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

 

We believe that compliance with existing permits and regulatory requirements under the Clean Water Act and state counterparts will not have a material adverse effect on our business. Future changes to permits or regulatory requirements under the Clean Water Act, however, could adversely affect our business.

 

Endangered species. The federal Endangered Species Act, or ESA, restricts activities that may affect endangered or threatened species or their habitats. Many states also have analogous laws designed to protect endangered or threatened species. Additionally, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the Fish and Wildlife Service was required to make a determination on the listing of more than 250 species as endangered or threatened under the ESA by the end of the Fish and Wildlife Service’s 2017 fiscal year. The Fish and Wildlife Service did not meet that deadline, but continues to consider whether to list additional species under the ESA. Although current listings have not had a material impact on our operations, the designation of previously unidentified endangered or threatened species under the ESA or similar state laws could limit our ability to expand our operations and facilities or could force us to incur material additional costs. Moreover, listing such species under the ESA or similar state laws could indirectly, but materially, affect our business by imposing constraints on our customers’ operations, including the curtailment of new drilling or a refusal to allow a new pipeline to be constructed.

 

Air emissions. Some of our operations also result in emissions of regulated air pollutants. The Clean Air Act, or CAA, and analogous state laws require permits for and impose other restrictions on facilities that have the potential to emit substances into the atmosphere above certain specified quantities or in a manner that could adversely affect environmental quality. Failure to obtain a permit or to comply with permit requirements could result in the imposition of substantial administrative, civil, and even criminal penalties. We do not believe that any of our operations are subject to CAA permitting or regulatory requirements for major sources of air emissions, but some of our facilities could be subject to state “minor source” air permitting requirements and other state regulatory requirements for air emissions. Our Pipeline & Process Services segment has certain equipment requirements in various states.

 

 

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 recently approved and proposed 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. The rules also establish new emission requirements for compressors, controllers, dehydrators, storage tanks, natural gas processing and certain other equipment used in the hydraulic fracturing process. These rules may increase the costs to our customers of developing and producing hydrocarbons, and as a result, may have an indirect and adverse effect on the amount of oilfield waste delivered to our facilities by our customers.

 

Climate change.  The EPA has adopted regulations under existing provisions of the federal Clean Air Act that, for example, require certain large stationary sources to obtain Prevention of Significant Deterioration, or PSD, pre-construction permits and Title V operating permits for greenhouse gas (“GHG”) emissions. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among others, certain onshore oil and natural gas processing and fractionating facilities, which was expanded in October 2015 to include onshore petroleum and natural gas gathering and boosting activities and natural gas transmission pipelines. Additionally, the U.S. Congress has, in the past, 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.  In addition, in December 2015, over 190 countries, including the United States, reached an agreement to reduce greenhouse gas emissions. The agreement entered into force in November 2016 after more than 70 countries, including the United States, ratified or otherwise consent to be bound by the agreement. However, in June 2017, President Trump announced that the United States plans to withdraw from the agreement and to seek negotiations either to reenter the agreement on different terms or a separately negotiated agreement. In August 2017, the U.S. Department of State officially informed the United Nations of the United States’ intent to withdraw from the agreement, and in November 2019 formally initiated the withdrawal process, which will result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may re-enter the agreement or a separately negotiated agreement are unclear at this time. To the extent that the United States and other countries implement this agreement or impose other climate change regulations on the oil and natural gas industry, it could have an adverse effect on our business. The EPA and other federal and state agencies have also acted to address greenhouse gas emissions in other industries, most notably coal-fired power generation, and as a result could attempt in the future to impose additional regulations on the oil and natural gas industry.

 

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

 

Hydraulic fracturing. We do not conduct hydraulic fracturing operations, but we do provide treatment and disposal services with respect to the fluids used and wastes generated by our customers in such operations, which are often necessary to drill and complete new wells and maintain existing wells.  Hydraulic fracturing involves the injection of water, sand, or other proppants and chemicals under pressure into target geological formations to fracture the surrounding rock and stimulate production.  Presently, hydraulic fracturing is regulated primarily at the state level, typically by state oil and natural gas commissions and similar agencies.  Several states, including North Dakota, where we conduct our Environmental Services business, have either adopted or proposed laws and/or regulations to require oil and natural gas operators to disclose chemical ingredients and water volumes used to hydraulically fracture wells, in addition to more stringent well construction and monitoring requirements.  The chemical ingredient information is generally available to the public via online databases including fracfocus.org, and this may bring more public scrutiny to hydraulic fracturing operations.

 

At the federal level, the SDWA regulates the underground injection of substances through the UIC program and generally exempts hydraulic fracturing from the definition of “underground injection.” The U.S. Congress has in recent legislative sessions considered legislation to amend the SDWA, including legislation that would repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process.

 

Federal agencies have also asserted regulatory authority over certain aspects of the process within their jurisdiction. For example, the EPA issued an Advanced Notice of Proposed Rulemaking seeking comment on its intent to develop regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing, and proposed effluent limitations for the disposal of wastewater from unconventional resources to publicly owned treatment works. In addition, the U.S. Department of the Interior (“DOI”) published a rule that updated existing regulation of hydraulic fracturing activities on federal lands, including requirements for disclosure, well bore integrity and handling of flowback water. A U.S. District Court in Wyoming struck down this rule in June 2016; that ruling was overturned and the rule reinstated by the U.S. Court of Appeals for the Tenth Circuit in September 2017. However, the DOI formally rescinded the rule in December 2017.

 

 

The EPA conducted a study of the potential impacts of hydraulic fracturing activities on drinking water. The EPA released its final report in December 2016.   The study concluded that under certain limited circumstances, hydraulic fracturing activities and related disposal and fluid management activities, could adversely affect drinking water supplies. 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 our cost of doing business by more strictly regulating how hydraulic fracturing wastes are handled or disposed.

 

Occupational Safety and Health Act.  We are subject to the requirements of the Occupational Safety and Health Act, or OSHA and comparable state laws that regulate the protection of employee health and safety.  OSHA’s hazard communications standard requires that information about hazardous materials used or produced in our operations be maintained and provided to employees, state and local government authorities and citizens.  These laws and regulations are subject to frequent changes.  Failure to comply with these laws could lead to the assertion of third-party claims against us, civil and/or criminal fines, and changes in the way we operate our facilities that could have an adverse effect on our financial position.

 

Seismic activity.  Several states have acted to address a growing concern that the underground injection of water into disposal wells may have triggered seismic activity in certain areas. Any new seismic permitting requirements applicable to disposal wells would impose more stringent permitting requirements and would be likely to result in added costs to comply or, perhaps, may require alternative methods of disposing of saltwater and other fluids, which could delay production schedules and also result in increased costs. Additional regulatory measures designed to minimize or avoid damage to geologic formations may be imposed to address such concerns.

 

Employees

 

The Partnership does not have any employees. All of the employees that conduct our business are employed by affiliates of our general partner, although we sometimes refer to these individuals in this report as our employees.

 

We are managed and operated by the directors and officers of our general partner. As of December 31, 2019, we employed 143 people in our corporate office, who provide various services including management, human resources, information technology, safety, and accounting, among others.

 

Our Pipeline Inspection segment employs a number of inspectors that varies based on client needs (we generally only employ these inspectors when there is a specific client project to deploy them on). As of December 31, 2019, this segment employed 1,297 inspectors, all of whom were employed in the United States.

 

Our Pipeline & Process Services segment employed 41 people at December 31, 2019. Most of the employees in the Pipeline & Process Services segment are full-time employees who are compensated regardless of whether or not they are deployed on a client project.

 

Our Environmental Services segment employed 11 people at December 31, 2019, all of whom work at our North Dakota facilities.

 

Certain inspectors of our Pipeline Inspection segment are members of a union and are covered by collective bargaining arrangements. As of December 31, 2019, 111 inspectors were members of a union. None of our other employees are covered by collective bargaining arrangements.

 

Insurance Matters

 

Our customers require that we maintain certain minimum levels of insurance and evaluate our insurance coverage as part of the initial and ongoing approval process they require to use our services. We also carry a variety of insurance coverages for our operations as required by law. 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.

 

Our businesses can be dangerous, involving unforeseen circumstances such as environmental damage from leaks, spills, or vehicle accidents. To address the hazards inherent in Environmental Services, our insurance coverage includes business, auto liability, commercial general liability, employer’s liability, environmental and pollution, and other coverage. To address the hazards inherent in Pipeline Inspection and Pipeline & Process Services, insurance coverage includes employer’s liability, auto liability, employee benefits liabilities, and contractor’s pollution and other coverage. We also carry cybersecurity and crime coverage that benefits all of our business segments. Coverage for environmental and pollution-related losses is subject to significant limitations. We do not carry business interruption insurance, given its cost and its coverage limitations.

 

 

Available Information

 

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (the “Exchange Act”) are made available free of charge on our website at www.cypressenvironmental.biz as soon as reasonably practicable after these reports have been electronically filed with, or furnished to, the SEC. Unitholders may request a printed copy of these reports free of charge by contacting Investor Relations at Cypress Environmental Partners, L.P., 5727 S. Lewis Ave., Suite 300, Tulsa, OK 74105 or by e-mailing ir@cypressenvironmental.biz. These documents are also available on the SEC’s website at www.sec.gov, or a unitholder may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.  No information from either the SEC’s website or our website is incorporated herein by reference.

 

ITEM 1A.

RISK FACTORS

 

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

 

Risks Related to Our Business

 

We may not be able to pay quarterly distributions to holders of our common units because we may not have sufficient cash from operations due to our establishment of cash reserves, and payment of fees and expenses.

 

We may not have sufficient available cash from operating surplus each quarter to enable us to pay distributions to our common unitholders. The holders of our Series A preferred units representing limited partner interests in the Partnership (“Series A Preferred Units”) are entitled to receive quarterly distributions equal to 9.5% per year plus accrued and unpaid distributions prior to distributions to holders of our common units.  

 

In order to pay a distribution at our current rate of $0.21 per common unit per quarter, or $0.84 per common unit on an annualized basis, we will require available cash of approximately $2.6 million per quarter, or $10.2 million per year, based on the number of outstanding common units as of March 10, 2020. We may not have sufficient available cash from operating surplus each quarter to enable us to pay the common unit distribution. The amount of cash we can distribute to our unitholders principally depends upon the amount of cash we generate from our operations, which fluctuates from quarter to quarter based on, among other things:  

 

	●	the fees we charge, and the margins we realize, from Pipeline Inspection, Pipeline & Process Services, and Environmental Services;
	●	the number and types of projects conducted by Pipeline Inspection and Pipeline & Process Services and the volume of water processed in Environmental Services;
	●	prevailing economic and market conditions, including low or volatile commodity prices and their effect on our customers;
	●	the cost of achieving organic growth in current and new markets;
	●	our ability to make profitable acquisitions of businesses;
	●	the level of competition from other companies;

 

	●	governmental regulations, including changes in governmental regulations, in our industry;
	●	weather and natural disasters, lightning, seismic activity, vandalism and acts of terror; and
	●	the amount of residual oil we are able to separate and sell from the water we process can be impacted by the quality and price of the oil.

 

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:

 

	●	our ability to borrow funds and access capital markets;
	●	the level of our operating costs and expenses and the performance of our various facilities, inspectors and staff;
	●	fluctuations in our working capital needs;
	●	our ability to collect receivables from customers in a timely manner;
	●	restrictions contained in our debt agreements;

	●	our debt service requirements, interest rates, and other liabilities;

	●	the level of capital expenditures we make;

	●	the cost of acquisitions;

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

●

other business risks affecting our cash levels.

 

The working capital needs of the Pipeline Inspection segment are substantial, and will continue to be substantial. This will reduce our borrowing capacity for other purposes and reduce our cash available for distribution.

 

We pay the majority of our inspectors in the Pipeline Inspection segment on a weekly basis, but typically receive payment from our customers 45 to 90 days after the inspectors’ services have been performed. We borrow under our credit facility as needed to fund our working capital needs, and these borrowings reduce the amount of credit we may use for other needs, such as, acquisitions, and growth projects. Borrowings also increase our aggregate interest expense, which reduces 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 our customers delay in paying us, our working capital needs will increase, and we could be required to make further borrowings under our revolving credit facility; these delays in our customers’ payments could also impact our ability to pay our quarterly distributions.

 

 

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

 

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

 

In the ordinary course of our business, we may become subject to lawsuits, indemnity, or other claims, which could materially and adversely affect our business, financial condition, results of operations, profitability, cash flows, and growth prospects. We may also be subject to litigation involving allegations of violations of the Fair Labor Standards Act and state wage and hour laws. In addition, we generally indemnify our customers for claims related to the services we provide and the actions we take under our contracts, and, in some instances, we may be allocated risk through our contract terms for actions by our customers or other third parties.

 

From time to time, we are subject to various claims, lawsuits and other legal proceedings brought or threatened against us in the ordinary course of our business. These actions and proceedings may seek, among other things, compensation for alleged personal injury, workers’ compensation, employment discrimination and other employment-related damages, breach of contract, property damage, environmental liabilities, multiemployer pension plan withdrawal liabilities, punitive damages and civil penalties or other losses, liquidated damages, consequential damages, or injunctive or declaratory relief.

 

Such actions and proceedings may also seek damages for alleged failure of our employees to adequately perform their professional obligations. Claims for damages could include such matters as damage to customer property, damage to third-party property, environmental damages, or third-party injury claims, among others. Given the inherent risks associated with the transportation and disposal of hydrocarbons, such damage claims could be material.

 

Certain of our contracts with customers contain onerous indemnification provisions that may expose us to indemnification demands by our customers for claims made against them. Certain of our contracts with customers also contain onerous damages provisions, including for such matters as consequential damages.

 

Our existing and future debt levels may limit our flexibility to obtain financing and to pursue other business opportunities.

 

On May 29, 2018, we entered into an amended and restated credit agreement (as amended and restated, the “Credit Agreement”) that provides up to $110.0 million in borrowing capacity, subject to certain limitations. As of December 31, 2019, we had $74.9 million of indebtedness outstanding under our Credit Agreement. We may be able to incur additional debt, subject to limitations in our Credit Agreement. Our degree of leverage could have important consequences to us, including the following:

 

	●	our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions, or other purposes may be impaired or such financing may not be available on favorable terms;

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

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

●

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

  

Our ability to refinance and 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 Credit Agreement matures on May 31, 2021. If we are unable to enter into a new or amended credit facility prior to May 31, 2021, all amounts outstanding under the Credit Agreement would become due and payable on that date.  Our ability to enter into a new or amended credit facility with a longer term will depend on a number of factors, many of which are beyond our control, which include the perceptions of lenders related to our future financial performance, the perceptions of lenders regarding market conditions, the lending strategies and policies of lenders, and other factors. Even if we are able to enter into a new or amended credit facility with a longer term, the terms of such a facility could be less favorable than the terms under our existing Credit Agreement.

 

On May 29, 2018 (the “Closing Date”), we entered into a Series A Preferred Unit Purchase Agreement (the “Preferred Unit Purchase Agreement”) with an entity controlled by Charles C. Stephenson, Jr. (the “Purchaser”), an affiliate of our General Partner, where we issued and sold in a private placement 5,769,231 Series A Preferred Units representing limited partner interests in the Partnership (the “Preferred Units”) to the Purchaser for a cash purchase price of $7.54 per Preferred Unit, resulting in gross proceeds to the Partnership of $43.5 million.

 

The Purchaser is entitled to receive quarterly distributions that represent an annual return of 9.5% on the Preferred Units. Of this 9.5% annual return, we will be required to pay at least 2.5% in cash and will have the option to pay the remaining 7.0% in kind (in the form of issuing additional preferred units) for the first twelve quarters after the Closing Date. Distributions we pay on preferred units reduce the cash available for other purposes. Our preferred units rank senior to our common units, and we must pay distributions on our preferred units (including any arrearages) before paying distributions on our common units. In addition, the preferred units rank senior to the common units with respect to rights upon liquidation.

 

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

 

We do not typically enter into long-term contracts with our customers. While we frequently operate under master services agreements with customers that set forth the terms on which we will provide services, customers operating under these agreements typically have the ability to terminate their relationship with us at any time at their sole discretion by choosing to not use us to provide services. Therefore, it is possible that our customers may decide not to use our pipeline inspection, pipeline and process services, or water treatment services. The failure of customers to continue to use our services could adversely affect our operations, financial condition, cash flows 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, any of 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 77%, 67% and 68% of our consolidated revenue in 2019, 2018 and 2017, respectively. The following table sets forth the customers who accounted for more than 10% of our consolidated revenue for the years ended December 31, 2019, 2018, and 2017:

 

2019		2018		2017
Pacific Gas and Electric Company		Pacific Gas and Electric Company		Enterprise Products Partners L.P.
Phillips 66		Plains All American Pipeline, L.P.		Pacific Gas and Electric Company
Plains All American Pipeline, L.P.				Plains All American Pipeline, L.P.

 

These are customers of our Pipeline Inspection segment. The loss of all, or even a portion of the revenues from these customers, as a result of competition, market conditions or otherwise, could have a material adverse effect on our business, results of operations, financial condition, and cash flows.

 

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

 

Our business is largely dependent on the willingness of customers to outsource their pipeline inspection and pipeline and process service activities and their water and environmental treatment services. Some pipeline owners and operators currently inspect and perform pipeline and process service 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. In addition, many oil and natural gas producing companies own and operate waste treatment, recovery, and water treatment facilities that provide services that we could otherwise provide to them, and some producers recycle saltwater on-site that we could otherwise dispose for them. Most oilfield operators, including many of our customers, have numerous abandoned wells that could be licensed to dispose of internally generated waste and third-party waste, which, if our customers did license these abandoned wells, could result in competition for us. Additionally, technologies may be developed that could allow our customers to recycle saltwater and to recover oil through oilfield waste processing, which would make our services unnecessary. Our current customers could decide to inspect and perform integrity activities on their own pipeline systems or process and dispose of their waste internally, 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.

 

 

The credit risks of our concentrated customer base could indirectly result in losses to us.

 

Many of our customers are oil and natural gas companies that have or may face liquidity constraints, especially in light of the current commodity price environment. This concentration of our customers in the energy industry may impact our overall exposure to credit risk, since our customers may be similarly affected by prolonged changes in economic and industry conditions. If a significant number of our customers experience a prolonged business decline or disruptions, we may incur increased exposure to credit risk and bad debts.

 

Sanchez Energy Corporation and certain of its affiliates (collectively, “Sanchez”), a former customer, filed for bankruptcy protection in August 2019. As of December 31, 2019, our Consolidated Balance Sheet included $0.5 million of pre-petition accounts receivable from Sanchez. We have recorded an allowance of less than $0.1 million at December 31, 2019 against the accounts receivable from Sanchez. We do not believe it is probable that we will be unable to collect the remaining $0.4 million balance of the pre-petition receivables. However, due to uncertainties associated with the bankruptcy process, we cannot make assurances regarding the ultimate collection of these receivables nor can we make assurances regarding the timing of any such collections.

 

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

 

We depend 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 a published 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 rig count of 404 rigs in May 2016. The prices of crude oil and related products dropped substantially in the fourth quarter of 2014 and have stayed low. If crude oil prices do not rise, E&P companies, pipeline owners and operators and public utility or local distribution companies in the regions we conduct our business may reduce capital spending maintaining their pipelines or oil and natural gas production. The Environmental Services segment constitutes approximately 3%, 4%, and 3% of our revenue in 2019, 2018, and 2017, respectively. The Bakken region of North Dakota generally requires higher oil prices than certain other regions in order to generate suitable economic returns for E&P companies. Therefore, a continued decrease in drilling activity or hydraulic fracking could have an adverse effect on our financial position, results of operations, demand for services, cash flows or our ability to make cash distributions to our unitholders or make required payments on our outstanding debt.

 

Crude oil prices have decreased significantly in 2020, due in part to decreased demand as a result of a recent worldwide COVID-19 outbreak, and due in part to the oil price war started by Russia and Saudi Arabia with a focus on slowing down U.S. oil production. This decline in oil prices will likely lead our customers to change their budgets and plans, which will decrease their spending on drilling, completions, and exploration. This could have an impact on construction of new pipelines, gathering systems, and related energy infrastructure. Lower exploration and production activity will also impact the midstream industry and could lead to delays or cancellations of projects. It is also possible that our customers may elect to defer maintenance activities on their infrastructure. Such developments would reduce our opportunities to generate revenues. It is impossible at this time to determine what may occur, as customer plans will evolve over time.  It is possible that the cumulative nature of these events could have a material adverse effect on our results of operations and financial position. These market conditions could also have a material adverse effect on the financial position of our customers, which could increase the risk that we are unable to collect accounts receivable from customers for services we have provided. 

 

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

 

	●	the supply of and demand for oil and natural gas;
	●	the level of prices, and market expectations with respect to future prices of oil and natural gas;
	●	the cost of exploring for, developing, producing, and delivering oil and natural gas;

 

	●	the cost of fracturing services;
	●	the market’s expected rate of decline of current oil and natural gas production;
	●	the rate and frequency at which new oil and natural gas reserves are discovered;
	●	available pipeline and other transportation capacity;
	●	lead times associated with acquiring equipment and products and availability of personnel;
	●	weather conditions, including hurricanes, tornadoes, earthquakes, wildfires, drought or man-made disasters that can affect oil and natural gas operations over a wide area, as well as local weather conditions such as unusually cold winters in the Bakken Shale region of the Williston Basin in North Dakota that can have a significant impact on drilling activity in that region;
	●	domestic and worldwide economic conditions;
	●	contractions in the credit market;
	●	political instability in certain oil and natural gas producing countries;
	●	the continued threat of terrorism and the impact of military and other action, including military action in the Middle East or other parts of the world;
	●	governmental regulations, including income tax laws or government incentive programs relating to the oil and natural gas industry and the policies of governments regarding the exploration for and production and development of oil and natural gas reserves;
	●	the level of oil production by non-OPEC countries and the available excess production capacity contained in OPEC member countries;
	●	oil refining capacity and shifts in end-customer preferences toward fuel efficiency;
	●	potential acceleration in the development, and the price and availability, of alternative fuels;
	●	the availability of water resources for use in hydraulic fracturing operations;

 

	●	public pressure on, and legislative and regulatory interest in, federal, state, and local governments to ban, stop, significantly limit or regulate hydraulic fracturing operations;
	●	technical advances affecting energy consumption;
	●	access to necessary labor and services;
	●	the access to and cost of debt and equity capital for oil and natural gas producers;
	●	merger and divestiture activity among oil and natural gas producers; and
	●	the impact of changing regulations and environmental and safety rules and policies.

 

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

 

We have many competitors in our primary markets. Some of our customers also compete with us in the treatment and disposal sector by offering similar 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 aggressively control our costs 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, lower cost of capital or other advantages over the services we provide. Adverse market conditions could lead customers to demand lower prices, which could result in a reduction in our profit margins.

 

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. Under Department of Transportation regulations, a sustained failure to operate vehicles safely could result in the loss of our ability to operate vehicles in the conduct of our business.

 

In addition, while an inspector is performing pipeline inspection or integrity services for us, the inspector is our employee and is eligible for workers’ compensation claims if the inspector is injured or killed while working for us. As the inspectors generally travel to and from projects in their own vehicles, we may be responsible for workers compensation claims or third-party claims arising out of vehicle accidents, which could negatively affect our results of operations. Our inspectors travel extensively in their own vehicles, as job sites are often a long distance from an inspector’s home and from his/her lodging location while he/she is working on a project.

 

Unsatisfactory safety performance may negatively affect our customer relationships, workers compensation rates and, to the extent we fail to retain existing customers or attract new customers, adversely impact our revenues.

 

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, which could cause us to lose substantial revenues. Further, our ability to attract new customers may be impaired if they elect not to purchase our services because they view our safety record as unacceptable. 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 if 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.

 

 

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

 

We believe that our future success depends on our ability to manage growth, including increased demands and responsibilities. The following factors could present difficulties to us:

 

	●	access to debt and equity capital on attractive terms;
	●	limitations with systems and technology;
	●	organizational challenges common to large, expansive operations;
	●	administrative burdens;
	●	employee insurance;
	●	safety and training;
	●	ability to recruit, train, and retain personnel and managers;
	●	ability to obtain permits for expanded operations; and
	●	long lead times associated with acquiring equipment and building any new facilities.

 

Our operating results could be adversely affected if we do not successfully manage any of these potential difficulties.

 

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 depend in part on third party trucking companies to transport saltwater to our water treatment facilities. In recent years, certain states, including North Dakota, and certain counties, have increased enforcement of weight limits they impose on water treatment trucks. Also, as a result of regulations issued in March 2014, all waste haulers transporting produced water in North Dakota must possess a valid permit for transporting solid waste from the North Dakota Department of Health. It is possible that the states, counties and cities in which the Environmental Services segment conducts its operations 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 and increased costs in transporting saltwater to our water treatment facilities, which may either increase our operating costs or reduce the amount of saltwater transported to our water treatment facilities. This could decrease our operating margins and thereby affect our results of operations and cash available for distribution.

 

 

A significant increase in fuel or insurance prices may adversely affect the transportation costs of our trucking company customers, which could result in a decrease in the rates for our saltwater and environmental services they would be willing to pay.

 

A significant increase in fuel prices will result in increased transportation costs to our trucking customers. 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 result in our trucking company customers becoming unwilling to pay the resulting increase in water processing fees, which would reduce our revenues and impact our ability to make distributions to our unitholders. A significant increase in insurance prices or decrease in availability of coverage also would result in increased transportation costs to our customers.

 

We sell residual oil that we recover during our water treatment process. Volumes of residual oil recovered during the water treatment process can vary. Any significant reduction in residual oil content in the water we treat, or the price we achieve for residual oil sales, will affect our recovery of residual oil and, indirectly, our profitability.

 

Approximately 6%, 5%, and 7% of the revenue in 2019, 2018, and 2017, respectively, of our Environmental Services segment was derived from sales of residual oil recovered during the water treatment process. Our ability to recover sufficient volumes of residual oil is dependent upon the residual oil content in the water 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 recover higher levels of residual oil in water prior to delivering such water 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 water we treat or the prices we realize on our sales of residual oil could materially and adversely affect our profitability.

 

Our utilization of existing capacity, expansion of existing water treatment facilities, and construction or purchase of new water treatment 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 and expand existing water treatment facilities. The construction of a new water treatment facility or the extension, renovation or expansion of an existing water treatment facility, such as by connecting such water treatment facility to existing or newly constructed pipeline systems, involves numerous business, competitive, regulatory, environmental, political, and legal uncertainties, most of which are beyond our control. If we undertake these projects, they may not be completed on schedule, 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 water treatment facilities may not be able to attract enough demand for water and environmental services to achieve our expected investment return, which could materially adversely affect our results of operations and financial condition and our ability in the future to make distributions to our unitholders.

 

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

 

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

 

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

 

 

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

 

	●	unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts;
	●	unable to obtain financing for these acquisitions on economically acceptable terms;
	●	outbid by competitors; or
	●	for any other reason.

 

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

 

Any acquisition involves potential risks, including, among other things:

 

	●	mistaken assumptions about disposal capacity, number and quality of inspectors, revenues and costs, cash flows, capital expenditures, and synergies;
	●	the assumption of unknown liabilities;
	●	limitations on rights to indemnity from the seller;
	●	mistaken assumptions about the overall costs of equity or debt;
	●	the diversion of management’s attention from other business concerns;
	●	integrating business operations or unforeseen regulatory issues;
	●	unforeseen new regulations;
	●	unforeseen difficulties operating in new geographic areas; and
	●	customer or key personnel losses at the acquired businesses.

 

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

 

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

 

We own a 51.0% interest in Brown, a 25% interest in Alati Arnegard, LLC, and a 49.0% interest in CF Inspection. We may also enter into other arrangements with third parties in the future. Other third parties in future arrangements may have obligations that are important to the success of the arrangement, such as the obligation to pay their share of capital and other costs of these partially owned entities. The performance of these third-party obligations, including the ability of our current partners to satisfy their respective obligations, is outside our control. If these parties do not satisfy their obligations under the arrangements, our business may be adversely affected.

 

 

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

 

	●	our partner shares certain blocking rights over transactions;

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

	●	although we may control these joint ventures, we may have contractual duties to the joint ventures’ respective other owners, which may conflict with our interests and the interests of our unitholders; and

●

disputes between us and other partners may result in delays, litigation, or operational impasses.

 

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

 

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

 

In May 2018, we entered into a new Credit Agreement that provides up to $110.0 million in borrowing capacity. The Credit Agreement matures in May 2021. Our Credit Agreement limits our ability to, among other things:

 

	●	incur or guarantee additional debt;

	●	make certain investments and acquisitions;

	●	incur certain liens or permit them to exist;

	●	alter our lines of business;

	●	enter into certain types of transactions with affiliates;

	●	merge or consolidate with another company; and

●

transfer, sell or otherwise dispose of assets.

 

The Credit Agreement also contains certain covenants requiring us to maintain certain financial ratios. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure unitholders that we will be able to meet these ratios and tests.

 

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

 

 

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 environmental, health, and safety laws and regulations applicable to our business and the business of our customers, including laws regulating the energy industry, and the interpretation or enforcement of these laws and regulations, are constantly evolving. Failure to comply with these health and safety laws and regulations could lead to third-party claims, criminal and regulatory violations, civil fines, and changes in the way we operate our facilities, which could increase the cost of operating our business and have a material adverse effect on our financial position, results of operations, and cash flows and our ability to make cash distributions to our unitholders. Our safety and compliance record is also important to our clients, and our failure to maintain safe operations could materially impact our business.

 

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

 

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 water treatment 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 water treatment facilities develop a leak (depending upon the terms of the insurance contracts at issue).

 

On November 29, 2018, a production inspector employed by CEM-TIR, suffered a fatal injury while working at a client’s jobsite. The injury occurred while the employee was performing a procedure inconsistent with his job duties, at the direction of the client’s employee. CEM-TIR had no knowledge or control over the work that was performed by the employee. An OSHA investigation determined that neither CEM-TIR nor TIR were at fault, and instead issued citations to the client.

 

 

A failure in our operational and communications systems, loss of power, natural disasters, or cyber security attacks on any of our facilities, or any of our third-parties’ facilities on which we rely, may adversely affect our results of operations and financial results.

 

Our business is dependent upon our operational systems to process a large amount of data and a substantial number of transactions. If any of our financial, operational, or other data processing systems fail or have other significant shortcomings, our financial results could be adversely affected. Our financial results could also be adversely affected if an employee causes our operational or financial systems to fail, either as a result of inadvertent error, or by deliberately tampering with or manipulating our operational systems. In addition, dependence upon automated systems may further increase the risk that operational system flaws, employee tampering, or manipulation of those systems will result in losses that are difficult to detect.

 

Due to technological advances, we have become more reliant on technology to help increase efficiency in our business. We use computer programs to help run our financial and operations processes, and this may subject our business to increased risks. Any future cyber security attacks that affect our facilities, communications systems, our customers, or any of our financial data could have a material adverse effect on our business. In addition, cyber-attacks on our customer and employee data may result in a financial loss and may negatively impact our reputation. 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.

 

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 water treatment facilities in North Dakota, which are subject to regulatory programs 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 our developing and operating waste treatment and storage facilities and in connection with our disposing and transporting certain types of waste. 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. 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. It is not uncommon for local property owners or, in some cases, oil and natural gas producers, to oppose water treatment 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.

 

Our customers’ delays in obtaining permits 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 water treatment facilities and we may be required to provide an increased level of financial assurance to regulatory agencies to ensure the appropriate closure activities occur for a water treatment facility.

 

Obtaining a permit to own or operate a water treatment 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 water treatment facilities. In particular, the North Dakota regulatory agencies require us to post letters of credit in connection with the operation of our water treatment facilities. As we acquire additional water treatment facilities or expand our existing water treatment facilities, these obligations will increase. Additionally, in the future, regulatory agencies may require us to increase the amount of our closure bonds at existing water treatment facilities. We have accrued approximately $0.2 million on our Consolidated Balance Sheet related to our contemplated future closure obligations of our water treatment facilities as of December 31, 2019. This amount was calculated by estimating the total amount of closure obligations and the dates at which such closures might occur and discounting this total estimated cost to calculate a present value. However, actual costs could exceed our current expectations, as a result of, among other things, federal, state or local government regulatory action, increased costs our service providers charge who assist in closing water treatment facilities, and additional environmental remediation requirements. Increased regulatory requirements regarding our existing or future water treatment facilities, including the requirement to pay increased closure and post-closure costs or to establish increased financial assurance for such activities could substantially increase our operating costs and cause our available cash that we have to distribute to our unitholders to decline.

 

Changes in laws or government regulations regarding hydraulic fracturing could increase our customers’ costs of doing business, limit the areas in which our customers can operate and reduce oil and natural gas production by our customers, which could adversely impact our business.

 

We do not conduct hydraulic fracturing operations, but we do provide treatment and disposal services with respect to the fluids used and wastes generated by our customers in such operations, which are often necessary to drill and complete new wells and maintain existing wells. Hydraulic fracturing involves the injection of water, sand or other proppants and chemicals under pressure into target geological formations to fracture the surrounding rock and stimulate oil and gas production. Presently, hydraulic fracturing is regulated primarily at the state level, typically by state oil and natural gas commissions and similar agencies.  Several states, including 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 such operators use to hydraulically fracture wells. These states also impose stringent well construction and monitoring requirements.  The chemical ingredient information we provide to these states is generally available to the public via online databases including fracfocus.org. Making this information publicly available may bring more scrutiny to hydraulic fracturing operations.

 

At the federal level, the SDWA regulates the underground injection of substances through the UIC program and generally exempts hydraulic fracturing from the definition of “underground injection.” The U.S. Congress has in recent legislative sessions considered legislation to amend the SDWA. Such legislation 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.

 

Federal agencies have also asserted regulatory authority over certain aspects of the process within their respective jurisdictions. For example, the EPA issued an Advanced Notice of Proposed Rulemaking seeking comment on its intent to develop regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing, and proposed effluent limitations for the disposal of wastewater from unconventional resources to publicly owned treatment works.

 

The EPA conducted a study of the potential impacts of hydraulic fracturing activities on drinking water. The EPA released its final report in December 2016. The study concluded that under certain limited circumstances, hydraulic fracturing activities and related disposal and fluid management activities, could adversely affect drinking water supplies. 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.

 

 

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 oil and natural gas producers’ water recycling efforts which would decrease the volume of saltwater delivered to our water treatment facilities and correspondingly decrease our revenues attributed to saltwater delivery services.

 

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 by natural occurrences, such as prolonged droughts. As a result, some local water districts have begun restricting the use of water for hydraulic fracturing in an effort to protect local water supplies. For example, in response to continuing drought conditions in 2015, 2014, and 2013, the Texas Legislature considered a number of bills that would have mandated recycling of flowback and produced water and/or prohibited recyclable water from being disposed of in wells. If oil and natural gas producers 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 water treatment facilities. Similarly, mandatory recycling programs could reduce the amount of materials sent to us for treatment and disposal. Any such limits or mandates could adversely affect our business and results of operations.

 

Increased attention to seismic activity associated with hydraulic fracturing and underground disposal could result in additional regulations and adversely impact demand for our services.

 

There exists a growing concern among certain experts in the oil and gas industry that the underground injection of produced water into disposal wells has triggered seismic activity in certain areas. Some states have promulgated rules or guidance in response to these concerns. For example, in Texas, the Texas Railroad Commission (“TRC”) published a final rule in October 2014 governing permitting or re-permitting of disposal wells that will require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections, and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal zone, or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the TRC may deny, modify, suspend, or terminate the permit application or existing operating permit for that well. New seismic permitting requirements applicable to disposal wells would impose more stringent permitting requirements and would be likely to result in added costs to comply, or perhaps, may require alternative methods of disposing of saltwater and other fluids, which could delay production schedules and also result in increased costs. Additional regulatory measures designed to minimize or avoid damage to geologic formations may be imposed to address such concerns.

 

We and our customers may incur significant liability under, or costs and expenditures to comply with, environmental regulations, which are complex and subject to frequent change.

 

Our and our customer’s operations are subject to stringent federal, state, provincial and local laws and regulations relating to, among other things, protection of natural resources, wetlands, endangered species, the environment, waste management, waste disposal, and transportation of waste and other materials. 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, 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. As the federal government continues to develop and propose regulations relating to fuel quality, engine efficiency and GHG emissions, we may experience an increase in costs related to equipment purchases and maintenance, impairment of equipment productivity, and a decrease in the residual value of equipment. In addition, our customers could impose environmental, social, and governance mandates on us that are more stringent than federal, state, provincial and local laws and regulations, which could result in further increases in costs. A breach of such requirements may result in suspension or revocation of necessary licenses or authorizations, civil liability for, among other things, pollution damage and the imposition of material fines.

 

Our 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 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 May 2016, a nonprofit environmental group filed suit in the federal district court for the District of Columbia, seeking a declaratory judgment directing the EPA to review and reconsider the RCRA E&P waste exemption. EPA and the environmental group entered into an agreement that was formalized in a consent decree issued by the U.S. District Court for the District of Columbia in December 2016. Under the consent decree, the EPA was required to propose a rulemaking for revisions of certain of its regulations pertaining to E&P wastes or sign a determination that revision of the regulations is not necessary. After undertaking its review, EPA signed a determination in 2019 concluding that it does not need to regulate E&P wastes, and specifically “drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of oil, gas or geothermal energy,” because the states are adequately regulating E&P wastes under the Subtitle D provisions of RCRA. If the exemption covering E&P wastes is repealed or modified in the future, 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.

