UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
(MARK ONE)
FORM 10-K
☒
☐
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2017
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
FOR THE TRANSITION PERIOD FROM________ TO_______
Commission File No. 001-36260
CYPRESS ENERGY PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of incorporation or organization)
61-1721523
(I.R.S. Employer Identification No.)
5727 South Lewis Avenue, Suite 300
Tulsa, Oklahoma
(Address of principal executive offices)
74105
(Zip Code)
(Registrant’s telephone number, including area code): (918) 748-3900
Securities Registered Pursuant to Section 12(b) of the Act:
Common Units Representing Limited Partner Interests
(Title of each class)
New York Stock Exchange
(Name of each exchange on which registered)
Securities Registered Pursuant to Section 12(g) of the Act: NONE
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the
past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit
and post such files). Yes ☒ No ☐
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of
the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Annual Report on Form 10-K or any
amendment to this Annual Report on Form 10-K. ☒
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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 ☐
(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
The aggregate market value of the registrant’s Common Units Representing Limited Partner Interests held by non-affiliates computed by reference to the price at which the
limited partner units were last sold as of June 30, 2017 was $31,607,624.
As of March 16, 2018, the registrant had 11,906,464 common units outstanding.
DOCUMENTS INCORPORATED BY REFERENCE: NONE
PART I
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
PART II
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
PART III
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
PART IV
Item 15.
Table of Contents
Business
Risk Factors
Unresolved Staff Comments
Properties
Legal Proceedings
Mine Safety Disclosures
Market for Our Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Selected Financial Data
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Quantitative and Qualitative Disclosures About Market Risk
Financial Statements and Supplementary Data
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
Controls and Procedures
Other Information
Directors, Executive Officers and Corporate Governance
Executive Compensation
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Certain Relationships, Related Transactions and Director Independence
Principal Accounting Fees and Services
Exhibits and Financial Statement Schedules
Signatures
2
Page
5
16
44
44
45
45
45
48
53
71
72
112
112
113
114
119
123
124
130
131
134
GLOSSARY OF TERMS
The following includes a description of the meanings of some of the terms used in this Annual Report on Form 10-K.
“Dig
site
”
The location where pipeline maintenance occurs by excavating the ground above the pipeline.
“ Flowback
water
”
The fluid that returns to the surface during and for the weeks following the hydraulic fracturing process.
"Gun
barrel"
A settling tank used for treating oil where oil and brine are sepearated 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 natural gas transmission pipelines from inside of the pipe.
“IPO”
Our initial public offering of common units representing limited partner interests in us.
“ Injection
intervals
”
The part of the injection zone in which the well is screened or in which the waste is otherwise directly emplaced.
“ NGLs
”
Natural gas liquids. The combination of ethane, propane, butane, isobutene and natural gasolines that, when removed from
natural gas, become liquid under various levels of higher pressure and lower temperature.
“ OPEC
”
The Organization of Petroleum Exporting Countries.
“ Pig
tracking
”
The locating, mapping and monitoring of the in-line inspection pig.
“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 salt 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
”
“ SWD
”
The process of marking the location where pipeline maintenance will occur.
Salt water disposal.
“Water
Services”
Our Water Services business segment
3
Unless the context otherwise requires, references in this Annual Report on Form 10-K to “Cypress Energy Partners, L.P.,” “our partnership,” “we,” “our,” “us,” or
like terms, refer to Cypress Energy Partners, L.P. and its subsidiaries.
NAMES OF ENTITIES
References to:
● “ Brown
” refers to Brown Integrity, LLC, a 51% owned subsidiary of CEP LLC acquired May 1, 2015;
● “ CEM
LLC
” refers to Cypress Energy Management, LLC, a wholly owned subsidiary of the General Partner;
● “ CEM
TIR
” refers to Cypress Energy Management – TIR, LLC, a wholly owned subsidiary of CEM LLC;
● “ CEM-Brown
” refers to Cypress Energy Management – Brown, LLC, a wholly owned subsidiary of CEM LLC;
● “ CEP
LLC
” refers to Cypress Energy Partners, LLC, a wholly owned subsidiary of the Partnership;
● “ CEP-TIR
” refers to Cypress Energy Partners – TIR, LLC, an indirect subsidiary of Holdings, and an owner of 1,346,800 common units representing 11.3% of our
outstanding common units, and an owner of a 36.2% interest in the TIR Entities prior to the sale of its interests to the Partnership effective February 1, 2015;
● “ CES
LLC
” refers to Cypress Energy Services, LLC, a wholly owned subsidiary as of June 1, 2015 that performs management services for our salt water disposal
facilities, as well as a third party facility;
● “ 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;
● “ General
Partner
” refers to Cypress Energy Partners GP, LLC, a subsidiary of Cypress Energy 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 47.2% of our outstanding common units;
● “ Partnership
” refers to the registrant, Cypress Energy Partners, L.P.;
● “ TIR
Entities
” refer collectively to TIR LLC; TIRC; Tulsa Inspection Resources – Nondestructive Examination, LLC; TIR-PUC and CF Inspection; all of which were
50.1% owned by CEP LLC from our IPO until February 1, 2015, at which time CEP LLC acquired the remaining interests from affiliates of Holdings and now owns
100%;
● “ TIRC
” refers to Tulsa Inspection Resources – Canada, ULC, a wholly owned subsidiary of CEP 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.
4
CAUTIONARY REMARKS REGARDING FORWARD LOOKING STATEMENTS
The information discussed in this Annual Report on Form 10-K includes “forward-looking statements.” These forward-looking statements are identified by their
use of terms and phrases such as “may,” “expect,” “estimate,” “project,” “plan,” “believe,” “intend,” “achievable,” “anticipate,” “continue,” “potential,” “should,”
“could,” and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve
certain assumptions, risks and uncertainties and we can give no assurance that such expectations or assumptions will be achieved. Important factors that could
cause actual results to differ materially from those in the forward-looking statements are described under “ Item
1A
-
Risk
Factors
” and “ Item
7
-
Management’s
Discussion
and
Analysis
of
Financial
Condition
and
Results
of
Operations
” in this Annual Report. All forward-looking statements attributable to us or persons
acting on our behalf are expressly qualified in their entirety by the cautionary statements in this paragraph and elsewhere in this Annual Report on Form 10-K and
speak only as of the date of this Annual Report on Form 10-K. Other than as required under the securities laws, we do not assume a duty to update these forward-
looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.
PART I
ITEM 1.
BUSINESS
Overview
The Partnership is a Delaware limited partnership formed on September 19, 2013 to become a diversified Partnership serving energy companies throughout North
America. We currently provide essential midstream services that include independent pipeline inspection and integrity services to producers and pipeline
companies and water and environmental services with salt water disposal facilities to U.S. onshore oil and natural gas producers and trucking companies. On
January 21, 2014, we completed the IPO of our limited partner common units. As part of the transaction, affiliates of Holdings conveyed an aggregate 50.1%
interest in the TIR Entities in exchange for an aggregate 15.7% ownership in the Partnership. Affiliates of Holdings held the remaining 49.9% interest in the TIR
Entities, which was then acquired by the Partnership on February 1, 2015. The Partnership now owns 100% of the TIR Entities.
Our business is currently organized into three reportable segments: (1) Pipeline Inspection Services (“Pipeline Inspection”), comprising the TIR Entities’
operations, (2) Integrity Services (“Integrity Services”), made up of Brown’s operations and (3) Water and Environmental Services (“Water Services”),
constituting salt water disposal activities in the CEP LLC and CES LLC entities. We also have a number of other potential lines of business outlined in our IRS
private letter ruling (“PLR”) that would allow us to further diversify our business activities and lines of business serving the energy industry.
Through the Pipeline Inspection segment, we provide independent inspection services to various energy, public utility and pipeline companies in both the United
States and Canada. Inspectors in this segment perform a variety of inspection services on both new and existing midstream pipelines, midstream assets and
infrastructure, gathering systems, and distribution systems, including data gathering and supervision of third-party construction, inspection, and maintenance and
repair projects. Results in this segment are driven primarily by the number and type of inspectors performing services for our customers and the fees they charge
for those services, which depend on the nature and duration of the projects. Pipeline Inspection is entirely comprised of the operations of the TIR Entities.
The Integrity Services segment primarily provides hydrostatic testing services to major natural gas and petroleum companies and pipeline construction companies
for both newly-constructed and existing natural gas and petroleum pipelines. Field personnel in this segment perform various integrity services on newly-
constructed and existing oil and natural gas pipelines. Results in this segment are driven primarily by the number and skill level of our field personnel performing
the integrity services, size and length of the pipelines tested, the complexity of services provided, the degree to which customers use our equipment, and the nature
and duration of the projects. These projects are typically based on fixed-bid agreements with customers. The Integrity Services segment is mainly comprised of the
operations of Brown.
Our Water Services segment provides salt water disposal services to oil and natural gas producers and trucking companies and consists of the operations of CEP
LLC, which, as of the end of the year, owned and operated eight commercial salt water disposal facilities in the Bakken Shale region of the Williston Basin in
North Dakota and two in the Permian Basin in Texas and CES LLC, which provides management and staffing services for an additional salt water disposal facility
(one salt water disposal facility in the Permian Basin was sold in January 2018). We generate revenue by treating produced water and flowback water and
injecting the water into our salt water disposal facilities. Results are driven primarily by the volume of water injected into our salt water disposal facilities and the
fees we charge for these services. These fees are charged on a per-barrel basis and vary based on the quantity and type of salt water disposed, competitive
dynamics, and operating costs. Our salt water disposal facilities currently utilize specialized equipment and remote monitoring to minimize downtime and increase
efficiency for peak utilization and are located in close proximity to existing producing wells and expected future drilling sites, making our salt water disposal
facilities attractive to our current and future customers. These facilities also contain oil skimming processes that remove oil from flowback and produced water
that has been delivered to our sites. We then generate revenue by selling the residual oil recovered from the water treatment process. In addition to the nine salt
water disposal facilities owned by CEP LLC (post the sale of the one salt water facility in January 2018), our consolidated subsidiary, CES LLC, provides
management and staffing services for an additional salt water disposal facility in the Bakken Shale region, pursuant to a management agreement. CES LLC also
owns a 25% interest in this facility. The Water Services segment is directly tied to oil and gas activity and is impacted by changes in commodity prices,
competition, and newly completed oil and gas wells.
5
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, 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 approximately
64.0% of our outstanding limited partner interests, Holdings and its affiliates have a strong alignment of interests with our minority unitholders to ensure the
ongoing successful execution of our business plan.
Business Strategies
Our principal business objective is to build a diversified partnership serving energy customers that will allow us, over time, to incrementally increase the quarterly
cash distributions that we pay to our unitholders. We expect to achieve this objective through the following business strategies:
●
Capitalize
on
improving
industry
fundamentals
.
●
●
●
Pipeline
Inspection
. We believe the pipeline inspection services market offers attractive long-term growth fundamentals; as such, 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 material 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. Although the recent energy downturn has impacted our customers,
most of our clients are investment–grade, well-capitalized 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. That being said, our business is not immune to
changes in the energy economy. However, we believe that we can continue to grow organically by acquiring new customers and additional work
from existing customers. For example, in 2017 despite lower revenues due to the loss of one large customer in Canada, we added 30 new customers in this
segment. We also continue to grow our business development team to pursue these and other opportunities.
Integrity
Services
. Effective May 1, 2015, we acquired Brown, which operates our Integrity Services business segment. The industry downturn
significantly impacted Brown and the Integrity Services segment. We took a variety of actions in the second half of 2016 to reduce the cost structure of
Brown. We continue to remain cautiously optimistic that Brown is well positioned to resume growth as customers become more active following the most
recent industry downturn. It is our intent to capitalize on Brown’s strong reputation and expand our Integrity Services business.
Water
Services
. We believe that the water and environmental services market will continue to offer long-term growth fundamentals and we intend to
maintain our position as a high quality operator of salt water disposal facilities, despite the recent sluggish energy economy that has adversely impacted our
Water Services segment. We took aggressive actions in the second quarter of 2016 to adjust our cost structure to compensate for the lower volumes
associated with the industry downturn. We continue to look for pipeline opportunities with exploration and production (“E&P”) companies that will secure
water for our salt water disposal facilities. Regulations continue to increase and we have proven to our customers that we are a trusted and dependable
service provider. Increasingly, E&P companies are having their central procurement and Environment, Health and Safety (“EHS”) personnel conduct
inspections of our salt water disposal facilities. This trend should benefit our Partnership. We remain an approved vendor for many prestigious investment
grade E&P companies that demand very high standards from their vendors. Although the oil and gas industry can be cyclical in nature (as is evidenced by
the recent three year downturn), our current business strategy is to derive a significant portion of our volume and revenue from existing wells. Although new
drilling activity declined significantly over the last three years, the recent rebound in commodity prices have led to an increase in drilling activity in both
basins in which we operate. Currently, activity in the Permian is much stronger than activity in the Bakken. A portion of Water Services salt water disposal
facilities will continue to suffer declines in volumes and pricing until the market continues to rebound leading to additional drilling and completions that, in
turn, generate additional produced water for the life of those newly-completed oil and gas wells. We intend to capitalize on the continued demand for
removal, treatment, storage and disposal of flowback and produced water by positioning ourselves as a trusted, dependable provider of safe, high-quality
water and environmental services to our energy customers.
6
●
●
●
●
Optimize
existing
salt
water
disposal
assets.
The average age of our salt water disposal facilities was 5.3 years at the end of 2017. We estimate that we
utilized approximately 24% of the aggregate annual capacity (53 million barrels per year) of these facilities for the year ended December 31, 2017,
evidencing capacity for growth without additional capital expenditures. We are seeking to increase the utilization of our existing salt water disposal
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 salt water disposal facilities. We currently have ten pipelines connected to four of our salt water disposal facilities. Because
many of the costs of constructing and operating a salt water disposal facility are either upfront capital costs or fixed costs, we expect that increased
utilization of our existing salt water disposal facilities will lead to increased gross margin percentage and operating cash flow in the Water Services
segment. The three-year industry downturn placed significant pressure on both the volumes we processed and the prices we were able to charge for our
services, however, the industry began a recovery following OPEC’s decision to reduce production in November 2016.
Increase
the
number
of
pipelines
connected
to
our
salt
water
disposal
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 the natural
gas producers will increasingly prefer to utilize pipeline systems to transport their saltwater directly to salt water disposal facilities. We intend to purchase or
construct, whether alone or in joint ventures, saltwater pipeline systems that connect producers to our salt water disposal facilities or newly developed salt
water disposal facilities. We continue to focus on increasing pipeline water delivered to our facilities. Our 2017 pipeline water volumes (excluding two salt
water disposal facilities which were inoperable a significant portion of 2017 due to being struck by lightning) increased approximately 249,000 barrels from
piped water volumes in 2016. As a percentage of total water volume, pipeline water was 46%, 45% and 31% in 2017, 2016 and 2015, respectively. We will
continue to focus on potential pipeline opportunities. For example, in January 2018, we completed the construction of a gathering system that transports
water from a customer’s producing fields to one of our disposal facilities in North Dakota.
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 Water Services 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.
We intend to pursue accretive acquisitions that will complement the Partnership. Our business segments
operate in industries that are fragmented, giving us the opportunity to make strategic and accretive acquisitions. We remain optimistic that
attractive acquisition opportunities are currently present or will present themselves in the near future. We plan to expand Water Services by
seeking water and solid acquisition opportunities that will diversify our customer base in existing and additional high-growth resource plays
throughout the U.S. We are particularly focused on pursuing on pipeline opportunities directly with E&P customers. In addition, provided
certain opportunities fit with our strategic plan of expanding our businesses (such as the addition of our Integrity Services segment), we intend to
grow Pipeline Inspection and Integrity Services by acquiring other strategic pipeline service companies that will allow us to broaden the suite of
services we offer our existing customer base.
Our Business Segments
Our business currently operates in three reportable segments: (1) Pipeline Inspection Services (“Pipeline Inspection”), comprising the TIR Entities’ operations, (2)
Integrity Services, made up of Brown’s operations and (3) Water and Environmental Services (“Water Services”), constituting salt water disposal activities. Our
IRS private letter ruling (“PLR”) allows for expansion into other lines of business. Our long-term goal continues to be to diversifying the Partnership into other
attractive lines of business including, but not limited to, traditional midstream activities, production chemicals and remote monitoring of energy infrastructure, in
addition to the continued expansion of our current segments. For information relating to revenues from external customers, operating income, and total assets for
each segment, refer to “ Note
13
–
Segment
Disclosures
” of our Consolidated Financial Statements included in “ Item
8.
–
Financial
Statements
and
Supplementary
Data
.”
Pipeline Inspection
Overview
. We believe that the Pipeline Inspection segment is a leading provider of independent inspection services to the pipeline industry. We provide essential services for
pipelines, gathering systems, local distribution systems, equipment, and facilities to our well-established customer base. We provide inspection to oil and natural gas producers,
public utility companies, and other pipeline operators that are required by law to inspect their gathering systems, storage facilities, infrastructure, distribution systems and
pipelines. Our approximately 120 pipeline inspection and integrity service customers include oil and natural gas producers, pipeline owners and operators and public utility
companies throughout North America. We also have entered into a joint venture with CF Inspection, a nationally-qualified minority-owned inspection firm affiliated with one of
Holdings’ owners. CF Inspection serves energy companies that require a minority-owned vendor. We own 49% of CF Inspection and Cynthia A. Field, the daughter of Charles
C. Stephenson, Jr., owns the remaining 51% of CF Inspection. In 2017, CF Inspection represented approximately 3.5% of our consolidated revenue.
7
Pipeline Inspection offers independent inspection services for the following facilities and equipment:
●
Transmission pipelines (oil, gas and liquids);
●
Oil and natural gas gathering systems;
●
Natural gas processing plants;
●
Pump, compressor, measurement, and regulation stations;
●
Storage facilities and terminals; and
●
Gas distribution systems.
Operations.
Oil and natural gas producers, public utility companies, and other pipeline operators are required by federal and state law and regulation to inspect their pipelines
and gathering systems on a regular basis in order to protect the environment and ensure 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 more than
16,000 professionals. Our inspectors have significant industry experience and are certified to meet the qualification requirements of both the customer and the Pipeline and
Hazardous Materials Safety Administration (“PHMSA”). As the industry continues to adopt new technology, demand has increased for inspectors with greater technical skills
and computer proficiencies. Our customers require inspectors to undergo specific training prior to performing inspection work on their projects. We utilize the National Center
for Construction Education and Research and Veriforce training curricula to train and evaluate employees, along with other resources. In addition to assignment-specific
training, welding inspectors and coating inspectors also must meet special certification requirements. During the years ended December 31, 2017, 2016 and 2015 we employed
or engaged an average of 1,145, 1,147 and 1,392 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);
●
Ultrasonic nondestructive examination services (using high-frequency sound waves to detect pipeline imperfections); and
●
Related data management services.
Integrity Services
Overview
. The Integrity Services segment, comprised of our Brown operations, 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 petroleum pipelines.
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 or pipeline construction companies are required to integrity-test newly-
constructed pipelines prior to placing the pipelines in service. In our Integrity Services segment, we contract directly with pipeline owners or 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 20, 23 and 33 field technicians performing the testing services during the years ended December 31,
2017, 2016 and 2015, respectively.
8
Water Services Segment
Overview.
Through our Water Services segment, which specializes in water and environmental services, we currently own and operate nine salt water disposal facilities (which
excludes one salt water disposal facility In Pecos, Texas in the Permian Basin, Pecos, which we sold in early 2018 and which is excluded from the description below), eight of
which are in the Bakken Shale region of the Williston Basin in North Dakota and one of which is in the Permian Basin in west Texas. Four of our facilities are connected to ten
different pipelines owned by various energy companies in both North Dakota and the Permian basin. In addition to owning and operating these nine salt water disposal facilities,
we manage another salt water disposal facility in which we own a 25% interest.
Operations.
Water Services 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 have significantly increased their volumes of completion barrels of water in various formations in order to get higher productions 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 salt water disposal facilities via pipeline or by truck or contracts with a trucking company for transport. Once the water is
received at the salt water disposal facility, we treat the water through a combination of separation tanks, gun barrels, and chemical processes, store the water as necessary
prior to injection, and then inject the water into the salt water disposal well at depths of at least 4,000 feet after recovering the skim oil. Like produced water, we assess
the composition of flowback water in our facilities so that we can maximize oil separation and treat the water to maximize the life of our equipment and the wellbore.
We believe our approach to scientifically and methodically filtering and treating the flowback water prior to injecting it into our wells helps extend the life of our wells
and furthers our reputation as an environmentally-conscious service provider.
● 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 salt water
produced may decline more slowly 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 salt water disposal facilities by truck or pipeline or contracts with a trucking company to transport it to one of our salt water disposal
facilities. Once we receive the water at one of our salt water disposal facilities, we filter and treat the water and then inject it into the salt water disposal well at depths of
at least 4,000 feet after recovering any skim oil. We also maintain the ability to store salt water 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 salt water disposal well, we separate the residual oil from the salt water 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 salt water
disposal facilities.
● Management
of
existing
salt
water
disposal
facilities.
In addition to the salt water disposal facilities we own or lease, we own a management and development company
that manages an additional salt water disposal facility in North Dakota. Our responsibilities in managing this salt water disposal facility typically include operations,
billing, collections, insurance, maintenance, repairs and, in some cases, sales and marketing. We are compensated for management of this facility based on a percentage
of the gross revenue of the facility or a minimum monthly fee.
The majority of our disposed salt water volumes are derived from produced water that is generated throughout the life of the oil or natural gas well. For the years
ended December 31, 2017, 2016 and 2015, produced water represented approximately 93%, 96%, and 93%, respectively, of our total barrels of disposed water.
This differentiates us from many competitors that focus on flowback water and the associated skim oil revenue. As a region matures and the predominant activity
shifts from drilling and completion of wells to production, our facilities continue to experience demand for ongoing processing of wastewater produced over the
life of the wells.
Each of our salt water disposal facilities are open 365 days per year, with some being open by appointment only. Some of our locations in North Dakota 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. We anticipate that more of our salt water disposal
facilities will be run through technological automation with off-site monitoring and control. Our facilities have been inspected and approved by several of our
public E&P customers that have stringent approval standards and field audits performed by their Environmental, Health and Safety groups.
9
The amount of salt water disposed in our salt water disposal facilities decreased by 0.7 million barrels for the year ended December 31, 2017 compared to the year ended
December 31, 2016 (to 12.6 million barrels) due primarily to lightning strikes and subsequent fires at two of our salt water disposal facilities. Excluding the two wells struck by
lightning, the amount of salt water disposed in our remaining eight salt water disposal facilities increased approximately 0.7 million barrels for the year ended December 31,
2017 compared to the year ended December 31, 2016. The amount of salt water disposed in our salt water disposal facilities decreased by 5.6 million barrels for the year ended
December 31, 2016 compared to the year ended December 31, 2015 (to 13.3 million barrels) due primarily to decreased oil and gas well activity in the Bakken region, as well as
increased competition from several new salt water disposal facilities in the Permian basin that competed for business with our locations.
After the sale of our Pecos, Texas salt water disposal facility effective January 1, 2018, we had an aggregate in excess of 116,000 barrels of maximum daily disposal capacity in
the following salt water disposal facilities, all of which were built using completion techniques consistent with current industry practices and utilizing well depths of at least
5,000 feet with injection intervals beginning at least 4,000 feet beneath the surface. Our permitted capacity is much higher.
Location
Tioga, ND
Manning, ND
Grassy Butte, ND
New Town, ND (1)
Williston, ND (1)
Stanley, ND
Orla, TX (1)
Belfield, ND
Watford City, ND (1), (2)
Arnegard, ND (1)
County
Williams
Dunn
McKenzie
Mountrail
Williams
Mountrail
Reeves
Billings
McKenzie
McKenzie
In-service Date
Leased / Owned (3)
June 2011
December 2011
May 2012
June 2012
August 2012
September 2012
September 2012
October 2012
May 2013
August 2014
Owned
Owned
Leased
Leased
Owned
Owned
Owned
Leased
Leased
Leased
(1) Currently receives piped water.
(2) We own a 25.0% noncontrolling interest in this salt water disposal 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 oil and natural gas producers, pipeline owners and operators, and public utility or local distribution companies with
infrastructure in North America. During the years ended December 31, 2017, 2016 and 2015, Pipeline Inspection had approximately 120, 90 and 90 customers, respectively. The
five largest customers in this segment generated approximately, 53%, 62%, and 65% of our segment revenue for the years ended December 31, 2017, 2016 and 2015,
respectively. For the years ended December 31, 2017, 2016 and 2015, we had three customers that individually accounted for more than 10% of segment revenues.
Integrity Services
Integrity Services segment customers are primarily pipeline construction companies and, in some instances, the pipeline owners. During the period from May 1, 2015
(acquisition date) through December 31, 2015, we had approximately 61 customers. During the years ended December 31, 2017 and 2016, we had approximately 57 and 60
customers, respectively. Our ten largest customers generated approximately 74%, 71% and 70% of our total segment revenue during the years ended December 31, 2017, 2016
and 2015, respectively. We had two customers that each generated more than 10% of the total segment revenues for the years ended December 31, 2017, 2016 and 2015.
Water Services
Water 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, 2017, 2016 and 2015, we had approximately 196, 180, and 178 customers, respectively, in Water
Services. Our ten largest customers generated approximately 65%, 65%, and 62% of Water Services revenue for the years ended December 31, 2017, 2016, and 2015,
respectively. For the years ended December 31, 2017 and 2015, we had one customer and for the year ended December 31, 2016, two customers that generated 10% or more of
Water Services revenue.
10
Competition
Pipeline Inspection
The pipeline inspection business is highly competitive. Pipeline Inspection’s competition consists primarily of three types of companies: independent energy
inspection firms, engineering and construction firms, and diversified inspection service firms. Diversified inspection firms may inspect, for example, electric and
nuclear facilities in addition to pipelines 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 non-destructive examination experience, safety record, insurance, the level of inspector training provided, reputation, dependability of services, customer
service, and price.
Integrity Services
The pipeline integrity services business (hydrotesting) 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.
Water Services
The water and environmental services business is highly competitive with relatively low barriers of entry. During 2014, competitors opened a number of new
locations around our existing facilities based upon anticipated new drilling activity prior to a downturn in the oil and gas industry beginning in November 2014.
Our competition consists primarily of smaller regional companies that utilize a variety of disposal methods and generally serve specific geographical markets. In
addition, we face competition from other large oil field service companies that also own trucking operations and our customers, who may have the option of using
internal disposal methods instead of outsourcing to us or to another third-party disposal company. Many E&P companies also own their own salt water disposal
facilities and water gathering systems, and therefore do not send their produced water to third parties for disposal. We believe that the principal competitive
differentiating factors in our businesses include gaining and maintaining customer approval of salt water disposal 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 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. By contrast, our Canadian customers use
inspection services the most during the fourth and first quarters of the year when the tundra is frozen. We believe our presence across various regions in the U.S.
and our presence in Canada helps mitigate the seasonality of our business. As we expand our relationships with public utility commissions in California and other
locations with moderate climates, our inspection and integrity business could become less seasonal.
Integrity Services
Since most of the work of the Integrity Services segment is currently performed in the southern United States, weather does not create a major seasonality issue.
However, business has historically been slower in the first calendar quarter and during the month of November and December, due to the holiday season and
budgeting cycles of our customers.
Water Services
The overall operations and financial performance of our Bakken Shale operations are impacted by seasonality. The volume of salt water that we handle in the
Bakken Shale region of the Williston Basin in North Dakota tends to be lower in the winter, due to heavy snow and cold temperatures, and in the spring, due to
heavy rains and muddy conditions that may lead to road restrictions and weight limits that can impact business. The amount of residual oil is also less prevalent
and more difficult to separate from the salt water during the winter months. Seasonality is not typically a significant factor in the Permian Basin in West Texas;
however, ice and snow can lead to reduced activity for E&P companies operating in the region.
Regulation of the Industry
Environmental and Occupational Health and Safety Matters
Our operations and the operations of our customers are subject to numerous federal, state, and local environmental laws and regulations relating to worker health
and safety, the discharge of materials, and environmental protection. These laws and regulations may, among other things, require the acquisition of permits for
regulated activities; govern the amounts and types of substances that may be released into the environment in connection with our operations; restrict the way we
handle or dispose of wastes; limit or prohibit our or our customers’ activities in sensitive areas such as wetlands, wilderness areas, or areas inhabited by endangered
or threatened species; require investigatory and remedial actions to mitigate pollution conditions caused by our current or former operations; and impose specific
standards addressing worker protections. Numerous governmental agencies issue regulations to implement and enforce these laws, for which compliance is often
costly and difficult. The violation of these laws and regulations may result in the denial or revocation of permits, issuance of corrective action orders, assessment
of administrative and civil penalties and even criminal prosecution.
11
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 impact on our financial position,
results of operations, or future cash flows.
Hazardous
substances
and
wastes.
Our operations are subject to environmental laws and regulations relating to the management and release of hazardous
substances, solid wastes, hazardous wastes and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and
disposal of solid and hazardous waste and may impose strict joint and several liability for the investigation and remediation of affected areas where hazardous
substances may have been released or disposed. For instance, the Comprehensive Environmental Response Compensation and Liability Act, or CERCLA, and
comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of
a hazardous substance into the environment. We may handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our
ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these
hazardous substances have been released into the environment. Under such laws, we could be required to remove previously disposed substances and wastes
(including substances disposed of or released by prior owners or operators) or remediate contaminated property (including groundwater contamination, whether
from prior owners or operators or other historical activities or spills). These laws may also require us to conduct natural resource damage assessments and pay
penalties for such damages. It is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly
caused by the release of hazardous substances or other pollutants into the environment. These laws and regulations may also expose us to liability for our acts that
were in compliance with applicable laws at the time the acts were performed.
Petroleum hydrocarbons and other substances arising from oil and natural gas-related activities have been disposed of or released on or under many of our sites. At
some of our facilities, we have conducted and continue to conduct monitoring or remediation of known soil and groundwater contamination. We will continue to
perform such monitoring and remediation of known contamination, including any post remediation groundwater monitoring that may be required, until the
appropriate regulatory standards have been achieved. These monitoring and remediation efforts are usually overseen by state environmental regulatory agencies.
We estimate that we will incur costs of less than $0.1 million over the next one to three years in connection with continued monitoring and remediation of known
contamination at our facilities.
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 US District court for the District of Columbia in December 2016. Under the decree, the EPA is
required to propose, by no later than March 15, 2019, 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. If EPA proposes a rulemaking for revised E&P waste regulations, the consent decree requires that the EPA take final
action following notice and comment rulemaking no later than July 15, 2021. If the RCRA E&P waste exemption is repealed or modified, we could become subject
to more rigorous and costly operating and disposal requirements.
12
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 salt water injection process prior to sale could
impose liability on us in the event that the entity to which the oil was transferred fails to manage and, as necessary, dispose of residual crude oil in accordance with
applicable environmental and occupational health and safety laws.
Our customers are subject to these same regulations. While these largely result in their needing our services, some waste regulations could have the opposite
effect. For instance, some states, including Texas, have considered laws mandating the recycling of flowback and produced water. If such laws are passed, our
customers may divert some salt water 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.
For example, the lesser-prairie chicken was listed as threatened in March 2014, although a district court recently vacated this decision. 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.
13
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 Integrity 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. The agreement provides for a four-year exit process beginning when it
took effect in November 2016, which would 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 Texas and North Dakota, where we conduct our water and environmental services business, have either adopted or proposed
laws and/or regulations to require oil and natural gas operators to disclose chemical ingredients and water volumes used to hydraulically fracture wells, in addition
to more stringent well construction and monitoring requirements. The chemical ingredient information is generally available to the public via online databases
including fracfocus.org, and this may bring more public scrutiny to hydraulic fracturing operations.
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 updates 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 instated by the U. S. Court of Appeals for the Tenth Circuit in September 2017. The DOI
formally rescinded the rule in December 2017.
14
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 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 has triggered seismic activity
in certain areas. Some states, including Texas, have promulgated rules or guidance in response to these concerns. In Texas, the Texas Railroad Commission
(“TRC”) published a final rule in October 2014 governing permitting or re-permitting of disposal wells that will require, among other things, the submission of
information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating
to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal
zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the TRC may deny, modify, suspend
or terminate the permit application or existing operating permit for that well. These new seismic permitting requirements applicable to disposal wells impose more
stringent permitting requirements and are likely to result in added costs to comply or, perhaps, may require alternative methods of disposing of salt water and other
fluids, which could delay production schedules and also result in increased costs. 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. All of our executive management personnel are employees of CEM LLC or
another affiliate of Holdings, and devote the portion of their time to managing our operations. As of December 31, 2017, ten employees of CEM LLC provided
services to us that are charged to us through the quarterly administrative fee that is specified in the omnibus agreement between the Partnership and Holdings.
As of December 31, 2017, affiliates of Holdings employed 109 people in our corporate office, who provide various services including management, human
resources, information technology, safety, and accounting, among others. We directly reimburse Holdings and its affiliates for the cost of these employees.
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, 2017, this segment employed approximately 1,015 inspectors. Of these inspectors, 8 were employed
in Canada and the remainder were employed in the United States. We directly reimburse Holdings and its affiliates for the cost of these inspectors.
Our Integrity Services employed approximately 34 people at December 31, 2017. Most of the employees in the Integrity Services segment are full-time employees
who are compensated regardless of whether they are deployed on a client project. We directly reimburse Holdings and its affiliates for the cost of these employees.
Our Water Services segment employed 9 people at December 31, 2017 who work at our Texas and North Dakota facilities. We directly reimburse Holdings and its
affiliates for the cost of these employees.
As of December 31, 2017, approximately 59 inspectors of our Pipeline Inspection segment are members of a union and are covered by collective bargaining
arrangements. None of our other employees are covered by collective bargaining arrangements.
15
Insurance Matters
Our customers require that we maintain certain minimum levels of insurance and evaluate our insurance coverage as part of the initial and ongoing approval
process they require to use our services to treat and dispose of their waste. We 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.
