10-Q

UNITED STATES 

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(MARK ONE)

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

For the quarterly period ended September 30, 2018

or

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

FOR THE TRANSITION PERIOD FROM _________ TO _________

Commission File Number 001-36260

CYPRESS ENERGY PARTNERS, L.P.

(Exact name of Registrant as specified in its charter)

Delaware	61-1721523
(State of or other jurisdiction of  incorporation or organization)	(I.R.S. Employer  Identification No.)
5727 South Lewis Avenue, Suite 300
Tulsa, Oklahoma	74105
(Address of principal executive offices)	(zip code)

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

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files).   Yes ☒  No ☐

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

Large accelerated filer  ☐ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☒ Emerging growth company ☐

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

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

As of November 7, 2018, the registrant had 11,946,040 common units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:     None.

CYPRESS ENERGY PARTNERS, L.P.

  Table of Contents

		Page
PART I – FINANCIAL INFORMATION
ITEM 1.	Unaudited Condensed Consolidated Financial Statements	5
	Unaudited Condensed Consolidated Balance Sheets as of September 30, 2018 and December 31, 2017	5
	Unaudited Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2018 and 2017	6
	Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss) for the Three and Nine Months Ended September 30, 2018 and 2017	7
	Unaudited Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2018 and 2017	8
	Unaudited Condensed Consolidated Statement of Owners’ Equity for the Nine Months Ended September 30, 2018	9
	Notes to the Unaudited Condensed Consolidated Financial Statements	10
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
ITEM 3.	Quantitative and Qualitative Disclosures about Market Risk	48
ITEM 4.	Controls and Procedures	49
PART II – OTHER INFORMATION
ITEM 1.	Legal Proceedings	49
ITEM 1A.	Risk Factors	50
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	50
ITEM 3.	Defaults upon Senior Securities	50
ITEM 4.	Mine Safety Disclosures	50
ITEM 5.	Other Information	50
ITEM 6.	Exhibits	51
SIGNATURES		52

  2

NAMES OF ENTITIES

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

References to:

●  “Brown” refers to Brown Integrity, LLC, a 51% owned subsidiary of CEP LLC;

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

●  “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 47.0% of our outstanding common units;

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

●  “Pipeline & Process Services” refers to our Pipeline & Process Services (formerly referred to as our Integrity Services) business segment;

●  “Pipeline Inspection” refers to our Pipeline Inspection business segment;

●  “TIR Entities” refer collectively to TIR LLC, TIR-Canada, TIR-NDE, TIR-PUC and CF Inspection;

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

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

●  “TIR-NDE” refers to Tulsa Inspection Resources – Nondestructive Examination, 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 federal income tax purposes; and

●  “Water Services” refers to our Water and Environmental Services business segment.

  3

CAUTIONARY REMARKS REGARDING FORWARD-LOOKING STATEMENTS

The information discussed in this Quarterly Report on Form 10-Q 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 our Annual Report on Form 10-K for the year ended December 31, 2017 and in this 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 Quarterly Report on Form 10-Q and speak only as of the date of this Quarterly Report on Form 10-Q.  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.

  4

PART I.   FINANCIAL INFORMATION

ITEM 1. Unaudited Condensed Consolidated Financial Statements

CYPRESS ENERGY PARTNERS, L.P.
Unaudited Condensed Consolidated Balance Sheets
As of September 30, 2018 and December 31, 2017
(in thousands, except unit data)
	September 30,			December 31,
	2018			2017
ASSETS
Current assets:
Cash and cash equivalents	$	11,230		$	24,508
Trade accounts receivable, net		51,027			41,693
Prepaid expenses and other		1,511			2,294
Assets held for sale		—			2,172
Total current assets		63,768			70,667
Property and equipment:
Property and equipment, at cost		23,694			22,700
Less:  Accumulated depreciation		10,666			9,312
Total property and equipment, net		13,028			13,388
Intangible assets, net		23,433			25,477
Goodwill		50,370			53,435
Debt issuance costs, net		1,391			—
Other assets		285			236
Total assets	$	152,275		$	163,203
LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable	$	2,230		$	3,757
Accounts payable - affiliates		3,656			3,173
Accrued payroll and other		14,132			9,109
Liabilities held for sale		—			97
Income taxes payable		708			646
Current portion of long-term debt		—			136,293
Total current liabilities		20,726			153,075
Long-term debt		76,129			—
Other non-current liabilities		369			143
Total liabilities		97,224			153,218
Commitments and contingencies - Note 8
Owners’ equity:
Partners’ capital:
Common units (11,946,040 and 11,889,958 units outstanding at September 30, 2018 and December 31, 2017, respectively)		35,266			34,614
Preferred units (5,769,231 units outstanding at September 30, 2018)		44,671			—
General partner		(25,876	)		(25,876	)
Accumulated other comprehensive loss		(2,616	)		(2,677	)
Total partners’ capital		51,445			6,061
Noncontrolling interests		3,606			3,924
Total owners’ equity		55,051			9,985
Total liabilities and owners’ equity	$	152,275		$	163,203

See accompanying notes.

  5

CYPRESS ENERGY PARTNERS, L.P.

Unaudited Condensed Consolidated Statements of Operations

For the Three and Nine Months Ended September 30, 2018 and 2017

(in thousands, except unit and per unit data) 

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Revenue	$	84,778		$	77,682		$	226,072		$	216,971
Costs of services		71,870			68,292			194,092			192,643
Gross margin		12,908			9,390			31,980			24,328
Operating costs and expense:
General and administrative		6,064			5,574			17,341			16,013
Depreciation, amortization and accretion		1,124			1,184			3,368			3,561
Impairments		—			—			—			3,598
(Gains) losses on asset disposals, net		(822	)		208			(4,137	)		95
Operating income		6,542			2,424			15,408			1,061
Other (expense) income:
Interest expense, net		(1,283	)		(1,907	)		(4,907	)		(5,411	)
Debt issuance cost write-off		—			—			(114	)		—
Foreign currency gains (losses)		97			557			(354	)		824
Other, net		95			17			302			122
Net income (loss) before income tax expense		5,451			1,091			10,335			(3,404	)
Income tax expense		497			529			865			458
Net income (loss)		4,954			562			9,470			(3,862	)
Net income (loss) attributable to noncontrolling interests		289			8			673			(1,290	)
Net income (loss) attributable to partners / controlling interests		4,665			554			8,797			(2,572	)
Net loss attributable to general partner		—			(1,000	)		—			(2,750	)
Net income attributable to limited partners		4,665			1,554			8,797			178
Net income attributable to preferred unitholder		1,045			—			1,412			—
Net income attributable to common unitholders	$	3,620		$	1,554		$	7,385		$	178
Net income per common limited partner unit:
Basic	$	0.30		$	0.13		$	0.62		$	0.02
Diluted	$	0.26		$	0.13		$	0.59		$	0.02
Weighted average common units outstanding:
Basic		11,940,032			11,884,196			11,924,183			10,902,838
Diluted		18,140,691			11,994,881			14,970,434			11,111,454
Weighted average subordinated units outstanding - basic and diluted		—			—			—			974,670

See accompanying notes.

6

CYPRESS ENERGY PARTNERS, L.P.

Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss)

For the Three and Nine Months Ended September 30, 2018 and 2017

(in thousands) 

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018		2017
Net income (loss)	$	4,954		$	562		$	9,470	$	(3,862	)
Other comprehensive income (loss) - foreign currency translation		(71	)		(207	)		61		(187	)
Comprehensive income (loss)	$	4,883		$	355		$	9,531	$	(4,049	)
Comprehensive income attributable to preferred unitholders		1,045			—			1,412		—
Comprehensive income (loss) attributable to noncontrolling interests		289			8			673		(1,290	)
Comprehensive loss attributable to general partner		—			(1,000	)		—		(2,750	)
Comprehensive income (loss) attributable to common unitholders	$	3,549		$	1,347		$	7,446	$	(9	)

See accompanying notes.

7

CYPRESS ENERGY PARTNERS, L.P.

Unaudited Condensed Consolidated Statements of Cash Flows

For the Nine Months Ended September 30, 2018 and 2017

(in thousands)

	Nine Months Ended September 30,
	2018			2017
Operating activities:
Net income (loss)	$	9,470		$	(3,862	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, amortization and accretion		4,186			4,378
Impairments		—			3,598
(Gain) loss on asset disposals, net		(4,137	)		95
Interest expense from debt issuance cost amortization		429			443
Debt issuance cost write-off		114			—
Equity-based compensation expense		908			1,136
Equity in earnings of investee		(169	)		(98	)
Distributions from investee		113			75
Deferred tax benefit, net		—			(361	)
Non-cash allocated expenses		—			1,750
Foreign currency (gains) losses, net		354			(824	)
Changes in assets and liabilities:
Trade accounts receivable		(9,395	)		(11,583	)
Prepaid expenses and other		891			(765	)
Accounts payable and accrued payroll and other		4,129			6,552
Income taxes payable		62			(271	)
Net cash provided by operating activities		6,955			263
Investing activities:
Proceeds from fixed asset disposals		12,762			1,578
Purchases of property and equipment, excluding capital leases		(5,466	)		(1,182	)
Net cash provided by investing activities		7,296			396
Financing activities:
Issuance of preferred units, net of issuance costs		43,259			—
Repayments of long-term debt		(60,771	)		—
Debt issuance cost payments		(1,327	)		—
Taxes paid related to net share settlement of equity-based compensation		(131	)		(120	)
Contributions attributable to general partner		—			1,000
Capital lease repayments		(8	)		—
Distributions to limited partners		(7,510	)		(9,813	)
Distributions to noncontrolling interests		(991	)		(12	)
Net cash used in financing activities		(27,479	)		(8,945	)
Effect of exchange rates on cash		11			831
Net decrease in cash and cash equivalents and restricted cash equivalents		(13,217	)		(7,455	)
Cash and cash equivalents (including restricted cash equivalents of $490 at December 31, 2017 and December 31, 2016), beginning of period		24,998			27,183
Cash and cash equivalents (including restricted cash equivalents of $551 at September 30, 2018 and $490 at September 30, 2017), end of period	$	11,781		$	19,728
Non-cash items:
Accounts payable excluded from capital expenditures	$	75		$	320
Acquisitions of property and equipment included in liabilities	$	335		$	—

See accompanying notes. 

8

CYPRESS ENERGY PARTNERS, L.P.

Unaudited Condensed Consolidated Statement of Owners’ Equity

For the Nine Months Ended September 30, 2018

(in thousands) 

	Common Units			Preferred Units		General Partner			Accumulated Other Comprehensive Loss			Noncontrolling Interests			Total Owners’ Equity
Owners’ equity at December 31, 2017	$	34,614		$	—	$	(25,876	)	$	(2,677	)	$	3,924		$	9,985
Net income for the period January 1, 2018 through September 30, 2018		7,385			1,412		—			—			673			9,470
Issuance of preferred units, net		—			43,259		—			—			—			43,259
Foreign currency translation adjustment		—			—		—			61			—			61
Distributions to partners		(7,510	)		—		—			—			—			(7,510	)
Distributions to noncontrolling interests		—			—		—			—			(991	)		(991	)
Equity-based compensation		908			—		—			—			—			908
Taxes paid related to net share settlement of equity-based compensation		(131	)		—		—			—			—			(131	)
Owners’ equity at September 30, 2018	$	35,266		$	44,671	$	(25,876	)	$	(2,616	)	$	3,606		$	55,051

See accompanying notes.

9

CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

1. Organization and Operations

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

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

The Water Services segment owns and operates nine (9) Environmental Protection Agency Class II saltwater disposal facilities in the Williston Basin region of North Dakota.  Eight (8) of the facilities are wholly-owned and we have ten (10) pipelines from multiple E&P customers connected to these saltwater disposal facilities, including two (2) that were developed and are owned by the Partnership.  Approximately 95% of our disposal water is produced water that is generated during the production life of an oil and gas well and approximately 41% of our water is delivered via pipeline to our saltwater disposal facilities.  We currently serve in excess of 75 customers.  Our saltwater disposal facilities provide essential midstream services to oil and natural gas upstream producers and their transportation companies. All of the saltwater disposal facilities utilize specialized equipment and remote monitoring to minimize the facilities’ downtime and increase the facilities’ efficiency for peak utilization. These facilities also utilize oil skimming and recovery processes that remove residual oil from water delivered to our saltwater disposal facilities via pipeline or truck. We sell the oil recovered from these skimming processes, which contributes to our revenues. In addition to these saltwater disposal facilities, we provide management and staffing services to a saltwater disposal facility in which we own a 25% ownership interest (see Note 7).

2. Basis of Presentation and Summary of Significant Accounting Policies

Basis of Presentation

The Unaudited Condensed Consolidated Financial Statements as of and for the three months ended September 30, 2018 and 2017 and for the nine months ended September 30, 2018 and 2017 include our accounts and those of our controlled subsidiaries. Investments over which we exercise significant influence, but do not control, are accounted for using the equity method of accounting. Intercompany transactions and account balances have been eliminated in consolidation. The Unaudited Condensed Consolidated Balance Sheet at December 31, 2017 is derived from our audited financial statements.

The accompanying Unaudited Condensed Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim consolidated financial information and in accordance with the rules and regulations of the Securities and Exchange Commission (the “SEC”). The Unaudited Condensed Consolidated Financial Statements include all adjustments considered necessary for a fair presentation of the consolidated financial position and consolidated results of operations for the interim periods presented. Such adjustments consist only of normal recurring items, unless otherwise disclosed herein. Accordingly, the Unaudited Condensed Consolidated Financial Statements do not include all of the information and notes required by GAAP for complete consolidated financial statements. However, we believe that the disclosures made are adequate to make the information not misleading. These interim Unaudited Condensed Consolidated Financial Statements should be read in conjunction with our audited financial statements as of and for the year ended December 31, 2017 included in our Form 10-K. The results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

Use of Estimates in the Preparation of Financial Statements

The preparation of our Unaudited Condensed Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in these financial statements and accompanying notes. Actual results could differ from those estimates.

10

CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

Significant Accounting Policies

Our significant accounting policies are consistent with those disclosed in Note 2 to our audited financial statements as of and for the year ended December 31, 2017 included in our Form 10-K, except for the adoption of Accounting Standards Update (“ASU”) 2014-09 - Revenue from Contracts with Customers and ASU 2016-18 - Statement of Cash Flows - Restricted Cash on January 1, 2018. Under ASU 2014-09, an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Based on this new accounting guidance, our revenue is earned and recognized through the service offerings of our three reportable business segments. Our sales contracts have terms of less than one year. As such, we have used the practical expedient contained within the accounting guidance which exempts us from the requirement to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract with an original expected duration of one year or less. See Note 10 for disaggregated revenue reported by segment and for disclosure regarding variable consideration. The adoption and application of this ASU had no effect on our Unaudited Condensed Consolidated Financial Statements, other than additional disclosures included in this Form 10-Q. Under ASU 2016-18, an entity is required to show changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents in the statement of cash flows. The adoption and application of this ASU has modified the presentation of cash, cash equivalents, restricted cash, and restricted cash equivalents on our Unaudited Condensed Consolidated Statements of Cash Flows applied on a retrospective basis.

Accounts Receivable and Allowance for Bad Debts

We grant unsecured credit to customers under normal industry standards and terms, and have established policies and procedures that allow for an evaluation of each of our customer’s creditworthiness. We typically receive payment from our customers 45 to 90 days after the services have been performed.  The Partnership determines allowances for bad debts based on management’s assessment of the creditworthiness of our customers. Trade receivables are written off against the allowance when deemed uncollectible. Recoveries of trade receivables previously written off are recorded when cash is received. In the first quarter of 2017, we received $0.3 million on accounts receivable previously reserved, which we recorded as a reduction to general and administrative expense in our Unaudited Condensed Consolidated Statements of Operations.

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, a subsidiary of our Pipeline Inspection segment that performs pipeline inspection services for utility customers, and Brown Integrity – PUC, LLC, a subsidiary in which we own a 51% membership interest, 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 tax. The amounts recognized as income tax expense (benefit), income taxes payable, and deferred tax assets / liabilities in our Unaudited Condensed Consolidated Financial Statements include the Canadian income taxes and U.S. federal and state income taxes referred to above, as well as partnership-level taxes levied by various states, which primarily include franchise taxes assessed by the state of Texas.

As a publicly-traded partnership, we are subject to a statutory requirement that 90% of our total gross income represent “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations, and Internal Revenue Service pronouncements), determined on a calendar-year basis. 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 each year since our initial public offering (“IPO”).

11

CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

Noncontrolling Interest

We own a 51% interest in Brown Integrity, LLC (“Brown”) and a 49% interest in CF Inspection Management, LLC (“CF Inspection”). The accounts of these subsidiaries are included in our Unaudited Condensed Consolidated Financial Statements. The portion of the net income (loss) of these entities that is attributable to outside owners is reported as net income (loss) attributable to noncontrolling interests in our Unaudited Condensed Consolidated Statements of Operations, and the portion of the net assets of these entities that is attributable to outside owners is reported as noncontrolling interests in our Unaudited Condensed Consolidated Balance Sheets.

Property and Equipment

Property and equipment consists of land, land and leasehold improvements, buildings, facilities, wells and related equipment, computer and office equipment, and vehicles. We record property and equipment at cost. Costs of 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 or disposition 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 Unaudited Condensed Consolidated Statements of Operations.

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 exceeds the future undiscounted cash flows expected from the asset, we recognize an impairment charge for the excess of the carrying value of the asset over its estimated fair value. Determinations as to whether and how much an asset is impaired involve 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.

Identifiable Intangible Assets

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

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 values of the assets to their fair values and record a corresponding impairment loss.

Goodwill

Goodwill is not amortized, but is subject to an annual review for impairment on November 1 (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 used to evaluate and measure goodwill for impairment are determined primarily from the manner in which the business that relates to the applicable goodwill is managed or operated. We have determined that our Pipeline Inspection, Pipeline & Process Services, and Water Services segments are the appropriate reporting units for testing goodwill impairment.

To perform a goodwill impairment assessment, we perform an analysis to assess whether it is more likely than not that the fair value of the reporting unit exceeds its carrying value. If we determine that it is more likely than not that the carrying value of the reporting unit exceeds its fair value, we reduce the carrying value of goodwill and record a corresponding impairment expense.

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CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

Accrued Payroll and Other

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

	September 30, 2018		December 31, 2017
	(in thousands)
Accrued payroll	$	11,148	$	6,893
Customer deposits		1,893		1,510
Other		1,091		706
	$	14,132	$	9,109

Foreign Currency Translation

Our Unaudited Condensed 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 in which the applicable revenues and expenses were recorded.

Our Unaudited Condensed Consolidated Balance Sheet at September 30, 2018 includes $2.6 million of accumulated other comprehensive loss associated with accumulated currency translation adjustments, all of which relate to our Canadian operations. If at some point in the future we were to 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 Unaudited Condensed Consolidated Statement of Operations as a reduction to net income.

Our Canadian subsidiary has certain intercompany payables to our U.S.-based subsidiaries. These intercompany payables and receivables among our consolidated subsidiaries are eliminated in our Unaudited Condensed Consolidated Balance Sheets. Beginning April 1, 2017, we report currency translation adjustments on these intercompany payables and receivables within foreign currency gains (losses) in our Unaudited Condensed Consolidated Statements of Operations, with offsetting amounts reported within other comprehensive income (loss) in our Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss).

New Accounting Standards

On January 1, 2018, we adopted the following new accounting standards issued by the Financial Accounting Standards Board (“FASB”);

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

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

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CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

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

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

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

In July 2018, the FASB issued ASU 2018-11 – Targeted Improvements which provides entities with a transition option to not restate the comparative periods for the effects of applying the new leasing standard (i.e. comparative periods presented in the Unaudited Condensed Consolidated Financial Statements will continue to be in accordance with Accounting Standards Codification 840).  We will adopt the new standard on the effective date of January 1, 2019 and expect to use a modified retrospective approach as permitted under ASU 2018-11.  We continue to evaluate the impact this ASU will have on our Unaudited Condensed Consolidated Balance Sheets and the related disclosures.  We expect the effects of implementing ASU 2016-02 will be material to our Unaudited Condensed Consolidated Balance Sheets related to the addition of the right-of-use asset and associated lease liability, but immaterial to our Unaudited Condensed Consolidated Statements of Operations and Unaudited Condensed Consolidated Statements of Cash Flows. Liabilities recorded as a result of this standard will be excluded from the definition of indebtedness under our credit facility and therefore, will not adversely impact the leverage ratio under our credit facility.

3. Impairments

During the three months ended March 31, 2017, the largest customer of TIR-Canada, the Canadian subsidiary of our Pipeline Inspection segment, completed a bid process and selected different service providers for its inspection projects. These rates were lower than we were prepared to extend to this client. In consideration of the expiration and non-renewal of this contract, we recorded impairments to the carrying values of certain intangible assets of $1.3 million during the three months ended March 31, 2017. Of this amount, $1.1 million related to customer relationships and $0.2 million related to trade names.

During the three months ended March 31, 2017, we recorded an impairment to the remaining $1.6 million carrying value of the goodwill of our Pipeline & Process Services segment. Revenues of this segment were lower than we had expected for the first quarter of 2017. In addition, for this segment, the level of bidding activity for work is typically high in March and April once customers have finalized their budgets for the upcoming year. While we won bids on a number of projects, and our backlog began to improve, the improvement in the backlog was slower than we had originally anticipated, and we revised downward our expectations of the near-term operating results of the segment. We estimated the fair value of the Pipeline & Process Services segment utilizing the income approach (discounted cash flows valuation method), which is a Level 3 input as defined in ASC 820 – Fair Value Measurement. Significant inputs in the valuation included projections of future revenue, anticipated operating costs and appropriate discount rates. Significant assumptions included a 2% annual growth rate of cash flows and a discount rate of 18%. We determined through this analysis that the fair value of goodwill of the Pipeline & Process Services segment was fully impaired. These calculations represent Level 3 non-recurring fair value measurement.

During the three months ended March 31, 2017, we recorded an impairment of $0.7 million to the property and equipment at one of our saltwater disposal facilities. We have experienced low volumes at this facility due to competition in the area and to low levels of exploration and production activity near the facility. The impairment reduced the carrying value of the facility to $0.1 million, all of which is attributable to land.