 

 

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

 

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

 

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

 

The EPA has adopted regulations under existing provisions of the federal Clean Air Act, that, for example, require certain large stationary sources to obtain Prevention of Significant Deterioration, or PSD, pre-construction permits and Title V operating permits for GHG emissions. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among others, certain onshore oil and natural gas processing and fractionating facilities, which was expanded in October 2015 to include onshore petroleum and natural gas gathering and boosting activities and natural gas transmission pipelines. Additionally, the U.S. Congress has in the past 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. In addition, in December 2015, over 190 countries, including the United States, reached an agreement to reduce greenhouse gas emissions. The agreement entered into force in November 2016 after over 70 countries, including the United States, ratified or otherwise consented to be bound by the agreement. However, in June 2017, President Trump announced that the United States plans to withdraw from the agreement and to seek negotiations either to reenter the agreement on different terms or a separately negotiated agreement. In August 2017, the U.S. Department of State officially informed the United Nations of the United States’ intent to withdraw from the agreement, and in November 2019 formally initiated the withdrawal process, which will result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may re-enter the agreement or a separately negotiated agreement are unclear at this time. To the extent that the United States and other countries implement this agreement or impose other climate change regulations on the oil and natural gas industry, it could have an adverse effect on our business. The EPA and other federal and state agencies have also acted to address GHG emissions in other industries, most notably coal-fired power generation, and as a result could attempt in the future to impose additional regulations on the oil and natural gas industry.

 

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.

 

Finally, 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 (“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. Additionally, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the Fish and Wildlife Service was required to make a determination on the listing of more than 250 species as endangered or threatened under the ESA by the end of the Fish and Wildlife Service’s 2017 fiscal year. Although current listings have not had a material impact on our operations, the designation of previously unidentified endangered or threatened species under the ESA or similar state laws 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.

 

 

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

 

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 water treatment facilities are located exclusively in North Dakota. This concentration could disproportionately expose us to operational, economic, and regulatory risk in these areas. Our water treatment facilities currently consist of eight owned and one managed facility. 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 our markets, including, for example, transportation constraints, adverse regulatory developments, or other adverse events at one of our water treatment facilities, could have a significantly greater impact on our financial condition, results of operations, and cash flows than if we were more diversified.

 

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.

 

New technology, including those involving recycling of saltwater or the replacement of water in fracturing fluid, may hurt our competitive position.

 

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

 

Technology advancements in connection with alternatives to hydraulic fracturing could decrease the demand for our water treatment facilities.

 

Some oil and natural gas producers are focusing on developing and utilizing non-water fracturing techniques, such as techniques that utilize 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 water treatment services could be materially impacted because these wells would not produce flowback water.

 

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 Environmental Services could decrease if the volume of saltwater processed and disposed of by our customers’ decreases or if we are unable to increase the rates charged to correspond with increasing costs of operations. Our revenues and profitability for Pipeline Inspection and Pipeline & Process Services could decrease if the demand for our inspectors decreases, if our safety record declines, or we are unable to obtain affordable insurance, if we are unable to recruit and retain qualified inspectors, or if we are unable to increase the daily and hourly rates charged to correspond with any potential increasing costs of operations. In addition, new agreements for our services in these business segments may not be obtainable on terms acceptable to us or, if obtained, may not be obtained on terms favorably 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.

 

Public health threats, such as the coronavirus (COVID-19) and other highly communicable diseases, could adversely impact the operations of our customers, and the global economy, including the worldwide demand for oil and natural gas and the level of demand for our environmental services.

 

 

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 water treatment 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, Pipeline Inspection and Pipeline & Process Services are dependent on specialized inspectors, who must undergo specific training prior to performing inspection and integrity 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 of skilled workers is limited. A significant increase in the wages paid by our competitors 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. Likewise, laws and regulations to which we are, or may in the future become subject, could increase our labor costs or subject us to liabilities to our employees. In addition, the U.S. customers in Pipeline Inspection and Pipeline & Process Services could choose to hire our inspectors directly. If any of these events were to occur, our capacity and profitability could be diminished and our growth potential could be impaired.

 

Our ability to operate our business effectively could be impaired if affiliates of our general partner fail to attract and retain key management personnel.

 

We depend on the continuing efforts of our executive officers and other key management personnel, all of whom are employees of affiliates of our general partner. Additionally, neither we, nor our subsidiaries, have employees. CEM LLC and its affiliates are responsible for providing the employees and other personnel necessary to conduct our operations. All of the employees that conduct our business are employed by affiliates of our general partner. 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, experience significant interruptions.

 

We are dependent upon the uninterrupted operations of our water treatment 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 water treatment facilities, for any reason, would adversely affect our results of operations, cash flow, and ability to make distributions to our unitholders. Operations at our facilities and at the facilities owned or operated by our customers could be partially or completely shut down, temporarily or permanently, as the result of any number of circumstances that are not within our control, such as:

 

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

	●	loss of electricity or power;

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

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

 

	●	environmental remediation;
	●	pressure issues that limit or restrict our ability to inject water into the disposal well or limitations with the injection zone formation and its permeability or porosity that could limit or prevent disposal of additional fluids;
	●	labor difficulties;
	●	malfunctions in automated control systems at the facilities;

	●	disruptions in the supply of saltwater to our facilities;

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

	●	governmental mandates, restrictions, or rules and regulations.

In addition, there can be no assurance that we are adequately insured against such risks because the Partnership does not carry business interruption insurance. 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 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. 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. Our common unit price is impacted by the 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 sustained failure of our information technology systems could adversely affect our business.

 

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

 

We implemented a new information technology system in early 2020 to support our payroll, inspector recruitment, and human resource management processes. It is our intent, through this system, to integrate the major facets of our organization in order to improve planning, development, processes, sales, human resources management, and other applications as they affect our evolving business model. We may not realize the benefits we anticipate should all or a part of the system implementation process prove to be ineffective.

 

 

Public health threats could have a material adverse effect on our operations and our financial results.

 

Public health threats, such as the coronavirus (COVID-19) and other highly communicable diseases, could adversely impact our operations, the operations of our customers, and the global economy, including the worldwide demand for oil and natural gas and the level of demand for our environmental services. Any quarantine of personnel or inability to access our offices or work locations could adversely affect our operations. Travel restrictions or operational problems in any areas in which we operate, or any reduction in the demand for our environmental services caused by public health threats, may materially impact operations and adversely affect our financial results.

 

If we fail to develop or maintain an effective system of internal controls, we may not be able to report our financial results accurately or prevent fraud, which would likely have a negative impact on the market price of our common units.

 

Effective internal controls are necessary for us to provide timely, 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 (“Section 404”). For example, Section 404 requires us, among other things, to annually review and report on the effectiveness of our internal controls over financial reporting. Any failure to develop, implement, or maintain effective internal controls, or to improve our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Given the difficulties inherent in the design and operation of internal controls over financial reporting, we can provide no assurance as to our conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404.

 

In early 2020 we implemented a new software system for payroll and human resources management. We will apply and test internal control procedures related to this new system as we deem necessary. It is our intent through this new system to improve processes for human resources management, payroll, and other applications as they affect our evolving business model. Any failure(s) during this implementation process 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 a new system implementation, we can provide no assurance as to our conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404. Ineffective internal controls could subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business, and would likely have a negative effect on the trading price of our common units.

 

We are required to disclose changes made in our internal control over financial reporting on a quarterly basis, and we are required to assess the effectiveness of our controls annually. We are not an “accelerated filer” as defined in Rule 12b-2 of the Exchange Act, and therefore our independent registered public accounting firm will not be required to attest to the effectiveness of our internal controls over financial reporting until we become an accelerated filer.

 

Risks Inherent in an Investment in Us

 

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

 

As of December 31, 2019, Holdings and its affiliates own an approximate 64% common unit interest in us and own and control our general partner and appoint all the officers and directors of our general partner. As of December 31, 2019, an affiliate of Holdings owns all of the preferred unit interests in us. Although our general partner has a duty to manage us in a manner that is in the best interests of our partnership and our unitholders, the directors and officers of our general partner also have a fiduciary duty to manage our general partner in a manner that is in the best interests of its owner, Holdings. Conflicts of interest may arise between Holdings and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates, including Holdings, over the interests of our common unitholders. These conflicts include, among others, the following situations:

 

	●	neither our partnership agreement nor any other agreement requires Holdings to pursue a business strategy that favors us or utilizes our assets, which could involve decisions by Holdings to invest in competitors, pursue and grow particular markets, or undertake acquisition opportunities for itself.  Holdings’ directors and officers have a fiduciary duty to make these decisions in the best interests of Holdings;

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

 

	●	Holdings may be constrained by the terms of its debt instruments from taking actions, or refraining from taking actions, that may be in our best interests;

	●	our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limiting our general partner’s liabilities and restricting the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty;

	●	except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;
	●	our general partner will determine the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities, and the creation, reduction or increase of cash reserves, each of which can affect the amount of cash that is distributed to our unitholders;
	●	expenditures, which would not reduce operating surplus, or a maintenance capital expenditure, which would reduce our operating surplus, and whether to set aside cash for future maintenance capital expenditures on certain of our assets that will need extensive repairs during their useful lives. This determination can affect the amount of available cash from operating surplus that is distributed to our unitholders and to our general partner, and the amount of adjusted operating surplus generated in any given period;
	●	our general partner will determine which costs incurred by it are reimbursable by us;
	●	our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions;
	●	our partnership agreement permits us to classify up to $10.0 million as operating surplus, even if it is the surplus 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 to our general partner in respect of the general partner interest or the incentive distribution rights;
	●	our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;
	●	our general partner intends to limit its liability regarding our contractual and other obligations;
	●	our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if it and its affiliates own more than 80.0% of the common units;
	●	our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates;
	●	our general partner decides whether to retain separate counsel, accountants or others to perform services for us;

 

	●	our general partner may or may not provide financial support to the Partnership. They may also require compensation for financial support in the form of additional units, preferred equity, dividend reinvestment plan, and other mechanisms;
	●	our general partner may decide to issue additional Partnership common units to the general public, thus diluting current unitholders’ ownership interests. This action could result in lower distributions to our common unitholders; and
	●	our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to the incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner, which we refer to as our conflicts committee, or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

 

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

 

Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.

 

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of Holdings to transfer its membership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own choices.

 

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

 

Our partnership agreement requires that we distribute all of our available cash to our unitholders. As a result, we expect to rely primarily upon external financing sources, including commercial bank borrowings, and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. Therefore, to the extent we are unable to finance our growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we 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 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 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.

 

 

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

 

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

 

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

	●	whether to exercise its limited call right;

	●	whether to seek approval by the conflicts committee of the board of directors of our general partner to address and resolve a conflict of interest;

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

	●	whether to elect to reset target distribution levels;

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

●

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

 

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

 

Our general partner limits its liability regarding our obligations.

 

Our general partner limits 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 units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

 

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

 

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

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

 

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

●

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

 

In connection with a situation involving a transaction with an affiliate or a conflict of interest, our partnership agreement provides that any determination by our general partner must be made in good faith, and that our conflicts committee and the board of directors of our general partner are entitled to a presumption that they acted in good faith. In any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Please read “Item 13 – Certain Relationships and Related Party Transactions – Conflicts of Interest and Duties.”  

 

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 do 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 have no right to elect our general partner or the board of directors of our general partner on an annual or other continuing basis. The board of directors of our general partner is chosen by the member of our general partner, which is a wholly-owned subsidiary of Holdings. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which our common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

 

The vote of the holders of at least 66²/₃% of all outstanding common units is required to remove our general partner. As of March 10, 2020, Holdings and its affiliates own approximately 64% of our outstanding common units. Therefore, the unitholders will be unable initially to remove our general partner without its consent, because our general partner and its affiliates own sufficient units to be able to prevent its removal.

 

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.

 

We may issue additional common units and other equity interests ranking junior to the Series A Preferred Units without unitholder approval, which would dilute unitholders’ existing ownership interests.

 

At any time, we may issue an unlimited number of general partner interests or limited partner interests of any type without the approval of our unitholders and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such general partner interests or limited partner interests, except that, subject to certain limited exceptions, we will need the consent of 66^2/₃% of the outstanding Series A Preferred Units to issue any additional Series A Preferred Units or any class or series of partnership interests that, with respect to distributions on such partnership interests or distributions in respect of such partnership interests upon our liquidation, dissolution and winding up, ranks equal to or senior to the Series A Preferred Units. Further, there are no limitations in our partnership agreement on our ability to issue equity securities that rank equal, or senior to, our common units as to distributions, or in liquidation, or that have special voting rights and other rights. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

 

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

 

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

	●	the ratio of taxable income to distributions may increase;

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

●

the market price of our common units may decline.

 

The issuance by us of additional general partner interests may have the following effects, among others, if such general partner interests are issued to a person who is not an affiliate of Holdings:

 

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

●

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

 

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

 

As of December 31, 2019, Holdings and CEP-TIR, a former indirect subsidiary of Holdings, together held 6,957,349 common units. Additionally, we have agreed to provide Holdings and CEP-TIR with certain registration rights under applicable securities laws. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.

 

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

 

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

 

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

 

If at any time, our general partner and its affiliates own more than 80.0% of our then-outstanding common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on unitholders’ investment. Unitholders may also incur a tax liability upon a sale of their units. As of March 10, 2020, Holdings and its affiliates own 64% of our common units and therefore are not currently able to exercise the call right.

 

The incentive distribution rights of our general partner may be transferred to a third party without unitholder consent.

 

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

 

 

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

 

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

 

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

 

As of December 31, 2019, there are only 4,275,842 publicly traded common units held by public unitholders. As of December, 31, 2019, Holdings and CEP-TIR, a former indirect subsidiary of Holdings, held 6,957,349 common units representing an aggregate 58% of our common units. The lack of liquidity in the trading market for our common units may result in wide bid-ask spreads, which could result in significant fluctuations in the market price of our common units and limit the number of investors who are able to buy our common units. In addition, our Series A Preferred Units may be converted into common units at the then-applicable conversion rate at the earlier of (i) May 29, 2021 or (ii) immediately prior to a liquidation of us. 

 

Our general partner, or any transferee holding incentive distribution rights, may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights, without the approval of our conflicts committee or the holders of our common units. This could result in lower distributions to holders of our common units.

 

Our general partner has the right, at any time units are outstanding and the holder of the incentive distribution rights 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, the holder of the incentive distribution rights will be entitled to receive a number of common units equal to that number of common units that would have entitled the holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions 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 cash distributions related to the incentive distribution rights and may, therefore, desire the holder of the incentive distribution rights be issued common units, rather than retain the right to receive distributions based on the initial target distribution levels. This risk could be elevated if our incentive distribution rights have been transferred to a third party. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that they would have otherwise received had we not issued new common units in connection with resetting the target distribution levels. Additionally, our general partner has the right to transfer all or any portion of our incentive distribution rights at any time, and such transferee shall have the same rights as the general partner relative to resetting target distributions if our general partner concurs that the tests for resetting target distributions have been fulfilled.

 

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

 

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

 

A unitholder’s liability may not be limited if a court finds that unitholder action constitutes control of our business.

 

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

 

 

Our Series A Preferred Units have rights, preferences and privileges that are not held by, and are preferential to the rights of, holders of our common units.

 

Our Series A Preferred Units rank senior to our common units with respect to distribution rights and rights upon liquidation. These preferences could adversely affect the market price for our common units or could make it more difficult for us to sell our common units in the future.

 

In addition, until the conversion of the Series A Preferred Units into common units or their redemption, holders of the Series A Preferred Units will receive cumulative quarterly distributions equal to 9.5% per annum plus accrued and unpaid distributions. With respect to any quarter up to and including the quarter ending June 30, 2021, our general partner may elect to pay such quarterly distribution in cash, in-kind in the form of additional Series A Preferred Units or in a combination thereof, provided that a minimum of 2.5% of such distribution will be paid in cash unless the holders of the Series A Preferred Units otherwise agree. For any quarter ending after June 30, 2021, the quarterly distribution will be paid in cash. Each holder of the Series A Preferred Units has the right to share in any special distributions by us of cash, securities or other property pro rata with the common units on an as-converted basis, subject to customary adjustments. Accordingly, we cannot pay any distributions on any junior securities, including any of the common units, prior to paying the quarterly distribution payable to the Series A Preferred Units, including any previously accrued and unpaid distributions. Our obligation to pay distributions on our Series A Preferred Units could impact our liquidity and reduce the amount of cash flow available for working capital, capital expenditures, growth opportunities, acquisitions and other general partnership purposes. Our obligations to the holders of the Series A Preferred Units could also limit our ability to obtain additional financing or increase our borrowing costs, which could have an adverse effect on our financial condition.

 

The terms of our Series A Preferred Units contain covenants that may limit our business flexibility.

 

The terms of our Series A Preferred Units contain covenants preventing us from taking certain actions without the approval of the holders of 66^2/₃% of the outstanding Series A Preferred Units, voting separately as a class. The need to obtain the approval of holders of the Series A Preferred Units before taking these actions could impede our ability to take certain actions that management or the Board of Directors of our General Partner may consider to be in the best interests of our unitholders.

 

The affirmative vote of 66^2/₃% of the outstanding Series A Preferred Units, voting separately as a class, is necessary to amend our partnership agreement in any manner that is materially adverse to any of the rights, preferences and privileges of the Series A Preferred Units. The affirmative vote of 66^2/₃% of the outstanding Series A Preferred Units voting separately as a class, is necessary to, among other things issue, authorize or create any additional Series A Preferred Units or any class or series of partnership interests that, with respect to distributions on such partnership interests or distributions in respect of such partnership interests upon our liquidation, dissolution and winding up, ranks equal to or senior to the Series A Preferred Units.

 

Tax Risks

 

Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for U.S. 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 U.S. 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 U.S. 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 U.S. 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 at 21.0%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to a unitholder. Because a tax would be imposed upon us as a corporation, our cash available for distribution to a unitholder would be substantially reduced. Therefore, if we were treated as a corporation for federal income tax purposes, there would be a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

 

 

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

 

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

 

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

 

The tax treatment of publicly traded partnerships, or an investment in our common units, could be subject to potential legislative, judicial, or administrative changes and differing interpretations, possibly on a retroactive basis.

 

The present U.S. 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, members of Congress and the President have periodically considered substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships, including the elimination of partnership tax treatment for publicly traded partnerships. Any modification to the U.S. 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 qualifying income exception upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any such changes will ultimately be enacted. However, it is possible that a change in law could affect us, and any such changes could negatively impact the value of an investment in our common units.

 

Our unitholders’ share of our income will be taxable to them for U.S. federal income tax purposes even if they do not receive any cash distributions from us.

 

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

 

If the IRS contests the U.S. 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 U.S. federal income tax purposes. The IRS may adopt positions that differ from the positions we take, and the IRS’s positions may ultimately be sustained. The IRS or state taxing authorities could also adopt positions different than the positions we take on such matters as the attribution of taxable income among states (both for our income and the income of our employees), the determination of which types of payments to our employees are taxable and which are not, the allocation of shared expenses among affiliated entities, and other matters that require judgment in the interpretation of tax laws and regulations. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on the market for our common units, and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner, because the costs will reduce our cash available for distribution to our unitholders and for incentive distributions to our general partner.

 

If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.

 

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. Generally, we expect to elect to have our general partner and our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, but there can be no assurance that such election will be effective in all circumstances. If we are unable to have our general partner and our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties, and interest, our cash available for distribution to our unitholders might be substantially reduced.

 

 

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

 

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

 

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

 

Some of our activities may not generate qualifying income, and we conduct these activities in separate subsidiaries that are treated as corporations for U.S. federal income tax purposes. Corporate U.S. federal income taxes paid by these subsidiaries 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. To ensure that 90% or more of our gross income in each tax year is qualifying income, we currently conduct the portions of our business unrelated to these operations in separate subsidiaries that are treated as corporations for U.S. federal income tax purposes. These corporate subsidiaries will be subject to corporate-level tax, which reduces the cash available for distribution to us and, in turn, to our unitholders. If the IRS were to successfully assert that any corporate subsidiary has more tax liability than we anticipate, or legislation were enacted that increased the corporate tax rate, our cash available for distribution to our unitholders would be further reduced.

 

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

 

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

 

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

 

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

 

The U.S. Department of the Treasury and the IRS have issued Treasury Regulations that permit publicly traded partnerships to use a monthly simplifying convention that is similar to ours, but they do not specifically authorize all aspects of the proration method we have adopted. If the IRS were to successfully challenge this method, we could be required to change the allocation of items of income, gain, loss, and deduction among our unitholders.

 

 

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

 

We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss, and deduction. The IRS may challenge these methodologies or the resulting allocations, and such a challenge could adversely affect the value of our common units.

 

In determining the items of income, gain, loss, and deduction allocable to our unitholders, in certain circumstances, including when we issue additional units, we must determine the fair market value of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss, and deduction.

 

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

 

We may be required to deduct and withhold amounts from distributions to foreign unitholders related to withholding tax obligations arising from the sale or disposition of our units by foreign unitholders.

 

Upon the sale, exchange, or other disposition of a unit by a foreign unitholder, the transferee is generally required to withhold 10% of the amount realized on such sale, exchange, or other disposition, if any portion of the gain on such sale, exchange, or other disposition would be treated as effectively connected with a U. S. trade or business. If the transferee fails to satisfy this withholding requirement, we will be required to deduct and withhold such amount (plus interest) from future distributions to the transferee. Because the “amount realized” would include a unitholder’s share of our nonrecourse liabilities, 10% of the amount realized could exceed the total cash purchase price for such disposed units. Due to this fact, our inability to match transferors and transferees of units, and other uncertainty surrounding the application of these withholding rules, the U. S. Department of the Treasury and the IRS have currently suspended these rules for transfers of certain publicly traded partnership interests, including transfers of our units, until regulations or other guidance has been finalized. It is unclear when such regulations or other guidance will be finalized.

 

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

 

In addition to U.S. federal income taxes, our unitholders are likely 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 are likely required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently own property or conduct business in many states, most of which impose an income tax on individuals, corporations, and other entities. As we make acquisitions, or expand our business, we may control assets or conduct business in additional states that impose a personal income tax. It is each unitholder’s responsibility to file all federal, state, and local tax returns. Unitholders should consult their tax advisors.

 

ITEM 1B.

UNRESOLVED STAFF COMMENTS

 

Not Applicable.

 

 

ITEM 2.

PROPERTIES

 

Our Properties

 

We have an aggregate maximum daily disposal capacity of 96,800 barrels in the following water treatment facilities, all of which were built using completion techniques consistent with current industry practices and utilizing well depths of at least 5,300 feet to 6,332 feet with injection intervals beginning at least 5,010 feet beneath the surface. Our permitted capacity is much higher.

 

Location		County		In-service Date		Leased / Owned (3)
Tioga, ND		Williams		June 2011		Owned
Manning, ND		Dunn		December 2011		Owned
Grassy Butte, ND		McKenzie		May 2012		Leased
New Town, ND (1)		Mountrail		June 2012		Leased
Williston, ND (1)		Williams		August 2012		Owned
Stanley, ND		Mountrail		September 2012		Owned
Belfield, ND		Billings		October 2012		Leased
Watford City, ND (1), (2)		McKenzie		May 2013		Leased
Arnegard, ND (1)		McKenzie		August 2014		Leased

 

(1)		Currently receives piped water.
(2)		We own a 25.0% noncontrolling interest in this water treatment facility.
(3)		Some facilities are constructed on land that is leased under long-term arrangements.

 

We lease general office space at our corporate headquarters located at 5727 S. Lewis Ave., Suite 300, Tulsa, Oklahoma 74105. The lease expires in November of 2024, unless terminated earlier under certain circumstances specified in our lease. We also lease office space in Houston, TX that is shared by our Pipeline Inspection and Pipeline & Process Services segments, primarily for business development purposes. This lease expires in March of 2020. Our Pipeline & Process Services segment rents office space in Odessa, Texas on a month by month basis.

 

ITEM 3.

LEGAL PROCEEDINGS

 

Fithian v. TIR LLC

 

On October 5, 2017, a former inspector for TIR LLC and Cypress Environmental Management – TIR, LLC (“CEM TIR”) filed a putative collective action lawsuit alleging that TIR LLC, CEM TIR and Cypress Energy Partners – Texas, LLC failed to pay a class of workers overtime in compliance with the Fair Labor Standards Act (“FLSA”) titled James Fithian, et al v. TIR LLC, et al in the United States District Court for the Western District of Texas, Midland Division. The plaintiff subsequently withdrew his action and filed a similar action in Oklahoma State Court, District of Tulsa County. The plaintiff alleged he was a non-exempt employee of CEM TIR and that he and other potential class members were not paid overtime in compliance with the FLSA. The plaintiff sought to proceed as a collective action and to receive unpaid overtime and other monetary damages, including attorney’s fees. The Partnership, TIR LLC, CEM TIR and Cypress Energy Partners – Texas, LLC denied the claims.

 

On March 28, 2018, the court granted a joint stipulation of dismissal without prejudice in regard to TIR LLC and Cypress Energy Partners – Texas, LLC, as neither of those parties were employers of the plaintiff or the putative class members during the time period that is the subject of the lawsuit. On July 26, 2018, the plaintiff filed a motion for conditional class certification. CEM TIR subsequently filed pleadings opposing the motion. On January 25, 2019, the court denied the plaintiff’s motion for conditional class certification. On June 10, 2019, the court entered a scheduling order that proscribed, among other things, August 1, 2019 as the deadline for additional parties to join the lawsuit, and that the parties participate in a settlement conference or mediation no later than September 1, 2019. After the deadline, plaintiff’s counsel submitted consents for five additional inspectors to join the lawsuit, to which CEM TIR objected. On August 28, 2019, the parties participated in a settlement conference in which no settlement was reached. Subsequent to the settlement conference, CEM TIR submitted offers of judgment in immaterial amounts to the named plaintiff and the two opt-in plaintiffs. The Court entered the agreed judgment on February 25, 2020.

 

 

Sun Mountain LLC v. TIR-PUC

 

On February 27, 2019, Sun Mountain LLC (“Sun Mountain”), a subcontractor of TIR-PUC, filed a lawsuit alleging that TIR-PUC failed to pay invoices amounting to approximately $3.5 million for services subcontracted to Sun Mountain under TIR-PUC’s agreement to provide services to Pacific Gas and Electric Company. Sun Mountain filed the action in Federal District Court for the Northern District of Oklahoma. TIR-PUC denied that such amounts were owed, as conditions to TIR-PUC’s obligation to make the payments were not met. The full amount of these invoices is included within accounts payable on the accompanying Consolidated Balance Sheets at September 30, 2019 and December 31, 2018. TIR-PUC denied the claims. On October 22, 2019, the parties participated in a settlement conference at which the parties agreed to settle the lawsuit. As part of the settlement, TIR-PUC made specified cash payments in November 2019 and January 2020 and will make a final payment in July 2020. We recorded a gain of $1.3 million within other, net in the Consolidated Statement of Operations in the fourth quarter of 2019 related to this settlement.

 

Diaz v. CEM TIR

 

On December 12, 2019, three of the former inspectors who unsuccessfully attempted to join the Fithian lawsuit after the deadline set by the court filed a putative collective action lawsuit alleging that TIR LLC and CEM TIR failed to pay a class of workers overtime in compliance with the FLSA titled Francisco Diaz, et al v. CEM TIR, et al in the United States District Court for the Northern District of Oklahoma. TIR LLC and CEM TIR deny the claims.  CEM TIR and TIR LLC filed a motion to dismiss one of the plaintiffs for bringing the lawsuit in a venue that was inconsistent with the forum selection clause in his employment agreement mandating suit exclusively in the District Court of Tulsa County, Oklahoma. CEM TIR and TIR LLC also filed a motion to compel arbitration for the other two plaintiffs to enforce the binding arbitration clauses in their employment agreements. The Court has not yet ruled on either motion. The two plaintiffs with the binding arbitration provisions subsequently initiated arbitration proceedings.

 

Other

 

We have been and may in the future be subject to litigation involving allegations of violations of the Fair Labor Standards Act and state wage and hour laws. In addition, we generally indemnify our customers for claims related to the services we provide and actions we take under our contracts, including claims regarding the Fair Labor Standards Act and state wage and hour laws, and, in some instances, we may be allocated risk through our contract terms for actions by our customers or other third parties. Claims related to the Fair Labor Standards Act are generally not covered by insurance. From time to time, we are subject to various claims, lawsuits and other legal proceedings brought or threatened against us in the ordinary course of business. These actions and proceedings may seek, among other things, compensation for alleged personal injury, workers’ compensation, employment discrimination and other employment-related damages, breach of contract, property damage, environmental liabilities, multiemployer pension plan withdrawal liabilities, punitive damages and civil penalties or other losses, liquidated damages, consequential damages, or injunctive or declaratory relief.

 

ITEM 4.

MINE SAFETY DISCLOSURES

 

Not Applicable.

 

PART II

 

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

 

Our common units are listed on the NYSE under the symbol “CELP.”

 

On March 10, 2020, the closing price for the common units was $5.97 per unit and there were approximately 3,500 unitholders of record and beneficial owners (held in street name) of the Partnership’s common units. The Partnership issued approximately 5,600 federal K-1s to unitholders of record for 2019.

 

In addition to the common units we issued at our IPO date, we also issued 5,913,000 subordinated units, for which there was no established public trading market. As of December 31, 2016, 5,612,699 of the subordinated units were effectively held by Holdings and its controlled affiliates, either directly or indirectly through its ownership of CEP-TIR. The remaining 300,301 subordinated units were held directly by certain beneficial owners and management. With the payment of the February 2017 quarterly distribution and the fulfillment of other requirements as provided in the partnership agreement, on February 14, 2017, the subordination period with respect to our 5,913,000 subordinated units expired and all outstanding subordinated units converted to common units on a one-for-one basis. The conversion did not impact the total number of our outstanding units representing limited partner interests.

 

 

On May 29, 2018 we issued and sold in a private placement 5,769,231 Series A Preferred Units representing limited partner interests in the Partnership (the “Preferred Units”) for a cash purchase price of $7.54 per Preferred Unit, resulting in gross proceeds to the Partnership of $43.5 million. The purchaser of the Preferred Units is entitled to receive quarterly distributions that represent an annual return of 9.5% (which amounts to $4.1 million per year). Of this 9.5% annual return, we are required to pay at least 2.5% in cash and have the option to pay the remaining 7.0% in kind (in the form of issuing additional Preferred Units) for the first twelve quarters after the initial sale of the Preferred Units.

 

Our Cash Distribution Policy

 

Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date.  It is our intent to continue to make cash distributions to common unitholders on a quarterly basis; however, we make no representation or assurances as to the availability of future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. Our preferred units rank senior to our common units, and we must pay distributions on our preferred units (including any arrearages) before paying distributions on our common units. In addition, the preferred units rank senior to the common units with respect to rights upon liquidation.

 

Definition of Available Cash

 

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

 

	●	less, the amount of cash reserves established by our general partner at the date of determination of available cash for the quarter to:

	●	provide for the proper conduct of our business, which could include, but is not limited to, amounts reserved for capital expenditures, working capital and operating expenses;

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

	●	provide funds for distributions to our unitholders (including our general partner) for any one or more of the next four quarters;

●

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

 

Distributions

 

Although it is the Partnership’s policy to continue to make cash distributions to our common unitholders on a quarterly basis, the Partnership makes no representation or assurances as to the availability of future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial conditions, and other factors. Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter in the following manner:

 

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

 

Series A Preferred Units

 

As of March 10, 2020, we had 5,769,231 Series A Preferred Units outstanding. Until the conversion of the Series A Preferred Units into common units or their redemption, holders of the Series A Preferred Units are entitled to receive cumulative quarterly distributions equal to 9.5% per annum plus accrued and unpaid distributions. With respect to any quarter up to and including the quarter ending June 30, 2021, our general partner may elect to pay such quarterly distribution in cash, in-kind in the form of additional Series A Preferred Units or in a combination thereof, provided that a minimum of 2.5% of such distribution will be paid in cash unless the holders of the Series A Preferred Units otherwise agree. For any quarter ending after June 30, 2021, the quarterly distribution will be paid in cash. We cannot redeem, repurchase or pay any distributions on any junior securities, including any of the common units, prior to paying the quarterly distribution payable to the Series A Preferred Units, including any previously accrued and unpaid distributions.

 

 

General Partner Interest and Incentive Distribution Rights

 

Incentive distribution rights (“IDRs”) represent a common unitholder’s right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. The IDRs are effectively held by the same ownership group that own and control our general partner.

 

The following discussion assumes there are no arrearages on common units.

 

If, for any quarter, we have distributed available cash from operating surplus to our common unitholders in an aggregate amount equal to the minimum quarterly distribution, then, our partnership agreement requires that we distribute any additional available cash from operating surplus for that quarter among the common unitholders and the owner(s) of the IDRs in the following manner:

 

	●	first, 100.0% to all common unitholders, pro rata, until each common unitholder receives a total of $0.445625 per unit for that quarter (the “first target distribution”);
	●	second, 85.0% to all common unitholders, pro rata, and 15.0% to the owner(s) of the IDRs, until each common unitholder receives a total of $0.484375 per unit for that quarter (the “second target distribution”);
	●	third, 75.0% to all common unitholders, pro rata, and 25.0% to the owner(s) of the IDRs, until each common unitholder receives a total of $0.581250 per unit for that quarter (the “third target distribution”); and
	●	thereafter, 50.0% to all common unitholders, pro rata, and 50.0% to the owner(s) of the IDRs.

 

Securities Authorized for Issuance under Equity Compensation Plans

 

See “Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters” for information regarding our equity compensation plans as of December 31, 2019.

 

Unregistered Sales of Equity Securities

 

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

 

Issuer Purchases of Equity Securities

 

None.

 

 

ITEM 6.

SELECTED FINANCIAL DATA

 

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

 

Cypress Environmental Partners, L.P. (“we”, “us”, “our”, the “Partnership”) is a Delaware limited partnership formed in 2013. Trading of our common units began January 15, 2014 on the New York Stock Exchange under the symbol “CELP.” At our Initial Public Offering (“IPO”), 4,312,500 of our common units were sold to the general public. The remaining common units and 100% of the subordinated units were constructively owned by affiliates, employees, and directors of the Partnership. With the payment of the February 2017 quarterly distribution and the fulfillment of other requirements provided in the partnership agreement, on February 14, 2017, the subordination period with respect to our 5,913,000 subordinated units expired and all outstanding subordinated units converted to common units on a one-for-one basis.

 

In connection with our IPO, a 100% ownership interest in our water treatment facilities (the Environmental Services segment) and a 50.1% interest in the TIR Entities (the Pipeline Inspection segment) were contributed to us.

 

Effective February 1, 2015, we acquired the remaining 49.9% interest in the TIR Entities previously held by affiliates of Holdings. Effective May 1, 2015, we acquired a 51% interest in Brown (the Pipeline & Process Services segment).

 

The following table also presents Adjusted EBITDA, which we use in evaluating the performance and liquidity of our business. This financial measure is not calculated or presented in accordance with generally accepted accounting principles, or GAAP. We explain this measure below and reconcile it to net income and net cash from operating activities, its most directly comparable financial measures calculated and presented in accordance with GAAP.

  

 

		Year Ended December 31, 2019				Year Ended December 31, 2018				Year Ended December 31, 2017				Year Ended December 31, 2016				Year Ended December 31, 2015 (a)
		(in thousands, except cash distributions per common unit and operational data)
Income Statement Data
Revenues		$	401,648			$	314,960			$	286,342			$	297,997			$	371,191
Costs of services			347,924				270,914				252,739				262,517				326,261
Gross margin			53,724				44,046				33,603				35,480				44,930
General and administrative expense			25,626				23,744				21,055				21,853				23,795
Depreciation, amortization and accretion			4,448				4,404				4,443				4,861				5,427
Impairments			—				—				3,598				10,530				6,645
Gain on asset disposals, net			25				4,108				570				—				—
Operating income (loss)			23,675				20,006				5,077				(1,764	)			9,063
Interest expense, net			5,330				6,206				7,335				6,559				5,656
Net income (loss)			17,424				12,098				(1,923	)			(9,162	)			4,091
Net income (loss) attributable to noncontrolling interests			1,410				685				(1,110	)			(4,499	)			599
Net income (loss) attributable to partners / controlling interests			16,014				11,413				(813	)			(4,663	)			3,492
Net income attributable to preferred unitholders			4,133				2,445				—				—				—
Net income (loss) attributable to common unitholders			11,881				8,968				3,237				819				2,071
Balance Sheet Data - Period End
Total assets		$	157,342			$	152,853			$	163,203			$	167,512			$	190,882
Current portion of long-term debt			—				—				136,293				—				—
Long-term debt			74,929				76,129				—				135,699				139,129
Finance lease obligations			542				338				—				—				—
Total owners’ equity			58,191				54,287				9,985				19,388				40,702
Cash Flow Data
Cash flows from operating activities		$	18,179			$	15,409			$	8,253			$	24,819			$	26,921
Cash flows from investing activities			(1,933	)			7,007				(1,041	)			(1,330	)			(64,879	)
Cash flows from financing activities			(15,930	)			(31,466	)			(10,150	)			(21,289	)			42,501
Cash distributions per common unit (b)			0.84				0.84				0.84				1.63				1.63
Capital expenditures (cash basis)			1,976				5,762				3,345				1,376				1,857
Other Financial Data
Adjusted EBITDA			31,430			$	23,102			$	16,640			$	19,794			$	24,663
Adjusted EBITDA attributable to limited partners / controlling interests			29,454				21,883				18,692				22,238				23,147
Distributable cash flow			18,083				12,860				10,018				15,521				17,207
Operational Data
Average number of inspectors (PI segment)			1,485				1,214				1,145				1,147				1,392
Average revenue per inspector per week (PI segment)		$	4,804			$	4,551			$	4,499			$	4,601			$	4,711
Average number of field personnel (PPS segment) (c)			28				23				20				23				33
Average revenue per field personnel per week (PPS segment)		$	13,245			$	12,508			$	8,887			$	11,577			$	12,653
Total barrels of water processed (in thousands)			13,416				14,782				12,588				13,307				18,864
Average revenue per barrel		$	0.77			$	0.80			$	0.67			$	0.67			$	0.78

 

(a)	Activity for the year ended December 31, 2015 includes operations of Brown (PPS segment) from the May 1, 2015 acquisition date to the end of the year.
(b)	Includes distributions paid in February related to the previous quarter ended December 31.
(c)	Represents Brown (PPS segment) personnel from the May 1, 2015 acquisition date.