The salt water disposal and the pipeline inspection and integrity businesses can be dangerous, involving unforeseen circumstances such as environmental damage
from leaks, spills, or vehicle accidents. To address the hazards inherent in Water 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 Integrity
Services, insurance coverage includes employer’s liability, auto liability, employee benefits liabilities, and contractor’s pollution and other coverage. Coverage for
environmental and pollution-related losses is subject to significant limitations and are commonly provided for exclusion on such policies. 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.cypressenergy.com
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 Energy Partners, L.P., 5727 South Lewis Ave., Suite 300, Tulsa, OK 74105 or by e-mailing
ir@cypressenergy.com. 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 our minimum quarterly distributions to holders of our units because we may not have sufficient cash from operations due to our
establishment of cash reserves, payment of fees and expenses, and cash reimbursement to our General Partner and its affiliates.
In order to pay the minimum quarterly distribution of $0.3875 per unit per quarter, or $1.55 per unit on an annualized basis, we will require available cash of
approximately $4.6 million per quarter, or $18.5 million per year, based on the number of outstanding common units as of March 16, 2018. We may not have
sufficient available cash from operating surplus each quarter to enable us to pay the minimum quarterly distribution. Because of various factors, including the
recent oil and gas economic downturn, it is currently anticipated that, for the immediate future, our quarterly distributions will be $0.21 per unit per quarter,
approximately 54% of our minimum quarterly distribution. On February 14, 2017, we exited subordination pursuant to the terms of the Partnership agreement. As
a result, our subordinated units were converted to common units at that time on a one-for-one basis. 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, Integrity Services and Water Services;
● the number and types of projects conducted by Pipeline Inspection and Integrity Services and the volume of salt water handled in Water Services;
● the amount of residual oil we are able to separate and sell from the salt water we receive that can be impacted by the quality and price of the oil;
● the cost of achieving organic growth in current and new markets;
● our ability to make profitable acquisitions of pipeline inspection and integrity companies, other salt water disposal facilities, and other types of businesses;
● the level of competition from other companies;
● governmental regulations, including changes in governmental regulations, in our industry;
● prevailing economic and market conditions, including low or volatile commodity prices and their effect on our customers; and
● weather and natural disasters, lightning, seismic activity, vandalism and acts of terror.
16
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:
● 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 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 borrow funds and access capital markets;
● the amount of cash reserves established by our general partner; and
● other business risks affecting our cash levels.
We serve customers who are involved in drilling for, producing and transporting oil and natural gas. Adverse developments affecting the oil and natural gas
industry or drilling activity, including sustained low or further reduced oil or natural gas liquids prices, reduced demand for oil and natural gas products,
adverse weather conditions, and increased regulation of drilling and production, could have a material adverse effect on our results of operations.
Water Services depends on our oil and natural gas customers’ willingness to make operating and capital expenditures to develop and produce oil and natural gas in
the United States. A reduction in drilling activity generally results in decreases in the volumes of new flowback and produced water generated, which adversely
impacts our revenues. Therefore, if these expenditures decline, our business is likely to be adversely affected.
The level of activity in the oil and natural gas exploration and production industry in the U.S. has been volatile. According to the Baker Hughes oil and gas drilling
rig count, the U.S. weekly aggregate rig count reached an all-time high of 4,530 rigs in December 1981 and a post-1942 low of 488 rigs in April 1999. In May
2016, aggregate rig count dropped to 404 rigs. The prices of crude oil and related products dropped substantially in the fourth quarter of 2014, have stayed low, and
have been negatively affected by a combination of factors, including weakening demand, increased worldwide production, the decision by the Organization of
Petroleum Exporting Countries to keep production levels unchanged and a strengthening in the U.S. dollar relative to most other currencies. If crude oil prices do
not rise, or take longer to recover than anticipated, 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. Water Services constitutes approximately 3%,
3% and 4% of our revenue for the years ended December 31, 2017, 2016 and 2015, respectively. The Bakken region of North Dakota generally requires higher oil
prices than the Permian Basin region 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 required payments on our outstanding debt.
17
Our customers’ willingness to engage in drilling and production of oil and natural gas depends largely upon prevailing industry conditions that are influenced by
numerous factors over which our management has no control, such as:
● the supply of and demand for oil and natural gas;
● the level of prices, and 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.
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 intend to make borrowings under our credit facility to fund the working capital needs of Pipeline Inspection, and
these borrowings will reduce the amount of credit we may use for other needs, such as working capital for our water disposal business, acquisitions and growth
projects. Borrowings also increase our aggregate interest expense, which indirectly 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 pipeline inspection and
integrity services customers delay in paying us, our working capital will decrease such that we would be required to make further borrowings under our revolving
credit facility; these delays in our customers' payments would also impact our ability to pay our minimum quarterly distributions.
18
Our ability to grow in the future is dependent on our ability to access external growth capital.
We will distribute substantially all of our available cash after expenses and prudent operating reserves to our unitholders. We expect that we will rely primarily upon external
financing sources, including borrowings under our credit facilities and the issuance of debt and equity securities, to fund growth capital expenditures. However, we may not be
able to obtain equity or debt financing on terms favorable to us, or at all. To the extent we are unable to efficiently finance growth externally, our cash distribution policy will
significantly impair our ability to grow. In addition, because we distribute all of our available cash, we may not grow as quickly as businesses that reinvest their available cash to
expand ongoing operations. Furthermore, Holdings is under no obligation to fund our growth. To the extent we issue additional units in connection with the financing of other
growth capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per-unit distribution
level. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of
borrowings or other debt by us to finance our growth strategy would result in interest expense, which in turn would affect the available cash that we have to distribute to our
unitholders.
Our existing and future debt levels may limit our flexibility to obtain financing and to pursue other business opportunities.
As of December 31, 2017, we had $136.9 million of indebtedness outstanding under our Credit Agreement. In March 2018, we obtained commitment letters from our lenders
for a new Credit Agreement for a total of $80.0 million, with an accordion feature of $20.0 million ($100.0 million total). 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.
19
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.
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 pipeline inspection and integrity management services or by ceasing to deliver salt water to our
salt water disposal facilities. Therefore, it is possible that our customers may decide not to use our inspection and integrity services or dispose of their salt water
through us. 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 68%, 80% and 71% of our consolidated revenue for the years ended December 31, 2017, 2016 and 2015,
respectively. Three customers accounted for more than 10% of revenues for each of the years ended December 31, 2017, 2016 and 2015; Enterprise Product
Partners, Pacific Gas and Electric Company, and Plains All America Pipeline in 2017, Enbridge Energy Partners, Pacific Gas and Electric Company, and Plains All
America Pipeline in 2016 and Enbridge Energy Partners, Enterprise Products Partners and Plains All America Pipeline in 2015. 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 integrity service activities and their water and
environmental treatment services. Some pipeline owners and operators currently inspect and perform integrity activities on their own pipeline systems using the
same techniques and technologies that we use, as well as others that we currently do not employ. In addition, many oil and natural gas producing companies own
and operate waste treatment, recovery and salt water disposal facilities that provide services that we could otherwise provide to them, and some producers recycle
salt water 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 salt water 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.
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 in the Pipeline Inspection, Integrity Services and Water Services segments. 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.
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 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.
20
Disruptions in the transportation services of trucking companies transporting salt water could adversely affect our results of operations and cash available for
distribution to our unitholders.
We primarily depend on third party trucking companies to transport salt water to our salt water disposal facilities. In recent years, certain states, including North
Dakota and Texas, and certain counties have increased enforcement of weight limits they impose on salt water disposal 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 Water 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 salt water to our salt water disposal facilities, which may either increase our operating costs or reduce the amount of salt water
transported to our salt water disposal 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 salt water 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 disposal 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 salt water treatment process. Volumes of residual oil recovered during the salt 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,
indrectly, our profitability.
Approximately 7%, 6% and 8% of our revenue for the years ended December 31, 2017, 2016 and 2015, respectively, in the Water Services segment was derived
from sales of residual oil recovered during the salt water treatment process. Our ability to recover sufficient volumes of residual oil is dependent upon the residual
oil content in the salt 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 salt water prior to delivering such salt 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 salt water we treat or the prices we realize on our sales of residual oil could materially and
adversely affect our profitability.
Our business may be difficult to evaluate because we have a limited period of historical financial and operating data.
Prior to June 26, 2013, our historical financial and operating data does not include the Pipeline Inspection segment. Prior to May 1, 2015, our historical financial
and operation data does not include the Integrity Services segment. As a result, we have provided only limited financial and operating data regarding the
consolidated businesses that we operate. The historical financial and operating results of our business may be materially different from our future financial and
operating results. Our future results will depend on our ability to efficiently manage our integrated operations and execute our business strategy. Our historical
financial performance should not be considered reliable indicators of our future performance.
In addition, we face challenges and uncertainties in financial and operational planning as a result of the limited access to historical data regarding volumes of
oilfield waste we have treated and related sales and pricing (our first facilities were opened during 2011). Our competitros in the salt water disposal industry do not
regularly release historical data related to their salt water disposal facilities. This limited data may make it more difficult for us and our investors to evaluate our
business and prospects and to forecast our future operating results.
We are vulnerable to the potential difficulties, expenses and uncertainties associated with rapid growth and expansion.
We grew rapidly since our inception in 2012 prior to the industry downturn, primarily through acquisitions. We believe that our future success depends on our and
our management's ability to manage growth, including increased demands and responsibilities. The following factors could present difficulties to us:
● organizational challenges common to large, expansive operations;
● administrative burdens;
● employee insurance;
21
● limitations with systems and technology;
● safety and training;
● ability to recruit, train and retain personnel and managers;
● ability to obtain permits for expanded operations;
● access to debt and equity capital on attractive terms; and
● long lead times associated with acquiring equipment and building any new facilities.
Our operating results could be adversely affected if we do not successfully manage these potential difficulties.
Our utilization of existing capacity, expansion of existing salt water disposal facilities and construction or purchase of new salt water disposal facilities may
not result in revenue increases and will be subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our operations
and financial condition.
A portion of our strategy to grow and increase distributions to unitholders is dependent on our ability to utilize available capacity at our existing facilities, expand
existing salt water disposal facilities and construct or purchase new salt water disposal facilities. The construction of a new salt water disposal facility or the
extension, renovation or expansion of an existing salt water disposal facility, such as by connecting such salt water disposal 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 salt water disposal 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 is seeking 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.
22
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.
23
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.
On December 24, 2013, we entered into a $120.0 million Credit Agreement, which we used to replace the TIR Entities’ existing credit facilities. On October 21,
2014, the Credit Agreement was amended to increase the aggregate availability under the Credit Agreement from $120.0 million to $200.0 million and extend its
maturity date to December 24, 2018. In March 2018, we obtained commitment letters from our lenders for a new Credit Agreement for $80.0 million, with a $20.0
million accordion feature ($100.0 million total). Our Credit Agreement limits our ability to, among other things:
● incur or guarantee additional debt;
● make certain investments and acquisitions;
● incur certain liens or permit them to exist;
● alter our line of business;
● enter into certain types of transactions with affiliates;
● merge or consolidate with another company; and
● transfer, sell or otherwise dispose of assets.
The Credit Agreement also contains certain covenants requiring us to maintain certain financial ratios. Our ability to meet those financial ratios and tests can be
affected by events beyond our control, and we cannot assure unitholders that it would meet those ratios and tests.
The provisions of our credit agreements, including the credit facility we recently negotiated (the "New Credit Agreement") that will replace the Credit Agreement
that expires December 24, 2018, 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, our New Credit
Agreemnt 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.
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Our business could be adversely impacted if we are unable to obtain or maintain the regulatory permits required to develop and operate our facilities and to
dispose of certain types of waste.
We own and operate salt water disposal facilities in North Dakota and Texas, each with its own regulatory program for addressing the handling, treatment,
recycling and disposal of salt water. 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 salt
water disposal 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.
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In the future we may face increased obligations relating to the closing of our salt water disposal facilities and we may be required to provide an increased level
of financial assurance to regulatory agencies to guaranty the appropriate closure activities occur for a salt water disposal facility.
Obtaining a permit to own or operate a salt water disposal 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 salt water disposal facilities. In particular, the North Dakota and Texas regulatory agencies require us
to post letters of credit in connection with the operation of our salt water disposal facilities. As we acquire additional salt water disposal facilities or expand our
existing salt water disposal facilities, these obligations will increase. Additionally, in the future, regulatory agencies may require us to increase the amount of our
closure bonds at existing salt water disposal facilities. We have accrued approximately $143 thousand on our balance sheet related to our contemplated future
closure obligations of our salt water disposal facilities as of December 31, 2017. 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 salt water disposal facilities and
additional environmental remediation requirements. Increased regulatory requirements regarding our existing or future salt water disposal 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 Texas and North Dakota, where we conduct our water and environmental services business, have either adopted or proposed laws and/or regulations to
require oil and natural gas operators to disclose chemical ingredients and water volumes 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 salt water delivered to our
salt water disposal facilities and correspondingly decrease our revenues attributed to salt water 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 in Texas are unable to obtain water to use in their operations from local sources, they may be incentivized to
recycle and reuse salt water instead of delivering such salt water to our Texas salt water disposal facilities (or in other states that adopt similar programs).
Similarly, mandatory recycling programs could reduce the amount of materials sent to us for treatment and disposal. Any such limits or mandates could adversely
affect our business and results of operations.
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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, including Texas, have promulgated rules or guidance in response to these concerns. In Texas, the Texas Railroad
Commission (“TRC”) published a final rule in October 2014 governing permitting or re-permitting of disposal wells that will require, among other things, the
submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure
maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the injected fluids are confined to
the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the TRC may deny,
modify, suspend or terminate the permit application or existing operating permit for that well. These new seismic permitting requirements applicable to disposal
wells impose more stringent permitting requirements and are likely to result in added costs to comply or, perhaps, may require alternative methods of disposing of
salt water and other fluids, which could delay production schedules and also result in increased costs. 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. 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 US District court for the District of Columbia in
December 2016. Under the decree, the EPA is required to propose, by no later than March 15, 2019, 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. If EPA proposes a rulemaking for revised E&P waste
regulations, the consent decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. If the exemption
covering E&P wastes is repealed or modified, or if the regulations interpreting the rules regarding the treatment or disposal of this type of waste were changed, our
operations could face significantly more stringent regulations, permitting requirements, and other restrictions, which could have a material adverse effect on our
business.
Under the terms of our amended and restated omnibus agreement, Holdings will indemnify us for certain potential claims, losses and expenses relating to
environmental matters and associated with the operation of the assets contributed to us and occurring before the closing date of our IPO. However, the liability of
Holdings for these indemnification obligations is subject to a $350,000 deductible. Moreover, our assets constitute a substantial portion of Holdings’ assets, and
Holdings has not agreed to maintain any cash reserve to fund any indemnification obligations under our amended and restated omnibus agreement. In addition,
changes in environmental laws occur frequently, and any such changes that result in more stringent and costly requirements would not be covered by the
environmental indemnity and could have a material adverse effect on our operations or financial position.
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We could incur significant costs in cleaning up contamination that occurs at our facilities.
Petroleum hydrocarbons, salt water, 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. The agreement provides for a four-year exit process beginning when it took effect in November 2016, which would 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.
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. For example, the lesser-prairie chicken was listed as threatened in March 2014, although a district court
recently vacated this decision.
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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.
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 can materially impact our business.
A failure by our employees to follow applicable procedures and guidelines or on-site accidents could have a material adverse effect on our business.
We require our employees to comply with various internal procedures and guidelines, including an environmental management program and worker health and
safety guidelines. The failure by our employees to comply with our internal environmental, health and safety guidelines could result in personal injuries, property
damage or non-compliance with applicable governmental laws and regulations, which may lead to fines, remediation obligations or third-party claims. Any such
fines, remediation obligations, third-party claims or losses could have a material adverse effect on our financial position, results of operations and cash flows. In
addition, on-site accidents can result in injury or death to our or other contractors’ employees or damage to our or other contractors’ equipment and facilities and
damage to other people, truck drivers, area residents and property. Any fines or third-party claims resulting from any such on-site accidents could have a material
adverse effect on our business.
In addition, while an inspector is performing pipeline inspection or integrity services for us, the inspector is considered 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.
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 third-party 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 as we continue to grow, if we experience high employee turnover
or labor shortage, or add inexperienced personnel. In addition, we could be subject to liability for damages as a result of such accidents and could incur penalties or
fines for violations of applicable safety laws and regulations.
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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 salt water disposal 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 salt water disposal 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, salt water 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 salt
water disposal facilities develop a leak (depending upon the terms of the insurance contracts at issue).
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 salt water disposal facilities are located exclusively in North Dakota and Texas. This concentration could disproportionately expose us to operational,
economic and regulatory risk in these areas. Additionally, after the sale of one of our Texas salt water disposal facilities in January 2018, our salt water disposal
facilities currently comprise nine 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 salt water disposal facilities, could have a significantly greater
impact on our financial condition, results of operations and cash flows than if we were more diversified.
Changes in the provincial royalty rates and drilling incentive programs in Canada could decrease the oil and gas exploration and pipeline activities in Canada,
which could adversely affect the demand for our pipeline inspection services.
Certain provincial governments collect royalties on the production from lands owned by the government of Canada. These fiscal royalty regimes are reviewed and
adjusted from time to time by the respective provincial governments for appropriateness and competitiveness. Any increase in the royalty rates assessed by, or any
decrease in the drilling incentive programs offered by, a provincial government could negatively affect the drilling activity and the need for pipelines and gathering
systems, which could adversely affect the demand for our pipeline inspection services.
Conservation measures and technological advances could reduce demand for oil and natural gas.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel
economy and energy generation devices could reduce demand for oil and natural gas and our customers’ drilling and production activities, and therefore the
amount of drilling and production waste provided to us for treatment and disposal. Management cannot predict the impact of the changing demand for oil and
natural gas services and products, and any major changes may have a material adverse effect on our business, financial condition, results of operations and cash
flows.
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New technology, including those involving recycling of salt water or the replacement of water in fracturing fluid, may hurt our competitive position.
The salt water disposal industry is subject to the introduction of new waste treatment and disposal techniques and services using new technologies including those
involving recycling of salt water, 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 salt water disposal 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 salt water disposal services could be materially impacted because these wells would not produce flowback water. In particular, our salt water disposal facilities
in West Texas could be negatively affected by these new technologies, as the drought conditions of West Texas make fracturing with materials other than water
attractive alternatives.
We may be unable to ensure that customers will continue to utilize our services or facilities and pay rates that generate acceptable margins for us.
We cannot ensure that customers will continue to pay rates that generate acceptable margins for us. Our margins for Water Services could decrease if the volume
of salt water 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 Integrity Services could decrease if the demand for our inspectors decrease, 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.
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 salt water disposal industry has experienced a high rate of employee turnover as a result of the volatility of the oilfield service industry and
the demanding nature of the work, and workers may choose to pursue employment in fields that offer a less demanding work environment. In addition, Pipeline
Inspection and Integrity 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 Integrity 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.
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Our ability to operate our business effectively could be impaired if affiliates of our general partner fail to attract and retain key management personnel.
We depend on the continuing efforts of our executive officers and other key management personnel, all of whom are employees of affiliates of our general partner.
Additionally, neither we, nor our subsidiaries, have employees. CEM LLC and its affiliates are responsible for providing the employees and other personnel
necessary to conduct our operations. All of the employees that conduct our business are employed by affiliates of our general partner, including our Chairman,
Chief Executive Officer and President, Peter C. Boylan III. 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 salt water disposal facilities for the processing of salt water, 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 salt water disposal 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 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 salt water 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.
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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 will be 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 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. We do not maintain specialized insurance for possible liability resulting from a cyber-
attack on our assets that may shut down all or part of our business. Third-party systems on which we rely could also suffer operational system failure. Any of these
occurrences could disrupt our business, result in potential liability or reputational damage or otherwise have an adverse effect on our financial results.
If we fail to develop or maintain an effective system of internal controls, we may not be able to report our financial results accurately or prevent fraud, which
would likely have a negative impact on the market price of our common units.
Effective internal controls are necessary for us to provide 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, and (except as described below) our independent registered public accounting firm
to attest to, the effectiveness of our internal controls over financial reporting. Any failure to develop, implement or maintain effective internal controls or to
improve our internal controls could harm our operating results or cause us to fail to meet our reporting obligations. Given the difficulties inherent in the design and
operation of internal controls over financial reporting, we can provide no assurance as to our, or our independent registered public accounting firm’s conclusions
about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404. Ineffective internal controls could
subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would
likely have a negative effect on the trading price of our common units.
We have recently implemented a new Enterprise Resource Planning (“ERP”) business solution to create a system of integrated applications to manage our
businesses and automate many functions related to financial reporting, human resources and other services. It is our intent through this ERP 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. Any failure(s) during this continued 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 ERP system implementation, we can provide no assurance as to our, or our independent registered public accounting
firm’s conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404. Ineffective
internal controls could subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our
business and would likely have a negative effect on the trading price of our common units.
33
We are required to disclose changes made in our internal control over financial reporting on a quarterly basis, and we are required to assess the effectiveness of our
controls annually. However, for as long as we are an “emerging growth company” under the Jumpstart Our Business Startups Act of 2012, or the JOBS Act, our
independent registered public accounting firm will not be required to attest to the effectiveness of our internal controls over financial reporting pursuant to Section
404. We 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. Even if we conclude that our internal
controls over financial reporting are effective, our independent registered public accounting firm may issue a report that is qualified if it is not satisfied with our
controls or the level at which our controls are documented, designed, operated or reviewed, or if it interprets the relevant requirements differently from us.
A sustained failure of our information technology systems could adversely affect our business.
An enterprise-wide information system has been developed and integrated into our operations. If our information technology systems are disrupted due to problems
with the integration of our information system or otherwise, we may face difficulties in generating timely and accurate financial information. Such a disruption to
our information technology systems could have an adverse effect on our financial condition, results of operations and cash available for distribution to our
unitholders. In addition, we may not realize the benefits we anticipate from the implementation of our enterprise-wide information system.
We have recently implemented a new ERP business solution to create a system of integrated applications to manage our businesses and automate many functions
related to financial reporting, human resources and other services. It is our intent through this ERP 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 ERP implementation process prove to be ineffective.
The seasonal nature of the oilfield service industry in Canada may negatively affect us and our customers.
In Canada, the level of activity in the oilfield services industry is influenced by seasonal weather patterns. As warm weather returns in the spring, the winter’s frost
comes out of the ground (commonly referred to as “spring break up”) rendering many secondary roads incapable of supporting heavy loads, and as a result, road
bans are implemented prohibiting heavy loads from being transported in certain areas. As a result, the movement of the heavy equipment required for drilling and
well servicing activities is restricted and the level of activity of our Canadian operations and the operations of our customers are consequently reduced.
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 the 2017 year-end, Holdings and its affiliates own an approximate 64.0% limited partner interest in us and own and control our general partner and appoint
all of the officers and directors of our general partner. Although our general partner has a duty to manage us in a manner that is in the best interests of our
partnership and our unitholders, the directors and officers of our general partner also have a fiduciary duty to manage our general partner in a manner that is in the
best interests of its owner, Holdings. Conflicts of interest may arise between Holdings and its affiliates, including our general partner, on the one hand, and us and
our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates, including
Holdings, over the interests of our common unitholders. These conflicts include, among others, the following situations:
● 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;
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● 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; 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 partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.
Our partnership agreement requires that we distribute all of our available cash to our unitholders. As a result, we expect to rely primarily upon external financing
sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures.
Therefore, to the extent we are unable to finance our growth externally, our cash distribution policy will significantly impair our ability to grow. In addition,
because we will distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing
operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those
additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership
agreement, and we do not anticipate there being limitations in our indebtedness, on our ability to issue additional units, including units ranking senior to our
common units as to distributions or in liquidation or that have special voting rights and other rights, and our unitholders will have no preemptive or other rights
(solely as a result of their status as unitholders) to purchase any such additional units. The incurrence of additional commercial borrowings or other debt to finance
our growth strategy would result in increased interest expense, which, in turn, may reduce the amount of cash that we have available to distribute to our
unitholders.
35
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 intends to limit its liability regarding our obligations.
Our general partner intends to limit its liability under contractual arrangements so that counterparties to such agreements have recourse only against our assets and
not against our general partner or its assets or any affiliate of our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or
other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is
not a breach of our general partner’s fiduciary duties, even if we could have obtained terms that are more favorable without the limitation on liability. In addition,
we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification
payments would reduce the amount of cash otherwise available for distribution to our unitholders.
36
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.”
Cost reimbursements and fees due to Holdings for services provided to us or on our behalf following the termination of our amended and restated omnibus
agreement could be substantial and will reduce our cash available for distribution to our unitholders.
Pursuant to our amended and restated omnibus agreement, prior to making any distributions to our unitholders, we will pay Holdings a quarterly administrative fee
of $1.0 million for the provision of certain general and administrative expenses. However, during the years ended December 31, 2017 and 2016, Holdings provided
sponsor support to the Partnership by waiving payment of the quarterly administrative fee for two quarters and four quarters ($2.0 million and $4.0 million),
respectively. Holdings received no consideration for this support. In the future, Holdings may require appropriate compensation if it provides any future additional
support. This fee is subject to increase by an amount equal to the producer price index (“PPI”) plus one percent or, with the concurrence of the conflicts committee,
in the event of an expansion of our operations, including through acquisitions or internal growth. The amount of this fee is below the amount we would expect to
reimburse the general partner for such services in the absence of the fee. In the event of termination of our amended and restated omnibus agreement, in lieu of the
quarterly fee, we will be required by our partnership agreement to reimburse Holdings and its affiliates for all costs and expenses that they incur on our behalf for
managing and controlling our business and operations, at which time we expect our payment for these services to increase. This increase may be substantial. Our
partnership agreement provides that Holdings will determine in good faith the expenses that are allocable to us. Furthermore, Holdings and its affiliates will
allocate other expenses related to our operations to us and may provide us other services for which we will be charged fees as determined by Holdings. Payments to
Holdings and its affiliates following the termination of our amended and restated omnibus agreement could be substantial and will reduce the amount of cash we
have available to distribute to unitholders.
Unitholders have very limited voting rights and, even if they are dissatisfied, they cannot remove our general partner without its consent.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to
influence management’s decisions regarding our business. For example, unlike holders of stock in a public corporation, unitholders will not have “say-on-pay”
advisory voting rights. Unitholders did not elect our general partner or the board of directors of our general partner and will have no right to elect our general
partner or the board of directors of our general partner on an annual or other continuing basis. The board of directors of our general partner is chosen by the
member of our general partner, which is a wholly-owned subsidiary of Holdings. Furthermore, if the unitholders are dissatisfied with the performance of our
general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which our common units will trade could be
diminished because of the absence or reduction of a takeover premium in the trading price.
The vote of the holders of at least 66 2/3% of all outstanding common units is required to remove our general partner. As of March 16, 2018, Holdings and its
affiliates own approximately 64.0% 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.
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Furthermore, unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20.0% or
more of any class of units then outstanding, other than our general partner, its affiliates, their transferees, and persons who acquired such units with the prior
approval of the board of directors of our general partner, cannot vote on any matter.
Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as
other provisions limiting the unitholders’ ability to influence the manner or direction of management.
Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the
unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of Holdings to transfer its membership interest in our general partner to
a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own
choices.
We may issue additional units without unitholder approval, which would dilute unitholders’ existing ownership interests.
At any time, we may issue an unlimited number of general partner interests or limited partner interests of any type without the approval of our unitholders and our
unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such general partner interests or limited partner
interests. Further, there are no limitations in our partnership agreement on our ability to issue equity securities that rank equal or senior to our common units as to
distributions or in liquidation or that have special voting rights and other rights. The issuance by us of additional common units or other equity securities of equal
or senior rank will have the following effects:
● our existing unitholders’ proportionate ownership interest in us will decrease;
● the amount of cash we have available to distribute on each unit may decrease;
● 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 March 16, 2018, Holdings and CEP-TIR together hold 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.
38
Affiliates of our general partner, including, but not limited to, Holdings, may compete with us, and neither our general partner nor its affiliates have any
obligation to present business opportunities to us.
Neither our partnership agreement nor our amended and restated omnibus agreement will prohibit Holdings or any other affiliates of our general partner from
owning assets or engaging in businesses that compete directly or indirectly with us. Under the terms of our partnership agreement, the doctrine of corporate
opportunity, or any analogous doctrine, will not apply to our general partner or any of its affiliates, including Holdings. Any such entity that becomes aware of a
potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to
us. Moreover, except for the obligations set forth in our amended and restated omnibus agreement, neither Holdings nor any of its affiliates have a contractual
obligation to offer us the opportunity to purchase additional assets from it, and we are unable to predict whether or when such an offer may be presented and acted
upon. As a result, competition from Holdings and other affiliates of our general partner could materially and adversely impact our results of operations and
distributable cash flow.
Our right of first offer on certain of Holdings’ assets is subject to risks and uncertainty, and ultimately we may not acquire any of those assets.
Our amended and restated omnibus agreement provides us with a right of first offer on certain assets owned by and ownership interests held by Holdings and its
subsidiaries that they decide to sell during the five-year period following the closing of our IPO. The consummation and timing of any acquisition by us of the
assets covered by our right to first offer will depend upon, among other things, our ability to reach an agreement with Holdings on price and other terms and our
ability to obtain financing on acceptable terms. Accordingly, we can provide no assurance whether, when or on what terms we will be able to successfully
consummate any future acquisitions pursuant to our right of first offer, and Holdings is under no obligation to accept any offer that we may choose to make or to
enter into any commercial agreements with us. For these or a variety of other reasons, we may decide not to exercise our right of first offer when we are permitted
to do so, and our decision will not be subject to unitholder approval. In addition, our right of first offer may be, upon a change of control of our general partner, or
by agreement between us and Holdings, terminated by Holdings at any time after it no longer controls our general partner.
Our general partner has a limited call right that may require our unitholders to sell their common units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 80.0% of our then-outstanding common units, our general partner will have the right, but not the obligation,
which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current
market price. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on unitholders’ investment.
Unitholders may also incur a tax liability upon a sale of their units. As of March 16, 2018, Holdings and its affiliates own approximately 64.0% of our common units and
therefore are not currently able to exercise the call right at that time.
Unitholders may have to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully distributed to them. Under Section 17-607 of the Delaware Revised Uniform
Limited Partnership Act, we may not make a distribution to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets.
Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew
at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Transferees of common units are
liable for the obligations of the transferor to make contributions to the partnership that are known to the transferee at the time of the transfer and for unknown
obligations if the liabilities could be determined from our partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that
are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
The price of our common units may fluctuate significantly, and unitholders could lose all or part of their investment.
As of December 31, 2017, there are only 4,285,263 publicly traded common units held by public unitholders. As of March 16, 2018, Holdings and CEP-TIR own 6,957,349
common units representing an aggregate 58.5% limited partner interest in us. We do not know how liquid our trading market might be. Additionally, the lack of liquidity may
result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common
units.
39
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 will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance
requirements.
The incentive distribution rights of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers
its incentive distribution rights to a third party, but retains its general partner interest, our general partner may not have the same incentive to grow our partnership
and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its incentive distribution rights. For example, a transfer of
incentive distribution rights by our general partner could reduce the likelihood that Holdings, which owns our general partner, will sell or contribute additional
assets to us, as Holdings would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.
A unitholder’s liability may not be limited if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership
that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other
states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of
the other states in which we do business. A unitholder could be liable for any and all of our obligations as if a unitholder were a general partner if a court or
government agency were to determine that unitholders’ right to act with other unitholders to remove or replace our general partner, to approve some amendments
to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.
40
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 a maximum of 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.
41
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. 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.
42
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 issued. It is unclear when such regulations
or other guidance will be issued.
43
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
After the sale of our Pecos, Texas salt water disposal facility on January 5, 2018, we had an aggregate in excess of 116,000 barrels of maximum daily disposal
capacity in the following salt water disposal facilities, all of which were built since June 2011 with most having new well bores, using completion techniques
consistent with current industry practices and utilizing well depths of at least 5,000 feet and injection intervals beginning at least 4,000 feet beneath the surface:
Location
Tioga, ND
Manning, ND
Grassy Butte, ND
New Town, ND (1)
Williston, ND (1)
Stanley, ND
Orla, TX (1)
Belfield, ND
Watford City, ND (1), (2)
Arnegard, ND (1)
County
Williams
Dunn
McKenzie
Mountrail
Williams
Mountrail
Reeves
Billings
McKenzie
McKenzie
In-service Date
Leased / Owned (3)
June 2011
December 2011
May 2012
June 2012
August 2012
September 2012
September 2012
October 2012
May 2013
August 2014
Owned
Owned
Leased
Leased
Owned
Owned
Owned
Leased
Leased
Leased
(1)
Currently receives piped water.
(2)
We own a 25.0% noncontrolling interest in this salt water disposal facility.
(3)
Some facilities are constructed on land that is leased under long-term arrangements.
44
We lease general office space at our corporate headquarters located at 5727 S. Lewis Avenue, Suite 300, Tulsa, Oklahoma 74105. The lease expires in November
of 2024 unless terminated earlier under certain circumstances specified in our lease. We lease office space in Houston, TX that is shared by our Pipeline Inspection
and Integrity Services segments, primarily for business development purposes. This lease expires in August of 2020. We also lease a small office in Walnut Creek,
CA that expires in March of 2020. We are party to a lease for office space in Tulsa, OK that we no longer use; this lease expires in June 2018. Our Integrity
Services segment owns an office building and staging and storage facility in Giddings, Texas.
ITEM 3.
LEGAL PROCEEDINGS
Fithian v. TIR LLC
On October 5, 2017, a former inspector for 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 alleges he was a non-exempt employee of TIR and that he and other potential class members were
not paid overtime in compliance with the FLSA. The plaintiff seeks to proceed as a collective action and to receive unpaid overtime and other monetary damages,
including attorney’s fees. TIR LLC, CEM TIR and Cypress Energy Partners – Texas, LLC deny the claims. On March 16, 2018, the parties filed a joint stipulation
of dismissal without prejudice in regards to TIR LLC and CEM TIR, 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. Upon such dismissal, no subsidiaries of the Partnership will be parties to the lawsuit.
Other
From time to time, we are subject to legal proceedings and claims that arise in the ordinary course of business. Like other organizations, our operations are subject
to extensive and rapidly changing federal and state environmental, health and safety and other laws and regulations governing air emissions, wastewater
discharges, and solid and hazardous waste management activities.
We are not a party to any other material pending or overtly threatened legal or governmental proceedings, other than proceedings and claims that arise in the
ordinary course and are incidental to our business.