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CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

4. Debt

Credit Agreement

On May 29, 2018, we entered into an amended and restated credit agreement (as amended and restated, the “Credit Agreement”) that provides up to $90.0 million in borrowing capacity, subject to certain limitations, and contains an accordion feature that allows us to increase the borrowing capacity to $110.0 million if the lenders agree to increase their commitments in the future or if other lenders join the facility. The three-year Credit Agreement matures May 29, 2021. The obligations under the Credit Agreement are secured by a first priority lien on substantially all of our assets. The credit agreement as it existed prior to the May 29, 2018 amendment will hereinafter be referred to as the “Previous Credit Agreement” or, together with the Credit Agreement, as the “Credit Agreements”.

Outstanding borrowings at September 30, 2018 were $76.1 million and are reflected as long-term debt on the Unaudited Condensed Consolidated Balance Sheets beginning May 29, 2018. Debt issuance costs are reported as debt issuance costs, net on the Unaudited Condensed Consolidated Balance Sheets and total $1.4 million at September 30, 2018. Outstanding borrowings at December 31, 2017 were $136.9 million and are reflected net of debt issuance costs of $0.6 million as current portion of long-term debt on the Unaudited Condensed Consolidated Balance Sheet. At December 31, 2017, the outstanding balance was classified as current due to the fact that the facility was scheduled to mature within one year. The carrying value of our long-term debt approximates fair value, as the borrowings under the Credit Agreement are considered to be priced at market for debt instruments having similar terms and conditions (Level 2 of the fair value hierarchy).

We incurred certain debt issuance costs associated with the Previous Credit Agreement, which we were amortizing on a straight-line basis over the life of the Previous Credit Agreement. Upon amending the Credit Agreement in May 2018, we wrote off $0.1 million of these debt issuance costs and reported this expense within debt issuance cost write-off in our Unaudited Condensed Consolidated Statements of Operations for the nine months ended September 30, 2018, which represented the portion of the unamortized debt issuance costs attributable to lenders who are no longer participating in the credit facility subsequent to the amendment. The remaining debt issuance costs associated with the Previous Credit Agreement, along with $1.3 million of debt issuance costs associated with the amended and restated Credit Agreement, are being amortized on a straight-line basis over the three-year term of the Credit Agreement.

All borrowings under the Credit Agreement bear interest, at our option, on a leveraged based grid pricing at (i) a base rate plus a margin of 1.5% to 3.0% per annum (“Base Rate Borrowing”) or (ii) an adjusted LIBOR rate plus a margin of 2.5% to 4.0% per annum (“LIBOR Borrowings”). The applicable margin is determined based on the leverage ratio of the Partnership, as defined in the Credit Agreement. Generally, the interest rate on our borrowings ranged between 4.74% and 5.95% for the nine months ended September 30, 2018 and 3.90% and 4.99% for the nine months ended September 30, 2017. Interest on Base Rate Borrowings is payable monthly. Interest on LIBOR Borrowings is paid upon maturity of the underlying LIBOR contract, but no less often than quarterly. Commitment fees are charged at a rate of 0.50% on any unused credit and are payable quarterly. Interest paid during the three months ended September 30, 2018 and 2017 was $1.1 million and $1.7 million respectively, including commitment fees. Interest paid during the nine months ended September 30, 2018 and 2017 was $4.6 million and $5.0 million, respectively, including commitment fees.

The Credit Agreement contains various customary covenants and restrictive provisions. The Credit Agreement also requires maintenance of certain financial covenants, including a leverage ratio (as defined in the Credit Agreement) of not more than 4.0 to 1.0 and an interest coverage ratio (as defined in the Credit Agreement) of not less than 3.0 to 1.0. At September 30, 2018, our leverage ratio was 3.32 to 1.0 and our interest coverage ratio was 5.24 to 1.0, pursuant to the Credit Agreement. Upon the occurrence and during the continuation of an event of default, subject to the terms and conditions of the Credit Agreement, the lenders may declare any outstanding principal, together with any accrued and unpaid interest, to be immediately due and payable and may exercise the other remedies set forth or referred to in the Credit Agreement. We were in compliance with all debt covenants as of September 30, 2018.

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

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CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

Capital Leases

During the third quarter of 2018, our Pipeline and Process Services and Water Services segments leased vehicles for $0.3 million under lease agreements at interest rates of 6.16% that are classified as capital leases. The leased vehicles are amortized on a straight-line basis over the lease terms of four years. Minimum lease payments will be less than $0.1 million in 2018 and $0.1 million for the years ended December 31, 2019 through 2021. The $0.3 million capital lease obligation is reflected in the Unaudited Condensed Consolidated Balance Sheet at September 30, 2018 in accrued payroll and other ($0.1 million) and other non-current liabilities ($0.2 million).

5. Income Taxes

The income tax expense reported in our Unaudited Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2018 and 2017 differs from the statutory tax rate of 21% in 2018 and 35% in 2017 due to the fact that, as a partnership, we are generally not subject to U.S. federal or state income taxes. Our income tax provision relates primarily to (1) our U.S. corporate subsidiaries that provide services to public utility customers, which may not fit within the definition of qualified income as it is defined in the Internal Revenue Code, Regulations, and other guidance, which subjects this income to U.S. federal and state income taxes, (2) our Canadian subsidiary, which is subject to Canadian federal and provincial income taxes, and (3) certain other state income taxes, including the Texas franchise tax.

6. Equity

Series A Preferred Units

On May 29, 2018 (the “Closing Date”), we entered into a Series A Preferred Unit Purchase Agreement (the “Preferred Unit Purchase Agreement”) with Stephenson Equity, Co. No. 3 which subsequently assigned the units to Charles C. Stephenson, Jr. (the “Purchaser”), an affiliate of our General Partner, where we issued and sold in a private placement 5,769,231 Series A Preferred Units representing limited partner interests in the Partnership (the “Preferred Units”) to the Purchaser for a cash purchase price of $7.54 per Preferred Unit, resulting in proceeds to the Partnership of $43.5 million. We used proceeds from the transaction to reduce outstanding borrowings on our revolving credit facility. Concurrent with the closing of this transaction, we entered into an amended and restated Credit Agreement dated as of May 29, 2018, to amend and restate the terms of our credit facility, as more fully described in Note 4.

The Preferred Unit Purchase Agreement also provides us with the right to exercise an option at any time during the six months after the Closing Date, to issue and sell to the Purchaser up to $6.5 million of additional Preferred Units. The Preferred Unit Purchase Agreement sets forth the method of determining the purchase price of these additional units, which price would, in turn, determine the number of units to be issued and sold.

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

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

The Purchaser is entitled to receive quarterly distributions that represent an annual return of 9.5% on the Preferred Units. Of this 9.5% annual return, we will be required to pay at least 2.5% in cash and will have the option to pay the remaining 7.0% in kind (in the form of issuing additional preferred units) for the first twelve quarters after the Closing Date.  We intend to pay the first distribution on the Preferred Units of $1.4 million in November 2018 in cash. 

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CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

After the third anniversary of the Closing Date, the Purchaser will have the option to convert the Preferred Units into common units on a one-for-one basis. If certain conditions are met after the third anniversary of the Closing Date, we will have the option to cause the Preferred Units to convert to common units. After the third anniversary of the Closing Date, we will also have the option to redeem the Preferred Units. The Partnership may redeem the Preferred Units (a) before November 29, 2018 at a redemption price equal to 100% of the issue price (plus $0.2 million), (b) at any time after the third anniversary of the closing date and on or prior to the fourth anniversary of the closing date at a redemption price equal to 105% of the issue price, and (c) at any time after the fourth anniversary of the closing date at a redemption price equal to 101% of the issue price.

Earnings Per Unit

Our net income (loss) is attributable and allocable to four ownership groups: (1) our preferred unitholder, (2) the noncontrolling interests in certain subsidiaries, (3) our General Partner, and (4) our common unitholders. Income attributable to our preferred unitholder represents the 9.5% annual return to which the owner of the Preferred Units is entitled. Net income (loss) attributable to noncontrolling interests represent 49% of the income (loss) generated by Brown and 51% of the income (loss) generated by CF Inspection. Net loss attributable to the General Partner includes expenses incurred by Holdings and not charged to us. Net income (loss) attributable to common unitholders represents our remaining net income (loss), after consideration of amounts attributable to our preferred unitholder, the noncontrolling interests, and our General Partner. In February 2017, all the then-outstanding subordinated units converted into common units. Since the subordinated units did not share in the distribution of cash generated subsequent to December 31, 2016, we did not allocate any income or loss after that date to the subordinated units.

Basic net income (loss) per common limited partner unit is calculated as net income (loss) attributable to common unitholders divided by the basic weighted average common units outstanding. Diluted net income (loss) per common limited partner unit includes the net income attributable to preferred unitholder and the dilutive effect of the potential conversion of the preferred units and the dilutive effect of the unvested equity compensation. The following summarizes the calculation of the basic net income per common limited partner unit for the three and nine months ended September 30, 2018 and 2017:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
	(in thousands, except per unit data)
Net income attributable to common unitholders	$	3,620	$	1,554	$	7,385	$	178
Weighted average common units outstanding		11,940		11,884		11,924		10,903
Basic net income per common limited partner unit	$	0.30	$	0.13	$	0.62	$	0.02

The following summarizes the calculation of the diluted net income per common limited partner unit for the three and nine months ended September 30, 2018 and 2017:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
	(in thousands, except per unit data)
Net income attributable to common unitholders	$	3,620	$	1,554	$	7,385	$	178
Net income attributable to preferred unitholder		1,045		—		1,412		—
Net income attributable to limited partners	$	4,665	$	1,554	$	8,797	$	178
Weighted average common units outstanding		11,940		11,884		11,924		10,903
Effect of dilutive securities:
Weighted average preferred units outstanding		5,769		—		2,628		—
Long-term incentive plan unvested units		431		111		418		208
Diluted weighted average common units outstanding		18,140		11,995		14,970		11,111
Diluted net income per common limited partner unit	$	0.26	$	0.13	$	0.59	$	0.02

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CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

Cash Distributions

The following table summarizes the cash distributions declared and paid to our limited partners since our IPO.

					Total Cash
	Per Unit Cash		Total Cash		Distributions
Payment Date	Distributions		Distributions		to Affiliates (a)
			(in thousands)
Total 2014 Distributions		1.104646		13,064		8,296
Total 2015 Distributions		1.625652		19,232		12,284
Total 2016 Distributions		1.625652		19,258		12,414
February 13, 2017		0.406413		4,823		3,107
May 13, 2017		0.210000		2,495		1,606
August 12, 2017		0.210000		2,495		1,607
November 14, 2017		0.210000		2,497		1,608
Total 2017 Distributions		1.036413		12,310		7,928
February 14, 2018		0.210000		2,498		1,599
May 15, 2018		0.210000		2,506		1,604
August 14, 2018		0.210000		2,506		1,604
November 14, 2018 (b)		0.210000		2,509		1,606
Total 2018 Distributions		0.840000		10,019		6,413
Total Distributions (since IPO)	$	6.232363	$	73,883	$	47,335

(a) Approximately 63.9% of the Partnership’s outstanding common units at September 30, 2018 were held by affiliates.

(b) Third quarter 2018 distribution was declared and will be paid in the fourth quarter of 2018.

In addition, the owner of the Series A Preferred Units is entitled to receive quarterly distributions that represent an annual return of 9.5% on the Preferred Units. Of this 9.5% annual return, we will be required to pay at least 2.5% in cash and will have the option to pay the remaining 7.0% in kind (in the form of issuing additional preferred units) for the first twelve quarters after the Closing Date. We expect to pay the first distribution on the Preferred Units in November 2018 in the amount of $1.4 million in cash.

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CYPRESS ENERGY PARTNERS, L.P.
Notes to the Unaudited Condensed Consolidated Financial Statements

Equity Compensation

Our General Partner has adopted a long-term incentive plan (“LTIP”) that authorizes the issuance of up to 1,182,600 common units. Certain directors and employees of the Partnership have been awarded Phantom Restricted Units under the terms of the LTIP. The fair value of the awards is determined based on the quoted market value of the publicly-traded common units at each grant date, adjusted for a discount to reflect the fact that distributions are not paid on the restricted units during the vesting period. Compensation expense is recorded on a straight-line basis over the vesting period of each grant. We recorded expense of $0.9 million and $1.1 million during the nine months ended September 30, 2018 and 2017, respectively, related to the unit awards.  We have historically granted annual LTIP awards to key employees in the second quarter of each year.

The following table summarizes the LTIP unit activity for the nine months ended September 30, 2018 and 2017:

	Nine Months Ended September 30,
	2018					2017
				Weighted					Weighted
				Average					Average
				Grant					Grant
	Number			Date Fair		Number			Date Fair
	of Units			Value / Unit		of Units			Value / Unit
Unvested units at January 1		664,509		$	8.46		573,902		$	9.86
Unvested units granted		396,484		$	3.24		249,120		$	7.11
Units vested		(75,222	)	$	13.56		(43,930	)	$	16.56
Unvested units forfeited		(85,092	)	$	7.07		(39,722	)	$	8.51
Unvested units at September 30		900,679		$	5.87		739,370		$	8.61

The majority of the 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. One grant of 29,602 units vests three years from the grant date, contingent upon the recipient meeting certain performance targets. Total unearned compensation associated with the LTIP was $3.2 million at September 30, 2018, and the awards had an average remaining life of 2.31 years.

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CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

7. Related-Party Transactions

Omnibus Agreement and Other Support from Holdings

We are party to an omnibus agreement with Holdings and other related parties. The omnibus agreement governs the following matters, among other things:

● our payment of a quarterly administrative fee in the amount of $1.0 million to Holdings for providing certain partnership overhead services, including certain executive management services by certain officers and employees of our General Partner. This fee also includes the incremental general and administrative expenses we incur as a result of being a publicly-traded partnership. For the nine months ended September 30, 2018 and for the three months ended September 30, 2017, this fee was paid to Holdings in accordance with its terms and conditions. For the six months ended June 30, 2017, Holdings provided sponsor support to the Partnership by waiving payment of the quarterly administrative fee.  The fee will be adjusted each year by an inflation adjustment as outlined in the omnibus agreement.  If any additional modifications to this agreement are proposed, they would require approval by the Conflicts Committee of our Board of Directors.

● our right of first offer on Holdings’ and its subsidiaries’ assets used in, and entities primarily engaged in, providing saltwater disposal and other water and environmental services, and pipeline inspection and integrity services; and

● indemnification of us by Holdings for certain environmental and other 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 affiliates of Holdings control our General Partner, the omnibus agreement will remain in effect, unless we and Holdings agree to terminate it sooner. If affiliates of Holdings cease 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 amend the omnibus agreement; however, amendments will also require the approval of the Conflicts Committee of our Board of Directors. As part of our new Credit Agreement, Holdings agreed to waive the omnibus fee to support us in the event our leverage ratio were to exceed 3.75 times our trailing twelve-month Adjusted EBITDA at any quarter-end during the term of the credit facility.

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 reported as general and administrative expenses in the Unaudited Condensed Consolidated Statement of Operations and as a contribution attributable to general partner in the Unaudited Condensed Consolidated Statement of Owners’ Equity. These costs are included as a component of net loss attributable to general partner in the Unaudited Condensed Consolidated Statements of Operations. Non-cash allocated costs reported in our financial statements were $1.8 million for the nine months ended September 30, 2017. 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 us with additional financial support by contributing $1.0 million for the three months ended September 30, 2017 in cash, as a reimbursement of certain expenditures incurred by us. This payment is reflected as a contribution attributable to general partner in the Unaudited Condensed Consolidated Statement of Owners’ Equity and as a component of the net loss attributable to the general partner in the Unaudited Condensed Consolidated Statements of Operations.  Holdings has not provided any financial support to us in 2018.

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CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

Alati Arnegard, LLC

We provide management services to Alati Arnegard, LLC (“Arnegard”), an entity that owns a saltwater disposal facility in North Dakota in which we hold a 25% membership interest. Management fee revenue earned from Arnegard totaled $0.2 million for the three months ended September 30, 2018 and 2017, and $0.5 million for the nine months ended September 30, 2018 and 2017. Accounts receivable from Arnegard were $0.1 million at September 30, 2018 and December 31, 2017, and are included in trade accounts receivable, net in the Unaudited Condensed Consolidated Balance Sheets.

CF Inspection Management, LLC

We have also entered into a joint venture with CF Inspection, a nationally-qualified woman-owned inspection firm affiliated with one of Holdings’ owners. We own 49% of CF Inspection and Cynthia A. Field, the daughter of Charles C. Stephenson, Jr., owns the remaining 51% of CF Inspection. For the nine months ended September 30, 2018, CF Inspection represented approximately 3.4% of our consolidated revenue.  CF Inspection allows us to offer various services to clients that require the services of an approved Women's Business Enterprise ("WBE"), as CF Inspection is certified as a Women's Business Enterprise by the Supplier Clearinghouse in California and as a National Women's Business Enterprise by the Women's Business Enterprise National Council..

Sale of Preferred Equity

As described in Note 6, we issued and sold $43.5 million of preferred equity to an affiliate in May 2018.

8. Commitments and Contingencies

Security Deposits

We have various performance obligations related to our saltwater disposal facilities in North Dakota in our Water Services segment that are secured with short-term security deposits (reflected as restricted cash equivalents on our Unaudited Condensed Consolidated Statements of Cash Flows) of $0.6 million and $0.5 million at September 30, 2018, and December 31, 2017, respectively, included in prepaid expenses and other on the Unaudited Condensed Consolidated Balance Sheets.

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, the MSA’s may provide the customer the right to receive a credit or refund for any overcharges identified. As of September 30, 2018, we have established a reserve of $0.1 million for potential liabilities related to these compliance audit contingencies.  As of December 31, 2017, there were no reserves established for compliance audit contingencies.

Legal Proceedings

On October 5, 2017, a former inspector for TIR LLC and Cypress Energy Management – TIR, LLC (“CEM TIR”) filed a putative collective action lawsuit alleging that TIR LLC, CEM TIR and Cypress Energy Partners – Texas, LLC failed to pay a class of workers overtime in compliance with the Fair Labor Standards Act (“FLSA”) titled James Fithian, et al v. TIR LLC, et al in the United States District Court for the Western District of Texas, Midland Division. The plaintiff subsequently withdrew his action and filed a similar action in Oklahoma State Court, District of Tulsa County. The plaintiff alleges he was a non-exempt employee of TIR LLC 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 the Partnership, TIR LLC, CEM TIR and Cypress Energy Partners – Texas, LLC deny the claims. The defendants plan to continue to vigorously defend these claims and have stayed a counterclaim against the named plaintiff.

On March 28, 2018, the court granted a joint stipulation of dismissal without prejudice in regard to TIR LLC and Cypress Energy Partners – Texas, LLC, as neither of those parties were employers of the plaintiff or the putative class members during the time period that is the subject of the lawsuit. On July 26, 2018, plaintiff filed a motion for conditional class certification. CEM-TIR subsequently filed pleadings opposing the motion. The court set plaintiff’s motion for conditional certification for hearing on November 29, 2018.

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.

9. Sale of Saltwater Disposal Facilities

In May 2018, we sold our subsidiary Cypress Energy Partners – Orla SWD, LLC (“Orla”), which owns a saltwater disposal facility in Orla, Texas, to an unrelated party for $8.2 million of cash proceeds. The proceeds of this transaction were utilized to reduce our outstanding debt.  We recorded a gain on this transaction of $1.8 million ($0.2 million of this gain was recorded on contingent proceeds that were received and recorded in the third quarter of 2018), which represents the excess of the cash proceeds over the net book value of assets sold. The net book value of the assets sold included $3.0 million of allocated goodwill, calculated based on the estimated fair value of the Orla facility relative to the estimated fair value of the Water Services reporting unit as a whole. This calculation is considered Level 3 and the fair values included in this calculation were determined utilizing estimated discounted cash flows of the Orla facility and the Water Services reporting unit as a whole as of the date of sale.

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CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

In January 2018, we sold our subsidiary Cypress Energy Partners – Pecos SWD, LLC (“Pecos”), which owns a saltwater disposal facility in Pecos, Texas, to an unrelated party for $4.0 million of cash proceeds and a royalty interest in the future revenues of the facility. We concluded this represented the sale of a business and we record the royalties in the periods in which they are received. We recorded a gain on this transaction of $1.8 million, which represents the excess of the cash proceeds over the net book value of assets sold. The proceeds were used to reduce our debt.  The net book value of the assets sold included $2.0 million of allocated goodwill, calculated based on the estimated fair value of the Pecos facility relative to the estimated fair value of the Water Services reporting unit as a whole.  This calculation is considered Level 3 and the fair values included in this calculation were determined utilizing estimated discounted cash flows of the Pecos facility and the Water Services reporting unit as a whole as of the date of sale.  Assets held for sale and liabilities held for sale on the Unaudited Condensed Consolidated Balance Sheet at December 31, 2017 represent the carrying values of the Pecos saltwater facility prior to its sale.

During the three months ended September 30, 2018, we received proceeds of $0.4 million from the settlement of litigation related to lightning strikes that occurred in 2017 at our facilities in Orla, Texas and Grassy Butte, North Dakota. This litigation related to the non-performance of certain lightning protection equipment we had purchased to protect the facilities against lightning strikes. The proceeds from these settlements are reported within gain on assets disposals, net in our Unaudited Condensed Consolidated Statements of Operations.

10.  Reportable Segments

Our operations consist of three reportable segments: (i) Pipeline Inspection, (ii) Pipeline & Process Services, and (iii) Water Services.

Pipeline Inspection – We generate revenue in this segment primarily by providing essential inspection and integrity services on a variety of infrastructure assets including midstream pipelines, gathering systems, and distribution systems.  Services include non-destructive examination, mechanical integrity, inline support, PIG tracking, survey, data gathering and supervision of third-party contractors. Our results in this segment are driven primarily by the number of inspectors that perform services for our customers and the fees that we charge for those services, which depend on the type, skills, technology, equipment, and number of inspectors used on a particular project, the nature of the project, and the duration of the project. The number of inspectors engaged on projects is driven by the type of project, prevailing market rates, the age and condition of customers’ assets including pipelines, gas plants, compression stations, storage facilities, and gathering and distribution systems including the legal and regulatory requirements relating to the inspection and maintenance of those assets. Our customers are also billed for per diem charges, mileage, and other reimbursement items. Revenue and costs in this segment may be subject to seasonal variations and interim activity may not be indicative of yearly activity, considering many of our customers develop yearly operating budgets and enter into contracts with us during the winter season for work to be performed during the remainder of the year.  Additionally, inspection work throughout the United States during the winter months (especially in the northern states) may be hampered or delayed due to inclement weather, thus affecting our revenue and costs.  During the three months ended September 30, 2018, we recognized $0.5 million of revenue on services performed in previous years. We had constrained recognition of this revenue until the expiration of a contract provision that had given the customer the opportunity to reopen negotiation of the fee paid for the services. As of September 30, 2018, we have recognized a refund liability of $0.2 million for revenue associated with such variable consideration.