 

Non-GAAP Financial Measures

 

We define Adjusted EBITDA as net income (loss); plus interest expense; depreciation, amortization and accretion expenses; income tax expense; impairments; non-cash allocated expenses; equity-based compensation expense; less certain other unusual or non-recurring items. We define Adjusted EBITDA attributable to limited partners as net income (loss) attributable to limited partners; plus interest expense attributable to limited partners; depreciation, amortization and accretion expenses attributable to limited partners; impairments attributable to limited partners; income tax expense attributable to limited partners; non-cash allocated expenses attributable to limited partners; and equity-based compensation attributable to limited partners; less certain other unusual or non-recurring items attributable to limited partners. We define Distributable Cash Flow as Adjusted EBITDA attributable to limited partners less cash interest paid, cash income taxes paid, maintenance capital expenditures, and cash distributions on preferred equity. Adjusted EBITDA, Adjusted EBITDA attributable to limited partners, and Distributable Cash Flow are used as supplemental financial measures 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;

 

●

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

 

●

the ability of our assets to generate cash sufficient to make debt payments and to make distributions.

 

We believe that the presentation of these non-GAAP measures provides useful information to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA, Adjusted EBITDA attributable to limited partners, and Distributable Cash Flow are net income (loss) and cash flow from operating activities. These non-GAAP measures should not be considered as alternatives to the most directly comparable GAAP financial measures. Each of these non-GAAP measures excludes some, but not all, of the items that affect the most directly comparable GAAP financial measures. Adjusted EBITDA, Adjusted EBITDA attributable to limited partners, and Distributable Cash Flow should not be considered alternatives to net income (loss), income (loss) before income taxes, net income (loss) attributable to limited partners, cash flows from operating activities, or any other measure of financial performance calculated in accordance with GAAP, as those items are used to measure operating performance, liquidity, or the ability to service debt obligations.

 

Because Adjusted EBITDA, Adjusted EBITDA attributable to limited partners, and Distributable Cash Flow may be defined differently by other companies, our definitions of Adjusted EBITDA, Adjusted EBITDA attributable to limited partners, and Distributable Cash Flow may not be comparable to a similarly titled measure of other companies, thereby diminishing their utility.

 

The following tables present a reconciliation of net income (loss) to Adjusted EBITDA and to Distributable Cash Flow, a reconciliation of net income attributable to limited partners to Adjusted EBITDA attributable to limited partners and to Distributable Cash Flow, and a reconciliation of net cash provided by operating activities to Adjusted EBITDA and to Distributable Cash Flow for each of the periods indicated.

 

 

Reconciliation of Net Income (Loss) to Adjusted EBITDA

and to Distributable Cash Flow

 

		Years ended December 31,
		2019				2018				2017
						(in thousands)
Net income (loss)		$	17,424			$	12,098			$	(1,923	)
Add:
Interest expense			5,330				6,206				7,335
Debt issuance cost write-off			—				114				—
Depreciation, amortization and accretion			5,537				5,480				5,544
Impairments			—				—				3,598
Income tax expense			2,254				1,318				596
Non-cash allocated expenses			—				—				1,750
Equity based compensation			1,107				1,247				1,059
Foreign currency losses			—				643				—
Less:
Gains on asset disposals, net			—				4,004				587
Foreign currency gains			222				—				732
Adjusted EBITDA		$	31,430			$	23,102			$	16,640
Adjusted EBITDA attributable to general partner			—				—				(2,300	)
Adjusted EBITDA attributable to noncontrolling interests			1,976				1,219				248
Adjusted EBITDA attributable to limited partners / controlling interests		$	29,454			$	21,883			$	18,692
Less:
Preferred unit distributions			4,133				1,412				—
Cash interest paid, cash taxes paid, maintenance capital expenditures attributable to limited partners			7,238				7,611				8,674
Distributable cash flow		$	18,083			$	12,860			$	10,018

 

Reconciliation of Net Income Attributable to Limited Partners to Adjusted

EBITDA Attributable to Limited Partners and to Distributable Cash Flow

 

		Years ended December 31,
		2019				2018				2017
						(in thousands)
Net income attributable to limited partners			16,014			$	11,413			$	3,237
Add:
Interest expense attributable to limited partners			5,330				6,206				7,335
Debt issuance costs attributable to limited partners			—				114				—
Depreciation, amortization and accretion attributable to limited partners			5,006				4,974				4,977
Impairments attributable to limited partners			—				—				2,823
Income tax expense attributable to limited partners			2,219				1,290				580
Equity based compensation attributable to limited partners			1,107				1,247				1,059
Foreign currency losses attibutable to limited partners			—				643				—
Less:
Gains on asset disposals attributable to limited partners, net			—				4,004				587
Foreign currency gains attributable to limited partners			222				—				732
Adjusted EBITDA attributable to limited partners			29,454				21,883				18,692
Less:
Preferred unit distributions			4,133				1,412				—
Cash interest paid, cash taxes paid and maintenance capital expenditures attributable to limited partners			7,238				7,611				8,674
Distributable cash flow		$	18,083			$	12,860			$	10,018

 

 

Reconciliation of Net Cash Provided by Operating Activities to

Adjusted EBITDA and to Distributable Cash Flow

 

		Years ended December 31,
		2019				2018				2017
						(in thousands)
Cash flows provided by operating activities		$	18,179			$	15,409			$	8,253
Changes in trade accounts receivable, net			4,247				7,165				3,406
Changes in prepaid expenses and other			(136	)			(1,004	)			1,321
Changes in accounts payable and accrued liabilities			1,506				(5,440	)			(4,471	)
Changes in income taxes payable			(356	)			(87	)			365
Interest expense (excluding non-cash interest)			4,797				5,646				6,741
Income tax expense (excluding deferred tax benefit)			2,290				1,267				968
Other			903				146				57
Adjusted EBITDA		$	31,430			$	23,102			$	16,640
Adjusted EBITDA attributable to general partner			—				—				(2,300	)
Adjusted EBITDA attributable to noncontrolling interests			1,976				1,219				248
Adjusted EBITDA attributable to limited partners / controlling interests		$	29,454			$	21,883			$	18,692
Less:
Preferred unit distributions			4,133				1,412				—
Cash interest paid, cash taxes paid, maintenance capital expenditures			7,238				7,611				8,674
Distributable cash flow		$	18,083			$	12,860			$	10,018

 

 

ITEM 7.

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

 

This Management’s Discussion and Analysis of Financial Condition and Results of Operations contains a discussion of our business, including a general overview of our properties, our results of operations, our liquidity and capital resources, and our quantitative and qualitative disclosures about market risk.

 

The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs, and expected performance. The forward-looking statements are dependent upon events, risks, and uncertainties that may be outside our control, including among other things, the risk factors discussed in “Item 1A. Risk Factors” of this Annual Report on Form 10-K. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil and natural gas, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this Annual Report on Form 10-K, all of which are difficult to predict. In light of these risks, uncertainties, and assumptions, the forward-looking events discussed may not occur. See “Cautionary Remarks Regarding Forward-Looking Statements” in the front of this Annual Report on Form 10-K.

 

Overview

 

We are a growth-oriented master limited partnership formed in September 2013. We offer essential services that help protect the environment and ensure sustainability. We provide a wide range of environmental services including independent inspection, integrity, and support services for pipeline and energy infrastructure owners and operators and public utilities. We also provide water pipelines, hydrocarbon recovery, disposal, and water treatment services. The Pipeline Inspection segment comprises the operations of our TIR Entities and the Pipeline & Process Services segment comprises the operations of Brown. We also provide water treatment and other water and environmental services to U.S. onshore oil and natural gas producers and trucking companies through our Environmental Services segment. We operate nine (eight wholly-owned) water treatment facilities, all of which are in the Bakken Shale region of the Williston Basin in North Dakota. We also have a management agreement in place to provide staffing and management services to one 25%-owned water treatment facility in the Bakken Shale region. In all of our 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, assisting in reducing their operating costs.

 

How We Generate Revenue

 

The Pipeline Inspection segment generates revenue primarily by providing essential environmental services including inspection and integrity services on a variety of infrastructure assets including midstream pipelines, gathering systems, and distribution systems. Services include nondestructive examination, in-line inspection support, pig tracking, survey, data gathering, and supervision of third-party contractors. Our results in this segment are driven primarily by the number of inspectors that perform services for our customers and the fees that we charge for those services, which depend on the type, skills, technology, equipment, and number of inspectors used on a particular project, the nature of the project, and the duration of the project. The number of inspectors engaged on projects is driven by the type of project, prevailing market rates, the age and condition of customers’ assets including pipelines, gas plants, compression stations, storage facilities, and gathering and distribution systems including the legal and regulatory requirements relating to the inspection and maintenance of those assets. We also bill our customers for per diem charges, mileage, and other reimbursement items. Revenue and costs in this segment may be subject to seasonal variations and interim activity may not be indicative of yearly activity considering many of our customers develop yearly operating budgets and enter into contracts with us during the winter season for work to be performed during the remainder of the year. Additionally, inspection work throughout the United States during the winter months (especially in the northern states) may be hampered or delayed due to inclement weather.

 

 

The Pipeline & Process Services segment (formerly our Integrity Services segment) generates revenue primarily by providing essential environmental services including hydrostatic testing services and chemical cleaning to energy companies and pipeline construction companies on newly-constructed and existing pipelines and related infrastructure. We generally charge our customers in this segment on a fixed-bid basis, with the price depending on the size and length of the pipeline being tested, the complexity of services provided, and the utilization of our work force and equipment. Our results in this segment are driven primarily by the number of field personnel that perform services for our customers and the fees that we charge for those services, which depend on the type and number of field personnel used on a particular project, the type of equipment used and the fees charged for the utilization of that equipment, and the nature and duration of the project.

 

The Environmental Services segment owns and operates nine (9) water treatment facilities with ten (10) EPA Class II injection wells in the Bakken shale region of the Williston Basin in North Dakota.  These water treatment facilities are connected to twelve (12) pipeline gathering systems, including two (2) that we developed and own. We specialize in the treatment, recovery, separation, and disposal of waste byproducts generated during the lifecycle of an oil and natural gas well to protect the environment and our drinking water. All of the water treatment facilities utilize specialized equipment and remote monitoring to minimize the facilities’ downtime and increase the facilities’ efficiency for peak utilization. Revenue is generated on a fixed-fee per barrel basis for receiving, separating, filtering, recovering,  processing, and injecting produced and flowback water. We also sell recovered oil, receive fees for pipeline transportation of water, and receive fees from a partially owned water treatment facility for management and staffing services  (see Note 11).

 

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. These metrics include:

 

	●	inspector headcount in our Pipeline Inspection segment;
	●	gross margin percentages in our Pipeline Inspection segment;
	●	field personnel headcount and utilization in our Pipeline & Process Services segment;
	●	water treatment and residual oil volumes in our Environmental Services segment;
	●	operating expenses;
	●	segment gross margin;
	●	safety metrics;
	●	Adjusted EBITDA;
	●	maintenance and capital expenditures; and
	●	distributable cash flow.

 

 

Inspector Headcount

 

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

 

Field Personnel Headcount and Utilization

 

The amount of revenue we generate in our Pipeline & Process Services segment depends primarily on the number of field personnel that perform services for our customers and the fees that we charge for those services, which depend on the type and number of field personnel used on a particular project, the type of equipment used and the fees charged for the utilization of that equipment, and the nature and the duration of the project. The number of field personnel engaged on projects is driven by the type of project, the size and length of the pipeline being inspected, the complexity of services provided, and the utilization of our work force and equipment. The employees of the Pipeline & Process Services segment are full-time employees, and therefore represent fixed costs (in contrast to the employees of the Pipeline Inspection segment who perform work in the field, most of whom only earn wages when they are performing work for a customer and whose wages are therefore primarily variable costs).

 

Water Treatment and Residual Oil Volumes

 

The amount of revenue we generate in the Environmental 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 rates that are determined based on the quality of the oil sold and prevailing oil prices. Most of the revenue generated from water delivered to our facilities by truck is generated pursuant to contracts that are short-term in nature. Most of the revenue generated from water delivered to our facilities by pipeline is generated pursuant to contracts that are several years in duration. The volumes of water processed at our water treatment 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 new 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 natural gas liquids, 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 natural gas liquids.

 

Approximately 6%, 5%, and 7% of our Environmental Services segment revenue in 2019, 2018, and 2017, respectively, was derived from sales of residual oil recovered during the water treatment process. Our ability to recover residual oil is dependent upon the oil content in the water we treat, which is, among other things, a function of water type, chemistry, source, and temperature. Generally, where outside temperatures are lower, oil separation is more difficult. Thus, our residual oil recovery during the winter season is lower than our recovery during the summer season. 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.

 

Operating Expenses

 

The primary components of our operating expenses include cost of services, general and administrative, and depreciation, amortization and accretion.

 

Costs of services. Employee-related costs and reimbursable expenses are the primary cost of services components in the Pipeline Inspection and Pipeline & Process Services segments. These expenses fluctuate based on the number, type, and location of projects on which we are engaged at any given time. Repair and maintenance costs, employee-related costs, residual oil disposal costs, lease expenses, and utility expenses are the primary cost of services components in the Environmental Services segment. These expenses generally remain relatively stable with fluctuations in  volumes of water processed (although certain expenses, such as utilities, vary based on the volume of water processed) but can fluctuate from period to period depending on the mix of activities performed during that period and the timing of these expenses.

 

General and administrative. General and administrative expenses include compensation and related costs of employees performing general and administrative functions, general office expenses, insurance, legal and other professional fees, and other expenses.

 

Depreciation, amortization and accretion. Depreciation, amortization and accretion expense primarily consists of the decrease in value of assets as a result of using the assets over their estimated useful life. Depreciation and amortization are recorded on a straight-line basis. We estimate that our assets have useful lives ranging from 3 to 39 years. The fixed assets of our Environmental Services segment constituted approximately 69% of the net book value of our consolidated fixed assets as of December 31, 2019.

 

 

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, defined as net income (loss) plus interest expense, depreciation and amortization expense, income tax expense, impairments, non-cash allocated expenses, and equity-based compensation (less certain other unusual or non-recurring items). We use distributable cash flow, defined as Adjusted EBITDA less cash interest paid, cash taxes paid, maintenance capital expenditures, and cash distributions on preferred equity, as an additional measure to analyze our performance. Distributable cash flow does not reflect changes in working capital balances, which could be significant, as headcounts of the Pipeline Inspection segment vary from period to period. Adjusted EBITDA and distributable cash flow are non-GAAP, supplemental financial measures used by management and by external users of our financial statements, such as investors, lenders, and 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; and
	●	our ability to incur and service debt and fund capital expenditures.

 

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 provides useful information to investors in assessing our financial condition and results of operations. Net income (loss) 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 measures. Each of these non-GAAP financial measures has important limitations as an analytical tool because it excludes some, but not all, of the items that affect the most directly comparable GAAP financial measure. You should not consider Adjusted EBITDA or distributable cash flow in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

 

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

 

Overview and Outlook

 

Revenues of our Pipeline Inspection segment increased from $288.1 million in 2018 to $372.0 million in 2019, an increase of 29%. Gross margins in this segment increased from $31.6 million in 2018 to $40.5 million in 2019, an increase of 28%. This increase was due to high demand for our services and increased business development efforts. During the fourth quarter of 2018, we began work on the largest contract in the 17-year history of TIR. The headcount for this pipeline inspection project peaked in the second quarter of 2019, and this project continued, with declining headcounts, into early 2020. In 2019, we generated an increased percentage of our revenue from inspection services (due in part to the pipeline inspection project that represented the largest contract award in our history), which typically carry lower margins than integrity services. The resulting decrease in gross margin percentage was partially offset by increased activity in our business that serves public utility customers, as these services typically generate higher margins than our other inspection services.

 

Revenues of our Pipeline & Process Services segment increased from $15.0 million in 2018 to $19.3 million in 2019, an increase of 29%. The increase was due in part to increasing demand and in part to improved business development efforts. Gross margins in this segment increased from $4.3 million in 2018 to $5.9 million in 2019, an increase of 38%. We began 2020 with a solid project backlog and have had robust bidding activity on new projects.

 

 

Revenues of our Environmental Services segment decreased from $11.9 million during 2018 to $10.3 million in 2019, a decrease of 13%. The decrease was primarily due to a decrease of 1.4 million barrels of water processed in 2019 compared to 2018. The decrease in volume resulted from a slowdown in exploration and production activity in the areas near our facilities. Gross margins in this segment decreased from $8.1 million in 2018 to $7.3 million in 2019, a decrease of 10%. The decrease in gross margin was due primarily to a $1.6 million decrease in revenue, partially offset by a $0.8 million decrease in cost of services.

 

In 2018, our sponsor, Holdings completed two acquisitions to further broaden our collective suite of environmental services. Importantly, these acquisitions also provided entry into the municipal water industry, whereby we can offer our traditional inspection services, including corrosion and nondestructive testing services, as well as in-line inspection (“ILI”). We remain excited about entering the ILI industry with next generation 5G ultra high-resolution magnetic flux leakage (“MFL”) ILI technology called EcoVision UHD, capable of helping pipeline owners and operators better manage the integrity of their assets in both the municipal water and energy industries.

 

The U.S. Pipeline and Hazardous Materials Safety Administration (“PHMSA”) recently finalized a rule that significantly revises certain aspects of the hazardous liquid pipeline safety regulations codified at Title 49 Code of Federal Regulations Parts 190-199. Nearly nine years in the making, the final rule is PHMSA’s response to several significant hazardous liquid pipeline accidents that have occurred in recent years, most notably the 2010 crude oil spill near Marshall, Michigan. The final rule also addresses 2011 and 2016 outstanding congressional mandates and U.S. Government Accountability Office recommendations. Effective July 1, 2020, this rule expands requirements to address risks to pipelines outside of environmentally sensitive and populated areas, requiring the performance of periodic integrity assessments and the use of leak detection systems for all regulated hazardous liquids pipelines (except for offshore gathering and regulated rural gathering lines). In addition, the rule makes changes to the integrity management requirements, including revising data integration requirements and emphasizing the use of in-line inspection technology.  The long-term increasing demand for environmental services such as pipeline inspection, integrity services, and water solutions remains strong due to our nation’s aging pipeline infrastructure, and we believe we continue to be well-positioned to capitalize on these opportunities. Our General Partner continues to remain fully aligned with our noncontrolling unitholders, as our General Partner and its affiliates collectively own 76% of our total common and preferred units.

 

In recent years, many companies have been active in constructing new energy infrastructure, such as pipelines, gas plants, compression stations, and storage facilities, which has afforded us the opportunity to provide services on large projects. Currently, many energy companies face challenging market conditions, including lower commodity prices, the COVID-19 pandemic, and negative investor sentiment. Crude oil prices have decreased significantly in 2020, due in part to decreased demand as a result of a recent worldwide COVID-19 outbreak, and due in part to the oil price war started by Russia and Saudi Arabia with a focus on slowing down U.S. oil production. This decline in oil prices will likely lead our customers to change their budgets and plans, which will decrease their spending on drilling, completions, and exploration. This could have an impact on construction of new pipelines, gathering systems, and related energy infrastructure. Lower exploration and production activity will also impact the midstream industry and could lead to delays or cancellations of projects. It is also possible that our customers may elect to defer maintenance activities on their infrastructure. Such developments would reduce our opportunities to generate revenues. It is impossible at this time to determine what may occur, as customer plans will evolve over time and there is a possibility that Saudi Arabia and Russia will make a new deal to lift oil prices.  It is possible that the cumulative nature of these events could have a material adverse effect on our results of operations and financial position. These market conditions could also have a material adverse effect on the financial position of our customers, which could increase the risk that we are unable to collect accounts receivable from customers for services we have provided. We would aggressively act to protect our rights in any such event, as we have done in the past. We have taken incremental steps to monitor counterparty risks. 

 

Pipeline Inspection

 

We operate in a very large market, with more than 3,000 customer prospects who require federally and/or state-mandated inspection and integrity services. During the third quarter of 2018, we signed the largest contract in the 17-year history of TIR and began work on this project in the fourth quarter of 2018. The headcount for this pipeline inspection project peaked in the second quarter of 2019, and this project continued, with declining headcounts, into early 2020.

 

Our focus remains on maintenance and integrity work on existing pipelines, as well as work on new projects. The majority of our clients are large public companies with long planning cycles that lead to healthy backlogs of new long-term projects and existing pipeline networks that also require inspection and integrity services. We believe that regulatory requirements, coupled with the aging pipeline infrastructure, mean that, regardless of commodity prices, our customers will require our inspection services. However, a prolonged downturn in oil and natural gas prices could lead to a downturn in demand for our services.

 

Pipeline & Process Services

 

During the third quarter of 2018, we opened a new office in Odessa, Texas, to better serve the growing Permian basin market. In addition, we added several industry veterans to our management team in order to further enhance our image and grow the segment. In early 2019, we opened a new location in the Houston market that will help us take advantage of the growing market in the industry. In 2019, Brown worked in eight states and obtained new business from TIR relationships. Brown continues to enjoy an excellent reputation in the industry and continues to bid on a substantial amount of new work.

 

 

Environmental Services

 

Drilling activity improved dramatically following the downturn and the lows that occurred in May 2016. According to a published rig count as of March 6, 2020, the Williston basin of the Bakken totaled 52 rigs, up 136% from its trough of 22 in May 2016, and down 15% from its subsequent peak of 61 in April 2019.

 

We continue to focus on produced water and pipeline water by pursuing pipeline water opportunities whenever possible to secure additional long-term volumes of produced water for the life of the oil and gas wells’ production. During 2019, 93% of our volumes were produced water and 41% of our volumes were delivered via ten pipelines, including two that we constructed and own. 

 

In July of 2017, a lightning strike at our Grassy Butte water treatment facility initiated a fire that destroyed the surface storage equipment at the facility. It did not damage our pumps, electrical, housing, office, or downhole facilities. We had insurance covering the surface facilities with a reasonable deductible. We rebuilt and reopened the Grassy Butte facility in June 2018.

 

In January of 2018, we sold our subsidiary that owned a water treatment facility in Pecos, Texas to an unrelated party for $4.0 million of cash proceeds and a perpetual royalty interest in the future revenues of the facility. In May of 2018, we sold our subsidiary that owns a water treatment facility in Orla, Texas to an unrelated party for $8.2 million. We used the proceeds from these sales to reduce our outstanding long-term debt.

 

Pacific Gas and Electric Bankruptcy

 

PG&E Corporation and its wholly-owned subsidiary Pacific Gas and Electric Company (collectively, “PG&E”) filed for bankruptcy protection on January 29, 2019. PG&E cited as the reason for its bankruptcy filing the fact that PG&E might become liable for paying damages to those affected by certain wildfires that occurred in 2017 and 2018. Regulators have completed investigations and have found PG&E responsible for certain of the wildfires and not responsible for others. Investigations of certain of the other wildfires are ongoing. PG&E has asserted that filing for bankruptcy protection will enable it to continue its normal operations until any liabilities associated with the wildfires can be resolved.

 

PG&E is a significant customer that accounted for $50.7 million of the revenue and $8.7 million of the gross margin of our Pipeline Inspection segment during 2019. As of December 31, 2018, the assets on our Consolidated Balance Sheet included $10.3 million of accounts receivable from PG&E. We collected $1.0 million of this balance in January 2019 prior to PG&E’s bankruptcy filing. We generated $2.8 million of revenue from PG&E during the period from January 1, 2019 through January 28, 2019, bringing the total accounts receivable from PG&E to $12.1 million as of the date of the bankruptcy filing.

 

In November 2019, we sold $10.4 million of our pre-petition receivables from PG&E in a non-recourse sale to a third party for cash proceeds of $9.8 million. We recorded a loss of $0.5 million on the sale of these pre-petition receivables reported within other, net on our Consolidated Statement of Operations. In March 2020 we collected from PG&E the remaining $1.7 million of pre-petition receivables under a court-approved “operational integrity supplier program”. 

 

Our relationship with PG&E remains strong. We have continued to provide services to PG&E after their bankruptcy filing and we value our business relationship. We have been receiving timely payment for such post-petition services.

 

Sanchez Bankruptcy

 

Sanchez Energy Corporation and certain of its affiliates (collectively, “Sanchez”), a former customer, filed for bankruptcy protection in August 2019. As of December 31, 2019, our Consolidated Balance Sheet included $0.5 million of pre-petition accounts receivable from Sanchez. We have filed liens to secure $0.4 million of these accounts receivable. We have recorded an allowance of less than $0.1 million at December 31, 2019 against the accounts receivable from Sanchez. We do not believe it is probable that we will be unable to collect the remaining $0.4 million balance of the pre-petition receivables. However, due to uncertainties associated with the bankruptcy process, we cannot make assurances regarding the ultimate collection of these receivables nor can we make assurances regarding the timing of any such collections.

 

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 make estimates and assumptions that affect the reported amounts of assets, liabilities, revenue and expenses. See “Note 2 — Summary of Significant Accounting Policies” in the audited financial statements included in “Item 8 — Financial Statements and Supplementary Data” for descriptions of our major accounting policies and estimates. Certain of these accounting policies and estimates involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts could 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.

 

 

Business Combinations and Intangible Assets Including Goodwill

 

We account for acquisitions of businesses using the acquisition method of accounting. Accordingly, assets acquired and liabilities assumed are recorded at their estimated fair values at the acquisition date. The excess of purchase price over fair value of net assets acquired, including the amount assigned to identifiable intangible assets, is recorded as goodwill. The results of operations of acquired businesses are included in the Consolidated Financial Statements from the acquisition date.

 

Impairments of Long-Lived Assets

 

Property and Equipment

 

We assess property and equipment for possible impairment whenever events or changes in circumstances indicate that the carrying value of the assets may not be recoverable. Such indicators include, among others, the nature of the asset, the projected future economic benefit of the asset, changes in regulatory and political environments, and historical and future cash flow and profitability measurements. If the carrying value of an asset group exceeds the undiscounted cash flows estimated to be generated by the asset group, we recognize an impairment loss equal to the excess of carrying value of the asset group over its estimated fair value. Estimating the future cash flows and the fair value of an asset group involves management estimates on highly uncertain matters such as future commodity prices, the effects of inflation on operating expenses, and the outlook for national or regional market supply and demand for the services we provide.

 

For our Environmental Services segment, we evaluate property and equipment for impairment at the water treatment facility level. Our estimates utilize judgments and assumptions such as undiscounted future cash flows, discounted future cash flows, estimated fair value of the asset group, and economic environment in which the asset is operated. Significant judgments and assumptions in these assessments include estimates of rates for water treatment services, volumes of water processed, expected capital costs, oil and gas drilling and producing volumes in the markets served, risks associated with the different zones into which water is processed, and our estimate of an applicable discount rate commensurate with the risk of the underlying cash flow estimates.

 

During 2017, we identified impairment indicators at one of our water treatment facilities and reviewed the associated property and equipment for impairment. We recognized impairment charges of $0.7 million during 2017 for assets that were determined to be impaired, primarily driven by the dramatic decline in oil prices. These impairment reviews utilized inputs generally consistent with those described above. Judgments and assumptions are inherent in our estimate of future cash flows used to evaluate these assets. The use of alternate judgments and assumptions could result in the recognition of different levels of impairment charges in the Consolidated Financial Statements.

 

An estimate as to the sensitivity to earnings for these periods had we used other assumptions in our impairment reviews and impairment calculations is not practicable, given the number of assumptions involved in the estimates. Favorable changes to some assumptions might have obviated the need to impair any assets in these periods, whereas unfavorable changes might have caused an additional unknown number of other assets to become impaired. Additionally, further unfavorable changes in the future are reasonably possible, and therefore, it is possible that we may incur additional impairment charges in the future.

 

Identifiable Intangible Assets

 

Our recorded net identifiable intangible assets of $20.1 million and $22.8 million at December 31, 2019 and 2018, respectively, consist primarily of customer relationships and trademarks and trade names, amortized on a straight-line basis over estimated useful lives ranging from 5 – 20 years. Identifiable intangible assets with finite lives are amortized on a straight-line basis over their estimated useful lives, which is the period over which the asset is expected to contribute directly or indirectly to our future cash flows. We have no indefinite-lived intangibles other than goodwill. The determination of the fair value of the intangible assets and the estimated useful lives are based on an analysis of all pertinent factors including (1) the use of widely-accepted valuation approaches, such as 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/or 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.

 

In 2017, we ceased to perform certain services for the largest customer of the Canadian subsidiary of our Pipeline Inspection segment, as these services generated low margins and high general and administrative and income tax expenses. In consideration of this, we recorded impairments to the carrying values of certain intangible assets of $1.3 million in the first quarter of 2017. Of this amount, $1.1 million related to customer relationships and $0.2 million related to trade names. Based on discounted cash flow calculations, we concluded the fair value of the customer relationships and trade names of our Canadian business was zero, and therefore we impaired the full amounts.

 

 

Goodwill

 

At December 31, 2019 and 2018, we had $50.4 million and $50.3 million, respectively, of goodwill on our Consolidated Balance Sheets. Goodwill is not amortized, but is subject to annual reviews on November 1 for impairment (or at other dates if events or changes in circumstances indicate that the carrying value of goodwill may be impaired) at a reporting unit level. The reporting units are determined primarily from the manner in which the business is managed and operated. A reporting unit is an operating segment or a component that is one level below an operating segment. We have determined that the Pipeline Inspection, Pipeline & Process Services, and Environmental Services segments are the appropriate reporting units for testing goodwill impairment.

 

To perform a goodwill impairment assessment, we first evaluate qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit exceeds its carrying value. If this assessment reveals that it is more likely than not that the carrying value of a reporting unit exceeds its fair value, we then determine the estimated fair market value of the reporting unit. If the carrying amount exceeds the reporting unit’s fair value, we record a goodwill impairment charge for the excess (not exceeding the carrying value of the reporting unit’s goodwill).

 

Our estimates of fair value are sensitive to changes in a number of variables, certain of which relate to broader macroeconomic conditions outside our control. As a result, actual performance 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. In addition, some of the estimates and assumptions used in determining the fair value of the reporting units are outside the control of management, including commodity prices, interest rates, cost of capital, and our credit ratings. The facilities of our Environmental Services reporting units are concentrated in one basin, and changes in oil and gas production in this basin could have a significant impact on the profitability of this reporting unit. While we believe we have made reasonable estimates and assumptions to estimate the fair values of our reporting units, it is reasonably possible that changes could occur that would require a goodwill impairment charge in the future.

 

Pipeline Inspection

 

We completed our annual goodwill impairment assessment as of November 1, 2019 and concluded the $40.3 million of goodwill of the Pipeline Inspection segment was not impaired. Our evaluations included various qualitative factors, including current and projected earnings and current customer relationships and projects. The qualitative assessments on this reporting unit indicated that there was no need to conduct further quantitative testing for goodwill impairment. The use of different assumptions and estimates from the assumptions and estimates we used in our qualitative analyses could have resulted in the requirement to perform quantitative goodwill impairment analyses.

 

Pipeline & Process Services

 

In the first quarter of 2017, we recorded an impairment to the remaining $1.6 million carrying value of the goodwill of the Pipeline & Process Services segment. Revenues of this segment were lower than we had expected for the first quarter of 2017. In addition, for this segment, the level of bidding activity for work is typically high in March and April once customers have finalized their budgets for the upcoming year. While we won bids on a number of projects and our backlog began to improve, the improvement in the backlog was slower than we had originally anticipated, and we revised downward our expectations of the near-term operating results of the segment. We estimated the fair value of the Pipeline & Process Services segment utilizing the income approach (discounted cash flows) valuation method, which is a Level 3 input as defined in ASC 820, Fair Value Measurement. Significant inputs in the valuation included projections of future revenues, anticipated operating costs and appropriate discount rates. Significant assumptions included a 2% annual growth rate of cash flows and a discount rate of 18%. We determined through this analysis that the fair value of goodwill of the Pipeline & Process Services segment was fully impaired.

 

Environmental Services

 

We completed our annual goodwill impairment assessment as of November 1, 2019 and concluded that the remaining $10.1 million of goodwill of the Environmental Services segment was not impaired. We performed a qualitative analysis that took into consideration current and projected earnings, current customer relationships, and the fact that we sold two of our water treatment facilities in 2018 at prices that exceeded their carrying values for a combined gain of $3.6 million, which is included in gain on asset disposals, net in our Consolidated Statement of Operations for 2018. Based on these qualitative considerations, we concluded that the remaining carrying value of the goodwill of the Environmental Services segment was not impaired. The use of different assumptions and estimates from the assumptions and estimates we used in our qualitative analyses could have resulted in the requirement to perform quantitative goodwill impairment analyses.

 

 

Revenue Recognition

 

Under Accounting Standards Codification (“ASC”) 606 - Revenue from Contracts with Customers, an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Based on this accounting guidance, our revenue is earned and recognized through the service offerings of our three reportable business segments. Our sales contracts have terms of less than one year. As such, we have used the practical expedient contained within the accounting guidance which exempts us from the requirement to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract with an original expected duration of one year or less. We apply judgment in determining whether we are the principal or the agent in instances where we utilize subcontractors to perform all or a portion of the work under our contracts. Based on the criteria in ASC 606, we have determined we are principal in all such circumstances. 

 

In the third quarter of 2019 and 2018, we recognized $0.2 million and $0.5 million of revenue within our Pipeline Inspection segment, respectively, on services performed in previous years. We had constrained recognition of this revenue until the expiration of a contract provision that had given the customer the opportunity to reopen negotiation of the fee paid for the services. As of December 31, 2019 and December 31, 2018, we recognized a refund liability of $0.7 million and $0.4 million within our Pipeline Inspection segment, respectively, for revenue associated with such variable consideration. In the fourth quarter of 2019, we received a signed contract modification from one of our customers for a price increase that was retroactive to June 2019. We recognized $0.5 million of revenue within our Pipeline Inspection segment in the fourth quarter of 2019 related to this retroactive price increase.  In the first quarter of 2018, we recognized $0.3 million of revenue within our Pipeline & Process Services segment associated with additional billings on a project that we completed in the fourth quarter of 2017 (we recognized the revenue upon receipt of customer acknowledgment of the additional fees).

 

Consolidated Results of Operations – Cypress Environmental Partners, L.P.

 

Factors Impacting Comparability

 

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

 

	●	In 2018, we issued $43.5 million of preferred equity and made net payments of $60.8 million on our revolving credit facility.
	●	We recorded net gains on asset disposals of $4.1 million in 2018.
	●	We recorded impairments of long-lived assets totaling $3.6 million in 2017.
	●	During 2017, Holdings waived $2.0 million of the $4.0 million annual administrative fee that we otherwise would have owed to Holdings. We reported the $1.8 million of expense incurred by Holdings but not charged to us within general and administrative in our Consolidated Statements of Operations. In addition, Holdings provided us with additional financial support by making cash contributions of $2.3 million in 2017 as a reimbursement for certain expenditures incurred by the Partnership. These cash contributions are reflected as a component of the net loss attributable to general partner in the Consolidated Statements of Operations for 2017. In 2019, the annual administrative fee increased from $4.0 million in 2018 to $4.5 million in 2019 in accordance with the terms of the omnibus agreement, based on the cumulative increase in the producer price index since the inception of the omnibus agreement.

 

 

Consolidated Results of Operations

 

The following table compares the operating results of Cypress Environmental Partners, L.P. for the years ended December 31:

 

		2019				2018				2017
			(in thousands)
Revenues		$	401,648			$	314,960			$	286,342
Costs of services			347,924				270,914				252,739
Gross margin			53,724				44,046				33,603
Operating costs and expense:
General and administrative			25,626				23,744				21,055
Depreciation, amortization and accretion			4,448				4,404				4,443
Impairments			—				—				3,598
Gain on asset disposals, net			(25	)			(4,108	)			(570	)
Operating income			23,675				20,006				5,077
Other income (expense):
Interest expense, net			(5,330	)			(6,206	)			(7,335	)
Debt issuance cost write-off			—				(114	)			—
Foreign currency gains (losses)			222				(643	)			732
Other, net			1,111				373				199
Net income (loss) before income tax expense			19,678				13,416				(1,327	)
Income tax expense			2,254				1,318				596
Net income (loss)			17,424				12,098				(1,923	)
Net income (loss) attributable to noncontrolling interests			1,410				685				(1,110	)
Net income (loss) attributable to partners / controlling interests			16,014				11,413				(813	)
Net loss attributable to general partner			—				—				(4,050	)
Net income attributable to limited partners			16,014				11,413				3,237
Net income attributable to preferred unitholder			4,133				2,445				—
Net income attributable to common unitholder		$	11,881			$	8,968			$	3,237

 

See the detailed discussion of elements of operating income (loss) by reportable segment below. See also Note 14 to our Consolidated Financial Statements included in “Item 8. – Financial Statement and Supplementary Data.”

 

The following is a discussion of significant changes in the non-segment related corporate other income and expenses for the years ended December 31, 2019, 2018, and 2017.