ITEM 4. MINE SAFETY DISCLOSURES
Not Applicable.
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 16, 2018, the closing price for the common units was $6.08 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 will issue approximately 6,400 federal K-1s to unitholders of record for 2017.
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.
45
The high and low trading prices for our common units and distribution paid per unit by quarter were as follows:
Quarter Ended
High
Low
Distribution (a)
March 31, 2017
June 30, 2017
September 30, 2017
December 31, 2017
March 31, 2016
June 30, 2016
September 30, 2016
December 31, 2016
$
14.27 $
9.27
8.10
8.30
10.73
10.27
12.36
11.69
7.80 $
7.01
6.12
5.55
5.28
7.34
8.04
8.99
0.210000
0.210000
0.210000
0.210000
0.406413
0.406413
0.406413
0.406413
(a) Represents declared distributions associated with each respective quarter. Distributions were declared and paid within 45 days following the
close of each quarter in accordance with our cash distribution policy.
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 the Partnership’s intent to continue to make cash distributions to unitholders on a quarterly basis; however, 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 condition and other factors.
Definition of Available Cash
Available cash, for any quarter, consists of all cash and cash equivalents on hand at the end of that quarter:
●
less
, the amount of cash reserves established by our general partner at the date of determination of available cash for the quarter to:
● provide for the proper conduct of our business, which could include, but is not limited to, amounts reserved for capital expenditures,
working capital and operating expenses;
● comply with applicable law, any of our debt instruments or other agreements; or
● provide funds for distributions to our unitholders (including our general partner) for any one or more of the next four quarters;
●
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.
46
Distributions
Although it is the Partnership’s policy to continue to make cash distributions to 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 unitholders, pro rata, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that
quarter; and
● thereafter,
in the manner described in “ General
Partner
Interest
and
Incentive
Distribution
Rights
” below.
The preceding discussion is based on the assumptions that we do not issue additional classes of equity securities.
General Partner Interest and Incentive Distribution Rights
Incentive distribution rights (“IDRs”) represent a 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 unitholders
and the owner(s) of the IDRs in the following manner:
● first, 100.0% to all unitholders, pro rata, until each unitholder receives a total of $0.445625 per unit for that quarter (the “first target distribution”);
● second, 85.0% to all unitholders, pro rata, and 15.0% to the owner(s) of the IDRs, until each unitholder receives a total of $0.484375 per unit for that
quarter (the “second target distribution”);
● third, 75.0% to all unitholders, pro rata, and 25.0% to the owner(s) of the IDRs, until each unitholder receives a total of $0.581250 per unit for that
quarter (the “third target distribution”); and
● thereafter, 50.0% to all unitholders, pro rata, and 50.0% to 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, 2017.
Unregistered Sales of Equity Securities
None not previously reported on a current report on Form 8-K.
Issuer Purchases of Equity Securities
None.
47
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 Energy Partners, L.P. (the “Partnership”) is a Delaware limited partnership formed in 2013 to provide independent pipeline inspection and integrity
services to producers and pipeline companies and to provide salt water disposal and other water and environmental services to U.S. onshore oil and natural gas
producers and trucking companies. 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 the IPO, Holdings II, a wholly-owned subsidiary of Holdings, conveyed a 100% interest in CEP LLC. Prior to its contribution to the
Partnership, CEP LLC distributed to Holdings its interest in four subsidiaries. In addition to CEP LLC, affiliates of Holdings contributed 50.1% of their interest in
the TIR Entities (the Partnership’s Pipeline Inspection segment). The Partnership then subsequently conveyed this 50.1% interest to CEP LLC. We have recast
prior period financial data and information of Cypress Energy Partners, L.P. to reflect CEP LLC’s distribution of its four subsidiaries to Holdings, which were
originally acquired on December 31, 2012, and to reflect the conveyance of CEP LLC and the TIR Entities to the Partnership at the closing of our IPO, as if the
contribution of CEP LLC had occurred as of March 15, 2012 and the contribution of the TIR Entities had occurred as of June 26, 2013, the date affiliated members
of the Partnership acquired a controlling interest in the TIR Entities.
Effective February 1, 2015, the Partnership acquired the remaining 49.9% interest in the TIR Entities previously held by affiliates of Holdings. Effective May 1,
2015, the Partnership acquired a 51% interest in Brown, and a hydrostatic testing integrity services business creating our Integrity 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.
48
$
$
$
Income Statement Data
Revenues
Costs of services
Gross margin
General and administrative expense
Depreciation, amortization and accretion
Impairments
Operating income (loss)
Interest expense, net
Offering costs
Net income (loss)
Net income attributable to noncontrolling interests
Net income (loss) attributable to partners / controlling
interests
Balance Sheet Data - Period End
Total assets
Long-term debt
Total parent net investment and owners’ equity
Cash Flow Data
Cash flows from operating activities
Cash flows from investing activities
Cash flows from financing activities
Cash distributions per unit (subsequent to IPO) (c)
Capital expenditures
Other Financial Data
Adjusted EBITDA
Adjusted EBITDA attributable to limited partners /
controlling interests
Year Ended
December 31,
Year Ended
December 31,
Cypress Energy Partners, L.P.
Year Ended
December 31,
Year Ended
December 31,
2017
2016
2015 (a)
2014
Year Ended
December 31,
2013 (b)
Recast
(in
thousands,
except
cash
distributions
per
unit
and
operational
data)
286,342 $
252,739
33,603
21,055
4,443
3,598
5,077
7,335
—
(1,923)
(1,110)
297,997 $
262,517
35,480
21,853
4,861
10,530
(1,764)
6,559
—
(9,162)
(4,499)
371,191 $
326,261
44,930
23,795
5,427
6,645
9,063
5,656
—
4,091
599
404,418 $
355,355
49,063
21,321
6,345
32,546
(11,149)
3,208
446
(15,179)
4,973
249.133
213,690
35,443
12,467
5,164
4,131
13,681
4,000
1,376
4,355
22
(813)
(4,663)
3,492
(20,152)
4,333
163,203 $
—
9,985
167,512 $
135,699
19,388
190,882 $
139,129
40,702
187,524 $
75,282
100,428
238,441
72,851
135,547
8,138 $
(926)
(10,150)
0.84
3,345
24,819 $
(1,330)
(21,289)
1.63
1,376
26,921 $
(64,879)
42,501
1.63
1,857
13,016 $
(2,286)
(16,030)
1.51
2,286
$
16,640 $
19,794 $
24,663 $
28,499 $
18,692
22,238
23,147
18,190
7,154
5,779
13,636
—
4,329
23,110
23,079
Operational Data
Average number of inspectors (Pipeline Inspection
segment)
Average revenue per inspector per week
Average number of field personnel (Integrity Services
segment)
Average revenue per field personnel per week
Total barrels of salt water disposed (in thousands)
Average revenue per barrel
$
$
$
1,145
4,499 $
20
8,887 $
12,588
0.67 $
1,147
4,601 $
23
11,577 $
13,307
0.67 $
1,392
4,711 $
33
12,653
18,864
0.78 $
1,535
4,733 $
1,706
4,952
19,066
1.18 $
19,541
1.14
(a) Activity for the year ended December 31, 2015 includes operations of Brown (Integrity Services segment) from the May 1, 2015 acquisition date to the
end of the year.
(b) Activity for the year ended December 31, 2013 includes operations of the TIR Entities (Pipeline Inspection segment from the June 26, 2013 acquisition
date through the end of the year.
(c)
Includes February distributions related to the previous quarter ended December 31.
49
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 excluding cash interest paid, cash income
taxes paid and maintenance capital expenditures. 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;
● the viability of capital expenditure projects and the overall rates of return on alternative investment opportunities;
● our ability to incur and service debt and fund capital expenditures;
● the ability of our assets to generate cash sufficient to make debt payments and to make distributions; and
● our operating performance as compared to those of other companies in our industry without regard to the impact of financing methods and capital
structure.
We believe that the presentation of 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 exclude some, but not all, 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 in our
industry, 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
(loss)
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.
50
Reconciliation of Net Income (Loss) to Adjusted EBITDA and to Distributable Cash Flow
Net income (loss)
Add:
Interest expense
Depreciation, amortization and accretion
Impairments
Income tax expense
Non-cash allocated expenses
Equity based compensation
Less:
Gains on asset disposals, net
Foreign currency gains
Adjusted EBITDA
Adjusted EBITDA attributable to general partner
Adjusted EBITDA attributable to noncontrolling interests
Adjusted EBITDA attributable to limited partners/controlling interests
Less:
Cash interest paid, cash taxes paid, and maintenance capital expenditures
Distributable cash flow
2017
Years ended December 31,
2016
(in
thousands)
2015 (a)
$
(1,923) $
(9,162) $
4,091
7,335
5,545
3,598
596
1,750
1,059
588
732
16,640 $
(2,300)
248
18,692 $
6,559
5,788
10,530
1,195
3,798
1,086
—
—
19,794 $
(2,500)
56
22,238 $
5,656
6,004
6,645
452
648
1,167
—
—
24,663
—
1,516
23,147
8,674
10,018 $
6,717
15,521 $
5,940
17,207
$
$
$
(a) The Partnership acquired a 51% ownership interest in Brown effective May 1, 2015. Due to this, amounts for the year ended December 31, 2015 include
Brown from this date forward. The Partnership acquired the remainder of the TIR Entities February 1, 2015. Adjusted EBITDA attributable to noncontrolling
interests for the year ended December 31, 2015 includes the activity of the TIR Entities through its acquisition date.
Reconciliation of Net Income Attributable to Limited Partners to Adjusted EBITDA Attributable to Limited Partners and to Distributable Cash Flow
Net income attributable to limited partners
Add:
Interest expense attributable to limited partners
Depreciation, amortization and accretion attributable to limited partners
Impairments attributable to limited partners
Income tax expense attributable to limited partners
Equity based compensation attributable to limited partners
Less:
Gains on asset disposals, net
Foreign currency gains
Adjusted EBITDA attributable to limited partners
Less:
Cash interest paid, cash taxed paid, and maintenance capital expenditures
Distributable cash flow
2017
Years ended December 31,
2016
(in
thousands)
2015 (a)
$
3,237 $
1,635 $
4,140
7,335
4,978
2,823
580
1,059
588
732
18,692
6,556
5,373
6,409
1,179
1,086
—
—
22,238
5,290
5,522
6,645
383
1,167
—
—
23,147
$
8,674
10,018 $
6,717
15,521 $
5,940
17,207
(a) The Partnership acquired a 51% ownership interest in Brown effective May 1, 2015. Due to this, amounts for the year ended December 31, 2015 include
Brown from this date forward. The Partnership acquired the remainder of the TIR Entities February 1, 2015. Adjusted EBITDA attributable to limited partners
for the year ended December 31, 2015 includes the activity of the TIR Entities through its acquisition date.
51
Reconciliation of Net Cash Provided by Operating Activities to Adjusted EBITDA and to Distributable Cash Flow
Cash flows provided by operating activities
Changes in trade accounts receivable, net
Changes in prepaid expenses and other
Changes in accounts payable and accrued liabilities
Change in income taxes payable
Interest expense (excluding non-cash interest)
Income tax expense (excluding deferred tax benefit)
Other
Adjusted EBITDA
Adjusted EBITDA attributable to general partner
Adjusted EBITDA attributable to noncontrolling interests
Adjusted EBITDA attributable to limited partners / controlling interests
Less:
Cash interest paid, cash taxes paid, and maintenance capital expenditures
Distributable cash flow
2017
Years ended December 31,
2016
(in
thousands)
2015 (a)
$
$
$
$
8,253 $
3,406
1,332
(4,471)
365
6,741
957
57
16,640 $
(2,300)
248
18,692 $
24,819 $
(9,871)
(1,350)
(478)
(662)
5,989
1,219
128
19,794 $
(2,500)
56
22,238 $
26,921
(9,039)
(233)
1,222
196
5,109
484
3
24,663
—
1,516
23,147
8,674
10,018 $
6,717
15,521 $
5,940
17,207
(a) The Partnership acquired a 51% ownership interest in Brown effective May 1, 2015. Due to this, amounts for the year ended December 31, 2015 include
Brown from this date forward.
52
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.
Brown
(which
comprises
our
Integrity
Services
segment),
was
acquired
effective
May
1,
2015,
and
the
results
of
this
segment
have
been
included
in
our
financial
statements
for
periods
subsequent
to
that
date.
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 to provide services to the oil and gas industry. We provide independent pipeline
inspection and integrity services to various energy E&P and midstream companies and their vendors in our Pipeline Inspection and Integrity Services segments
throughout the United States and Canada. The Pipeline Inspection segment is comprised of the operations of the TIR Entities and the Integrity Service segment is
comprised of the operations of Brown. We also provide salt water disposal and other water and environmental services to U.S. onshore oil and natural gas
producers and trucking companies through our Water Services segment. We operate nine salt water disposal facilities, eight of which are in the Bakken Shale
region of the Williston Basin in North Dakota and one of which is in the Permian Basin in west Texas. We also have a management agreement in place to provide
staffing and management services to one 25%-owned salt water disposal 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
We generate revenue in the Pipeline Inspection segment primarily by providing inspection services on midstream pipelines, gathering systems, and distribution
systems, including data gathering and supervision of third-party construction, inspection, and maintenance and repair projects. Our results in this segment are
driven primarily by the number of inspectors that perform services for our customers and the fees that we charge for those services, which depend on the type and
number of inspectors used on a particular project, the nature of the project, and the duration of the project. The number of inspectors engaged on projects is driven
by the type of project, prevailing market rates, the age and condition of customers’ midstream pipelines, gathering systems, and distribution systems, and the legal
and regulatory requirements relating to the inspection and maintenance of those assets. We charge our customers on a per-inspector basis, including per diem
charges, mileage, and other reimbursement items.
We generate revenue in our Integrity Services segment primarily by providing hydrostatic testing services to major natural gas and petroleum companies and
pipeline construction companies. We perform these services on newly-constructed and existing natural gas and petroleum pipelines. We generally charge our
customers in this segment on a fixed-bid basis. Bid prices vary based on the size and length of the pipeline being inspected, 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, 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.
53
We generate revenue in the Water Services segment primarily by treating flowback and produced water and injecting the salt water into our salt water disposal
facilities. Our Water Services results are driven primarily by the volumes of produced water and flowback water we receive and the fees we charge for our
services. These fees are charged on a per-barrel basis under contracts that are short-term in nature and vary based on the quantity and type of salt water disposed,
competitive dynamics, and operating costs. The volumes of salt water disposed at our salt water disposal facilities are driven by water volumes generated from
existing oil and natural gas wells during their useful lives and development drilling and production volumes from the wells located near our facilities. Producers’
willingness to engage in new drilling is determined by a number of factors, the most important of which are the prevailing and projected prices of oil, natural gas,
and NGLs, the cost to drill and operate a well, the availability and cost of capital, and environmental and governmental regulations. We generally expect the level
of drilling to positively correlate with long-term trends in prices of oil, natural gas, and NGLs. Revenues in this segment are recognized when the service is
performed and collectability of fees is reasonably assured. We also generate revenue for managing one salt water disposal facility.
In addition, for minimal marginal cost, we generate revenue by selling residual oil we recover from the flowback and produced water. Our ability to recover
residual oil is dependent upon the residual oil content in the salt 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 usually lower than our recovery during the summer season in North Dakota. Additionally, residual oil content will decrease if, among
other things, producers begin recovering higher levels of residual oil in salt water prior to delivering such salt water to us for treatment. For more information on
our revenue by country, see “Note 2 – Basis of Presentation and Significant Accounting Policies” in the audited financial statements included in “Item 8 –
Financial Statements and Supplementary Data.”
How We Evaluate Our Operations
Our management uses a variety of financial and operating metrics to analyze our performance. We view these metrics as significant factors in assessing our
operating results and profitability and intend to review these measurements frequently for consistency and trend analysis. These metrics include:
● inspector headcount in Pipeline Inspection;
● field personnel headcount and utilization in Integrity Services;
● salt water disposal and residual oil volumes in Water Services;
● operating expenses;
● segment gross margin;
● safety metrics;
● Adjusted EBITDA;
● maintenance and expansion capital expenditures; and
● distributable cash flow.
Inspector Headcount
The amount of revenue we generate in Pipeline Inspection 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 Integrity Services 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.
Salt Water Disposal and Residual Oil Volumes
The amount of revenue we generate in the Water 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. Our revenues from produced water, flowback water, and residual oil sales are generated pursuant to contracts that are short-
term in nature. Revenues in this segment are recognized when the service is performed and collectability of fee is reasonably assured. The volumes of salt water
disposed at our salt water disposal facilities are driven by water volumes generated from existing oil and natural gas wells during their useful lives and
development drilling and production volumes from the wells located near our facilities. Producers’ willingness to engage in new drilling is determined by a
number of factors, the most important of which are the prevailing and projected prices of oil, natural gas, and NGLs, the cost to drill and operate a well, the
availability and cost of capital and environmental and governmental regulations. We generally expect the level of drilling to positively correlate with long-term
trends in prices of oil, natural gas, and NGLs.
54
Approximately 7%, 6%, and 8% of our Water Services segment revenue for the years ended December 31, 2017, 2016 and 2015, respectively, was derived from
sales of residual oil recovered during the salt water treatment process. Our ability to recover residual oil is dependent upon the oil content in the salt 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 in North Dakota. Additionally, residual oil
content will decrease if, among other things, producers begin recovering higher levels of residual oil in salt water prior to delivering such salt water to us for
treatment.
Operating Expenses
The primary components of our operating expenses that we evaluate include costs of services, general and administrative, and depreciation and amortization.
Costs
of
services
. Employee-or-contractor-related costs and per diem expenses are the primary costs of services components in Pipeline Inspection and Integrity
Services. These expenses fluctuate from period to period based on the number, type, and location of projects on which we are engaged at any given time. We seek
to maximize the profitability of our operations in part by minimizing, to the extent appropriate, expenses directly tied to operating and maintaining our assets.
Repair and maintenance costs, employee-related costs, residual oil disposal costs, lease expenses, and utility expenses are the primary cost of services components
in Water Services. These expenses generally remain relatively stable across broad ranges of salt water disposal volumes but can fluctuate from period to period
depending on the mix of activities performed during that period and the timing of these expenses.
General
and
administrative.
General and administrative expenses include management and overhead payroll, general office expenses, management fees, legal
fees, and other expenses.
Under our amended and restated omnibus agreement, Holdings charges us an annual administrative fee of $4.0 million (payable in equal quarterly installments) for
the provision of certain administrative services. This fee is subject to an increase by an annual amount equal to PPI plus one percent or, with the concurrence of the
conflicts committee, in the event of an expansion of our operations, including through acquisitions or internal growth. To the extent that Holdings incurs overhead
expenses in excess of our annual administrative fee that are attributable to the operations of the Partnership, these expenses are reported in our Consolidated
Statements of Operations within general
and
administrative
expense
and as an equity contribution
attributable
to
our
General
Partner
in our Consolidated
Statement of Owners’ Equity.
Included in this administrative fee are general and administrative expenses attributable to operating as a publicly traded partnership, such as expenses associated
with annual and quarterly SEC reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance; listing on the New York
Stock Exchange; independent registered public accounting firm fees; certain legal fees; investor relations, registrar, and transfer agent fees; director and officer
liability insurance costs; and director compensation. Our partnership agreement provides that Holdings will determine and allocate expenses related to our
operations and may provide us other services for which we will be charged fees as determined in good faith. Payments to Holdings and its affiliates following the
termination of our amended and restated omnibus agreement could be substantial and will reduce the amount of cash we have available to distribute to unitholders.
During the years ended December 31, 2017 and 2016, Holdings provided sponsor support to the Partnership by waiving certain payments of the quarterly
administrative fee (in 2017, Holdings waived the fee for two of the quarters; in 2016, Holdings waived the fee for all four quarters). We reported the amount of the
waived fees within general
and
administrative
expense
in our Consolidated Statement of Operations and as an equity contribution in our Consolidated Statement of
Owners’ Equity.
Depreciation,
amortization
and
accretion.
Depreciation, amortization and accretion expense primarily consists of our estimate of the decrease in value of our
capitalized tangible and intangible assets as a result of using the assets over time. 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 facilities, wells, and equipment of our Water Services segment constituted approximately 44% and
60% of the net book value of our fixed assets as of December 31, 2017 and 2016, respectively, and generally have useful lives of 5 to 15 years.
55
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 net cash interest paid, cash taxes paid, and maintenance capital expenditures, 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 Pipeline
Inspection 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;
● the viability of capital expenditure projects and the overall rates of return on alternative investment opportunities;
● our ability to incur and service debt and fund capital expenditures; and
● the viability of acquisitions and other capital expenditure projects and the rates of return on various investment opportunities.
Adjusted EBITDA and distributable cash flow are not financial measures presented in accordance with GAAP. We believe that the presentation of these non-
GAAP financial measures provides useful information to investors in assessing our financial condition and results of operations. Net income is the GAAP measure
most directly comparable to Adjusted EBITDA. The GAAP measure most directly comparable to distributable cash flow is net cash provided by operating
activities. Our non-GAAP financial measures should not be considered as alternatives to the most directly comparable GAAP financial 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
.”
Outlook
Refinancing
Our current $200 million credit facility matures in December 2018 and had approximately $136.9 million outstanding at December 31, 2017. In the fall of 2017,
we began working with our agent on the terms of a new credit facility, anticipating that we would close the new facility prior to the end of 2017. In December
2017, we learned that some of our lenders were not comfortable with the proposed terms and conditions and they requested the agent for various modifications to
the proposed terms. In February, we agreed upon a new revised term sheet and in March 2018, we successfully negotiated commitments for a new revolving credit
facility with our existing bank group with a term that extends three years after closing, consistent with the strategy outlined in our Form 10-Q for the three months
ended September 30, 2017.
To reduce leverage, we negotiated the sale of our Pecos, Texas salt water disposal facility and utilized the $4.0 million of proceeds to repay principal on our credit
facility in January, 2018. We were also successful in retaining a perpetual royalty on that facility. We plan to use approximately $7.0 million of our cash on hand
to repay an additional amount of principal at the time we close on the new credit facility, sometime in the second quarter, while maintaining sufficient liquidity to
support our operations. The new credit facility will have a maximum capacity of $80.0 million, with a $20.0 million accordion feature (for a total of $100.0
million) with additional banks still evaluating the proposed facility. Under the new credit facility, we will be able to borrow up to 3.75 times our trailing twelve-
month adjusted EBITDA (“TTM EBITDA”) (as adjusted EBITDA is defined in the credit agreement, which may differ from how adjusted EBITDA is defined
elsewhere in this annual report) for senior debt. Additionally, we may incur additional indebtedness other than the new credit facility, provided the pro forma
senior secured leverage ratio may not exceed 3.25 times TTM EBITDA and the total leverage ratio may not exceed 4.75 times TTM EBITDA. As part of the
refinancing, Holdings agreed to waive the omnibus fee to support us in the event leverage exceeds 3.75 times trailing twelve-month adjusted EBITDA during the
term of the facility. The new credit facility will have customary covenants, including but not limited to a maximum senior leverage ratio of 4.0 times adjusted
EBITDA, or 3.25 times senior secured leverage if additional debt not to exceed 1.5 times is incurred, and a minimum interest coverage ratio of 3.0 times adjusted
EBITDA. The new facility will no longer have a required borrowing base calculation and borrowings under the new agreement will 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 or (ii) a LIBOR rate plus a margin of 2.5% to 4.0% per annum. The
facility will also include a 50 basis point non-use fee consistent with the current facility, and no amortization will be required during the term which extends three
years after closing. We have received commitment letters from banks for the full amount of the facility, and these commitment letters will remain in effect through
May 31, 2018. We also have another bank considering joining the facility. We believe this new facility will support our current business requirements until we
find an attractive acquisition opportunity, at which time we will seek to expand the current revolving credit facility or refinance it to accommodate the transaction,
which may include the support of Holdings or its afffiliates. We expect to borrow approximately $76.1 million on the new credit facility at closing, a reduction of
approximately 44% from our debt outstanding at December 31, 2017. Our net debt (effectively outstanding debt less outstanding cash balance) at closing will be
approximately 48% lower and approximately 3.0 times TTM EBITDA.
To successfully obtain commitments to refinance our existing credit facility, our lenders required that we significantly de-leverage the Partnership, given general
macro sentiment toward the industry. To ensure the successful refinancing and prior to filing this report, we received a commitment from an affiliate of Holdings
to invest up to $50.0 million of preferred equity (the "PIPE"). The conflicts committee of our board of directors and their legal and financial advisors negotiated the
final terms of the PIPE to ensure fairness to the Partnership. We believe the terms of the PIPE obtained from the affiliate of Holdings are substantially more
attractive than we could have obtained from third parties. The terms of the PIPE include standard and customary provisions frequently found in many recently-
completed PIPE financings in our industry. The proposed PIPE does not include any warrants, which are frequently required by third-party institutional investors,
thereby benefitting us. Key terms include a conversion premium on the PIPE that is 15% greater than our common unit trailing closing price at the time of
issuance. The holder of the preferred units will be entitled to receive quarterly distributions that represent an annual return of 9.5% on the investment. The
Partnership was able to negotiate very favorable terms affording flexibility on the amount paid in cash versus amounts paid-in-kind (“PIK”). We are only required
to pay 2.5% in cash and will have the option to PIK the remaining 7.0% for a period of time. Additionally, the holder will not be able to convert until after the third
anniversary. 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. We were not required to pay customary origination fees associated with this PIPE investment, saving us a substantial amount of cost. Finally, another
important benefit we have negotiated is the ability to redeem the PIPE after the third anniversary of the closing date on favorable terms.
These cash payments (from cash on hand and from the sale of Pecos as outlined above), combined with the up to $50.0 million of proceeds from the issuance of the
PIPE, should allow us to reduce our outstanding debt balance from approximately $136.9 million to approximately $76.1 million (or 44%). The significant
decrease in leverage resulting from the refinancing should significantly reduce our interest expense and improve our distributable cash flow and our coverage ratio.
In addition, our existing credit facility has significant unused capacity on which we have paid non-use fees. Such non-use fees will be lower under the new credit
facility.
Before closing on the PIPE, we will also fully check the market to ensure that no better alternatives are available. To accomplish this, we have retained a financial
advisor to determine if more favorable PIPE terms can be obtained from an independent third party and to explore strategic alternatives to determine if any more
attractive opportunities may exist for the Partnership. The affiliate of Holdings providing the required PIPE commitment will not require any compensation if the
Partnership is able to obtain better terms from an unaffiliated third party.
We plan to continue our focus on improving our operating results through a combination of 1) enhanced business development efforts in our Pipeline Inspection
and Integrity Services segments with our continued focus on higher-margin services; 2) the rebuilding of our Orla, Texas facility that was struck by lightning in
January 2017; 3) the rebuilding of our Grassy Butte, North Dakota facility that was struck by lightning in July 2017; and 4) continuing to expand our North Dakota
business through the pursuit of new pipeline gathering opportunities, and to generally take advantage of the increased activity as a result of increased rig count,
commodity prices, and renewed interest in the Williston Basin.
Holdings has been very supportive of the Partnership during the recent economic downturn and has provided sponsor support of $6.3 million during the year ended
December 31, 2016 and $4.1 million during the year ended December 31, 2017 for no consideration. We believe that the owners of Holdings, who collectively own
approximately 64.0% of our common units, remain fully aligned with our minority unitholders and have the financial wherewithal and the incentive to continue to
support us to help us maintain compliance with the financial ratio covenants through the maturity date of the new credit agreement. This alignment of interest is
further demonstrated by an affiliate of Holdings’ commitment to offer a below-market PIPE to benefit us and complete the refinancing of our credit facility.
56
Overall
For our Pipeline Inspection and Integrity Services business segments, revenues, margins, and margin percentages were higher in the second half of 2017 than they
were in the first half of 2017. This is generally consistent with the seasonality inherent in our business, in which the third and fourth quarters of each year are
generally the strongest quarters of the annual business cycle, due to weather patterns and our clients’ budgeting cycles. We believe that these segments will have
many opportunities over the next several years, as many projects previously delayed have recently been approved. We have also invested in organic growth and
have started two new business units this year. The newest business unit offers mechanical integrity services, which is a new line of inspection and integrity support.
This new line of business has already been awarded several new projects from investment-grade energy companies and exceeded our internal forecast for the first
six months of the business.
For our Pipeline Inspection segment, headcount was higher in the second half of 2017 than it was in the first half of 2017, despite the loss in the second quarter of
2017 of 200 inspectors who were performing work for the largest customer of our Canadian operations (this customer completed a bidding process and awarded
new contracts at rates that were lower than we were willing to accept). We have continued to focus on our nondestructive examination, staking, integrity support,
and mechanical integrity services, all of which generate higher margins than our core inspection business. The revenues of these lines of business were higher in
the fourth quarter 2017 than in any previous quarter.
Revenues from our 51%-owned Integrity Services Segment (currently comprised entirely of our controlling interest in Brown Integrity, LLC (“Brown”), a
hydrostatic testing provider) were higher in the fourth quarter of 2017 than they were in the third quarter of 2017, as our utilization rate significantly improved and
our backlog increased. We continue to bid on a substantial amount of upcoming work and remain focused on winning more of these bids. We ended 2017 with a
backlog of approximately $2.8 million, which was more than ten times larger than the backlog at December 31, 2016. We are also changing our business strategy
to focus more on maintenance and integrity work, which tends to occur when scheduled, as opposed to new construction work, which often slides with delays that
frequently occur on new construction projects. We are also evaluating whether to open field offices in the Permian Basin and in Houston to better serve those
markets and reduce our mobilization costs.
Revenues of our Water and Environmental Services segment were 15.4% higher in fourth quarter 2017 than in the third quarter 2017 despite some facilities that
have not yet reopened following lightning strikes. Our Orla, Texas facility in Reeves County in the Delaware basin should reopen for regular business in early
second quarter of 2018 (since a January 2017 lightning strike and fire, we have been operating this facility using temporary equipment). In January 2018, we
completed two pipelines that connect large multi-well pads into one of our facilities in the Bakken for a large public energy company. We expect to rebuild our
Grassy Butte facility, which was struck by lightning in July 2017, and we expect to reopen it in the second quarter of 2018. The Williston basin has seen a dramatic
increase in activity from the lows in the second quarter 2016, with substantial new investment from private equity investors and public E&P companies. The
completion of the DAPL pipeline and higher oil prices have significantly improved the economics in the Williston basin for all producers.
Despite the low commodity prices of recent years, we maintained positive operating cash flows during the year ended December 31, 2017, 2016 and 2015. We
continue to believe the long term increasing demand for inspection and integrity services and water solutions remains solid despite our relatively slow pace of the
recovery from the multi-year downturn. We are less correlated to the drilling rig count as many other service companies.
We continue to search for attractive acquisition opportunities. In 2017 our team was busy, as we considered over 25 potential acquisition opportunities and we still
have a few under consideration. In January 2018, as part of our ongoing due diligence, we discovered some significant concerns on a large transaction under letter
of intent that led us to terminate discussions. Future areas of focus continue to be inspection, integrity, traditional midstream opportunities, chemicals, and
logistics. Our sponsor and its affiliates remain willing to deploy capital to assist us in acquiring attractive assets that may be larger than what we can currently
acquire independently, with plans to offer those assets to us as drop-down opportunities. We remain focused on a disciplined and conservative approach to
evaluating acquisition opportunities.
Pipeline Inspection
Demand is once again growing for our pipeline inspection and integrity services, as we operate in a very large market with well over 1,000 customer prospects that
we do not currently serve who require federally and/or state-mandated inspection and integrity services. During 2017 we added 30 new customers and successfully
started two new lines of service.
A Stifel energy research analyst recently published the following multi-year pipeline industry update that is summarized below:
●
●
2018 Forecast: Tracking $38.5 billion of pipeline/midstream infrastructure spending proposed for 2018. On a probability-weighted basis, forecasted all-
in potential 2018 spending of $33.1 billion, or a 30.2% year-to-year increase. If only highest confidence Tier 1 projects were to move forward, would
produce 13.7% year-to-year growth. Layering in moderate confidence Tier 2 projects, the growth forecast rises to 25.3%.
2019 and beyond: Anticipated 2019 spending will reflect growth over 2018 levels. Given that the database only includes announced, named pipeline
projects, the tracker currently reflects a decline in proposed activity in 2019 and 2020. This is a function of the timing of project announcements, and is
expected to rise through 2018. Virtually every industry contact/source along the supply chain, including equipment providers, engineers and construction
sources, are suggesting that 2019 could post growth off of a record 2018.
● Bidding and award activity is accelerating following delays related to the lack of a quorum at FERC. Recall that the Federal Energy Regulatory
Commission (“FERC”) lacked a quorum for roughly 6 months, delaying large project approval activity in the first half of 2017. The quorum was re-
established on August 10, with the swearing-in of Robert Powelson. At the time the quorum was re-established, it was estimated that approximately $14
billion of pipeline projects had been backlogged. FERC is beginning to take action on the queue, with NEXUS, Atlantic Coast, and the Mountain Valley
Pipelines approved in October.
● Tracking nearly $30 billion in projects that could be awarded over the next approximately 12 months, and believe that at least $4.5 billion worth
of projects is currently out to bid. This bodes well for additional large pipeline project awards for contractors in late 2017/early 2018. Developers are
concerned about procuring quality construction partners, given that the industry is likely to reach full utilization in 2018. This generally bodes well for
contractor pricing, terms, and conditions.
Our continued focus remains on both maintenance and integrity work on existing pipelines as well as work on new projects. The majority of our existing and
potential customers are once again investing in their businesses following a difficult economic downturn. We continue to focus on new lines of business to serve
our existing customers including mechanical integrity and pipeline decontamination services. The majority of our clients are public, investment-grade 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 with regulatory requirements, and the aging pipeline infrastructure, that the Pipeline Inspection business is more insulated from changes in
commodity prices in the near term than has been the case in the past. However, a prolonged depression in oil and natural gas prices could lead to a downturn in
demand for our services as was the case in recent years.