Pipeline & Process Services – This segment provides essential midstream services including hydrostatic testing services and chemical cleaning to energy companies and pipeline construction companies of newly-constructed and existing pipelines and related infrastructure. We generally charge our customers in this segment on a fixed-bid basis, depending on the size and length of the pipeline being tested, the complexity of services provided, and the utilization of our work force and equipment. Our results in this segment are driven primarily by the number of field personnel that perform services for our customers and the fees that we charge for those services, which depend on the type and number of field personnel used on a particular project, the type of equipment used and the fees charged for the utilization of that equipment, and the nature and duration of the project.  Revenue during the nine months ended September 30, 2018 included $0.3 million associated with additional billings on a project that we completed in the fourth quarter of 2017 (we recognized the revenue upon receipt of customer acknowledgment of the additional fees).

Water Services – This segment owns and operates nine (9) Environmental Protection Agency Class II saltwater disposal facilities in the Williston Basin region of North Dakota.  Eight (8) of the facilities are wholly-owned and we have ten (10) pipelines from multiple E&P customers connected to these saltwater disposal facilities, including two (2) that were developed and are owned by the Partnership.  Approximately 95% of our disposal water is produced water that is generated during production life of an oil and gas well and approximately 41% of our water is delivered via pipeline to our saltwater disposal facilities.  We currently serve in excess of 75 customers.  Our saltwater disposal facilities provide essential midstream services to oil and natural gas upstream producers and their transportation companies. All of the saltwater disposal facilities utilize specialized equipment and remote monitoring to minimize the facilities’ downtime and increase the facilities’ efficiency for peak utilization. These facilities also utilize oil skimming and recovery processes that remove residual oil from water delivered to our saltwater disposal facilities via pipeline or truck. We sell the oil recovered from these skimming processes, which contributes to our revenues. In addition to these saltwater disposal facilities, we provide management and staffing services to a saltwater disposal facility in which we own a 25% ownership interest.  Segment results are driven primarily by the volumes of water we inject into our saltwater disposal facilities and the fees we charge for transporting water in our two pipelines connected to these facilities. These fees are charged on a per-barrel basis and vary based on the quantity and type of saltwater disposed, competitive dynamics, and operating costs. In addition, for minimal marginal cost, we generate revenue by selling residual oil we recover from the disposed water. Revenue and costs in this segment may be subject to seasonal fluctuations and interim activity may not be indicative of yearly activity, given that our saltwater disposal facilities are located in North Dakota and weather conditions there (especially winter weather conditions) can affect drilling, operations, and trucking activity, and ultimately, our volumes, revenues, and costs.

Other – These amounts represent general and administrative expenses not specifically allocable to our reportable segments.

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CYPRESS ENERGY PARTNERS, L.P.

 Notes to the Unaudited Condensed Consolidated Financial Statements

The following tables show operating income (loss) by reportable segment and a reconciliation of segment operating income (loss) to net income (loss) before income tax expense.

	Pipeline			Pipeline &			Water
	Inspection			Process Services			Services			Other			Total
	(in thousands)
Three months ended September 30, 2018
Revenue	$	77,606		$	3,881		$	3,325		$	(34	)	$	84,778
Costs of services		68,350			2,592			962			(34	)		71,870
Gross margin		9,256			1,289			2,363			—			12,908
General and administrative		4,422			592			774			276			6,064
Depreciation, amortization and accretion		571			143			410			—			1,124
(Gain) loss on asset disposal, net		(21	)		(32	)		(769	)		—			(822	)
Operating income (loss)	$	4,284		$	586		$	1,948		$	(276	)		6,542
Interest expense, net														(1,283	)
Foreign currency gains														97
Other, net														95
Net income before income tax expense													$	5,451
Three months ended September 30, 2017
Revenue	$	72,737		$	2,834		$	2,111		$	—		$	77,682
Costs of services		65,323			2,132			837			—			68,292
Gross margin		7,414			702			1,274			—			9,390
General and administrative		3,893			525			858			298			5,574
Depreciation, amortization and accretion		577			157			450			—			1,184
Losses on asset disposals, net		—			—			208			—			208
Operating income (loss)	$	2,944		$	20		$	(242	)	$	(298	)		2,424
Interest expense, net														(1,907	)
Foreign currency gains														557
Other, net														17
Net income before income tax expense													$	1,091

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CYPRESS ENERGY PARTNERS, L.P.

 Notes to the Unaudited Condensed Consolidated Financial Statements

	Pipeline			Pipeline &			Water
	Inspection			Process Services			Services			Other			Total
	(in thousands)
Nine months ended September 30, 2018
Revenue	$	205,938		$	11,307		$	8,861		$	(34	)	$	226,072
Costs of services		183,305			7,840			2,981			(34	)		194,092
Gross margin		22,633			3,467			5,880			—			31,980
General and administrative		12,313	(a)		1,715			2,402	(b)		911			17,341
Depreciation, amortization and accretion		1,717			449			1,202			—			3,368
Gains on asset disposals, net		(21	)		(77	)		(4,039	)		—			(4,137	)
Operating income (loss)	$	8,624		$	1,380		$	6,315		$	(911	)		15,408
Interest expense, net														(4,907	)
Debt issuance cost write-off														(114	)
Foreign currency losses														(354	)
Other, net														302
Net income before income tax expense													$	10,335
Nine months ended September 30, 2017
Revenue	$	205,039		$	5,927		$	6,005		$	—		$	216,971
Costs of services		185,308			5,005			2,330			—			192,643
Gross margin		19,731			922			3,675			—			24,328
General and administrative		10,212	(c)		1,488			1,651	(d)		2,662	(e)		16,013
Depreciation, amortization and accretion		1,755			471			1,335			—			3,561
Impairments		1,329			1,581			688			—			3,598
Losses on asset disposal, net		18			—			77			—			95
Operating income (loss)	$	6,417		$	(2,618	)	$	(76	)	$	(2,662	)		1,061
Interest expense, net														(5,411	)
Foreign currency gains														824
Other, net														122
Net loss before income tax expense													$	(3,404	)
Total Assets
September 30, 2018	$	116,510		$	9,365		$	24,939		$	1,461		$	152,275
December 31, 2017 (recast to exclude intercompany receivables)	$	120,368		$	10,481		$	31,472		$	882		$	163,203

(a)	Amount includes $2.1 million of the allocated quarterly administrative fee charged by Holdings specified in the omnibus agreement.
(b)	Amount includes $0.9 million of the allocated quarterly administrative fee charged by Holdings specified in the omnibus agreement.
(c)	Amount includes $0.7 million of the allocated quarterly administrative fee charged by Holdings specified in the omnibus agreement.
(d)	Amount includes $0.3 million of the allocated quarterly administrative fee charged by Holdings specified in the omnibus agreement.
(e)	Amount includes $1.8 million of allocated general and administrative expenses incurred by Holdings but not charged to us. For the six months ended June 30, 2017, Holdings waived the administrative fee specified in the omnibus agreement.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

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 our Annual Report on Form 10-K for the year ended December 31, 2017 and this Quarterly Report on Form 10-Q. 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, capital expenditures, weather, economic and competitive conditions, regulatory changes, and other uncertainties, as well as those factors discussed below and elsewhere in our Annual Report on Form 10-K for the year ended December 31, 2017 and this Quarterly Report on Form 10-Q, all of which are difficult to predict. In light of these risks, uncertainties, and assumptions, the forward-looking events discussed may or may not occur. See “Cautionary Remarks Regarding Forward-Looking Statements” in the front of this Quarterly Report on Form 10-Q.

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 broken down into three segments: (1) our Pipeline Inspection (“Pipeline Inspection”) segment is comprised of our investment in the TIR Entities; (2) our Pipeline & Process Services (“Pipeline & Process Services”) segment (formerly referred to as our “Integrity Services” segment), comprised of our 51% ownership investment in Brown Integrity, LLC and; (3) our Water and Environmental Services (“Water Services”) segment, comprised of our investments in various saltwater disposal facilities and activities related thereto. The financial information for Pipeline Inspection, Pipeline & Process Services and Water Services included in “Item 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations” should be read in conjunction with the interim financial statements and related notes included elsewhere in this report and prepared in accordance with accounting principles generally accepted in the United States of America and in our Consolidated Financial Statements for the year ended December 31, 2017.

Overview

We are a growth-oriented master limited partnership formed in September 2013 to provide essential midstream services to the oil and gas industry. Our Pipeline Inspection 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 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 projects. Revenue and costs in this segment may be subject to seasonal variations and interim activity may not be indicative of yearly activity, considering many of our customers develop yearly operating budgets and enter into contracts with us during the winter season for work to be performed during the remainder of the year.  Additionally, inspection work throughout the United States during the winter months (especially in the northern states) may be hampered or delayed due to inclement weather, thus affecting our revenue and costs. 

The Pipeline & Process Services segment provides various integrity services including, but not limited to, independent hydrostatic testing services to major natural gas and petroleum pipeline companies and to pipeline construction companies in the United States. This segment primarily performs hydrostatic testing on many different pipelines including, but not limited to, natural gas and petroleum pipelines. Results in this segment are driven primarily by field personnel performing various integrity services for customers and the fees charged for those services, which depend on the nature, scope, and duration of the projects. 

The Water Services segment owns and operates nine (9) Environmental Protection Agency Class II saltwater disposal facilities in the Williston Basin region of North Dakota.  Eight (8) of the facilities are wholly-owned and we have ten (10) pipelines from multiple E&P customers connected to these saltwater disposal facilities, including two (2) that were developed and are owned by the Partnership.  Approximately 95% of our disposal water is produced water that is generated during production life of an oil and gas well and approximately 41% of our water is delivered via pipeline to our saltwater disposal facilities.  We currently serve in excess of 75 customers.  Our saltwater disposal facilities provide essential midstream services to oil and natural gas upstream producers and their transportation companies. All of the saltwater disposal facilities utilize specialized equipment and remote monitoring to minimize the facilities’ downtime and increase the facilities’ efficiency for peak utilization. These facilities also utilize oil skimming and recovery processes that remove residual oil from water delivered to our saltwater disposal facilities via pipeline or truck. We sell the oil recovered from these skimming processes, which contributes to our revenues. In addition to these saltwater disposal facilities, we provide management and staffing services to a saltwater disposal facility in which we own a 25% ownership interest.  Segment results are driven primarily by the volumes of water we inject into our saltwater disposal facilities and the fees we charge for transporting water in our two pipelines connected to these facilities. These fees are charged on a per-barrel basis and vary based on the quantity and type of saltwater disposed, competitive dynamics, and operating costs. In addition, for minimal marginal cost, we generate revenue by selling residual oil we recover from the disposed water. Revenue and costs in this segment may be subject to seasonal fluctuations and interim activity may not be indicative of yearly activity, given that our saltwater disposal facilities are located in North Dakota and weather conditions there (especially winter weather conditions) can affect drilling, operations, and trucking activity, and ultimately, our volumes, revenues, and costs.

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 maintaining the integrity of their assets and reducing their operating costs.

Ownership

As of September 30, 2018, Holdings owns approximately 58.2% of the Partnership’s common units, while affiliates of Holdings own approximately 5.7% of the Partnership’s common units, for a total ownership percentage of the Partnership’s common units of approximately 63.9% by Holdings and its affiliates. Holdings’ ownership group also owns 100% of the General Partner and the incentive distribution rights (“IDR’s”), and an affiliate of our General Partner owns 100% of the preferred units.

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Omnibus Agreement

We are party to an omnibus agreement with Holdings and other related parties. The omnibus agreement governs the following matters, among other things:

● our payment of a quarterly administrative fee in the amount of $1.0 million to Holdings for providing certain partnership overhead services, including certain executive management services by certain officers and employees of our General Partner. This fee also includes the incremental general and administrative expenses we incur as a result of being a publicly-traded partnership. For the nine months ended September 30, 2018 and for the three months ended September 30, 2017, this fee was paid to Holdings in accordance with its terms and conditions. For the six months ended June 30, 2017, Holdings provided sponsor support to the Partnership by waiving payment of the quarterly administrative fee.  The fee will be adjusted each year by an inflation adjustment as outlined in the omnibus agreement.  If any additional modifications to the agreement are proposed, they would require approval by the Conflicts Committee of our Board of Directors;

● our right of first offer on Holdings’ and its subsidiaries’ assets used in, and entities primarily engaged in, providing saltwater disposal and other water and environmental services, and pipeline inspection and integrity services; and

● indemnification of us by Holdings for certain environmental and other 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 affiliates of Holdings control our General Partner, the omnibus agreement will remain in effect, unless we and Holdings agree to terminate it sooner. If affiliates of Holdings cease 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 amend the omnibus agreement; however, amendments will also require the approval of the Conflicts Committee of our Board of Directors.

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 reported as general and administrative expenses in the Unaudited Condensed Consolidated Statement of Operations and as a contribution attributable to general partner in the Unaudited Condensed Consolidated Statement of Owners’ Equity. These costs are included as a component of net loss attributable to general partner in the Unaudited Condensed Consolidated Statements of Operations. Non-cash allocated costs reported in our financial statements were $1.8 million for the nine months ended September 30, 2017 as Holdings waived the payment of the quarterly administrative fee for the first two quarters of 2017. 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 $1.0 million for the three months ended September 30, 2017 in cash, as a reimbursement of certain expenditures incurred by us. This payment is reflected as a Contribution attributable to general partner in the Unaudited Condensed Consolidated Statement of Owners’ Equity and as a component of the net loss attributable to the general partner in the Unaudited Condensed Consolidated Statements of Operations.  Holdings has not provided any financial support to us in 2018.

Pipeline Inspection

We generate revenue in the Pipeline Inspection segment primarily by providing essential inspection and integrity services on a variety of infrastructure assets including midstream pipelines, gathering systems, and distribution systems.  Services include non-destructive examination, mechanical integrity, inline support, PIG tracking, survey, data gathering and supervision of third-party contractors. Our results in this segment are driven primarily by the number of inspectors that perform services for our customers and the fees that we charge for those services, which depend on the type, skills, technology, equipment, and number of inspectors used on a particular project, the nature of the project, and the duration of the project. The number of inspectors engaged on projects is driven by the type of project, prevailing market rates, the age and condition of customers’ assets including pipelines, gas plants, compression stations, storage facilities, and gathering and distribution systems including the legal and regulatory requirements relating to the inspection and maintenance of those assets. Our customers are also billed for per diem charges, mileage, and other reimbursement items.

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 Pipeline & Process Services

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

Water Services

We generate revenue in the Water Services segment primarily by treating flowback and produced water and injecting the saltwater into our saltwater disposal facilities. Our results are driven primarily by the volumes of produced water and flowback water we inject into our saltwater disposal facilities and the fees we charge for these 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 saltwater disposed, competitive dynamics, and operating costs. In addition, for minimal marginal cost, we generate revenue by selling residual oil we recover from the saltwater. We also generate revenue managing a saltwater disposal facility for a fee.

The volumes of saltwater disposed at our saltwater disposal facilities are driven by water volumes generated from existing oil and natural gas wells during their useful lives and development drilling. Producers’ willingness to engage in new drilling is determined by a number of factors, the most important of which are the current and projected prices of oil, natural gas, and natural gas liquids, the cost to drill and operate a well, the availability and cost of capital, and environmental and governmental regulations. We generally expect the level of drilling to correlate with long-term trends in prices of oil, natural gas, and natural gas liquids.

  We also generate revenues from the sales of residual oil recovered during the saltwater treatment process.  Our ability to recover residual oil is dependent upon the residual oil content in the saltwater we treat, which is, among other things, a function of water type, chemistry, source, and temperature.  Generally, where outside temperatures are lower, there is less residual oil content and separation is more difficult.  Thus, our residual oil recovery during the winter season is usually lower than our recovery during the summer season in North Dakota.  Additionally, residual oil content decreases with an increase in pipeline water as operators control the flow of the pipeline water and if, among other things, producers begin recovering higher levels of residual oil in saltwater prior to delivering the saltwater to us for treatment.

Outlook

Overall

All three of our segments generated increased revenues during the third quarter of 2018 relative to the second quarter of 2018, which reflects the continuing recovery in the energy markets. We believe our essential midstream services are well-positioned for long-term growth, given the aging energy infrastructure in the U.S., the new construction of pipelines, and growing oil and gas production.

Revenues of our Pipeline Inspection segment increased from $70.4 million in the second quarter of 2018 to $77.6 million in the third quarter of 2018, an increase of 10.3%. The increase was due in part to the normal seasonal increase (the third quarter of each year is typically the strongest quarter for this segment), and due in part to increasing demand. The gross margin percentage for the Pipeline Inspection segment increased from 11.2% in the second quarter of 2018 to 11.9% in the third quarter of 2018, as we continue our strategy of diversifying our revenues into higher-margin services.  Gross margins in this segment increased from $7.4 million in the third quarter of 2017 to $9.3 million in the third quarter of 2018, an increase of 24.8%.

Revenues of our Pipeline & Process services segment increased from $3.1 million during the second quarter of 2018 to $3.9 million during the third quarter of 2018, an increase of 26.2%. The increase was due in part to the normal seasonal increase (the third quarter of each year is typically the strongest quarter for this segment), and due in part to increasing demand and improved business development efforts.  Gross margins in this segment increased from $0.7 million in the third quarter of 2017 to $1.3 million in the third quarter of 2018, an increase of 83.6%.

Revenues of our Water Services segment increased from $3.0 million during the second quarter of 2018 to $3.3 million during the third quarter of 2018, an increase of 9.8%. Demand for this segment has continued to increase as customer activity has increased in the Bakken shale region and due to the completion of two owned pipelines in the early part of 2018. Gross margins in this segment increased from $1.3 million in the third quarter of 2017 to $2.4 million in the third quarter of 2018, an increase of 85.5%.

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We have evaluated numerous acquisition opportunities to expand and enhance the breadth and depth of the essential pipeline inspection and integrity services we offer to our clients. Our sponsor, Cypress Energy Holdings, LLC, recently completed two acquisitions that we believe will allow us to accomplish that goal. Both transactions were asset purchases (business combinations for accounting purposes) that require some repositioning before bringing them into the Partnership. Our sponsor intends to offer them to the Partnership once it has accomplished certain developmental goals. These acquisitions would move us into several new lines of work, including water treatment, in-line inspection for oil and gas and other customers, equipment rental (which could be converted into a service business before offering this line of business to the Partnership), and offshore hydrostatic testing, and would give us a platform to expand into other pipeline and process services, both onshore and offshore. These two transactions would also allow us to enter the growing and attractive in-line inspection (“ILI”) industry with next-generation technology capable of helping pipeline owners and operators better manage the integrity of their assets in both the energy industry and municipal water industry.

We have completed the previously-announced process of evaluating strategic alternatives and concluded that remaining independent at this time and building out these acquisition opportunities represents the most attractive opportunity to build long-term value for the Partnership. The long-term increasing demand for pipeline inspection, integrity services, and water solutions remains strong due to our nation’s aging pipeline infrastructure and growing production, and we believe we are well-positioned to capitalize on the opportunities that improving market conditions will create. The future drop down of the recent acquisitions should also position us to eventually resume increasing our distributions.

Pipeline Inspection

Demand is growing for our Pipeline Inspection segment. We operate in a very large market, with more than over 1,500 customer prospects who require federally and/or state-mandated inspection and integrity services. We are pursuing a large market in the U.S. and Canada that is made up of over 2,200 energy companies that could utilize our pipeline inspection, processing, and integrity services.  During the third quarter of 2018, we signed the largest contract in the 15-year history of TIR and added several new customers.  Additionally, a number of new projects have been announced in 2018.

Energy research analysts have published the following updates as summarized below:

● 2019 Forecast: Large pipeline/midstream infrastructure projects proposed for 2019 total $39.4 billion.  Based on these project estimates, anticipated 2019 spending will reflect positive growth over 2018. Tier 3 forecasts currently suggest potential annual growth in the mid-teens.

● 2020 and beyond: Commentary from key players along the midstream supply chain and production forecasts in light of pipeline capacity constraints suggest the industry is gaining visibility into growth beyond 2019.  Projects include the Keystone XL pipeline and LNG infrastructure currently in development.  Given the size of investment in LNG terminals and facilities, and the significant undertaking in the development stage, they view these as higher risk projects in terms of timing and the regulatory process.  However, if these projects move forward, they see the potential for growth beyond 2021.  Additionally, if the bullish view on production holds up, they believe that we could see additional waves of infrastructure additions in the Permian and other high-growth regions.

● Growing and shifting production versus takeaway capacity. Production of shale oil, natural gas, and natural gas liquids has dramatically increased in the past decade, changing product flow and infrastructure needs across the country.  Demand for increased takeaway capacity has followed, resulting in heightened levels of pipeline development.  These drivers remain intact for at least three years, and opportunity exists for additional infrastructure development with continued production growth well past 2020, as regions like the Permian basin continue to face takeaway constraints.

● Aging infrastructure. As pipeline and distribution systems are reaching the end of their useful life, the market has seen growing demand for infrastructure replacement work in recent years, often coinciding with capacity additions.  Most recently, Enbridge's $7.0 billion Line 3 Replacement program plans to expand on the former Line 3 segment, replacing 1,031 miles of the old pipeline and associated facilities on both sides of the U.S. - Canada border.  Various industry reports estimate that there exist more than 1.3 million miles of gathering and transmission lines operating currently in the U.S. and Canada.  It is estimated that over 50% of these pipelines are pre-1970 infrastructure and the average age of these pipelines is 42 years.

● In-Line Inspection ("ILI") Industry. Various industry research reports estimated that the total North American in-line inspection market represented $530 million to $650 million in 2017.  The U.S. market is roughly four to five times the size of the Canadian market.  Potential regulatory changes at federal and state levels could increase this market 40% - 50% if enacted.  The in-line inspection market includes over 625 potential energy industry customers in Canada and another 1,550 in the U.S., for a total of over 2,100 potential in-line customers that own gathering or transmission pipeline systems.  The in-line industry has about a dozen Tier 1 providers that make up approximately 60% - 70% of the in-line inspection market.