 

Interest expense. Interest expense primarily consists of interest on borrowings under our Credit Agreement, amortization of debt issuance costs, and unused commitment fees. Changes in interest expense resulted primarily from changes in the balance of outstanding debt and to changes in interest rates. During 2018, we made net payments of $60.8 million to reduce the balance on our revolving credit facility. The average debt balance outstanding and average interest rates are summarized in the table below:

 

			Average				Average
Year Ended			Debt Balance				Interest
December 31			Outstanding				Rate
				(in thousands)
2019				81,400				5.78	%
2018				98,655				5.52	%
2017				136,900				4.71	%

 

 

Debt issuance cost write-off. In 2018, we entered into an amendment to our revolving credit facility and wrote off $0.1 million of debt issuance costs, which represented the portion of the unamortized debt issuance costs attributable to lenders who are no longer participating in the credit facility subsequent to the amendment to the Credit Agreement.

 

Foreign currency gains (losses). Our Canadian subsidiary has certain intercompany payables to our U.S.-based subsidiaries. Such intercompany payables and receivables among our consolidated subsidiaries are eliminated in our Consolidated Balance Sheets. Beginning April 1, 2017, we report currency translation adjustments on these intercompany payables and receivables within foreign currency gains (losses) in our Consolidated Statements of Operations. The net foreign currency gains in 2019 and 2017 resulted from the appreciation of the Canadian dollar relative to the U.S. dollar. The net foreign currency losses during 2018 resulted from the depreciation of the Canadian dollar relative to the U.S. dollar.

 

Other, net. Other income in 2019 includes a gain of $1.3 million of the settlement of litigation with a former subcontractor. Other expense in 2019 includes a loss of $0.5 million on the sale of pre-petition accounts receivable from PG&E. Other income in 2019, 2018, and 2017 also includes royalty income, interest income, and income associated with our 25% interest in a water treatment facility that we account for under the equity method.

 

Income tax expense. We qualify as a partnership for income tax purposes, and therefore, we generally do not pay income tax; instead, each owner reports his or her share of our income or loss on his or her individual tax return. Our income tax provision relates primarily to (1) our U.S. corporate subsidiaries that provide services to public utility customers, which do not appear to fit within the definition of qualified income as it is defined in the Internal Revenue Code, Regulations, and other guidance, which subjects this income to U.S. federal and state income taxes, (2) our Canadian subsidiary, which is subject to Canadian federal and provincial income taxes, and (3) certain other state income taxes, including the Texas franchise tax.

 

Income tax expenses increased from $1.3 million in 2018 to $2.3 million in 2019 primarily due to increased income in our U.S. corporate subsidiary that provides services to public utility customers and increases in revenue that is subject to the Texas franchise tax in our Pipeline Inspection and Pipeline and Process Services segments.

 

Income tax increased from $0.6 million during 2017 to $1.3 million during 2018 due to an income tax benefit recorded in 2017 related to the impairment of certain long-lived assets of our Canadian subsidiary, an increase in income in 2018 compared to 2017 of our taxable subsidiary in the U.S. that provides services to public utility customers, and increased franchise taxes in 2018 compared to 2017 due to an increase in revenue that is subject to the Texas franchise tax in our Pipeline Inspection and Pipeline and Process Services segments. These increases were partially offset by the reduction in the U.S. federal income tax rate as a result of a tax law that went into effect on January 1, 2018.

 

As a publicly-traded partnership, we are subject to a statutory requirement that 90% of our total gross income represent “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations, and Internal Revenue Service pronouncements), determined on a calendar-year basis. Income generated by taxable corporate subsidiaries is excluded from this calculation. In 2019, substantially all our gross income, which consisted of $314.7 million of revenue (exclusive of the income generated by our taxable corporate subsidiaries), represented “qualifying income”.

 

Net income (loss) attributable to noncontrolling interests. We own a 51% interest in Brown and a 49% interest in CF Inspection. The accounts of these subsidiaries are included within our Consolidated Financial Statements. The portion of the net income (loss) of these entities that is attributable to outside owners is reported in net income (loss) attributable to noncontrolling interests in our Consolidated Statements of Operations. Changes in the net income (loss) attributable to noncontrolling interests from 2017 to 2019 related primarily to changes in the net income generated by Brown.

 

Net loss attributable to general partner. The net loss attributable to general partner shown in our Consolidated Statements of Operations includes general and administrative expenses incurred by Holdings on behalf of the Partnership totaling $1.8 million for 2017. These represent administrative costs incurred by Holdings in excess of amounts charged to us under our omnibus agreement and are reflected as general and administrative in the Consolidated Statements of Operations. In addition, Holdings provided us with additional financial support in 2017 by making cash contributions of $2.3 million as a reimbursement for certain expenditures incurred by the Partnership. These cash contributions are reflected as a component of the net loss attributable to general partner in the Consolidated Statements of Operations for 2017.

 

Net income attributable to preferred unitholder. On May 29, 2018, we issued and sold $43.5 million of preferred equity. The holder of the preferred units is entitled to an annual return of 9.5% on this investment. This return is reported in net income attributable to preferred unitholder in the Consolidated Statements of Operations.

 

 

Segment Operating Results

 

Pipeline Inspection

 

The following table summarizes the operating results of our Pipeline Inspection segment for the years ended December 31, 2019 and 2018.

 

		Years Ended December 31
		2019				% of Revenue				2018				% of Revenue				Change				% Change
		(in thousands, except average revenue and inspector data)
Revenues		$	371,994							$	288,083							$	83,911				29.1%
Costs of services			331,498								256,436								75,062				29.3%
Gross margin			40,496				10.9%				31,647				11.0%				8,849				28.0%
General and administrative			19,086				5.1%				17,010				5.9%				2,076				12.2%
Depreciation, amortization and accretion			2,224				0.6%				2,237				0.8%				(13	)			(0.6)%
Other			1				0.0%				(21	)			0.0%				22				(104.8)%
Operating income		$	19,185				5.2%			$	12,421				4.3%			$	6,764				54.5%
Operating Data
Average number of inspectors			1,485								1,214								271				22.3%
Average revenue per inspector per week		$	4,804							$	4,551							$	253				5.6%
Revenue variance due to number of inspectors																		$	67,894
Revenue variance due to average revenue per inspector																		$	16,017

 

Revenue. Revenue increased $83.9 million in 2019 compared to 2018, due to an increase in the average number of inspectors engaged (an increase of 271 inspectors accounting for $67.9 million of the revenue increase) and an increase in the average revenue billed per inspector (accounting for $16.0 million of the revenue increase).

 

Revenue attributable to our U.S. operations increased $85.0 million in 2019 compared to 2018, due to increased activity by our clients and increased business development efforts. During the fourth quarter of 2018, we began work on the largest contract award in our history. The headcount for this pipeline inspection project peaked in the second quarter of 2019, and this project continued, with declining headcounts, into early 2020. We generated $62.9 million and $5.1 million of revenue from this project in 2019 and 2018, respectively. To help mitigate volatility in revenues associated with new construction projects, we continue to focus on areas of inspection that are less impacted by economic conditions, such as maintenance projects and projects associated with public utility companies. Revenues of our subsidiary that serves public utility companies increased by $12.8 million in 2019 compared to 2018. The increase in revenues of our U.S. operations was partially offset by a decrease of $1.1 million in revenue attributable to our Canadian operations.

 

The increase in average revenue per inspector is due to changes in customer mix. Fluctuations in the average revenue per inspector are expected, given that we charge different rates for different types of inspectors and different types of inspection services.

 

Costs of services. Costs of services increased $75.1 million in 2019 compared to 2018, consistent with the increase in revenue for the year.

 

Gross margin. Gross margin increased $8.8 million in 2019 compared to 2018. The gross margin percentage was 10.9% in 2019 compared to 11.0% in 2018. The slight decrease in gross margin percentage is due to changes in the mix of services provided. In 2019, we generated an increased percentage of our revenue from inspection services, which typically carry lower margins than integrity services. This was due in part to an inspection project that represented the largest contract award in our history. The resulting decrease in gross margin percentage was partially offset by increased activity in our business that serves public utility customers, as these services typically generate higher margins than our other inspection services.

 

Gross margin in 2019 and 2018 benefited from the fact that we recognized $0.2 million and $0.5 million, respectively, of revenue on services performed in previous years. We had constrained recognition of this revenue until the expiration of a contract provision that had given the customer the opportunity to reopen negotiation of the fee paid for the services.

 

General and administrative. General and administrative expenses increased by $2.1 million in 2019 compared to 2018. Compensation expense increased approximately $0.9 million in 2019 due to an increase in personnel to support our growing businesses and to increased incentive compensation expense resulting from the improved performance of our business. Professional fees increased by $0.8 million, due to legal costs associated with certain employment-related lawsuits and claims and to legal advisory costs related to the bankruptcy of one of our largest customers. The administrative fee charged by Holdings increased by $0.4 million, as a result of an inflation adjustment called for in our agreement with Holdings.

 

 

Depreciation, amortization and accretion. Depreciation, amortization and accretion expense in 2019 was similar to depreciation, amortization and accretion expense during 2018.

 

Operating income. Operating income increased by $6.8 million in 2019 compared to 2018, due primarily to the increase in gross margin, partially offset by an increase in general and administrative expenses.

 

The following table summarizes the operating results of our Pipeline Inspection segment for the years ended December 31, 2018 and 2017.

 

		Years Ended December 31
		2018				% of Revenue				2017				% of Revenue				Change				% Change
		(in thousands, except average revenue and inspector data)
Revenues		$	288,083							$	268,635							$	19,448				7.2%
Costs of services			256,436								241,889								14,547				6.0%
Gross margin			31,647				11.0%				26,746				10.0%				4,901				18.3%
General and administrative			17,010				5.9%				13,980				5.2%				3,030				21.7%
Depreciation, amortization and accretion			2,237				0.8%				2,331				0.9%				(94	)			(4.0)%
Impairments			—								1,329				0.5%				(1,329	)			(100.0)%
Other			(21	)			0.0%				18				0.0%				(39	)			(216.7)%
Operating income		$	12,421				4.3%			$	9,088				3.4%			$	3,333				36.7%
Operating Data
Average number of inspectors			1,214								1,145								69				6.0%
Average revenue per inspector per week		$	4,551							$	4,499							$	50				1.1%
Revenue variance due to number of inspectors																		$	16,374
Revenue variance due to average revenue per inspector																		$	3,076

 

Revenue. Revenue increased $19.4 million in 2018 compared to 2017 due to an increase in the average number of inspectors engaged (an increase of 69 inspectors accounting for $16.3 million of the revenue increase) and an increase in the average revenue billed per inspector (accounting for $3.1 million of the revenue increase).

 

Revenue attributable to our U.S. operations increased $41.5 million in 2018 compared to 2017, due to increased activity by our clients and increased business development efforts, including the expansion of the nondestructive examination business. Revenues of our subsidiary that serves public utility companies increased by $13.6 million in 2018 compared to 2017. Revenues from nondestructive examination services increased by $4.8 million in 2018 compared to 2017. The increase in revenues of our U.S. operations was partially offset by a decrease of $22.1 million in revenue attributable to our Canadian operations. We reduced our activities in Canada as a result of low margins and high general and administrative costs.

 

Costs of services. Costs of services increased $14.5 million in 2018 compared to 2017, consistent with the increase in revenue for the year.

 

Gross margin. Gross margin increased $4.9 million in 2018 compared to 2017. The gross margin percentage improved to 11.0% in 2018, compared to 10.0% in 2017. The increase in gross margin percentage is due to changes in the mix of services provided. In 2018, we generated more revenue from our public utility and nondestructive examination service lines, which typically produce higher margins. During the third quarter of 2017, we ceased to perform certain services for the largest customer of our Canadian subsidiary, which services typically produced lower margins. The gross margin in 2018 benefitted from the recognition of $0.5 million of revenue on services performed in previous years. We had constrained recognition of this revenue until the expiration of a contract provision that had given the customer the opportunity to reopen negotiation of the fee for the services.

 

General and administrative. General and administrative expenses increased by $3.0 million in 2018 compared to 2017, due in part to an increase of $1.4 million in expense associated with the administrative fee charged by Holdings. In 2017, Holdings waived $1.4 million of this administrative fee. In 2018, Holdings did not provide any financial support to us. Compensation expense increased approximately $1.0 million during 2018 due to an increase in personnel to support our growing businesses and to increased incentive compensation expense resulting from the improved performance of our business. In addition, professional fees increased by $0.5 million, due primarily to legal costs associated with certain employment-related lawsuits and claims.

 

 

Depreciation, amortization and accretion. Depreciation, amortization and accretion expense in 2018 was similar to depreciation, amortization and accretion expense in 2017.

 

Impairments. In the first quarter of 2017, we ceased to perform lower-margin services for the largest customer of our Canadian subsidiary. In consideration of this, we recorded impairments to the carrying values of certain intangible assets of $1.3 million in the first quarter of 2017. Of this amount, $1.1 million related to customer relationships and $0.2 million related to trade names. Based on discounted cash flow calculations, we concluded the fair value of the customer relationships and trade names of our Canadian business was zero, and therefore we impaired the full amounts.

 

Operating income. Operating income increased by $3.3 million in 2018 compared to 2017, due primarily to the increase in gross margin and the absence of impairment expense in 2018, partially offset by our payment of the quarterly administrative fees charged by Holdings in 2018, which fees were waived in the first two quarters of 2017, additional compensation expense, and increased professional services expense.

 

Pipeline & Process Services

 

The following table summarizes the results of the Pipeline & Process Services segment for the years ended December 31, 2019 and 2018.

 

		Year Ended December 31
		2019				% of Revenue				2018				% of Revenue				Change				% Change
		(in thousands, except average revenue and inspector data)
Revenue		$	19,337							$	15,001							$	4,336				28.9%
Costs of services			13,397								10,708								2,689				25.1%
Gross margin			5,940				30.7%				4,293				28.6%				1,647				38.4%
General and administrative			2,500				12.9%				2,379				15.9%				121				5.1%
Depreciation, amortization and accretion			574				3.0%				592				3.9%				(18	)			(3.0)%
Gain on asset disposals, net			(26	)			(0.1)%				(83	)			(0.6)%				57				(68.7)%
Operating income		$	2,892				15.0%			$	1,405				9.4%			$	1,487				105.8%
Operating Data
Average number of field personnel			28								23								5				21.7%
Average revenue per field personnel per week		$	13,245							$	12,508							$	737				5.9%
Revenue variance due to number of field personnel																		$	3,455
Revenue variance due to average revenue per field personnel																		$	881

 

Revenue. Revenue increased $4.3 million in 2019 compared to 2018. The increase in revenue was due to increased success in winning bids for projects as a result of improved business development efforts. Revenue in 2018 included $0.3 million associated with additional billings on a project that we completed in the fourth quarter of 2017 (we recognized the revenue upon receipt of customer acknowledgment of the additional fees).

 

Our Pipeline & Process Services segment generates most of its revenues from a smaller number of larger-scale projects than does our Pipeline Inspection segment. As a result, the revenues of the Pipeline & Process Services segment are more volatile, and revenues for a given period of time can be significantly influenced by the ability to win a relatively small number of bids for hydrotesting projects. In 2019, 72% of the revenues in the Pipeline & Process Services segment were generated from the 10 largest projects.

 

Costs of services. Costs of services increased $2.7 million in 2019 compared to 2018, as a result of the increase in revenues.

 

Gross margin. Gross margin increased $1.6 million in 2019 compared to 2018. The employees of the Pipeline & Process Services segment are full-time employees, and therefore represent fixed costs (in contrast to the employees of the Pipeline Inspection segment who perform work in the field, most of whom only earn wages when they are performing work for a customer and whose wages are therefore primarily variable costs). Because these employees were more fully utilized in 2019 than during 2018, the gross margin percentage was higher. The increase in gross margin percentage was partially offset by $0.3 million of revenue recognized during 2018 associated with additional billings on a project that we completed in the fourth quarter of 2017.

 

 

General and administrative. General and administrative expenses primarily include compensation expense for office employees and general office expenses. These expenses increased by $0.1 million in 2019 compared to 2018 due primarily to an increase in employee compensation expenses, which related primarily to increased incentive compensation expense resulting from the improved performance of the business.

 

Depreciation, amortization and accretion. Depreciation, amortization and accretion expense includes depreciation of property and equipment and amortization of intangible assets associated with customer relationships, trade names, and noncompete agreements. Depreciation, amortization and accretion expense in 2019 was similar to depreciation, amortization and accretion expense in 2018.

 

Operating income. Operating income increased by $1.5 million in 2019 compared to 2018. This increase was due to higher gross margins of $1.6 million partially offset by an increase of $0.1 million in general and administrative expenses.

 

The following table summarizes the results of the Pipeline & Process Services segment for the years ended December 31, 2018 and 2017.

 

		Year Ended December 31
		2018				% of Revenue				2017				% of Revenue				Change				% Change
		(in thousands, except average revenue and inspector data)
Revenue		$	15,001							$	9,268							$	5,733				61.9%
Costs of services			10,708								7,347								3,361				45.7%
Gross margin			4,293				28.6%				1,921				20.7%				2,372				123.5%
General and administrative			2,379				15.9%				1,981				21.4%				398				20.1%
Depreciation, amortization and accretion			592				3.9%				626				6.8%				(34	)			(5.4)%
Impairments			—								1,581				17.1%				(1,581	)			(100.0)%
Gain on asset disposals, net			(83	)			(0.6)%				—								(83	)
Operating income (loss)		$	1,405				9.4%			$	(2,267	)			(24.5)%			$	3,672				(162.0)%
Operating Data
Average number of field personnel			23								20								3				15.0%
Average revenue per field personnel per week		$	12,508							$	8,887							$	3,621				40.7%
Revenue variance due to number of field personnel																		$	1,951
Revenue variance due to average revenue per field personnel																		$	3,782

 

Revenue. Revenue increased $5.7 million in 2018 compared to 2017. The Pipeline & Process Services segment won more bids for projects, and as a result, employee utilization was significantly higher in 2018 than in 2017. The increase in successful bids was due to improving market conditions and to improved business development efforts. Revenue during 2018 included $0.3 million associated with additional billings on a project that we completed in the fourth quarter of 2017 (we recognized the revenue upon receipt of customer acknowledgment of the additional fees).

 

Costs of services. Costs of services increased $3.4 million in 2018 compared to 2017, as a result of the increase in revenues.

 

Gross margin. Gross margin increased $2.4 million in 2018 compared to 2017. The employees of the Pipeline & Process Services segment are full-time employees, and therefore represent fixed costs (in contrast to the employees of the Pipeline Inspection segment who perform work in the field, most of whom only earn wages when they are performing work for a customer and whose wages are therefore primarily variable costs). Because these employees were more fully utilized in 2018 than in 2017, the gross margin percentage was higher.

 

General and administrative. General and administrative expenses primarily include compensation expense for office employees and general office expenses. These expenses increased by $0.4 million in 2018 compared to 2017 due primarily to increased compensation and business development costs, including incentive compensation expenses resulting from the improved performance of the business.

 

Depreciation, amortization and accretion. Depreciation, amortization and accretion expenses include depreciation of property and equipment and amortization of intangible assets associated with customer relationships, trade names, and noncompete agreements. Depreciation, amortization and accretion expense in 2018 was similar to depreciation and amortization expense in 2017.

 

Impairments. In 2017, we recorded a full impairment to the goodwill of the Pipeline & Process Services reporting unit. Although we had recently won bids on a number of projects and our backlog had begun to improve, the improvement in the backlog had been slower than we had anticipated, and accordingly, we revised downward our expectations of the near-term operating results of the segment.

 

 

Operating income (loss). Operating income increased by $3.7 million in 2018 compared to 2017. This increase was due, in part, to higher gross margins of $2.4 million and in part to the absence of impairment expense in 2018, compared to $1.6 million of impairment expense recorded in 2017, partially offset by increased general and administrative expense.

 

Environmental Services

 

The following table summarizes the operating results of our Environmental Services segment for the years ended December 31, 2019 and 2018.

 

		Year Ended December 31
		2019				% of Revenue				2018				% of Revenue				Change				% Change
		(in thousands, except per barrel data)
Revenues		$	10,317							$	11,876							$	(1,559	)			(13.1)%
Costs of services			3,029								3,770								(741	)			(19.7)%
Gross margin			7,288				70.6%				8,106				68.3%				(818	)			(10.1)%
General and administrative			2,995				29.0%				3,295				27.7%				(300	)			(9.1)%
Depreciation, amortization and accretion			1,632				15.8%				1,575				13.3%				57				3.6%
Gain on asset disposals, net			—								(4,004	)			(33.7)%				4,004				(100.0)%
Operating income		$	2,661				25.8%			$	7,240				61.0%			$	(4,579	)			(63.2)%
Operating Data
Total barrels of water processed			13,416								14,782								(1,366	)			(9.2)%
Average revenue per barrel processed (a)		$	0.77							$	0.80							$	(0.03	)			(3.8)%
Revenue variance due to barrels processed																		$	(1,097	)
Revenue variance due to revenue per barrel																		$	(462	)

 

(a)

Average revenue per barrel processed is calculated by dividing revenues (which includes water treatment revenues, residual oil sales, and management fees) by the total barrels of water processed.

 

Revenue. Revenue of the Environmental Services segment decreased by $1.6 million in 2019 compared to 2018. Revenues in 2018 included $0.2 million from our two Texas facilities, which included management fees associated with a transition services agreement related to the sale in January 2018 of our Pecos, Texas facility and revenues from our Orla, Texas facility, which was sold in May 2018. Revenues of our North Dakota facilities decreased by approximately $1.4 million in 2019 compared to 2018. The decrease was due primarily to the decrease of 1.2 million barrels of water processed in 2019 compared to 2018. The decrease in volume resulted from a slowdown in exploration and production activity in the areas near our facilities. The average revenue per barrel decreased in 2019 compared to 2018, due in part to the fact that piped water, which typically generates higher per-barrel revenues than trucked water, represented a lower percentage of total volumes in 2019 than in 2018. The average price per barrel of recovered crude oil also decreased in 2019 compared to 2018, as a result of lower market prices for crude oil. Revenues from the sale of recovered crude oil represented 6% and 5% of the revenue in the Environmental Services segment in 2019 and 2018, respectively.

 

Costs of services. Costs of services decreased by $0.7 million in 2019 compared to 2018. The decrease was due to a decrease of $0.2 million in variable expenses such as chemicals and utilities as a result of the decrease in volumes processed, a decrease of $0.1 million resulting from the sale in 2018 of our two facilities in Texas, a decrease of $0.2 million in repairs and maintenance expense, and approximately $0.2 million of expense associated with the cleanup and remediation of spills in 2018.

 

Gross margin. Gross margin decreased $0.8 million in 2019 compared to 2018, due primarily to a $1.6 million decrease in revenue, partially offset by a $0.7 million decrease in cost of services.

 

General and administrative. General and administrative expenses include general overhead expenses such as employee compensation costs, insurance, property taxes, royalty expenses, and other miscellaneous expenses. These expenses decreased by $0.3 million in 2019 compared to 2018, due primarily to a decrease of $0.1 million in employee compensation expenses and a decrease of $0.1 million in professional services expenses. General and administrative expense in 2018 included $0.1 million of legal expense associated with certain employment-related matters.

 

 

Depreciation, amortization and accretion. Depreciation, amortization and accretion expenses include depreciation of property and equipment and amortization of intangible assets associated with customer relationships, trade names, and noncompete agreements. Depreciation, amortization and accretion expense in 2019 was similar to depreciation, amortization and accretion expense in 2018.

 

Gain on asset disposals, net. In 2018, we recorded a combined gain of $3.6 million from the sale of our two water treatment facilities in Texas, a gain of $0.4 million from proceeds received from the settlement of litigation related to lightning strikes that occurred in 2017 at our facilities in Orla, Texas and Grassy Butte, North Dakota, and a gain of $0.1 million from the collection of insurance proceeds, which represented the final payment on a property damage insurance claim related to the Grassy Butte facility. These gains were partially offset by a loss of $0.1 million on the abandonment of a capital expansion project.

 

Operating income. Operating income decreased by $4.6 million in 2019 compared to 2018. The decrease in operating income was due in part to a decrease in gross margin of $0.8 million and due in part to gains in 2018 of $4.1 million from asset disposals, partially offset by a loss in 2018 of $0.1 million on the abandonment of a capital expansion project.

 

The following table summarizes the operating results of our Environmental Services segment for the years ended December 31, 2018 and 2017.

 

		Year Ended December 31
		2018				% of Revenue				2017				% of Revenue				Change				% Change
		(in thousands, except per barrel data)
Revenues		$	11,876							$	8,439							$	3,437				40.7%
Costs of services			3,770								3,503								267				7.6%
Gross margin			8,106				68.3%				4,936				58.5%				3,170				64.2%
General and administrative			3,295				27.7%				2,451				29.0%				844				34.4%
Depreciation, amortization and accretion			1,575				13.3%				1,486				17.6%				89				6.0%
Impairments			—								688				8.2%				(688	)			(100.0)%
Gain on asset disposals, net			(4,004	)			(33.7)%				(588	)			(7.0)%				(3,416	)			581.0%
Operating income (loss)		$	7,240				61.0%			$	899				10.7%			$	6,341				705.3%
Operating Data
Total barrels of water processed			14,782								12,588								2,194				17.4%
Average revenue per barrel processed (a)		$	0.80							$	0.67							$	0.13				19.8%
Revenue variance due to barrels processed																		$	1,471
Revenue variance due to revenue per barrel																		$	1,966

 

(a)

Average revenue per barrel processed is calculated by dividing revenues (which includes water treatment revenues, residual oil sales, and management fees) by the total barrels of water processed.

 

Revenue. Revenue of the Environmental Services segment increased by $3.4 million in 2018 compared to 2017, due primarily to a 17% increase in the volume of water processed and an increase in the average revenue per barrel disposed of 20%. Revenues of our North Dakota facilities increased by $4.9 million, from $6.8 million in 2017 to $11.7 million in 2018. Volumes of our North Dakota facilities increased by 4.7 million barrels, from 9.9 million barrels in 2017 to 14.6 million barrels in 2018. The increase in volumes was due to the completion of a pipeline system at one of our facilities in January 2018 and to increased customer activity around several of our other facilities.

 

Revenues of our Texas facilities decreased by $1.4 million, from $1.6 million in 2017 to $0.2 million in 2018. Volumes of our Texas facilities decreased by 2.6 million barrels, from 2.7 million barrels in 2017 to 0.1 million barrels in 2018. This was due to the sale in January 2018 of our Pecos facility and the sale in May 2018 of our Orla facility. All of our remaining facilities are located in North Dakota.

 

The average revenue per barrel increased in 2018 compared to 2017, due in part to increased revenues from our new pipelines, as well as pricing increases. In addition, revenues in 2018 included $0.1 million of management fees associated with a transition services agreement related to the sale of the Pecos facility. Revenues from the sale of recovered crude oil were modestly higher in 2018 than in 2017, due primarily to higher prices. Revenues from the sale of recovered crude oil represented 5% and 7% of the revenue in the Environmental Services segment in 2018 and 2017, respectively.

 

Costs of services. Costs of services increased by $0.3 million in 2018 compared to 2017. A decrease of $0.5 million in costs of services resulting from the sale of our Texas facilities was offset by an increase of $0.4 million in chemical and utility expense, as a result of higher volumes at our North Dakota facilities, an increase of $0.2 million in expense related to spill cleanup costs at certain facilities, and an increase of $0.2 million in employee compensation expense.

 

 

Gross margin. Gross margin increased $3.2 million in 2018 compared to 2017, due primarily to a $3.4 million increase in revenue, partially offset by a $0.3 million increase in cost of services.

 

General and administrative. General and administrative expenses include general overhead expenses such as salary costs, insurance, property taxes, royalty expenses, and other miscellaneous expenses. These expenses increased by $0.8 million in 2018 compared to 2017. Of this increase, $0.6 million related to the administrative fee charged by Holdings (Holdings waived this administrative fee for the six months ended June 30, 2017). In addition, general and administrative expense in 2017 were reduced by $0.3 million upon collection of an account receivable on which we had previously recorded a valuation allowance.

 

Depreciation, amortization and accretion. Depreciation, amortization and accretion expense increased by $0.1 million in 2018 compared to 2017. This was due primarily to an increase of $0.3 million of depreciation expense related to two pipelines that we placed into service in January 2018, partially offset by a reduction of $0.1 million in depreciation expense associated with the sale in 2018 of one of our facilities in Texas and by a reduction of $0.1 million in amortization expense, resulting from the fact that certain of the intangible assets became fully amortized in 2018.

 

Impairments. In 2017, we recorded an impairment of $0.7 million to the property, plant and equipment at one of our water treatment facilities. We experienced low volumes at this facility due to competition in the area and to low levels of exploration and production activity near the facility.

 

Gain on asset disposals, net. In 2018, we recorded a combined gain of $3.6 million from the sale of our two water treatment facilities in Texas, a gain of $0.4 million from proceeds received from the settlement of litigation related to lightning strikes that occurred in 2017 at our facilities in Orla, Texas and Grassy Butte, North Dakota, and a gain of $0.1 million from the collection of insurance proceeds, which represented the final payment on a property damage insurance claim related to the Grassy Butte facility. These gains were partially offset by a loss of $0.1 million on the abandonment of a capital expansion project.

 

In 2017, we recorded net gains on asset disposals of $0.6 million related to the lightning strikes and the resultant fires at two of our facilities. We carried property damage and cleanup insurance on both facilities, and the proceeds we received on these policies were in excess of the net book value of the damaged property and the cleanup costs we incurred.

 

Operating income. Operating income of $7.2 million in 2018 compared to operating income of $0.9 million in 2017. The increase in operating income was due in part to gains of $3.6 million from the sales of our water treatment facilities in Texas, an increase of $3.2 million in gross margin, lawsuit settlement gains of $0.4 million, and impairments of $0.7 million recorded in 2017, partially offset by an increase of $0.8 million in general and administrative expenses and $0.6 million of net gains on asset disposals in 2017.

 

 

Liquidity and Capital Resources

 

We anticipate making growth capital expenditures in the future, including acquiring new businesses or expanding the existing assets and offerings in our current operations. In addition, the working capital needs of the Pipeline Inspection segment are substantial, driven by payroll and reimbursable expenses paid to our inspectors on a weekly basis. Please read “Risk Factors — Risks Related to Our Business — The working capital needs of the Pipeline Inspection segment 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 future borrowings and the issuance of debt and equity securities. However, we may not be able to raise additional funds on desired or favorable terms or at all.

 

At December 31, 2019, our sources of liquidity included:

 

	●	$15.7 million of cash on our Consolidated Balance Sheet at December 31, 2019 (inclusive of cash attributable to the noncontrolling interest owners);
	●	available borrowings under our Credit Agreement of $34.5 million at December 31, 2019; and
	●	issuance of equity and/or debt securities.

 

In January 2020, we made a payment of $5.0 million to reduce the balance outstanding on the Credit Agreement from $74.9 million to $69.9 million. In March 2020, in an abundance of caution, we borrowed $32.0 million on the Credit Agreement to provide substantial liquidity to manage our business in light of the COVID-19 outbreak and the significant recent decline in the price of crude oil. The current balance outstanding on the Credit Agreement is $101.9 million and we have over $40 million of cash. At this time our businesses are operating in the normal course, and we recently implemented our business continuity plan in our largest offices, including our headquarters, to allow most office employees to work from home to support our field employees.

 

At-the-Market Equity Program

 

In April 2018, we established an at-the-market equity program (“ATM Program”), which will allow us to offer and sell common units from time to time, to or through the sales agent under the ATM Program, up to an aggregate offering amount of $10 million. We are under no obligation to sell any common units under this program. As of the date of this filing, we have not sold any common units under the ATM Program and, as such, have not received any net proceeds or paid any compensation to the sales agent under the ATM Program.

 

Employee Unit Purchase Plan

 

In November 2019, we established an employee unit purchase plan (“EUPP”), which will allow us to offer and sell up to 500,000 common units. Employees can elect to have up to 10 percent of their annual base pay withheld to purchase common units, subject to terms and limitations of the EUPP. The purchase price of the common units is 95% of the volume weighted average of the closing sales prices of our common units on the ten immediately preceding trading days at the end of each offering period. There have been no common unit issuances under the EUPP.

 

 

Common Unit Distributions

 

Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash to common unitholders of record on the applicable record date.

 

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

 

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

 

 

The following table summarizes the distributions on common and subordinated units declared since our initial public offering:

 

										Total Cash
		Per Unit Cash				Total Cash				Distributions
Payment Date		Distributions				Distributions				to Affiliates (a)
						(in thousands)
Total 2014 Distributions		$	1.104646			$	13,064			$	8,296
Total 2015 Distributions			1.625652				19,232				12,284
Total 2016 Distributions			1.625652				19,258				12,414
Total 2017 Distributions			1.036413				12,310				7,928
February 14, 2018			0.210000				2,498				1,599
May 15, 2018			0.210000				2,506				1,604
August 14, 2018			0.210000				2,506				1,604
November 14, 2018			0.210000				2,509				1,606
Total 2018 Distributions			0.840000				10,019				6,413
February 14, 2019			0.210000				2,510				1,606
May 15, 2019			0.210000				2,531				1,622
August 14, 2019			0.210000				2,534				1,624
November 14, 2019			0.210000				2,534				1,627
Total 2019 Distributions			0.840000				10,109				6,479
February 14, 2020 (b)			0.210000				2,534				1,627
Total Distributions (through February 14, 2020 since IPO)		$	7.282363			$	86,526			$	55,441

 

(a)

Approximately 64% of the Partnership’s outstanding common units at December 31, 2019 were held by affiliates.

(b)

Fourth quarter 2019 distribution was declared and paid in the first quarter of 2020.

 

Preferred Unit Distributions

 

On May 29, 2018 we issued and sold in a private placement 5,769,231 Series A Preferred Units representing limited partner interests in the Partnership (the “Preferred Units”) for a cash purchase price of $7.54 per Preferred Unit, resulting in gross proceeds to the Partnership of $43.5 million. The purchaser of the Preferred Units is entitled to receive quarterly distributions that represent an annual return of 9.5% (which amounts to $4.1 million per year). Of this 9.5% annual return, we will be required to pay at least 2.5% in cash and will have the option to pay the remaining 7.0% in kind (in the form of issuing additional Preferred Units) for the first twelve quarters after the initial sale of the Preferred Units.

 

		Cash				Paid-in-Kind				Total
Payment Date		Distributions				Distributions				Distributions
		(in thousands)
November 14, 2018 (a)		$	1,412			$	—			$	1,412
Total 2018 Distributions			1,412				—				1,412
February 14, 2019			1,033				—				1,033
May 15, 2019			1,033				—				1,033
August 14, 2019			1,033				—				1,033
November 14, 2019			1,034				—				1,034
Total 2019 Distributions			4,133				—				4,133
February 14, 2020 (b)			1,033				—				1,033
Total Distributions (through February 14, 2020)		$	6,578			$	—			$	6,578

 

(a)

This distribution relates to the period from May 29, 2018 (date of preferred unit issuance) through September 30, 2018.

(b)

Fourth quarter 2019 distribution was declared and paid in the first quarter of 2020.

 

Brown Integrity, LLC

Brown’s company agreement generally requires Brown to make an annual distribution to its members equal to or greater than the amount of Brown’s taxable income multiplied by the maximum federal income tax rate.

 

 

Cash Flows

 

The following table sets forth a summary of the net cash provided by (used in) operating, investing and financing activities for the periods identified.

 

		Year Ended December 31
		2019				2018				2017
		(in thousands)
Net cash provided by operating activities		$	18,179			$	15,409			$	8,253
Net cash (used in) provided by investing activities			(1,933	)			7,007				(1,041	)
Net cash used in financing activities			(15,930	)			(31,466	)			(10,150	)
Effect of exchange rates on cash			4				(17	)			753
Net increase (decrease) in cash and cash equivalents		$	320			$	(9,067	)		$	(2,185	)

 

Operating activities. In 2019, we generated operating cash flows of $18.2 million. Prior to consideration of changes in working capital, operating cash flows in 2019 were $23.4 million, consisting of net income of $17.4 million plus non-operating-cash expenses of $6.0 million (non-cash expenses include depreciation and amortization, equity-based compensation, foreign currency gains/losses, gain on litigation settlement, and loss on sale of accounts receivable, among others). In 2019, changes in working capital reduced operating cash flows by $5.3 million. During periods of revenue growth, changes in working capital typically reduce operating cash flows, based on the fact that we pay our employees before we collect our accounts receivable from our customers.

 

During 2018, we generated operating cash flows of $15.4 million. Prior to consideration of changes in working capital, operating cash flows during 2018 were $16.0 million, consisting of net income of $12.1 million plus non-operating-cash expenses of $3.9 million (non-cash expenses include depreciation and amortization, equity-based compensation, foreign currency gains/losses, and gains/losses on the sale or impairment of assets, among others). During 2018, changes in working capital reduced operating cash flows by $0.6 million. During periods of revenue growth, changes in working capital typically reduce operating cash flows, based on the fact that we pay our employees before we collect our accounts receivable from our customers.

 

During 2017, we generated operating cash flows of $8.3 million. Prior to consideration of changes in working capital, operating cash flows during 2017 were $8.9 million, consisting of a net loss of $1.9 million plus non-operating-cash expenses of $10.8 million (non-cash expenses include depreciation and amortization, equity-based compensation, foreign currency gains/losses, and gains/losses on the sale or impairment of assets, among others). Non-cash expenses included $1.8 million expense that was incurred by Holdings for our benefit but not charged to us. During 2017, changes in working capital reduced operating cash flows by $0.6 million. During periods of revenue growth, changes in working capital typically reduce operating cash flows, based on the fact that we pay our employees before we collect our accounts receivable from our customers.