Integrity Services
Brown, our 51% owned hydrotesting business unit, has seen a material improvement in its utilization rate and backlog. Brown had a difficult year in 2016, which
forced us to implement aggressive measures to manage and reduce its cost structure. We believe our new strategy is working and we plan to continue to focus on
the potential synergies that may develop between this segment and other current customers of the Partnership, as well as the growth and nurturing of Brown’s
historical, ongoing business. Brown operated in only 13 states during 2016, compared with 40 states that the TIR Entities (through our Pipeline Inspection
segment) operated in throughout 2017. In 2017, Brown worked in 15 states and has successfully obtained new business from TIR relationships. Brown’s revenues
and EBITDA improved in the fourth quarter along with its backlog. Brown continues to enjoy an excellent reputation in the industry and has a substantial amount
of new work that it is currently bidding to win.
57
Water Services
During the fourth quarter of 2017, we grew volumes in our Water Services segment, by 15.4% over the prior quarter despite two of our facilities having been hit by
lightning earlier in the year. Our average revenue per barrel for the year held steady at $0.67 (inclusive of water, oil reclamation, and management fees). Drilling
activity has improved dramatically following the downturn and the lows that occurred in May 2016. Baker Hughes North America Rotary Rig Count, as of the end
of February 9, 2018 had the following information:
●
Total US rig count of 975, including 437 in the Permian basin and 50 in the Williston basin/Bakken
● Rigs have increased 141%, or 571 rigs, from the May 2016 trough of 404; and
● Rigs still remain down 50%, or 956 rigs, from September 2014 peak of 1,931.
Crude oil prices have also increased, and in early February 2018 NYMEX Near Month crude exceeded $60 per barrel. The decline in the market price of crude oil
that began in the second half of 2014 has had an adverse impact on our volumes and revenues over the last three years. The resultant slowdown in exploration and
production activity led to lower new drilling activity, volumes, and commodity prices from sales of crude oil we recover from the water we process. In addition,
many of our E&P customers requested pricing concessions to help them cope with the lower commodity prices and the market became over supplied relative to
activity levels. In the majority of the basins in the country, new salt water disposal facilities were developed to support previous rig counts and activity levels prior
to the sharp contraction in activity and commodity prices. These events have led to excess salt water disposal facility supply relative to current demand in many
locations, including the Bakken and the Permian that, in turn, has led to aggressive pricing.
We have always focused on produced water and piped water whenever possible instead of trucked flowback water and therefore, we believe we have been less
impacted than many of our competitors. During the fourth quarter of 2017, 91% of our volumes were produced water and 41% of our water was delivered via
pipelines. We continue to focus on piped water opportunities to secure additional long-term volumes of produced water for the life of the oil and gas wells’
production.
We continue to actively pursue the right acquisition opportunities with the same discipline that protected the Partnership during a heated market in 2014 and 2013
that drove up valuations to unsustainable levels leading to many bankruptcies and restructurings. We also continue to evaluate and compete for some interesting
opportunities for pipelines and new salt water disposal facilities directly with E&P companies seeking to monetize their midstream assets or minimize their
spending on infrastructure required to support their production.
In January 2017, one of our facilities was struck by lightning. The downhole facilities were not damaged and we had insurance covering the surface facilities with a
reasonable deductible. We do not carry business interruption insurance given its costs, waiting periods, and coverages. Within two weeks, the facility reopened
with temporary surface facilities. We have begun the redevelopment process with insurance proceeds and plan to have the Delaware basin Orla, Texas facility re-
opened in the second quarter of 2018. In the interim, we continue to take both piped and trucked water with temporary facilities. In July 2017, we experienced
another lightning strike at our Grassy Butte salt water disposal facility that initiated a fire that effectively destroyed the surface storage equipment at the facility. It
did not damage our pumps, electrical, housing, office, or downhole facilities.
In January 2018, we sold our subsidiary that owns a salt water disposal facility in Pecos, Texas to an unrelated party. We received $4.0 million of cash proceeds
and a perpetual royalty interest in the future revenues of the facility (although the amount of the cash proceeds is subject to adjustment upon final calculation of
certain working capital amounts).
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 would have been reported under different conditions, or if different assumptions had been used. The
following discussions of critical accounting estimates, including any related discussion of contingencies, address all important accounting areas where the nature of
accounting estimates or assumptions could be material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the
susceptibility of such matters to change.
58
As a company with less than $1.0 billion in revenue during its last fiscal year, we qualify as an “emerging growth company” as defined in the Jumpstart Our
Business Startups Act of 2012, or the JOBS Act. As an emerging growth company, we have elected to opt out of the exemption that allows emerging growth
companies to extend the transition period for complying with new or revised financial accounting standards.
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 Water Services segment, we evaluate property and equipment for impairment at the salt water disposal 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 the current and future economic
environment in which the asset is operated. Significant judgments and assumptions in these assessments include estimates of water disposal rates, disposal
volumes, expected capital costs, oil and gas drilling and producing volumes in the markets served, risks associated with the different zones into which salt water is
disposed, and our estimate of an applicable discount rate commensurate with the risk of the underlying cash flow estimates.
The Water Services segment has experienced increased competition in the regions in which we operate, which has resulted in declining volumes and increased
pricing pressure. Steady and continued declines in oil prices until the middle of 2017 have intensified competitive pressures and had a direct impact on our
revenues. Many of our customers have announced significantly reduced drilling programs in the Bakken in particular; however, the number of drilling rigs
operating in the United States, including the Bakken, began to increase in the last half of 2017 and have continued to increase in the beginning of 2018. The decline
in drilling has impacted the amount of flowback and produced water that we process and dispose, and has negatively impacted our pricing as our customers look
for ways to reduce costs. In addition, as we process lower water volumes, in particular flowback water volumes directly attributable to drilling, we recover less
skim oil.
During the years ended December 31, 2017, 2016 and 2015, we identified impairment indicators at certain of our salt water disposal facilities and reviewed the
associated property and equipment for impairment. We recognized impairment charges of $0.7 million, $2.1 million, and $6.6 million during the years ended
December 31, 2017, 2016 and 2015, respectively, for assets that were determined to be impaired, primarily driven by the dramatic decline in oil prices from over
$100.00 / barrel to as low as $26.00 / barrel during the three-year downturn. 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 identifiable intangible assets of $25.5 million and $29.6 million at December 31, 2017 and 2016, 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 the first quarter of 2017, the largest customer of the Canadian subsidiary in our Pipeline Inspection segment completed a bid process and selected different
service providers for its inspection projects. In consideration of the loss of this contract, 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. We continue to perform inspection and integrity work for customers in Canada.
59
Goodwill
At December 31, 2017 and 2016, we had $53.4 million (plus another $2.0 million of goodwill included in assets
held
for
sale
) and $56.9 million of goodwill,
respectively. 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, Integrity Services, and Water 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 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
Water Services reporting units are concentrated in two basins, and changes in oil and gas production in these two basins 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 near future.
Integrity Services Segment
In the Integrity Services segment, we experienced declining revenues in 2016 due to the decline in the overall energy economy, including decreased new
infrastructure construction, postponement of inspection and integrity activity by our E&P customers, and reduced revenues and margins on completed contracts
due to increased competition, among other factors. Given these indicators of impairment, we performed an impairment assessment in the second quarter of 2016 of
the $10.0 million of goodwill that was attributable to our Integrity Services segment. We estimated the fair value of the reporting unit 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. To estimate the fair value of the reporting unit and the implied
fair value of goodwill under a hypothetical acquisition of the reporting unit, we assumed a tax structure wherein a buyer would obtain a step-up in the tax basis of
the net assets acquired. Significant assumptions used in valuing the reporting unit included revenue growth rates ranging from 2% to 5% annually and a discount
rate of 17.5%. In our assessment, the carrying value of the reporting unit, including goodwill, exceeded its estimated fair value. We then determined through our
hypothetical acquisition analysis that the fair value of goodwill was impaired. As a result, we recorded an impairment loss of $8.4 million and reduced the carrying
value of goodwill to $1.6 million in the second quarter of 2016.
In the first quarter of 2017, we recorded an impairment to the remaining $1.6 million carrying value of the goodwill of the Integrity 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 Integrity 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 Integrity Services segment was fully impaired.
Water Services Segment
We completed our annual goodwill impairment assessment as of November 1, 2017, and concluded that the remaining $15.1 million of goodwill of the Water
Services segment was not impaired. We performed a qualitative analysis that took into consideration recent favorable trends (including recent increases in crude oil
prices and increased customer activity at certain of our facilities) and the subsequent fact that we sold one of our salt water disposal facilities in January 2018 at a
price that exceeded its carrying value. Based on these qualitative considerations, we concluded that the remaining carrying value of the goodwill of the Water
Services segment was not impaired.
Pipeline Inspection Segment
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, market capitalization,
current customer relationships and projects, and the impact of crude oil 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.
60
Depreciation Methods, Estimated Useful Lives of Property and Equipment
Depreciation expense represents the systematic write-off of the cost of property and equipment, net of residual or salvage value (if any), to the results of operations
for the periods the assets are used. We depreciate our property and equipment using the straight-line method, which results in recording depreciation expense
evenly over the estimated life of the individual assets. The estimate of depreciation expense requires us to make assumptions regarding the useful economic lives
and residual values of our assets. At the time we acquired and placed our property and equipment in service, we developed assumptions about such lives and
residual values that we believe are reasonable; however, circumstances may develop that could require us to change these assumptions in future periods, which
would change our depreciation expense amounts prospectively. We currently use a life of 15 years for wells and related equipment, which include subsurface well
completion and other improvements. We use a life of 9 years for tanks, plumbing and storage tanks and we generally use 5 years for our testing equipment and
trailers. We use lives of 30 – 39 years for buildings. We believe that these lives represent a reasonable estimate of the economic lives of the assets and that
substantial capital expenditures would need to be incurred to further extend their economic lives.
Consolidated Results of Operations – Cypress Energy 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:
● The Partnership has recorded impairments of long-lived assets totaling $3.6 million, $10.5 million, and $6.6 million in 2017, 2016, and 2015, respectively.
● Effective June 1, 2015, the Partnership acquired the remaining 49% interest in a Water Services segment management entity previously held by a related
party. As a result of this transaction, the 2015 Consolidated Financial Statements reflect a 49% noncontrolling interest from January 1, 2015 through May
31, 2015 related to this interest.
● Effective May 1, 2015, the Partnership acquired a 51% controlling interest in Brown, a hydrostatic integrity services business. The Consolidated Financial
Statements include Brown from this date forward with a 49% noncontrolling interest.
● At the closing of the IPO, we acquired a 50.1% interest in each of the TIR Entities with Holdings and certain affiliates continuing to hold the remaining
49.9% interest (“Retained Interest”). Effective February 1, 2015, we acquired the remaining 49.9% noncontrolling ownership interest of the TIR Entities
from affiliated parties. Accordingly, the Consolidated Financial Statements for 2015 reflect a 49.9% noncontrolling interest from January 1, 2015 through
January 31, 2015 related to the TIR Entities (less certain amounts charged directly to the noncontrolling interests in both periods).
61
● At the closing of the IPO, CEP LLC, the Partnership and other affiliates entered into an omnibus agreement with Holdings. Among other things, the
agreement calls for an annual administrative fee to be paid by the Partnership in the amount of $4.0 million (adjusted annually as provided for in the
omnibus agreement), payable in quarterly installments to Holdings, for providing the Partnership with certain administrative services, including executive
management services by certain officers of our General Partner, compensation expense for employees required to manage and operate our business, as well
as the costs of operating a publicly traded partnership, including costs associated with SEC reporting requirements, tax return and Schedule K-1
preparation and distribution, independent registered public accounting firm fees, investor relations activities, and registrar and transfer agent fees. During
the years ended December 31, 2017 and 2016, Holdings provided sponsor support to the Partnership by waiving certain of the quarterly administrative fees
(in 2017, Holdings waived the fee for two of the quarters; in 2016, Holdings waived the fee for all four quarters). We reported the amount of expenses
incurred by Holdings but not charged to us within general
and
administrative
expense
in our consolidated statement of operations and as an equity
contribution in our Consolidated Statement of Owners’ Equity.
● Interest expense will not be comparable between periods presented as a result of changes in the amount of debt outstanding and interest rates.
Consolidated Results of Operations
The following table compares the operating results of Cypress Energy Partners, L.P. for the years ended December 31:
Revenues
Costs of services
Gross margin
Operating costs and expense:
General and administrative
Depreciation, amortization and accretion
Impairments
Gain on asset disposals, net
Operating income (loss)
Other income (expense):
Interest expense, net
Foreign currency gains
Other, net
Net income (loss) before income tax expense
Income tax expense
Net income (loss)
2017
2016
(in
thousands)
2015 (a)
$
286,342 $
252,739
33,603
297,997 $
262,517
35,480
371,191
326,261
44,930
21,055
4,443
3,598
(570)
5,077
(7,335)
732
199
(1,327)
596
(1,923)
(1,110)
(813)
(4,050)
3,237 $
21,853
4,861
10,530
—
(1,764)
(6,559)
—
356
(7,967)
1,195
(9,162)
(4,499)
(4,663)
(6,298)
1,635 $
23,795
5,427
6,645
—
9,063
(5,656)
—
1,136
4,543
452
4,091
599
3,492
(648)
4,140
Net income (loss) attributable to noncontrolling interests
Net income (loss) attributable to partners / controlling interests
Net loss attributable to general partner
Net income attributable to limited partners
$
(a) Activity for the year ended December 31, 2015 includes the operations of Brown (IS segment) beginning with the May 1, 2015 acquisition date.
See the detailed discussion of elements of operating income (loss) by reportable segment below. See also Note 13 to our Consolidated Financial Statements
included in “ Item
8.
–
Financial
Statement
and
Supplementary
Data.”
62
The following is a discussion of significant changes in the non-segment related corporate other income and expenses for the years ended December 31, 2017, 2016,
and 2015.
Interest
expense.
Interest expense primarily consists of interest on borrowings under our Credit Agreement, as well as amortization of debt issuance costs and
unused commitment fees. Interest expense increased in 2017, 2016 and 2015 primarily due to increased borrowings related to the acquisition of the remaining
49.9% interest in the TIR Entities, the acquisition of 51% of Brown and higher interest rates. Average debt outstanding for the years ended December 31, 2017,
2016, and 2015 was $136.9 million, $137.3 million, and $129.9 million, respectively.
Foreign
currency
gains
. 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
in our Consolidated Statements of Operations. The net foreign currency gain during
the year ended December 31, 2017 resulted from the appreciation of the Canadian dollar relative to the U.S. dollar.
Other,
net
. During the year ended December 31, 2015, we received $1.0 million for relinquishing our option to purchase certain assets from a related party. The
remaining income during the years ended December 31, 2017, 2016, and 2015 relates primarily to earnings from our 25% interest in an entity that owns a salt
water disposal facility, which investment we account for under the equity method.
Income
tax
expense.
We qualify as a partnership for income tax purposes and therefore, 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. Income tax expense relates to two taxable corporate subsidiaries in the United States and one taxable
corporate subsidiary in Canada in our Pipeline Inspection and Integrity Services segments, as well as business activity, gross margin, and franchise taxes incurred
in certain states. The decrease in income tax expense from 2016 to 2017 is primarily attributable to decreased income generated by our Canadian and TIR-PUC
subsidiaries that are taxed as corporations in their respective tax jurisdictions. The increase in income tax expense from 2015 to 2016 results primarily from
increased income generated by our TIR-PUC subsidiary that is taxed as a corporation for federal and state income tax purposes.
Net
income
attributable
to
noncontrolling
interests.
The net income attributable to noncontrolling interests shown in our Consolidated Results of Operations
reflects interests in the net income of consolidated entities that are not 100% owned by us. The amounts for the years ended December 31, 2017, 2016, and 2015
relate primarily to Brown, of which 49% is owned by outside parties. The amounts during the year ended December 31, 2015 include one month of activity for the
TIR Entities, of which we owned 50.1% until we acquired the remaining 49.9% on February 1, 2015.
Net
income
attributable
to
the
general
partner.
The net income attributable to the general partner shown in our Consolidated Results of Operations includes general
and administrative expenses incurred by Holdings on behalf of the Partnership totaling $1.8 million, $3.8 million, and $0.6 million for the years ended December
31, 2017, 2016, and 2015, respectively. These costs represent administrative costs incurred by Holdings in excess of amounts charged to the Partnership under our
omnibus agreement and are reflected as general
and
administrative
in the Consolidated Statements of Operations and as contributions
attributable
to
General
Partner
in the Consolidated Statement of Owners’ Equity. In addition, Holdings provided the Partnership with additional financial support by making cash
contributions of $2.3 million and $2.5 million in 2017 and 2016, respectively, as a reimbursement for certain expenditures incurred by the Partnership. These
payments 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
the
general
partner
in the Consolidated Statements of Operations for the years ended December 31, 2017 and 2016.
Segment Operating Results
Pipeline Inspection
The following table summarizes the operating results of our Pipeline Inspection segment for the years ended December 31, 2017 and 2016.
2017
% of
Revenue
Years Ended December 31,
2016
% of
Revenue
Change
% Change
(in
thousands,
except
average
revenue
and
inspector
data)
Revenue
Costs of services
Gross margin
General and administrative
Depreciation and amortization
Impairments
Other
Operating income
Operating Data
Average number of inspectors
Average revenue per inspector per week
Revenue variance due to number of inspectors
Revenue variance due to average revenue per
inspector
$
$
$
268,635
241,889
26,746
13,980
2,331
1,329
18
9,088
$
10.0%
5.2%
0.9%
0.5%
0.0%
3.4% $
275,171
247,214
27,957
12,521
2,439
—
—
$
10.2%
4.6%
0.9%
12,997
4.7% $
1,145
4,499
$
1,147
4,601
$
$
$
(2.4)%
(2.2)%
(4.3)%
11.7%
(4.4)%
(30.1)%
(0.2)%
(2.2)%
(6,536)
(5,325)
(1,211)
1,459
(108)
1,329
18
(3,909)
(2)
(102)
(469)
(6,067)
Revenues
. Revenues decreased approximately $6.5 million for the year ended December 31, 2017 compared to the year ended December 31, 2016, primarily due
to a reduction in the average revenue billed for each inspector (accounting for a $6.1 million revenue decrease) and, to a lesser extent, a decrease in the average
number of inspectors engaged (a decrease of 2 inspectors, accounting for $0.5 million of the decrease). Revenues of our Canadian business decreased $7.8 million
during the year ended December 31, 2017 compared to the year ended December 31, 2016, due primarily to the loss of our largest Canadian customer in the second
quarter of 2017 (this customer completed a bidding process and awarded new contracts at rates that were lower than we were willing to accept). This decrease was
partially offset by an increase of $1.3 million in our U.S. business lines, including increases of $1.4 million in our public utility business and $4.4 million in
nondestructive examination service line, partially offset by a decrease of $4.5 million in revenues of our traditional inspection services during the year ended
December 31, 2017 compared to the year ended December 31, 2016. 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.
63
The decline in average revenue per inspector is due to changes in customer mix. Fluctuations in the average revenue per inspector per year are expected, given that
we charge different rates for different type of inspectors and different types of inspection services. Competition remains intense in the industry, which continued to
exert downward pressure on rates.
Costs
of
services
. Costs of services decreased approximately $5.3 million during the year ended December 31, 2017 compared to the year ended December 31,
2016, consistent with lower revenues.
Gross
margin
. Gross margin decreased approximately $1.2 million during the year ended December 31, 2017, due primarily to lower revenues. The gross margin
percentage during the year ended December 31, 2017 was similar to that of the year ended December 31, 2016, as declines in margin percentage resulting from
competitive pressures were partially offset by increased revenues in our higher-margin business lines, such as the nondestructive examination service line.
General
and
administrative
. General and administrative expenses increased approximately $1.5 million in the year ended December 31, 2017, compared to the
year ended December 31, 2016. The increase was primarily due to the fact that Holdings charged the Pipeline Inspection segment $1.4 million during the year
ended December 31, 2017 for administrative services, as allowed for under our omnibus agreement with Holdings. During the year ended December 31, 2016,
Holdings waived the full amount of this administrative fee.
Depreciation
and
amortization.
Depreciation and amortization expense for the year ended December 31, 2017 was similar to depreciation and amortization
expense for the year ended December 31, 2016.
Impairments
. During the year ended December 31, 2017, we recorded an impairment of $1.3 million to the carrying values of certain intangible assets associated
with our Canadian subsidiary, which was due to the loss during the second quarter of 2017 of the largest customer of this subsidiary. The intangible assets included
customer relationships with a book value of $1.1 million and trade names with a book value of $0.2 million.
The following table summarizes the operating results of our Pipeline Inspection segment for the year ended December 31, 2016 and 2015.
Revenue
Costs of services
Gross margin
General and administrative
Depreciation and amortization
Operating income
Operating Data
Average number of inspectors
Average revenue per inspector per week
Revenue variance due to number of inspectors
Revenue variance due to average revenue per
inspector
$
$
$
2016
% of
Revenue
Years Ended December 31,
2015
% of
Revenue
Change
% Change
(in
thousands,
except
average
revenue
and
inspector
data)
275,171
247,214
27,957
12,521
2,439
12,997
$
10.2%
4.6%
0.9%
4.7% $
341,929
309,584
32,345
16,672
2,512
13,161
$
9.5%
4.9%
0.7%
3.8% $
(66,758)
(62,370)
(4,388)
(4,151)
(73)
(164)
(19.5)%
(20.1)%
(13.6)%
(24.9)%
(2.9)%
(1.2)%
1,147
4,601
$
1,392
4,711
(245)
(110)
(17.6)%
(2.3)%
(58,777)
(7,981)
$
$
$
Revenues
. Revenues decreased $66.8 million from 2015 to 2016, primarily due to a decrease in the average number of inspectors engaged (a decline of 245
inspectors accounting for $58.8 million of the revenue decrease) and, to a lesser extent, a reduction in the average revenue billed for each inspector during the years
presented. During 2016, we experienced delays and/or cancellations of significant projects within our customer base as a result of economic conditions in the
energy industry. We continue to focus on areas of inspection less impacted by economic conditions, such as maintenance projects and projects associated with
public utility companies to help mitigate the decline in revenues associated with new construction projects. The decline in average revenue per inspector is
generally impacted by a change in customer mix as well as pricing concessions granted during the year. Fluctuations in the average revenue per inspector per year
are not unexpected, given that we charge different rates for different types of inspectors and different types of inspection services.
Costs
of
services
. Costs of services decreased $62.4 million from 2015 to 2016, which is directly attributable to the decline in revenues and average number of
inspectors in the field.
Gross
margin
. Gross margin decreased $4.4 million from 2015 to 2016. The gross margin percentages from year-to-year improved slightly (10.2% in 2016
compared to 9.5% in 2015). The increase in gross margin percentage is attributable to the mix of services provided throughout the year.
General
and
administrative
. General and administrative expenses decreased $4.2 million, due primarily to the fact that Holdings waived the omnibus fee in 2016
(in 2015, $2.8 million of the omnibus fee was reported within the Pipeline Inspection segment). Compensation expense was approximately $0.5 million lower in
2016 than in 2015, due to focused efforts to reduce overhead costs in response to the energy sector downturn.
Operating
income
. Operating income for the year ended December 31, 2016 decreased $0.2 million compared to the year ended December 31, 2015, primarily
due to the gross margin decrease of $4.4 million, partially offset by a decrease in general and administrative expense of $4.2 million.
64
Integrity Services
The following table summarizes the results of the Integrity Services segment for the years ended December 31, 2017 and 2016.
2017
% of
Revenue
Year Ended December 31,
2016
% of
Revenue
Change
% Change
(in
thousands,
except
average
revenue
and
inspector
data)
Revenue
Costs of services
Gross margin
General and administrative
Depreciation and amortization
Impairments
Operating income (loss)
Operating Data
Average number of field personnel
Average revenue per field personnel per week
Revenue variance due to number of field personnel
Revenue variance due to average revenue per field
personnel
$
$
$
9,268
7,347
1,921
1,981
626
1,581
(2,267)
20
8,887
$
20.7%
21.4%
6.8%
17.1%
(24.5)% $
13,884
11,542
2,342
2,829
658
8,411
(9,556)
23
11,577
$
$
16.9%
20.4%
4.7%
60.6%
(68.8)% $
$
$
$
(4,616)
(4,195)
(421)
(848)
(32)
(6,830)
7,289
(3)
(2,690)
(1,386)
(3,230)
(33.2)%
(36.3)%
(18.0)%
(30.0)%
(4.9)%
(81.2)%
(76.3)%
(13.0)%
(23.2)%
Revenue.
Revenues decreased approximately $4.6 million during the year ended December 31, 2017 compared to the year ended December 31, 2016. Revenues
declined during late 2016 and early 2017, due in part to a slowdown in customer projects and to the loss during 2016 of certain business development personnel.
During the second half of 2017, our revenues began to recover due to increases in customer project activity and improved business development efforts. Our
Integrity 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 Integrity Services segment are somewhat more volatile, and revenues for a given period of time can be significantly influenced by the ability or
inability to win a relatively small number of bids for large hydrotesting projects.
Costs
of
services.
Costs of services decreased approximately $4.2 million during the year ended December 31, 2017 compared to the year ended December 31,
2016, consistent with the decrease in revenues.
Gross
margin.
Gross margin decreased approximately $0.4 million during the year ended December 31, 2017 compared to the year ended December 31, 2016,
primarily due to lower revenues. The employees of the Integrity Services segment who perform work in the field are full-time employees, and therefore represent
fixed costs (in contrast to the employees of the Pipeline Inspection segment that perform work in the field, most of whom only earn wages when they are
performing work for a customer, and whose wages are therefore variable costs). Because of this, margin percentages typically improve when revenues are higher,
as our field employees are more fully utilized. The gross margin percentage was higher during the year ended December 31, 2017 than during the year ended
December 31, 2016, despite the lower revenues, due to cost management measures that we implemented in response to the slowdown in activity that began during
2016.
General
and
administrative
. General and administrative expenses consist primarily of compensation for office employees and general office expenses. These
expenses decreased approximately $0.8 million during the year ended December 31, 2017 compared to the year ended December 31, 2016, due primarily to cost-
cutting measures we implemented in response to the low-revenue environment, which included reductions in office head count as well as the closure of an office
location.
Depreciation
and
amortization
. Depreciation and amortization expense includes depreciation of property and equipment and amortization of intangible assets
associated with customer relationships, trade names and non-compete agreements. Depreciation and amortization expense during the year ended December 31,
2017 was similar to depreciation and amortization expense for the year ended December 31, 2016.
Impairments.
During the year ended December 31, 2016, we recorded an impairment of $8.4 million to the goodwill associated with the Integrity Services segment
in response to the decline in revenues. During the first quarter of the year ended December 31, 2017, we recorded an additional impairment of $1.6 million to
goodwill, which represented the full remaining amount of the goodwill attributable to this segment.
The following table summarizes the results of the Integrity Services segment for the year ended December 31, 2016 and the period from May 1, 2015 (date of
acquisition) through December 31, 2015.
2016
% of
Revenue
Year Ended December 31,
2015 (a)
% of
Revenue
Change
% Change
(in
thousands,
except
average
revenue
and
inspector
data)
Revenue
Costs of services
Gross margin
$
13,884
11,542
2,342
$
16.9%
14,614
10,398
4,216
$
28.8%
(730)
1,144
(1,874)
(5.0)%
11.0%
(44.4)%
General and administrative
Depreciation and amortization
Impairments
Operating income (loss)
Operating Data
Average number of field personnel
Average revenue per field personnel per week
Revenue variance due to number of field personnel
Revenue variance due to average revenue per field
personnel
Revenue variance due to period differences (see (a))
2,829
658
8,411
(9,556)
23
11,577
$
$
20.4%
4.7%
60.6%
(68.8)% $
2,490
421
—
1,305
17.0%
2.9%
8.9% $
339
237
8,411
(10,861)
$
33
12,653
$
$
$
$
(10)
(1,076)
(6,020)
(1,846)
7,136
13.6%
56.3%
(832.3)%
(30.3)%
(8.5)%
(a) We owned the Integrity Services segment for only eight months of the year ended December 31, 2015.
Revenue.
Revenues decreased $0.7 million from 2015 to 2016. Revenues of the Integrity Services segment were adversely affected by a slowdown in new
projects by its customers and by the loss of key business development employees. These decreases were partially offset by an additional four months of activity in
2016, as Brown was acquired May 1, 2015.
Costs
of
services.
Costs of services increased $1.1 million from 2015 to 2016, as we owned Brown for the full year ended December 31, 2016, but for only eight
months of the year ended December 31, 2015. The employees of the Integrity Services segment who perform work in the field 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 variable costs). In addition, increases in costs of services were partially offset by
cost saving measures instituted during 2016, including the closing of an office and reductions in work force.
Gross
margin.
Gross margin decreased $1.9 million from 2015 to 2016. The decrease in gross margin was due to lower revenues. Because most of the employees
of the Integrity Services segment are full time employees, cost of services from 2015 to 2016 did not decline commensurate with the decrease in revenues over the
same period.
General
and
administrative
. General and administrative expenses increased $0.3 million. This increase was primarily due to the fact that we owned our 51%
interest in Brown for the full year ended December 31, 2016, but for only eight months of the year ended December 31, 2015. The resultant increase in general and
administrative expense was partially offset by reductions in personnel that we initiated in response to the low-revenue environment.
Depreciation
and
amortization
. Depreciation and amortization expense increased $0.2 million from 2015 to 2016. This increase was primarily due to the fact that
we owned our 51% interest in Brown for the full year ended December 31, 2016, but for only eight months of the year ended December 31, 2015.
Impairments.
During the year ended December 31, 2016, we recorded an impairment of $8.4 million to the goodwill of the Integrity Services segment.
Operating
income
(loss)
. Operating income for the year ended December 31, 2016 decreased $10.9 million compared to the year ended December 31, 2015,
primarily due to the gross margin decrease of $1.9 million and to the goodwill impairment charge of $8.4 million.
65
Water Services
The following table summarizes the operating results of our Water Services segment for the years ended December 31, 2017 and 2016.
2017
% of
Revenue
Year Ended December 31,
2016
% of
Revenue
(in
thousands,
except
per
barrel
data)
Change
% Change
Revenue
Costs of services
Gross margin
General and administrative
Depreciation, amortization and accretion
Impairments
(Gain) loss on asset disposals, net
Operating income (loss)
Operating Data
Total barrels of salt water disposed
Average revenue per barrel disposed (a)
Revenue variance due to barrels disposed
Revenue variance due to revenue per barrel
$
$
$
8,439
3,503
4,936
2,451
1,486
688
(588)
899
$
58.5%
29.0%
17.6%
8.2%
(7.0)%
10.7% $
8,942
3,761
5,181
1,866
1,764
2,119
—
(568)
12,588
0.67
13,307
0.67
$
$
57.9%
20.9%
19.7%
23.7%
(6.4)% $
$
$
$
(503)
(258)
(245)
585
(278)
(1,431)
(588)
1,467
(719)
0.0
(483)
(20)
(5.6)%
(6.9)%
(4.7)%
31.4 %
(15.8)%
(67.5)%
(258.3) %
(5.4)%
0.0 %
(a) Average revenue per barrel disposed is calculated by dividing revenues (which includes disposal revenues, residual oil sales and management fees) by the
total barrels of salt water disposed.
Revenue.
Revenues decreased by $0.5 million during the year ended December 31, 2017 compared to the year ended December 31, 2016. The decline was
primarily due to a 5.4% decrease in the volume of salt water disposed. The decrease in the volume of water disposed was due to in part to a lightning strike and fire
at our Orla, Texas facility in January 2017 that destroyed the surface equipment. Although we soon reopened the facility using temporary equipment, the volume of
water processed at this facility decreased by 1.1 million barrels during the year ended December 31, 2017 compared to the year ended December 31, 2016. The
volume of water processed at our North Dakota facilities decreased by 0.4 million barrels during the year ended December 31, 2017 compared to the year ended
December 31, 2016, due primarily to a July 2017 lightning strike and fire at our Grassy Butte facility, which destroyed the surface equipment. This facility is not
currently operational. These decreases in volumes were partially offset by an increase of 0.8 million barrels processed at our Pecos, Texas facility, due to increased
customer activity in the area of the facility. Average revenue per barrel processed during the year ended December 31, 2017 was similar to that of the year ended
December 31, 2016. Oil revenue represented approximately 7% of total revenue during the year ended December 31, 2017, compared to 6% of total revenue during
the year ended December 31, 2016.
Costs
of
services.
Costs of services decreased by $0.3 million from the year ended December 31, 2017, compared to the year ended December 31, 2016, primarily
due to cost reduction measures we implemented in mid-2016 in response to adverse market conditions. These measures included the temporary suspension of
activity at two of our facilities and investments in automation at other facilities.
Gross
margin.
Gross margin decreased by $0.2 million during the year ended December 31, 2017, compared to the year ended December 31, 2016, due to a $0.5
million decrease in revenue which was partially offset by a $0.3 million decrease in costs of services.
General
and
administrative
expense
. General and administrative expenses include general office overhead expenses such as salary costs, office expense,
insurance, property taxes, royalty expenses, and other miscellaneous expenses. General and administrative expense during the year ended December 31, 2017
included $0.6 million that Holdings charged the Water Services segment for administrative services, as allowed for under our omnibus agreement with Holdings.
During the year ended December 31, 2016, Holdings waived the full amount of this administrative fee.
Depreciation,
amortization
and
accretion.
Depreciation, amortization and accretion expenses decreased from 2016 to 2017 primarily due to the prior impairment
of equipment at various salt water disposal facilities. As equipment is impaired, there is less asset basis to depreciate.
Impairments
. In the first quarter of 2017, we recorded an impairment of $0.7 million to the property, plant and equipment at one of our facilities in North Dakota.
We experienced low volumes at this facility due to competition in the area and to low levels of production activity near the facility, and we have temporarily idled
the facility. In the second quarter of 2016, we recorded an impairment of $2.1 million to the property, plant and equipment at one of our facilities in North Dakota,
due to low levels of customer activity in the area. Market conditions near this facility have since improved, and we recently completed construction of a gathering
system to connect this facility to a customer’s newly-developed production fields.
(Gain)
loss
on
asset
disposals.
During 2017, lightning strikes and the resultant fires destroyed the surface equipment at two of our facilities. We carry 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.
The following table summarizes the operating results of our Water Services segment for the years ended December 31, 2016 and 2015.