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Our continued focus remains on both maintenance and integrity work on existing pipelines as well as work on new projects. With stronger commodity prices and healthier balance sheets, our existing and potential customers are investing in their businesses following a difficult two-year generational economic downturn in the energy industry. 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 regulatory requirements, coupled with the aging pipeline infrastructure, mean that, regardless of commodity prices, our customers will require our regulatory inspection services.  Therefore, the Pipeline Inspection business is more insulated from changes in commodity prices. 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. 

Pipeline & Process Services

Brown, our 51% owned integrity services hydrotesting business unit, has seen a significant improvement in its utilization rates thus far in 2018. Improved operating results are evidenced by observing the near 84% increase in the gross margin of the Pipeline & Process Services segment from $0.7 million in the third quarter of 2017 to $1.3 million in the third quarter of 2018.  During the quarter, we also opened a new office in Odessa, Texas, to better serve the growing Permian basin market.  In addition, we added several industry veterans to our management team in order to further enhance our image and grow the segment.  We also plan to open a new location in the Houston market to take advantage of the growing work in the industry.  Brown has had two difficult years during the economic energy downturn, which forced us to implement aggressive measures to manage and reduce its cost structure. We believe the measures implemented have been very successful as is evidenced by our strong and continually improving operating results, and we plan to continue to focus on the potential synergies that may develop between this segment and our current customers in our other business segments. In 2017, Brown worked in 15 states and has successfully obtained new business from TIR relationships. Brown’s revenues increased $5.4 million, from $5.9 million in the first nine months of 2017 to $11.3 million in the first nine months of 2018. Brown continues to enjoy an excellent reputation in the industry and continues to bid on a substantial amount of new work. 

Water Services

Our Water Services segment disposed of 4.3 million barrels of saltwater during the third quarter of 2018, which was an increase over the 3.1 million barrels disposed during the third quarter of 2017 (despite the sale of our Texas facilities in 2018). This increase was due, in part, to the completion, early in the year, of two new water pipelines into one of our saltwater disposal facilities.  Our average revenue per barrel increased to $0.78 (inclusive of water disposal, oil reclamation, and management fees) in the third quarter of 2018, an increase over the average revenue per barrel of $0.68 during the third quarter of 2017, due in part to an increase in revenues associated with the two new pipelines that we placed into service in January 2018, higher disposal prices, and increased residual oil recovered during the saltwater disposal process at our saltwater disposal facilities. Drilling activity has improved dramatically following the downturn and the lows that occurred in May 2016. Per the Baker Hughes North America Rotary Rig Count as of October 26, 2018, the U.S. rig count totaled 1,068, up 164% from its trough in May 2016, including a rig total of 56 in the Williston basin of the Bakken.

Crude oil prices have also increased since a year ago, and in September 2018, NYMEX crude exceeded $70.00 per barrel. The decline in the market price of crude oil that began in the second half of 2014 had an adverse impact on our volumes and revenues over the last three years.

We continue to focus on produced water and pipeline water whenever possible. During the third quarter of 2018, 95% (90% in the third quarter of 2017) of our volumes were produced water and 41% (45% in the third quarter of 2017) of our volumes were delivered via ten pipelines, including two that have been developed and are owned by us. We continue to focus on pipeline water opportunities to secure additional long-term volumes of produced water for the life of the oil and gas wells’ production and plan to add two new pipelines to our facilities in the fourth quarter of 2018.

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

In January of 2018, we sold our subsidiary that owned a saltwater 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. In May of 2018, we sold our subsidiary that owns a saltwater disposal facility in Orla, Texas to an unrelated party for $8.2 million.  The proceeds from these sales were utilized to decrease our outstanding debt.

Results of Operations

Consolidated Results of Operations

The following table summarizes our Unaudited Condensed Consolidated Statements of Operations for the three and nine-month periods ended September 30, 2018 and 2017:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
	(in thousands)
Revenue	$	84,778		$	77,682		$	226,072		$	216,971
Costs of services		71,870			68,292			194,092			192,643
Gross margin		12,908			9,390			31,980			24,328
Operating costs and expense:
General and administrative - segment		5,744			5,276			16,430			13,351
General and administrative - corporate		320			298			911			2,662
Depreciation, amortization and accretion		1,124			1,184			3,368			3,561
Impairments		—			—			—			3,598
(Gains) losses on asset disposals, net		(822	)		208			(4,137	)		95
Operating income		6,542			2,424			15,408			1,061
Other (expense) income:
Interest expense, net		(1,283	)		(1,907	)		(4,907	)		(5,411	)
Debt issuance cost write-off		—			—			(114	)		—
Foreign currency gains (losses)		97			557			(354	)		824
Other, net		95			17			302			122
Net income (loss) before income tax expense		5,451			1,091			10,335			(3,404	)
Income tax expense		497			529			865			458
Net income (loss)		4,954			562			9,470			(3,862	)
Net income (loss) attributable to noncontrolling interests		289			8			673			(1,290	)
Net income (loss) attributable to partners / controlling interests		4,665			554			8,797			(2,572	)
Net loss attributable to general partner		—			(1,000	)		—			(2,750	)
Net income attributable to limited partners		4,665			1,554			8,797			178
Net income attributable to preferred unitholder		1,045			—			1,412			—
Net income (loss) attributable to common unitholders	$	3,620		$	1,554		$	7,385		$	178

See the detailed discussion of revenues, costs of services, gross margin, general and administrative expense and depreciation, amortization and accretion by reportable segment below. The following is a discussion of significant changes in the non-segment related corporate other income and expenses during the respective periods.

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General and administrative – corporate. General and administrative - corporate decreased by $1.8 million for the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017, due primarily to the waiving of the two $1.0 million quarterly administrative fees due to Holdings in the first and second quarters of 2017. Amounts in the nine months ended September 30, 2017 include $1.8 million of expenses incurred by Holdings on our behalf that they elected not to charge us. During each of the first three quarters of 2018, we paid the $1.0 million administrative fee, and this expense is reported in general and administrative – segment in the table above ($2.1 million of which was allocated to the Pipeline Inspection segment and $0.9 million of which was allocated to the Water Services segment). During the three months ended September 30, 2017, $0.7 million of the administrative fee was allocated to the Pipeline Inspection segment and $0.3 million was allocated to the Water Services segment.  In 2018, Holdings has not provided any financial support to us.

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 decreased for the nine months ended September 30, 2017 to the nine months ended September 30, 2018 primarily due to the refinancing of our Credit Agreement. We made payments of $4.0 million, $5.0 million, and $8.0 million in January, April, and May 2018, respectively, to reduce the outstanding balance on our Credit Agreement. In May 2018, we issued preferred equity and used the proceeds to reduce the outstanding balance on the Credit Agreement by an additional $43.8 million. Average debt outstanding during the nine months ended September 30, 2018 and 2017 was $105.9 million and $136.9 million, respectively. The decrease in interest expense as a result of lower outstanding borrowings was partially offset by an increase in the interest rate. The average interest rate on our borrowings increased from 4.62% in the nine months ended September 30, 2017 to 5.42% in the nine months ended September 30, 2018. 

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

Foreign currency gains (losses). Our Canadian subsidiary has certain intercompany payables to our U.S.-based subsidiaries. Such intercompany payables and receivables among our consolidated subsidiaries are eliminated in our Unaudited Condensed Consolidated Balance Sheets. Beginning April 1, 2017, we report currency translation adjustments on these intercompany payables and receivables within foreign currency gains (losses) in our Unaudited Condensed Consolidated Statements of Operations. The net foreign currency losses during the nine months ended September 30, 2018 resulted from the depreciation of the Canadian dollar relative to the U.S. dollar. The net foreign currency gains during the nine months ended September 30, 2017 resulted from the appreciation of the Canadian dollar relative to the U.S. dollar.

Other, net. Other income primarily consists of royalty income, interest income, and income associated with our 25% interest in a managed saltwater disposal facility in North Dakota, which we account for under the equity method.

Income tax expense.  Our income tax provision relates primarily to (1) our U.S. corporate subsidiaries that provide services to public utility customers, which do not appear to fit within the definition of qualified income as it is defined in the Internal Revenue Code, Regulations, and other guidance, which subjects this income to U.S. federal and state income taxes, (2) our Canadian subsidiary, which is subject to Canadian federal and provincial income taxes, and (3) certain other state income taxes, including the Texas franchise tax. We estimate an annual tax rate based on our projected income for the year and apply that annual tax rate to our year-to-date earnings. The increase in income tax expense during the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017 is due to an income tax benefit recorded in 2017 related to the impairment of certain long-lived assets of our Canadian subsidiary, an increase in earnings of our taxable subsidiary in the U.S. that provides services to public utility customers, and other services that we have deemed to be non-qualified income, and increased franchise taxes as a result of increased business activity in Texas. These increases were partially offset by the reduction in the U.S. federal income tax rate as a result of a tax law that went into effect on January 1, 2018.

As a publicly-traded partnership, we are subject to a statutory requirement that 90% of our total gross income represent “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations, and Internal Revenue Service pronouncements), determined on a calendar-year basis. Income generated by taxable corporate subsidiaries is excluded from this calculation. During the nine months ended September 30, 2018, substantially all of our gross income, which consisted of approximately $180 million of revenue (exclusive of the income generated by our taxable corporate subsidiaries), represented “qualifying income”.

Net income (loss) attributable to noncontrolling interests. We own a 51% interest in Brown and a 49% interest in CF Inspection. The accounts of these subsidiaries are included within our consolidated financial statements. The portion of the net income (loss) of these entities that is attributable to outside owners is reported in net income (loss) attributable to noncontrolling interest in our Unaudited Condensed Consolidated Statements of Operations.

Net loss attributable to general partner. The net loss attributable to the general partner during the three and nine months ended September 30, 2017 consists of expenses that Holdings incurred on our behalf. Since Holdings did not charge us for these expenses, we recorded these expenses as an equity contribution from our general partner.

Net income attributable to preferred unitholder. On May 29, 2018, we issued and sold $43.5 million of preferred equity. The holder of the preferred units is entitled to an annual return of 9.5% on this investment. The earnings attributable to the preferred unitholder reflects this return.  We expect to pay the first distribution on the Preferred Units in November 2018 in the amount of $1.4 million in cash.

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Segment Operating Results

Pipeline Inspection

The following table summarizes the operating results of the Pipeline Inspection segment for the three months ended September 30, 2018 and 2017.  

	Three Months Ended September 30,
	2018			% of Revenue			2017		% of Revenue			Change			% Change
	(in thousands, except average revenue and inspector data)
Revenue	$	77,606					$	72,737				$	4,869			6.7	%
Costs of services		68,350						65,323					3,027			4.6	%
Gross margin		9,256			11.9	%		7,414		10.2	%		1,842			24.8	%
General and administrative		4,422			5.7	%		3,893		5.4	%		529			13.6	%
Depreciation and amortization		571			0.7	%		577		0.8	%		(6	)		(1.0	)%
Gains on asset disposals, net		(21	)					—		0.0	%		(21	)		0.0	%
Operating income	$	4,284			5.5	%	$	2,944		4.0	%	$	1,340			45.5	%
Operating Data
Average number of inspectors		1,263						1,211					52			4.3	%
Average revenue per inspector per week	$	4,675					$	4,570				$	105			2.3	%
Revenue variance due to number of inspectors												$	3,195
Revenue variance due to average revenue per inspector												$	1,674

Revenue. Revenue of the Pipeline Inspection segment increased $4.9 million during the three months ended September 30, 2018 compared to the three months ended September 30, 2017, an increase of 6.7%, due to an increase in the average number of inspectors engaged (an increase of 52 inspectors accounting for $3.2 million of the revenue increase) and in the average revenue billed per inspector (accounting for $1.7 million of the revenue increase).   

Revenue attributable to our U.S. operations increased $5.9 million during the three months ended September 30, 2018 compared to the three months ended September 30, 2017, an increase of 8.2%, due to increased activity by our clients and increased business development efforts, including the expansion of the non-destructive examination business and the formation of two new lines of businesses. This increase was partially offset by a decrease of $1.0 million in revenues attributable to our Canadian operations, due primarily to our decision not to pursue low-margin work for a major Canadian customer in the third quarter of 2017.  

Average revenue per inspector fluctuates due to changes in customer mix, type of work, and margins that vary by client. Fluctuations in the average revenue per inspector are expected, given that we charge different rates for different types of inspectors and different types of inspection services. We continue to compete with many other competitors on quality, service, price, safety, and training.

Costs of services. Costs of services increased $3.0 million during the three months ended September 30, 2018 compared to the three months ended September 30, 2017, primarily related to an increase in the average number of inspectors employed during the period.  

Gross margin. Gross margin increased $1.8 million during the three months ended September 30, 2018 compared to the three months ended September 30, 2017, an increase of 24.8%. The gross margin percentage improved to 11.9% in the third quarter of 2018, compared to 10.2% in the third quarter of 2017, an increase of 17.7%. The increase in gross margin percentage is due to changes in the mix of services provided and our decision not to pursue low-margin work that was generated in Canada during 2017. In addition, during the three months ended September 30, 2018, we generated additional revenue from our public utility, mechanical integrity group, and nondestructive examination service lines, which typically generate higher margins. In addition, during the three months ended September 30, 2018, we recognized $0.5 million of revenue on services performed in previous years. We had deferred recognition of this revenue until the expiration of a contract provision that had given the customer the opportunity to reopen negotiation of the fee for the services.

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General and administrative. General and administrative expenses increased by $0.5 million during the three months ended September 30, 2018 compared to the three months ended September 30, 2017, due primarily to an increase in compensation expense of $0.3 million, resulting from an increase in personnel to support our growing businesses. In addition, professional fees increased by $0.2 million, due primarily to legal costs associated with certain on-going employment-related lawsuits and claims.

Depreciation and amortization. Depreciation and amortization expense during the third quarter of 2018 was not significantly different from depreciation and amortization expense during the third quarter of 2017.

Operating income. Operating income increased $1.3 million during the three months ended September 30, 2018 compared to the three months ended September 30, 2017, an increase of 45.5%, due primarily to the increase in gross margin, partially offset by an increase in general and administrative expenses. 

The following table summarizes the operating results of the Pipeline Inspection segment for the nine months ended September 30, 2018 and 2017.  

	Nine Months Ended September 30,
	2018			% of Revenue			2017		% of Revenue			Change			% Change
	(in thousands, except average revenue and inspector data)
Revenue	$	205,938					$	205,039				$	899			0.4	%
Costs of services		183,305						185,308					(2,003	)		(1.1	)%
Gross margin		22,633			11.0	%		19,731		9.6	%		2,902			14.7	%
General and administrative		12,313			6.0	%		10,212		5.0	%		2,101			20.6	%
Depreciation and amortization		1,717			0.8	%		1,755		0.9	%		(38	)		(2.2	)%
Impairments		—						1,329		0.6	%		(1,329	)		100.0	%
(Gains) losses on asset disposals, net		(21	)					18		0.0	%		(39	)		216.7	%
Operating income	$	8,624			4.2	%	$	6,417		3.1	%	$	2,207			34.4	%
Operating Data
Average number of inspectors		1,160						1,160					—			0.0	%
Average revenue per inspector per week	$	4,552					$	4,532				$	20			0.4	%
Revenue variance due to number of inspectors												$	—
Revenue variance due to average revenue per inspector												$	899

Revenue. Revenue of the Pipeline Inspection segment increased $0.9 million during the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017, due to an increase in the average revenue billed per inspector.  

Revenue attributable to our U.S. operations increased $22.1 million during the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017, due to increased activity by our clients and increased business development efforts, including the expansion of the non-destructive examination business and the formation of our mechanical integrity service business line. This increase was partially offset by a decrease of $21.2 million in revenue attributable to our Canadian operations, due primarily to our decision not to pursue low-margin work in Canada resulting in the loss of our largest Canadian customer in the third quarter of 2017.  

Fluctuations in the average revenue per inspector are expected, given that we charge different rates for different types of inspectors and different types of inspection services.  

Costs of services. Costs of services decreased $2.0 million during the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017 as a result of changes in the mix of services provided and our focus on higher margin opportunities.

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Gross margin. Gross margin increased $2.9 million during the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017, an increase of 14.7%. The gross margin percentage improved to 11.0% in 2018, compared to 9.6% in 2017, an increase of 14.6%. The increase in gross margin percentage is due to changes in the mix of services provided and our decision not to pursue low-margin work, leading to the loss of a major customer in Canada. In addition, during the nine months ended September 30, 2018, we generated more revenues from our public utility, mechanical integrity, and nondestructive examination service lines, which typically produce higher margins. In addition, during the three months ended September 30, 2018, we recognized $0.5 million of revenue on services performed in previous years. We had deferred recognition of this revenue until the expiration of a contract provision that had given the customer the opportunity to reopen negotiation of the fee for the services.

General and administrative. General and administrative expenses increased by $2.1 million during the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017, due primarily to $2.1 million of expense associated with the administrative fee charged by Holdings that was recorded by our Pipeline Inspection segment in 2018. During the nine months ended September 30, 2017, Holdings waived $1.4 million of this administrative fee. Compensation expense increased approximately $0.4 million during the nine months ended September 30, 2018, due to an increase in personnel to support our growing businesses. In addition, professional fees increased by $0.2 million, due primarily to legal costs associated with certain on-going employment-related lawsuits and claims.  In 2018, Holdings has not provided any financial support to us.

Depreciation and amortization. Depreciation and amortization expense during the nine months ended September 30, 2018 was not significantly different from depreciation and amortization expense during the nine months ended September 30, 2017.   

Impairments. During 2017, we declined to pursue low-margin work previously performed by our Canadian subsidiary. Due to the loss of this contract, we recorded impairments of $1.3 million to the carrying values of certain intangible assets in the first quarter of 2017. Of this amount, $1.1 million related to customer relationships and $0.2 million related to trade names.  

Operating income. Operating income increased by $2.2 million during the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017, an increase of 34.4%, due primarily to the increase in gross margin and the absence of impairment expense in 2018 that incurred in 2017, partially offset by our payment of the quarterly administrative fees charged by Holdings in 2018, which fees were waived in the first two quarters of 2017, additional compensation expense, and increased professional services expense.

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Pipeline & Process Services

The following table summarizes the results of the Pipeline & Process Services segment for the three months ended September 30, 2018 and 2017.

	Three Months Ended September 30,
	2018			% of Revenue			2017		% of Revenue			Change			% Change
	(in thousands, except average revenue and inspector data)
Revenue	$	3,881					$	2,834				$	1,047			36.9	%
Costs of services		2,592						2,132					460			21.6	%
Gross margin		1,289			33.2	%		702		24.8	%		587			83.6	%
General and administrative		592			15.3	%		525		18.5	%		67			12.8	%
Depreciation and amortization		143			3.7	%		157		5.5	%		(14	)		(8.9)	%
Gain on asset disposals, net		(32	)		(0.8)	%		—					(32	)
Operating income	$	586			15.1	%	$	20		0.7	%	$	566			2830.0	%
Operating Data
Average number of field personnel		23						21					2			9.5	%
Average revenue per field personnel per week	$	12,839					$	10,268				$	2,571			25.0	%
Revenue variance due to number of field personnel												$	337
Revenue variance due to average revenue per field personnel												$	710

Revenue. Revenue increased $1.0 million during the three months ended September 30, 2018 compared to the three months ended September 30, 2017, an increase of 36.9%. The Pipeline & Process Services segment won more bids for large projects, and as a result, employee utilization was significantly higher in the third quarter of 2018 than in the third quarter of 2017. The increase in successful bids was due to improving market conditions and improved business development efforts.

Costs of services. Cost of services increased $0.5 million during the three months ended September 30, 2018 compared to the three months ended September 30, 2017, due to an increase in revenues.

Gross margin. Gross margin increased $0.6 million during the three months ended September 30, 2018 compared to the three months ended September 30, 2017, an increase of 83.6%. The employees of the Pipeline & Process 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 primarily variable costs). Because these employees were more fully utilized during the three months ended September 30, 2018, the gross margin percentage was higher.

General and administrative. General and administrative expenses primarily include compensation expense for office employees and general office expenses. These expenses increased slightly from the three months ended September 30, 2018 compared to the three months ended September 30, 2017, due primarily to increased business development efforts.

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 noncompete agreements. Depreciation and amortization expense during the three months ended September 30, 2018 was not significantly different from depreciation and amortization expense during the three months ended September 30, 2017.

Operating income. Operating income increased by $0.6 million during the three months ended September 30, 2018 compared to the three months ended September 30, 2017, due primarily to higher gross margins of $0.6 million.

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The following table summarizes the results of the Pipeline & Process Services segment for the nine months ended September 30, 2018 and 2017.

	Nine Months Ended September 30,
	2018			% of Revenue			2017			% of Revenue			Change			% Change
	(in thousands, except average revenue and inspector data)
Revenue	$	11,307					$	5,927					$	5,380			90.8	%
Costs of services		7,840						5,005						2,835			56.6	%
Gross margin		3,467			30.7	%		922			15.6	%		2,545			276.0	%
General and administrative		1,715			15.2	%		1,488			25.1	%		227			15.3	%
Depreciation and amortization		449			4.0	%		471			7.9	%		(22	)		(4.7)	%
Impairments		—						1,581			26.7	%		(1,581	)		(100.0)	%
Gains on asset disposals, net		(77	)		(0.7)	%		—						(77	)
Operating income (loss)	$	1,380			12.2	%	$	(2,618	)		(44.2)	%	$	3,998			152.7	%
Operating Data
Average number of field personnel		22						18						4			22.2	%
Average revenue per field personnel per week	$	13,178					$	8,443					$	4,735			56.1	%
Revenue variance due to number of field personnel													$	2,056
Revenue variance due to average revenue per field personnel													$	3,324

Revenue. Revenue increased $5.4 million during the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017, an increase of 90.8%. The Pipeline & Process Services segment won more bids for large projects, and as a result, employee utilization was significantly higher in 2018 than in 2017. The increase in successful bids was due to improving market conditions and to improved business development efforts. Revenue during the nine months ended September 30, 2018 included $0.3 million associated with additional billings on a project that we completed in the fourth quarter of 2017 (we recognized the revenue upon receipt of customer acknowledgment of the additional fees).

Costs of services. Cost of services increased $2.8 million during the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017, due to an increase in revenues.

Gross margin. Gross margin increased $2.5 million during the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017, an increase of 276.0%. The employees of the Pipeline & Process 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 primarily variable costs). Because these employees were more fully utilized during the nine months ended September 30, 2018, the gross margin percentage was higher.