 

Investing activities. In 2019, cash outflows for investing activities consisted of capital expenditures of $2.0 million, which were partially offset by less than $0.1 million in proceeds from fixed asset disposals. Capital expenditures in 2019 included the purchase of equipment (primarily for our nondestructive examination business) and costs associated with a new software system for payroll and human resources management that we implemented in early 2020.

 

During 2018, cash inflows from investing activities included proceeds of $12.2 million related to the sales of our two water treatment facilities in Texas, $0.4 million related to the settlement of litigation related to lightning strikes at two of our facilities, and $0.1 million of property damage insurance proceeds related to the lightning strikes. Cash outflows from investing activities for 2018 included $5.8 million of capital expenditures, which related primarily to the construction of two pipelines into one of our facilities in North Dakota, the rebuilding of the Orla, Texas facility prior to its sale, and the rebuilding of the Grassy Butte, North Dakota facility (the surface equipment at both the Orla and Grassy Butte facilities were destroyed by fires in 2017 resulting from lightning strikes). Capital expenditures also included the purchase of equipment to support the growth in our Pipeline Inspection segment’s nondestructive examination business.

 

During 2017, cash outflows for investing activities consisted of capital expenditures of $3.3 million. Capital expenditures during 2017 included the construction of two pipelines to connect one of our water treatment facilities in North Dakota to a customer’s production fields. The remaining capital expenditures consisted primarily of equipment purchases, much of which was in support of increasing revenues in the Pipeline Inspection segment’s nondestructive examination business. Cash inflows from investing activities during 2017 included $2.3 million of proceeds on property damage insurance claims, which resulted from lightning strikes and resultant fires at two of our water treatment facilities.

 

 

Financing activities. In 2019, cash outflows from financing activities included $1.2 million of net payments on our revolving credit facility. Financing cash outflows for 2019 also included $10.1 million of common unit distributions and $4.1 million of preferred unit distributions.

 

During 2018, cash inflows from financing activities included $43.3 million of proceeds from the sale of preferred units, net of related costs. Cash outflows from financing activities included $60.8 million of net payments to reduce the balance outstanding on our revolving credit facility. In May 2018 we completed a refinancing of our revolving credit agreement; as part of this refinancing, we significantly reduced the balance of debt outstanding using proceeds from the sale of preferred equity, proceeds from the sale of two of our water treatment facilities, and cash on hand. Cash outflows from financing activities also included $1.3 million of debt issuance costs related to the amendment to our revolving credit facility, $10.0 million of distributions to common unitholders, $1.4 million of distributions to preferred unitholders, and $1.0 million of distributions to noncontrolling interests.

 

During 2017, cash outflows from financing activities included $12.3 million of distributions to common and subordinated unitholders. Cash inflows from financing activities for 2017 included $2.3 million of contributions from Holdings to support the Partnership.

 

Working Capital

 

Our working capital (defined as net current assets less net current liabilities) was $47.9 million at December 31, 2019. Our Pipeline Inspection and Pipeline & Process Services segments have substantial working capital needs, as we generally pay our field personnel on a weekly basis, but typically receive payment from our customers 45 to 90 days after the services have been performed. Please read “Risk Factors — Risks Related to Our Business — The working capital needs of the Pipeline Inspection segment are substantial, which could require us to seek additional financing that we may not be able to obtain on satisfactory terms, or at all.”

 

Capital Requirements

 

We generally have small capital expenditure requirements compared to many other master limited partnerships. Our Environmental Services Segment has minimal capital expenditure requirements for the maintenance of existing water treatment facilities. Our Pipeline Inspection segment does not generally require significant capital expenditures, other than in the nondestructive examination service line, which has invested growth capital to acquire field equipment to support revenue growth. Our Pipeline & Process Services segment has both maintenance and growth capital needs for heavy equipment and vehicles in order to perform hydrostatic testing and other integrity procedures. Our partnership agreement requires 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 expenditures to maintain equipment reliability, integrity, and safety, as well as to address environmental laws and regulations. Maintenance capital expenditures, inclusive of finance lease obligation payments, were $0.7 million, $0.7 million, and $0.5 million for the years ended December 31, 2019, 2018 and 2017, respectively (cash basis).

 

●

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 and the construction or development of additional water treatment capacity, to the extent such expenditures are expected to expand our long-term operating capacity or operating income. Expansion capital expenditures were $1.5 million, $5.1 million, and $2.8 million in 2019, 2018, and 2017, respectively (cash basis).

 

Future expansion capital expenditures may vary significantly from period to period based on the investment opportunities available. We expect to fund future capital expenditures from cash flows generated from our operations, borrowings under our Credit Agreement, the issuance of additional partnership units, or debt offerings.

 

Credit Agreement

 

On May 29, 2018, we entered into an amended and restated credit agreement (as amended and restated, the “Credit Agreement”) that provides up to $110.0 million in borrowing capacity, subject to certain limitations. The three-year Credit Agreement matures May 29, 2021. Deutsche Bank Trust Company Americas serves as the Administrative Agent for the Credit Agreement. The obligations under the Credit Agreement are secured by a first priority lien on substantially all of our assets. The credit agreement as it existed prior to the May 29, 2018 amendment will hereinafter be referred to as the “Previous Credit Agreement” or, together with the Credit Agreement, as the “Credit Agreements”.

 

 

Outstanding borrowings at December 31, 2019 and December 31, 2018 were $74.9 million and $76.1 million, respectively, and are reflected as long-term debt on the Consolidated Balance Sheets.

 

All borrowings under the Credit Agreement bear interest, at our option, on a leveraged based grid pricing at (i) a base rate plus a margin of 1.5% to 3.0% per annum (“Base Rate Borrowing”) or (ii) an adjusted LIBOR rate plus a margin of 2.5% to 4.0% per annum (“LIBOR Borrowings”).  The applicable margin is determined based on the leverage ratio of the Partnership, as defined in the Credit Agreement. The interest rate on our borrowings ranged from 4.70% to 6.02% in 2019. The interest rate in effect at December 31, 2019 was 4.80%. Interest on Base Rate Borrowings is payable monthly. Interest on LIBOR Borrowings is paid upon maturity of the underlying LIBOR contract, but no less often than quarterly. Commitment fees are charged at a rate of 0.50% on any unused credit and are payable quarterly. The average debt balance outstanding in 2019 was $81.4 million.

 

The Credit Agreement contains various customary covenants and restrictive provisions. The Credit Agreement also requires maintenance of certain financial covenants, including a leverage ratio (as defined in the Credit Agreement) of not more than 4.0 to 1.0 and an interest coverage ratio (as defined in the Credit Agreement) of not less than 3.0 to 1.0. At December 31, 2019, our leverage ratio was 2.4 to 1.0 and our interest coverage ratio was 8.7 to 1.0, pursuant to the Credit Agreement. Upon the occurrence and during the continuation of an event of default, subject to the terms and conditions of the Credit Agreement, the lenders may declare any outstanding principal, together with any accrued and unpaid interest, to be immediately due and payable and may exercise the other remedies set forth or referred to in the Credit Agreement. We were in compliance with all debt covenants as of December 31, 2019.

 

Borrowings under the Credit Agreement may not exceed 4 times the trailing-twelve-month EBITDA as of the most recently-filed quarterly compliance certificate. Trailing-twelve-month EBITDA, as calculated under the Credit Agreement, was $31.4 million at December 31, 2019.

 

In addition, the Credit Agreement restricts our ability to make distributions on, or redeem or repurchase, our equity interests, with certain exceptions detailed in the Credit Agreement. However, we may make distributions of available cash so long as, both at the time of the distribution and after giving effect to the distribution, no default exists under the Credit Agreement, we are in compliance with the financial covenants in the Credit Agreement, and we have at least $5.0 million of unused capacity on the Credit Agreement at the time of the distribution.

 

In January 2020, we made a payment of $5.0 million to reduce the balance outstanding on the Credit Agreement from $74.9 million to $69.9 million. In March 2020, in an abundance of caution, we borrowed $32.0 million on the Credit Agreement to provide substantial liquidity to manage our business in light of the COVID-19 outbreak and the significant recent decline in the price of crude oil. The current balance outstanding on the Credit Agreement is $101.9 million and we have over $40 million of cash. At this time our businesses are operating in the normal course, and we recently implemented our business continuity plan in our largest offices, including our headquarters, to allow most office employees to work from home to support our field employees. 

 

Off-Balance Sheet Arrangements

 

We do not have any off-balance sheet or hedging arrangements.

 

ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below.

 

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil, natural gas, and natural gas liquids prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. None of our market risk sensitive instruments were entered into for speculative trading purposes.

 

Commodity Price Risk

  

Approximately 0.2% of our consolidated revenues in 2018 and 2019 were derived from sales of crude oil. A hypothetical change in crude oil prices of 10% would result in an increase or decrease of our revenues derived from sales of commodities by approximately $0.1 million. Increases or decreases in commodity prices can also result in changes in demand for our water treatment, pipeline inspection, and pipeline and process services, resulting in an increase or decrease of our revenues and gross margins.

 

Crude oil prices have decreased significantly in 2020, due in part to decreased demand as a result of a recent worldwide COVID-19 outbreak, and due in part to the oil price war started by Russia and Saudi Arabia with a focus on slowing down U.S. oil production. This decline in oil prices will likely lead our customers to change their budgets and plans, which will decrease their spending on drilling, completions, and exploration. This could have an impact on construction of new pipelines, gathering systems, and related energy infrastructure. Lower exploration and production activity will also impact the midstream industry and could lead to delays or cancellations of projects. It is also possible that our customers may elect to defer maintenance activities on their infrastructure. Such developments would reduce our opportunities to generate revenues. It is impossible at this time to determine what may occur, as customer plans will evolve over time and there is a possibility that Saudi Arabia and Russia will make a new deal to lift oil prices.  It is possible that the cumulative nature of these events could have a material adverse effect on our results of operations and financial position. These market conditions could also have a material adverse effect on the financial position of our customers, which could increase the risk that we are unable to collect accounts receivable from customers for services we have provided. We would aggressively act to protect our rights in any such event, as we have done in the past. For further discussion of the volatility of crude oil prices, please read “Risk Factors”.

 

  

Interest Rate Risk

The interest rate on our Credit Agreement floats based on LIBOR, and as a result we have exposure to changes in interest rates on this indebtedness, which was $74.9 million as of December 31, 2019 and $76.1 million as of December 31, 2018. A hypothetical change in interest rates of 1.0% would have resulted in an increase or decrease in our annual interest expense of approximately $0.8 million and $1.0 million for 2019 and 2018, respectively.

 

The credit markets have recently experienced historical lows in interest rates. It is possible that monetary policy will tighten, resulting in higher interest rates to counter possible inflation. Interest rates in the future could be higher than current levels, causing our financing costs to increase accordingly.

 

Counterparty and Customer Credit Risk

 

Our credit exposure generally relates to receivables for services provided. If significant customers were to have credit or financial problems resulting in a delay or failure to repay the amounts they owe to us, this could have a material adverse effect on our business, financial condition, results of operations or cash flows.

 

 

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

The following information is included in this Item 8:

 

Report of Independent Registered Public Accounting Firm	Page 84
Consolidated Balance Sheets as of December 31, 2019 and 2018	Page 85
Consolidated Statements of Operations for the Years Ended December 31, 2019, 2018, and 2017	Page 86
Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2019, 2018, and 2017	Page 87
Consolidated Statement of Owners’ Equity for the Years Ended December 31, 2019, 2018, and 2017	Page 88
Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018, and 2017	Page 89
Notes to Consolidated Financial Statements	Page 90

 

 

Report of Independent Registered Public Accounting Firm

 

To the Limited Partners of Cypress Environmental Partners, L.P.

and the Board of Directors of Cypress Environmental Partners, GP, LLC, 

General Partner of Cypress Environmental Partners, L.P.

 

Opinion on the Financial Statements

 

We have audited the accompanying consolidated balance sheets of Cypress Environmental Partners, L.P. (the “Partnership”) as of December 31, 2019 and 2018, and the related consolidated statements of operations, comprehensive income (loss), owners’ equity and cash flows for each of the three years in the period ended December 31, 2019, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership at December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with U.S. generally accepted accounting principles.

 

Basis for Opinion

 

These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

 

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting 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.

 

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

 

/s/ Ernst & Young LLP

 

We have served as the Partnership’s auditor since 2012.
Tulsa, Oklahoma
March 16, 2020

 

CYPRESS ENVIRONMENTAL PARTNERS, L.P.  

(formerly CYPRESS ENERGY PARTNERS, L.P.)
Consolidated Balance Sheets
As of December 31, 2019 and 2018
(in thousands)

 

		December 31,  2019				December 31, 2018
ASSETS
Current assets:
Cash and cash equivalents		$	15,700			$	15,380
Trade accounts receivable, net			52,524				48,789
Prepaid expenses and other			988				1,396
Total current assets			69,212				65,565
Property and equipment:
Property and equipment, at cost			26,499				23,988
Less: Accumulated depreciation			13,738				11,266
Total property and equipment, net			12,761				12,722
Intangible assets, net			20,063				22,759
Goodwill			50,356				50,294
Finance lease right-of-use assets, net			600				—
Operating lease right-of-use assets			2,942				—
Debt issuance costs, net			803				1,260
Other assets			605				253
Total assets		$	157,342			$	152,853
LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable		$	3,529			$	4,848
Accounts payable - affiliates			1,167				4,060
Accrued payroll and other			14,850				12,276
Income taxes payable			1,092				737
Finance lease obligations			183				90
Operating lease obligations			459				—
Total current liabilities			21,280				22,011
Long-term debt			74,929				76,129
Finance lease obligations			359				248
Operating lease obligations			2,425				—
Other noncurrent liabilities			158				178
Total liabilities			99,151				98,566
Commitments and contingencies - Note 13
Owners’ equity:
Partners’ capital:
Common units (12,068 and 11,947 units outstanding at December 31, 2019 and 2018, respectively)			37,334				34,677
Preferred units (5,769 units outstanding at December 31, 2019 and 2018)			44,291				44,291
General partner			(25,876	)			(25,876	)
Accumulated other comprehensive loss			(2,577	)			(2,414	)
Total partners’ capital			53,172				50,678
Noncontrolling interests			5,019				3,609
Total owners’ equity			58,191				54,287
Total liabilities and owners’ equity		$	157,342			$	152,853

 

See accompanying notes.

 

CYPRESS ENVIRONMENTAL PARTNERS, L.P.

(formerly CYPRESS ENERGY PARTNERS, L.P.)
Consolidated Statements of Operations
For the Years Ended December 31, 2019, 2018 and 2017
(in thousands, except per unit data)

 

		2019				2018				2017
Revenues		$	401,648			$	314,960			$	286,342
Costs of services			347,924				270,914				252,739
Gross margin			53,724				44,046				33,603
Operating costs and expense:
General and administrative			25,626				23,744				21,055
Depreciation, amortization and accretion			4,448				4,404				4,443
Impairments			—				—				3,598
Gain on asset disposals, net			(25	)			(4,108	)			(570	)
Operating income			23,675				20,006				5,077
Other income (expense):
Interest expense, net			(5,330	)			(6,206	)			(7,335	)
Debt issuance cost write-off			—				(114	)			—
Foreign currency gains (losses)			222				(643	)			732
Other, net			1,111				373				199
Net income (loss) before income tax expense			19,678				13,416				(1,327	)
Income tax expense			2,254				1,318				596
Net income (loss)			17,424				12,098				(1,923	)
Net income (loss) attributable to noncontrolling interests			1,410				685				(1,110	)
Net income (loss) attributable to partners / controlling interests			16,014				11,413				(813	)
Net loss attributable to general partner			—				—				(4,050	)
Net income attributable to limited partners			16,014				11,413				3,237
Net income attributable to preferred unitholder			4,133				2,445				—
Net income attributable to common unitholders		$	11,881			$	8,968			$	3,237
Net income per common limited partner unit:
Basic		$	0.99			$	0.75			$	0.29
Diluted		$	0.88			$	0.72			$	0.29
Weighted average common units outstanding:
Basic			12,039				11,929				11,152
Diluted			18,289				15,757				11,253
Net income per subordinated limited partner unit - basic and diluted		$	—			$	—			$	—
Weighted average subordinated units outstanding - basic and diluted			—				—				729

 

See accompanying notes.

 

 

CYPRESS ENVIRONMENTAL PARTNERS, L.P.  

(formerly CYPRESS ENERGY PARTNERS, L.P.)
Consolidated Statements of Comprehensive Income (Loss)
For the Years Ended December 31, 2019, 2018 and 2017
(in thousands)

 

		2019				2018				2017
Net income (loss)		$	17,424			$	12,098			$	(1,923	)
Other comprehensive income (loss) - foreign currency translation			(163	)			263				(139	)
Comprehensive income (loss)		$	17,261			$	12,361			$	(2,062	)
Comprehensive income attributable to preferred unitholders			4,133				2,445				—
Comprehensive income (loss) attributable to noncontrolling interests			1,410				685				(1,110	)
Comprehensive loss attributable to general partner			—				—				(4,050	)
Comprehensive income attributable to common unitholders		$	11,718			$	9,231			$	3,098

 

See accompanying notes.

 

 

CYPRESS ENVIRONMENTAL PARTNERS, L.P. 

(formerly CYPRESS ENERGY PARTNERS, L.P.)
Consolidated Statement of Owners’ Equity
For the Years Ended December 31, 2019, 2018 and 2017
(in thousands)

 

		Common Units				Preferred Units				General Partner				Subordinated Units				Accumulated Other Comprehensive Gain (Loss)				Noncontrolling Interests				Total Owners’ Equity
Owners’ equity at December 31, 2016		$	(7,722	)		$	—			$	(25,876	)		$	50,474			$	(2,538	)		$	5,050			$	19,388
Net income (loss)			3,237				—				(4,050	)			—				—				(1,110	)			(1,923	)
Foreign currency translation adjustment			—				—				—				—				(139	)			—				(139	)
Contributions attributable to General Partner			—				—				4,050				—				—				—				4,050
Distributions			(9,905	)			—				—				(2,405	)			—				(16	)			(12,326	)
Conversion of Subordinated Units to Common Units			48,111				—				—				(48,111	)			—				—				—
Equity-based compensation			1,017				—				—				42				—				—				1,059
Taxes paid related to net share settlement of equity-based compensation			(124	)			—				—				—				—				—				(124	)
Owners’ equity at December 31, 2017			34,614				—				(25,876	)			—				(2,677	)			3,924				9,985
Net income			8,968				2,445				—				—				—				685				12,098
Issuance of preferred units, net			—				43,258				—				—				—				—				43,258
Foreign currency translation adjustment			—				—				—				—				263				—				263
Distributions			(10,019	)			(1,412	)			—				—				—				(1,000	)			(12,431	)
Equity-based compensation			1,247				—				—				—				—				—				1,247
Taxes paid related to net share settlement of equity-based compensation			(133	)			—				—				—				—				—				(133	)
Owners’ equity at December 31, 2018			34,677				44,291				(25,876	)			—				(2,414	)			3,609				54,287
Net income			11,881				4,133				—				—				—				1,410				17,424
Foreign currency translation adjustment			—				—				—				—				(163	)			—				(163	)
Distributions			(10,109	)			(4,133	)			—				—				—				—				(14,242	)
Equity-based compensation			1,107				—				—				—				—				—				1,107
Taxes paid related to net share settlement of equity-based compensation			(222	)			—				—				—				—				—				(222	)
Owners’ equity at December 31, 2019		$	37,334			$	44,291			$	(25,876	)		$	—			$	(2,577	)		$	5,019			$	58,191

 

See accompanying notes.

 

CYPRESS ENVIRONMENTAL PARTNERS, L.P.  

(formerly CYPRESS ENERGY PARTNERS, L.P.)
Consolidated Statements of Cash Flows
For the Years Ended December 31, 2019, 2018 and 2017
(in thousands)

 

		2019				2018				2017
Operating activities:
Net income (loss)		$	17,424			$	12,098			$	(1,923	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, amortization and accretion			5,537				5,480				5,544
Impairments			—				—				3 ,598
Gain on asset disposals, net			(25	)			(4,108	)			(570	)
Interest expense from debt issuance cost amortization			533				560				594
Debt issuance cost write-off			—				114				—
Equity-based compensation expense			1,107				1,247				1,059
Equity in earnings of investee			(214	)			(217	)			(149	)
Distributions from investee			75				175				75
Deferred tax (expense) benefit, net			(36	)			51				(372	)
Non-cash allocated expenses			—				—				1,750
Foreign currency (gains) losses			(222	)			643				(732	)
Gain on litigation settlement			(1,254	)			—				—
Loss on sale of accounts receivable			515				—				—
Changes in assets and liabilities:
Trade accounts receivable			(4,247	)			(7,165	)			(3,406	)
Prepaid expenses and other			136				1,004				(1,321	)
Accounts payable and accounts payable - affiliates			(3,681	)			2,273				2,947
Accrued payroll and other			2,175				3,167				1,524
Income taxes payable			356				87				(365	)
Net cash provided by operating activities			18,179				15,409				8,253
Investing activities:
Proceeds from fixed asset disposals, including insurance proceeds			43				12,769				2,304
Purchases of property and equipment			(1,976	)			(5,762	)			(3,345	)
Net cash (used in) provided by investing activities			(1,933	)			7,007				(1,041	)
Financing activities:
Issuance of preferred units, net of issuance costs			—				43,258				—
Borrowings on credit facility			7,800				2,500				—
Payments on credit facility			(9,000	)			(63,271	)			—
Debt issuance cost payments			(75	)			(1,327	)			—
Repayments on finance lease obligations			(191	)			(62	)			—
Taxes paid related to net share settlement of equity-based compensation			(222	)			(133	)			(124	)
Contributions from general partner			—				—				2,300
Distributions			(14,242	)			(12,431	)			(12,326	)
Net cash used in financing activities			(15,930	)			(31,466	)			(10,150	)
Effect of exchange rates on cash			4				(17	)			753
Net increase (decrease) in cash and cash equivalents			320				(9,067	)			(2,185	)
Cash and cash equivalents, beginning of period (includes restricted cash equivalents of $551 at December 31, 2018 and $490 at December 31, 2017 and 2016)			15,931				24,998				27,183
Cash and cash equivalents, end of period (includes restricted cash equivalents of $551 at December 31, 2019 and 2018, and $490 at December 31, 2017)		$	16,251			$	15,931			$	24,998
Non-cash items:
Accounts payable and accrued payroll and other excluded from capital expenditures		$	1,148			$	25			$	567
Acquisitions of finance leases included in liabilities		$	357			$	400			$	—
Supplemental cash flow disclosures:
Cash taxes paid		$	1,980			$	1,174			$	1,350
Cash interest paid		$	4,783			$	5,781			$	6,842

 

See accompanying notes.

 

 

CYPRESS ENVIRONMENTAL PARTNERS, L.P.

(formerly CYPRESS ENERGY PARTNERS, L.P.) 

Notes to Consolidated Financial Statements

 

1.	Organization and Operations

 

Cypress Environmental Partners, L.P. (“we”, “us”, “our”, or the “Partnership”) is a Delaware limited partnership formed in 2013. We offer essential services that help protect the environment and ensure sustainability. We provide a wide range of environmental services including independent inspection, integrity, and support services for pipeline and energy infrastructure owners and operators and public utilities. We also provide water pipelines, hydrocarbon recovery, disposal, and water treatment services. Trading of our common units began January 15, 2014 on the New York Stock Exchange under the symbol “CELP”. Our business is organized into the Pipeline Inspection Services (“Pipeline Inspection”), Pipeline & Process Services (“Pipeline & Process Services”), and Water and Environmental Services (“Environmental Services”) segments.

 

The Pipeline Inspection segment generates revenue primarily by providing essential environmental services including inspection and integrity services on a variety of infrastructure assets including midstream pipelines, gathering systems, and distribution systems. Services include nondestructive examination, in-line inspection support, pig tracking, survey, data gathering, and supervision of third-party contractors. Our results in this segment are driven primarily by the number of inspectors that perform services for our customers and the fees that we charge for those services, which depend on the type, skills, technology, equipment, and number of inspectors used on a particular project, the nature of the project, and the duration of the project. The number of inspectors engaged on projects is driven by the type of project, prevailing market rates, the age and condition of customers’ assets including pipelines, gas plants, compression stations, storage facilities, and gathering and distribution systems including the legal and regulatory requirements relating to the inspection and maintenance of those assets. We also bill our customers for per diem charges, mileage, and other reimbursement items. Revenue and costs in this segment may be subject to seasonal variations and interim activity may not be indicative of yearly activity considering that many of our customers develop yearly operating budgets and enter into contracts with us during the winter season for work to be performed during the remainder of the year. Additionally, inspection work throughout the United States during the winter months (especially in the northern states) may be hampered or delayed due to inclement weather.

 

The Pipeline & Process Services segment generates revenue primarily by providing essential environmental services including hydrostatic testing services and chemical cleaning to energy companies and pipeline construction companies of newly-constructed and existing pipelines and related infrastructure. We generally charge our customers in this segment on a fixed-bid basis, depending on the size and length of the pipeline being tested, the complexity of services provided, and the utilization of our work force and equipment. Our results in this segment are driven primarily by the number of field personnel that perform services for our customers and the fees that we charge for those services, which depend on the type and number of field personnel used on a particular project, the type of equipment used and the fees charged for the utilization of that equipment, and the nature and duration of the project. Revenue and costs in this segment may be subject to seasonal variations and interim activity may not be indicative of yearly activity, considering that many of our customers develop yearly operating budgets and enter into contracts with us for work to be performed during the remainder of the year. Additionally, field work during the winter months may be hampered or delayed due to inclement weather.

 

The Environmental Services segment owns and operates nine (9) water treatment facilities with ten (10) EPA Class II injection wells in the Bakken shale region of the Williston Basin in North Dakota.  These water treatment facilities are connected to twelve (12) pipeline gathering systems, including two (2) that we developed and own. We specialize in the treatment, recovery, separation, and disposal of waste byproducts generated during the lifecycle of an oil and natural gas well to protect the environment and our drinking water. All of the water treatment facilities utilize specialized equipment and remote monitoring to minimize the facilities’ downtime and increase the facilities’ efficiency for peak utilization. Revenue is generated on a fixed-fee per barrel basis for receiving, separating, filtering, recovering,  processing, and injecting produced and flowback water. We also sell recovered oil, receive fees for pipeline transportation of water, and receive fees from a partially owned water treatment facility for management and staffing services (see Note 11).

 

The volumes of water processed at our water treatment facilities are driven by water volumes generated from existing oil and natural gas wells during their useful lives and development drilling. Producers’ willingness to engage in new drilling is determined by a number of factors, the most important of which are the current and projected prices of oil, natural gas, and natural gas liquids; 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 correlate with long-term trends in prices of oil, natural gas, and natural gas liquids.

 

 

CYPRESS ENVIRONMENTAL PARTNERS, L.P.

(formerly CYPRESS ENERGY PARTNERS, L.P.) 

Notes to Consolidated Financial Statements

 

We also generate revenues from the sale of residual oil recovered during the water treatment process. Our ability to recover 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 is usually lower than our recovery during the summer. Additionally, residual oil content can decrease based on the following factors, among others: an increase in pipeline water as operators control the flow of pipeline water and an increase in residual oil recovered in saltwater by producers prior to delivering the saltwater to us for treatment. 

 

2.	Basis of Presentation and Significant Accounting Policies

 

Basis of Presentation

 

The accompanying Consolidated Financial Statements include our accounts and those of our controlled subsidiaries. All intercompany transactions and account balances have been eliminated in consolidation. Investments over which we exercise significant influence, but do not control, are accounted for using the equity method of accounting.

 

The accompanying Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for consolidated financial information and in accordance with the rules and regulations of the Securities and Exchange Commission. The Consolidated Financial Statements include all adjustments considered necessary for a fair presentation of the financial position and results of operations for the periods presented.

 

Use of Estimates in the Preparation of Financial Statements

 

The preparation of financial statements in conformity with GAAP 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 include, among others, amounts of expected future cash flows used in determining possible impairments of property and equipment, intangible assets, and goodwill; the determination of fair values of assets acquired and liabilities assumed in business combinations; the allocation of goodwill to disposals of assets; the amount and timing of future asset retirement obligations; and the useful lives of property, equipment and intangible assets. Certain estimates are inherently imprecise and may change as future information becomes available. The use of alternative judgments and/or assumptions could result in different outcomes.

 

Fair Value Measurement

 

We utilize fair value measurements to measure assets in a business combination or assess impairment of property and equipment, intangible assets, and goodwill. Fair value is the amount received from the sale of an asset or the amount paid to transfer a liability in an orderly transaction between market participants (an exit price) at the measurement date. Fair value is a market-based measurement considered from the perspective of a market participant. We use market data or assumptions that we believe market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation. These inputs can be readily observable, market corroborated, or unobservable. We apply both market and income approaches for fair value measurements using the best available information while utilizing valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.

 

The fair value hierarchy in GAAP prioritizes the inputs used to measure fair value, giving the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The Partnership classifies fair value balances based on the observability of those inputs.  The three levels of the fair value hierarchy are as follows:

 

●

Level 1 – Quoted prices for identical assets or liabilities in active markets that management has the ability to access. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

 

●

Level 2 – Inputs are other than quoted prices in active markets included in Level 1 that are either directly or indirectly observable. These inputs are either directly observable in the marketplace or indirectly observable through corroboration with market data for substantially the full contractual term of the asset or liability being measured.

 

 

CYPRESS ENVIRONMENTAL PARTNERS, L.P.

(formerly CYPRESS ENERGY PARTNERS, L.P.) 

Notes to Consolidated Financial Statements

 

●

Level 3 – Inputs that are not observable for which there is little, if any, market activity for the asset or liability being measured. These inputs reflect management’s best estimate of the assumptions market participants would use in determining fair value.

 

Contributions Attributable to General Partner

 

During 2017, Holdings incurred overhead expenses on our behalf totaling $1.8 million. These costs represent administrative expenses incurred by Holdings in excess of amounts charged to us under our omnibus agreement.  These expenses are reflected as general and administrative and as a component of the net loss attributable to general partner in the Consolidated Statements of Operations for 2017 and as contributions attributable to general partner in the Consolidated Statement of Owners’ Equity.

 

In addition to incurring the expenses described above, Holdings provided us with additional financial support by making cash contributions of $2.3 million in 2017 as a reimbursement for certain expenditures incurred by us. These cash contributions are reflected as a contribution attributable to general partner in the Consolidated Statement of Owners’ Equity and as a component of the net loss attributable to general partner in the Consolidated Statements of Operations for 2017.

 

Cash and Cash Equivalents

 

We consider 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 sheet approximate fair value.

 

As of December 31, 2019, U.S. cash balances are insured by the Federal Deposit Insurance Corporation (FDIC) up to $250,000 per financial institution. Canadian cash balances are insured by the Canada Deposit Insurance Corporation (CDIC) up to $100,000 (Canadian Dollars) per financial institution. Our cash is primarily held at three financial institutions, and therefore is in excess of the FDIC or CDIC insurance limits. We periodically assess the financial condition of the institutions where we deposit funds.

 

Restricted Cash

 

Restricted cash was approximately $0.6 million at December 31, 2019 and 2018, respectively. These amounts are included in prepaid expenses and other on the Consolidated Balance Sheets.

 

Accounts Receivable, Allowance for Bad Debts and Concentration of Credit Risk

 

We grant unsecured credit to customers under normal industry standards and terms, and have established policies and procedures that allow for an evaluation of each of our customer’s creditworthiness. We typically receive payment from our customers 45 to 90 days after the services have been performed. We determine allowances for bad debts based on management’s assessment of the creditworthiness of our customers. Trade receivables are written off against the allowance when deemed uncollectible. Recoveries of trade receivables previously written off are recorded when cash is received. We do not typically charge interest on past due trade receivables nor do we require collateral on our trade receivables. We had an allowance for doubtful accounts of $0.2 million and less than $0.1 million at December 31, 2019 and 2018, respectively. We recorded bad debt expense of $0.2 million in 2019 and less than $0.1 million in 2018 and 2017. In 2019 and 2017, we received $0.1 million and $0.3 million, respectively, on accounts receivable previously written off which we recorded as a reduction to general and administrative on our Consolidated Statements of Operations.

 

We had four customers, Pacific Gas & Electric Company, Plains All American Pipeline L.P., ONEOK, Inc. and Phillips 66 that represented more than 10% of total accounts receivable as of December 31, 2019.

 

The majority of our revenues are generated in the United States. Total revenues generated in Canada were $0.2 million, $1.3 million, and $23.4 million in 2019, 2018, and 2017, respectively.

 

Pacific Gas and Electric Bankruptcy

 

PG&E Corporation and its wholly-owned subsidiary Pacific Gas and Electric Company (collectively, “PG&E”) filed for bankruptcy protection on January 29, 2019. As of December 31, 2018, the assets on our Consolidated Balance Sheet included $10.3 million of accounts receivable from PG&E. We collected $1.0 million of this balance in January 2019 prior to PG&E’s bankruptcy filing. We generated $2.8 million of revenue from PG&E during the period from January 1, 2019 through January 28, 2019, bringing the total accounts receivable from PG&E to $12.1 million as of the date of the bankruptcy filing.

 

 

CYPRESS ENVIRONMENTAL PARTNERS, L.P.

(formerly CYPRESS ENERGY PARTNERS, L.P.) 

Notes to Consolidated Financial Statements

 

In November 2019, we sold $10.4 million of our pre-petition receivables from PG&E in a non-recourse sale to a third party for cash proceeds of $9.8 million. We recorded a loss of $0.5 million in the fourth quarter of 2019 on the sale of these pre-petition receivables reported within Other, net on our Consolidated Statement of Operations. In March 2020 we collected from PG&E the remaining $1.7 million of pre-petition receivables under a court-approved “operational integrity supplier program”.

 

Sanchez Bankruptcy

 

Sanchez Energy Corporation and certain of its affiliates (collectively, “Sanchez”), a former customer, filed for bankruptcy protection in August 2019. As of December 31, 2019, our Consolidated Balance Sheet included $0.5 million of pre-petition accounts receivable from Sanchez. We have recorded an allowance of less than $0.1 million at December 31, 2019 against the accounts receivable from Sanchez. We do not believe it is probable that we will be unable to collect the remaining $0.4 million balance of the pre-petition receivables. However, due to uncertainties associated with the bankruptcy process, we cannot make assurances regarding the ultimate collection of these receivables nor can we make assurances regarding the timing of any such collections.

 

Property and Equipment     

 

Property and equipment consists of land, land and leasehold improvements, buildings, facilities, wells and related equipment, field equipment, computer and office equipment, and vehicles. We record 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. We depreciate property and equipment on a straight-line basis over the estimated useful lives of the assets. Upon retirement, disposition, or impairment of an asset, we remove the cost and related accumulated depreciation from the balance sheet and report the resulting gain or loss, if any, in the Consolidated Statement of Operations.

 

Debt Issuance Costs

 

Debt issuance costs represent fees and expenses associated with securing our Credit Agreement (see Note 6). Amortization of the capitalized debt issuance costs is recorded on a straight-line basis over the term of the Credit Agreement.

 

Income Taxes

 

As a limited partnership, we generally are not subject to federal, state or local income taxes. The tax on our net income is generally borne by the individual partners. Net income (loss) for financial statement purposes may differ significantly from taxable income (loss) of the partners as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. The aggregated difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner’s tax attributes is not available to us.

 

The income of Tulsa Inspection Resources – Canada, ULC, our Canadian subsidiary, is taxable in Canada. Tulsa Inspection Resources – PUC, LLC (“TIR-PUC”), a subsidiary of our Pipeline Inspection segment that performs pipeline inspection services for utility customers, and Cypress Brown Integrity - PUC, LLC, a 51% owned subsidiary, have elected to be taxed as corporations for U.S. federal income tax purposes, and therefore these subsidiaries are subject to U.S. federal and state income taxes. The amounts recognized as income tax expense, income taxes payable, and deferred tax liabilities in our Consolidated Financial Statements represent the Canadian and U.S. taxes referred to above, as well as partnership-level taxes levied by various states, most notably, franchise taxes assessed by the state of Texas.

 

As a publicly-traded partnership, we are subject to a statutory requirement that at least 90% of our total gross income is classified as “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations, and Internal Revenue Service pronouncements), determined on a calendar year basis. If our qualifying income does not meet this statutory requirement, we could be taxed as a corporation for federal and state income tax purposes. Our income has met the statutory qualifying income requirement for each year since our IPO.

 

We evaluate uncertain tax positions for recognition and measurement in the Consolidated Financial Statements. To recognize a tax position, we determine whether it is more likely than not that a tax position 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 Consolidated 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. We had no uncertain tax positions that required recognition in the financial statements at December 31, 2019 or 2018. Any interest or penalties would be recognized as a component of income tax expense.

 

 

CYPRESS ENVIRONMENTAL PARTNERS, L.P.

(formerly CYPRESS ENERGY PARTNERS, L.P.) 

Notes to Consolidated Financial Statements

 

Revenue Recognition

 

Under Accounting Standards Codification (“ASC”) 606 - Revenue from Contracts with Customers, an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Based on this accounting guidance, our revenue is earned and recognized through the service offerings of our three reportable business segments. Our sales contracts have terms of less than one year. As such, we have used the practical expedient contained within the accounting guidance which exempts us from the requirement to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract with an original expected duration of one year or less. We apply judgment in determining whether we are the principal or the agent in instances where we utilize subcontractors to perform all or a portion of the work under our contracts. Based on the criteria in ASC 606, we have determined we are principal in all such circumstances. See Note 14 for disaggregated revenue reported by segment.