Year Ended December 31,
% of
% of
Revenue
Costs of services
Gross margin
General and administrative
Depreciation, amortization and accretion
Impairments
Operating loss
Operating Data
Total barrels of salt water disposed
Average revenue per barrel disposed (a)
Revenue variance due to barrels disposed
Revenue variance due to revenue per barrel
2016
Revenue
2015
Revenue
Change
% Change
(in
thousands,
except
per
barrel
data)
$
$
$
8,942
3,761
5,181
1,866
1,764
2,119
(568)
$
57.9%
20.9%
19.7%
23.7%
(6.4)% $
14,648
6,279
8,369
3,351
2,494
6,645
(4,121)
13,307
0.67
18,864
0.78
$
$
57.1%
22.9%
17.0%
45.4%
(28.1)% $
$
$
$
(5,706)
(2,518)
(3,188)
(1,485)
(730)
(4,526)
3,553
(5,557)
(0.10)
(4,315)
(1,391)
(39.0)%
(40.1)%
(38.1)%
(44.3)%
(29.3)%
(68.1)%
(86.2)%
(29.5)%
(13.5)%
(a) Average revenue per barrel disposed is calculated by dividing revenues (which includes disposal revenues, residual oil sales and management fees) by the
total barrels of salt water disposed.
66
Revenue.
The decrease of $5.7 million in revenues from 2015 to 2016 is primarily due to a 29.5% decrease in the volume of produced and flowback salt water
disposed (accounting for $4.3 million of the decrease in revenues) and to a decrease in the average revenue per barrel disposed (accounting for $1.4 million of the
decrease in revenues). The decrease in volumes was due primarily to reduced exploration and production activity in the areas where we operate, as a result of low
commodity prices. The decrease in average revenue per barrel processed was due to pricing pressures resulting from competition, the fact that recovered oil
volumes were lower as a percentage of water volumes processed, and to lower selling prices for crude oil we recovered. Oil revenue represented 6% of total
revenue in 2016, compared to 8% in 2015.
Costs
of
services.
Costs of services decreased by $2.5 million from 2015 to 2016, due primarily to a $1.3 million decrease in employee compensation expense and
to a $0.9 million decrease in repair and maintenance expense. The decrease in employee compensation expense was attributable to cost reduction measures that we
implemented in mid-2016 in response to adverse conditions in the exploration and production market. These measures included the temporary suspension of
activity at two of our facilities and investments in automation at other facilities. Repair and maintenance expenses fluctuate based on a variety of factors. Other
decreases in cost of sales from 2015 to 2016 included a decrease of $0.2 million in utility expense and a decrease of $0.1 million in oil disposal costs, both of
which are attributable to lower volumes.
Gross
margin.
Gross margin decreased by $3.2 million from 2015 to 2016, due to a decrease in revenues of $5.7 million, partially offset by a decrease in cost of
services of $2.5 million.
General
and
administrative
expense
. General and administrative expenses decreased by $1.5 million from 2015 to 2016, due primarily to the fact that Holdings
waived the omnibus fee in 2016 (the portion of the omnibus fee allocable to the Water Services segment was $1.2 million in 2015). In addition, royalty expenses
were $0.2 million lower in 2016 than in 2015, as a result of lower revenues.
Depreciation,
amortization
and
accretion.
Depreciation, amortization and accretion expenses decreased from 2015 to 2016 primarily due to the prior impairment
of equipment at various salt water disposal facilities. As equipment is impaired, there is less asset basis to depreciate.
Impairments
. As a result of the decline in commodity prices and a decline in drilling activity around some of our facilities, we recorded impairment charges
during the years ended December 31, 2016 and 2015 to property, plant and equipment of $2.1 million and $6.6 million, respectively.
Operating
loss.
Operating loss declined $3.6 million from 2015 to 2016. The decrease in gross margin from 2015 to 2016 was more than offset by lower general
and administrative expenses and impairment charges.
67
Liquidity and Capital Resources
We anticipate making growth capital expenditures in the future, including acquiring new businesses that may include pipeline inspection companies and salt water
disposal facilities or expanding our 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 per diem 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, 2017, our sources of liquidity included:
●
●
$24.5 million in cash on the balance sheet at December 31, 2017 (inclusive of cash attributable to the noncontrolling interest owners);
borrowings under our Credit Agreement under which we had $63.1 million available for borrowings at December 31, 2017, that are limited by certain
borrowing base limitations and financial covenant ratios as outlined in the Credit Agreement; and
●
issuance of equity and/or debt securities.
Refinancing
Our revolving credit facility matures in December 2018. In March 2018, we successfully negotiated commitments for a new three-year credit facility with our
existing bank group. Also in March 2018, we received a commitment from an affiliate of Holdings to invest up to $50.0 million of preferred equity. These
commitments are described in more detail under Outlook above.
Distribution
Effective with the February 2017 distribution, our Board made the decision to reduce our quarterly distribution by approximately 50% to $0.21 per unit. This
action should provide a sound catalyst to reducing our currently elevated cost of capital by de-levering and improving increased distribution coverage to our
unitholders. We are confident this action supports the long-term interests of our unitholders, employees, and other stakeholders.
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. The cash
flows include activity of the Integrity Services segment since the acquisition of Brown on May 1, 2015, and therefore, may not be comparable from period to
period.
Net cash provided by operating activities
Net cash used in investing activities
Net cash provided by (used in) financing activities
Effect of exchange rates on cash
Net increase (decrease) in cash and cash equivalents
2017
Year Ended December 31,
2016
(in
thousands)
2015
$
$
8,253 $
(1,041)
(10,150)
753
(2,185) $
24,819 $
(1,330)
(21,289)
343
2,543 $
26,921
(64,879)
42,501
(1,150)
3,393
Operating
activities
. Net operating cash inflows for the year ended December 31, 2017 were $8.3 million, consisting of a net loss of $1.9 million plus non-cash
expenses of $10.8 million and net decrease in working capital of $0.6 million. Non-cash expenses included depreciation, amortization and accretion and
impairment expense, among others. Non-cash expenses also included $1.8 million of expenses attributable to the Partnership that were paid by Holdings and
recorded as an equity contribution in the Partnership’s financial statements. The change in working capital included a net increase of $3.4 million in accounts
receivable over the course of 2017, due to an increase in business activity toward the end of the year. Operating cash flows during 2017 benefitted from an increase
of $4.4 million in accounts payable and accrued liabilities, due in part to increased business activity and due in part to the fact that we had not yet paid the $1.0
million fourth quarter omnibus fee to Holdings as of December 31, 2017. Net operating cash inflows for the year ended December 31, 2016 were $24.8 million,
consisting of a net loss of $9.2 million plus non-cash expenses of $21.6 million and net changes in working capital of $12.4 million. Non-cash expenses included
depreciation and impairment expense, among others. Non-cash expenses also included $3.8 million of expenses attributable to the Partnership that were paid by
Holdings and recorded as an equity contribution in the Partnership’s financial statements. The net change in working capital included a net decrease of $9.9 million
in accounts receivable over the course of 2016, due to a slowdown in business activity. Net operating cash for the year ended December 31, 2015 included $4.1
million of net income, $15.0 million of non-cash expenses, and $7.9 million of net changes in working capital.
Investing
activities
. Cash used in investing activities consists primarily of acquisitions and capital expenditures. In 2015, we acquired the remaining 49.9%
interest in TIR Entities for $52.6 million and we acquired a 51% interest in Brown for $10.4 million. Capital expenditures were $3.3 million, $1.4 million, and $1.9
million during the years ended December 31, 2017, 2016, and 2015, respectively. Capital expenditures during the year ended December 31, 2017 included $1.9
million for the construction of a gathering system to connect one of our salt water disposal facilities in North Dakota to a customer’s production fields. The first
phase of this system, consisting of two pipelines, was completed in January 2018. The remaining capital expenditures consisted primarily of equipment purchases,
much of which was in support of increasing revenues in TIR’s non-destructive examination business. Cash inflows from investing activities during the year ended
December 31, 2017 included $2.3 million of proceeds on property damage insurance claims, which resulted from lightning strikes and resultant fires at two of our
salt water disposal facilities.
Financing
activities
. Financing cash outflows for the year ended December 31, 2017 included $12.3 million of distributions to owners. Financing cash inflows for
the year ended December 31, 2017 included $2.3 million of contributions from Holdings to support the Partnership. Financing cash outflows for the year ended
December 31, 2016 included $19.7 million of distributions to owners and $4.0 million of repayments on the revolving credit facility. Financing cash inflows for the
year ended December 31, 2016 included $2.5 million of contributions from Holdings to support the Partnership. Financing cash inflows during the year ended
December 31, 2015 included net borrowings of $63.3 million on the revolving credit facility, in order to fund acquisitions. Financing cash outflows for the year
ended December 31, 2015 included $20.8 million of distributions to owners.
68
Working Capital
Our working capital was $(82.4) million at December 31, 2017, compared to $54.3 million at December 31, 2016. As of December 31, 2017, all of the
Partnership’s revolving credit facility ($136.3 million, net of unamortized debt issuance costs), which is due in December of 2018, was classified as current
compared to the prior year where the balance of the revolving credit facility was classified as long-term. The Partnership has received commitments from its
lenders to refinance $80.0 million of the facility as well as a commitment from an affiliate of Holdings to invest up to $50.0 million through a PIPE (see
Refinancing
). Excluding the current portion of long-term debt, our working capital would have been $53.9 million. Our Pipeline Inspection and Integrity Services
segments have substantial working capital needs as they generally pay their inspectors and field personnel on a weekly basis, but typically receive payment from
their 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.”
As described below under “Refinancing”, we have received commitments from our existing lenders to refinance our revolving credit facility. Upon
completion of this refinancing, the new credit facility will have less borrowing capacity than our existing credit facility, and we will need to fund our working
capital needs primarily from operating cash flows.
Capital Requirements
Water Services has capital needs requiring investment for the maintenance of existing salt water disposal facilities and the acquisition or construction and
development of new salt water disposal facilities. 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 tankage, workovers, pipelines, pumps and other improvement of existing capital assets,
including the construction or development of new capital assets to replace our existing salt water disposal systems as they become obsolete. Other
examples of maintenance capital expenditures are expenditures to repair, refurbish and replace tubing and packers on the salt water disposal well itself
to maintain equipment reliability, integrity and safety, as well as to address environmental laws and regulations. Maintenance capital expenditures for
the years ended December 31, 2017 and 2016 were $0.5 million and $0.5 million, respectively.
●
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 construction or development of additional salt water disposal capacity or efficiencies, to the extent
such expenditures are expected to expand our long-term operating capacity or operating income. Expansion capital expenditures include interest
payments (and related fees) on debt incurred to finance all or a portion of expansion capital expenditures in respect of the period from the date that we
enter into a binding obligation to commence the construction, development, replacement, improvement, automation or expansion of a capital asset and
ending on the earlier to occur of the date that such capital improvement commences commercial service and the date that such capital improvement is
abandoned or disposed of. Expansion capital expenditures for the years ended December 31, 2017 and 2016 were $2.3 million and $0.8 million,
respectively.
Our future expansion capital expenditures may vary significantly from period to period based on the investment opportunities available to us. We expect to fund
future capital expenditures from cash flow generated from our operations, borrowings under our Credit Agreement, the issuance of additional partnership units, or
debt offerings.
Our Credit Agreement
The Partnership is party to a credit agreement (as amended, the “Credit Agreement”) that provides up to $200.0 million in borrowing capacity, subject to certain
limitations. The Credit Agreement includes a working capital revolving credit facility (“Working Capital Facility”) which provides up to $75.0 million in
borrowing capacity to fund working capital needs and an acquisition revolving credit facility (“Acquisition Facility”) which provides up to $125.0 million in
borrowing capacity to fund acquisitions and expansion projects if lenders agree to increase their commitments. In addition, the Credit Agreement contains an
accordion feature that allows us to increase the availability under the facilities by an additional $125.0 million if lenders agree to increase their commitment. The
Credit Agreement matures on December 24, 2018.
Outstanding borrowings at December 31, 2017 and 2016 under the Credit Agreement were as follows:
Working capital facility
Acquisition facility
Total borrowings
Debt issuance costs
Long-term debt, including current portion
Current portion of long-term debt
Long-term debt
December 31,
2017
2016
(in
thousands)
$
$
48,000 $
88,900
136,900
607
136,293
136,293
— $
48,000
88,900
136,900
1,201
135,699
—
135,699
The carrying value of the partnership’s 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).
Borrowings under the Working Capital Facility are limited by a monthly borrowing base calculation as defined in the Credit Agreement. If, at any time,
outstanding borrowings under the Working Capital Facility exceed the Partnership’s calculated borrowing base, a principal payment in the amount of the excess is
due upon submission of the borrowing base calculation. Available borrowings under the Acquisition Facility may be limited by certain financial covenant ratios as
defined in the Credit Agreement. The obligations under our Credit Agreement are secured by a first priority lien on substantially all assets of the Partnership.
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 1.25% to 2.75% per
annum (“Base Rate Borrowing”) or (ii) an adjusted LIBOR rate plus a margin of 2.25% to 3.75% per annum (“LIBOR Borrowings”). The applicable margin is
determined based on the leverage ratio of the Partnership, as defined in the Credit Agreement. Generally, the interest rate on our Credit Agreement borrowings
ranged between 3.90% and 5.32% for the year ended December 31, 2017, 3.54% and 4.52% for the year ended December 31, 2016, and 2.68% and 4.17% for the
year ended December 31, 2015. 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.
69
Our Credit Agreement contains various customary affirmative and negative covenants and restrictive provisions. Our Credit Agreement also requires maintenance
of certain financial covenants, including a combined total adjusted leverage ratio (as defined in our Credit Agreement) of not more than 4.0 to 1.0 and an interest
coverage ratio (as defined in our Credit Agreement) of not less than 3.0 to 1.0. At December 31, 2017, our combined total adjusted leverage ratio was 3.7 to 1.0
and our interest coverage ratio was 3.1 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 our Credit Agreement, the lenders may declare any outstanding principal of our Credit Agreement debt, together with accrued and
unpaid interest, to be immediately due and payable and may exercise the other remedies set forth or referred to in our Credit Agreement. We were in compliance
with all debt covenants as of December 31, 2017. Working capital borrowings, which are fully secured by the Partnership’s net working capital, are subject to a
monthly borrowing base and are excluded from the Partnership’s debt compliance ratios.
In addition, our Credit Agreement restricts our ability to make distributions on, or redeem or repurchase, our equity interests. 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 our Credit Agreement, the
borrowers and the guarantors are in compliance with the financial covenants, the borrowing base (which includes 100% of cash on hand) exceeds the amount of
outstanding credit extensions under the Working Capital Facilities by at least $5.0 million, and at least $5.0 million in lender commitments are available to be
drawn under the Working Capital Facility.
Refinancing
Our current $200 million credit facility matures in December 2018 and had approximately $136.9 million outstanding at December 31, 2017. In the fall of 2017,
we began working with our agent on the terms of a new credit facility, anticipating that we would close the new facility prior to the end of 2017. In December
2017, we learned that some of our lenders were not comfortable with the proposed terms and conditions and they requested the agent for various modifications to
the proposed terms. In February, we agreed upon a new revised term sheet and in March 2018, we successfully negotiated commitments for a new revolving credit
facility with our existing bank group with a term that extends three years after closing, consistent with the strategy outlined in our Form 10-Q for the three months
ended September 30, 2017.
To reduce leverage, we negotiated the sale of our Pecos, Texas salt water disposal facility and utilized the $4.0 million of proceeds to repay principal on our credit
facility in January, 2018. We were also successful in retaining a perpetual royalty on that facility. We plan to use approximately $7.0 million of our cash on hand
to repay an additional amount of principal at the time we close on the new credit facility, sometime in the second quarter, while maintaining sufficient liquidity to
support our operations. The new credit facility will have a maximum capacity of $80.0 million, with a $20.0 million accordion feature (for a total of $100.0
million) with additional banks still evaluating the proposed facility. Under the new credit facility, we will be able to borrow up to 3.75 times our trailing twelve-
month adjusted EBITDA (“TTM EBITDA”) (as adjusted EBITDA is defined in the credit agreement, which may differ from how adjusted EBITDA is defined
elsewhere in this annual report) for senior debt. Additionally, we may incur additional indebtedness other than the new credit facility, provided the pro forma
senior secured leverage ratio may not exceed 3.25 times TTM EBITDA and the total leverage ratio may not exceed 4.75 times TTM EBITDA. As part of the
refinancing, Holdings agreed to waive the omnibus fee to support us in the event leverage exceeds 3.75 times trailing twelve-month adjusted EBITDA during the
term of the facility. The new credit facility will have customary covenants, including but not limited to a maximum senior leverage ratio of 4.0 times adjusted
EBITDA, or 3.25 times senior secured leverage if additional debt not to exceed 1.5 times is incurred, and a minimum interest coverage ratio of 3.0 times adjusted
EBITDA. The new facility will no longer have a required borrowing base calculation and borrowings under the new agreement will 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 or (ii) a LIBOR rate plus a margin of 2.5% to 4.0% per annum. The
facility will also include a 50 basis point non-use fee consistent with the current facility, and no amortization will be required during the term which extends three
years after closing. We have received commitment letters from banks for the full amount of the facility, and these commitment letters will remain in effect through
May 31, 2018. We also have another bank considering joining the facility. We believe this new facility will support our current business requirements until we
find an attractive acquisition opportunity, at which time we will seek to expand the current revolving credit facility or refinance it to accommodate the transaction,
which may include the support of Holdings or its afffiliates. We expect to borrow approximately $76.1 million on the new credit facility at closing, a reduction of
approximately 44% from our debt outstanding at December 31, 2017. Our net debt at closing will be approximately 48% lower and approximately 3.0 times TTM
EBITDA.
To successfully obtain commitments to refinance our existing credit facility, our lenders required that we significantly de-leverage the Partnership, given general
macro sentiment toward the industry. To ensure the successful refinancing and prior to filing this report, we received a commitment from an affiliate of Holdings
to invest up to $50.0 million of preferred equity (the "PIPE"). The conflicts committee of our board of directors and their legal and financial advisors negotiated the
final terms of the PIPE to ensure fairness to the Partnership. We believe the terms of the PIPE obtained from the affiliate of Holdings are substantially more
attractive than we could have obtained from third parties. The terms of the PIPE include standard and customary provisions frequently found in many recently-
completed PIPE financings in our industry. The proposed PIPE does not include any warrants, which are frequently required by third-party institutional investors,
thereby benefitting us. Key terms include a conversion premium on the PIPE that is 15% greater than our common unit trailing closing price at the time of
issuance. The holder of the preferred units will be entitled to receive quarterly distributions that represent an annual return of 9.5% on the investment. The
Partnership was able to negotiate very favorable terms affording flexibility on the amount paid in cash versus amounts paid-in-kind (“PIK”). We are only required
to pay 2.5% in cash and will have the option to PIK the remaining 7.0% for a period of time. Additionally, the holder will not be able to convert until after the third
anniversary. 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. We were not required to pay customary origination fees associated with this PIPE investment, saving us a substantial amount of cost. Finally, another
important benefit we have negotiated is the ability to redeem the PIPE after the third anniversary of the closing date on favorable terms.
70
These cash payments (from cash on hand and from the sale of Pecos as outlined above), combined with the up to $50.0 million of proceeds from the issuance of the
PIPE, should allow us to reduce our outstanding debt balance from approximately $136.9 million to approximately $76.1 million (or 44%). The significant
decrease in leverage resulting from the refinancing should significantly reduce our interest expense and improve our distributable cash flow and our coverage ratio.
In addition, our existing credit facility has significant unused capacity on which we have paid non-use fees. Such non-use fees will be lower under the new credit
facility.
Before closing on the PIPE, we will also fully check the market to ensure that no better alternatives are available. To accomplish this, we have retained a financial
advisor to determine if more favorable PIPE terms can be obtained from an independent third party and to explore strategic alternatives to determine if any more
attractive opportunities may exist for the Partnership. The affiliate of Holdings providing the required PIPE commitment will not require any compensation if the
Partnership is able to obtain better terms from an unaffiliated third party.
We plan to continue our focus on improving our operating results through a combination of 1) enhanced business development efforts in our Pipeline Inspection
and Integrity Services segments with our continued focus on higher-margin services; 2) the rebuilding of our Orla, Texas facility that was struck by lightning in
January 2017; 3) the rebuilding of our Grassy Butte, North Dakota facility that was struck by lightning in July 2017; and 4) continuing to expand our North Dakota
business through the pursuit of new pipeline gathering opportunities, and to generally take advantage of the increased activity as a result of increased rig count,
commodity prices, and renewed interest in the Williston Basin.
Holdings has been very supportive of the Partnership during the recent economic downturn and has provided sponsor support of $6.3 million during the year ended
December 31, 2016 and $4.1 million during the year ended December 31, 2017 for no consideration. We believe that the owners of Holdings, who collectively own
approximately 64.0% of our common units, remain fully aligned with our minority unitholders and have the financial wherewithal and the incentive to continue to
support us to help us maintain compliance with the financial ratio covenants through the maturity date of the new credit agreement. This alignment of interest is
further demonstrated by an affiliate of Holdings’ commitment to offer a below-market PIPE to benefit us and complete the refinancing of our credit facility.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements.
Contractual Obligations
A summary of our contractual obligations and other commitments as of December 31, 2017 is shown in the table below.
Total
Less than
1 Year
1 - 3 Years
3 - 5 Years
5 Years
More than
(in
thousands)
Long-term debt (current portion)
Operating lease obligations
$
136,900 $
3,682
136,900 $
626
— $
1,056
— $
998
Total
$
140,582 $
137,526 $
1,056 $
998 $
—
1,002
1,002
We can exit our headquarters office building which represents approximately $3.3 million of the operating lease obligations after 18 months (the original lease
term is 84 months) with the payment of a penalty.
71
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below.
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market
risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil, natural gas, and NGL prices and interest rates. The disclosures are not
meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. None of our market risk sensitive instruments were
entered into for speculative trading purposes.
Commodity Price Risk
We are exposed to the impact of market fluctuations in the prices of crude oil in Water Services. Both our profitability and our cash flow are affected by volatility
in the prices of crude oil. Crude oil prices are impacted by changes in the supply and demand, as well as market uncertainty. For a discussion of the volatility of
crude oil prices, please read “ Risk
Factors
.” Adverse effects on our cash flow from reductions in crude oil prices could adversely affect our ability to make cash
distributions to unitholders. We do not hedge our exposure to crude oil prices.
Approximately 0.2% of our consolidated revenues in 2017 were derived from sales of commodities. A hypothetical change in commodity prices of 10% would
result in an increase or decrease of our revenues derived from sales of commodities of approximately $0.1 million. Increases or decreases in commodity prices can
also result in changes in demand for our wastewater disposal and pipeline inspection and integrity services resulting in an increase or decrease of our revenues and
gross margins.
Interest Rate Risk
We currently have exposure to changes in interest rates on our indebtedness associated with our Credit Agreement. We may implement swap or cap structures to
mitigate our exposure to interest rate risk; however, we do not currently have any swaps or cap structures in place. Accordingly, as of December 31, 2017, our
exposure consists of floating interest rate fluctuations on our outstanding indebtedness under our Credit Agreement of $136.9 million. A hypothetical change in
interest rates of 1.0% would result in an increase or decrease of our annual interest expense of approximately $1.4 million.
The credit markets have recently experienced historical lows in interest rates. As the overall economy strengthens, it is possible that monetary policy will continue
to tighten further, resulting in higher interest rates to counter possible inflation as has been evidenced by recent interest rate hikes by the Federal Reserve. Interest
rates on floating rate credit facilities and future debt offerings could be higher than current levels, causing our financing costs to increase accordingly.
Counterparty and Customer Credit Risk
Our credit exposure generally relates to receivables for services provided. If any significant customer of ours should have credit or financial problems resulting in a
delay or failure to repay the amounts they owe to us, this could have a material adverse effect on our business, financial condition, results of operations or cash
flows. In addition, any downgrade of our customers’ receivables from investment grade (defined as BBB- or higher by S&P or Baa3 or higher by Moody’s) could
reduce our borrowing capacity or potentially place the Partnership at risk of default on the working capital revolving credit facility of our Credit Agreement. The
result of downgrades of our customers’ receivables could have a material adverse effect on our business, financial condition, results of operations, or cash flows.
During 2017, approximately 81.4% of our revenues were earned from customers that were rated investment grade.
72
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The following information is included in this Item 8:
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2017 and 2016
Consolidated Statements of Operations for the years ended December 31, 2017, 2016 and 2015
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2017, 2016 and 2015
Consolidated Statement of Owners’ Equity for the years ended December 31, 2017, 2016 and 2015
Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015
Notes to Consolidated Financial Statements
73
Page 73
Page 74
Page 75
Page 76
Page 77
Page 78
Page 79
Report of Independent Registered Public Accounting Firm
To the Limited Partners of Cypress Energy Partners, L.P.
and the Board of Directors of Cypress Energy Partners, GP, LLC,
General Partner of Cypress Energy Partners, L.P.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Cypress Energy Partners, L.P. (the “Partnership”) as of December 31, 2017 and 2016, 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, 2017, 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, 2017 and 2016, and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 2017, 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, and
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 23, 2018
74
CYPRESS ENERGY PARTNERS, L.P.
Consolidated Balance Sheets
As of December 31, 2017 and 2016
(in
thousands,
except
unit
data)
ASSETS
Current assets:
Cash and cash equivalents
Trade accounts receivable, net
Prepaid expenses and other
Assets held for sale
Total current assets
Property and equipment:
Property and equipment, at cost
Less: Accumulated depreciation
Total property and equipment, net
Intangible assets, net
Goodwill
Other assets
Total assets
LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable
Accounts payable - affiliates
Accrued payroll and other
Liabilities held for sale
Income taxes payable
Current portion of long-term debt (Note 6)
Total current liabilities
Long-term debt
Deferred tax liabilities
Asset retirement obligations
Total liabilities
Commitments and contingencies - Note 12
Owners’ equity:
Partners’ capital:
Common units (11,889,958 and 5,945,348 units outstanding at December 31, 2017 and 2016, respectively)
Subordinated units (5,913,000 units outstanding at December 31, 2016)
General partner
Accumulated other comprehensive loss
Total partners’ capital
Noncontrolling interests
Total owners’ equity
Total liabilities and owners’ equity
See
accompanying
notes.
75
December 31,
December 31,
2017
2016
$
$
$
$
24,508 $
41,693
2,294
2,172
70,667
22,700
9,312
13,388
25,477
53,435
236
163,203 $
3,757 $
3,173
9,109
97
646
136,293
153,075
—
—
143
153,218
34,614
—
(25,876)
(2,677)
6,061
3,924
9,985
163,203 $
26,693
38,482
1,042
—
66,217
22,459
7,840
14,619
29,624
56,903
149
167,512
1,690
1,638
7,585
—
1,011
—
11,924
135,699
362
139
148,124
(7,722)
50,474
(25,876)
(2,538)
14,338
5,050
19,388
167,512
Consolidated Statements of Operations
For the Years Ended December 31, 2017, 2016 and 2015
(in
thousands,
except
unit
and
per
unit
data)
Revenues
Costs of services
Gross margin
Operating costs and expense:
General and administrative
Depreciation, amortization and accretion
Impairments
Gain on asset disposals, net
Operating income (loss)
Other income (expense):
Interest expense, net
Foreign currency gains
Other, net
Net income (loss) before income tax expense
Income tax expense
Net income (loss)
Net income (loss) attributable to noncontrolling interests
Net income (loss) attributable to partners / controlling interests
Net loss attributable to general partner
Net income attributable to limited partners
Net income attributable to limited partners allocated to:
Common unitholders
Subordinated unitholders
Net income per common limited partner unit:
Basic
Diluted
Net income per subordinated limited partner unit - basic and diluted
Weighted average common units outstanding:
Basic
Diluted
2017
2016
2015
$
286,342 $
252,739
33,603
297,997 $
262,517
35,480
371,191
326,261
44,930
21,055
4,443
3,598
(570)
5,077
(7,335)
732
199
(1,327)
596
(1,923)
(1,110)
(813)
(4,050)
3,237 $
3,237 $
—
3,237 $
21,853
4,861
10,530
—
(1,764)
(6,559)
—
356
(7,967)
1,195
(9,162)
(4,499)
(4,663)
(6,298)
1,635 $
819 $
816
1,635 $
0.29 $
0.29 $
0.14 $
0.13 $
— $
0.14 $
23,795
5,427
6,645
—
9,063
(5,656)
—
1,136
4,543
452
4,091
599
3,492
(648)
4,140
2,071
2,069
4,140
0.35
0.35
0.35
11,151,646
11,253,069
5,934,226
6,090,103
5,918,608
5,918,608
$
$
$
$
$
$
Weighted average subordinated units outstanding - basic and diluted
729,000
5,913,000
5,913,000
See
accompanying
notes.
76
CYPRESS ENERGY PARTNERS, L.P.
Consolidated Statements of Comprehensive Income (Loss)
For the Years Ended December 31, 2017, 2016 and 2015
(in
thousands)
Net income (loss)
Other comprehensive income (loss) - foreign currency translation
Comprehensive income (loss)
2017
2016
2015
$
$
(1,923) $
(139)
(9,162) $
253
4,091
(1,742)
(2,062) $
(8,909) $
2,349
Comprehensive income (loss) attributable to noncontrolling interests
Comprehensive income (loss) attributable to general partner
(1,110)
(4,050)
(4,499)
(6,298)
142
(648)
Comprehensive income (loss) attributable to limited partners
$
3,098 $
1,888 $
2,855
See
accompanying
notes.
77
CYPRESS ENERGY PARTNERS, L.P.
Consolidated Statement of Owners’ Equity
For the Years Ended December 31, 2017, 2016 and 2015
(in
thousands)
General
Partner
Common
Units
Subordinated
Units
Accumulated
Other
Comprehensive
Loss
Non
controlling
Interests
Total Owners’
Equity
Owners’ equity at December 31, 2014
$
1,999 $
6,285 $
66,096 $
(525) $
26,573 $
100,428
Net income (loss)
Foreign currency translation adjustment
Acquisition of 49.9% interest in the TIR Entities
Acquisition of 51% interest in Brown Integrity, LLC
Acquisition of 49% interest in Cypress Energy
Services, LLC (Note 11)
Contributions attributable to General Partner
Distributions to limited partners
Distributions to noncontrolling interests
Equity-based compensation
(648)
—
(27,729)
—
—
648
—
(146)
—
2,071
—
—
—
470
—
(9,620)
—
1,047
2,069
—
—
—
470
—
(9,612)
—
120
—
(1,285)
(981)
—
—
—
—
—
—
599
(457)
(23,878)
9,497
(940)
—
—
(1,421)
—
4,091
(1,742)
(52,588)
9,497
—
648
(19,232)
(1,567)
1,167
Owners’ equity at December 31, 2015
(25,876)
253
59,143
(2,791)
9,973
40,702
Net income (loss)
Foreign currency translation adjustment
Contributions attributable to General Partner
Distributions to limited partners
Distributions to noncontrolling interests
Equity-based compensation
Taxes paid related to net share settlement of equity-
based compensation
(6,298)
—
6,298
—
—
—
819
—
—
(9,646)
—
959
816
—
—
(9,612)
—
127
—
(107)
—
—
253
—
—
—
—
—
(4,499)
—
—
—
(424)
—
(9,162)
253
6,298
(19,258)
(424)
1,086
—
(107)
Owners’ equity at December 31, 2016
(25,876)
(7,722)
50,474
(2,538)
5,050
19,388
Net income (loss)
Foreign currency translation adjustment
Contributions attributable to General Partner
Distributions to limited partners
Distributions to noncontrolling interests
Conversion of Subordinated Units to Common Units
Equity-based compensation
Taxes paid related to net share settlement of equity-
(4,050)
—
4,050
—
—
—
—
3,237
—
—
(9,905)
—
48,111
1,017
based compensation
—
(124)
Owners’ equity at December 31, 2017
(25,876)
34,614
—
—
—
(2,405)
—
(48,111)
42
—
—
—
(139)
—
—
—
—
—
—
(1,110)
—
—
—
(16)
—
—
(1,923)
(139)
4,050
(12,310)
(16)
—
1,059
—
(124)
(2,677)
3,924
9,985
See
accompanying
notes.
78
CYPRESS ENERGY PARTNERS, L.P.
Consolidated Statements of Cash Flows
For the Years Ended December 31, 2017, 2016 and 2015
(in
thousands)
2017
2016
2015
Operating activities:
Net income (loss)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
$
(1,923) $
(9,162) $
Depreciation, amortization and accretion
Impairments
(Gain) loss on asset disposals, net
Interest expense from debt issuance cost amortization
Equity-based compensation expense
Equity in earnings of investee
Distributions from investee
Deferred tax benefit, net
Non-cash allocated expenses
Foreign currency gains
Changes in assets and liabilities:
Trade accounts receivable
Prepaid expenses and other
Accounts payable and accrued payroll and other
Income taxes payable
Net cash provided by operating activities
Investing activities:
Proceeds from fixed asset disposals, including insurance proceeds
Acquisition of 49.9% interest in the TIR Entities
Cash paid for acquisition of 51% interest in Brown Integrity, LLC, net of cash acquired
Purchases of property and equipment
Net cash used in investing activities
Financing activities:
Advances on long-term debt
Repayments of long-term debt
Taxes paid related to net share settlement of equity-based compensation
Contributions from general partner
Distributions to limited partners
Distributions to noncontrolling members
Net cash provided by (used in) financing activities
Effect of exchange rates on cash
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents, beginning of period
Cash and cash equivalents, end of period
Non-cash items:
Accrued capital expenditures
Supplemental cash flow disclosures:
Cash taxes paid
Cash interest paid
See
accompanying
notes.
79
5,544
3,598
(570)
594
1,059
(149)
75
(372)
1,750
(732)
(3,406)
(1,321)
4,471
(365)
8,253
2,304
—
—
(3,345)
(1,041)
—
—
(124)
2,300
(12,310)
(16)
(10,150)
5,788
10,530
(19)
570
1,086
(309)
200
(24)
3,798
—
9,871
1,350
478
662
24,819
46
—
—
(1,376)
(1,330)
—
(4,000)
(107)
2,500
(19,258)
(424)
(21,289)
4,091
6,004
6,645
(1)
547
1,167
(102)
100
(32)
648
—
9,039
233
(1,222)
(196)
26,921
2
(52,588)
(10,436)
(1,857)
(64,879)
68,800
(5,500)
—
—
(19,232)
(1,567)
42,501
753
343
(1,150)
(2,185)
26,693
24,508 $
2,543
24,150
26,693 $
3,393
20,757
24,150
567 $
— $
100
1,350 $
6,842
551 $
5,859
579
5,167
$
$
$
1. Organization and Operations
CYPRESS ENERGY PARTNERS, L.P.