General and administrative. General and administrative expenses primarily include compensation expense for office employees and general office expenses. These expenses increased by $0.2 million during the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017, due primarily to increased costs related to business development efforts.

 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 noncompete agreements. Depreciation and amortization expense during the nine months ended September 30, 2018 was not significantly different from depreciation and amortization expense during the nine months ended September 30, 2017.

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

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Operating income (loss). Operating income increased by $4.0 million during the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017, an increase of 152.7%. This increase was due in part to higher gross margins of $2.5 million and, in part, to the absence of impairment expense in the nine months ended September 30, 2018, compared to $1.6 million of impairment expense recorded during the nine months ended September 30, 2017.

Water Services

The following table summarizes the operating results of the Water Services segment for the three months ended September 30, 2018 and 2017.

	Three Months Ended September 30,
	2018			% of Revenue			2017			% of Revenue			Change			% Change
	(in thousands, except per barrel data)
Revenue	$	3,325					$	2,111					$	1,214			57.5	%
Costs of services		962						837						125			14.9	%
Gross margin		2,363			71.1	%		1,274			60.4	%		1,089			85.5	%
General and administrative		774			23.3	%		858			40.6	%		(84	)		(9.8)	%
Depreciation, amortization and accretion		410			12.3	%		450			21.3	%		(40	)		(8.9)	%
Gains on asset disposals, net		(769	)		(23.1)	%		208			9.9	%		(977	)		469.7	%
Operating income	$	1,948			58.6	%	$	(242	)		(11.5)	%	$	2,190			905.0	%
Operating Data
Total barrels of saltwater disposed		4,276						3,102						1,174			37.8	%
Average revenue per barrel disposed (a)	$	0.78					$	0.68					$	0.10			14.0	%
Revenue variance due to barrels disposed													$	799
Revenue variance due to revenue per barrel													$	415

(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 saltwater disposed.

Revenue. Revenue of the Water Services segment increased by $1.2 million during the three months ended September 30, 2018 compared to the three months ended September 30, 2017, an increase of 57.5%, due primarily to a 38% increase in the volume of saltwater disposed and an increase in the average revenue per barrel disposed of 14%.  This is despite the sale of two of our saltwater disposal facilities in the early part of 2018.

Revenues at our North Dakota facilities increased by $1.5 million, from $1.8 million during the three months ended September 30, 2017 to $3.3 million during the three months ended September 30, 2018, an increase of 83.3%. Volumes of our North Dakota facilities increased by 1.7 million barrels, from 2.6 million barrels during the three months ended September 30, 2017 to 4.3 million barrels during the three months ended September 30, 2018, an increase of 65.4%. The increase in volumes was due to the completion of two pipelines into one of our facilities in January 2018, rising rates, higher oil prices, and to increased customer activity around several of our other facilities.

Our Texas facilities generated revenues of $0.3 million on the disposal of 0.5 million barrels during the three months ended September 30, 2017. We sold both of our Texas facilities in the first half of 2018. All of our remaining facilities are located in North Dakota.

The average revenue per barrel increased during the three months ended September 30, 2018 compared to the three months ended September 30, 2017, due in part to increased revenues from our new pipeline system, higher rates, and oil prices. 

 Costs of services. Costs of services increased by $0.1 million during the three months ended September 30, 2018 compared to the three months ended September 30, 2017. A decrease of $0.1 million in costs of services resulting from the sale of our Texas facilities was offset by an increase in costs, including utility and chemical expense, resulting from higher volumes at our other facilities.

Gross margin. Gross margin increased $1.1 million during the three months ended September 30, 2018 compared to the three months ended September 30, 2017, due primarily to an increase in revenue. 

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General and administrative. General and administrative expenses include general overhead expenses such as salary costs, insurance, property taxes, royalty expenses, and other miscellaneous expenses. These expenses decreased by $0.1 million during the three months ended September 30, 2018 compared to the three months ended September 30, 2017.

Depreciation, amortization and accretion. Depreciation, amortization and accretion expense during the three months ended September 30, 2018 was not significantly different from depreciation and amortization expense during the three months ended September 30, 2017.

Gain on asset disposals, net. During the three months ended September 30, 2018, we received $0.2 million of additional proceeds from the May 2018 sale of our facility in Orla, Texas. These proceeds had been subject to a holdback provision in the agreement to sell the facility, and we received these proceeds upon settlement of a dispute related to workmanship associated with one of the assets that was rebuilt prior to the sale.

During the three months ended September 30, 2018, we received proceeds of $0.4 million from the settlement of litigation related to lightning strikes that occurred in 2017 at our facilities in Orla, Texas and Grassy Butte, North Dakota. This litigation related to the non-performance of certain lightning protection equipment we had purchased to protect the facilities against lightning strikes.

During the three months ended September 30, 2018, we collected $0.1 million of insurance proceeds, which represented the final payment on a property damage insurance claim related to the Grassy Butte facility.

During the three months ended September 30, 2017, we recorded losses of $0.2 million related to lightning strikes at two of our facilities for non-reimbursable costs associated with these incidents.

Operating income. Our Water Services segment generated operating income of $1.9 million during the three months ended September 30, 2018 compared to an operating loss of $0.2 million during the three months ended September 30, 2017. This increase is primarily attributable to an increase in the segment’s gross margin of $1.1 million and a $1.0 million increase in gains on asset disposals.

The following table summarizes the operating results of the Water Services segment for the nine months ended September 30, 2018 and 2017.

	Nine Months Ended September 30,
	2018			% of Revenue			2017			% of Revenue			Change			% Change
	(in thousands, except per barrel data)
Revenue	$	8,861					$	6,005					$	2,856			47.6	%
Costs of services		2,981						2,330						651			27.9	%
Gross margin		5,880			66.4	%		3,675			61.2	%		2,205			60.0	%
General and administrative		2,402			27.1	%		1,651			27.5	%		751			45.5	%
Depreciation, amortization and accretion		1,202			13.6	%		1,335			22.2	%		(133	)		(10.0	)%
Impairments		—						688			11.5	%		(688	)		(100.0	)%
Gains on asset disposals, net		(4,039	)		(45.6	)%		77			1.3	%		(4,116	)		5345.5	%
Operating income	$	6,315			71.3	%	$	(76	)		(1.3	)%	$	6,391			8409.2	%
Operating Data
Total barrels of saltwater disposed		10,928						8,841						2,087			23.6	%
Average revenue per barrel disposed (a)	$	0.81					$	0.68					$	0.13			19.0	%
Revenue variance due to barrels disposed													$	1,418
Revenue variance due to revenue per barrel													$	1,438

(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 saltwater disposed.

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Revenue. Revenue of the Water Services segment increased by $2.9 million during the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017, an increase of 47.6%, due primarily to a 24% increase in the volume of saltwater disposed and an increase in the average revenue per barrel disposed of 19%.

Revenues of our North Dakota facilities increased by $4.0 million, from $4.8 million during the nine months ended September 30, 2017 to $8.8 million during the nine months ended September 30, 2018, an increase of 80.8%. Volumes of our North Dakota facilities increased by 3.9 million barrels, from 6.9 million barrels during the nine months ended September 30, 2017 to 10.8 million barrels during the nine months ended September 30, 2018, an increase of 56.5%. The increase in volumes was due to the completion of a pipeline system at one of our facilities in January 2018 and to increased customer activity around several of our other facilities.

Revenues of our Texas facilities decreased by $1.1 million, from $1.2 million during the nine months ended September 30, 2017 to $0.1 million during the nine months ended September 30, 2018. Volumes of our Texas facilities decreased by 1.9 million barrels, from 2.0 million barrels during the nine months ended September 30, 2017 to 0.1 million barrels during the nine months ended September 30, 2018. This was due to the sale in January 2018 of our Pecos facility and the sale in May 2018 of our Orla facility. All of our remaining facilities are located in North Dakota.  

The average revenue per barrel increased during the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017, due in part to increased revenues from our new pipeline system, as well as pricing increases. In addition, revenues during the nine months ended September 30, 2018 included $0.1 million of management fees associated with a transition services agreement related to the sale of the Pecos facility.

Costs of services. Costs of services increased by $0.7 million during the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017. A decrease of $0.3 million in costs of services resulting from the sale of our Texas facilities was offset by an increase of $0.4 million in chemical and utility expense, as a result of higher volumes at our other facilities, an increase of $0.2 million in expense related to spill cleanup at certain facilities, an increase in repair and maintenance expense, and an increase in employee compensation expense.

Gross margin. Gross margin increased $2.2 million during the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017, an increase of 60.0%, due primarily to a $2.9 million increase in revenue, partially offset by a $0.7 million increase in cost of services. 

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

   Depreciation, amortization and accretion. Depreciation, amortization and accretion expense during the nine months ended September 30, 2018 was not significantly different from depreciation and amortization expense during the nine months ended September 30, 2017.

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 saltwater disposal facilities. We experienced low volumes at this facility due to competition in the area and to low levels of exploration and production activity near the facility.

Gain on asset disposals, net. During the nine months ended September 30, 2018, we recorded a gain of $1.8 million on the sale of our facility in Orla, Texas and a gain of $1.8 million on the sale of our facility in  Pecos, Texas. During the nine months ended September 30, 2018, we received proceeds of $0.4 million from the settlement of litigation related to lightning strikes that occurred in 2017 at our facilities in Orla, Texas and Grassy Butte, North Dakota. This litigation related to the non-performance of certain equipment we had purchased to protect the facilities against lightning strikes.

During the nine months ended September 30, 2018, we collected $0.1 million of insurance proceeds, which represented the final payment on a property damage insurance claim related to the Grassy Butte facility.

These gains were partially offset by a loss of $0.1 million on the abandonment of a capital expansion project.

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Operating income. Our Water Services segment generated operating income of $6.3 million during the nine months ended September 30, 2018 compared to an operating loss of $0.1 million during the nine months ended September 30, 2017. The increase in operating income was due in part to gains of $3.6 million from the sales of our saltwater disposal facilities in Texas, an increase of $2.2 million in the segment’s gross margin, lawsuit settlement gains of $0.4 million, and impairments of $0.7 million recorded in 2017, partially offset by an increase of $0.8 million in general and administrative expenses.

Adjusted EBITDA

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 expense 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, maintenance capital expenditures, and cash distributions on preferred equity. Adjusted EBITDA, Adjusted EBITDA attributable to limited partners and Distributable Cash Flow are used as supplemental financial measures by management and by external users of our financial statements, such as investors and commercial banks, to assess:

● the financial performance of our assets without regard to the impact of financing methods, capital structure or historical cost basis of our assets;

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

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

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

● our operating performance as compared to those of other companies in our industry without regard to the impact of financing methods and capital structure.

We believe that the presentation of Adjusted EBITDA 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 measure. Each of these non-GAAP measures exclude some, but not all, items that affect the most directly comparable GAAP financial measure. Adjusted EBITDA, Adjusted EBITDA attributable to limited partners, and Distributable Cash Flow should not be considered alternatives to net income (loss), net 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 similarly titled measures of other companies, thereby diminishing their utility.

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

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Reconciliation of Net Income (Loss) to Adjusted EBITDA to Distributable Cash Flow
	Three Months ended September 30,					Nine Months ended September 30,
	2018		2017			2018		2017
	(in thousands)
Net income (loss)	$	4,954	$	562		$	9,470	$	(3,862	)
Add:
Interest expense		1,283		1,907			4,907		5,411
Debt issuance cost write-off		—		—			114		—
Depreciation, amortization and accretion		1,393		1,465			4,186		4,378
Impairments		—		—			—		3,598
Income tax expense		497		529			865		458
Non-cash allocated expenses		—		—			—		1,750
Equity-based compensation		361		371			908		1,137
Foreign currency losses		—		—			354		—
Losses on asset disposals, net		—		208			—		77
Less:
Foreign currency gains		97		557			—		824
Gain on asset disposals, net		769		—			4,039		—
Adjusted EBITDA	$	7,622	$	4,485		$	16,765	$	12,123
Adjusted EBITDA attributable to general partner		—		(1,000	)		—		(1,000	)
Adjusted EBITDA attributable to noncontrolling interests		412		163			1,076		(73	)
Adjusted EBITDA attributable to limited partners / controlling interests	$	7,210	$	5,322		$	15,689	$	13,196
Less:
Cash interest paid, cash taxes paid, and maintenance capital expenditures		1,469		1,910			5,897		6,380
Distributable cash flow (a)	$	5,741	$	3,412		$	9,792	$	6,816

(a) In future periods, cash distributions paid on the preferred equity that we issued and sold in May 2018 will be reported as a reduction to distributable cash flow. The first distribution on the preferred equity will be paid in November 2018.

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Reconciliation of Net Income Attributable to Limited Partners to Adjusted EBITDA Attributable to Limited Partners and Distributable Cash Flow
	Three Months ended September 30,				Nine Months ended September 30,
	2018		2017		2018		2017
	(in thousands)
Net income attributable to limited partners	$	4,665	$	1,554	$	8,797	$	178
Add:
Interest expense attributable to limited partners		1,283		1,907		4,907		5,411
Debt issuance cost write-off attributable to limited partners		—		—		114		—
Depreciation, amortization and accretion attributable to limited partners		1,277		1,322		3,804		3,952
Impairments attributable to limited partners		—		—		—		2,823
Income tax expense attributable to limited partners		490		517		844		442
Equity-based compensation attributable to limited partners		361		371		908		1,137
Losses on asset disposals attributable to limited partners, net		—		208		—		77
Foreign currency losses attributable to limited partners		—		—		354		—
Less:
Foreign currency gains attributable to limited partners		97		557		—		824
Gain on asset disposals attributable to limited partners, net		769		—		4,039		—
Adjusted EBITDA attributable to limited partners		7,210		5,322		15,689		13,196
Less:
Cash interest paid, cash taxed paid and maintenance capital expenditures attributable to limited partners		1,469		1,910		5,897		6,380
Distributable cash flow (a)	$	5,741	$	3,412	$	9,792	$	6,816

(a) In future periods, cash distributions paid on the preferred equity that we issued and sold in May 2018 will be reported as a reduction to distributable cash flow. The first distribution on the preferred equity will be paid in November 2018.

Reconciliation of Net Cash Provided by Operating Activities to Adjusted EBITDA to Distributable Cash Flow
	Nine Months ended September 30,
	2018			2017
	(in thousands)
Cash flows provided by operating activities	$	6,955		$	263
Changes in trade accounts receivable, net		9,395			11,583
Changes in prepaid expenses and other		(891	)		765
Changes in accounts payable and accrued liabilities		(4,129	)		(6,552	)
Change in income taxes payable		(62	)		271
Interest expense (excluding non-cash interest)		4,478			4,968
Income tax expense (excluding deferred tax benefit)		865			819
Other		154			6
Adjusted EBITDA	$	16,765		$	12,123
Adjusted EBITDA attributable to general partner		—			(1,000	)
Adjusted EBITDA attributable to noncontrolling interests		1,076			(73	)
Adjusted EBITDA attributable to limited partners / controlling interests	$	15,689		$	13,196
Less:
Cash interest paid, cash taxes paid, maintenance capital expenditures		5,897			6,380
Distributable cash flow (a)	$	9,792		$	6,816

(a) In future periods, cash distributions paid on the preferred equity that we issued and sold in May 2018 will be reported as a reduction to distributable cash flow. The first distribution on the preferred equity will be paid in November 2018.

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Management’s Discussion and Analysis of Financial Condition and Liquidity

Liquidity and Capital Resources

We anticipate making growth capital expenditures in the future, including acquiring new businesses. 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 and will continue to be substantial. This will reduce our borrowing capacity for other purposes and reduce our cash available for distribution” in our Annual Report on Form 10-K for the year ended December 31, 2017), 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.

At September 30, 2018, our sources of liquidity included:

● $11.2 million cash on the balance sheet at September 30, 2018;

● available borrowings under our Credit Agreement of $13.9 million at September 30, 2018 that are limited by certain financial covenant ratios as outlined in the Credit Agreement; and

● issuance of equity and/or debt securities, subject to our debt covenants.

Distributions

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.

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

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

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The following table summarizes the distributions declared since our IPO:

					Total Cash
	Per Unit Cash		Total Cash		Distributions
Payment Date	Distributions		Distributions		to Affiliates (a)
			(in thousands)
Total 2014 Distributions		1.104646		13,064		8,296
Total 2015 Distributions		1.625652		19,232		12,284
Total 2016 Distributions		1.625652		19,258		12,414
February 13, 2017		0.406413		4,823		3,107
May 13, 2017		0.210000		2,495		1,606
August 12, 2017		0.210000		2,495		1,607
November 14, 2017		0.210000		2,497		1,608
Total 2017 Distributions		1.036413		12,310		7,928
February 14, 2018		0.210000		2,498		1,599
May 15, 2018		0.210000		2,506		1,604
August 14, 2018		0.210000		2,506		1,604
November 14, 2018 (b)		0.210000		2,509		1,606
Total 2018 Distributions		0.840000		10,019		6,413
Total Distributions (since IPO)	$	6.232363	$	73,883	$	47,335

(a) Approximately 63.9% of the Partnership’s outstanding common units at September 30, 2018 were held by affiliates.

(b) Third quarter 2018 distribution was declared and will be paid in the fourth quarter of 2018.

On May 29, 2018 we issued and sold in a private placement 5,769,231 Series A Preferred Units representing limited partner interests in the Partnership (the “Preferred Units”) for a cash purchase price of $7.54 per Preferred Unit, resulting in proceeds to the Partnership of $43.5 million. The purchaser of the Preferred Units is entitled to receive quarterly distributions that represent an annual return of 9.5% (which amounts to $4.1 million per year). Of this 9.5% annual return, we will be required to pay at least 2.5% in cash and will have the option to pay the remaining 7.0% in kind (in the form of issuing additional Preferred Units) for the first twelve quarters after the initial sale of the Preferred Units. We expect to pay the first distribution on the Preferred Units in November 2018 of $1.4 million in cash.

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Our Credit Agreement

On May 29, 2018, we entered into an amended and restated credit agreement (as amended and restated, the “Credit Agreement”) that provides up to $90.0 million in borrowing capacity, subject to certain limitations, and contains an accordion feature that allows us to increase the borrowing capacity to $110.0 million if the lenders agree to increase their commitments in the future or if other lenders join the facility. The Credit Agreement matures May 29, 2021. The obligations under the Credit Agreement are secured by a first priority lien on substantially all of our assets. The credit agreement as it existed prior to the May 29, 2018 amendment will hereinafter be referred to as the “Previous Credit Agreement” or, together with the Credit Agreement, as the “Credit Agreements”.

Outstanding borrowings at September 30, 2018 were $76.1 million and are reflected as long-term debt on the Unaudited Condensed Consolidated Balance Sheets beginning May 29, 2018. Debt issuance costs are reported as debt issuance costs, net on the Unaudited Condensed Consolidated Balance Sheets and total $1.4 million at September 30, 2018. Outstanding borrowings at December 31, 2017 were $136.9 million and are reflected net of debt issuance costs of $0.6 million as current portion of long-term debt on the Unaudited Condensed Consolidated Balance Sheet. At December 31, 2017, the outstanding balance was classified as current due to the fact that the facility was scheduled to mature within one year. 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).

We incurred certain debt issuance costs associated with the Previous Credit Agreement, which we were amortizing on a straight-line basis over the life of the Previous Credit Agreement. Upon amending the Credit Agreement in May 2018, we wrote off $0.1 million of these debt issuance costs and reported this expense within debt issuance cost write-off in our Unaudited Condensed Consolidated Statements of Operations for the nine months ended September 30, 2018, which represented the portion of the unamortized debt issuance costs attributable to lenders who are no longer participating in the credit facility subsequent to the amendment. The remaining debt issuance costs associated with the Previous Credit Agreement, along with $1.3 million of debt issuance costs associated with the amended and restated Credit Agreement, are being amortized on a straight-line basis over the three-year term of the Credit Agreement.

All borrowings under the Credit Agreement bear interest, at our option, on a leveraged based grid pricing at (i) a base rate plus a margin of 1.5% to 3.0% per annum (“Base Rate Borrowing”) or (ii) an adjusted LIBOR rate plus a margin of 2.5% to 4.0% per annum (“LIBOR Borrowings”). The applicable margin is determined based on the leverage ratio of the Partnership, as defined in the Credit Agreement. Generally, the interest rate on our borrowings ranged between 4.74% and 5.95% for the nine months ended September 30, 2018 and 3.90% and 4.99% for the nine months ended September 30, 2017. Interest on Base Rate Borrowings is payable monthly. Interest on LIBOR Borrowings is paid upon maturity of the underlying LIBOR contract, but no less often than quarterly. Commitment fees are charged at a rate of 0.50% on any unused credit and are payable quarterly. Interest paid during the three months ended September 30, 2018 and 2017 was $1.1 million and $1.7 million respectively, including commitment fees. Interest paid during the nine months ended September 30, 2018 and 2017 was $4.6 million and $5.0 million, respectively, including commitment fees.

The Credit Agreement contains various customary covenants and restrictive provisions. The Credit Agreement also requires maintenance of certain financial covenants, including a leverage ratio (as defined in the Credit Agreement) of not more than 4.0 to 1.0 and an interest coverage ratio (as defined in the Credit Agreement) of not less than 3.0 to 1.0. At September 30, 2018, our leverage ratio was 3.32 to 1.0 and our interest coverage ratio was 5.24 to 1.0, pursuant to the Credit Agreement. Upon the occurrence and during the continuation of an event of default, subject to the terms and conditions of the Credit Agreement, the lenders may declare any outstanding principal, together with any accrued and unpaid interest, to be immediately due and payable and may exercise the other remedies set forth or referred to in the Credit Agreement. We were in compliance with all debt covenants as of September 30, 2018.

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

Capital Leases

During the third quarter of 2018, our Pipeline and Process Services and Water Services segments leased vehicles for $0.3 million under lease agreements at interest rates of 6.16% that are classified as capital leases. The leased vehicles are amortized on a straight-line basis over the lease terms of four years. Minimum lease payments will be less than $0.1 million in 2018 and $0.1 million for the years ended December 31, 2019 through 2021. The $0.3 million capital lease obligation is reflected in the Unaudited Condensed Balance Sheet at September 30, 2018 in accrued payroll and other ($0.1 million) and other non-current liabilities ($0.2 million).

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Cash Flows

The following table sets forth a summary of the net cash provided by (used in) operating, investing, and financing activities for the nine months ended September 30, 2018 and 2017.