 

In the third quarters of 2019 and 2018, we recognized $0.2 million and $0.5 million of revenue within our Pipeline Inspection segment, respectively, on services performed in previous years. We had constrained recognition of this revenue until the expiration of a contract provision that had given the customer the opportunity to reopen negotiation of the fee paid for the services. As of December 31, 2019 and December 31, 2018, we recognized a refund liability of $0.7 million and $0.4 million within our Pipeline Inspection segment, respectively, for revenue associated with such variable consideration. In the fourth quarter of 2019, we received a signed contract modification from one of our customers for a price increase that was retroactive to June 2019. We recognized $0.5 million of revenue within our Pipeline Inspection segment in the fourth quarter of 2019 related to this retroactive price increase.  In the first quarter of 2018, we recognized $0.3 million of revenue within our Pipeline & Process Services segment associated with additional billings on a project that we completed in the fourth quarter of 2017 (we recognized the revenue upon receipt of customer acknowledgment of the additional fees).

 

Accrued Payroll and Other

 

Accrued payroll and other on our Consolidated Balance Sheets includes the following:

 

		December 31, 2019				December 31, 2018
			(in thousands)
Accrued payroll		$	9,670			$	9,468
Customer deposits			1,682				1,202
Litigation settlement (Note 13)			1,900				—
Other			1,598				1,606
		$	14,850			$	12,276

 

Fair Value of Financial Instruments

 

The carrying amounts reported in the Consolidated Balance Sheets for cash and cash equivalents; trade accounts receivable, net; prepaid expenses and other; accounts payable; accounts payable – affiliates; accrued payroll and other; and income taxes 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 our Consolidated Balance Sheets. The following methods and assumptions were used to estimate the fair values:

 

Property, Plant, and Equipment

 

We assess property and equipment for possible impairment whenever events or changes in circumstances indicate, in the judgment of management, that the carrying value of the assets may not be recoverable. Such indicators include, among others, the nature of the asset, the projected future economic benefit of the asset, changes in regulatory and political environments, and historical and future cash flow and profitability measurements. If the carrying value of an asset exceeds the future undiscounted cash flows expected from the asset, we recognize an impairment charge for the excess of carrying value of the asset over its estimated fair value. Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain matters such as future commodity prices, the effects of inflation on operating expenses, and the outlook for national or regional market supply and demand for the services we provide. Assets are grouped for impairment purposes at each water treatment facility in the Environmental Services segment, as these asset groups represent the lowest level at which cash flows are separately identifiable.

 

 

CYPRESS ENVIRONMENTAL PARTNERS, L.P.

(formerly CYPRESS ENERGY PARTNERS, L.P.) 

Notes to Consolidated Financial Statements

 

Goodwill

 

At December 31, 2019 and 2018, we had $50.4 million and $50.3 million, respectively, of goodwill on our Consolidated Balance Sheets. Goodwill is not amortized, but is subject to annual assessments on November 1 (or at other dates if events or changes in circumstances indicate that the carrying value of goodwill may be impaired) for impairment at a reporting unit level. The reporting units used to evaluate and measure goodwill for impairment are determined primarily from the manner in which the business is managed or operated. We have determined that our Pipeline Inspection, Pipeline & Process Services, and Environmental Services operating segments are the appropriate reporting units for testing goodwill impairment.

 

To perform a goodwill impairment assessment, we first evaluate qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit exceeds its carrying value. If this assessment reveals that it is more likely than not that the carrying value of a reporting unit exceeds its fair value, we then determine the estimated fair market value of the reporting unit. If the carrying amount exceeds the reporting unit’s fair value, we record a goodwill impairment charge for the excess (not exceeding the carrying value of the reporting unit’s goodwill). 

 

Identifiable Intangible Assets

 

Our intangible assets consist primarily of customer relationships, trade names, and our database of inspectors. We recorded these intangible assets as part of our accounting for the acquisitions of businesses and we amortize these assets on a straight-line basis over their estimated useful lives, which typically range from 5 – 20 years (see Note 5).

 

We review our intangible assets for impairment whenever events or circumstances indicate that the asset group to which they relate may be impaired. To perform an impairment assessment, we first determine whether the cash flows expected to be generated from the asset group exceed the carrying value of the asset group. If such estimated cash flows do not exceed the carrying value of the asset group, we reduce the carrying value of the assets to their fair values and record a corresponding impairment loss.

 

Depending on future events, it is reasonably possible that we could incur impairment charges associated with our property and equipment, goodwill, or intangible assets.

 

Noncontrolling Interests

 

We own a 51% interest in Brown and a 49% interest in CF Inspection Management, LLC (“CF Inspection”). The accounts of these subsidiaries are included in our Consolidated Financial Statements. The portion of the net income (loss) of these entities that is attributable to outside owners is reported in net income (loss) attributable to noncontrolling interests in our Consolidated Statements of Operations, and the portion of the net assets of these entities that is attributable to outside owners is reported in noncontrolling interests in our Consolidated Balance Sheets. Brown’s company agreement generally requires Brown to make an annual distribution to its members equal to or greater than the amount of Brown’s taxable income multiplied by the maximum federal income tax rate.

   

Business Combinations

 

We evaluate all potential acquisitions and changes in control to determine whether we have purchased or acquired control of a business. If the acquired or newly-controlled assets meet the definition of a business, the transaction is accounted for as a business combination; otherwise it is accounted for as an asset acquisition.

 

Gains on Asset Disposals

 

During 2018, we sold our two water treatment facilities in Texas and recorded a combined gain of $3.6 million. During 2018, we received proceeds of $0.4 million from the settlement of litigation related to lightning strikes that occurred in 2017 at our facilities in Orla, Texas and Grassy Butte, North Dakota. This litigation related to the non-performance of certain lightning protection equipment we had purchased to protect the facilities against lightning strikes. The proceeds from these settlements are reported within gain on asset disposals, net in our Consolidated Statements of Operations.

 

During 2017, lightning strikes and the resultant fires destroyed the surface equipment at two of our facilities. We carried property damage and cleanup insurance on both facilities, and the proceeds we received on these policies were in excess of the net book value of the destroyed property and the cleanup costs we incurred. We recorded a net gain of $0.6 million in 2017 related to these incidents, reported within gain on asset disposals, net in our Consolidated Statements of Operations.

 

 

CYPRESS ENVIRONMENTAL PARTNERS, L.P.

(formerly CYPRESS ENERGY PARTNERS, L.P.) 

Notes to Consolidated Financial Statements

 

Foreign Currency Translation

 

Our Consolidated Financial Statements are reported in U.S. dollars. We translate our Canadian-dollar-denominated assets and liabilities into U.S. dollars at the exchange rate in effect at the balance sheet date. We translate our Canadian-dollar-denominated revenues and expenses into U.S. dollars at the average exchange rate in effect during the period.

 

Our Consolidated Balance Sheet at December 31, 2019 includes $2.6 million of accumulated other comprehensive loss associated with accumulated currency translation adjustments, all of which relate to our Canadian operations. If at some point in the future we were to substantially liquidate our Canadian operations, we would reclassify the balance in accumulated other comprehensive loss to other accounts within partners’ capital, which would be reported in the Consolidated Statements of Operations as a reduction to net income.

 

Our Canadian subsidiary has certain payables to our U.S.-based subsidiaries. These intercompany payables and receivables among our consolidated subsidiaries are eliminated in our Consolidated Balance Sheets. Beginning April 1, 2017, with the expiration of a contract with our largest Canadian customer, we report currency translation adjustments on these intercompany payables and receivables within foreign currency gains (losses) in our Consolidated Statements of Operations. Prior to April 1, 2017, we reported currency translation adjustments on these intercompany payables and receivables within other comprehensive income (loss). We continue to report currency translation adjustments on other Canadian activity and balances within accumulated other comprehensive loss in our Consolidated Statement of Owners’ Equity.

 

New Accounting Standards

 

In 2019, we adopted the following new accounting standard issued by the Financial Accounting Standards Board (“FASB”):

 

The FASB issued ASU 2016-02 – Leases in February 2016. This guidance attempts to increase transparency and comparability among organizations by recognizing certain lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between previous GAAP methodology and the method used in this new guidance is the recognition on the balance sheet of lease assets and lease liabilities by lessees for certain operating leases.

 

We made accounting policy elections to not capitalize leases with a lease term of twelve months or less and to not separate lease and non-lease components for all asset classes. We also elected the package of practical expedients within ASU 2016-02 that allows an entity to not reassess prior to the effective date (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases, or (iii) initial direct costs for any existing leases, but did not elect the practical expedient of hindsight when determining the lease term of existing contracts at the effective date.

 

In July 2018, the FASB issued ASU 2018-11 – Targeted Improvements, which provided entities with a transition option to not restate the comparative periods for the effects of applying the new leasing standard (i.e. comparative periods presented in the Consolidated Financial Statements will continue to be in accordance with Accounting Standards Codification 840). We adopted the new standard on the effective date of January 1, 2019 and used a modified retrospective approach as permitted under ASU 2018-11. The effects of implementing ASU 2016-02 included the addition of right-of-use assets and associated lease liabilities to our Consolidated Balance Sheet, but were immaterial to our Consolidated Statement of Operations and Consolidated Statement of Cash Flows. The cumulative effect adjustment was not material to partners’ capital on our Consolidated Balance Sheet. Upon adoption, we recorded operating lease right-of-use assets of $3.5 million and current and noncurrent operating lease obligations of $0.5 million and $3.0 million, respectively. Liabilities recorded as a result of this standard are excluded from the definition of indebtedness under our credit facility, and therefore do not affect the leverage ratio under our credit facility.

 

In 2018, we adopted the following new accounting standards issued by the FASB: 

 

The FASB issued Accounting Standards Update (“ASU”) 2014-09 – Revenue from Contracts with Customers in May 2014. ASU 2014-09 is intended to clarify the principles for recognizing revenue and to develop a common standard for recognizing revenue for GAAP and International Financial Reporting Standards that is applicable to all organizations. This guidance requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to receive in exchange for those goods and services. It also requires additional disclosure about the nature, amount, timing, and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to obtain or fulfill a contract. We adopted this new standard utilizing the modified retrospective transition approach. The adoption of this ASU had no effect on our Consolidated Financial Statements other than additional disclosures included in our Consolidated Financial Statements.

 

The FASB issued ASU 2016-18 - Statement of Cash Flows - Restricted Cash in November 2016. This ASU requires entities to show the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents in the statement of cash flows on a retrospective basis. The requirements of this ASU have been reflected in our Consolidated Statements of Cash Flows for all periods presented. Under this ASU, certain short-term security deposits are reported as restricted cash in our Consolidated Statements of Cash Flows.  

 

 

CYPRESS ENVIRONMENTAL PARTNERS, L.P.

(formerly CYPRESS ENERGY PARTNERS, L.P.) 

Notes to Consolidated Financial Statements

 

In 2017, we adopted the following new accounting standards issued by the FASB:

 

The FASB issued ASU 2016-09 – Compensation – Stock Compensation in March 2016. This ASU gives entities the option to account for forfeitures of share-based awards when the forfeitures occur (previously, entities were required to estimate future forfeitures and reduce their share-based compensation expense accordingly). We adopted this new standard on January 1, 2017 and elected to account for forfeitures as they occur. The adoption of this ASU had no significant effect on our Consolidated Financial Statements.

 

The FASB issued ASU 2017-04 – Intangibles – Goodwill and Other in January 2017. The objective of this guidance is to simplify how an entity is required to calculate amounts of goodwill impairments. We adopted this new standard effective January 1, 2017 in order to simplify the measurement process for impairments of goodwill. Under the new standard, we perform a goodwill impairment test by comparing the fair value of a reporting unit to its carrying amount. If the carrying amount exceeds the reporting unit’s fair value, we record a goodwill impairment charge for the excess (not to exceed the carrying value of the reporting unit’s goodwill).

 

Other accounting guidance proposed by the FASB impacting our Consolidated Financial Statements which we adopted on January 1, 2020 include:

 

The FASB issued ASU 2018-15 – Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract in August 2018. This guidance requires a customer in a cloud computing arrangement to follow the internal use software guidance in ASC 350-40 to determine which costs should be capitalized as assets or expensed as incurred. The amendments in this ASU are effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. We adopted this guidance prospectively from the date of adoption (January 1, 2020) and do not believe this guidance will have a material effect on our Consolidated Financial Statements.

 

Other accounting guidance proposed by the FASB that may impact our Consolidated Financial Statements, which we have not yet adopted include:

 

The FASB issued ASU 2016-13 – Financial Instruments – Credit Losses in June 2016, which replaces the current “incurred loss” methodology for recognizing credit losses with an “expected loss” methodology. This guidance affects trade receivables, financial assets and certain other instruments that are not measured at fair value through net income. In November 2019, the FASB issued final guidance to delay the implementation of this new guidance for smaller reporting companies until fiscal years beginning after December 15, 2022, including interim periods within those fiscal years. We are currently evaluating the impact this ASU will have on our Consolidated Financial Statements.

 

 

CYPRESS ENVIRONMENTAL PARTNERS, L.P.

(formerly CYPRESS ENERGY PARTNERS, L.P.) 

Notes to Consolidated Financial Statements

 

3.	Property and Equipment

 

Property and equipment consist of the following, recorded at cost, as of December 31, 2019 and 2018:

 

						December 31,
Asset Category		Useful Lives (years)				2019				2018
						(in thousands)
Land						$	1,301			$	1,301
Land improvements			15				984				952
Buildings and leasehold improvements			30 - 39				1,183				1,183
Facilities, wells and equipment			5 - 15				19,231				18,736
Computer and office equipment			3 - 9				3,454				1,357
Vehicles and other			3 - 5				346				459
							26,499				23,988
Less accumulated depreciation							(13,738	)			(11,266	)
Net property, plant and equipment						$	12,761			$	12,722

 

Depreciation expense is computed using the straight-line method over the estimated useful lives of the assets. Depreciation expense was $2.8 million, $2.8 million, and $2.7 million in 2019, 2018, and 2017, respectively, of which $1.1 million was included as a component of costs of services in each of 2019, 2018, and 2017. In 2019, depreciation expense also included $0.2 million related to finance leases. In 2018, we sold two of our water treatment facilities, which reduced accumulated depreciation by $0.7 million, and we sold other property and equipment which reduced accumulated depreciation by $0.1 million. In 2019, we sold other property and equipment which reduced accumulated depreciation by $0.1 million.  

 

During 2017, we recorded an impairment of property and equipment at one of our water treatment facilities. We had experienced revenue and volume decreases at this facility due to lower commodity pricing and increasing competition and had forecasted decreases in drilling activity over the remaining life of the facility. Given these indicators of impairment, we compared our estimates of undiscounted future cash flows from the facility to the carrying amounts of the long-lived assets of the facility, and determined that the carrying value was no longer recoverable. We recognized an impairment of $0.7 million included within impairments on the Consolidated Statements of Operations for 2017. We impaired the full carrying value of the property and equipment (although, we did not conclude that the land was fully impaired). Fair value was determined using expected future cash flows, which is a Level 3 input as defined in ASC 820, Fair Value Measurement. The cash flows are those expected to be generated by the market participants, discounted at our estimated cost of capital. 

 

 

CYPRESS ENVIRONMENTAL PARTNERS, L.P.

(formerly CYPRESS ENERGY PARTNERS, L.P.) 

Notes to Consolidated Financial Statements

 

4.

Goodwill

 

Goodwill represents the excess of cost over fair value of the assets and liabilities of businesses acquired. Changes in goodwill are as follows:

  

		Pipeline				Pipeline and				Environmental
		Inspection				Process Services				Services				Total
							(in thousands)
Balance - December 31, 2016		$	40,247			$	1,581			$	15,075			$	56,903
Impairments			—				(1,581	)			—				(1,581	)
Foreign currency translation			97				—				—				97
Reclassified to assets held for sale			—				—				(1,984	)			(1,984	)
Balance - December 31, 2017		$	40,344			$	—			$	13,091			$	53,435
Foreign currency translation			(116	)			—				—				(116	)
Dispositions			—				—				(3,025	)			(3,025	)
Balance - December 31, 2018		$	40,228			$	—			$	10,066			$	50,294
Foreign currency translation			62				—				—				62
Balance - December 31, 2019		$	40,290			$	—			$	10,066			$	50,356

 

Goodwill is not amortized, but is subject to annual reviews on November 1 (or other dates if events or changes in circumstances warrant) for impairment at a reporting unit level. We have determined that the Pipeline Inspection, Pipeline & Process Services, and Environmental Services operating segments are the appropriate reporting units for testing goodwill for impairment.

 

Pipeline Inspection

 

For our Pipeline Inspection segment, we performed qualitative goodwill impairment analyses, and concluded that the fair value of the reporting unit was more likely than not greater than its carrying value. Our evaluations included various qualitative factors, including current and projected earnings, current customer relationships and projects, and the impact of commodity prices on our earnings. The qualitative assessments on this reporting unit indicated that there was no need to conduct further quantitative testing for goodwill impairment. The use of different assumptions and estimates from the assumptions and estimates we used in our qualitative analyses could have resulted in the requirement to perform quantitative goodwill impairment analyses.

 

Pipeline & Process Services

 

In the first quarter of 2017, we recorded an impairment to the remaining $1.6 million carrying value of the goodwill of the Pipeline & Process Services segment. Revenues of this segment were lower than we had expected for the first quarter of 2017. In addition, for this segment, the level of bidding activity for work is typically high in March and April, once customers have finalized their budgets for the upcoming year. While we won bids on a number of projects and our backlog began to improve, the improvement in the backlog was slower than we had originally anticipated, and we revised downward our expectations of the near-term operating results of the segment. We estimated the fair value of the Pipeline & Process Services segment utilizing the income approach (discounted cash flows) valuation method, which is a Level 3 input as defined in ASC 820, Fair Value Measurement. Significant inputs in the valuation included projections of future revenues, anticipated operating costs and appropriate discount rates. Significant assumptions included a 2% annual growth rate of cash flows and a discount rate of 18%. We determined through this analysis that the fair value of goodwill of the Pipeline & Process Services segment was fully impaired. These calculations represent Level 3 non-recurring fair value measurements. This impairment loss is included in impairments on the Consolidated Statement of Operations for 2017.

 

Environmental Services

 

We completed our annual goodwill impairment assessment as of November 1, 2019 and concluded that the goodwill of the Environmental Services segment was not impaired. We performed a qualitative analysis that took into consideration current and budgeted future cash flows and the fact that we sold two of our water treatment facilities in 2018 at prices that exceeded their carrying values for a combined gain of $3.6 million, which is included in gain on asset disposals, net in our Consolidated Statements of Operations for 2018. Based on these qualitative considerations, we concluded that carrying value of the goodwill of the Environmental Services segment was not impaired. The use of different assumptions and estimates from the assumptions and estimates we used in our qualitative analyses could have resulted in the requirement to perform quantitative goodwill impairment analyses.

 

In May 2018, we sold our Orla, Texas water treatment facility. The net book value of the assets sold included $3.0 million of allocated goodwill, calculated based on the estimated fair value of the Orla facility relative to the estimated fair value of the Environmental Services reporting unit as a whole. In January 2018, we sold our Pecos, Texas water treatment facility. The net book value of the assets sold included $2.0 million of allocated goodwill, calculated based on the estimated fair value of the Pecos facility relative to the estimated fair value of the Environmental Services reporting unit as a whole.

 

 

CYPRESS ENVIRONMENTAL PARTNERS, L.P.

(formerly CYPRESS ENERGY PARTNERS, L.P.) 

Notes to Consolidated Financial Statements

 

5.	Intangible Assets

 

Intangible assets consist of the following at December 31, 2019 and 2018:

  

						December 31,
Asset Category		Useful Lives				2019				2018
		(years)				(in thousands)
Customer relationships			5 - 20			$	22,853			$	22,853
Contracts			3				241				241
Non-compete agreements			3				143				143
Trademarks and trade names			10				11,679				11,679
Inspector database			10				2,080				2,080
							36,996				36,996
Less accumulated amortization							(16,933	)			(14,237	)
Net intangibles						$	20,063			$	22,759

 

Amortization expense in 2019, 2018, and 2017 was $2.7 million, $2.7 million, and $2.8 million respectively.

 

Future amortization expense of our intangible assets is estimated to be as follows:

 

Year ending December 31,			(in thousands)
2020			$	2,677
2021				2,668
2022				2,668
2023				2,070
2024				1,497
Thereafter				8,483
			$	20,063

 

In 2017, we ceased to perform certain services for the largest customer of the Canadian subsidiary of our Pipeline Inspection segment. In consideration of this, we recorded impairments to the carrying values of certain intangible assets of $1.3 million in the first quarter of 2017. Of this amount, $1.1 million related to customer relationships and $0.2 million related to trade names. Based on discounted cash flow calculations, which represent Level 3 non-recurring fair value adjustments, we concluded the fair value of the customer relationships and trade names of our Canadian business was zero, and therefore we impaired the full amounts.

 

6.	Credit Agreement

 

On May 29, 2018, we entered into an amended and restated credit agreement (as amended and restated, the “Credit Agreement”) that provides up to $110.0 million in borrowing capacity, subject to certain limitations. The three-year Credit Agreement matures May 29, 2021. The obligations under the Credit Agreement are secured by a first priority lien on substantially all of our assets. The credit agreement as it existed prior to the May 29, 2018 amendment will hereinafter be referred to as the “Previous Credit Agreement” or, together with the Credit Agreement, as the “Credit Agreements”.

 

Outstanding borrowings at December 31, 2019 and December 31, 2018 were $74.9 million and $76.1 million, respectively, and are reflected as long-term debt on the Consolidated Balance Sheets. We also had $0.5 million of finance lease liabilities at December 31, 2019 that count as indebtedness under the Credit Agreement. Debt issuance costs are reported as debt issuance costs, net on the Consolidated Balance Sheets and total $0.8 million and $1.3 million at December 31, 2019 and December 31, 2018, respectively.

 

CYPRESS ENVIRONMENTAL PARTNERS, L.P.

(formerly CYPRESS ENERGY PARTNERS, L.P.)

Notes to Consolidated Financial Statements

  

The carrying value of our long-term debt approximates fair value, as the borrowings under the Credit Agreement are considered to be priced at market for debt instruments having similar terms and conditions (Level 2 of the fair value hierarchy).

 

We incurred certain debt issuance costs associated with the Previous Credit Agreement, which we were amortizing on a straight-line basis over the life of the Previous Credit Agreement. Upon amending the Credit Agreement in May 2018, we wrote off $0.1 million of these debt issuance costs and reported this expense within debt issuance cost write-off in our Consolidated Statements of Operations for 2018, which represented the portion of the unamortized debt issuance costs attributable to lenders who are no longer participating in the credit facility subsequent to the amendment. The remaining debt issuance costs associated with the Previous Credit Agreement, along with $1.3 million of debt issuance costs associated with the amended and restated Credit Agreement, are being amortized on a straight-line basis over the three-year term of the Credit Agreement.

 

All borrowings under the Credit Agreement bear interest, at our option, on a leveraged based grid pricing at (i) a base rate plus a margin of 1.5% to 3.0% per annum (“Base Rate Borrowing”) or (ii) an adjusted LIBOR rate plus a margin of 2.5% to 4.0% per annum (“LIBOR Borrowings”). The applicable margin is determined based on the leverage ratio of the Partnership, as defined in the Credit Agreement. Generally, the interest rate on our borrowings ranged from 4.70% to 6.02% in 2019, 4.74% to 6.02% in 2018, and 3.90% to 5.32% in 2017. Interest on Base Rate Borrowings is payable monthly. Interest on LIBOR Borrowings is paid upon maturity of the underlying LIBOR contract, but no less often than quarterly. Commitment fees are charged at a rate of 0.50% on any unused credit and are payable quarterly. Interest paid in 2019, 2018, and 2017 was $4.8 million, $5.8 million, and $6.8 million, respectively, including commitment fees. The average debt balance outstanding in 2019, 2018, and 2017 was $81.4 million, $98.6 million, and $136.9 million, respectively.

 

The Credit Agreement contains various customary covenants and restrictive provisions. The Credit Agreement also requires maintenance of certain financial covenants, including a leverage ratio (as defined in the Credit Agreement) of not more than 4.0 to 1.0 and an interest coverage ratio (as defined in the Credit Agreement) of not less than 3.0 to 1.0. At December 31, 2019, our leverage ratio was 2.4 to 1.0 and our interest coverage ratio was 8.7 to 1.0, pursuant to the Credit Agreement. Upon the occurrence and during the continuation of an event of default, subject to the terms and conditions of the Credit Agreement, the lenders may declare any outstanding principal, together with any accrued and unpaid interest, to be immediately due and payable and may exercise the other remedies set forth or referred to in the Credit Agreement. We were in compliance with all debt covenants as of December 31, 2019.

 

Borrowings under the Credit Agreement may not exceed 4 times the trailing-twelve-month EBITDA as of the most recently-filed quarterly compliance certificate. Trailing-twelve-month EBITDA, as calculated under the Credit Agreement, was $31.4 million at December 31, 2019.

 

In addition, the Credit Agreement restricts our ability to make distributions on, or redeem or repurchase, our equity interests, with certain exceptions detailed in the Credit Agreement. However, we may make distributions of available cash so long as, both at the time of the distribution and after giving effect to the distribution, no default exists under the Credit Agreement, we are in compliance with the financial covenants in the Credit Agreement, and we have at least $5.0 million of unused capacity on the Credit Agreement at the time of the distribution.

 

In January 2020, we made a payment of $5.0 million to reduce the balance outstanding on the Credit Agreement from $74.9 million to $69.9 million. In March 2020, in an abundance of caution, we borrowed $32.0 million on the Credit Agreement to provide substantial liquidity to manage our business in light of a recent COVID-19 outbreak and a significant recent decline in the price of crude oil.

 

7.	Income Taxes

 

As a limited partnership, we generally are not subject to federal, state or local income taxes. The tax on the net income of the Partnership is generally borne by the individual partners. We have Canadian activity that is taxable in Canada. In addition, we own three entities which have elected to be taxed as corporations for U.S. federal income tax purposes. The amounts recognized as income tax expense, income taxes payable, and deferred tax liabilities in the Consolidated Financial Statements represent the Canadian and U.S. taxes referred to above, as well as partnership-level taxes levied by various states (primarily Texas).

 

 

CYPRESS ENVIRONMENTAL PARTNERS, L.P.

(formerly CYPRESS ENERGY PARTNERS, L.P.)

Notes to Consolidated Financial Statements

 

Significant components of income tax expense (benefit) are as follows for the years ended December 31:

 

		2019				2018				2017
							(in thousands)
Current tax expense (benefit):
U.S. federal		$	1,007			$	497			$	356
State			1,329				797				531
Canadian			(46	)			(27	)			81
Total			2,290				1,267				968
Deferred tax expense (benefit):
U.S. federal			(36	)			36				(7	)
State			(15	)			15				(2	)
Canadian			15				—				(363	)
Total			(36	)			51				(372	)
Total income tax expense		$	2,254			$	1,318			$	596

 

Income tax expense increased from 2017 to 2018 due to the deferred tax benefit of intangible asset impairments from our Canadian subsidiary in 2017 and due to increased taxable income in our taxable subsidiary that serves public utility customers. Income tax expense increased from 2018 to 2019 due to increased taxable income in our taxable subsidiary that serves public utility customers and increased Texas margin tax due to increased activity in Texas.

 

The following table reconciles the differences between the U.S. federal statutory rate of 21% in 2019 and 2018 and 35% in 2017 to the Partnership’s income tax expense on the Consolidated Statements of Operations for the years ended December 31:

 

		2019				2018				2017
						(in thousands)
Tax (benefit) computed at statutory rate		$	4,132			$	2,817			$	(464	)
(Income) loss not subject to federal tax			(3,102	)			(2,396	)			682
State income taxes, net of federal benefit			1,265				787				509
Other			(41	)			110				(131	)
		$	2,254			$	1,318			$	596

 

Tax years that remain subject to examination by various taxing authorities for each of our consolidated entities include the years 2017 through 2019. Tax-related interest and penalties were insignificant in 2019, 2018, and 2017.

 

We had no uncertain tax positions that required recognition in the financial statements at December 31, 2019 or 2018. During the next twelve months, we do not expect that the ultimate resolution of any uncertain tax positions will result in a significant increase or decrease of an unrecognized tax benefit.

 

8.	Owners’ Equity

 

Common Units and Subordinated Units

 

As of December 31, 2019, there were 12,068,343 common units outstanding. As of December 31, 2018, there were 11,946,901 common units outstanding. On February 14, 2017, all subordinated units outstanding were converted to common units upon satisfaction of the requirements as outlined in our partnership agreement. Prior to the conversion of all subordinated units to common units, items of income (loss) were allocated to common units and subordinated units equally.

 

 

CYPRESS ENVIRONMENTAL PARTNERS, L.P.

(formerly CYPRESS ENERGY PARTNERS, L.P.)

Notes to Consolidated Financial Statements

 

Incentive Distribution Rights

 

Our General Partner owns a 0.0% non-economic general partnership interest in the Partnership, which does not entitle it to receive cash distributions. Affiliates of our General Partner hold incentive distribution rights (“IDRs”), which represent the right to receive an increasing percentage (15%, 25%, and 50%) of quarterly distributions of available cash from operating surplus after specified target distribution levels have been achieved. Affiliates of the General Partner would begin receiving incentive distribution payments when the quarterly cash distribution exceeds $0.445625 per unit. There were no incentive distribution payments in 2019, 2018, or 2017.

 

Series A Preferred Units

 

On May 29, 2018 (the “Closing Date”), we entered into a Series A Preferred Unit Purchase Agreement (the “Preferred Unit Purchase Agreement”) with an entity controlled by Charles C. Stephenson, Jr. (the “Purchaser”), an affiliate of our General Partner, where we issued and sold in a private placement 5,769,231 Series A Preferred Units representing limited partner interests in the Partnership (the “Preferred Units”) to the Purchaser for a cash purchase price of $7.54 per Preferred Unit, resulting in gross proceeds to the Partnership of $43.5 million. We used proceeds from the transaction to reduce outstanding borrowings on our revolving credit facility. Concurrent with the closing of this transaction, we entered into an amended and restated Credit Agreement dated as of May 29, 2018, to amend and restate the terms of our credit facility, as more fully described in Note 6.

 

The Preferred Unit Purchase Agreement contains customary representations, warranties, and covenants of the Partnership and the Purchaser. The Partnership and the Purchaser agreed to indemnify each other and their respective officers, directors, managers, employees, agents, counsel, accountants, investment bankers, and other representatives against certain losses resulting from breaches of their respective representations, warranties, and covenants, subject to certain negotiated limitations and survival periods set forth in the Preferred Unit Purchase Agreement.

 

Pursuant to the Preferred Unit Purchase Agreement, and in connection with the closing of this transaction, our General Partner executed the First Amendment to First Amended and Restated Agreement of Limited Partnership of the Partnership, which authorizes and establishes the rights and preferences of the Preferred Units. The Preferred Units have voting rights that are identical to the voting rights of the common units into which such Preferred Units would be converted at the then-applicable conversion rate.

 

The Purchaser is entitled to receive quarterly distributions that represent an annual return of 9.5% on the Preferred Units. Of this 9.5% annual return, we will be required to pay at least 2.5% in cash and will have the option to pay the remaining 7.0% in kind (in the form of issuing additional preferred units) for the first twelve quarters after the Closing Date. 

 

After the third anniversary of the Closing Date, the Purchaser will have the option to convert the Preferred Units into common units on a one-for-one basis. If certain conditions are met after the third anniversary of the Closing Date, we will have the option to cause the Preferred Units to convert to common units. After the third anniversary of the Closing Date, we will also have the option to redeem the Preferred Units. The Partnership may redeem the Preferred Units (a) at any time after the third anniversary of the closing date and on or prior to the fourth anniversary of the closing date at a redemption price equal to 105% of the issue price, and (b) at any time after the fourth anniversary of the closing date at a redemption price equal to 101% of the issue price.

 

The Preferred Units rank senior to our common units, and we must pay distributions on the Preferred Units (including any arrearages) before paying distributions on our common units. In addition, the Preferred Units rank senior to the common units with respect to rights upon liquidation.

 

Earnings Per Unit

 

Our net income (loss) is attributable and allocable to four ownership groups: (1) our preferred unitholder, (2) the noncontrolling interests in certain subsidiaries, (3) our General Partner and (4) our common unitholders. Income attributable to preferred unitholder represents the 9.5% annual return to which the owner of the Preferred Units is entitled. Net income (loss) attributable to noncontrolling interests represent 49% of the income (loss) generated by Brown and 51% of the income (loss) generated by CF Inspection. Net loss attributable to General Partner includes expenses incurred by Holdings and not charged to us. Net income attributable to common unitholders represents our remaining net income (loss), after consideration of amounts attributable to our preferred unitholder, the noncontrolling interests, and our General Partner.

 

In February 2017, all outstanding subordinated units were converted to common units upon satisfaction of the requirements as outlined in our partnership agreement; prior to this conversion, items of income (loss) were allocated to common units and subordinated units equally. Since the subordinated units did not share in the distribution of cash generated subsequent to December 31, 2016, we did not allocate any income or loss after that date to the subordinated units.

 

 

CYPRESS ENVIRONMENTAL PARTNERS, L.P.

(formerly CYPRESS ENERGY PARTNERS, L.P.)

Notes to Consolidated Financial Statements

 

Basic net income per common limited partner unit is calculated as net income attributable to common unitholders divided by the basic weighted average common units outstanding. Diluted net income per common limited partner unit  includes the dilutive effect of the unvested equity-based compensation and the Preferred Units. The following summarizes the calculation of the basic net income per common limited partner unit  for the periods presented:

 

		Twelve Months Ended December 31
		2019				2018				2017
		(in thousands, except per unit data)
Net income attributable to common unitholders		$	11,881			$	8,968			$	3,237
Weighted average common units outstanding			12,039				11,929				11,152
Basic net income per common limited partner unit		$	0.99			$	0.75			$	0.29

 

The following summarizes the calculation of the diluted net income per common limited partner unit for the periods presented:

 

		Twelve Months Ended December 31
		2019				2018				2017
		(in thousands, except per unit data)
Net income attributable to common unitholders		$	11,881			$	8,968			$	3,237
Net income attributable to preferred unitholder			4,133				2,445				—
		$	16,014			$	11,413			$	3,237
Weighted average common units outstanding			12,039				11,929				11,152
Effect of dilutive securities:
Weighted average preferred units outstanding			5,769				3,413				—
Long-term incentive plan unvested units			481				415				101
Diluted weighted average common units outstanding			18,289				15,757				11,253
Diluted net income per common limited partner unit		$	0.88			$	0.72			$	0.29

 

9.	Major Customers

 

The following table sets forth the customers who accounted for more than 10% of our consolidated revenue for the years ended December 31, 2019, 2018, and 2017:

 

2019		2018		2017
Pacific Gas and Electric Company		Pacific Gas and Electric Company		Enterprise Products Partners L.P.
Phillips 66		Plains All American Pipeline, L.P.		Pacific Gas and Electric Company
Plains All American Pipeline, L.P.				Plains All American Pipeline, L.P.

  

No other customer accounted for more than 10% of our consolidated revenues during these years. Revenues from these customers resulted from activities conducted by our Pipeline Inspection segment.

 

 

CYPRESS ENVIRONMENTAL PARTNERS, L.P.

(formerly CYPRESS ENERGY PARTNERS, L.P.)

Notes to Consolidated Financial Statements

 

10.	Equity Compensation

 

Long-Term Incentive Plan (“LTIP”)

 

Our General Partner has adopted a long-term incentive plan (“LTIP”) that authorizes the issuance of up to 2.5 million common units. Certain directors and employees of the Partnership have been awarded phantom restricted units (“Units”) under the terms of the LTIP in the form of time-based unit awards (“Service Units”), performance-based unit awards (“Performance Units”) and market-based unit awards (“Market Units”). In 2019, 2018, and 2017, compensation expense of $1.1 million, $1.2 million and $1.1 million, respectively was recorded under the LTIP (including expense associated with the Profit Interest Units described below).

 

Time-Based Unit Awards  – The majority of the Service Units vest in three tranches, with one-third of the units vesting three years from the grant date, one-third vesting four years from the grant date, and one-third vesting five years from the grant date, contingent only on the continued service of the recipients through the vesting dates. However, certain of the Service Units have different, and typically shorter, vesting periods. The fair value of the Service Units is determined based on the quoted market value of the publicly-traded common units at the grant date, adjusted for a discount to reflect the fact that distributions are not paid on the Service Units during the vesting period. We recognize compensation expense on a straight-line basis over the vesting period of the grant. We account for forfeitures when they occur. Total unearned compensation associated with the Service Units at December 31, 2019 and 2018 was $2.3 million and $2.9 million, respectively, with an average remaining life of 1.9 years and 2.1 years, respectively. The following table summarizes the activity of the Service Units in 2019, 2018, and 2017:

 

		Number of  Unvested Units				Weighted Average  Grant Date Fair  Value / Unit
Units at December 31, 2016			496,407			$	10.19
Units granted			257,419			$	7.02
Units vested			(44,408	)		$	16.56
Units forfeited			(122,404	)		$	9.25
Units at December 31, 2017			587,014			$	8.56
Units granted			399,726			$	3.24
Units vested			(69,296	)		$	13.97
Units forfeited			(44,383	)		$	5.76
Units at December 31, 2018			873,061			$	5.83
Units granted			201,306			$	4.40
Units vested			(145,200	)		$	8.48
Units forfeited			(64,635	)		$	6.10
Units at December 31, 2019			864,532			$	5.04

 

Performance-Based Unit Awards  – We have issued grants of Performance Units that vest three years from the grant date. Upon vesting, the recipient is entitled to receive a number of common units equal to a percentage of the units granted, based on the recipient meeting various performance targets in addition to the service condition.