Notes to Consolidated Financial Statements
Cypress Energy Partners, L.P. (“we”, “us”, “our”, or the “Partnership”) is a Delaware limited partnership formed in 2013 to provide independent pipeline
inspection and integrity services to producers and pipeline companies and to provide salt water disposal and other water and environmental services to U.S.
onshore oil and natural gas producers and trucking companies. 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”), Integrity Services, and Water and Environmental Services (“Water
Services”) reportable segments. Pipeline Inspection provides pipeline inspection and other services to energy exploration and production (“E&P”), public utility
companies (“PUCs”), and midstream companies and their vendors throughout the United States and Canada. The inspectors of Pipeline Inspection perform a
variety of inspection services on midstream pipelines, gathering systems, and distribution systems, including data gathering and supervision of third-party
construction, inspection, and maintenance and repair projects.
Integrity Services provides independent hydrotesting integrity services to pipeline owners and pipeline construction companies located throughout the United
States. Field personnel in this segment primarily perform hydrostatic testing on newly-constructed and existing natural gas and petroleum pipelines.
Water Services provides services to oil and natural gas producers and trucking companies through its ownership and operation of eight commercial salt water
disposal facilities in the Bakken Shale region of the Williston Basin in North Dakota and one in the Permian Basin in Texas. All of the facilities utilize specialized
equipment and remote monitoring to minimize downtime and increase efficiency for peak utilization. These facilities also contain oil skimming processes that
remove oil from water delivered to the sites. In addition to these salt water disposal facilities, we provide management and staffing services for a third-party salt
water disposal facility pursuant to a management agreement (see Note 11). We also own a 25% interest in this managed facility.
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.
In May 2015, the Partnership acquired 51% of Brown Integrity, LLC (“Brown”) and Brown was included in our Consolidated Financial Statements subsequent to
that date. Accordingly, Brown’s operations were only included in our Consolidated Statement of Operations for approximately 8 months in the year ended
December 31, 2015.
80
CYPRESS ENERGY PARTNERS, L.P.
Notes to Consolidated Financial Statements - Continued
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 the Partnership’s Consolidated 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 amounts of expected future cash flows used in determining possible impairments of long-
lived assets, the determination of fair values of assets acquired and liabilities assumed in business combinations, useful lives of property, equipment and intangible
assets, and the amount of future asset retirement obligations. 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
The Partnership utilizes 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. The
Partnership uses market data or assumptions that it believes 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. The Partnership applies 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 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.
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 the years ended December 31, 2017, 2016, and 2015, Holdings incurred overhead expenses on behalf of the Partnership totaling $1.8 million, $3.8 million,
and $0.6 million, respectively. These costs represent administrative costs incurred by Holdings in excess of amounts charged to the Partnership under our omnibus
agreement. These expenses are reflected as general
and
administrative
and as a component of the net loss attributable to the general partner in the Consolidated
Statements of Operations for the years ended December 31, 2017, 2016, and 2015 and as contributions
attributable
to
General
Partner
in the Consolidated
Statement of Owners’ Equity.
In addition to incurring the expenses described above, Holdings provided the Partnership with additional financial support by making cash contributions of $2.3
million and $2.5 million in 2017 and 2016, respectively, as a reimbursement for certain expenditures incurred by the Partnership. These payments 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
the
general
partner
in the Consolidated Statements of Operations for the years ended December 31, 2017 and 2016.
Cash and Cash Equivalents
The Partnership considers all investments purchased with initial maturities of three months or less to be cash equivalents. Cash equivalents consist primarily of
investments in highly-liquid securities. The carrying amounts of cash and cash equivalents reported in the balance sheet approximate fair value.
As of December 31, 2017, 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 two financial institutions, and therefore in excess of the FDIC or CDIC insurance limits. We periodically assess the financial condition of the institutions
where we deposit funds, and we believe our credit risk related to these funds was minimal at December 31, 2017.
81
Accounts Receivable, Allowance for Bad Debts and Concentration of Credit Risk
CYPRESS ENERGY PARTNERS, L.P.
Notes to Consolidated Financial Statements - Continued
We operate in the United States and Canada and grant unsecured credit to customers under normal industry standards and terms, and have established policies and
procedures that allow for an evaluation of each customer’s creditworthiness. We determine accounts receivable allowances for bad debts based on our assessment
of the creditworthiness of our customers. Trade receivables are written off against the allowance when collection efforts have been exhausted and the receivable is
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 less than $0.1 million and $0.6 million at
December 31, 2017 and 2016, respectively. We recorded bad debt expense of approximately $0.0 million in the years ended December 31, 2017 and 2016 and $0.1
million in the year ended December 31, 2015. During the year ended December 31, 2017, we received $0.3 million on accounts receivable previously written off
which we recorded as a reduction to general
and
administrative
expense
on our Consolidated Statement of Operations.
We had one and three customers that each represented more than 10% of total accounts receivable as of December 31, 2017 and 2016, respectively. If any of these
customers were to default on their payment obligations, we may not be able to replace these customers in a timely fashion, on favorable terms, or at all. In
addition, any downgrade of our customers’ receivables from investment grade (defined as BBB- or higher by S&P or Baa3 or higher by Moody’s) could reduce our
borrowing capacity or potentially place the Partnership at risk of default on the working capital revolving credit facility of our Credit Agreement. The result of
downgrades of our customers’ receivables could have a material adverse effect on our business, financial condition, results of operations, or cash flows.
The majority of our revenues are generated in the United States. Total revenues generated in Canada were $23.4 million, $31.2 million, and $27.5 million for the
years ended December 31, 2017, 2016, and 2015, respectively.
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.
82
Debt Issuance Costs
CYPRESS ENERGY PARTNERS, L.P.
Notes to Consolidated Financial Statements - Continued
Debt issuance costs represent fees and expenses associated with securing the Partnership’s 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 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 90% or more 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.
The Partnership evaluates uncertain tax positions for recognition and measurement in the Consolidated Financial Statements. To recognize a tax position, the
Partnership determines 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. The Partnership had no uncertain tax positions that required recognition in the financial
statements at December 31, 2017 or 2016. Any interest or penalties would be recognized as a component of income tax expense.
83
Revenue Recognition
CYPRESS ENERGY PARTNERS, L.P.
Notes to Consolidated Financial Statements - Continued
Revenues are recognized when there is persuasive evidence that an arrangement exists, delivery has occurred or services have been rendered, the price is fixed or
determinable, and collectability is reasonably assured. Revenues related to pipeline inspection and integrity services are recognized when the services are
performed. Water disposal revenues are recognized upon receipt of the wastewater at our disposal facilities. Revenues from sales of oil that is recovered in the
process of treating wastewater are recognized when the oil is delivered to the customer.
Unit-Based Compensation
Our General Partner adopted a long-term incentive plan (“LTIP”) under which the Partnership grants equity-based compensation to employees and directors. The
cost of such equity-based compensation is measured based on the grant-date fair value of those instruments. That cost is recognized on a straight-line basis over the
requisite service period, as described in Note 10.
Net Income (Loss) Per Unit
We utilize the two-class method in calculating basic and diluted income (loss) per common and subordinated unit. Net
income
(loss)
attributable
to
partners
/
controlling
interests
is allocated to the general partner and limited partners in accordance with their respective partnership ownership percentages, after giving
effect to any specifically allocated items.
For the year ended December 31, 2017, there were 101,423 dilutive phantom restricted units. For the year ended December 31, 2016, there were 155,877 dilutive
phantom restricted units. For the year ended December 31, 2015, there were no dilutive phantom restricted units.
Accrued Payroll and Other
Accrued
payroll
and
other
on our Consolidated Balance Sheets includes the following:
Accrued payroll and other
Accrued payroll
Customer deposits
Other
December 31,
2017
December 31,
2016
(in
thousands)
6,893 $
1,510
706
9,109 $
5,594
1,361
630
7,585
$
$
84
Fair Value of Financial Instruments
CYPRESS ENERGY PARTNERS, L.P.
Notes to Consolidated Financial Statements - Continued
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 the Partnership’s 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 salt water disposal facility in the Water Services segment, as these asset groups represent the
lowest level as which cash flows are separately identifiable.
Goodwill
At December 31, 2017 and 2016, the Partnership had $53.4 million and $56.9 million of goodwill, respectively. Goodwill is not amortized, but is subject to
annual reviews 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, Integrity Services, and Water 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).
85
Identifiable Intangible Assets
CYPRESS ENERGY PARTNERS, L.P.
Notes to Consolidated Financial Statements - Continued
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 Interest
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. Prior to February 1, 2015 when the Partnership acquired the remaining 49.9%
interest in the TIR Entities, the portion of the net income (loss) and net assets of the TIR entities attributable to outside owners were also included in net
income
(loss)
attributable
to
noncontrolling
interests
and noncontrolling
interests
, respectively.
Business Combinations
The Partnership evaluates all potential acquisitions and changes in control to determine whether it has 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 2017, lightning strikes and the resultant fires destroyed the surface equipment at two of our salt water disposal facilities. We carried property damage and
cleanup insurance on both facilities, and the proceeds we received on these policies exceeded the net book value of the destroyed property and the cleanup costs we
incurred. The $0.6 million reported in gain
on
assets
disposals,
net
in our consolidated statement of operations for the year ended December 31, 2017 represents
the excess of the insurance proceeds over the net book value of the assets destroyed and the cleanup costs we incurred.
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, 2017 includes $2.7 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 sell or 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 Statement 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 loss of our largest Canadian customer, we report currency translation
adjustments on these intercompany payables and receivables within foreign
currency
gains
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 translations adjustments on other Canadian activity and balances.
86
CYPRESS ENERGY PARTNERS, L.P.
Notes to Consolidated Financial Statements – Continued
New Accounting Standards
In 2017, the Partnership adopted the following new accounting standards issued by the Financial Accounting Standards Board (“FASB”):
The FASB issued Accounting Standards Update (“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 the 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 that may impact our Consolidated Financial Statements which we have not yet adopted include:
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 and this new guidance is the recognition on the balance sheet of certain lease assets and lease liabilities by lessees for those leases
classified as operating leases under previous GAAP. The amendments in this ASU are effective for fiscal years beginning after December 15, 2018, including
interim periods within those fiscal years. Early adoption is permitted. We are currently examining the guidance provided in the ASU and determining the
impact this guidance will have on our Consolidated Financial Statements.
The FASB issued 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. We will be required to adopt this standard in 2018 and to apply its provisions either retrospectively to each prior reporting period presented or
prospectively with the cumulative effect of initially applying the ASU recognized at the date of initial application (modified retrospective method). We are
adopting ASU 2014-09 utilizing the modified retrospective transition approach, effective January 1, 2018 by recognizing the cumulative effect of initially
applying ASU 2014-09 for periods prior to January 1, 2018 which we expect to have an immaterial impact on the opening balance of total owners’ equity in
the Consolidated Balance Sheet.
We are in the final stages of evaluating the impact ASU 2014-09 will have on our financial statements. For each operating segment we have conducted a
formal contract review process to evaluate the impact of ASU 2014-09. We have substantially completed our evaluation and have not identified any material
change in how we recognize revenue. Financial systems and internal controls necessary for adoption were implemented effective January 1, 2018.
87
CYPRESS ENERGY PARTNERS, L.P.
Notes to Consolidated Financial Statements - Continued
3. Property and Equipment
Property and equipment consist of the following, recorded at cost, as of December 31, 2017 and 2016:
Asset Category
Useful Lives (years)
2017
2016
December 31,
Land
Land improvements
Buildings and leasehold improvements
Facilities, wells and equipment
Computer and office equipment
Vehicles and other
Construction-in-progress
Less accumulated depreciation
Net property, plant and equipment
15
30 - 39
5 - 15
3 - 9
3 - 5
$
$
(in
thousands)
1,218 $
513
1,179
15,399
1,171
498
2,722
22,700
(9,312)
13,388 $
1,278
698
1,242
17,563
1,268
410
—
22,459
(7,840)
14,619
Depreciation expense is computed using the straight-line method over the estimated useful lives of the assets. Depreciation expense was $2.7 million, $2.9 million
and $3.1 million for the Partnership for the years ended December 31, 2017, 2016 and 2015, respectively, of which $1.1 million, $0.9 million and $0.6 million was
included as a component of costs of services for the years ended December 31, 2017, 2016 and 2015, respectively. As a result of our impairment analyses, we
recorded impairments to certain property and equipment which resulted in decreases in accumulated depreciation of $0.3 million, $0.3 million $1.3 million in
2017, 2016 and 2015, respectively.
During 2017, 2016 and 2015, we recorded impairments of property and equipment at certain of our salt water disposal facilities. At each of these facilities, we had
experienced revenue and volume decreases due to lower commodity pricing and increasing competition and had forecasted decreases in drilling activity over the
remaining life of the underlying assets. Given these indicators of impairment, we compared our estimates of undiscounted future cash flows from the facilities to
the carrying amounts of the long-lived assets of the facilities, and determined that the carrying values were no longer recoverable. We recognized impairments on
the facilities totaling $0.7 million, $2.1 million and $6.6 million, included within Impairments
on the Consolidated Statements of Operations for the years ended
December 31, 2017, 2016 and 2015, respectfully. At the time of the impairment for each of these facilities, we impaired the full carrying value of the property and
equipment (although, for the facilities at which we own the land, 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. Because of the uncertainties surrounding the salt water disposal facilities and the market conditions,
including our ability to generate and maintain sufficient revenues to operate the facilities profitably, our estimate of expected future cash flows may change in the
future resulting in the need to further adjust our determinations of fair value.
In January 2017, one of our facilities was struck by lightning. The downhole facilities were not damaged but the above ground facilities were totally destroyed and
accordingly the net cost of all above ground facilities were written off. In July 2017, we experienced another lightning strike at our Grassy Butte salt water disposal
facility that initiated a fire that effectively destroyed the surface storage equipment at the facility. It did not damage our pumps, electrical, housing, office, or
downhole facilities. We had property damage insurance covering the surface facilities. The proceeds from these insurance policies in excess of the net property and
equipment written off are included in Gain
on
asset
disposals,
net
in our Consolidated Statements of Operations.
88
CYPRESS ENERGY PARTNERS, L.P.
Notes to Consolidated Financial Statements - Continued
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:
Balance - December 31, 2015
Impairments
Foreign currency translation
Balance - December 31, 2016
Impairments
Foreign currency translation
Reclassified to assets held for sale
Balance - December 31, 2017
PIS
IS
W&ES
Total
$
$
$
40,206 $
—
41
40,247 $
—
97
—
40,344 $
(in
thousands)
9,992 $
(8,411)
—
1,581 $
(1,581)
—
—
— $
15,075 $
—
—
15,075 $
—
—
(1,984)
13,091 $
65,273
(8,411)
41
56,903
(1,581)
97
(1,984)
53,435
Goodwill is not amortized, but is subject to annual reviews on November 1 (or 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. We have determined that the Pipeline Inspection, Integrity Services and Water Services
operating segments are the appropriate reporting units for testing goodwill for impairment.
Integrity Services Segment
In the Integrity Services segment, we experienced declining revenues in 2016 due to the overall energy economy, including decreased new infrastructure
construction, postponement of inspection and integrity activity by our E&P customers, and reduced revenues and margins on completed contracts due to increased
competition, among other factors. Given these indicators of impairment, we performed an impairment assessment in the second quarter of 2016 of the $10.0
million of goodwill that was attributable to our Integrity Services segment. We estimated the fair value of the reporting unit 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. To estimate the fair value of the reporting unit and the implied fair value
of goodwill under a hypothetical acquisition of the reporting unit, we assumed a tax structure wherein a buyer would obtain a step-up in the tax basis of the net
assets acquired. Significant assumptions used in valuing the reporting unit included revenue growth rates ranging from 2% to 5% annually and a discount rate of
17.5%. In our assessment, the carrying value of the reporting unit, including goodwill, exceeded its estimated fair value. We then determined through our
hypothetical acquisition analysis that the fair value of goodwill was impaired. As a result, we recorded an impairment loss of $8.4 million and reduced the carrying
value of goodwill to $1.6 million in the second quarter of 2016. This impairment loss is included in Impairments
on the Consolidated Statement of Operations for
the year ended December 31, 2016.
In the first quarter of 2017, we recorded an impairment to the remaining $1.6 million carrying value of the goodwill of the Integrity 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 Integrity 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 Integrity 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 the year ended December 31, 2017.
Water Services Segment
We completed our annual goodwill impairment assessment as of November 1, 2017, and concluded that the goodwill of the Water Services segment was not
impaired. We performed a qualitative analysis that took into consideration recent favorable trends (including recent increases in crude oil prices and increased
customer activity at certain of our facilities) and the fact that we sold one of our salt water disposal facilities in January 2018 at a price that exceeded its carrying
value. Based on these qualitative considerations, we concluded that carrying value of the goodwill of the Water 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 January 2018, we sold our subsidiary that owns a salt water disposal facility in Pecos, TX to an unrelated party. The assets and liabilities of the Pecos, TX salt
water disposal facility are presented as held for sale in the Water Services segment as of December 31, 2017. Included in the Assets
held
for
sale
on our
Consolidated Balance Sheet is approximately $2.0 million which was previously included in Goodwill
on our Consolidated Balance Sheet (see Note 15 Subsequent
Events).
Pipeline Inspection Segment
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, market capitalization,
current customer relationships and projects, and the impact of crude oil 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.
89
CYPRESS ENERGY PARTNERS, L.P.
Notes to Consolidated Financial Statements - Continued
5. Intangible Assets
Intangible assets consist of the following at December 31, 2017 and 2016:
Asset Category
Useful Lives (years)
2017
2016
December 31,
Customer relationships
Contracts
Non-compete agreements
Trademarks and trade names
Inspector database
Less accumulated amortization
Net intangibles
5 - 20
3
3
10
10
$
$
(in
thousands)
22,853 $
241
143
11,679
2,080
36,996
(11,519)
25,477 $
24,261
241
143
12,079
2,080
38,804
(9,180)
29,624
Amortization expense for the years ended December 31, 2017, 2016 and 2015 was $2.8 million, $2.9 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)
2018
2019
2020
2021
2022
Thereafter
2,719
2,697
2,677
2,668
2,668
12,048
25,477
$
In the first quarter of 2017, the largest customer of the Canadian subsidiary of our Pipeline Inspection segment completed a bid process and selected different
service providers for its inspection projects. During the year ended December 31, 2017, pipeline inspection services to this customer accounted for approximately
$18.8 million of revenue and $1.3 million of gross margin, which represented approximately 81% of the revenues and 86% of the gross margin of our Canadian
operations (and approximately 7% of our consolidated revenues and 4% of our consolidated gross margin for the year ended December 31, 2017). In consideration
of the loss of this contract, 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. We continue to perform inspection and integrity work for customers in Canada.
90
6. Credit Agreement
CYPRESS ENERGY PARTNERS, L.P.
Notes to Consolidated Financial Statements - Continued
The Partnership is party to a credit agreement (as amended, the “Credit Agreement”) that provides up to $200.0 million in borrowing capacity, subject to certain
limitations. The Credit Agreement includes a working capital revolving credit facility (“Working Capital Facility”) which provides up to $75.0 million in
borrowing capacity to fund working capital needs and an acquisition revolving credit facility (“Acquisition Facility”) which provides up to $125.0 million in
borrowing capacity to fund acquisitions and expansion projects. In addition, the Credit Agreement contains an accordion feature that allows us to increase the
availability under the facilities by an additional $125.0 million if lenders agree to increase their commitments. The Credit Agreement matures on December 24,
2018.
Outstanding borrowings at December 31, 2017 and 2016 under the Credit Agreement were as follows:
Working capital facility
Acquisition facility
Total borrowings
Debt issuance costs
Long-term debt, including current portion
Current portion of long-term debt
Long-term debt
December 31,
2017
2016
(in thousands)
$
$
48,000 $
88,900
136,900
607
136,293
136,293
— $
48,000
88,900
136,900
1,201
135,699
—
135,699
The carrying value of the partnership’s 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).
Borrowings under the Working Capital Facility are limited by a monthly borrowing base calculation as defined in the Credit Agreement. If, at any time,
outstanding borrowings under the Working Capital Facility exceed the Partnership’s calculated borrowing base, a principal payment in the amount of the excess is
due upon submission of the borrowing base calculation. Available borrowings under the Acquisition Facility may be limited by certain financial covenant ratios as
defined in the Credit Agreement. The obligations under our Credit Agreement are secured by a first priority lien on substantially all assets of the Partnership.
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 1.25% to 2.75% per
annum (“Base Rate Borrowing”) or (ii) an adjusted LIBOR rate plus a margin of 2.25% to 3.75% per annum (“LIBOR Borrowings”). The applicable margin is
determined based on the leverage ratio of the Partnership, as defined in the Credit Agreement. Generally, the interest rate on our Credit Agreement borrowings
ranged between 3.90% and 5.32% for the year ended December 31, 2017, 3.54% and 4.52% for the year ended December 31, 2016 and, 2.68% and 4.17% for the
year ended December 31, 2015. 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. Weighted average interest rate for the Working Capital and Acquisition Facilities were 4.75% and 5.29%,
respectively, for the year ended December 31, 2017. Commitment fees are charged at a rate of 0.50% on any unused credit and are payable quarterly.
Our Credit Agreement contains various customary affirmative and negative covenants and restrictive provisions. Our Credit Agreement also requires maintenance
of certain financial covenants, including a combined total adjusted leverage ratio (as defined in our Credit Agreement) of not more than 4.0 to 1.0 and an interest
coverage ratio (as defined in our Credit Agreement) of not less than 3.0 to 1.0. At December 31, 2017, our combined total adjusted leverage ratio was 3.7 to 1.0
and our interest coverage ratio was 3.1 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 our Credit Agreement, the lenders may declare any outstanding principal of our Credit Agreement debt, together with accrued and
unpaid interest, to be immediately due and payable and may exercise the other remedies set forth or referred to in our Credit Agreement. We were in compliance
with all debt covenants as of December 31, 2017. Working capital borrowings, which are fully secured by the Partnership’s net working capital, are subject to a
monthly borrowing base and are excluded from the Partnership’s debt compliance ratios.
In addition, our Credit Agreement restricts our ability to make distributions on, or redeem or repurchase, our equity interests. 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 our Credit Agreement, the
borrowers and the guarantors are in compliance with the financial covenants, the borrowing base (which includes 100% of cash on hand) exceeds the amount of
outstanding credit extensions under the Working Capital Facilities by at least $5.0 million, and at least $5.0 million in lender commitments are available to be
drawn under the Working Capital Facility.
91
Refinancing
CYPRESS ENERGY PARTNERS, L.P.
Notes to Consolidated Financial Statements - Continued
Our current $200 million credit facility matures in December 2018 and had approximately $136.9 million outstanding at December 31, 2017. In the fall of 2017,
we began working with our agent on the terms of a new credit facility. In February, we agreed upon a new revised term sheet and in March 2018, we successfully
negotiated commitments for a new revolving credit facility with our existing bank group with a term that extends three years after closing, consistent with the
strategy outlined in our Form 10-Q for the three months ended September 30, 2017.
To reduce leverage, we negotiated the sale of our Pecos, Texas salt water disposal facility and utilized the $4.0 million of proceeds to repay principal on our credit
facility in January, 2018. We plan to use approximately $7.0 million of our cash on hand to repay an additional amount of principal at the time we close on the
new credit facility, sometime in the second quarter. The new credit facility will have a maximum capacity of $80.0 million, with a $20.0 million accordion feature
(for a total of $100.0 million). Under the new credit facility, we will be able to borrow up to 3.75 times our trailing twelve-month adjusted EBITDA (“TTM
EBITDA”) (as adjusted EBITDA is defined in the credit agreement) at the time of closing for senior debt. Additionally, we may incur additional indebtedness
other than the new credit facility, provided the pro forma senior secured leverage ratio may not exceed 3.25 times TTM EBITDA and the total leverage ratio may
not exceed 4.75 times TTM EBITDA. As part of the refinancing, Holdings agreed to waive the omnibus fee to support us in the event leverage exceeds 3.75 times
trailing twelve-month adjusted EBITDA during the term of the facility. The new credit facility will have customary covenants, including but not limited to a
maximum senior leverage ratio of 4.0 times adjusted EBITDA, or 3.25 times senior secured leverage if additional debt not to exceed 1.5 times is incurred, and a
minimum interest coverage ratio of 3.0 times adjusted EBITDA. The new facility will no longer have a required borrowing base calculation and borrowings under
the new agreement will 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 or (ii) a LIBOR
rate plus a margin of 2.5% to 4.0% per annum. The facility will also include a 50 basis point non-use fee consistent with the current facility, and no amortization
will be required during the term which extends three years after closing. We have received commitment letters from banks for the full amount of the facility, and
these commitment letters will remain in effect through May 31, 2018. We expect to borrow approximately $76.1 million on the new credit facility at closing.
To successfully obtain commitments to refinance our existing credit facility, our lenders required that we materially de-leverage the Partnership. To ensure the
successful refinancing and prior to filing this report, we received a commitment from an affiliate of Holdings to invest up to $50.0 million of preferred equity (the
"PIPE"). The conflicts committee of our board of directors and their advisors negotiated and approved the final terms of the PIPE. The terms of the PIPE include
standard and customary provisions for similar type arrangements and the proposed PIPE does not include any warrants, nor will it require payment of any
origination fees. The preferred equity will have a conversion premium that is 15% greater than our common unit trailing closing price at the time of issuance. The
holder of the preferred units will be entitled to receive quarterly distributions that represent an annual return of 9.5% on the investment. 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 12 quarters after closing. After the third anniversary of the closing date, the holder of the preferred units 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.
We expect the $50.0 million of proceeds from the PIPE and the use of $10.8 million of cash on hand to reduce the outstanding balance on the Credit Agreement
from $136.9 million at December 31, 2017 to approximately $76.1 million upon closing of the new credit facility. We believe the new credit facility will support
our current business requirements. We expect to be able to maintain compliance with the financial ratios and other covenants specified in the new credit facility.
Holdings has continued to support the Partnership during the oil and gas economic downturn and has provided sponsor support of $6.3 and $4.1 million during the
year ended December 31, 2016 and 2017 respectively. The owners of Holdings, who collectively own approximately 64.0% of our common units, will waive the
omnibus fee due from us, as required under the new credit facility in order to help us maintain compliance with the financial ratio covenants through the maturity
date of the new credit agreement.
The balance outstanding on the Credit Agreement has been reported within Current
portion
of
long-term
debt
on our Consolidated Balance Sheet at December 31,
2017, based on the fact that the Credit Agreement matures within one year of the balance sheet date.
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).
92
Significant components of income tax expense (benefit) are as follows for the years ended December 31:
CYPRESS ENERGY PARTNERS, L.P.
Notes to Consolidated Financial Statements - Continued
Current tax expense (benefit)
U.S. federal
State
Canadian
Total
Deferred tax expense (benefit)
U.S. federal
State
Canadian
Total
Total income tax expense
2017
2016
(in
thousands)
2015
$
356 $
531
81
968
(7)
(2)
(363)
(372)
527 $
690
3
1,220
(27)
(8)
10
(25)
$
596 $
1,195 $
(123)
501
6
384
45
13
10
68
452
The increase in total income tax expense from 2015 to 2016 is primarily attributable to improved operating results of Tulsa Inspection Resources – PUC, LLC, an
entity that has elected to be taxable as a corporation for federal and state income tax purposes. Revenues and net taxable income of this entity have increased from
the year ended December 31, 2015 to the year ended December 31, 2016. The decrease in total income tax expense from 2016 to 2017 is primarily attributable to
deferred tax effects of intangible asset impairments from our Canadian subsidiary.
Noncurrent deferred tax liabilities of $0.4 million at December 31, 2016 are primarily attributable to the recorded unamortized portion of book intangible assets in
our Canadian subsidiary. These intangible assets were impaired in 2017 with the resulting deferred tax benefit recorded in 2017.
The following table reconciles the differences between the U.S. federal statutory rate of 35% to the Partnership’s income tax expense on the Consolidated
Statements of Operations for the years ended December 31:
Tax (benefit) computed at statutory rate
(Income) loss not subject to federal tax
State income taxes, net of federal benefit
Other
2017
2016
2015
(in
thousands)
$
$
(464) $
682
509
(131)
596 $
(2,788) $
3,336
644
3
1,195 $
1,590
(1,790)
514
138
452
Tax years that remain subject to examination by various taxing authorities for each of our consolidated entities include the years 2015 through 2017. It is the
Partnership’s policy to recognize tax-related interest and penalties as a component of income tax expense in the year incurred. Tax-related interest and penalties
were insignificant in the years ended December 31, 2017, 2016 and 2015.
As of December 31, 2017 or December 31, 2016, the Partnership had no significant unrecognized tax benefits. 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.
93
CYPRESS ENERGY PARTNERS, L.P.
Notes to Consolidated Financial Statements - Continued
8.
Owners’ Equity
Common Units and Subordinated Units
As of December 31, 2017, there are 11,889,958 common units outstanding. As of December 31, 2016 there were 5,945,348 common units and 5,913,000
subordinated 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 common units to common units, items of income (loss) were allocated to
common units and subordinated units equally. The common unitholders had the right to receive the minimum quarterly cash distributions of $0.3875 per common
unit, plus any arrearages in the payment of the minimum quarterly distributions on the common units from prior quarters, before any distributions of available cash
could be made on the subordinated units. For the years ended December 31, 2017, 2016, and 2015, there were no limitations or arrearages related to the quarterly
distributions made by the Partnership.
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 2017,
2016, or 2015.
94
9.
Major Customers
CYPRESS ENERGY PARTNERS, L.P.
Notes to Consolidated Financial Statements - Continued
For the year ended December 31, 2017, 2016 and 2015, three customers individually exceeded 10% of our consolidated total revenues: Enterprise Product Partners,
Pacific Gas and Electric Company and Plains All America Pipeline in 2017, Enbridge Energy Partners, Pacific Gas and Electric Company and Plains All America
Pipeline in 2016 and Enbridge Energy Partners, Enterprise Products Partners and Plains All America Pipeline in 2015. 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. In no
year did a single customer account for more than 15% of our consolidated revenue.
10.
Equity Compensation
Partnership Long-Term Incentive Plan (“LTIP”)
Effective at the closing of the IPO, our General Partner adopted an LTIP that authorized up to 1,182,600 units, representing 10% of the initial outstanding units.
Certain directors and employees of the Partnership have been awarded Phantom Restricted Units (“Units”) under the terms of the LTIP. The fair value of each
award 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 Units during the vesting period. Compensation expense is recognized on a straight-line basis over the vesting period of the grant.
For the years ended December 31, 2017, 2016, and 2015, compensation expense of $1.1 million, $1.1 million and $1.2 million, respectively was recorded under the
LTIP (including expense associated with the Profit Interest Units described below).
The following table sets forth the grants and forfeitures of Units under the LTIP for the years ended December 31, 2017, 2016, and 2015:
Units at December 31, 2014
Units granted
Units vested
Units forfeited
Units at December 31, 2015
Units granted
Units vested
Units forfeited
Units at December 31, 2016
Units granted
Units vested
Units forfeited
Units at December 31, 2017
Number
Weighted
Average
of Unvested Grant Date Fair
Units
Value / Unit
158,353 $
230,310 $
(7,467) $
(19,498) $
361,698 $
346,999 $
(36,505) $
(98,290) $
573,902 $
257,419 $
(44,408) $
(122,404) $
664,509 $
18.11
12.08
19.72
16.92
14.30
6.32
16.17
11.38
9.86
7.02
16.56
9.25
8.42
The majority of the common unit awards 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. However, certain of the awards have different, and typically shorter, vesting periods. Two
grants, totaling 77,495 units, vest three years from the grant dates, contingent upon the recipient meeting certain performance targets. Total unearned compensation
associated with the LTIP at December 31, 2017 and 2016 was $3.2 million and $3.8 million, respectively, with an average remaining life of 2.1 years and 2.4
years, respectively.
In addition to the awards shown in the table 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. Vesting for the Profit Interest Units is retroactive to the initial grant date. Compensation
expense associated with the Profit Interest Units was $0.1 million for each of the three years ended December 31, 2017, 2016 and 2015. The unearned
compensation related to the Profit Interest Units at December 31, 2017 was less than $0.1 million with an average remaining life of 0.8 years.
95
CYPRESS ENERGY PARTNERS, L.P.
Notes to Consolidated Financial Statements - Continued
11.
Related-Party Transactions
Omnibus Agreement
Effective as of the closing of the IPO, we entered into an omnibus agreement with Holdings and other related parties. The omnibus agreement, as amended in
February 2015, governs the following matters, among other things:
● our payment of an annual administrative fee in the amount of $4.0 million ($1.0 million per quarter) to Holdings for providing certain partnership overhead
services, including certain executive management services by certain officers of our General Partner, and payroll services for substantially all employees
required to manage and operate our businesses. This fee also includes the incremental general and administrative expenses we incur as a result of being a
publicly traded partnership. For the first two quarters of 2017, Holdings provided sponsor support to the Partnership by waiving the quarterly payment ($2.0
million total) of the quarterly administrative fee. For the year ended December 31, 2016, Holdings provided sponsor support to the Partnership by waiving
the annual administrative fee for the entire year ($4.0 million total);
● our right of first offer on Holdings’ and its subsidiaries’ assets used in, and entities primarily engaged in, providing salt water disposal and other water and
environmental services; and
● indemnification of us by Holdings for certain environmental and other liabilities (including income tax liabilities), including events and conditions
associated with the operation of assets that occurred prior to the closing of the IPO and our obligation to indemnify Holdings for events and conditions
associated with the operation of our assets that occur after the closing of the IPO and for environmental liabilities related to our assets to the extent Holdings
is not required to indemnify us.
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, provided that the indemnification obligations will remain in
full force and effect in accordance with their terms. 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. As part of our Refinancing
(see Note 6 Credit Agreement) Holdings agreed to waive the omnibus fee to support us in the event leverage exceeds 3.75 times our trailing twelve-month
Adjusted EBITDA during the term of the facility.