	Nine Months Ended September 30,
	2018			2017
	(in thousands)
Net cash provided by operating activities	$	6,955		$	263
Net cash provided by investing activities		7,296			396
Net cash used in financing activities		(27,479	)		(8,945	)
Effect of exchange rates on cash		11			831
Net decrease in cash and cash equivalents	$	(13,217)		$	(7,455)

Net cash provided by operating activities. Net operating cash inflows for the nine months ended September 30, 2018 were $7.0 million, consisting of net income of $9.5 million plus non-cash expenses of $1.8 million, less net changes in working capital of $4.3 million. Non-cash expense items include depreciation, amortization, and accretion expense of $4.2 million, equity-based compensation expense of $0.9 million, interest expense from debt issuance cost amortization of $0.4 million, and foreign currency losses of $0.4 million, partially offset by net gains on asset disposals of $4.1 million. The net change in working capital includes a net increase of $9.4 million in accounts receivable, a decrease in prepaid expenses and other of $0.9 million, and a net increase of $4.2 million in current liabilities. The increase in working capital resulted from the growth of our business, primarily in the Pipeline Inspection segment.

Net operating cash inflows for the nine months ended September 30, 2017 were $0.3 million, consisting of a net loss of $3.9 million, plus non-cash expenses of $10.2 million (including impairments of $3.6 million), less a net increase in working capital of $6.1 million. Non-cash expenses included depreciation, amortization and accretion, and impairment expense, among others. Non-cash expenses also included expenses attributable to us that were paid by Holdings and recorded as an equity contribution in our financial statements.

Net cash provided by investing activities. During the nine months ended September 30, 2018, cash inflows from investing activities included proceeds of $12.2 million related to the sales of our Orla and Pecos saltwater disposal facilities, $0.4 million related to the settlement of litigation related to lightning strikes at two of our facilities, and $0.1 million of property damage insurance proceeds related to the lightning strikes. Cash outflows from investing activities included $5.5 million of capital expenditures, which related primarily to the construction of a gathering system at one of our facilities in North Dakota, the rebuilding of the Orla, Texas facility prior to its sale, and the rebuilding of the Grassy Butte, North Dakota facility (the surface equipment at both the Orla and Grassy Butte facilities were destroyed by fires in 2017 resulting from lightning strikes). Capital expenditures also included the purchase of equipment to support the growth in our Pipeline Inspection segment. 

During the nine months ended September 30, 2017, cash inflows from investing activities consisted primarily of $1.6 million of insurance proceeds associated with property damage that resulted from the lightning strike and fire at our Orla, Texas facility.  Cash used in investing activities related to capital expenditures, which consisted primarily of equipment purchases, many of which were to support increasing revenues in our Pipeline Inspection segment’s non-destructive examination business.

Net cash used in financing activities. During the nine months ended September 30, 2018, cash inflows from financing activities included $43.3 million of proceeds from the sale of Preferred Units, net of related costs. Cash outflows from financing activities primarily included $60.8 million of payments to reduce the balance outstanding on our revolving credit facility, $1.3 million of debt issuance costs related to an amendment to our revolving credit facility, $7.5 million of distributions to common unitholders and $1.0 million of distributions to noncontrolling interests.

During the nine months ended September 30, 2017, financing cash outflows consisted primarily of $9.8 million of distributions to our common unitholders. Financing cash inflows included a $1.0 million contribution from Holdings.

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Working Capital

Our working capital was $43.0 million at September 30, 2018. Our Pipeline Inspection and Pipeline & Process Services segments have substantial working capital requirements, as we generally pay our inspectors and field personnel on a weekly basis, but typically receive payment from our customers 45 to 90 days after the services have been performed. We utilize borrowings under our Credit Agreement to fund the working capital needs of these segments. These borrowings reduce the amount of credit available for other uses, such as acquisitions and growth projects, and increase interest expense, thereby reducing cash flow. Please read “Risk Factors — Risks Related to Our Business — 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” and “Risk Factors – Risks Related to Our Business – Our existing and future debt levels may limit our flexibility to obtain financing and to pursue other business opportunities” in our Annual Report on Form 10-K for the year ended December 31, 2017.

Capital Expenditures

We generally have small capital expenditure requirements compared to many other master limited partnerships.  Water Services has minimal capital expenditure requirements for the maintenance of existing saltwater disposal facilities and the acquisition or construction and development of new saltwater disposal facilities. We regularly look for growth capital expenditure opportunities to build new pipelines into our existing saltwater disposal facilities or to build, develop or acquire additional saltwater disposal facilities.  Our Pipeline Inspection segment does not generally require significant capital expenditures, other than in the nondestructive examination service line, which has been investing growth capital to acquire field equipment to support its growing revenues. Pipeline & Process Services has both maintenance and growth capital needs for heavy equipment and vehicles in order to perform hydrostatic testing and other integrity procedures. Our partnership agreement requires that we categorize our capital expenditures as either maintenance capital expenditures or expansion capital expenditures. 

● Maintenance capital expenditures are those cash expenditures that will enable us to maintain our operating capacity or operating income over the long-term.  Maintenance capital expenditures include expenditures to maintain equipment reliability, integrity, and safety, as well as to address environmental laws and regulations.  Maintenance capital expenditures were $0.3 million and $0.5 million for the three and nine months ended September 30, 2018, respectively, and $0.2 million and $0.3 million for the three and nine months ended September 30, 2017, 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 acquisition of assets or businesses and the construction or development of additional saltwater disposal capacity, to the extent such expenditures are expected to expand our long-term operating capacity or operating income.  Expansion capital expenditures were $1.3 million and $4.9 million for the three and nine months ended September 30, 2018, respectively and $0.5 million and $0.8 million for the three and nine months ended September 30, 2017, respectively. Expansion capital expenditures during 2018 related primarily to the construction of a gathering system at one of our facilities in North Dakota, the rebuilding of the Orla, Texas facility prior to its sale, and the rebuilding of the Grassy Butte, North Dakota facility (the surface equipment at both the Orla and Grassy Butte facilities were destroyed by fires in 2017 resulting from lightning strikes). Expansion capital expenditures during 2018 also included the purchase of non-destructive technology for our inspection business.
 

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

Contractual Obligations

We have $76.1 million of borrowings under our Credit Agreement as of September 30, 2018. Additionally, we have long-term office and other lease obligations totaling approximately $4.4 million as of September 30, 2018, payable through calendar year 2026. The office lease for our headquarters represents approximately $3.8 million of our total operating lease obligation. We can exit this lease after 18 months after the inception date (the original lease term is 84 months) with the payment of a nominal penalty.  Our other leases are generally of a shorter term or we have early termination rights.

Off-Balance Sheet Arrangements

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

47

Critical Accounting Policies

There have been no material changes in our critical accounting policies and procedures during the three months ended September 30, 2018. For more information, please read our disclosure of critical accounting policies in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations of our Annual Report on Form 10-K for the year ended December 31, 2017, filed with the SEC on March 23, 2018. 

Recent Accounting Standards

In 2018, we adopted the following new accounting standards issued by the Financial Accounting Standards Board (“FASB”);

The FASB issued Accounting Standards Update (“ASU”) 2014-09 – Revenue from Contracts with Customers in May 2014. ASU 2014-09 is intended to clarify the principles for recognizing revenue and to develop a common standard for recognizing revenue for GAAP and International Financial Reporting Standards that is applicable to all organizations. This guidance requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to receive in exchange for those goods and services. It also requires additional disclosure about the nature, amount, timing, and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to obtain or fulfill a contract. We adopted this new standard utilizing the modified retrospective transition approach. The adoption of this ASU had no effect on our Unaudited Condensed Consolidated Financial Statements other than additional disclosures included in Form 10-Q.

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

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

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

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

In July 2018, the FASB issued ASU 2018-11 – Targeted Improvements which provides entities with a transition option to not restate the comparative periods for the effects of applying the new leasing standard (i.e. comparative periods presented in the Unaudited Condensed Consolidated Financial Statements will continue to be in accordance with ASC 840).  We will adopt the new standard on the effective date of January 1, 2019 and expect to use a modified retrospective approach as permitted under ASU 2018-11.  We continue to evaluate the impact this ASU will have on our Unaudited Condensed Consolidated Balance Sheets and the related disclosures.  We expect the effects of implementing ASU 2016-02 will be material to our Unaudited Condensed Consolidated Balance Sheets and related disclosures, but immaterial to our Unaudited Condensed Consolidated Statements of Operations and Unaudited Condensed Consolidated Statements of Cash Flows. Liabilities recorded as a result of this standard will be excluded from the definition of indebtedness under our credit facility and therefore, will not adversely impact the leverage ratio under our credit facility.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

There have been no material changes to the Partnership’s exposure to market risk since December 31, 2017.

We continue to 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 September 30, 2018, our exposure consists of floating interest rate changes on the outstanding borrowings under our Credit Agreement of $76.1 million.  A hypothetical change in interest rates of 1.0% would result in an increase or decrease of our annual interest expense of approximately $0.8 million. 

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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.

Item 4. Controls and Procedures

Management’s Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15 under the Exchange Act, as of the end of the period covered by this report, the Partnership carried out an evaluation of the effectiveness of the design and operation of the Partnership’s disclosure controls and procedures. This evaluation was carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, and others involved in the accounting and reporting functions.

Disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed in Partnership reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed in the Partnership reports filed under the Exchange Act is accumulated and communicated to management, including the Partnership’s Chief Executive Officer and Chief Financial Officer as appropriate, to allow timely decisions regarding required disclosure.

Based upon that evaluation, our management, including our Chief Executive Officer and Chief Financial Officer concluded that, as of the end of the period covered by this report, the Partnership’s disclosure controls and procedures were effective to provide reasonable assurance that financial information was processed, recorded and reported accurately.

Changes in Internal Control over Financial Reporting

There was no change in our internal control over financial reporting that occurred during the three months ended September 30, 2018 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION  

Item 1.           Legal Proceedings

Fithian v. TIR LLC

On October 5, 2017, a former inspector for TIR LLC and Cypress Energy Management – TIR, LLC (“CEM TIR”) filed a putative collective action lawsuit alleging that TIR LLC, CEM TIR and Cypress Energy Partners – Texas, LLC failed to pay a class of workers overtime in compliance with the Fair Labor Standards Act (“FLSA”) titled James Fithian, et al v. TIR LLC, et al in the United States District Court for the Western District of Texas, Midland Division. The plaintiff subsequently withdrew his action and filed a similar action in Oklahoma State Court, District of Tulsa County. The plaintiff alleges he was a non-exempt employee of TIR LLC 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. The defendants plan to continue to vigorously defend these claims and have stayed a counterclaim against the named plaintiff.

On March 28, 2018, the court granted a joint stipulation of dismissal without prejudice in regard to TIR LLC and Cypress Energy Partners – Texas, LLC, as neither of those parties were employers of the plaintiff or the putative class members during the time period that is the subject of the lawsuit. On July 26, 2018, plaintiff filed a motion for conditional class certification. CEM-TIR subsequently filed pleadings opposing the motion. The court set plaintiff’s motion for conditional certification for hearing on November 29, 2018.

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.

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Item 1A. Risk Factors

There have been no material changes with respect to the risk factors disclosed in our Annual Report on Form 10-K for the year ended December 31, 2017.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. Defaults upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

Appointment of Chief Financial Officer

On November 7, 2018, the board of directors (the “Board”) of Cypress Energy Partners GP, LLC, our general partner (the “General Partner”), appointed Jeffrey A. Herbers, 41, to the position of Chief Financial Officer of the General Partner. Prior to being appointed as Chief Financial Officer of the General Partner, Mr. Herbers served as the Chief Accounting Officer and Vice President of the General Partner from September 2016 to November 2017 and as the Interim Chief Financial Officer from November 2017 to November 2018. From December 2015 to September 2016, Mr. Herbers served as the sole member of Jeff Herbers PLLC. Prior to joining the General Partner, Mr. Herbers served as the Chief Accounting Officer of NGL Energy Holdings LLC from February 2012 to December 2015.

There are no arrangements or understandings with the Partnership, or any other persons, pursuant to which Mr. Herbers was appointed Chief Financial Officer. There are no relationships regarding Mr. Herbers that would require disclosure pursuant to Item 404(a) of Regulation S-K.

Appointment of Director to the Board of Directors

On November 9, 2018, Holdings II, as the sole member of our General Partner, appointed Cynthia A. Field, 58, to serve as a director on the Board of the General Partner. Ms. Field has served as the Sole Manager of CF Inspection, a nationally-qualified woman-owned inspection firm affiliated with one of Holdings’ owners, since August of 2013. Additionally, she was appointed President and Chief Executive Officer of CF Inspection in January 2018.  Ms. Field is the daughter of Charles C. Stephenson, Jr., one of the directors on the Board of the General Partner.  Ms. Field also serves as the Executive Director and a Trustee of the Charles & Peggy Stephenson Family Foundation, and as a member of the Gilcrease Museum National Advisory Board.

There are no arrangements or understandings with the Partnership, the General Partner or any other persons, pursuant to which Ms. Field was appointed as a director on the Board of the General Partner. We are party to a joint venture with CF Inspection. We own 49% of CF Inspection and Ms. Field owns the remaining 51% of CF Inspection. In 2017, CF Inspection represented approximately 3.5% of our consolidated revenue.

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Item 6. Exhibits

The following exhibits are filed as part of, or incorporated by reference into, this Form 10-Q.

Exhibit Number	Description
3.1	First Amendment to First Amended and Restated Agreement of Limited Partnership of Cypress Energy Partners, L.P. dated as of May 29, 2018 (incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed on May 31, 2018)
3.2	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)
10.1	Series A Preferred Unit Purchase Agreement between Cypress Energy Partners, L.P. and Stephenson Equity, Co. No. 3, dated as of May 29, 2018 (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed on May 31, 2018)
10.2	Amended and Restated Credit Agreement by and among Cypress Energy Partners, L.P., certain of its affiliates as co-borrowers and guarantors, Deutsche Bank AG, New York Branch, as lender, issuing bank, swing line lender and collateral agent, the other lenders from time to time party thereto, and Deutsche Bank Trust Company Americas, as administrative agent, dated May 29, 2018 (incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed on May 31, 2018)
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*	Principal 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
32.2**	Principal 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.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Tulsa, State of Oklahoma, on November 13, 2018.

Cypress Energy Partners, L.P.
By:	Cypress Energy Partners GP, LLC, its general partner
/s/ Peter C. Boylan III
By:	Peter C. Boylan III
Title:	Chief Executive Officer
/s/ Jeffrey A. Herbers
By:	Jeffrey A. Herbers
Title:	Chief Financial Officer

52

EX-31.1

Cypress Energy Partners, L.P. 10-Q

Exhibit 31.1

CERTIFICATION

I, Peter C. Boylan III, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q for the quarter ended September 30, 2018 of Cypress Energy Partners, L.P. (the “registrant”);

2. 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;

3. 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;

4. 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. 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;

b. 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;

c. 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

d. 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 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. 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

b. 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.

/s/ Peter C. Boylan III

Peter C. Boylan III

Chief Executive Officer

November 13, 2018

53  

EX-31.2

Cypress Energy Partners, L.P. 10-Q

Exhibit 31.2

CERTIFICATION

I, Jeffrey A. Herbers, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q for the quarter ended September 30, 2018 of Cypress Energy Partners, L.P. (the “registrant”);

2. 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;

3. 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;

4. 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. 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;

b. 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;

c. 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

d. 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 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. 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

b. 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.

/s/ Jeffrey A. Herbers

Jeffrey A. Herbers

Chief Financial Officer

November 13, 2018

54  

EX-32.1

Cypress Energy Partners, L.P. 10-Q

Exhibit 32.1

CERTIFICATION OF

 CHIEF EXECUTIVE OFFICER

OF CYPRESS ENERGY PARTNERS GP, LLC

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with this Quarterly Report on Form 10-Q of Cypress Energy Partners, L.P. for the fiscal quarter ended September 30, 2018, as filed with the Securities and Exchange Commission on the date hereof, I, Peter C. Boylan III, Chief Executive Officer and Chairman of Cypress Energy Partners GP, LLC, the general partner of Cypress Energy Partners, L.P., hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1.	This Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2018 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
2.	The information contained in the Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2018 fairly presents, in all material respects, the financial condition and results of operations of Cypress Energy Partners, L.P.

/s/ Peter C. Boylan III

Peter C. Boylan III

Chief Executive Officer

November 13, 2018

55  

EX-32.2

Cypress Energy Partners, L.P. 10-Q

Exhibit 32.2

CERTIFICATION OF

CHIEF FINANCIAL OFFICER

 OF CYPRESS ENERGY PARTNERS GP, LLC

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with this Quarterly Report on Form 10-Q of Cypress Energy Partners, L.P. for the fiscal quarter ended September 30, 2018, as filed with the Securities and Exchange Commission on the date hereof, I, Jeffrey A. Herbers, Chief Financial Officer of Cypress Energy Partners GP, LLC, the general partner of Cypress Energy Partners, L.P., hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1. This Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2018 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2018 fairly presents, in all material respects, the financial condition and results of operations of Cypress Energy Partners, L.P.

/s/ Jeffrey A. Herbers

Jeffrey A. Herbers

Chief Financial Officer

November 13, 2018

56  

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Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2018	Nov. 07, 2018
Document And Entity Information [Abstract]
Entity Registrant Name	Cypress Energy Partners, L.P.
Entity Central Index Key	0001587246
Document Type	10-Q
Trading Symbol	CELP
Document Period End Date	Sep. 30, 2018
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		11,946,040
Document Fiscal Period Focus	Q3
Document Fiscal Year Focus	2018

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Unaudited Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 11,230	$ 24,508
Trade accounts receivable, net	51,027	41,693
Prepaid expenses and other	1,511	2,294
Assets held for sale		2,172
Total current assets	63,768	70,667
Property and equipment:
Property and equipment, at cost	23,694	22,700
Less:Accumulated depreciation	10,666	9,312
Total property and equipment, net	13,028	13,388
Intangible assets, net	23,433	25,477
Goodwill	50,370	53,435
Debt issuance costs, net	1,391
Other assets	285	236
Total assets	152,275	163,203
Current liabilities:
Accounts payable	2,230	3,757
Accounts payable - affiliates	3,656	3,173
Accrued payroll and other	14,132	9,109
Liabilities held for sale		97
Income taxes payable	708	646
Current portion of long-term debt		136,293
Total current liabilities	20,726	153,075
Long-term debt	76,129
Other non-current liabilities	369	143
Total liabilities	97,224	153,218
Partners' capital:
Common units (11,946,040 and 11,889,958 units outstanding at September 30, 2018 and December 31, 2017, respectively)	35,266	34,614
Preferred units (5,769,231 units outstanding at September 30, 2018)	44,671
General partner	(25,876)	(25,876)
Accumulated other comprehensive loss	(2,616)	(2,677)
Total partners' capital	51,445	6,061
Noncontrolling interests	3,606	3,924
Total owners' equity	55,051	9,985
Total liabilities and owners' equity	$ 152,275	$ 163,203

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Unaudited Condensed Consolidated Balance Sheets (Parenthetical) - shares	Sep. 30, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Common units outstanding (in shares)	11,946,040	11,889,958
Preferred units outstanding (in shares)	5,769,231

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Unaudited Condensed Consolidated Statements of Operations - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Revenue	$ 84,778	$ 77,682	$ 226,072	$ 216,971
Costs of services	71,870	68,292	194,092	192,643
Gross margin	12,908	9,390	31,980	24,328
Operating costs and expense:
General and administrative	6,064	5,574	17,341	16,013
Depreciation, amortization and accretion	1,124	1,184	3,368	3,561
Impairments				3,598
(Gains) losses on asset disposals, net	(822)	208	(4,137)	95
Operating income	6,542	2,424	15,408	1,061
Other (expense) income:
Interest expense, net	(1,283)	(1,907)	(4,907)	(5,411)
Debt issuance cost write-off			(114)
Foreign currency gains (losses)	97	557	(354)	824
Other, net	95	17	302	122
Net income (loss) before income tax expense	5,451	1,091	10,335	(3,404)
Income tax expense	497	529	865	458
Net income (loss)	4,954	562	9,470	(3,862)
Net income (loss) attributable to noncontrolling interests	289	8	673	(1,290)
Net income (loss) attributable to partners / controlling interests	4,665	554	8,797	(2,572)
Net loss attributable to general partner		(1,000)		(2,750)
Net income attributable to limited partners	4,665	1,554	8,797	178
Net income attributable to preferred unitholder	1,045		1,412
Net income attributable to common unitholders	$ 3,620	$ 1,554	$ 7,385	$ 178
Net income per common limited partner unit:
Basic (in dollars per unit)	$ 0.30	$ 0.13	$ 0.62	$ 0.02
Diluted (in dollars per unit)	$ 0.26	$ 0.13	$ 0.59	$ 0.02
Weighted average common units outstanding:
Basic (in unit)	11,940,032	11,884,196	11,924,183	10,902,838
Diluted (in unit)	18,140,691	11,994,881	14,970,334	11,111,454
Subordinated Units [Member]
Weighted average common units outstanding:
Weighted average subordinated units outstanding - basic and diluted				974,670

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Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ 4,954	$ 562	$ 9,470	$ (3,862)
Other comprehensive income (loss) - foreign currency translation	(71)	(207)	61	(187)
Comprehensive income (loss)	4,883	355	9,531	(4,049)
Comprehensive income attributable to preferred unitholders	1,045		1,412
Comprehensive income (loss) attributable to noncontrolling interests	289	8	673	(1,290)
Comprehensive loss attributable to general partner		(1,000)		(2,750)
Comprehensive income (loss) attributable to common unitholders	$ 3,549	$ 1,347	$ 7,446	$ (9)