 

In addition, in the third quarter of 2019, we granted Performance Units to certain employees that are subject to performance conditions in addition to the service condition. These Performance Units will vest in April 2022, April 2023, April 2024, or not at all, depending on our performance relative to a specified profitability target. We recognize compensation expense on a straight-line basis over the estimated vesting period of the grant. We adjust the life-to-date expense recognized for the Performance Units for any changes in our estimates of the number of units that will vest and the timing of vesting. We account for forfeitures when they occur. The Performance Units granted in the third quarter of 2019 had an estimated grant date fair value of $4.19 per unit and are being expensed over a service period of 3.73 years.

 

 

CYPRESS ENVIRONMENTAL PARTNERS, L.P.

(formerly CYPRESS ENERGY PARTNERS, L.P.)

Notes to Consolidated Financial Statements

 

Total unearned compensation associated with the Performance Units at December 31, 2019 and 2018 was $0.4 million and $0.2 million, respectively, with an average remaining life of 2.6 years and 2.1 years, respectively. The following table summarizes the activity of the Performance Units in 2019, 2018, and 2017:

 

		Number of  Unvested Units				Weighted Average  Grant Date Fair  Value / Unit
Units at December 31, 2016			77,495			$	7.75
Units granted			—			$	—
Units vested			—			$	—
Units forfeited			—			$	—
Units at December 31, 2017			77,495			$	7.75
Units granted			72,046			$	4.52
Units vested			(7,184	)		$	8.49
Units forfeited			(40,709	)		$	8.49
Units at December 31, 2018			101,648			$	5.11
Units granted			89,402			$	4.19
Units vested			(6,167	)		$	6.54
Units forfeited			(24,310	)		$	6.45
Units at December 31, 2019			160,573			$	4.34

 

Market-Based Unit Awards  – In the third quarter of 2019, we granted Units that are subject to market conditions in addition to the service condition (the “Market Units”). One-half of the Market Units will vest in April 2022, April 2023, April 2024, or not at all, depending on the market value of our common units relative to specified targets on those dates. These Market Units had an estimated fair value on the grant date of $3.51 per unit and will be expensed over a derived service period of 2.73 years. One-half of the Market Units will vest in April 2022, April 2023, April 2024, or not at all, depending on the yield on our common units relative to specified targets on those dates. These Market Units granted in 2019 had an estimated fair value on the grant date of $3.58 per unit and will be expensed over a derived service period of 2.73 years. Compensation expense is recognized on a straight-line basis over a derived service period, regardless of when, if ever, the market condition is satisfied. Total unearned compensation associated with the Market Units at December 31, 2019 was $0.3 million with an average remaining life of 2.3 years. The following table summarizes the activity of the Market Units for 2019:

 

		Number of  Unvested Units				Weighted Average  Grant Date Fair  Value / Unit
Units at December 31, 2018			—			$	—
Units granted			89,403			$	3.54
Units vested			—			$	—
Units forfeited			(875	)		$	3.54
Units at December 31, 2019			88,528			$	3.54

 

 

CYPRESS ENVIRONMENTAL PARTNERS, L.P.

(formerly CYPRESS ENERGY PARTNERS, L.P.)

Notes to Consolidated Financial Statements

 

In addition to the awards shown above, at the time of our Initial Public Offering, certain profits interest units (“Profit Interest Units”) previously issued were converted into 44,451 units of the Partnership outside of the LTIP. Compensation expense associated with the Profit Interest Units was $0.1 million for each of the years ended December 31, 2018 and 2017. There were no unvested Profit Interest Units at December 31, 2019.

 

11.	Related-Party Transactions

 

Omnibus Agreement 

 

We are party to an omnibus agreement with Holdings and other related parties. The omnibus agreement provides for, among other things, our right of first offer on Holdings’ and its subsidiaries’ assets used in, and entities primarily engaged in, providing water treatment and other water and environmental services. So long as Holdings controls our General Partner, the omnibus agreement will remain in full force and effect, unless we and Holdings agree to terminate it sooner. If Holdings ceases to control our General Partner, either party may terminate the omnibus agreement. We and Holdings may agree to further amend the omnibus agreement; however, amendments that the General Partner determines are adverse to our unitholders will also require the approval of the Conflicts Committee of our Board of Directors.

 

Prior to January 1, 2020, the omnibus agreement called for Holdings to provide certain general and administrative services, including executive management services and expenses associated with our being a publicly-traded entity (such as audit, tax, and transfer agent fees, among others) in return for a fixed annual fee (adjusted for inflation) that was payable quarterly. This annual fee was $4.5 million in 2019 and $4.0 million in 2018 and 2017. In an effort to simplify this arrangement so it will be easier for investors to understand, in November 2019, with the approval of the Conflicts Committee of the Board of Directors, we and Holdings agreed to terminate the management fee provisions of the omnibus agreement effective December 31, 2019. Beginning January 1, 2020, the executive management services and other general and administrative expenses that Holdings previously incurred and charged to us via the annual administrative fee are charged directly to us as they are incurred. Under our current cost structure, we expect these direct expenses to be lower than the annual administrative fee that we previously paid, although we expect to experience more variability in our quarterly general and administrative expense now that we are incurring the expenses directly than when we paid a consistent administrative fee each quarter.

 

The amounts charged by Holdings under the omnibus agreement in 2019, 2018, and 2017 were $4.5 million, $4.0 million, and $2.0 million, respectively, and are reflected in general and administrative in the Consolidated Statements of Operations. In 2017, Holdings waived $2.0 million of the $4.0 administrative fee that it was entitled to charge. We recorded the $1.8 million of expense that Holdings incurred in 2017 and did not charge to us within general and administrative in the Consolidated Statement of Operations and as contributions attributable to general partner in the Consolidated Statement of Owners’ Equity. These costs are included as a component of net loss attributable to general partner in the Consolidated Statements of Operations for 2017. In addition to waiving $2.0 million of the administrative fee in 2017, Holdings provided us with additional financial support by contributing a total of $2.3 million in 2017 in cash, as a reimbursement of certain expenditures incurred by us. These cash contributions are reflected as contributions attributable to general partner in the Consolidated Statement of Owners’ Equity and as a component of the net loss attributable to general partner in the Consolidated Statement of Operations.

 

Alati Arnegard, LLC

 

The Partnership provides management services to a 25% owned company, Alati Arnegard, LLC (“Arnegard”), which is part of the Environmental Services segment. We recorded earnings from this investment of $0.2 million, $0.2 million, and $0.1 million in 2019, 2018, and 2017, respectively.  These earnings are recorded in other, net on the Consolidated Statements of Operations and equity in earnings of investee on the Consolidated Statements of Cash Flows. Management fee revenue earned from Arnegard is included in revenues on the Consolidated Statements of Operations and totaled $0.7 million, $0.7 million and $0.6 million in 2019, 2018, and 2017, respectively. Accounts receivable from Arnegard totaled $0.1 million at both December 31, 2019 and 2018, and is included in trade accounts receivable, net on the Consolidated Balance Sheets. Our investment in Arnegard totaled approximately $0.4 million and $0.2 million at December 31, 2019 and 2018, respectively and is included in other assets on the Consolidated Balance Sheets. 

 

CF Inspection Management, LLC

 

We have also entered into a joint venture with CF Inspection, a nationally-qualified woman-owned inspection firm. CF Inspection allows us to offer various services to clients that require the services of an approved Women’s Business Enterprise (“WBE”), as CF Inspection is certified as a Women’s Business Enterprise by the Supplier Clearinghouse in California and as a National Women’s Business Enterprise by the Women’s Business Enterprise National Council. We own 49% of CF Inspection and Cynthia A. Field, an affiliate of Holdings and a Director of our General Partner, owns the remaining 51% of CF Inspection. In 2019, 2018, and 2017, CF Inspection, which is part of the Pipeline Inspection segment, represented approximately 3.3%, 3.4%, and 3.5% of our consolidated revenue, respectively.

 

 

CYPRESS ENVIRONMENTAL PARTNERS, L.P.

(formerly CYPRESS ENERGY PARTNERS, L.P.)

Notes to Consolidated Financial Statements

 

Sale of Preferred Equity As described in Note 8, we issued and sold $43.5 million of preferred equity to an affiliate in May 2018.

 

12.

Leases

 

We determine if an agreement contains a lease at the inception of the arrangement. If an arrangement is determined to contain a lease, we classify the lease as an operating lease or a finance lease depending on the terms of the arrangement. Right-of-use (“ROU”) assets represent the right to use an underlying asset for the lease term, and lease liabilities represent the obligation to make lease payments arising from the lease. These assets and liabilities are initially recognized based on the present value of lease payments over the lease term calculated using our incremental borrowing rate, unless the implicit rate is readily determinable. Lease assets also include any upfront lease payments made and exclude lease incentives. The lease terms of our leases include options to extend or terminate the lease when it is reasonably certain that those options will be exercised.

 

Practical Expedients and Accounting Policy Elections

 

We made accounting policy elections to not capitalize leases with a lease term of twelve months or less and to not separate lease and non-lease components for all asset classes. We also elected the package of practical expedients within ASU 2016-02 that allows an entity to not reassess prior to the effective date (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases, or (iii) initial direct costs for any existing leases, but did not elect the practical expedient of hindsight when determining the lease term of existing contracts at the effective date.

 

Discount Rate

 

Our lease agreements do not generally provide an implicit interest rate. As a result, we use our incremental borrowing rate as the discount rate in calculating the present value of the lease payments. The incremental borrowing rate is the estimated rate of interest that we would have to pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment.

 

Operating Leases

 

Our operating leases include leases for office space and land lease agreements for four of our water treatment facilities. Our lease for our office space headquarters constitutes $2.8 million of our Operating ROU asset at December 31, 2019 of $2.9 million. The lease expires in November of 2024 unless terminated earlier with a payment of a penalty under certain circumstances specified in our lease. In the determination of the lease term for this lease, we concluded the lease term would go through November 2024 as it was not reasonably certain at the inception of the agreement that we would exercise any of the termination options in the agreement. As of December 31, 2019, the weighted average remaining lease term and weighted average discount rate for our operating leases was 5.1 years and 6.1%, respectively. Our operating leases are reflected as operating lease right-of-use assets within noncurrent assets and operating lease obligations  within current and noncurrent liabilities on our Consolidated Balance Sheet at December 31, 2019.

 

Our operating lease obligations at December 31, 2019 with terms that are greater than one year mature as follows (in thousands):

 

2020		$	624
2021			679
2022			679
2023			679
2024			625
Thereafter			95
Total lease payments		$	3,381
Less imputed interest			(497	)
Total operating lease obligation		$	2,884

 

 

CYPRESS ENVIRONMENTAL PARTNERS, L.P.

(formerly CYPRESS ENERGY PARTNERS, L.P.)

Notes to Consolidated Financial Statements

 

Finance Leases

 

Our finance leases primarily include leases for vehicles. As of December 31, 2019, the weighted average remaining lease term and weighted average discount rate for our finance leases was 2.7 years and 5.6%, respectively. Our finance leases are reflected as finance lease right-of-use assets, net within noncurrent assets and finance lease obligations  within current and noncurrent liabilities on our Consolidated Balance Sheet at December 31, 2019.

 

Our finance lease obligations at December 31, 2019 with terms that are greater than one year mature as follows (in thousands):           

 

2020		$	210
2021			201
2022			136
2023			38
Total lease payments		$	585
Less imputed interest			(43	)
Total finance lease obligation		$	542

 

Lease Expense Components

 

During the year ended December 31, 2019, our lease expense consists of the following components (in thousands):

 

		Year Ended December 31, 2019
Finance lease expense:
Amortization of right-of-use assets		$	178
Interest on lease liabilities			31
Operating lease expense			672
Short-term lease expense - general and administrative			103
Short-term lease expense - costs of services (a)			3,570
Variable lease expense			10
Sublease income - related parties			(32	)
Total lease expense		$	4,532

 

(a)

These short-term lease expenses are included in costs of services within our Consolidated Statement of Operations. The nature of these expenses includes the rental of compressors, dryers, vehicles, frac tanks, launchers, receivers and various other types of equipment. These rentals have lease terms of one year or less.

 

During the years ended December 31, 2018 and 2017, we recorded lease expense of $3.7 million and $3.2 million respectively. These amounts are inclusive of $3.0 million and $2.4 million in lease expense within costs of services on our Consolidated Statement of Operations during 2018 and 2017, respectively.

 

13.	Commitments and Contingencies

 

Security Deposits 

 

The Partnership has various performance obligations which are secured with short-term security deposits (reflected as restricted cash equivalents on our Consolidated Statements of Cash Flows) totaling $0.6 million at December 31, 2019 and 2018. These amounts are included in prepaid expenses and other on the Consolidated Balance Sheets.

 

 

CYPRESS ENVIRONMENTAL PARTNERS, L.P.

(formerly CYPRESS ENERGY PARTNERS, L.P.)

Notes to Consolidated Financial Statements

 

Compliance Audit Contingencies

 

Certain customer master service agreements (“MSA’s”) offer our customers the right to perform periodic compliance audits, which include the examination of the accuracy of our invoices. Should our invoices be determined to be inconsistent with the MSA, or inaccurate, the MSA’s may provide the customer the right to receive a credit or refund for any overcharges identified. At any given time, we may have multiple audits ongoing. As of December 31, 2019 and 2018, we established a reserve of $0.2 million and $0.1 million, respectively, as an estimate of potential liabilities related to these compliance audit contingencies.

 

Legal Proceedings

 

Fithian v. TIR LLC

 

On October 5, 2017, a former inspector for TIR LLC and Cypress Environmental Management – TIR, LLC (“CEM TIR”) filed a putative collective action lawsuit alleging that TIR LLC, CEM TIR and Cypress Energy Partners – Texas, LLC failed to pay a class of workers overtime in compliance with the Fair Labor Standards Act (“FLSA”) titled James Fithian, et al v. TIR LLC, et al in the United States District Court for the Western District of Texas, Midland Division. The plaintiff subsequently withdrew his action and filed a similar action in Oklahoma State Court, District of Tulsa County. The plaintiff alleged he was a non-exempt employee of CEM TIR and that he and other potential class members were not paid overtime in compliance with the FLSA. The plaintiff sought to proceed as a collective action and to receive unpaid overtime and other monetary damages, including attorney’s fees. The Partnership, TIR LLC, CEM TIR and Cypress Energy Partners – Texas, LLC denied the claims.

 

On March 28, 2018, the court granted a joint stipulation of dismissal without prejudice in regard to TIR LLC and Cypress Energy Partners – Texas, LLC, as neither of those parties were employers of the plaintiff or the putative class members during the time period that is the subject of the lawsuit. On July 26, 2018, the plaintiff filed a motion for conditional class certification. CEM TIR subsequently filed pleadings opposing the motion. On January 25, 2019, the court denied the plaintiff’s motion for conditional class certification. On June 10, 2019, the court entered a scheduling order that proscribed, among other things, August 1, 2019 as the deadline for additional parties to join the lawsuit, and that the parties participate in a settlement conference or mediation no later than September 1, 2019. After the deadline, plaintiff’s counsel submitted consents for five additional inspectors to join the lawsuit, to which CEM TIR objected. On August 28, 2019, the parties participated in a settlement conference in which no settlement was reached. Subsequent to the settlement conference, CEM TIR submitted offers of judgment in immaterial amounts to the named plaintiff and the two opt-in plaintiffs. The Court entered the agreed judgment on February 25, 2020.

 

Sun Mountain LLC v. TIR-PUC

 

On February 27, 2019, Sun Mountain LLC (“Sun Mountain”), a subcontractor of TIR-PUC, filed a lawsuit alleging that TIR-PUC failed to pay invoices amounting to approximately $3.5 million for services subcontracted to Sun Mountain under TIR-PUC’s agreement to provide services to Pacific Gas and Electric Company. Sun Mountain filed the action in Federal District Court for the Northern District of Oklahoma. TIR-PUC denied that such amounts were owed, as conditions to TIR-PUC’s obligation to make the payments were not met. The full amount of these invoices is included within accounts payable on the accompanying Consolidated Balance Sheet at December 31, 2018. TIR-PUC denied the claims. On October 22, 2019, the parties participated in a settlement conference at which the parties agreed to settle the lawsuit. As part of the settlement, TIR-PUC made specified cash payments in November 2019 and January 2020 and will make a final payment in July 2020. We recorded a gain of $1.3 million within other, net in the Consolidated Statement of Operations in the fourth quarter of 2019 related to this settlement.

 

Diaz v. CEM TIR

 

On December 12, 2019, three of the former inspectors who unsuccessfully attempted to join the Fithian lawsuit after the deadline set by the court filed a putative collective action lawsuit alleging that TIR LLC and CEM TIR failed to pay a class of workers overtime in compliance with the FLSA titled Francisco Diaz, et al v. CEM TIR, et al in the United States District Court for the Northern District of Oklahoma. TIR LLC and CEM TIR deny the claims.  CEM TIR and TIR LLC filed a motion to dismiss one of the plaintiffs for bringing the lawsuit in a venue that was inconsistent with the forum selection clause in his employment agreement mandating suit exclusively in the District Court of Tulsa County, Oklahoma.  CEM TIR and TIR LLC also filed a motion to compel arbitration for the other two plaintiffs to enforce the binding arbitration clauses in their employment agreements. The Court has not yet ruled on either motion. The two plaintiffs with the binding arbitration provisions subsequently initiated arbitration proceedings.

 

Other

 

We have been and may in the future be subject to litigation involving allegations of violations of the Fair Labor Standards Act and state wage and hour laws. In addition, we generally indemnify our customers for claims related to the services we provide and actions we take under our contracts, including claims regarding the Fair Labor Standards Act and state wage and hour laws, and, in some instances, we may be allocated risk through our contract terms for actions by our customers or other third parties. Claims related to the Fair Labor Standards Act are generally not covered by insurance. From time to time, we are subject to various claims, lawsuits and other legal proceedings brought or threatened against us in the ordinary course of our business. These actions and proceedings may seek, among other things, compensation for alleged personal injury, workers’ compensation, employment discrimination and other employment-related damages, breach of contract, property damage, environmental liabilities, multiemployer pension plan withdrawal liabilities, punitive damages and civil penalties or other losses, liquidated damages, consequential damages, or injunctive or declaratory relief.

 

 

CYPRESS ENVIRONMENTAL PARTNERS, L.P.

(formerly CYPRESS ENERGY PARTNERS, L.P.)

Notes to Consolidated Financial Statements

 

14.	Segment Disclosures

 

The Partnership’s operations consist of three reportable segments: (i) Pipeline Inspection Services (“Pipeline Inspection”), (ii) Pipeline & Process Services and (iii) Water and Environmental Services (“Environmental Services”). The amounts within “Other” represent corporate and overhead items not specifically allocable to the other reportable segments.

 

The following table outlines segment operating income and a reconciliation of total segment operating income to net income before income tax expense.

 

 

CYPRESS ENVIRONMENTAL PARTNERS, L.P.

(formerly CYPRESS ENERGY PARTNERS, L.P.)

Notes to Consolidated Financial Statements

 

		Pipeline Inspection				Pipeline and Process Services				Environmental Services				Other				Total
		(in thousands)
Twelve months ended December 31, 2019
Revenues		$	371,994			$	19,337			$	10,317			$	—			$	401,648
Costs of services			331,498				13,397				3,029				—				347,924
Gross margin			40,496				5,940				7,288				—				53,724
General and administrative			19,086	(a)			2,500				2,995	(b)			1,045				25,626
Depreciation, amortization and accretion			2,224				574				1,632				18				4,448
Losses (gains) on asset disposals, net			1				(26	)			—				—				(25	)
Operating income (loss)		$	19,185			$	2,892			$	2,661			$	(1,063	)		$	23,675
Interest expense, net																			(5,330	)
Foreign currency gains																			222
Other, net																			1,111
Net income before income tax expense																		$	19,678
Twelve months ended December 31, 2018
Revenues		$	288,083			$	15,001			$	11,876			$	—			$	314,960
Costs of services			256,436				10,708				3,770				—				270,914
Gross margin			31,647				4,293				8,106				—				44,046
General and administrative			17,010	(c)			2,379				3,295	(b)			1,060				23,744
Depreciation, amortization and accretion			2,237				592				1,575				—				4,404
Gains on asset disposals, net			(21	)			(83	)			(4,004	)			—				(4,108	)
Operating income (loss)		$	12,421			$	1,405			$	7,240			$	(1,060	)		$	20,006
Interest expense, net																			(6,320	)
Foreign currency losses																			(643	)
Other, net																			373
Net income before income tax expense																		$	13,416
Twelve months ended December 31, 2017
Revenues		$	268,635			$	9,268			$	8,439			$	—			$	286,342
Costs of services			241,889				7,347				3,503				—				252,739
Gross margin			26,746				1,921				4,936				—				33,603
General and administrative			13,980	(d)			1,981				2,451	(e)			2,643	(f)			21,055
Depreciation, amortization and accretion			2,331				626				1,486				—				4,443
Impairments			1,329				1,581				688				—				3,598
Losses (gains) on asset disposals, net			18				—				(588	)			—				(570	)
Operating income (loss)		$	9,088			$	(2,267	)		$	899			$	(2,643	)		$	5,077
Interest expense, net																			(7,335	)
Foreign currency gains																			732
Other, net																			199
Net loss before income tax expense																		$	(1,327	)
Total Assets
December 31, 2019		$	114,858			$	14,318			$	21,911			$	6,255			$	157,342
December 31, 2018		$	116,239			$	10,972			$	24,281			$	1,361			$	152,853

 

(a)	Amount includes $3.3 million of the administrative fee charged by Holdings specified in the omnibus agreement.

(b)	Amount includes $1.2 million of the administrative fee charged by Holdings specified in the omnibus agreement.

(c)	Amount includes $2.8 million of the administrative fee charged by Holdings specified in the omnibus agreement.

(d)	Amount includes $1.4 million of the administrative fee charged by Holdings specified in the omnibus agreement.

(e)	Amount includes $0.6 million of the administrative fee charged by Holdings specified in the omnibus agreement.

(f)	Amount includes $1.8 million of allocated general and administrative expenses incurred by Holdings but not charged to us. For the six months ended June 30, 2017, Holdings waived the administrative fee specified in the omnibus agreement.

 

 

CYPRESS ENVIRONMENTAL PARTNERS, L.P.

(formerly CYPRESS ENERGY PARTNERS, L.P.)

Notes to Consolidated Financial Statements

 

15.	Distributions

 

The following table summarizes the cash distributions that we declared and paid on common and subordinated units since our initial public offering:

 

Payment Date		Per Unit Cash  Distributions				Total Cash  Distributions				Total Cash  Distributions  to Affiliates (a)
		(in thousands)
Total 2014 Distributions		$	1.104646			$	13,064			$	8,296
Total 2015 Distributions			1.625652				19,232				12,284
Total 2016 Distributions			1.625652				19,258				12,414
Total 2017 Distributions			1.036413				12,310				7,928
February 14, 2018			0.210000				2,498				1,599
May 15, 2018			0.210000				2,506				1,604
August 14, 2018			0.210000				2,506				1,604
November 14, 2018			0.210000				2,509				1,606
Total 2018 Distributions			0.840000				10,019				6,413
February 14, 2019			0.210000				2,510				1,606
May 15, 2019			0.210000				2,531				1,622
August 14, 2019			0.210000				2,534				1,624
November 14, 2019			0.210000				2,534				1,627
Total 2019 Distributions			0.840000				10,109				6,479
February  14, 2020 (b)			0.210000				2,534				1,627
Total Distributions (through February 14, 2020 since IPO)		$	7.282363			$	86,526			$	55,441

 

(a)	Approximately 64% of the Partnership’s outstanding common units at December 31, 2019 were held by affiliates.
(b)	Fourth quarter 2019 distribution was declared and paid in the first quarter of 2020.

 

 

CYPRESS ENVIRONMENTAL PARTNERS, L.P.

(formerly CYPRESS ENERGY PARTNERS, L.P.)

Notes to Consolidated Financial Statements

 

The following table summarizes the distributions paid to our preferred unitholder for 2018 and 2019:

 

Payment Date		Cash Distributions				Paid-in-Kind  Distributions				Total Distributions
		(in thousands)
November 14, 2018 (a)		$	1,412			$	—			$	1,412
Total 2018 Distributions			1,412				—				1,412
February 14, 2019			1,033				—				1,033
May 15, 2019			1,033				—				1,033
August 14, 2019			1,033				—				1,033
November 14, 2019			1,034				—				1,034
Total 2019 Distributions			4,133				—				4,133
February  14, 2020 (b)			1,033				—				1,033
Total Distributions (through February 14, 2020)		$	6,578			$	—			$	6,578

 

(a)	This distribution relates to the period from May 29, 2018 (date of preferred unit issuance) through September 30, 2018.
(b)	Fourth quarter 2019 distribution was declared and paid in the first quarter of 2020.

 

16.	Sale of Water Treatment facilities

 

In 2018, we sold our subsidiaries Cypress Energy Partners – Orla SWD, LLC (“Orla”) and Cypress Energy Partners – Pecos SWD, LLC (“Pecos”), each of which owned a water treatment facility in Texas, in separate transactions to unrelated parties for a combined $12.2 million of cash proceeds and a royalty interest in the future revenues of the Pecos facility. We recorded a combined gain on these transactions of $3.6 million in 2018, which represented the excess of the cash proceeds over the net book value of the assets sold. These gains are reported within gain on asset disposals, net in our Consolidated Statements of Operations. The net book value of the assets sold included $5.0 million of allocated goodwill, calculated based on the estimated fair value of the Orla and Pecos facilities relative to the estimated fair value of the Environmental Services reporting unit as a whole. This calculation is considered Level 3 and the fair values included in this calculation were determined utilizing estimated discounted cash flows of the Orla and Pecos facilities and the Environmental Services reporting unit as a whole as of the date of sale. We used the proceeds from these transactions to reduce our outstanding debt.

 

The Pecos and Orla facilities generated combined revenues of $0.2 million and $1.6 million in 2018 and 2017, respectively. The Pecos and Orla facilities generated combined operating income (loss) of approximately ($0.1) million and $0.7 million in 2018 and 2017, respectively.

 

 

CYPRESS ENVIRONMENTAL PARTNERS, L.P.

(formerly CYPRESS ENERGY PARTNERS, L.P.)

Notes to Consolidated Financial Statements

 

17.	Quarterly Financial Information (Unaudited)

 

The following table sets forth certain unaudited financial data for each quarter in 2018 and 2019. The unaudited quarterly information includes all normal recurring adjustments that we consider necessary for a fair presentation of the information shown. 

 

2019		Quarter Ended,
		(in thousands, except per unit amounts)
		March 31				June 30				September 30				December 31
Revenues		$	90,376			$	111,091			$	108,934			$	91,247
Gross margin			10,023				14,807				15,401				13,493
Net income			1,381				5,643				5,480				4,920
Net income attributable to partners / controlling interests			1,600				5,366				4,846				4,202
Net income per common limited partner unit - basic			0.05				0.36				0.32				0.26
Net income per common limited partner unit - diluted			0.05				0.29				0.26				0.23

 

2018		Quarter Ended,
		(in thousands, except per unit amounts)
		March 31				June 30				September 30				December 31
Revenues		$	64,826			$	76,468			$	84,778			$	88,888
Gross margin			8,129				10,943				12,908				12,066
Gains (losses) on asset disposals, net			1,709				1,606				822				(29	)
Net income			960				3,556				4,954				2,628
Net income attributable to partners / controlling interests			725				3,407				4,665				2,616
Net income per common limited partner unit - basic			0.06				0.25				0.30				0.13
Net income per common limited partner unit - diluted			0.06				0.24				0.26				0.13

 

 

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

 

None.

 

ITEM 9A.

CONTROLS AND PROCEDURES

 

Evaluation of Disclosure Controls and Procedures.

 

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including the principal executive officer and principal financial officer of our general partner, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) or Rule 15d-15(e) under the Exchange Act) as of the end of the period covered by this Annual Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including the principal executive officer and principal financial officer of our general partner, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, the principal executive officer and principal financial officer of our general partner have concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of December 31, 2019. Additionally, we have implemented a quarterly sub-certification process whereby other members of management review our filings and confirm their responsibility for, among other things, the effectiveness of key controls in their functional areas and that they are not aware of any material inaccuracies or omissions in our financial statements.

 

Our management, including our principal executive officer and principal financial officer, does not expect that our disclosure controls or our internal controls over financial reporting (“Internal Controls”) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control deficiencies and instances of fraud, if any, within the Partnership have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that simple errors or mistakes can occur. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based, in part, upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, controls may become inadequate because of changes in conditions, or the degree of compliance with the policies or procedures may deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our disclosure controls and internal controls and make modifications as necessary; our intent in this regard is that the disclosure controls and the internal controls will be maintained as systems change and conditions warrant.

 

Management’s Report on Internal Control over Financial Reporting

 

Our management is responsible for establishing and maintaining adequate and effective internal control over financial reporting, as such term is defined under Exchange Act Rule 13a-15(f). Our internal control over financial reporting is a process that is designed under the supervision of our Chief Executive Officer and Chief Financial Officer, and effected by our Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. Our internal control over financial reporting includes those policies and procedures that:

 

i.

pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

 

ii.

provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures recorded by us are being made only in accordance with authorizations of our management and Board of Directors; and

 

iii.

provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on our financial statements.

 

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

 

 

The internal controls are supported by written processes and complemented by a staff of competent business process owners, as well as competent and qualified internal specialists used to assist in testing the operating effectiveness of the internal control over financial reporting.

 

Management has conducted its evaluation of the effectiveness of internal control over financial reporting as of December 31, 2019 based on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Management’s assessment included an evaluation of the design of our internal control over financial reporting and testing the operational effectiveness of our internal control over financial reporting. Management reviewed the results of the assessment with the Audit Committee of the Board of Directors. Based on its assessment and review with the Audit Committee, management concluded that, at December 31, 2019, we maintained effective internal control over financial reporting, and management believes that we have no material internal control weaknesses in our financial reporting process.

 

Changes in Internal Control over Financial Reporting

 

There were no changes in our internal control over financial reporting that occurred during the three months ended December 31, 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. In early 2020 we implemented a new software system for payroll and human resources management. We will apply and test internal control procedures related to this new system as deemed necessary.

 

ITEM 9B.

OTHER INFORMATION

 

None.

 

PART III

 

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

 

MANAGEMENT

 

Management of Cypress Environmental Partners, L.P.

 

We are managed by the executive officers of our general partner. Our general partner is not elected by our unitholders and will not be subject to re-election by our unitholders in the future. Affiliates of Holdings indirectly own 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 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 specifically nonrecourse. Whenever possible, we intend to incur indebtedness that is nonrecourse to our general partner.

 

Our general partner currently has six directors. Holdings appoints all members to the board of directors of our general partner. Pursuant to our general partner’s operating agreement, Holdings appointed to our board of directors (i) Peter C. Boylan III, who has the right to serve as a director as long as CEP Capital Partners, LLC, an entity controlled by Mr. Boylan, is a member of Holdings and (ii) such other individuals selected by Mr. Boylan that, together with Mr. Boylan, constitute a percentage of the board of directors equal to the percentage of Holdings that CEP Capital Partners, LLC owns. In his exercise of this right, Mr. Boylan has appointed himself and may appoint others to the board. We have three independent directors who qualify for service on the audit committee. Our board of directors has determined that Henry Cornell, John T. McNabb II, and Stanley A. Lybarger are independent under the independence standards of the NYSE and eligible for service on the audit committee. Despite the fact that Mr. Cornell beneficially owns 2.0% of Holdings, which together with its controlled affiliates owns 58% of our outstanding common units, the board of directors determined he is independent in that he does not have a current relationship with us that would interfere with the exercise of his independent judgment in carrying out his responsibilities as a director.

 

Our general partner has the sole responsibility for providing the employees and other personnel necessary to conduct our operations. All of the employees that conduct our business are employed by affiliates of our general partner, although we sometimes refer to these individuals in this report 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. All of our audit committee members are required to meet the independence and financial literacy tests established by the NYSE and the Exchange Act.

 

 

Committees of the Board of Directors

 

The board of directors of our general partner has an audit committee and a conflicts committee, and may have such other committees as the board of directors shall determine from time to time. Each of the standing committees of the board of directors will have the composition and responsibilities described below.

 

Audit Committee

 

Our general partner has an audit committee comprised of three directors who each meet the independence and experience standards established by the NYSE and the Exchange Act. Henry Cornell, John T. McNabb II, and Stanley A. Lybarger serve as members of our audit committee. Mr. Lybarger began serving as Chairman of the audit committee upon his appointment on March 5, 2014. Mr. McNabb served as Chairman prior to that date. Our board of directors has determined that Mr. Lybarger and Mr. McNabb each have such accounting or related financial management expertise sufficient to qualify as an audit committee financial expert in accordance with Item 407(d) of Regulation S-K. Our audit committee assists 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 has the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. Our audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is 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. John T. McNabb II and Stanley A. Lybarger serve as the members of the conflicts committee. Mr. McNabb serves as the Chairman of the conflicts committee. The board of directors of our general partner determines 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 a 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 acquired on the open market 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 Environmental Partners GP, LLC

 

Directors are elected by Holdings and hold office until their successors have been elected or qualified or until their earlier death, resignation, removal or disqualification. Executive officers are appointed by, and serve at the discretion of, the board of directors. The following table shows information for the directors and executive officers of our general partner.

  

Name		Age		Position with Cypress Environmental Partners GP, LLC
Peter C. Boylan III		56		Chairman of the Board, Chief Executive Officer and President
Richard M. Carson		53		Senior Vice President and General Counsel
Jeffrey A. Herbers		43		Vice President and Chief Financial Officer
Henry Cornell		63		Director
Cynthia A. Field		59		Director
Stanley A. Lybarger		70		Director & Audit Committee Chairman
John T. McNabb, II		75		Director & Conflicts Committee Chairman
Charles C. Stephenson, Jr.		83		Director

 

 

Peter C. Boylan III became co-Founder, President and Chief Executive Officer of Holdings in April 2012, and Chairman of the Board, President and Chief Executive Officer of Cypress Environmental Partners, GP, LLC, in 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 Operation Officer and Chief Financial Officer of several different companies. Mr. Boylan currently serves on the board of directors of publicly-traded BOK Financial Corporation. Mr. Boylan has also served on over a dozen other public and private company boards of directors over the last 20+ years. 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, Chief Executive Officer and President.

 

Richard M. Carson is Senior Vice President and General Counsel of Cypress Environmental Partners, GP, LLC, having served in that capacity since March 2016 and having previously served as Vice President and General Counsel since September 2013. Mr. Carson served as a director, officer, and shareholder of Gable & Gotwals, a Professional Corporation (“Gable Gotwals”), a law firm, where he practiced securities, corporate finance, transactional and environmental law, primarily for clients in the energy industry, including several master limited partnerships. Prior to joining Gable Gotwals, from 1999 to 2008, Mr. Carson served in the legal department of The Williams Companies, Inc. (“Williams”), 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, Cum Laude, from the University of Tulsa’s Honors Program in 1988. Mr. Carson serves as Chairman of the board of directors of Land Legacy. He has previously served as the Chair of the Oklahoma Bar Association’s Environmental Law Section, and the chair of the Environmental Auditing Roundtable’s South-Central Region.

 

Jeffrey A. Herbers is Vice President and Chief Financial Officer of Cypress Environmental Partners, GP, LLC, having served in that capacity since November 2018. Prior to being appointed as Chief Financial Officer of Cypress Environmental Partners, GP, LLC, Mr. Herbers served as the Vice President and Chief Accounting Officer of Cypress Environmental Partners, GP, LLC from September 2016 to November 2017 and as the Interim Chief Financial Officer from November 2017 to November 2018. Mr. Herbers served as sole member of Jeff Herbers PLLC from December 2015 until September 2016. Mr. Herbers served as the Chief Accounting Officer of the general partner of NGL Energy Partners LP from February 2012 to November 2015, as the Director of Financial Reporting of SemGroup Corporation from August 2009 to January 2012, and as an auditor for Ernst & Young LLP from August 1998 to July 2009. Mr. Herbers holds a B.B.A. in accounting from the University of Tulsa. He is a certified public accountant and a member of the American Institute of Certified Public Accountants.

 

Henry Cornell became a director of our board effective at the close of our public offering. Mr. Cornell is the Founder and Senior Partner of Cornell Capital, a private equity investment firm. Prior to founding Cornell Capital, he was Vice Chairman of the Merchant Banking Division of Goldman Sachs & Co., where he worked for nearly 30 years prior to his retirement in February 2013. Mr. Cornell served on the firm’s corporate, real estate and infrastructure investment committees. He also led Goldman Sachs & Co.’s investment activities in Asia from 1988 – 2000. Prior to joining Goldman Sachs & Co., Mr. Cornell was an attorney at Davis Polk & Wardwell. He is a trustee of The Asia Society, the Whitney Museum and the Mount Sinai Hospital, and a member of the Council on Foreign Relations. Mr. Cornell received his B.A. from Grinnell College in 1976 and his J.D. from New York Law School in 1981.

 

Cynthia A. Field has been a director on the board of Cypress Environmental Partners, GP, LLC since November 2018. Ms. Field has served as the Sole Manager of CF Inspection Management, LLC, a Women’s Business Enterprise by the Supplier Clearinghouse in California and as a National Women’s Business Enterprise by the Women’s Business Enterprise National Council, since August of 2013. Ms. Field was appointed President and Chief Executive Officer of CF Inspection in January 2018.  Ms. Field is the daughter of Charles C. Stephenson, Jr., one of the directors on the board of Cypress Environmental Partners, GP, LLC.  Ms. Field also serves as the Executive Director and a Trustee of the Charles & Peggy Stephenson Family Foundation, and as a member of the Gilcrease Museum National Advisory Board.