The amounts charged by Holdings under the omnibus agreement for the years ended December 31, 2017 and 2015 were $2.0 million and $4.0 million,
respectively, and are reflected in General
and
administrative
in the Consolidated Statements of Operations.
To the extent that Holdings incurs expenses on behalf of the Partnership in excess of administrative expense amounts paid under the omnibus agreement (including
executive management services, payroll services, general and administrative costs incurred as a result of being a publicly traded partnership, and other allocated
costs), the excess is allocated to the Partnership as non-cash allocated costs. The non-cash allocated amounts are reflected as General
and
administrative
expenses
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. Non-cash allocated costs reflected in the
Partnership’s financial statements were $1.8 million, $3.8 million and $0.6 million, respectively, for the years ended December 31, 2017, 2016 and 2015. The
allocation methods utilized in determining the non-cash allocated costs are primarily based on direct expenses incurred and allocation of salaries based on percent
of time incurred, and represent a reasonable allocation of costs incurred by Holdings on behalf of the Partnership.
In addition to funding certain general and administrative expenses on our behalf, Holdings provided the Partnership with additional financial support by
contributing a total of $2.3 million and $2.5 million for the year ended December 31, 2017 and 2016, respectively, in cash, as a reimbursement of certain
expenditures incurred by the Partnership. These payments 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
the
general
partner
in the Consolidated Statement of Operations.
96
CYPRESS ENERGY PARTNERS, L.P.
Notes to Consolidated Financial Statements - Continued
Other Related Party Transactions
A former board member had ownership interests in entities with which the Partnership transacted business including:
● Creek Energy Services, LLC (“Creek,” – formerly Rud Transportation, LLC) – Total revenue recognized by the Partnership from Creek while it was
considered a related party was $1.1 million in the year ended December 31, 2015.
● SBG Pipeline SW 3903, LLC (“3903”) – Total revenue recognized by the Partnership from 3903 while it was considered a related party was $0.6 million for
the year ended December 31, 2015, prior to the sale of the ownership interest to an unrelated third party effective June 30, 2015.
● Effective June 1, 2015, an affiliate of SBG Energy assigned and transferred its 49% membership interest in Cypress Energy Services, LLC (“CES LLC”) to
the Partnership for one dollar (the “CES Transaction”). As a result, the Partnership, as of that date, owns 100% of CES LLC. Because we already controlled
and consolidated CES LLC in our Consolidated Financial Statements, the previously recorded noncontrolling interest in CES LLC has been reflected in the
Consolidated Statement of Owners’ Equity as an increase in equity of $0.9 million for our common and subordinated unitholders.
● The CES Transaction was completed in conjunction with another transaction with SBG Energy effective July 1, 2015. On that date, the Partnership waived
its rights to purchase and its rights of first refusal related to certain salt water disposal assets pursuant to a previous option agreement with SBG Energy in
exchange for $1.0 million. The $1.0 million payment has been reflected in O
ther,
net
on the Consolidated Statements of Operations for the year ended
December 31, 2015.
The Partnership provides management services to a 25% owned company, Alati Arnegard, LLC (“Arnegard”). Management fee revenue earned from Arnegard is
included in revenues
on the Consolidated Statements of Operations and totaled $0.6 million, $0.6 million and $0.7 million for the years ended December 31, 2017,
2016 and 2015, respectively. Accounts receivable from Arnegard totaled $0.1 million at both December 31, 2017 and 2016, and is included in trade
accounts
receivable,
net
on the Consolidated Balance Sheets.
We also have entered into a joint venture with CF Inspection, a nationally-qualified minority-owned inspection firm affiliated with one of Holdings’ owners. CF Inspection
serves energy companies that require a minority-owned vendor. We own 49% of CF Inspection and Cynthia A. Field, the daughter of Charles C. Stephenson, Jr., owns the
remaining 51% of CF Inspection. In 2017, CF Inspection represented approximately 3.5% of our consolidated revenue.
The Partnership outsources staffing and payroll services to an affiliated entity, Cypress Energy Management – Brown, LLC (“CEM-Brown”). CEM-Brown was
owned 49% by SBG Energy. Effective June 1, 2015, Holdings acquired the 49% ownership interest of CEM-Brown and now owns 100% of CEM-Brown. Total
employee related costs paid to CEM-Brown prior to the acquisition of the 49% ownership interest on June 1, 2015 were $1.2 million for the year ended December
31, 2015.
We have also received a commitment from an affiliate of Holdings to invest up to $50.0 million of preferred equity. The preferred equity will have a conversion
premium that is 15% greater than our common unit trailing closing price at the time of issuance. The holder of the preferred units will be entitled to receive
quarterly distributions that represent an annual return of 9.5% on the investment. 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 12 quarters after closing. After the third
anniversary of the closing date, the holder of the preferred units 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 for cash at a price equal to 105% of the amount invested.
97
CYPRESS ENERGY PARTNERS, L.P.
Notes to Consolidated Financial Statements - Continued
12.
Commitments and Contingencies
Security Deposits
The Partnership has various performance obligations which are secured with short-term security deposits totaling $0.5 million at December 31, 2017 and 2016.
These amounts are included in prepaid
expenses
and
other
on the Consolidated Balance Sheets.
Employment Contract Commitments
The Partnership has employment agreements with certain executives. The executive employment agreements are effective for a term of three-to-five years from the
commencement date, after which time they will continue on an “at-will” basis. These agreements provide for minimum annual compensation, adjusted for annual
increases as authorized by the Board of Directors. Certain agreements provide for severance payments in the event of specified termination of employment. At
December 31, 2017 and 2016, the aggregate commitment for future compensation and severance was approximately $0.7 million and $1.0 million, respectively.
Compliance Audit Contingencies
Certain customer master service agreements (“MSA’s”) offer our customers the opportunity 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, 2017 and 2016, there
have been no reserves established for compliance audit contingencies.
Legal Proceeding
On October 5, 2017, a former inspector for 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 alleges he was a non-exempt employee of TIR and that he and other potential class members were
not paid overtime in compliance with the FLSA. The plaintiff seeks to proceed as a collective action and to receive unpaid overtime and other monetary damages,
including attorney’s fees. No estimate of potential loss can be determined at this time and TIR LLC, CEM TIR and Cypress Energy Partners – Texas, LLC deny
the claims. On March 16, 2018, the parties filed a joint stipulation of dismissal without prejudice in regards 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. Upon such
dismissal, no subsidiaries of the Partnership will be parties to the lawsuit.
Internal Revenue Service Audit
In January 2016, we received notice from the Internal Revenue Service that conveyed its intent to audit the consolidated income tax return of one of our
predecessor entities for the 2012 tax year. This audit concluded during the third quarter of 2017 with no material effect on the Partnership or its subsidiaries.
98
Leases
CYPRESS ENERGY PARTNERS, L.P.
Notes to Consolidated Financial Statements - Continued
In August of 2017 we entered into a new office lease for our corporate offices, which commenced in December of 2017. The lease is for 84 months and has two
renewal options of 60 months each. We also maintain leased office space in Texas and California which will expire at the end of June 2018. We have entered into
land lease agreements on four of our salt water disposal facilities. The leases generally provide for initial terms of 15 – 20 years with renewal options.
Lease expense under these operating leases was $0.8 million, $1.0 million $0.8 million for the years ended December 31, 2017, 2016 and 2015, respectively.
Minimum annual lease commitments under the current office lease and other operating leases at December 31, 2017 follows:
Year ending December 31,
(in
thousands)
2018
2019
2020
2021
2022
Thereafter
$
626
535
521
499
499
1,002
3,682
We can exit our headquarters office building which represents approximately $3.3 million of the minimum lease commitments after 18 months (the original lease
term is 84 months) with the payment of a penalty.
13.
Segment Disclosures
The Partnership’s operations consist of three reportable segments: (i) Pipeline Inspection Services (“Pipeline Inspection”), (ii) Integrity Services and (iii) Water
and Environmental Services (“Water Services”).
Pipeline Inspection – This segment represents our pipeline inspection services operations. This segment provides independent inspection and integrity services to
various energy, public utility and pipeline companies. The inspectors in this segment perform a variety of inspection services on midstream pipelines, gathering
systems and distribution systems, including data gathering and supervision of third-party construction, inspection and maintenance and repair projects. Our results
in this segment are driven primarily by the number and type of inspectors performing services for customers and the fees charged for those services, which depend
on the nature and duration of the project.
Integrity Services – This segment includes the acquired operations of Brown. This segment provides independent hydro-testing integrity services to major natural
gas and petroleum pipeline companies, as well as pipeline construction companies located throughout the United States. Field personnel in this segment primarily
perform hydrostatic testing on newly constructed and existing natural gas and petroleum pipelines. Results in this segment are driven primarily by field personnel
performing services for customers and the fees charged for those services, which depend on the nature, scope and duration of the project.
Water Services – This segment includes the operations of ten salt water disposal facilities, fees related to the management of a third party salt water disposal
facility, as well as an equity ownership in one managed facility. We aggregate these operating entities for reporting purposes as they have similar long-term
economic characteristics and have centralized management and processing. Segment results are driven primarily by the volumes of produced water and flowback
water we inject into our salt water disposal facilities and the fees we charge for our services. These fees are charged on a per barrel basis and vary based on the
quantity and type of salt water disposed, competitive dynamics and operating costs. In addition, for minimal marginal cost, we generate revenue by selling residual
oil we recover from the disposed water.
Other – These amounts represent corporate and overhead items not specifically allocable to the other reportable segments.
99
CYPRESS ENERGY PARTNERS, L.P.
Notes to Consolidated Financial Statements - Continued
The following table outlines segment operating income and a reconciliation of total segment operating income to net income before income tax expense.
PIS
IS
W&ES
(in
thousands)
Other
Total
Twelve months ended December 31, 2017
Revenue
Costs of services
Gross margin
General and administrative
Depreciation, amortization and accretion
Impairments
(Gain) loss on asset disposals, net
Operating income (loss)
Interest expense, net
Foreign currency gains
Other, net
Net loss before income tax expense
$
$
268,635 $
241,889
26,746
13,980
2,331
1,329
18
9,088 $
9,268 $
7,347
1,921
1,981
626
1,581
—
(2,267) $
8,439 $
3,503
4,936
2,451
1,486
688
(588)
899 $
$
—
—
—
2,643(a)
—
—
—
(2,643)
$
286,342
252,739
33,603
21,055
4,443
3,598
(570)
5,077
(7,335)
732
199
(1,327)
(a) Amount includes $1.8 million of allocated general and administrative expenses incurred by Holdings but not charged to us (for two of the quarters during
2017, Holdings waived the administrative fee specified in the omnibus agreement)
Twelve months ended December 31, 2016
Revenue
Costs of services
Gross margin
General and administrative
Depreciation, amortization and accretion
Impairments
Operating income (loss)
Interest expense, net
Other, net
Net loss before income tax expense
$
$
275,171 $
247,214
27,957
12,521
2,439
—
12,997 $
13,884 $
11,542
2,342
2,829
658
8,411
(9,556) $
8,942 $
3,761
5,181
1,866
1,764
2,119
(568) $
$
—
—
—
4,637(b)
—
—
(4,637)
$
297,997
262,517
35,480
21,853
4,861
10,530
(1,764)
(6,559)
356
(7,967)
(b) Amount includes $3.8 million of allocated general and administrative expenses incurred by Holdings but not charged to us (for all four of the quarters during
2017, Holdings waived the administrative fee specified in the omnibus agreement).
Twelve months ended December 31, 2015
Revenue
Costs of services
Gross margin
General and administrative
Depreciation, amortization and accretion
Impairments
Operating income (loss)
Interest expense, net
Gain on waiver of right of purchase and other, net
Net income before income tax expense
$
$
341,929 $
309,584
32,345
16,672
2,512
—
13,161 $
14,614 $
10,398
4,216
2,490
421
—
1,305 $
14,648 $
6,279
8,369
3,351
2,494
6,645
(4,121) $
$
—
—
—
1,282(c)
—
—
(1,282)
$
371,191
326,261
44,930
23,795
5,427
6,645
9,063
(5,656)
1,136
4,543
(c) Amount includes $0.6 million of allocated general and administrative expenses incurred by Holding that were in excess of the administrative fee specified in
the omnibus agreement.
Total Assets
December 31, 2017
December 31, 2016
$
$
124,669 $
10,481 $
41,693 $
(13,640) $
163,203
124,840 $
12,079 $
38,141 $
(7,548) $
167,512
100
CYPRESS ENERGY PARTNERS, L.P.
Notes to Consolidated Financial Statements – Continued
14.
Distributions
The following table summarizes the cash distributions that we declared and paid since our initial public offering:
Payment Date
Per Unit Cash
Total Cash
Distributions Distributions
Total Cash
Distributions
to Affiliates (a)
(in
thousands)
May 15, 2014 (b)
August 14, 2014
November 14, 2014
Total 2014 Distributions
February 14, 2015
May 14, 2015
August 14, 2015
November 13, 2015
Total 2015 Distributions
February 12, 2016
May 13, 2016
August 12, 2016
November 14, 2016
Total 2016 Distributions
February 13, 2017
May 13, 2017
August 12, 2017
November 14, 2017
Total 2017 Distributions
February 14, 2018 (c)
$
0.301389 $
0.396844
0.406413
1.104646
0.406413
0.406413
0.406413
0.406413
1.625652
0.406413
0.406413
0.406413
0.406413
1.625652
0.406413
0.210000
0.210000
0.210000
1.036413
3,565 $
4,693
4,806
13,064
4,806
4,808
4,809
4,809
19,232
4,810
4,812
4,817
4,819
19,258
4,823
2,495
2,495
2,497
12,310
0.210000
2,498
2,264
2,980
3,052
8,296
3,052
3,053
3,087
3,092
12,284
3,107
3,099
3,103
3,105
12,414
3,107
1,606
1,607
1,608
7,928
1,599
Total Distributions (through February 14, 2018 since IPO)
$
5.602363 $
66,362 $
42,521
(a) Approximately 64.0% of the Partnership’s outstanding units at December 31, 2017 were held by affiliates.
(b) Distribution was pro-rated from the date of our IPO through March 31, 2014.
(c) Fourth quarter 2017 distribution was declared and paid in the first quarter of 2018.
15.
Subsequent Events
In January 2018, we sold our subsidiary that owns a salt water disposal facility in Pecos, TX to an unrelated party. We received $4.0 million of cash proceeds and a
royalty interest in the future revenues of the facility (although the amount of the cash proceeds is subject to adjustment upon final calculation of certain working
capital amounts). Upon completion of the sale, we repaid $4.0 million of outstanding borrowings under our Credit Agreement.
The assets and liabilities of the Pecos, Texas salt water disposal facility are presented as held for sale in the December 31, 2017 Consolidated Balance Sheet.
Included in the Assets
held
for
sale
is $2.0 million of allocated goodwill, which we calculated based on the estimated fair value of the Pecos facility relative to the
estimated fair value of the Water Services segment as a whole. The following table summarizes the components of assets and liabilities held for sale at December
31, 2017:
Assets:
Current assets
Property and equipment – net
Goodwill
Liabilities:
Accounts payable and accrued liabilities
Asset retirement obligations
(in thousands)
$
$
$
$
84
104
1,984
2,172
79
18
97
The Pecos facility generated revenues of $1.0 million and $0.6 million during the years ended December 31, 2017 and 2016, respectively. The Pecos facility
generated operating income of approximately $0.5 million and $0.2 million during the years ended December 31, 2017 and 2016, respectively.
16.
Condensed Consolidating Financial Information
The Partnership may issue debt securities that would be fully and unconditionally guaranteed by certain guarantor subsidiaries. These debt securities would be
jointly and severally guaranteed by the guarantor subsidiaries.The following financial information reflects consolidating financial information of the Partnership
and its wholly owned guarantor subsidiaries and non-guarantor subsidiaries for the periods indicated. The information is presented in accordance with the
requirements of Rule 3-10 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of financial position, results of operations
or cash flows had the guarantor subsidiaries or non-guarantor subsidiaries operated as independent entities. The Partnership has not presented separate financial
and narrative information for each of the guarantor subsidiaries or non-guarantor subsidiaries because it believes such financial and narrative information would
not provide any additional relative information that would be material in evaluating the sufficiency of the guarantor subsidiaries and non-guarantor subsidiaries.
There are no restrictions on the Partnership’s ability to obtain cash dividends or other distributions of funds from the guarantor subsidiaries.
101
ASSETS
Current assets:
Cash and cash equivalents
Trade accounts receivable, net
Accounts receivable - affiliates
Prepaid expenses and other
Assets held for sale
Total current assets
Property and equipment:
Property and equipment, at cost
Less: Accumulated depreciation
Total property and equipment, net
Intangible assets, net
Goodwill
Investment in subsidiaries
Notes receivable - affiliates
Other assets
Total assets
LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable
Accounts payable - affiliates
Accrued payroll and other
Liabilities held for sale
Income taxes payable
Current portion of long-term debt
Total current liabilities
Notes payable - affiliates
Asset retirement obligations
Total liabilities
Owners’ equity:
Total partners’ capital
Noncontrolling interests
Total owners’ equity
Total liabilities and owners’ equity
Consolidating Balance Sheet
As of December 31, 2017
(in
thousands)
Parent
Guarantors
Non-
Guarantors
Eliminations
Consolidated
$
$
$
$
14,920 $
38,077
19,249
1,602
2,172
76,020
19,673
7,729
11,944
21,614
51,930
(3,155)
13,821
209
172,383 $
3,401 $
—
8,761
97
591
131,400
144,250
—
143
144,393
24,066
3,924
27,990
172,383 $
224 $
—
—
657
—
881
—
—
—
—
—
28,280
—
—
29,161 $
— $
15,824
1
—
—
(607)
15,218
—
—
15,218
10,019
3,924
13,943
29,161 $
102
9,364 $
4,259
—
35
—
13,658
3,027
1,583
1,444
3,863
1,505
—
—
27
20,497 $
1,069 $
6,598
277
—
55
5,500
13,499
13,821
—
27,320
(6,823)
—
(6,823)
20,497 $
— $
(643)
(19,249)
—
—
(19,892)
—
—
—
—
—
(25,125)
(13,821)
—
(58,838) $
(713) $
(19,249)
70
—
—
—
(19,892)
(13,821)
—
(33,713)
(21,201)
(3,924)
(25,125)
(58,838) $
24,508
41,693
—
2,294
2,172
70,667
22,700
9,312
13,388
25,477
53,435
—
—
236
163,203
3,757
3,173
9,109
97
646
136,293
153,075
—
143
153,218
6,061
3,924
9,985
163,203
ASSETS
Current assets:
Cash and cash equivalents
Trade accounts receivable, net
Accounts receivable - affiliates
Prepaid expenses and other
Total current assets
Property and equipment:
Property and equipment, at cost
Less: Accumulated depreciation
Total property and equipment, net
Intangible assets, net
Goodwill
Investment in subsidiaries
Notes receivable - affiliates
Other assets
Total assets
LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable
Accounts payable - affiliates
Accrued payroll and other
Income taxes payable
Total current liabilities
Long-term debt
Notes payable - affiliates
Deferred tax liabilities
Asset retirement obligations
Total liabilities
Commitments and contingencies - Note 13
Owners’ equity:
Total partners’ capital
Noncontrolling interests
Total owners’ equity
Total liabilities and owners’ equity
Consolidating Balance Sheet
As of December 31, 2016
(in
thousands)
Parent
Guarantors
Non-
Guarantors
Eliminations
Consolidated
$
$
$
$
695 $
—
—
—
695
—
—
—
—
—
29,454
—
—
30,149 $
— $
8,860
15
—
8,875
(1,201)
—
—
—
7,674
20,251 $
33,046
12,622
996
66,915
19,366
6,798
12,568
23,875
53,914
(417)
13,662
139
170,656 $
1,653 $
—
7,082
967
9,702
131,400
—
8
139
141,249
5,747 $
6,125
—
46
11,918
3,093
1,042
2,051
5,749
2,989
—
—
10
22,717 $
712 $
5,400
503
44
6,659
5,500
13,662
354
—
26,175
— $
(689)
(12,622)
—
(13,311)
—
—
—
—
—
(29,037)
(13,662)
—
(56,010) $
(675) $
(12,622)
(15)
—
(13,312)
—
(13,662)
—
—
(26,974)
26,693
38,482
—
1,042
66,217
22,459
7,840
14,619
29,624
56,903
—
—
149
167,512
1,690
1,638
7,585
1,011
11,924
135,699
—
362
139
148,124
17,425
5,050
22,475
30,149 $
24,357
5,050
29,407
170,656 $
(3,458)
—
(3,458)
22,717 $
(23,986)
(5,050)
(29,036)
(56,010) $
14,338
5,050
19,388
167,512
103
Consolidating Statement of Operations
For the Year Ended December 31, 2017
(in
thousands)
Parent
Guarantors
Non-
Guarantors
Eliminations
Consolidated
Revenues
Costs of services
Gross margin
$
— $
—
—
253,696 $
223,555
30,141
42,607 $
39,145
3,462
(9,961) $
(9,961)
—
286,342
252,739
33,603
Operating costs and expense:
General and administrative
Depreciation, amortization and accretion
Impairments
Gain on asset disposals, net
Operating (loss)
Other income (expense):
Equity earnings (loss) in subsidiaries
Interest expense, net
Foreign currency gains
Other, net
Net income (loss) before income tax expense
Income tax expense (benefit)
Net income (loss)
Net (loss) attributable to noncontrolling interests
Net income (loss) attributable to controlling interests
2,643
—
—
—
(2,643)
3,020
(913)
—
—
(536)
—
(536)
—
(536)
Net (loss) attributable to general partner
Net income (loss) attributable to limited partners
$
(4,050)
3,514 $
104
15,473
3,798
688
(577)
10,759
(2,776)
(5,579)
187
165
2,756
846
1,910
(1,110)
3,020
—
3,020 $
2,939
645
2,910
7
(3,039)
—
(843)
545
34
(3,303)
(250)
(3,053)
—
(3,053)
—
(3,053) $
—
—
—
—
—
(244)
—
—
—
(244)
—
(244)
—
(244)
—
(244) $
21,055
4,443
3,598
(570)
5,077
—
(7,335)
732
199
(1,327)
596
(1,923)
(1,110)
(813)
(4,050)
3,237
Consolidating Statement of Operations
For the Year Ended December 31, 2016
(in
thousands)
Parent
Guarantors
Non-
Guarantors
Eliminations
Consolidated
Revenues
Costs of services
Gross margin
$
— $
—
—
252,955 $
222,067
30,888
58,694 $
54,102
4,592
(13,652) $
(13,652)
—
297,997
262,517
35,480
Operating costs and expense:
General and administrative
Depreciation, amortization and accretion
Impairments
Operating (loss)
Other income (expense):
Equity earnings (loss) in subsidiaries
Interest expense, net
Other, net
Net income (loss) before income tax expense
Income tax expense
Net income (loss)
4,637
—
—
(4,637)
862
(889)
—
(4,664)
—
(4,664)
12,625
4,091
2,119
12,053
(10,020)
(4,854)
334
(2,487)
1,150
(3,637)
4,591
770
8,411
(9,180)
—
(816)
22
(9,974)
45
(10,019)
—
—
—
—
9,158
—
—
9,158
—
9,158
Net (loss) attributable to noncontrolling interests
Net income (loss) attributable to partners / controlling
interests
—
(4,499)
—
—
(4,664)
862
(10,019)
9,158
Net (loss) attributable to general partner
Net income (loss) attributable to limited partners
$
(6,298)
1,634 $
—
862 $
—
(10,019) $
—
9,158 $
21,853
4,861
10,530
(1,764)
—
(6,559)
356
(7,967)
1,195
(9,162)
(4,499)
(4,663)
(6,298)
1,635
105
Consolidating Statement of Operations
For the Year Ended December 31, 2015
(in
thousands)
Parent
Guarantors
Non-
Guarantors
Eliminations
Consolidated
Revenues
Costs of services
Gross margin
$
— $
—
—
329,086 $
290,524
38,562
54,708 $
48,340
6,368
(12,603) $
(12,603)
—
371,191
326,261
44,930
Operating costs and expense:
General and administrative
Depreciation, amortization and accretion
Impairments
Operating income (loss)
Other income (expense):
Equity earnings in subsidiaries
Interest expense, net
Other, net
Net income (loss) before income tax expense
Income tax expense
Net income (loss)
1,282
—
—
(1,282)
6,115
(902)
—
3,931
—
3,931
18,180
4,832
6,645
8,905
1,010
(4,115)
1,116
6,916
372
6,544
Net income (loss) attributable to noncontrolling interests
Net income (loss) attributable to partners / controlling
143
429
4,333
595
—
1,440
—
(639)
20
821
80
741
—
—
—
—
—
(7,125)
—
—
(7,125)
—
(7,125)
27
interests
3,788
6,115
741
(7,152)
Net (loss) attributable to general partner
Net income (loss) attributable to limited partners
$
(648)
4,436 $
—
6,115 $
—
741 $
—
(7,152) $
23,795
5,427
6,645
9,063
—
(5,656)
1,136
4,543
452
4,091
599
3,492
(648)
4,140
106
Consolidating Statement of Comprehensive Income (Loss)
For the Year Ended December 31, 2017
(in
thousands)
Parent
Guarantors
Non-
Guarantors
Eliminations
Consolidated
Net income (loss)
Other comprehensive income -
Foreign currency translation
Comprehensive income (loss)
$
$
(536) $
1,910 $
—
(175)
(536) $
1,735 $
(3,053) $
—
36
—
(3,017) $
(244) $
(1,923)
—
(139)
(244) $
(2,062)
Comprehensive (loss) attributable to noncontrolling
interests
Comprehensive income attributable to general partner
Comprehensive income (loss) attributable to
—
(4,050)
(1,110)
—
—
—
—
—
controlling interests
$
3,514 $
2,845 $
(3,017) $
(244) $
(1,110)
(4,050)
3,098
107
Consolidating Statement of Comprehensive Income (Loss)
For the Year Ended December 31, 2016
(in
thousands)
Parent
Guarantors
Non-
Guarantors
Eliminations
Consolidated
Net income (loss)
Other comprehensive income -
Foreign currency translation
$
(4,664) $
(3,637) $
(10,019) $
9,158 $
(9,162)
—
71
182
—
253
Comprehensive income (loss)
$
(4,664) $
(3,566) $
(9,837) $
9,158 $
(8,909)
Comprehensive (loss) attributable to noncontrolling
interests
Comprehensive (loss) attributable to general partner
Comprehensive income (loss) attributable to limited
—
(6,298)
(4,499)
—
—
—
—
—
partners
$
1,634 $
933 $
(9,837) $
9,158 $
(4,499)
(6,298)
1,888
Consolidating Statement of Comprehensive Income (Loss)
For the Year Ended December 31, 2015
(in
thousands)
Parent
Guarantors
Non-
Guarantors
Eliminations
Consolidated
Net income (loss)
Other comprehensive income -
Foreign currency translation
$
3,931 $
6,544 $
741 $
(7,125) $
—
(564)
(1,178)
—
Comprehensive income (loss)
$
3,931 $
5,980 $
(437) $
(7,125) $
Comprehensive (loss) attributable to noncontrolling
interests
Comprehensive (loss) attributable to general partner
Comprehensive income (loss) attributable to limited
143
(648)
429
—
—
—
(430)
—
partners
$
4,436 $
5,551 $
(437) $
(6,695) $
4,091
(1,742)
2,349
142
(648)
2,855
108
Consolidating Statement of Cash Flows
For the Year Ended December 31, 2017
(in
thousands)
Operating activities:
Net income (loss)
Adjustments to reconcile net income (loss) to cash provided by (used
in) operating activities:
Parent
Guarantors
Guarantors Eliminations Consolidated
Non-
$
(536) $
1,910 $
(3,053) $
(244) $
(1,923)
Depreciation, amortization and accretion
Impairments
(Gain) loss on asset disposal
Interest expense from debt issuance cost amortization
Equity-based compensation expense
Equity in earnings of investee
Distributions from investee
Equity earnings in subsidiaries
Deferred tax benefit, net
Non-cash allocated expenses
Foreign currency gains
Changes in assets and liabilities:
Trade accounts receivable
Receivables from affiliates
Prepaid expenses and other
Accounts payable and accrued payroll and other
Income taxes payable
Net cash provided by (used in) operating activities
Investing activities:
Proceeds from fixed asset disposals
Purchases of property and equipment
Net cash used in investing activities
Financing activities:
Taxes paid related to net share settlement of equity-based
compensation
Contributions from general partner
Distributions from subsidiaries
Distributions to limited partners
Distributions to noncontrolling members
Net cash provided by (used in) financing activities
—
—
—
594
1,059
—
—
(3,020)
—
1,750
—
—
—
(657)
6,950
—
6,140
—
—
—
(124)
2,300
3,523
(12,310)
—
(6,611)
4,359
688
(577)
—
—
(149)
75
2,776
(8)
—
(187)
(5,110)
(6,627)
(846)
2,945
(376)
(1,127)
2,302
(3,327)
(1,025)
—
—
(3,508)
—
—
(3,508)
1,185
2,910
7
—
—
—
—
—
(364)
—
(545)
1,750
—
24
1,315
11
3,240
2
(18)
(16)
—
—
(15)
—
(16)
(31)
Effects of exchange rates on cash
—
349
404
—
—
—
—
—
—
—
244
—
—
—
(46)
6,627
158
(6,739)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
— $
5,544
3,598
(570)
594
1,059
(149)
75
—
(372)
1,750
(732)
(3,406)
—
(1,321)
4,471
(365)
8,253
2,304
(3,345)
(1,041)
(124)
2,300
—
(12,310)
(16)
(10,150)
753
(2,185)
26,693
24,508
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents, beginning of period
Cash and cash equivalents, end of period
Non-cash items:
Accrued capital expenditures
$
$
109
(471)
695
224 $
(5,311)
20,251
14,940 $
3,597
5,747
9,344 $
— $
561 $
6 $
— $
567
Consolidating Statement of Cash Flows
For the Year Ended December 31, 2016
(in
thousands)
Parent
Guarantors
Guarantors Eliminations Consolidated
Non-
Operating activities:
Net income (loss)
Adjustments to reconcile net income (loss) to cash provided by (used
$
(4,664) $
(3,637) $
(10,019) $
9,158 $
(9,162)
in) operating activities:
Depreciation, amortization and accretion
Impairments
Gain (loss) on asset disposal
Interest expense from debt issuance cost amortization
Equity-based compensation expense
Equity in earnings of investee
Distributions from investee
Equity earnings in subsidiaries
Deferred tax benefit, net
Non-cash allocated expenses
Changes in assets and liabilities:
Trade accounts receivable
Receivables from affiliates
Prepaid expenses and other
Accounts payable and accrued payroll and other
Income taxes payable
Net cash provided by (used in) operating activities
Investing activities:
Proceeds from fixed asset disposals
Purchases of property and equipment
Net cash used in investing activities
Financing activities:
Repayments of long-term debt
Taxes paid related to net share settlement of equity-based
compensation
Contributions from general partner
Distributions from subsidiaries
Distributions to limited partners
Distributions to noncontrolling members
Net cash provided by (used in) financing activities
—
—
—
570
1,086
—
—
(862)
—
3,798
—
—
—
7,632
—
7,560
4,495
2,119
(12)
—
—
(309)
200
10,020
(35)
—
6,983
(7,021)
941
507
582
14,833
—
—
—
26
(1,066)
(1,040)
1,293
8,411
(7)
—
—
—
—
—
11
—
2,252
—
308
132
45
2,426
20
(310)
(290)
—
—
—
—
—
—
—
(9,158)
—
—
636
7,021
101
(7,793)
35
—
—
—
—
5,788
10,530
(19)
570
1,086
(309)
200
—
(24)
3,798
9,871
—
1,350
478
662
24,819
46
(1,376)
(1,330)
—
(4,000)
—
—
(4,000)
(107)
2,500
9,622
(19,258)
—
(7,243)
—
—
(9,239)
—
—
(13,239)
—
—
(383)
—
(424)
(807)
—
—
—
—
—
—
—
—
—
— $
(107)
2,500
—
(19,258)
(424)
(21,289)
343
2,543
24,150
26,693
Effects of exchange rates on cash
—
127
216
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents, beginning of period
Cash and cash equivalents, end of period
317
378
695 $
681
19,570
20,251 $
1,545
4,202
5,747 $
$
110
Consolidating Statement of Cash Flows
For the Year Ended December 31, 2015
(in
thousands)
Operating activities:
Net income (loss)
Adjustments to reconcile net income (loss) to cash provided by (used
in) operating activities:
Depreciation, amortization and accretion
Impairments
Loss on asset disposals
Interest expense from debt issuance cost amortization
Equity-based compensation expense
Equity in earnings of investee
Distributions from investee
Equity earnings in subsidiaries
Deferred tax benefit, net
Non-cash allocated expenses
Changes in assets and liabilities:
Trade accounts receivable
Receivables from affiliates
Prepaid expenses and other
Accounts payable and accrued payroll and other
Income taxes payable
Net cash provided by (used in) operating activities
Investing activities:
Proceeds from disposals of property and equipment
Cash paid for acquisition of 49.9% interest in the TIR Entities
Cash paid for acquisition of 51% of Brown Integrity, LLC, net of cash
acquired of $175
Purchases of property and equipment
Net cash (used in) investing activities
Financing activities:
Advances on long-term debt
Repayments of long-term debt
Distributions from subsidiaries
Distributions to limited partners
Distributions to noncontrolling members
Net cash provided by (used in) financing activities
Parent
Guarantors
Guarantors Eliminations Consolidated
Non-
$
3,931 $
6,544 $
741 $
(7,125) $
4,091
—
—
—
547
1,167
—
—
(6,115)
—
648
—
22
—
1,203
—
1,403
—
—
—
—
—
—
—
17,225
(19,232)
—
(2,007)
5,102
6,645
—
—
—
(102)
100
(1,010)
58
—
9,540
3,208
267
(1,074)
(122)
29,156
2
(52,588)
(10,436)
(1,607)
(64,629)
63,300
(5,500)
(17,225)
—
(1,567)
39,008
902
—
(1)
—
—
—
—
—
(90)
—
(546)
—
(69)
(4,536)
(39)
(3,638)
—
—
—
(250)
(250)
5,500
—
—
—
—
5,500
—
—
—
—
—
—
—
7,125
—
—
45
(3,230)
35
3,185
(35)
—
—
—
—
—
—
—
—
—
—
—
—
6,004
6,645
(1)
547
1,167
(102)
100
—
(32)
648
9,039
—
233
(1,222)
(196)
26,921
2
(52,588)
(10,436)
(1,857)
(64,879)
68,800
(5,500)
—
(19,232)
(1,567)
42,501
Effects of exchange rates on cash
—
(563)
(587)
—
(1,150)
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents, beginning of period
Cash and cash equivalents, end of period
Non-cash items:
Accrued capital expenditures
(604)
982
378 $
2,972
16,598
19,570 $
1,025
3,177
4,202 $
—
—
— $
3,393
20,757
24,150
— $
6 $
94 $
— $
100
$
$
111
17. Quarterly Financial Information (Unaudited)
CYPRESS ENERGY PARTNERS, L.P.