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Unaudited Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Operating activities:
Net income (loss)	$ 9,470	$ (3,862)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, amortization and accretion	4,186	4,378
Impairments		3,598
(Gain) loss on asset disposals, net	(4,137)	95
Interest expense from debt issuance cost amortization	429	443
Debt issuance cost write-off	114
Equity-based compensation expense	908	1,136
Equity in earnings of investee	(169)	(98)
Distributions from investee	113	75
Deferred tax benefit, net		(361)
Non-cash allocated expenses		1,750
Foreign currency (gains) losses, net	354	(824)
Changes in assets and liabilities:
Trade accounts receivable	(9,395)	(11,583)
Prepaid expenses and other	891	(765)
Accounts payable and accrued payroll and other	4,129	6,552
Income taxes payable	62	(271)
Net cash provided by operating activities	6,955	263
Investing activities:
Proceeds from fixed asset disposals	12,762	1,578
Purchases of property and equipment, excluding capital leases	(5,466)	(1,182)
Net cash provided by investing activities	7,296	396
Financing activities:
Issuance of preferred units, net of issuance costs	43,259
Repayments of long-term debt	(60,771)
Debt issuance cost payments	(1,327)
Taxes paid related to net share settlement of equity-based compensation	(131)	(120)
Contributions attributable to general partner		1,000
Capital lease repayments	(8)
Distributions to limited partners	(7,510)	(9,813)
Distributions to noncontrolling interests	(991)	(12)
Net cash used in financing activities	(27,479)	(8,945)
Effect of exchange rates on cash	11	831
Net decrease in cash and cash equivalents and restricted cash equivalents	(13,217)	(7,455)
Cash and cash equivalents (including restricted cash equivalents of $490 at December 31, 2017 and December 31, 2016), beginning of period	24,998	27,183
Cash and cash equivalents (including restricted cash equivalents of $551 at September 30, 2018 and $490 at September 30, 2017), end of period	11,781	19,728
Non-cash items:
Accounts payable excluded from capital expenditures	75	$ 320
Acquisitions of property and equipment included in liabilities	$ 335

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Unaudited Condensed Consolidated Statements of Cash Flows (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2016
Statement of Cash Flows [Abstract]
Restricted cash equivalents	$ 551	$ 490	$ 490	$ 490

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Unaudited Condensed Consolidated Statement of Owners Equity (Unaudited) - 9 months ended Sep. 30, 2018 - USD ($) $ in Thousands	Common Units [Member]	Preferred Units [Member]	General Partner [Member]	Noncontrolling Interest [Member]	Accumulated Other Comprehensive Loss [Member]	Total
Owners' equity at Dec. 31, 2017	$ 34,614		$ (25,876)	$ 3,924	$ (2,677)	$ 9,985
Net income	7,385	$ 1,412		673		9,470
Issuance of preferred units, net		43,259				43,259
Foreign currency translation adjustment					61	61
Distribution to partners	(7,510)					(7,510)
Distributions to non-controlling interest				(991)		(991)
Equity-based compensation	908					908
Taxes paid related to net share settlement of equity-based compensation	(131)					(131)
Owners' equity at Sep. 30, 2018	$ 35,266	$ 44,671	$ (25,876)	$ 3,606	$ (2,616)	$ 55,051

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Organization and Operations

9 Months Ended

Sep. 30, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization and Operations

1. Organization and Operations

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

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

The Water Services segment owns and operates nine (9) Environmental Protection Agency Class II saltwater disposal facilities in the Williston Basin region of North Dakota.  Eight (8) of the facilities are wholly-owned and we have ten (10) pipelines from multiple E&P customers connected to these saltwater disposal facilities, including two (2) that were developed and are owned by the Partnership.  Approximately 95% of our disposal water is produced water that is generated during the production life of an oil and gas well and approximately 41% of our water is delivered via pipeline to our saltwater disposal facilities.  We currently serve in excess of 75 customers.  Our saltwater disposal facilities provide essential midstream services to oil and natural gas upstream producers and their transportation companies. All of the saltwater disposal facilities utilize specialized equipment and remote monitoring to minimize the facilities’ downtime and increase the facilities’ efficiency for peak utilization. These facilities also utilize oil skimming and recovery processes that remove residual oil from water delivered to our saltwater disposal facilities via pipeline or truck. We sell the oil recovered from these skimming processes, which contributes to our revenues. In addition to these saltwater disposal facilities, we provide management and staffing services to a saltwater disposal facility in which we own a 25% ownership interest (see Note 7).

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Basis of Presentation and Significant Accounting Policies

9 Months Ended

Sep. 30, 2018

Accounting Policies [Abstract]

Basis of Presentation and Summary of Significant Accounting Policies

2. Basis of Presentation and Summary of Significant Accounting Policies

Basis of Presentation

The Unaudited Condensed Consolidated Financial Statements as of and for the three months ended September 30, 2018 and 2017 and for the nine months ended September 30, 2018 and 2017 include our accounts and those of our controlled subsidiaries. Investments over which we exercise significant influence, but do not control, are accounted for using the equity method of accounting. Intercompany transactions and account balances have been eliminated in consolidation. The Unaudited Condensed Consolidated Balance Sheet at December 31, 2017 is derived from our audited financial statements.

The accompanying Unaudited Condensed Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim consolidated financial information and in accordance with the rules and regulations of the Securities and Exchange Commission (the “SEC”). The Unaudited Condensed Consolidated Financial Statements include all adjustments considered necessary for a fair presentation of the consolidated financial position and consolidated results of operations for the interim periods presented. Such adjustments consist only of normal recurring items, unless otherwise disclosed herein. Accordingly, the Unaudited Condensed Consolidated Financial Statements do not include all of the information and notes required by GAAP for complete consolidated financial statements. However, we believe that the disclosures made are adequate to make the information not misleading. These interim Unaudited Condensed Consolidated Financial Statements should be read in conjunction with our audited financial statements as of and for the year ended December 31, 2017 included in our Form 10-K. The results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

Use of Estimates in the Preparation of Financial Statements

The preparation of our Unaudited Condensed Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in these financial statements and accompanying notes. Actual results could differ from those estimates.

Significant Accounting Policies

Our significant accounting policies are consistent with those disclosed in Note 2 to our audited financial statements as of and for the year ended December 31, 2017 included in our Form 10-K, except for the adoption of Accounting Standards Update (“ASU”) 2014-09 - Revenue from Contracts with Customers and ASU 2016-18 - Statement of Cash Flows - Restricted Cash on January 1, 2018. Under ASU 2014-09, an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Based on this new accounting guidance, our revenue is earned and recognized through the service offerings of our three reportable business segments. Our sales contracts have terms of less than one year. As such, we have used the practical expedient contained within the accounting guidance which exempts us from the requirement to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract with an original expected duration of one year or less. See Note 10 for disaggregated revenue reported by segment and for disclosure regarding variable consideration. The adoption and application of this ASU had no effect on our Unaudited Condensed Consolidated Financial Statements, other than additional disclosures included in this Form 10-Q. Under ASU 2016-18, an entity is required to show changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents in the statement of cash flows. The adoption and application of this ASU has modified the presentation of cash, cash equivalents, restricted cash, and restricted cash equivalents on our Unaudited Condensed Consolidated Statements of Cash Flows applied on a retrospective basis.

Accounts Receivable and Allowance for Bad Debts

We grant unsecured credit to customers under normal industry standards and terms, and have established policies and procedures that allow for an evaluation of each of our customer’s creditworthiness. We typically receive payment from our customers 45 to 90 days after the services have been performed. The Partnership determines allowances for bad debts based on management’s assessment of the creditworthiness of our customers. Trade receivables are written off against the allowance when deemed uncollectible. Recoveries of trade receivables previously written off are recorded when cash is received. In the first quarter of 2017, we received $0.3 million on accounts receivable previously reserved, which we recorded as a reduction to general and administrative expense in our Unaudited Condensed Consolidated Statements of Operations.

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, a subsidiary of our Pipeline Inspection segment that performs pipeline inspection services for utility customers, and Brown Integrity – PUC, LLC, a subsidiary in which we own a 51% membership interest, 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 tax. The amounts recognized as income tax expense (benefit), income taxes payable, and deferred tax assets / liabilities in our Unaudited Condensed Consolidated Financial Statements include the Canadian income taxes and U.S. federal and state income taxes referred to above, as well as partnership-level taxes levied by various states, which primarily include franchise taxes assessed by the state of Texas.

As a publicly-traded partnership, we are subject to a statutory requirement that 90% of our total gross income represent “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations, and Internal Revenue Service pronouncements), determined on a calendar-year basis. 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 each year since our initial public offering (“IPO”).

Noncontrolling Interest

We own a 51% interest in Brown Integrity, LLC (“Brown”) and a 49% interest in CF Inspection Management, LLC (“CF Inspection”). The accounts of these subsidiaries are included in our Unaudited Condensed Consolidated Financial Statements. The portion of the net income (loss) of these entities that is attributable to outside owners is reported as net income (loss) attributable to noncontrolling interests in our Unaudited Condensed Consolidated Statements of Operations, and the portion of the net assets of these entities that is attributable to outside owners is reported as noncontrolling interests in our Unaudited Condensed Consolidated Balance Sheets.

Property and Equipment

Property and equipment consists of land, land and leasehold improvements, buildings, facilities, wells and related equipment, computer and office equipment, and vehicles. We record property and equipment at cost. Costs of 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 or disposition 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 Unaudited Condensed Consolidated Statements of Operations.

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 exceeds the future undiscounted cash flows expected from the asset, we recognize an impairment charge for the excess of the carrying value of the asset over its estimated fair value. Determinations as to whether and how much an asset is impaired involve 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.

Identifiable Intangible Assets

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

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 values of the assets to their fair values and record a corresponding impairment loss.

Goodwill

Goodwill is not amortized, but is subject to an annual review for impairment on November 1 (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 used to evaluate and measure goodwill for impairment are determined primarily from the manner in which the business that relates to the applicable goodwill is managed or operated. We have determined that our Pipeline Inspection, Pipeline & Process Services, and Water Services segments are the appropriate reporting units for testing goodwill impairment.

To perform a goodwill impairment assessment, we perform an analysis to assess whether it is more likely than not that the fair value of the reporting unit exceeds its carrying value. If we determine that it is more likely than not that the carrying value of the reporting unit exceeds its fair value, we reduce the carrying value of goodwill and record a corresponding impairment expense.

Accrued Payroll and Other

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

	September 30, 2018		December 31, 2017
	(in thousands)
Accrued payroll	$	11,148	$	6,893
Customer deposits		1,893		1,510
Other		1,091		706
	$	14,132	$	9,109

Foreign Currency Translation

Our Unaudited Condensed 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 in which the applicable revenues and expenses were recorded.

Our Unaudited Condensed Consolidated Balance Sheet at September 30, 2018 includes $2.6 million of accumulated other comprehensive loss associated with accumulated currency translation adjustments, all of which relate to our Canadian operations. If at some point in the future we were to 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 Unaudited Condensed Consolidated Statement of Operations as a reduction to net income.

Our Canadian subsidiary has certain intercompany payables to our U.S.-based subsidiaries. These intercompany payables and receivables among our consolidated subsidiaries are eliminated in our Unaudited Condensed Consolidated Balance Sheets. Beginning April 1, 2017, we report currency translation adjustments on these intercompany payables and receivables within foreign currency gains (losses) in our Unaudited Condensed Consolidated Statements of Operations, with offsetting amounts reported within other comprehensive income (loss) in our Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss).

New Accounting Standards

On January 1, 2018, we adopted the following new accounting standards issued by the Financial Accounting Standards Board (“FASB”);

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

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

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

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

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

In July 2018, the FASB issued ASU 2018-11 – Targeted Improvements which provides entities with a transition option to not restate the comparative periods for the effects of applying the new leasing standard (i.e. comparative periods presented in the Unaudited Condensed Consolidated Financial Statements will continue to be in accordance with Accounting Standards Codification 840).  We will adopt the new standard on the effective date of January 1, 2019 and expect to use a modified retrospective approach as permitted under ASU 2018-11.  We continue to evaluate the impact this ASU will have on our Unaudited Condensed Consolidated Balance Sheets related to the addition of the right-of-use asset and associated lease liability.  We expect the effects of implementing ASU 2016-02 will be material to our Unaudited Condensed Consolidated Balance Sheets and related disclosures, but immaterial to our Unaudited Condensed Consolidated Statements of Operations and Unaudited Condensed Consolidated Statements of Cash Flows. Liabilities recorded as a result of this standard will be excluded from the definition of indebtedness under our credit facility and therefore, will not adversely impact the leverage ratio under our credit facility.

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Impairments

9 Months Ended

Sep. 30, 2018

Goodwill and Intangible Assets Disclosure [Abstract]

Impairments

3. Impairments

During the three months ended March 31, 2017, the largest customer of TIR-Canada, the Canadian subsidiary of our Pipeline Inspection segment, completed a bid process and selected different service providers for its inspection projects. These rates were lower than we were prepared to extend to this client. In consideration of the expiration and non-renewal of this contract, we recorded impairments to the carrying values of certain intangible assets of $1.3 million during the three months ended March 31, 2017. Of this amount, $1.1 million related to customer relationships and $0.2 million related to trade names.

During the three months ended March 31, 2017, we recorded an impairment to the remaining $1.6 million carrying value of the goodwill of our Pipeline & Process Services segment. Revenues of this segment were lower than we had expected for the first quarter of 2017. In addition, for this segment, the level of bidding activity for work is typically high in March and April once customers have finalized their budgets for the upcoming year. While we won bids on a number of projects, and our backlog began to improve, the improvement in the backlog was slower than we had originally anticipated, and we revised downward our expectations of the near-term operating results of the segment. We estimated the fair value of the Pipeline & Process Services segment utilizing the income approach (discounted cash flows valuation method), which is a Level 3 input as defined in ASC 820 – Fair Value Measurement. Significant inputs in the valuation included projections of future revenue, anticipated operating costs and appropriate discount rates. Significant assumptions included a 2% annual growth rate of cash flows and a discount rate of 18%. We determined through this analysis that the fair value of goodwill of the Pipeline & Process Services segment was fully impaired. These calculations represent Level 3 non-recurring fair value measurement.

During the three months ended March 31, 2017, we recorded an impairment of $0.7 million to the property and equipment at one of our saltwater disposal facilities. We have experienced low volumes at this facility due to competition in the area and to low levels of exploration and production activity near the facility. The impairment reduced the carrying value of the facility to $0.1 million, all of which is attributable to land.

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Debt

9 Months Ended

Sep. 30, 2018

Debt Disclosure [Abstract]

Debt

4. Debt

Credit Agreement

On May 29, 2018, we entered into an amended and restated credit agreement (as amended and restated, the “Credit Agreement”) that provides up to $90.0 million in borrowing capacity, subject to certain limitations, and contains an accordion feature that allows us to increase the borrowing capacity to $110.0 million if the lenders agree to increase their commitments in the future or if other lenders join the facility. The three-year Credit Agreement matures May 29, 2021. The obligations under the Credit Agreement are secured by a first priority lien on substantially all of our assets. The credit agreement as it existed prior to the May 29, 2018 amendment will hereinafter be referred to as the “Previous Credit Agreement” or, together with the Credit Agreement, as the “Credit Agreements”.

Outstanding borrowings at September 30, 2018 were $76.1 million and are reflected as long-term debt on the Unaudited Condensed Consolidated Balance Sheets beginning May 29, 2018. Debt issuance costs are reported as debt issuance costs, net on the Unaudited Condensed Consolidated Balance Sheets and total $1.4 million at September 30, 2018. Outstanding borrowings at December 31, 2017 were $136.9 million and are reflected net of debt issuance costs of $0.6 million as current portion of long-term debt on the Unaudited Condensed Consolidated Balance Sheet. At December 31, 2017, the outstanding balance was classified as current due to the fact that the facility was scheduled to mature within one year. The carrying value of our long-term debt approximates fair value, as the borrowings under the Credit Agreement are considered to be priced at market for debt instruments having similar terms and conditions (Level 2 of the fair value hierarchy).

We incurred certain debt issuance costs associated with the Previous Credit Agreement, which we were amortizing on a straight-line basis over the life of the Previous Credit Agreement. Upon amending the Credit Agreement in May 2018, we wrote off $0.1 million of these debt issuance costs and reported this expense within debt issuance cost write-off in our Unaudited Condensed Consolidated Statements of Operations for the nine months ended September 30, 2018, which represented the portion of the unamortized debt issuance costs attributable to lenders who are no longer participating in the credit facility subsequent to the amendment. The remaining debt issuance costs associated with the Previous Credit Agreement, along with $1.3 million of debt issuance costs associated with the amended and restated Credit Agreement, are being amortized on a straight-line basis over the three-year term of the Credit Agreement.

All borrowings under the Credit Agreement bear interest, at our option, on a leveraged based grid pricing at (i) a base rate plus a margin of 1.5% to 3.0% per annum (“Base Rate Borrowing”) or (ii) an adjusted LIBOR rate plus a margin of 2.5% to 4.0% per annum (“LIBOR Borrowings”). The applicable margin is determined based on the leverage ratio of the Partnership, as defined in the Credit Agreement. Generally, the interest rate on our borrowings ranged between 4.74% and 5.95% for the nine months ended September 30, 2018 and 3.90% and 4.99% for the nine months ended September 30, 2017. Interest on Base Rate Borrowings is payable monthly. Interest on LIBOR Borrowings is paid upon maturity of the underlying LIBOR contract, but no less often than quarterly. Commitment fees are charged at a rate of 0.50% on any unused credit and are payable quarterly. Interest paid during the three months ended September 30, 2018 and 2017 was $1.1 million and $1.7 million respectively, including commitment fees. Interest paid during the nine months ended September 30, 2018 and 2017 was $4.6 million and $5.0 million, respectively, including commitment fees.

The Credit Agreement contains various customary covenants and restrictive provisions. The Credit Agreement also requires maintenance of certain financial covenants, including a leverage ratio (as defined in the Credit Agreement) of not more than 4.0 to 1.0 and an interest coverage ratio (as defined in the Credit Agreement) of not less than 3.0 to 1.0. At September 30, 2018, our leverage ratio was 3.32 to 1.0 and our interest coverage ratio was 5.24 to 1.0, pursuant to the Credit Agreement. Upon the occurrence and during the continuation of an event of default, subject to the terms and conditions of the Credit Agreement, the lenders may declare any outstanding principal, together with any accrued and unpaid interest, to be immediately due and payable and may exercise the other remedies set forth or referred to in the Credit Agreement. We were in compliance with all debt covenants as of September 30, 2018.

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

Capital Leases

During the third quarter of 2018, our Pipeline and Process Services and Water Services segments leased vehicles for $0.3 million under lease agreements at interest rates of 6.16% that are classified as capital leases. The leased vehicles are amortized on a straight-line basis over the lease terms of four years. Minimum lease payments will be less than $0.1 million in 2018 and $0.1 million for the years ended December 31, 2019 through 2021. The $0.3 million capital lease obligation is reflected in the Unaudited Condensed Consolidated Balance Sheet at September 30, 2018 in accrued payroll and other ($0.1 million) and other non-current liabilities ($0.2 million).

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Income Taxes

9 Months Ended

Sep. 30, 2018

Income Tax Disclosure [Abstract]

Income Taxes

5. Income Taxes

The income tax expense reported in our Unaudited Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2018 and 2017 differs from the statutory tax rate of 21% in 2018 and 35% in 2017 due to the fact that, as a partnership, we are generally not subject to U.S. federal or state income taxes. Our income tax provision relates primarily to (1) our U.S. corporate subsidiaries that provide services to public utility customers, which may not fit within the definition of qualified income as it is defined in the Internal Revenue Code, Regulations, and other guidance, which subjects this income to U.S. federal and state income taxes, (2) our Canadian subsidiary, which is subject to Canadian federal and provincial income taxes, and (3) certain other state income taxes, including the Texas franchise tax.

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Equity

9 Months Ended

Sep. 30, 2018

Equity [Abstract]

Equity

6. Equity

Series A Preferred Units

On May 29, 2018 (the “Closing Date”), we entered into a Series A Preferred Unit Purchase Agreement (the “Preferred Unit Purchase Agreement”) with Stephenson Equity, Co. No. 3 which subsequently assigned the units to Charles C. Stephenson, Jr. (the “Purchaser”), an affiliate of our General Partner, where we issued and sold in a private placement 5,769,231 Series A Preferred Units representing limited partner interests in the Partnership (the “Preferred Units”) to the Purchaser for a cash purchase price of $7.54 per Preferred Unit, resulting in proceeds to the Partnership of $43.5 million. We used proceeds from the transaction to reduce outstanding borrowings on our revolving credit facility. Concurrent with the closing of this transaction, we entered into an amended and restated Credit Agreement dated as of May 29, 2018, to amend and restate the terms of our credit facility, as more fully described in Note 4.

The Preferred Unit Purchase Agreement also provides us with the right to exercise an option at any time during the six months after the Closing Date, to issue and sell to the Purchaser up to $6.5 million of additional Preferred Units. The Preferred Unit Purchase Agreement sets forth the method of determining the purchase price of these additional units, which price would, in turn, determine the number of units to be issued and sold.

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

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

The Purchaser is entitled to receive quarterly distributions that represent an annual return of 9.5% on the Preferred Units. Of this 9.5% annual return, we will be required to pay at least 2.5% in cash and will have the option to pay the remaining 7.0% in kind (in the form of issuing additional preferred units) for the first twelve quarters after the Closing Date.  We intend to pay the first distribution on the Preferred Units of $1.4 million in November 2018 in cash. 

After the third anniversary of the Closing Date, the Purchaser will have the option to convert the Preferred Units into common units on a one-for-one basis. If certain conditions are met after the third anniversary of the Closing Date, we will have the option to cause the Preferred Units to convert to common units. After the third anniversary of the Closing Date, we will also have the option to redeem the Preferred Units. The Partnership may redeem the Preferred Units (a) before November 29, 2018 at a redemption price equal to 100% of the issue price (plus $0.2 million), (b) at any time after the third anniversary of the closing date and on or prior to the fourth anniversary of the closing date at a redemption price equal to 105% of the issue price, and (c) at any time after the fourth anniversary of the closing date at a redemption price equal to 101% of the issue price.

Earnings Per Unit

Our net income (loss) is attributable and allocable to four ownership groups: (1) our preferred unitholder, (2) the noncontrolling interests in certain subsidiaries, (3) our General Partner, and (4) our common unitholders. Income attributable to our preferred unitholder represents the 9.5% annual return to which the owner of the Preferred Units is entitled. Net income (loss) attributable to noncontrolling interests represent 49% of the income (loss) generated by Brown and 51% of the income (loss) generated by CF Inspection. Net loss attributable to the General Partner includes expenses incurred by Holdings and not charged to us. Net income (loss) attributable to common unitholders represents our remaining net income (loss), after consideration of amounts attributable to our preferred unitholder, the noncontrolling interests, and our General Partner. In February 2017, all the then-outstanding subordinated units converted into common units. Since the subordinated units did not share in the distribution of cash generated subsequent to December 31, 2016, we did not allocate any income or loss after that date to the subordinated units.