 

Stanley A. Lybarger has served as a director on the board of Cypress Environmental Partners, GP, LLC since March 5, 2014. Mr. Lybarger retired as president and chief executive officer of BOK Financial, a leading regional bank, on January 1, 2014. He continues to serve on the board of directors of that corporation. Mr. Lybarger had a 40-year career with BOK Financial. Mr. Lybarger served as its first president and chief operating officer, in addition to continuing to hold that title for Bank of Oklahoma. He became the chief executive officer for BOK Financial and Bank of Oklahoma in 1996. Mr. Lybarger earned B.A. and M.B.A. degrees from the University of Kansas, and a Certification from the Stonier Graduate School of Banking at Rutgers University. Mr. Lybarger has also been an industry and community leader for decades and has held leadership positions at a number of organizations, including serving on the Federal Advisory Council (a 12-member council which consults and advises the Federal Reserve Board of Governors in Washington, DC), the Executive Committee of the Financial Institutions Division of the American Bankers Association, Chairman of the Tulsa Stadium Trust, Chairman of the Tulsa Metro Chamber, Chairman of the Oklahoma State Chamber, Chairman of the Oklahoma Business Roundtable and Chairman of Tulsa Area United Way.

 

 

John T. McNabb II has served on the board of directors of Cypress Environmental Partners, GP, LLC, the general partner of the Partnership, where he serves as the Chairman of the Conflicts Committee. He co-founded the Trump Leadership Council in April 2016 and served on the council until January 2017. He has also served as Vice Chairman of the American Leadership Council since August 2017. Mr. McNabb has served on the boards of eight publicly-traded companies and currently sits on the board of Continental Resources (where he has served as Lead Director). Mr. McNabb was elected to serve as non-executive Chairman of the Board of Willbros Group, Inc. from September 2007 until August 2014 when he was appointed Executive Chairman. He was appointed Chief Executive Officer in October 2014 and elected to the board of Directors in August 2006. Effective December 1, 2015, Mr. McNabb retired from his positions as Chairman and Chief Executive Officer and did not stand for re-election when his term as Director expired in 2016. Mr. McNabb also serves as Senior Advisor and was formerly Vice Chairman, Corporate Finance of Duff & Phelps Securities LLC, a leading global financial advisory firm. Prior thereto, Mr. McNabb was a founder and Chairman of Growth Capital Partners LP and formerly was a Managing Director of Bankers Trust New York Corporation and a board member of BT Southwest Inc., a wholly owned subsidiary of Bankers Trust. Prior thereto, he served in various capacities with The Prudential Insurance Company of America including having responsibility for a multi-billion dollar investment portfolio primarily focused on energy investments. He started his energy career with Mobil Oil in the E&P Division. He has owned equity interests in approximately twenty private energy related companies and acted in operating or financial roles in several. Mr. McNabb has also served as a director of twelve private energy companies located in both Canada and the United States. He is an emeritus member of the board of Visitors of The Fuqua School of Business at Duke University and served as Chairman of the Board of Visitors of The University of Houston and also served as Chairman of the Dean’s Advisory Board at The Bauer College of Business and as an Executive Professor of Finance at the University of Houston. Mr. McNabb holds BA and MBA degrees from Duke University and served in the US Air Force during the Vietnam conflict, rising to the rank of Captain and was awarded the Air Medal with three Oak Leaf Clusters and the Distinguished Flying Cross.

 

Charles C. Stephenson, Jr. has been a director on the board of Cypress Environmental Partners, GP, LLC since the close of the initial public offering in January 2014. Previously, Mr. Stephenson 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.

 

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 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 organizational governance guidelines provide that the board of directors of our general partner is responsible for reviewing the process for assessing the major risks facing us and the options for their mitigation. This responsibility will be largely satisfied by our audit committee, which is responsible for reviewing and discussing with management and our registered public accounting firm our major risk exposures and the policies management has implemented to monitor such exposures, including our financial risk exposures and risk management policies.

 

Section 16(a) Beneficial Ownership Reporting Compliance

 

Section 16(a) of the Exchange Act requires our general partner’s board of directors and officers, and persons who beneficially own more than 10% of a class of our equity securities registered pursuant to Section 12 of the Exchange Act to file certain reports with the SEC and NYSE concerning beneficial ownership of such securities. To our knowledge, based solely on a review of the copies of such reports furnished to us and written representations by our directors and officers, we believe that all reporting obligations of our general partner’s directors and officers and our greater than 10% unitholders under Section 16(a) were satisfied in 2019.

 

 

Corporate Governance

 

The board of directors of our general partner has adopted Corporate Governance Guidelines that outline important policies and practices regarding our governance and a Code of Business Conduct and Ethics that applies to the directors, officers and employees of our general partner and its affiliates and us.

 

Non-management directors of our general partner meet in executive session without management participation at each meeting of the board of directors. These executive sessions are chaired by Stanley A. Lybarger, the current chairman of our audit committee, or such independent director as he designates. Interested parties may communicate directly with the independent directors by submitting a communication in an envelope marked “Confidential” addressed to the “Independent Members of the Board of Directors” in care of Mr. Lybarger at:

 

Cypress Environmental Partners, GP, LLC 

5727 S. Lewis Ave., Suite 300 

Tulsa, Oklahoma 74105

  

We make available free of charge, within the “Governance Documents” section of our website at www.cypressenvironmental.biz, the Corporate Governance Guidelines, the Code of Business Conduct and Ethics and our Audit Committee Charter. The information contained on, or connected to, our website is not incorporated by reference into this Annual Report on Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC.

 

ITEM 11.

EXECUTIVE COMPENSATION

 

Compensation Overview

 

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, is responsible for managing our operations and CEM LLC employs the employees that operate our business. The compensation payable to the officers of our general partner is paid by CEM LLC and such payments are reimbursed by us. However, we sometimes refer to the employees and officers of our general partner as our employees and officers in this report.

 

This executive compensation disclosure provides an overview of the executive compensation program for our named executive officers identified below. For the year ended December 31, 2019, our named executive officers (“NEOs”) were:

 

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

	●	Richard M. Carson, our Senior Vice President and General Counsel and;

●

Jeffrey A. Herbers, our Vice President and Chief Financial Officer.

 

Summary Compensation Table

 

The following table sets forth certain information with respect to the compensation paid to our NEOs for the years ended December 31, 2019, 2018, and 2017.

 

														Unit
										Bonus				Awards
Name and Principal Position		Year				Salary				(a)				(b)				Total
Peter C. Boylan III			2019			$	466,807			$	891,159			$	463,881			$	1,821,847
Chairman, Chief Executive Officer and President			2018				438,062				—				382,500				820,562
			2017				431,474				50,000				506,069				987,543
Richard M. Carson			2019			$	312,500			$	234,500			$	161,350			$	708,350
Senior Vice President and General Counsel			2018				305,000				65,500				158,440				528,940
			2017				286,250				20,000				169,012				475,262
Jeffrey A. Herbers (c)			2019			$	222,502			$	197,500			$	80,675			$	500,677
Vice President and Chief Financial Officer			2018				196,253				37,500				61,145				294,898
			2017				175,000				7,500				53,779				236,279

  

 

(a)	Represents cash bonus awards paid.  For more information, see "Bonus awards" below.
(b)	Represents the grant date fair value of awards granted under the Cypress Energy Partners, L.P. 2013 Long-Term Incentive Plan as determined in accordance with FASB ASC Topic 718. For additional information, please see Note 10 to the Consolidated Financial Statements in Item 8 of this Annual Report.
(c)	Mr. Herbers assumed the role of interim Principal Financial Officer on November 24, 2017 and was appointed Chief Financial Officer on November 7, 2018.

 

Narrative Disclosure to Summary Compensation Table

 

Elements of the compensation program. For 2019, the primary elements of compensation for our NEOs included base salary, cash bonus awards and equity awards.

 

Base compensation for 2019. Base salaries for our NEOs are set at levels deemed necessary to attract and retain talented individuals and are intended to be competitive with executive 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		$	500,000
Chairman, Chief Executive Officer and President
Richard M. Carson		$	315,000
Senior Vice President and General Counsel
Jeffrey A. Herbers		$	225,000
Vice President and Chief Financial Officer

 

In April 2019, Mr. Boylan’s annual base salary was increased from $438,000 to $475,000, Mr. Carson’s annual base salary was increased from $305,000 to $315,000 and Mr. Herbers’ annual base salary was increased from $215,000 to $225,000. In December 2019, Mr. Boylan’s annual base salary was increased to $500,000. These increases were made in response to the improved financial performance of our businesses.

 

Bonus awards. Our NEOs are eligible for bonuses under our short-term incentive plan (“STI Plan”). Bonuses under the STI Plan are typically paid in March of the year following the performance year. We use target percentages of salary and various financial, safety, and individual performance metrics to guide in the calculation of the bonus amounts, although the bonus amounts under the STI Plan are subject to adjustment at the discretion of the board of directors.

 

Bonuses for our NEOs under the STI Plan for the 2018 plan year were delayed as a result of the bankruptcy of our customer PG&E. Upon the successful sale of our pre-petition receivables from PG&E in November 2019, the board finalized the amounts of the bonuses for the 2018 STI plan year and paid these bonuses to the NEOs in December 2019. Accordingly, these bonuses are reported in the 2019 year in the Summary Compensation Table above.

 

In 2018, Mr. Carson and Mr. Herbers received certain bonuses related to their efforts toward the sale of the Pecos, TX water treatment facility and toward the acquisition by Holdings of two businesses.

 

 

The following table summarizes bonus awards to our NEOs:

 

Year			Description		Boylan				Carson				Herbers
2019			STI for 2019 plan year		$	475,000			$	180,000			$	135,000
2019			STI for 2018 plan year			416,159				54,500				62,500
					$	891,159			$	234,500			$	197,500
2018			Bonus for sale of Pecos, TX facility			—				20,000				11,500
2018			First bonus for acquisions of business by Holdings			—				35,000				20,000
2018			Second bonus for acquisions of business by Holdings			—				10,500				6,000
					$	—			$	65,500			$	37,500
2017			STI for 2017 plan year		$	50,000			$	20,000			$	7,500

 

Discretionary long-term equity incentive awards.  In connection with our IPO, we adopted the Cypress Energy Partners, L.P. 2013 Long-Term Incentive Plan, or the LTIP, under which we make periodic grants of equity and equity-based awards in us to our NEOs and other key employees. The phantom units are subject to potential accelerated vesting as described below under “Severance and change in control arrangements.”

 

Outstanding Equity Awards at December 31, 2019 

 

The following table provides information regarding the outstanding and unvested long-term equity incentive awards held by our NEOs as of December 31, 2019. None of our NEOs held any option awards that were outstanding as of December 31, 2019.

 

					Unit Awards
Name and Principal Position		Grant Date			Number of Units That Have Not Vested #				Market Value of Units That Have Not Vested (a)
Peter C. Boylan III (b)		July 9, 2019			115,000	(d)		$	1,058,000
Chairman, Chief Executive Officer and President		April 9, 2018			125,000	(c)			1,150,000
		March 9, 2017			70,680	(c)			650,256
		March 10, 2016			59,091	(c)			543,637
		March 26, 2015			15,789	(c)			145,259
Richard M. Carson		July 9, 2019			40,000	(d)		$	368,000
Senior Vice President and General Counsel		April 9, 2018			44,000	(c)			404,800
		March 9, 2017			23,605	(c)			217,166
		March 10, 2016			19,735	(c)			181,562
		March 26, 2015			5,428	(c)			49,938
Jeffrey A. Herbers		July 9, 2019			20,000	(d)		$	184,000
Vice President and Chief Financial Officer		April 9, 2018			13,500	(c)			124,200
		March 9, 2017			7,511	(c)			69,101
		November 2, 2016			6,768	(c)			62,266

 

 

(a)	Amount shown reflects the per-unit value based upon the December 31, 2019 closing price of $9.20 per common unit.
(b)	In addition to equity awards, as our co-founder, Mr. Boylan also owns a part of Holdings.
(c)	Represents phantom units granted under the LTIP and scheduled to vest in three equal annual installments on the third, fourth and fifth anniversaries of the grant date.
(d)	Represents phantom units granted under the LTIP with half vesting in three equal tranches in April 2022, April 2023, and April 2024, respectively, contingent only on the continued service of the recipients through the vesting dates; one-fourth vesting either in April 2022, April 2023, April 2024, or not at all, depending on our performance relative to specified profitability targets and contingent on the continued service of the recipients through the vesting dates; and one-fourth vesting either in April 2022, April 2023, April 2024, or not at all, depending on the market value and yield of our common units relative to specified targets on those dates and contingent on the continued service of the recipients through the vesting dates.

 

Severance and change in control arrangements. Except for Mr. Boylan, none of our NEOs has entered into any employment or severance agreements with our general partner or any of its affiliates. Pursuant to arrangements between Mr. Boylan and Holdings, if Mr. Boylan’s employment is terminated without cause (including a deemed termination upon a change in control of Holdings), Mr. Boylan would receive severance payments equal to two times his annual salary and all outstanding equity awards would vest. In addition, if Mr. Boylan’s employment is terminated by Holdings without cause or by Mr. Boylan for good reason or due to Mr. Boylan’s death or disability, Mr. Boylan and his covered dependents would receive 12 months of continued health insurance coverage.

 

The terms of Mr. Carson’s phantom unit awards provide that in the event of a change in control of the partnership, his phantom units would become fully vested in the event Mr. Carson is terminated without cause within six months after such change in control.

 

Retirement, Health, Welfare and Additional Benefits 

 

We provide a basic benefits package that is available to all full-time employees, which currently includes medical, dental, disability, life insurance, and a 401(k) plan. We do not currently provide matching contributions for the 401(k) plan. We do not expect to maintain a defined benefit pension plan for our executive officers, because we believe such plans primarily reward longevity rather than performance.

 

Director Compensation 

 

Officers, employees or paid consultants or advisors of us or our general partner or its affiliates who also serve as directors do not receive additional compensation for their service as directors. Our independent directors who are not officers, employees, or paid consultants or advisors of us or our general partner or its affiliates receive cash and equity-based compensation for their services as directors.

  

Our non-employee director compensation program consists of the following:

 

●

an annual cash retainer of $25,000,

 

●

an additional annual cash retainer of (i) $5,000 for service as the chair of our conflicts committee and (ii) $7,500 for service as the chair of our audit committee, and

 

●

an annual equity-based award granted under our LTIP. Equity-based awards are subject to vesting in equal annual installments over a period of three years, based upon continued service as an independent director.

 

Non-employee directors also receive reimbursement for out-of-pocket expenses associated with attending 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.

 

  

The following table provides information regarding the compensation earned by our non-employee directors during the year ended December 31, 2019.

 

		Cash Fees				Unit
Name		Earned				Awards (a)				Total
Henry Cornell (b)		$	25,000			$	43,500			$	68,500
Stanley A. Lybarger (b)		$	32,500			$	43,500			$	76,000
John T. McNabb II (b)		$	30,000			$	43,500			$	73,500

 

(a)	Represents the grant date fair value of the awards, as determined in accordance with FASB ASC Topic 718. For additional information, please see Note 10 to the Consolidated Financial Statements included in Item 8 in this Annual Report.
(b)	As of December 31, 2019, each of the directors listed in the table above held 14,779 unvested restricted units.

 

Compensation Committee Interlocks and Insider Participation

 

As a limited partnership, we are not required by the NYSE to establish a compensation committee. Mr. Boylan, who serves as the Chairman of the Board, participates in his capacity as a director in the deliberations of the Board concerning executive officer compensation. In addition, Mr. Boylan makes recommendations to the Board regarding named executive officer compensation, but abstains from any decisions regarding his own compensation.

 

Compensation Committee Report

 

Neither we, nor our general partner, has a compensation committee. The board of directors of our general partner has reviewed and discussed the Compensation Overview set forth above and based on this review and discussion has approved it for inclusion in this Annual Report on Form 10-K.   

 

Members of the Board of Directors of Cypress Environmental Partners, GP, LLC
Peter C. Boylan III	Henry Cornell	Charles C. Stephenson, Jr.
Stanley A. Lybarger	John T. McNabb II	Cynthia A. Field

 

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

 

The following table sets forth the beneficial ownership of units of Cypress Environmental Partners, L.P., as of March 10, 2020, held by beneficial owners of 5.0% or more of the units, by each director and named executive officer of Cypress Environmental Partners, GP, LLC, our general partner, and by all directors and executive officers of our general partner as a group. The percentage of units beneficially owned is based on a total of 12,177,902 common units and 5,769,231 preferred units outstanding.

 

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 March 10, 2020, 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. Unless otherwise indicated, the address for each of the beneficial owners below is 5727 S. Lewis Ave., Suite 300, Tulsa, Oklahoma 74105.

 

  

		Common				Preferred				Total				Percentage of
		Units				Units				Units				Units
		Beneficially				Beneficially				Beneficially				Beneficially
Name of Beneficial Owner		Owned				Owned				Owned				Owned
Cypress Energy Holdings, LLC  (a)			6,957,349				—				6,957,349				38.8	%
Charles C. Stephenson, Jr.			413,740				5,769,231				6,182,971				34.5	%
Cynthia A. Field			118,900				—				118,900				*
Peter C. Boylan III			134,468				—				134,468				*
John T. McNabb II			79,617				—				79,617				*
Richard M. Carson			53,765				—				53,765				*
Stanley A. Lybarger			41,538				—				41,538				*
Henry Cornell			19,617				—				19,617				*
Jeffrey A. Herbers			9,955				—				9,955				*
All directors and executive officers as a group (consisting of 8 persons)			871,600				5,769,231				6,640,831				37.0	%

 

*

indicates that person or entity owns less than one percent.

 

(a)	As of year-end, Cypress Energy Holdings, LLC owns 58% of our common units.

 

 

The following table sets forth the beneficial ownership of Cypress Energy Holdings, LLC as of March 10, 2020.

 

					Ownership Interest
Name of Beneficial Owner					Ratio (1)
Cynthia A. Field Trust						36.750	%
Charles C. Stephenson, Jr.						27.468	%
CEP Capital Partners, LLC			(2)			24.500	%
Henry Cornell						1.333	%
Cornell Investment Partners, L.P.						0.667	%
Stephenson Grandchildren Family LLC						9.282	%

 

(1)

Cypress Energy Holdings, LLC is managed by a three-member board of directors consisting of Peter C. Boylan III, Cynthia A. Field and Charles C. Stephenson, Jr. The election of each director requires the affirmative vote of members representing at least a majority of the voting ratio of Holdings and the concurrence of CEP Capital Partners, LLC.

 

(2)

CEP Capital Partners, LLC is owned and controlled by affiliates of Peter C. Boylan III, Chairman, Chief Executive Officer and President of CELP.

  

Securities Authorized for Issuance under Equity Compensation Plans

  

The following table provides certain information with respect to our Long-Term Incentive Plan as of December 31, 2019:

  

Plan Category		Number of Securities  to be Issued upon  Exercise of  Outstanding  Options, Warrants  and Rights				Weighted Average  Exercise Price of  Outstanding  Options, Warrants  and Rights				Number of Securities  Remaining  Available for Future  Issuance under  Equity Compensation  Plans
Equity compensation plans approved by security holders			1,113,633				—				1,143,024
Equity compensation plans not approved by security holders			—				—				—
Total			1,113,633				—				1,143,024

 

Amounts shown represent outstanding phantom units. The phantom units do not have an exercise price.

 

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

 

Parent of Smaller Reporting Entities

 

We have no parents, though Holdings may be considered to be our parent by virtue of its indirect ownership of 6,957,349 common units, representing 58% of our outstanding common units. The owners of Holdings also own 100% of Cypress Environmental GP Holdings, LLC, which owns 100% of our general partner.

 

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 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 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 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 Holdings’ businesses, rather than indirectly benefitting Holdings solely through its ownership interests in us. We expect that any future decision by 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.

 

 

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 constitute breaches of our general partner’s fiduciary duties. Our partnership agreement also provides that affiliates of our general partner, including Holdings and its controlled 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. 

 

As of December 31, 2019, the general partner, its controlled affiliates, and the directors and executive officers own 7,748,460 common units, representing 64% of our total outstanding common units, and 100% of our total outstanding preferred units. In addition, our general partner owns a 0.0% non-economic general partner interest in us.

 

Distributions and Payments to Our General Partner and Its Affiliates (exclusive of Directors and Executive Officers)

 

The following table summarizes the distributions and payments to be made by us to our general partner and its controlled affiliates in connection with the formation, ongoing operation, and liquidation of Cypress Environmental 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.

 

Operational Stage
Distributions of available cash to our general partner and its controlled affiliates		We will generally make cash distributions to the unitholders pro rata, including Holdings and its controlled affiliates, as holder of an aggregate of 6,957,349 common units. In addition, if distributions exceed the minimum quarterly distribution and target distribution levels, the incentive distribution rights held by affiliates of our general partner will entitle the IDR owners to increasing percentages of the distributions in steps, up to 50% of the distributions above the highest target distribution level.   In 2019, 2018, and 2017, our general partner and its affiliates received common and subordinated distributions of approximately $6.5 million, $6.4 million, and $7.9 million, respectively. In 2019 and 2018, an affiliate of our general partner received preferred unit distributions of $4.1 million and $1.4 million, respectively.
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 amended and restated 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 amended and restated omnibus agreement, we reimbursed our general partner $4.5 million and $4.0 million in annual administrative fees for expenses incurred by it and their respective affiliates in providing certain partnership overhead services to us, including the provision of executive management services by certain officers of our general partner in 2019 and 2018, respectively. During 2017, we did not reimburse our general partner for $2.0 million of these administrative fees, because the general partner waived the fees for two quarters that year. Beginning January 1, 2020, the executive management services and other general and administrative expenses that Holdings previously incurred and charged to us via the annual administrative fee are charged directly to us as they are incurred. Under our current cost structure, we expect these direct expenses to be lower than the annual administrative fee that we previously paid, although we expect to experience more variability in our quarterly general and administrative expense now that we are incurring the expenses directly than when we paid a consistent administrative fee each quarter.

 

 

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.
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 with Affiliates

 

On January 21, 2014, we and other parties entered into the various agreements associated with the closing of our IPO, including the vesting of assets in, and the assumption of liabilities by, us and our subsidiaries.

 

Omnibus Agreement

 

We are party to an amended and restated omnibus agreement with Holdings, CEM LLC, CEP LLC, our general partner, the TIR Entities, Charles C. Stephenson, Jr., and Cynthia A. Field. So long as Holdings controls our General Partner, the omnibus agreement will remain in full force and effect, unless we and Holdings agree to terminate it sooner. If Holdings ceases to control our General Partner, either party may terminate the omnibus agreement. We and Holdings may agree to further amend the omnibus agreement; however, amendments that the General Partner determines are adverse to our unitholders will also require the approval of the Conflicts Committee of our Board of Directors.

 

Prior to January 1, 2020, the omnibus agreement called for Holdings to provide certain general and administrative services, including executive management services and expenses associated with our being a publicly-traded entity (such as audit, tax, and transfer agent fees, among others) in return for a fixed annual fee (adjusted for inflation) that was payable quarterly. This annual fee was $4.5 million in 2019 and $4.0 million in 2018 and 2017 (it was increased in 2019 based on the cumulative increase in the PPI since the inception of the omnibus agreement). In an effort to simplify this arrangement so it will be easier for investors to understand, in November 2019, with the approval of the Conflicts Committee of the Board of Directors, we and Holdings agreed to terminate the management fee provisions of the omnibus agreement effective December 31, 2019. Beginning January 1, 2020, the executive management services and other general and administrative expenses that Holdings previously incurred and charged to us via the annual administrative fee are charged directly to us as they are incurred. Under our current cost structure, we expect these direct expenses to be lower than the annual administrative fee that we previously paid, although we expect to experience more variability in our quarterly general and administrative expense now that we are incurring the expenses directly than when we paid a consistent administrative fee each quarter.

 

The amounts charged by Holdings under the omnibus agreement in 2019, 2018, and 2017 were $4.5 million, $4.0 million, and $2.0 million, respectively, and are reflected in general and administrative in the Consolidated Statements of Operations. In 2017, Holdings waived $2.0 million of the $4.0 administrative fee that it was entitled to charge. We recorded the $1.8 million of expense that Holdings incurred in 2017 and did not charge to us within general and administrative in the Consolidated Statement of Operations and as a contribution attributable to general partner in the Consolidated Statement of Owners’ Equity. These costs are included as a component of net loss attributable to general partner in the Consolidated Statements of Operations for 2017. In addition to waiving $2.0 million of the administrative fee in 2017, Holdings provided us with additional financial support by contributing a total of $2.3 million in 2017 in cash, as a reimbursement of certain expenditures incurred by us. These cash contributions are reflected as a contribution attributable to general partner in the Consolidated Statement of Owners’ Equity and as a component of the net loss attributable to general partner in the Consolidated Statement of Operations.

 

 

Indemnification

 

Under our amended and restated omnibus agreement, Holdings will indemnify us, without giving effect to any cap, for the following matters:

  

	●	Retained Assets: all events and conditions associated with any assets retained by Holdings regardless of when they occur;

	●	Litigation: any legal proceedings attributable to ownership or operation of the contributed assets prior to the closing of the IPO, except that indemnification for any legal proceeding not known at the time of the closing of the IPO is subject to an aggregate deductible of $250,000;
	●	TIR Restructuring Transactions: the acquisition of the shares in Tulsa Inspection Resources, Inc. and the merger of Tulsa Inspection Resources, Inc. with the TIR Entities; and

●

Tax Liabilities: for a period up to 60 days past the expiration of any applicable statute of limitations, any tax liability attributable to the assets contributed to us arising prior to the closing of the IPO or otherwise related to Holdings’ contribution of those assets to us in connection with the IPO.

 

We have agreed to indemnify Holdings, without giving effect to any deductible or cap, for events and conditions associated with the operation of our assets that occur after the closing of the IPO to the extent Holdings is not required to indemnify us as described above.  

 

Alati Arnegard, LLC

 

We provide management services to a 25% owned entity, Alati Arnegard, LLC (“Arnegard”). Management fee revenue earned from Arnegard totaled $0.7 million during 2019.

 

CF Inspection Management, LLC

 

We have entered into a joint venture with CF Inspection, a nationally-qualified woman-owned inspection firm affiliated with one of Holdings’ owners. We own 49% of CF Inspection and Cynthia A. Field, the daughter of Charles C. Stephenson, Jr. and a member of the board of directors of our general partner, owns the remaining 51%. In 2019, CF Inspection represented approximately 3.2% of our consolidated revenue.  CF Inspection allows us to offer various services to clients that require the services of an approved Women’s Business Enterprise (“WBE”), as CF Inspection is certified as a Women’s Business Enterprise by the Supplier Clearinghouse in California and as a National Women’s Business Enterprise by the Women’s Business Enterprise National Council.

 

Sale of Preferred Equity

 

On May 29, 2018 (the “Closing Date”), we entered into a Series A Preferred Unit Purchase Agreement (the “Preferred Unit Purchase Agreement”) with an entity controlled by Charles C. Stephenson, Jr. (the “Purchaser”), an affiliate of our General Partner, where we issued and sold in a private placement 5,769,231 Series A Preferred Units representing limited partner interests in the Partnership (the “Preferred Units”) to the Purchaser for a cash purchase price of $7.54 per Preferred Unit, resulting in gross proceeds to the Partnership of $43.5 million.

 

The Preferred Unit Purchase Agreement contains customary representations, warranties, and covenants of the Partnership and the Purchaser. The Partnership and the Purchaser agreed to indemnify each other and their respective officers, directors, managers, employees, agents, counsel, accountants, investment bankers, and other representatives against certain losses resulting from breaches of their respective representations, warranties, and covenants, subject to certain negotiated limitations and survival periods set forth in the Preferred Unit Purchase Agreement.

 

Pursuant to the Preferred Unit Purchase Agreement, and in connection with the closing of this transaction, our General Partner executed the First Amendment to First Amended and Restated Agreement of Limited Partnership of the Partnership, which authorizes and establishes the rights and preferences of the Preferred Units. The Preferred Units shall have voting rights that are identical to the voting rights of the common units into which such Preferred Units would be converted at the then-applicable conversion rate.

 

  

The Purchaser is entitled to receive quarterly distributions that represent an annual return of 9.5% on the Preferred Units. Of this 9.5% annual return, we will be required to pay at least 2.5% in cash and will have the option to pay the remaining 7.0% in kind (in the form of issuing additional preferred units) for the first twelve quarters after the Closing Date. 

 

After the third anniversary of the Closing Date, the Purchaser will have the option to convert the Preferred Units into common units on a one-for-one basis. If certain conditions are met after the third anniversary of the Closing Date, we will have the option to cause the Preferred Units to convert to common units. After the third anniversary of the Closing Date, we will also have the option to redeem the Preferred Units. The Partnership may redeem the Preferred Units (a) at any time after the third anniversary of the closing date and on or prior to the fourth anniversary of the closing date at a redemption price equal to 105% of the issue price, and (b) at any time after the fourth anniversary of the closing date at a redemption price equal to 101% of the issue price.

 

Procedures for Review, Approval and Ratification of Related Person Transactions

 

The board of directors of our general partner adopted a related party transactions policy in connection with the closing of the IPO that provides 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 provides 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.

 

ITEM 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

 

We have engaged Ernst & Young LLP as our independent registered public accounting firm. The following table sets forth fees we have paid to Ernst & Young LLP in 2019, 2018, and 2017. 

 

		Years Ended December 31,
Audit and Non-Audit Fees		2019				2018				2017
						(in thousands)
Audit fees (a)		$	678			$	648			$	559
Tax fees (b)			107				121				117
Other (c)			2				2				2
Total		$	787			$	771			$	678

 

(a)	Fees for audit services include fees associated with the annual audit of Cypress Environmental Partners, L.P., reviews of the Partnership’s quarterly reports, and SEC filings.
(b)	Includes fees for tax services for Cypress Environmental Partners, L.P. and affiliates in connection with tax compliance, tax advice, and tax planning.
(c)	Includes annual fee for accounting research subscription.

 

 

Audit Committee Pre-Approval Policies and Procedures

 

Our audit committee has adopted an audit committee charter which requires the audit committee to pre-approve all audit and non-audit services to be provided by our independent registered public accounting firm. The audit committee does not delegate its pre-approval responsibilities to management or to an individual member of the audit committee.

 

PART IV

  

ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)	Documents to be filed as part of this Annual Report

	1.	A list of the financial statements included in this Annual Report on Form 10-K is set forth in Part II, Item 8 of this Annual Report on Form 10-K.

	2.	Financial Statement Schedules: Financial Statement Schedules are omitted because they are not required, not significant, not applicable or the information is shown in another schedule, the financial statements or the notes to Consolidated Financial Statements.

3.

Exhibits: See “Exhibit Index” below.

 

 

Exhibit Index

 

Exhibit  number		Description
2.1		Contribution, Conveyance and Assumption Agreement, dated February 20, 2015, by and among Cypress Energy Holdings, LLC, Cypress Environmental Partners, LLC, Cypress Environmental Partners, L.P., Cypress Environmental Partners, GP, LLC, Cypress Energy Partners – TIR, LLC, Mr. Charles C. Stephenson, Jr. and Ms. Cynthia A. Field (incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K filed on February 23, 2015)
3.1		First Amended and Restated Agreement of Limited Partnership of Cypress Environmental Partners, L.P. dated as of January 21, 2014 (incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed on January 27, 2014)
3.2		First Amendment to First Amended and Restated Agreement of Limited Partnership of Cypress Environmental Partners, L.P. dated as of May 29, 2018 (incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed on May 31, 2018)
3.3		Second Amendment to First Amended and Restated Agreement of Limited Partnership of Cypress Energy Partners, L.P., dated as of March 5, 2020 (incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed on March 6, 2020)
3.4		Amended and Restated Limited Liability Company Agreement of Cypress Environmental Partners, GP, LLC dated as of January 21, 2014 (incorporated by reference to Exhibit 3.2 of our Current Report on Form 8-K filed on January 27, 2014)
3.5		First Amendment to Amended and Restated Limited Liability Agreement of Cypress Energy Partners GP, LLC, dated as of March 5, 2020 (incorporated by reference to Exhibit 3.3 of our Current Report on Form 8-K filed on March 6, 2020)
3.6		Certificate of Limited Partnership of Cypress Environmental Partners, L.P. (incorporated by reference to Exhibit 3.7 of our Registration Statement on Form S-1/A filed on December 17, 2013)
3.7		Certificate of Amendment to the Certificate of Limited Partnership of Cypress Energy Partners, L.P., dated as of March 2, 2020 (incorporated by reference to Exhibit 3.2 of our Current Report on Form 8-K filed on March 6, 2020)
3.8		Certificate of Formation of Cypress Environmental Partners, GP, LLC (incorporated by reference to Exhibit 3.5 of our Registration Statement on Form S-1/A filed on December 17, 2013)
3.9		First Amendment to the Certificate of Formation of Cypress Energy Partners GP, LLC, dated as of February 27, 2020 (incorporated by reference to Exhibit 3.4 of our Current Report on Form 8-K filed on March 6, 2020)
4.1*		Description of Registrant’s Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934
10.1†		Cypress Environmental Partners, L.P. 2013 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 of our Current Report on Form 8-K filed on January 27, 2014)
10.2		First Amendment to the Cypress Energy Partners, L.P. 2013 Long-Term Incentive Plan (incorporated by reference to Exhibit 99.1 of our Current Report on Form 8-K filed on March 18, 2019)
10.3†		Form of Cypress Environmental Partners, L.P. 2013 Long-Term Incentive Plan Phantom Unit Agreement (incorporated by reference to Exhibit 10.4 of our Registration Statement on Form S-1/A filed on December 17, 2013)
10.4		Amended and Restated Credit Agreement by and among Cypress Environmental Partners, L.P., certain of its affiliates as co-borrowers and guarantors, Deutsche Bank AG, New York Branch, as lender, issuing bank, swing line lender and collateral agent, the other lenders from time to time party thereto, and Deutsche Bank Trust Company Americas, as administrative agent, dated May 29, 2018 (incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed on May 31, 2018)

 

 

10.5		Series A Preferred Unit Purchase Agreement Between Cypress Environmental Partners, L.P. and Stephenson Equity, Co. No. 3, dated as of May 29, 2018 (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed on May 31, 2018)
10.6		Amended and Restated Omnibus Agreement, dated February 20, 2015, among Cypress Energy Holdings, LLC, Cypress Environmental Management, LLC, Cypress Environmental Partners, LLC, Cypress Environmental Partners, L.P., Cypress Environmental Partners, GP, LLC, Cypress Energy Partners – TIR, LLC, Tulsa Inspection Resources, LLC, Tulsa Inspection Resources – Canada ULC, Tulsa Inspection Resources Holdings, LLC and Tulsa Inspection Resources – Nondestructive Examination, LLC (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed on February 23, 2015)
10.7		Second Amended and Restated Omnibus Agreement among Cypress Energy Holdings, LLC, Cypress Environmental Management, LLC, Cypress Environmental Partners, LLC, Cypress Environmental Partners, L.P., Cypress Environmental Partners GP, LLC, Tulsa Inspection Resources, LLC and Tulsa Inspection Resources – Canada ULC (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed on January 31, 2020
10.8		At Market Issuance Sales Agreement by and between Cypress Energy Partners, L.P. and B. Riley FBR, Inc., dated April 5, 2019 (incorporated by reference to Exhibit 1.1 of our Current Report on Form 8-K filed on April 5, 2019)
10.9		Cypress Energy Partners, L.P. Employee Unit Purchase Plan (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed on November 18, 2019)
21.1*		List of Subsidiaries of Cypress Environmental Partners, L.P.
23.1*		Consent of Ernst & Young LLP
31.1*		Chief Executive Officer Certification Pursuant to Exchange Act Rule 13a-14(a) or Rule 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*		Chief Financial Officer Certification Pursuant to Exchange Act Rule 13a-14(a) or Rule 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

 

32.1**		Chief Executive Officer Certification Pursuant to Exchange Act Rule 13a-14(b) or Rule 15d-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code, as Adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.1**		Chief Financial Officer Certification Pursuant to Exchange Act Rule 13a-14(b) or Rule 15d-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code, as Adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101 INS*		XBRL Instance Document
101 SCH*		XBRL Schema Document
101 CAL*		XBRL Calculation Linkbase Document

 

 

101 DEF*		XBRL Definition Linkbase Document
101 LAB*		XBRL Label Linkbase Document
101 PRE*		XBRL Presentation Linkbase Document
104*		Cover Page Interactive Date File

 

* Filed herewith.
** Furnished herewith.
† Management contract or compensatory plan or arrangement.

  

ITEM 16.

SUMMARY

 

None.

  

 

SIGNATURES

 

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

  

	Cypress Environmental Partners, L.P.
	By:	Cypress Environmental Partners, GP, LLC, its general partner
	/s/ Jeffrey A. Herbers
	By:	Jeffrey A. Herbers
	Title:	Chief Financial Officer

 

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

 

Signature		Title		Date
/s/ Peter C. Boylan III		Chief Executive Officer and Chairman of the Board		March 16, 2020
Peter C. Boylan III
/s/ Jeffrey A. Herbers		Vice President and Chief Financial Officer		March 16, 2020
Jeffrey A. Herbers		(Principal Accounting and Financial Officer)
/s/ Henry Cornell		Director		March 16, 2020
Henry Cornell
/s/ Cynthia A. Field		Director		March 16, 2020
Cynthia A. Field
/s/ Stanley A. Lybarger		Director		March 16, 2020
Stanley A. Lybarger
/s/ John T. McNabb, II		Director		March 16, 2020
John T. McNabb, II
/s/ Charles C. Stephenson, Jr.		Director		March 16, 2020
Charles C. Stephenson, Jr.