Notes to Consolidated Financial Statements - Continued
The following table sets forth certain unaudited financial data for each quarter during 2017 and 2016. The unaudited quarterly information includes all normal
recurring adjustments that we consider necessary for a fair presentation of the information shown.
2017
Quarter Ended,
(in
thousands,
except
per
unit
amounts)
Revenues
Gross margin
Impairments
Net income (loss)
Net income (loss) attributable to partners / controlling interests
Net income (loss) attributable to limited partners
Net income (loss) per common limited partner unit - basic and diluted
March 31
$
64,722 $
6,329
3,598
(4,921)
(3,756)
(2,835)
(0.32)
June 30
September 30 December 31
77,682 $
9,390
—
562
554
1,554
0.13
69,371
9,275
—
1,939
1,759
3,059
0.26
74,567 $
8,609
—
497
630
1,459
0.12
2016
Quarter Ended,
(in
thousands,
except
per
unit
amounts)
Revenues
Gross margin
Impairments
Net income (loss)
Net income (loss) attributable to partners / controlling interests
Net income (loss) attributable to limited partners
Net income (loss) per common limited partner unit - basic
Net income (loss) per common limited partner unit - diluted
Net income (loss) per subordinated limited partner unit - basic and diluted
March 31
$
73,474 $
7,760
—
(1,361)
(994)
(26)
(0.00)
(0.00)
(0.00)
June 30
September 30 December 31
81,806 $
9,926
—
1,998
1,917
3,348
0.28
0.27
0.28
70,406
10,429
—
1,817
1,418
2,350
0.20
0.19
0.20
72,311 $
7,365
10,530
(11,616)
(7,004)
(4,037)
(0.34)
(0.34)
(0.34)
Revenues and gross margin for the quarter ended December 31, 2016 include $1.2 million related to a price increase on services we performed during preceding
quarters. We recognized this revenue upon receipt during the fourth quarter of a signed contract formally evidencing the customer’s agreement to the new pricing.
112
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, 2017. Additionally, we have implemented a quarterly sub-
certification process whereby all members of upper management and certain other management will review our filings and confirm their responsibility for, among
other things, the effectiveness of key controls in their functional areas and that they are unaware of inaccuracies or omissions in our financial statements.
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 issues 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.
113
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
external resources 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, 2017, 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, 2017, we maintained effective internal control over financial reporting, and management
believes that we have no material internal control weaknesses in our financial reporting process.
Attestation Report of the Registered Public Accounting Firm
Pursuant to the Jumpstart Our Business (“JOBS”) Act enacted in 2012, our independent registered public accounting firm will not be required to attest to the
effectiveness of our internal controls over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act of 2002 for up to five years or through such earlier
date that we are no longer an “emerging growth company” as defined in the JOBS Act.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting that occurred during the three months ended December 31, 2017 that have materially
affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
None.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
PART III
MANAGEMENT
Management of Cypress Energy 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 made specifically nonrecourse to it.
Whenever possible, we intend to incur indebtedness that is nonrecourse to our general partner.
Our general partner currently has five directors. Holdings will appoint 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
approximately 58.5% of our outstanding limited partner interests, the board of directors determined he is independent in that he does not have a current relationship
with us that would interfere with the exercise of his independent judgment in carrying out his responsibilities as a director.
114
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 Stan 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 or awards under our incentive compensation plan. If our general partner seeks approval from the conflicts committee, then it will be
presumed that, in making its decision, the conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the
partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Please read
“ Conflicts
of
Interest
and
Duties
.”
Directors and Executive Officers of Cypress Energy Partners GP, LLC
Directors are elected by 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
Peter C. Boylan III
Richard M. Carson
Jeffrey A. Herbers
Henry Cornell
Stanley A. Lybarger
John T. McNabb, II
Charles C. Stephenson, Jr.
Age
54
51
41
61
68
73
81
Position with Cypress Energy Partners GP, LLC
Chairman of the Board, Chief Executive Officer and President
Senior Vice President and General Counsel
Vice President, Chief Accounting Officer and Interim Principal Financial Officer
Director
Director & Audit Committee Chairman
Director & Conflicts Committee Chairman
Director
115
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 Energy 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 Energy 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, Chief Accounting Officer and Interim Principal Financial Officer of Cypress Energy Partners GP, LLC, having served in
that capacity since September 2016. 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.
116
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.
Stanley A. Lybarger has served as a director on the board of Cypress Energy Partners GP, LLC since March 5, 2014. Mr. Lybarger retired as president and chief
executive officer of BOK Financial, a top 25 US-based bank, 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. Mr. Lybarger currently serves on the board of directors of BOK
Financial.
John T. McNabb II has served on the board of directors of Cypress Energy Partners GP, LLC, the general partner of the Partnership, where he has served as the
Chairman of the Conflicts Committee. He co-founded the Trump Leadership Council in April 2016 and has served on the council since its founding. 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.
117
Charles C. Stephenson, Jr. has been a director on the board of Cypress Energy 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 during
the year ended December 31, 2017.
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 Energy Partners GP, LLC
5727 S. Lewis Avenue, Suite 300
Tulsa, Oklahoma 74105
We make available free of charge, within the “ Corporate
Governance
” section of our website at www.cypressenergy.com, the Corporate Governance Guidelines,
the Code of Business Conduct and Ethics and our Audit Committee Charter. The information contained on, or connected to, our website is not incorporated by
reference into this Annual Report on Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC.
118
ITEM 11. EXECUTIVE COMPENSATION
We are an “emerging growth company” as defined under the JOBS Act. As such, we are permitted to meet the disclosure requirements of Item 402 of Regulation
S-K by providing the reduced disclosures required of a smaller reporting company.
Compensation Overview
Executive Compensation
We do not directly employ any of the persons responsible for managing our business. Our general partner, under the direction of its board of directors, or the board,
is responsible for managing our operations and CEM 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, 2017, 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;
● Jeffrey A. Herbers, our Vice President, Chief Accounting Officer and Interim Principal Financial Officer; and
● G. Les Austin, our former Senior Vice President and Chief Financial Officer.
Mr. Austin resigned from his position with the General Partner effective November 24, 2017 and Mr. Herbers assumed the role of our interim principal financial
officer following such date.
Summary Compensation Table For 2017
The following table sets forth certain information with respect to the compensation paid to our NEOs for the years ended December 31, 2017, 2016 and 2015.
Name and Principal Position
Year
Salary
Bonus
(a)
Unit Awards
(b)
All Other
Compensation
$
$
$
2017
2016
2015
2017
2016
2015
2017
2016
2015
431,474 $
411,712
399,050
286,250 $
275,000
259,375
264,502 $
275,000
50,000 $
65,000
38,609
20,000 $
25,000
20,000
— $
25,000
506,069 $
554,167
593,173
169,012 $
185,076
203,907
169,012 $
185,076
260,000
20,000
203,907
Total
987,543
1,030,879
1,030,832
475,262
485,076
483,282
433,514
485,076
483,907
— $
—
—
— $
—
—
— $
—
—
2017
$
175,000 $
7,500 $
53,779 $
— $
236,279
Peter C. Boylan III
Chairman, Chief Executive
Officer and President
Richard M. Carson
Senior Vice President and
General Counsel
G. Les Austin (c)
Former Senior Vice
President and Chief Financial
Officer
Jeffrey A. Herbers (d)
Vice President, Chief
Accounting Officer and
Interim Principal Financial
Officer
(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 included in Item 8 of
this Annual Report.
(c) Mr. Austin resigned his position with the General Partner effective November 24, 2017. Accordingly, the compensation amounts shown for Mr. Austin
represent compensation Mr. Austin received from the first of the year through his departure date.
(d) Mr. Herbers assumed the role of Interim Principal Financial Officer in November of 2017. The amounts shown above are Mr. Herbers’s compensation
for the complete year 2017.
119
Narrative Disclosure to Summary Compensation Table
Elements
of
the
compensation
program
. For 2017, the primary elements of compensation for our NEOs included base salary, cash bonus awards and equity
awards.
Base
compensation
for
2017
. Base salaries for our NEOs are set at levels deemed necessary to attract and retain individuals with superior talent 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
Peter C. Boylan III
Chairman, Chief Executive Officer and President
Richard M. Carson
Senior Vice President and General Counsel
Jeffrey A. Herbers
Vice President, Chief Accounting Officer and Interim Principal Financial Officer
Current Base
Salary
$
438,062
$
305,000
$
185,000
In January 2018, Mr. Carson’s annual base salary was increased from $290,000 to $305,000 and Mr. Herbers’s annual base salary was increased from $175,000 to
$185,000. Both increases were made in response to increases in these officers’ responsibilities resulting from the departure in November 2017 of our Chief
Financial Officer.
Bonus
awards
. Our NEOs are eligible to receive discretionary cash bonus awards as our general partner’s board of directors may determine from time to time. For
2017 Mr. Boylan, Mr. Herbers and Mr. Carson received cash bonus awards. For 2016 and 2015, Mr. Boylan, Mr. Austin and Mr. Carson received cash bonus
awards. Mr. Boylan’s, Mr. Herbers’s, Mr. Austin’s and Mr. Carson’s bonus awards were granted based on subjective performance determinations. In January 2018,
Mr. Carson and Mr. Herbers received cash bonuses of $20,000 and $11,500, respectively, in recognition of their efforts toward the successful sale of the Pecos,
Texas salt water disposal facility.
Discretionary
long-term
equity
incentive
awards
. In December 2012, in connection with his commencement of employment, Mr. Austin, received a one-time
award of Class C Units in CEP LLC, which were intended to allow Mr. Austin to share in the future equity appreciation of CEP LLC from and after the date of
grant of such Class C Units. Mr. Carson received a similar award in connection with his commencement of service in September 2013. The awards vest in three
equal annual installments on the third, fourth and fifth anniversary of the grantee’s commencement of service with us, respectively. In connection with our IPO, the
Class C units in CEP LLC were converted into subordinated units in us on an equivalent value basis, based on the per unit price in our IPO and with the same
vesting terms as applied to the Class C Units. Mr. Austin’s award converted into 30,143 subordinated units and Mr. Carson’s award converted into 14,308
subordinated units. These subordinated units converted to common units once the Partnership emerged from subordination on February 14, 2017.
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 and other service providers. In addition to the equity awards received by Mr. Austin
and Mr. Carson in connection with the conversion of previously issued awards in CEP LLC described above, in 2017, 2016 and 2015, we granted long-term
incentive awards to our NEO’s in the form of phantom units. The phantom units are scheduled to vest in three equal annual installments on each of the third, fourth
and fifth anniversaries of the grant date, subject to the NEO’s continued employment with us on the applicable vesting date and potential accelerated vesting as
described below under “ Severance
and
change
in
control
arrangements
.”
In January 2018, we granted 5,000 unrestricted phantom units to Mr. Carson and 4,167 unrestricted phantom units to Mr. Herbers. These grants will vest eighteen
months after the grant date, contingent on the continued service of these NEO’s through such date. These grants were made in response to increases in these NEOs’
responsibilities resulting from the departure in November 2017 of our Chief Financial Officer.
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Outstanding Equity Awards at December 31, 2017
The following table provides information regarding the outstanding and unvested long-term equity incentive awards held by our NEOs as of December 31, 2017.
None of our NEOs held any option awards that were outstanding as of December 31, 2017.
Name and Principal Position
Grant Date
Unit Awards
Number of Units
That Have
Not Vested
#
Market Value of
Units That Have
Not Vested
(a)
Peter C. Boylan III (b)
Chairman, Chief Executive Officer and President
Richard M. Carson
Senior Vice President and General Counsel
Jeffrey A. Herbers
Vice President, Chief Accounting Officer and Interim Principal Financial Officer
March 9, 2017
March 10, 2016
March 26, 2015
March 9, 2017
March 10, 2016
March 26, 2015
February 1, 2014
—
March 9, 2017
November 2, 2016
70,680(c)
88,636(c)
47,365(c)
23,605(c)
29,602(c)
16,282(c)
1,714(c)
4,770(d)
7,511(c)
10,152(c)
424,080
531,816
284,190
141,630
177,612
97,692
10,284
28,620
45,066
60,912
(a) Amount shown reflects the per-unit value based upon the December 31, 2017 closing price of $6.00 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 restricted units in us into which previously-issued awards in CEP LLC that were outstanding as of December 31, 2013 were converted upon the
closing of our IPO on January 21, 2014 based upon the IPO price of $20.00 per common unit. The restricted units for Mr. Carson are scheduled to vest into
common units on September 30, 2018.
In connection, with his resignation in November 2017, Mr. Austin forfeited all of his unvested long-term equity incentive awards in us.
Severance
and
change
in
control
arrangements
. None of our NEOs has entered into any employment or severance agreements with our general partner or any of
its affiliates. Mr. Austin did not receive any severance payments or benefits in connection with his resignation in November 2017.
The terms of Mr. Boylan, Mr. Herbers, and Mr. Carson’s phantom restricted unit awards provide that in the event of a change in control of the partnership, their
phantom restricted units would become fully vested should they no longer remain employed in their respective positions 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 and life insurance and a 401(k)
plan. We do not expect to maintain a defined benefit pension plan for our executive officers, because we believe such plans primarily reward longevity rather than
performance.
Director Compensation
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, having a value as of the grant date of $50,000. 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.
121
Non-employee directors also receive reimbursement for out-of-pocket expenses associated with attending such board or committee meetings and director and
officer liability insurance coverage. Each director will be fully indemnified by us for actions associated with being a director to the fullest extent permitted under
Delaware law.
The following table provides information regarding the compensation earned by our non-employee directors during the year ended December 31, 2017.
Name
Henry Cornell (b)
Stanley A. Lybarger(b)
John T. McNabb II(b)
Cash Fees
Earned
Unit
Awards (a)
Total
$
$
$
25,000 $
40,216 $
65,216
32,500 $
40,216 $
72,716
30,000 $
40,216 $
70,216
(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 11 to the Consolidated Financial Statements included in Item 8 in this Annual Report.
(b) As of December 31, 2017, each of the directors listed in the table above has 8,867 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 III, 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 III makes
recommendations to the Board regarding named executive officer compensation but abstains from any decision 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.
Peter C. Boylan III
Stanley A. Lybarger
Henry Cornell
John T. McNabb II
Charles C. Stephenson, Jr.
Members of the Board of Directors of Cypress Energy Partners GP, LLC
122
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 Energy Partners, L.P., as of March 16, 2018, held by beneficial owners of 5.0% or more
of the units, by each director and named executive officer of Cypress Energy 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 11,906,464 common 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 12, 2018, 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 Avenue, Suite 300, Tulsa, Oklahoma 74105.
Name of Beneficial Owner
Cypress Energy Holdings, LLC (a) (b)
Peter C. Boylan III
Jeffrey A. Herbers
Richard M. Carson
Henry Cornell
John T. McNabb II
Stanley A. Lybarger
Charles C. Stephenson, Jr.
All directors and executive officers as a group (consisting of 7 persons)
Percentage of
Common Units Common Units
Beneficially
Owned
Beneficially
Owned
6,957,349
20,242
—
22,837
8,126
43,126
30,047
413,740
538 ,118
58.5%
*
*
*
*
*
*
3.5%
4.4%
indicates that person or entity owns less than one percent.
*
(a) Cypress Energy Holdings, LLC owns 100% of Cypress Energy Investments, LLC, which owns 100% of CEP-TIR. CEP-TIR owns 11.3% of
our common units.
(b) Cypress Energy Holdings, LLC owns 100% of Cypress Energy Holdings II, LLC, which owns 100% of our general partner. Cypress Energy
Holdings II, LLC owns 47.2% of our common units. The following table sets forth the beneficial ownership of Cypress Energy Holdings,
LLC.
123
Name of Beneficial Owner
Cynthia A. Field Trust
Charles C. Stephenson, Jr.
CEP Capital Partners, LLC
Henry Cornell
Cornell Investment Partners, L.P.
Stephenson Grandchildren Family LLC
(2)
(3)
(2)
Ownership
Interest
Ratio (1)
36.750%
27.468%
24.500%
1.333%
0.667%
9.282%
(1) Cypress Energy Holdings, LLC is managed by a three-member board of directors consisting of Peter C. Boylan III, Lawrence
D. 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) Voting rights of the trust are exercised by Cynthia A. Field, as trustee or manager of the LLC.
(3) CEP Capital Partners, LLC is owned and controlled by affiliates of Peter C. Boylan III, our Chairman, Chief Executive
Officer and President.
Securities Authorized for Issuance under Equity Compensation Plans
In connection with the consummation of our IPO on January 21, 2014, the board of directors of our general partner adopted the 2013 Long-Term Incentive Plan.
The following table provides certain information with respect to this plan as of December 31, 2017:
Plan Category
Equity compensation plans approved by security holders
Equity compensation plans not approved by security holders
Total
Number of
Securities
Number of Securities
Remaining
to be Issued upon Weighted Average Available for Future
Exercise of
Outstanding
Exercise Price of
Outstanding
Options, Warrants Options, Warrants
and Rights
and Rights
Issuance under
Equity
Compensation
Plans
664,509
—
664,509
—
—
—
518,091
—
518,091
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 58.5% of our outstanding common units, and the
owners of Holdings own 100.0% of Cypress Energy GP Holdings, LLC, which owns 100.0% of our general partner. Holdings II and Cypress Energy Investments,
LLC are both wholly owned subsidiaries of Holdings. Holdings II directly holds 5,610,549 of our outstanding common units. Cypress Energy Investment, LLC
owns 100.0% of Cypress Energy Partners – TIR, LLC, which directly holds 1,346,800 of our outstanding common units.
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.
124
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, 2017, the general partner and its controlled affiliates own 6,957,349 common units, representing a 58.5% limited partner interest in us. 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
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 Energy Partners, L.P. These distributions and payments were determined by and among affiliated entities
and, consequently, are not the result of arm’s-length negotiations.
Formation Stage
The consideration received by our general partner and
its controlled affiliates prior to or in connection with the
IPO for the contribution of the assets and liabilities to us
1,344,650 common units;
5,612,699 subordinated units;
Operational Stage
Distributions of available cash to our general partner
and its controlled affiliates
0.0% non-economic general partner interest;
the incentive distribution rights; and
a cash payment of approximately $80.2 million from the proceeds of the IPO.
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.
During the year ended December 31, 2017, the year ended December 31, 2016, and the
year ended December 31, 2015, our general partner and its affiliates received
approximately $7.9 million, $12.3 million, and $12.3 million, respectively.
125
Payments to our general partner and its affiliates
Withdrawal or removal of our general partner
Liquidation Stage
Liquidation
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 $2.0 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 for the years ended December 31, 2017
and December 31, 2015, respectively. The annual administrative fee is subject to increase
by an annual amount equal to PPI plus one percent or, with the concurrence of the
conflicts committee, in the event of an expansion of our operations, including through
acquisitions or internal growth. During the year ended December 31, 2016, we did not
reimburse our general partner for these administrative fees, because the general partner
waived the fees for that year. Please read “ Agreements
with
Affiliates
—
Omnibus
Agreement
” below and “ Compensation
Overview
.”
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.
Upon our liquidation, the partners, including our general partner, will be entitled to
receive liquidating distributions according to their respective capital account balances.
126
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, CEP-TIR, the TIR Entities, Charles C.
Stephenson, Jr. and Cynthia A. Field that address the following matters, among other things:
●
●
●
our payment of an annual administrative fee to be paid in quarterly installments of $1.0 million to Holdings for providing us with certain partnership
overhead services, including for certain executive management services by certain officers of our general partner, and compensation expense for all
employees required to manage and operate our business. This fee also includes the incremental general and administrative expenses we incur as a result of
being a publicly traded partnership;
our right of first offer on Holdings’ and its subsidiaries’ assets used in, and entities primarily engaged in, providing salt water disposal and other water and
environmental services; and
indemnification of us by Holdings for certain environmental and other liabilities, including events and conditions associated with our operation of assets
that occur prior to the closing of the IPO and our obligation to indemnify Holdings for events and conditions associated with the operation of our assets
that occur after the closing of the IPO and for environmental liabilities related to our assets to the extent Holdings is not required to indemnify us.
So long as Holdings controls our general partner, our amended and restated 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 our amended and restated omnibus agreement, provided that the
indemnification obligations will remain in full force and effect in accordance with their terms. We and Holdings may agree to amend our amended and restated
omnibus agreement; however, amendments that the general partner determines are adverse to our unitholders will also require the approval of the conflicts
committee.
Payment
of
Administrative
Fee
and
Reimbursement
of
Expenses
We pay an annual administrative fee of $4.0 million in quarterly installments to Holdings. The administrative fee is intended to reimburse Holdings for providing
us with certain partnership overhead services, including for certain executive management services by certain officers of our general partner, and for paying on our
behalf all compensation expense for the employees required to manage and operate our business and all expenses incurred by us as a result of our becoming and
continuing as a publicly traded entity, including costs associated with Exchange Act filings, independent public accounting firm fees, partnership governance and
compliance, registrar and transfer agent fees, tax return and Schedule K-1 preparation and distribution, legal fees and director compensation.
The amount of the administrative fee is subject to increase each year by the percentage equal to the increase, if any, in the PPI plus 1.0%. In addition, the
administrative fee may be increased with the approval of our conflicts committee in the event of an expansion of our operations, including though acquisitions or
internal growth, a change in applicable law or regulation, or as agreed upon by us and our general partner.
In 2017, we only paid two of the $1.0 million quarterly installments, as Holdings waived the other two quarterly installments of the administrative fee. In addition,
Holdings contributed $2.3 million to us during 2017.
Right
of
First
Offer
Under our amended and restated omnibus agreement, if Holdings or its controlled subsidiaries decide to sell, transfer or otherwise dispose of any of their assets or
entities within a five-year period following the closing of the IPO, Holdings will provide notice to us of such intended disposition and provide us with the
opportunity to make the first offer on any assets used in, or entities engaged primarily in, providing salt water disposal and other water and environmental services
to U.S. onshore oil and natural gas producers and trucking companies in the U.S., including any assets or entities currently owned by or acquired from SBG Energy
Services, LLC.
After receiving the notice of Holdings’ intention to sell or transfer such assets, we will have 45 days to make an offer to Holdings with our proposed terms for the
acquisition. The consummation and timing of any acquisition by us of the assets covered by our right of first offer will depend upon, among other things, our
ability to reach an agreement with Holdings on price and other terms and our ability to obtain financing on acceptable terms. Accordingly, we can provide no
assurance whether, when or on what terms we will be able to successfully consummate any future acquisitions pursuant to our right of first offer, and Holdings is
under no obligation to accept any offer that we may choose to make or to enter into any commercial agreements with us.
127
Indemnification
Under our amended and restated omnibus agreement, Holdings will indemnify us, without giving effect to any cap, for the following matters:
● Environmental : all known and unknown environmental liabilities that are associated with the ownership or operation of our assets and due to
occurrences on or before the closing of the IPO. Indemnification for any unknown environmental liabilities will be limited to liabilities arising out of
occurrences in existence before the closing of the IPO and identified prior to the third anniversary of the closing of the IPO, and will be subject to an
aggregate deductible of $350,000 before we are entitled to indemnification;
● Retained Assets : all events and conditions associated with any assets retained by Holdings regardless of when they occur;
●
●
●
●
●
IPO Transactions : for a period of five years after the closing of the IPO to the extent not covered by other indemnifications in our amended and
restated omnibus agreement, the formation transactions, asset contributions and ownership of the contributed assets prior to the closing, as well as any
event or condition that arise out of ownership of the contributed assets prior to closing;
Titles and Permits : for a period of five years after the closing of the IPO, any failure to have at the closing of the offering any title, right of way,
consent, license, permit, or approval necessary for us to own or operate our assets in substantially the same manner that the assets were owned or
operated immediately prior to the closing of the IPO and as described in this report, subject to an aggregate deductible of $500,000;
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 and for environmental liabilities related to our assets 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 $0.6 million
during 2017.
128
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.
129
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 for the years ended December 31, 2016, and 2015 and 2014.
Audit and Non-Audit Fees
2017
Years Ended December 31,
2016
(in thousands)
2015
Audit fees (a)
Audit-related fees (b)
Tax fees (c)
All other fees
Total
$
$
561 $
—
117
—
678 $
663 $
—
283
—
946 $
870
70
194
—
1,134
(a) Fees for audit services include fees associated with the annual audit of Cypress Energy Partners, L.P. and reviews of the
Partnership’s quarterly reports.
(b)
Includes fees related to acquisition due diligence and accounting consultations.
(c)
Includes fees for tax services for Cypress Energy Partners, L.P. and affiliates in connection with tax compliance, tax advice
and tax planning.
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.
130
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Documents to be filed as part of this Annual Report
PART IV
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 number Description
Exhibit Index
2.1
3.1
3.2
3.3
3.4
Contribution, Conveyance and Assumption Agreement, dated February 20, 2015, by and among Cypress Energy Holdings, LLC, Cypress
Energy Partners, LLC, Cypress Energy Partners, L.P., Cypress Energy 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)
First Amended and Restated Agreement of Limited Partnership of Cypress Energy 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)
Certificate of Formation of Cypress Energy Partners GP, LLC (incorporated by reference to Exhibit 3.5 of our Registration Statement on Form
S-1/A filed on December 17, 2013)
Amended and Restated Limited Liability Company Agreement of Cypress Energy 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)
Certificate of Limited Partnership of Cypress Energy Partners, L.P. (incorporated by reference to Exhibit 3.7 of our Registration Statement on
Form S-1/A filed on December 17, 2013)
10.1†
Cypress Energy 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†
Form of Cypress Energy Partners, L.P. 2013 Long-Term Incentive Plan Phantom Unit Agreement (incorporated by reference to Exhibit 10.4 of
10.3
10.4
10.5
our Registration Statement on Form S-1/A filed on December 17, 2013)
Credit Agreement, dated as of December 24, 2013 between Cypress, as borrower, certain of its affiliates as co-borrowers and guarantors,
Deutsche Bank AG, New York Branch, as a lender, swing line lender and collateral agent, the other lenders from time to time party thereto,
and Deutsche Bank Trust Company Americas, as the administrative agent (incorporated by reference to Exhibit 10.5 of our Registration
Statement on Form S-1/A filed on January 10, 2014)
Amendment No. 1 to Credit Agreement, dated as of October 21, 2014 between Cypress, as borrower, certain of its affiliates as co-borrowers
and guarantors, Deutsche Bank AG, New York Branch, as collateral agent, lender, issuing bank and swing line lender, the other lenders from
time to time party thereto, and Deutsche Bank Trust Company Americas, as the administrative agent (incorporated by reference to Exhibit 10.1
of our Current Report on Form 8-K filed on October 24, 2014)
Amended and Restated Omnibus Agreement, dated February 20, 2015, among Cypress Energy Holdings, LLC, Cypress Energy Management,
LLC, Cypress Energy Partners, LLC, Cypress Energy Partners, L.P., Cypress Energy 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)
131
10.6
Amendment No. 2 to Credit Agreement, dated May 4, 2015, by and among Cypress Energy Partners, L.P., Cypress Energy Partners – TIR,
LLC, Cypress Energy Partners, LLC and Tulsa Inspection Resources, LLC, as borrowers, Tulsa Inspection Resources – Canada ULC, the
guarantors party thereto, Deutsche Bank AG, New York Branch, in its capacity as collateral agent and as a lender, issuing bank and swing line
lender, Deutsche Bank Trust Company Americas, in its capacity as administrative agent, and the several banks and other financial institutions
or entities from time to time parties thereto (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed on May 7,
2015)
21.1*
List of Subsidiaries of Cypress Energy 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
*
Filed herewith.
** Furnished herewith.
† Management contract or compensatory plan or arrangement.
132
ITEM 16.
SUMMARY
None.
133
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, in the City of Tulsa, State of Oklahoma, on March 23, 2018.
SIGNATURES
Cypress Energy Partners, L.P.
By: Cypress Energy Partners GP, LLC, its general partner
/s/ Jeffrey A. Herbers
By:
Title: Vice President and Chief Accounting Officer,
Jeffrey A. Herbers
(Principal Accounting and Interim Principal 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 indicated.
Signature
Title
Date
/s/ Peter C. Boylan III
Peter C. Boylan III
/s/ Jeffrey A. Herbers
Jeffrey A. Herbers
/s/ Henry Cornell
Henry Cornell
/s/ Stanley A. Lybarger
Stanley A. Lybarger
/s/ John T. McNabb II
John T. McNabb II
/s/ Charles C. Stephenson, Jr.
Charles C. Stephenson, Jr.
Chief Executive Officer and Chairman of the Board
March 23, 2018
Vice President and Chief Accounting Officer,
(Principal Accounting and Interim Principal Financial Officer)
Director
Director
Director
Director
134
March 23, 2018
March 23, 2018
March 23, 2018
March 23, 2018
March 23, 2018
Cypress Energy Partners, L.P. 10-K
Subsidiaries of the Partnership
Brown Integrity - PUC, LLC
Brown Integrity, LLC
CF Inspection Management, LLC
Cypress Energy Finance Corporation
Cypress Energy Partners - 1804 SWD, LLC
Cypress Energy Partners - Bakken, LLC
Cypress Energy Partners - Grassy Butte SWD, LLC
Cypress Energy Partners - Green River SWD, LLC
Cypress Energy Partners - Manning SWD, LLC
Cypress Energy Partners - Mork SWD, LLC
Cypress Energy Partners - Mountrail SWD, LLC
Cypress Energy Partners - Orla SWD, LLC
Cypress Energy Partners - SBG, LLC
Cypress Energy Partners - Texas, LLC
Cypress Energy Partners - Tioga SWD, LLC
Cypress Energy Partners - Williams SWD, LLC
Cypress Energy Partners, LLC
Cypress Energy Services, LLC
Pipeline Services International, LLC
Tulsa Inspection Resources - Canada ULC
Tulsa Inspection Resources - Nondestructive Examination, LLC
Tulsa Inspection Resources - PUC, LLC
Tulsa Inspection Resources, LLC
Exhibit 21.1
Jurisdiction of
Incorporation / Formation
Delaware
Texas
Delaware
Delaware
North Dakota
Delaware
North Dakota
North Dakota
North Dakota
Delaware
Delaware
Delaware
Delaware
Texas
North Dakota
Delaware
Delaware
Delaware
Texas
Alberta
Delaware
Delaware
Delaware
Cypress Energy Partners, L.P. 10-K
Exhibit 23.1
Consent of Independent Registered Public Accounting Firm
We consent to the incorporation by reference in the following Registration Statements:
(1) Registration Statement (Form S-3 No. 333-204786) of Cypress Energy Partners, L.P., and
(2) Registration Statement (Form S-8 No. 333-193445) pertaining to the 2013 Long Term Incentive Plan of Cypress Energy Partners, L.P.;
of our report dated March 23, 2018, with respect to the consolidated financial statements of Cypress Energy Partners, L.P. included in this Annual Report
(Form 10-K) of Cypress Energy Partners L.P. for the year ended December 31, 2017.
/s/ Ernst & Young LLP
Tulsa, Oklahoma
March 23, 2018
Cypress Energy Partners, L.P. 10-K
I, Peter C. Boylan III, certify that:
CERTIFICATION OF CHIEF EXECUTIVE OFFICER
PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)
OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED
Exhibit 31.1
1.
2.
3.
4.
I have reviewed this Annual Report on Form 10-K of Cypress Energy Partners, L.P. (the “registrant”);
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial
condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for
the registrant and have:
a.
b.
c.
d.
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to
ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being prepared;
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our
supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting principles;
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially
affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the
registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.
b.
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably
likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control
over financial reporting.
Date: March 23, 2018
/ s / Peter C. Boylan III
Peter C. Boylan III
Chief Executive Officer
Cypress Energy Partners GP, LLC
( as general partner of Cypress Energy Partners, L.P.)
Cypress Energy Partners, L.P. 10-K
I, Jeffrey A. Herbers, certify that:
CERTIFICATION OF CHIEF FINANCIAL OFFICER
PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)
OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED
Exhibit 31.2
1.
2.
3.
4.
I have reviewed this Annual Report on Form 10-K of Cypress Energy Partners, L.P. (the “registrant”);
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial
condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for
the registrant and have:
a.
b.
c.
d.
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to
ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being prepared;
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our
supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting principles;
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially
affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the
registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.
b.
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably
likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control
over financial reporting.
Date: March 23, 2018
/s/ Jeffrey A. Herbers
Jeffrey A. Herbers
Vice President, Chief Accounting Officer and Interim Principal Financial
Officer
Cypress Energy Partners GP, LLC
( as general partner of Cypress Energy Partners, L.P.)
Cypress Energy Partners, L.P. 10-K
Exhibit 32.1
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report on Form 10-K of Cypress Energy Partners, L.P. (the “Partnership”), as filed with the Securities and Exchange Commission
on the date hereof (the “Report”), the undersigned, Peter C. Boylan III, Chief Executive Officer of Cypress Energy Partners GP, LLC, the general partner of
Cypress Energy Partners, L.P. and Jeffrey A. Herbers, Chief Accounting Officer and Interim Principal Financial Officer of Cypress Energy Partners GP, LLC,
certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:
(1)
(1)
the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.
Date: March 23, 2018
Date: March 23, 2018
/s/ Peter C. Boylan
Peter C. Boylan III
Chief Executive Officer
Cypress Energy Partners GP, LLC
(as general partner of Cypress Energy Partners, L.P.)
/s/ Jeffrey A. Herbers
Jeffrey A. Herbers
Vice President, Chief Accounting Officer and Interim Principal Financial
Officer
Cypress Energy Partners GP, LLC
(as general partner of Cypress Energy Partners, L.P.)