Basic net income (loss) per common limited partner unit is calculated as net income (loss) attributable to common unitholders divided by the basic weighted average common units outstanding. Diluted net income (loss) per common limited partner unit includes the net income attributable to preferred unitholder and the dilutive effect of the potential conversion of the preferred units and the dilutive effect of the unvested equity compensation. The following summarizes the calculation of the basic net income per common limited partner unit for the three and nine months ended September 30, 2018 and 2017:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
	(in thousands, except per unit data)
Net income attributable to common unitholders	$	3,620	$	1,554	$	7,385	$	178
Weighted average common units outstanding		11,940		11,884		11,924		10,903
Basic net income per common limited partner unit	$	0.30	$	0.13	$	0.62	$	0.02

The following summarizes the calculation of the diluted net income per common limited partner unit for the three and nine months ended September 30, 2018 and 2017:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
	(in thousands, except per unit data)
Net income attributable to common unitholders	$	3,620	$	1,554	$	7,385	$	178
Net income attributable to preferred unitholder		1,045		—		1,412		—
Net income attributable to limited partners	$	4,665	$	1,554	$	8,797	$	178
Weighted average common units outstanding		11,940		11,884		11,924		10,903
Effect of dilutive securities:
Weighted average preferred units outstanding		5,769		—		2,628		—
Long-term incentive plan unvested units		431		111		418		208
Diluted weighted average common units outstanding		18,140		11,995		14,970		11,111
Diluted net income per common limited partner unit	$	0.26	$	0.13	$	0.59	$	0.02

Cash Distributions

The following table summarizes the cash distributions declared and paid to our limited partners since our IPO.

					Total Cash
	Per Unit Cash		Total Cash		Distributions
Payment Date	Distributions		Distributions		to Affiliates (a)
			(in thousands)
Total 2014 Distributions		1.104646		13,064		8,296
Total 2015 Distributions		1.625652		19,232		12,284
Total 2016 Distributions		1.625652		19,258		12,414
February 13, 2017		0.406413		4,823		3,107
May 13, 2017		0.210000		2,495		1,606
August 12, 2017		0.210000		2,495		1,607
November 14, 2017		0.210000		2,497		1,608
Total 2017 Distributions		1.036413		12,310		7,928
February 14, 2018		0.210000		2,498		1,599
May 15, 2018		0.210000		2,506		1,604
August 14, 2018		0.210000		2,506		1,604
November 14, 2018 (b)		0.210000		2,509		1,606
Total 2018 Distributions		0.840000		10,019		6,413
Total Distributions (since IPO)	$	6.232363	$	73,883	$	47,335

(a) Approximately 63.9% of the Partnership’s outstanding common units at September 30, 2018 were held by affiliates.

(b) Third quarter 2018 distribution was declared and will be paid in the fourth quarter of 2018.

In addition, the owner of the Series A Preferred Units is entitled to receive quarterly distributions that represent an annual return of 9.5% on the Preferred Units. Of this 9.5% annual return, we will be required to pay at least 2.5% in cash and will have the option to pay the remaining 7.0% in kind (in the form of issuing additional preferred units) for the first twelve quarters after the Closing Date. We expect to pay the first distribution on the Preferred Units in November 2018 in the amount of $1.4 million in cash.

Equity Compensation

Our General Partner has adopted a long-term incentive plan (“LTIP”) that authorizes the issuance of up to 1,182,600 common units. Certain directors and employees of the Partnership have been awarded Phantom Restricted Units under the terms of the LTIP. The fair value of the awards is determined based on the quoted market value of the publicly-traded common units at each grant date, adjusted for a discount to reflect the fact that distributions are not paid on the restricted units during the vesting period. Compensation expense is recorded on a straight-line basis over the vesting period of each grant. We recorded expense of $0.9 million and $1.1 million during the nine months ended September 30, 2018 and 2017, respectively, related to the unit awards.  We have historically granted annual LTIP awards to key employees in the second quarter of each year.

The following table summarizes the LTIP unit activity for the nine months ended September 30, 2018 and 2017:

	Nine Months Ended September 30,
	2018					2017
				Weighted					Weighted
				Average					Average
				Grant					Grant
	Number			Date Fair		Number			Date Fair
	of Units			Value / Unit		of Units			Value / Unit
Unvested units at January 1		664,509		$	8.46		573,902		$	9.86
Unvested units granted		396,484		$	3.24		249,120		$	7.11
Units vested		(75,222	)	$	13.56		(43,930	)	$	16.56
Unvested units forfeited		(85,092	)	$	7.07		(39,722	)	$	8.51
Unvested units at September 30		900,679		$	5.87		739,370		$	8.61

The majority of the 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. One grant of 29,602 units vests three years from the grant date, contingent upon the recipient meeting certain performance targets. Total unearned compensation associated with the LTIP was $3.2 million at September 30, 2018, and the awards had an average remaining life of 2.31 years.

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Related-Party Transactions

9 Months Ended

Sep. 30, 2018

Related Party Transactions [Abstract]

Related-Party Transactions

7. Related-Party Transactions

Omnibus Agreement and Other Support from Holdings

We are party to an omnibus agreement with Holdings and other related parties. The omnibus agreement governs the following matters, among other things:

● our payment of a quarterly administrative fee in the amount of $1.0 million to Holdings for providing certain partnership overhead services, including certain executive management services by certain officers and employees of our General Partner. This fee also includes the incremental general and administrative expenses we incur as a result of being a publicly-traded partnership. For the nine months ended September 30, 2018 and for the three months ended September 30, 2017, this fee was paid to Holdings in accordance with its terms and conditions. For the six months ended June 30, 2017, Holdings provided sponsor support to the Partnership by waiving payment of the quarterly administrative fee.  The fee will be adjusted each year by an inflation adjustment as outlined in the omnibus agreement.  If any additional modifications to this agreement are proposed, they would require approval by the Conflicts Committee of our Board of Directors.

● our right of first offer on Holdings’ and its subsidiaries’ assets used in, and entities primarily engaged in, providing saltwater disposal and other water and environmental services, and pipeline inspection and integrity services; and

● indemnification of us by Holdings for certain environmental and other 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 affiliates of Holdings control our General Partner, the omnibus agreement will remain in effect, unless we and Holdings agree to terminate it sooner. If affiliates of Holdings cease 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 amend the omnibus agreement; however, amendments will also require the approval of the Conflicts Committee of our Board of Directors. As part of our new Credit Agreement, Holdings agreed to waive the omnibus fee to support us in the event our leverage ratio were to exceed 3.75 times our trailing twelve-month Adjusted EBITDA at any quarter-end during the term of the credit facility.

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 reported as general and administrative expenses in the Unaudited Condensed Consolidated Statement of Operations and as a contribution attributable to general partner in the Unaudited Condensed Consolidated Statement of Owners’ Equity. These costs are included as a component of net loss attributable to general partner in the Unaudited Condensed Consolidated Statements of Operations. Non-cash allocated costs reported in our financial statements were $1.8 million for the nine months ended September 30, 2017. 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 us with additional financial support by contributing $1.0 million for the three months ended September 30, 2017 in cash, as a reimbursement of certain expenditures incurred by us. This payment is reflected as a contribution attributable to general partner in the Unaudited Condensed Consolidated Statement of Owners’ Equity and as a component of the net loss attributable to the general partner in the Unaudited Condensed Consolidated Statements of Operations.  Holdings has not provided any financial support to us in 2018.

Alati Arnegard, LLC

We provide management services to Alati Arnegard, LLC (“Arnegard”), an entity that owns a saltwater disposal facility in North Dakota in which we hold a 25% membership interest. Management fee revenue earned from Arnegard totaled $0.2 million for the three months ended September 30, 2018 and 2017, and $0.5 million for the nine months ended September 30, 2018 and 2017. Accounts receivable from Arnegard were $0.1 million at September 30, 2018 and December 31, 2017, and are included in trade accounts receivable, net in the Unaudited Condensed Consolidated Balance Sheets.

CF Inspection Management, LLC

We have also entered into a joint venture with CF Inspection, a nationally-qualified woman-owned inspection firm affiliated with one of Holdings’ owners. We own 49% of CF Inspection and Cynthia A. Field, the daughter of Charles C. Stephenson, Jr., owns the remaining 51% of CF Inspection. For the nine months ended September 30, 2018, CF Inspection represented approximately 3.4% of our consolidated revenue.  CF Inspection allows us to offer various services to clients that require the services of an approved Women's Business Enterprise ("WBE"), as CF Inspection is certified as a Women's Business Enterprise by the Supplier Clearinghouse in California and as a National Women's Business Enterprise by the Women's Business Enterprise National Council..

Sale of Preferred Equity

As described in Note 6, we issued and sold $43.5 million of preferred equity to an affiliate in May 2018.

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2018

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

8. Commitments and Contingencies

Security Deposits

We have various performance obligations related to our saltwater disposal facilities in North Dakota in our Water Services segment that are secured with short-term security deposits (reflected as restricted cash equivalents on our Unaudited Condensed Consolidated Statements of Cash Flows) of $0.6 million and $0.5 million at September 30, 2018, and December 31, 2017, respectively, included in prepaid expenses and other on the Unaudited Condensed Consolidated Balance Sheets.

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, the MSA’s may provide the customer the right to receive a credit or refund for any overcharges identified. As of September 30, 2018, we have established a reserve of $0.1 million for potential liabilities related to these compliance audit contingencies.  As of December 31, 2017, there were no reserves established for compliance audit contingencies.

Legal Proceedings

On October 5, 2017, a former inspector for TIR LLC and Cypress Energy Management – TIR, LLC (“CEM TIR”) filed a putative collective action lawsuit alleging that TIR LLC, CEM TIR and Cypress Energy Partners – Texas, LLC failed to pay a class of workers overtime in compliance with the Fair Labor Standards Act (“FLSA”) titled James Fithian, et al v. TIR LLC, et al in the United States District Court for the Western District of Texas, Midland Division. The plaintiff subsequently withdrew his action and filed a similar action in Oklahoma State Court, District of Tulsa County. The plaintiff alleges he was a non-exempt employee of TIR LLC 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 the Partnership, TIR LLC, CEM TIR and Cypress Energy Partners – Texas, LLC deny the claims. The defendants plan to continue to vigorously defend these claims and have stayed a counterclaim against the named plaintiff.

On March 28, 2018, the court granted a joint stipulation of dismissal without prejudice in regard to TIR LLC and Cypress Energy Partners – Texas, LLC, as neither of those parties were employers of the plaintiff or the putative class members during the time period that is the subject of the lawsuit. On July 26, 2018, plaintiff filed a motion for conditional class certification. CEM-TIR subsequently filed pleadings opposing the motion. The court set plaintiff’s motion for conditional certification for hearing on November 29, 2018.

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.

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Sale of Salt Water Disposal Facility

9 Months Ended

Sep. 30, 2018

Business Combinations [Abstract]

Sale of Salt Water Disposal Facility

9. Sale of Saltwater Disposal Facilities

In May 2018, we sold our subsidiary Cypress Energy Partners – Orla SWD, LLC (“Orla”), which owns a saltwater disposal facility in Orla, Texas, to an unrelated party for $8.2 million of cash proceeds. The proceeds of this transaction were utilized to reduce our outstanding debt.  We recorded a gain on this transaction of $1.8 million ($0.2 million of this gain was recorded on contingent proceeds that were received and recorded in the third quarter of 2018), which represents the excess of the cash proceeds over the net book value of assets sold. The net book value of the assets sold included $3.0 million of allocated goodwill, calculated based on the estimated fair value of the Orla facility relative to the estimated fair value of the Water Services reporting unit as a whole. This calculation is considered Level 3 and the fair values included in this calculation were determined utilizing estimated discounted cash flows of the Orla facility and the Water Services reporting unit as a whole as of the date of sale.

In January 2018, we sold our subsidiary Cypress Energy Partners – Pecos SWD, LLC (“Pecos”), which owns a saltwater disposal facility in Pecos, Texas, to an unrelated party for $4.0 million of cash proceeds and a royalty interest in the future revenues of the facility. We concluded this represented the sale of a business and we record the royalties in the periods in which they are received. We recorded a gain on this transaction of $1.8 million, which represents the excess of the cash proceeds over the net book value of assets sold. The proceeds were used to reduce our debt.  The net book value of the assets sold included $2.0 million of allocated goodwill, calculated based on the estimated fair value of the Pecos facility relative to the estimated fair value of the Water Services reporting unit as a whole.  This calculation is considered Level 3 and the fair values included in this calculation were determined utilizing estimated discounted cash flows of the Pecos facility and the Water Services reporting unit as a whole as of the date of sale.  Assets held for sale and liabilities held for sale on the Unaudited Condensed Consolidated Balance Sheet at December 31, 2017 represent the carrying values of the Pecos saltwater facility prior to its sale.

During the three months ended September 30, 2018, we received proceeds of $0.4 million from the settlement of litigation related to lightning strikes that occurred in 2017 at our facilities in Orla, Texas and Grassy Butte, North Dakota. This litigation related to the non-performance of certain lightning protection equipment we had purchased to protect the facilities against lightning strikes. The proceeds from these settlements are reported within gain on assets disposals, net in our Unaudited Condensed Consolidated Statements of Operations.

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Reportable Segments

9 Months Ended

Sep. 30, 2018

Segment Reporting [Abstract]

Reportable Segments

10.  Reportable Segments

Our operations consist of three reportable segments: (i) Pipeline Inspection, (ii) Pipeline & Process Services, and (iii) Water Services.

Pipeline Inspection – We generate revenue in this segment primarily by providing essential inspection and integrity services on a variety of infrastructure assets including midstream pipelines, gathering systems, and distribution systems.  Services include non-destructive examination, mechanical integrity, inline support, PIG tracking, survey, data gathering and supervision of third-party contractors. Our results in this segment are driven primarily by the number of inspectors that perform services for our customers and the fees that we charge for those services, which depend on the type, skills, technology, equipment, and number of inspectors used on a particular project, the nature of the project, and the duration of the project. The number of inspectors engaged on projects is driven by the type of project, prevailing market rates, the age and condition of customers’ assets including pipelines, gas plants, compression stations, storage facilities, and gathering and distribution systems including the legal and regulatory requirements relating to the inspection and maintenance of those assets. Our customers are also billed for per diem charges, mileage, and other reimbursement items. Revenue and costs in this segment may be subject to seasonal variations and interim activity may not be indicative of yearly activity, considering many of our customers develop yearly operating budgets and enter into contracts with us during the winter season for work to be performed during the remainder of the year.  Additionally, inspection work throughout the United States during the winter months (especially in the northern states) may be hampered or delayed due to inclement weather, thus affecting our revenue and costs.  During the three months ended September 30, 2018, we recognized $0.5 million of revenue on services performed in previous years. We had constrained recognition of this revenue until the expiration of a contract provision that had given the customer the opportunity to reopen negotiation of the fee paid for the services. As of September 30, 2018, we have recognized a refund liability of $0.2 million for revenue associated with such variable consideration.

Pipeline & Process Services – This segment provides essential midstream services including hydrostatic testing services and chemical cleaning to energy companies and pipeline construction companies of newly-constructed and existing pipelines and related infrastructure. We generally charge our customers in this segment on a fixed-bid basis, depending on the size and length of the pipeline being tested, the complexity of services provided, and the utilization of our work force and equipment. Our results in this segment are driven primarily by the number of field personnel that perform services for our customers and the fees that we charge for those services, which depend on the type and number of field personnel used on a particular project, the type of equipment used and the fees charged for the utilization of that equipment, and the nature and duration of the project.  Revenue during the nine months ended September 30, 2018 included $0.3 million associated with additional billings on a project that we completed in the fourth quarter of 2017 (we recognized the revenue upon receipt of customer acknowledgment of the additional fees).

Water Services – This segment owns and operates nine (9) Environmental Protection Agency Class II saltwater disposal facilities in the Williston Basin region of North Dakota.  Eight (8) of the facilities are wholly-owned and we have ten (10) pipelines from multiple E&P customers connected to these saltwater disposal facilities, including two (2) that were developed and are owned by the Partnership.  Approximately 95% of our disposal water is produced water that is generated during production life of an oil and gas well and approximately 41% of our water is delivered via pipeline to our saltwater disposal facilities.  We currently serve in excess of 75 customers.  Our saltwater disposal facilities provide essential midstream services to oil and natural gas upstream producers and their transportation companies. All of the saltwater disposal facilities utilize specialized equipment and remote monitoring to minimize the facilities’ downtime and increase the facilities’ efficiency for peak utilization. These facilities also utilize oil skimming and recovery processes that remove residual oil from water delivered to our saltwater disposal facilities via pipeline or truck. We sell the oil recovered from these skimming processes, which contributes to our revenues. In addition to these saltwater disposal facilities, we provide management and staffing services to a saltwater disposal facility in which we own a 25% ownership interest.  Segment results are driven primarily by the volumes of water we inject into our saltwater disposal facilities and the fees we charge for transporting water in our two pipelines connected to these facilities. These fees are charged on a per-barrel basis and vary based on the quantity and type of saltwater disposed, competitive dynamics, and operating costs. In addition, for minimal marginal cost, we generate revenue by selling residual oil we recover from the disposed water. Revenue and costs in this segment may be subject to seasonal fluctuations and interim activity may not be indicative of yearly activity, given that our saltwater disposal facilities are located in North Dakota and weather conditions there (especially winter weather conditions) can affect drilling, operations, and trucking activity, and ultimately, our volumes, revenues, and costs.

Other – These amounts represent general and administrative expenses not specifically allocable to our reportable segments.

The following tables show operating income (loss) by reportable segment and a reconciliation of segment operating income (loss) to net income (loss) before income tax expense.

	Pipeline			Pipeline &			Water
	Inspection			Process Services			Services			Other			Total
Three months ended September 30, 2018
Revenue	$	77,606		$	3,881		$	3,325		$	(34	)	$	84,778
Costs of services		68,350			2,592			962			(34	)		71,870
Gross margin		9,256			1,289			2,363			—			12,908
General and administrative		4,422			592			774			276			6,064
Depreciation, amortization and accretion		571			143			410			—			1,124
(Gain) loss on asset disposal, net		(21	)		(32	)		(769	)		—			(822	)
Operating income (loss)	$	4,284		$	586		$	1,948		$	(276	)		6,542
Interest expense, net														(1,283	)
Foreign currency gains														97
Other, net														95
Net income before income tax expense													$	5,451
Three months ended September 30, 2017
Revenue	$	72,737		$	2,834		$	2,111		$	—		$	77,682
Costs of services		65,323			2,132			837			—			68,292
Gross margin		7,414			702			1,274			—			9,390
General and administrative		3,893			525			858			298			5,574
Depreciation, amortization and accretion		577			157			450			—			1,184
Losses on asset disposals, net		—			—			208			—			208
Operating income (loss)	$	2,944		$	20		$	(242	)	$	(298	)		2,424
Interest expense, net														(1,907	)
Foreign currency gains														557
Other, net														17
Net income before income tax expense													$	1,091

	Pipeline			Pipeline &			Water
	Inspection			Process Services			Services			Other			Total
Nine months ended September 30, 2018
Revenue	$	205,938		$	11,307		$	8,861		$	(34	)	$	226,072
Costs of services		183,305			7,840			2,981			(34	)		194,092
Gross margin		22,633			3,467			5,880			—			31,980
General and administrative		12,313	(a)		1,715			2,402	(b)		911			17,341
Depreciation, amortization and accretion		1,717			449			1,202			—			3,368
Gains on asset disposals, net		(21	)		(77	)		(4,039	)		—			(4,137	)
Operating income (loss)	$	8,624		$	1,380		$	6,315		$	(911	)		15,408
Interest expense, net														(4,907	)
Debt issuance cost write-off														(114	)
Foreign currency losses														(354	)
Other, net														302
Net income before income tax expense													$	10,335
Nine months ended September 30, 2017
Revenue	$	205,039		$	5,927		$	6,005		$	—		$	216,971
Costs of services		185,308			5,005			2,330			—			192,643
Gross margin		19,731			922			3,675			—			24,328
General and administrative		10,212	(c)		1,488			1,651	(d)		2,662	(e)		16,013
Depreciation, amortization and accretion		1,755			471			1,335			—			3,561
Impairments		1,329			1,581			688			—			3,598
Losses on asset disposal, net		18			—			77			—			95
Operating income (loss)	$	6,417		$	(2,618	)	$	(76	)	$	(2,662	)		1,061
Interest expense, net														(5,411	)
Foreign currency gains														824
Other, net														122
Net loss before income tax expense													$	(3,404	)
Total Assets
September 30, 2018	$	116,510		$	9,365		$	24,939		$	1,461		$	152,275
December 31, 2017 (recast to exclude intercompany receivables)	$	120,368		$	10,481		$	31,472		$	882		$	163,203

(a)	Amount includes $2.1 million of the allocated quarterly administrative fee charged by Holdings specified in the omnibus agreement.
(b)	Amount includes $0.9 million of the allocated quarterly administrative fee charged by Holdings specified in the omnibus agreement.
(c)	Amount includes $0.7 million of the allocated quarterly administrative fee charged by Holdings specified in the omnibus agreement.
(d)	Amount includes $0.3 million of the allocated quarterly administrative fee charged by Holdings specified in the omnibus agreement.
(e)	Amount includes $1.8 million of allocated general and administrative expenses incurred by Holdings but not charged to us. For the six months ended June 30, 2017, Holdings waived the administrative fee specified in the omnibus agreement.

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Basis of Presentation and Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2018

Accounting Policies [Abstract]

Basis of Presentation

Basis of Presentation

The Unaudited Condensed Consolidated Financial Statements as of and for the three months ended September 30, 2018 and 2017 and for the nine months ended September 30, 2018 and 2017 include our accounts and those of our controlled subsidiaries. Investments over which we exercise significant influence, but do not control, are accounted for using the equity method of accounting. All significant intercompany transactions and account balances have been eliminated in consolidation. The Unaudited Condensed Consolidated Balance Sheet at December 31, 2017 is derived from our audited financial statements.

The accompanying Unaudited Condensed Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim consolidated financial information and in accordance with the rules and regulations of the Securities and Exchange Commission (the “SEC”). The Unaudited Condensed Consolidated Financial Statements include all adjustments considered necessary for a fair presentation of the consolidated financial position and consolidated results of operations for the interim periods presented. Such adjustments consist only of normal recurring items, unless otherwise disclosed herein. Accordingly, the Unaudited Condensed Consolidated Financial Statements do not include all of the information and notes required by GAAP for complete consolidated financial statements. However, we believe that the disclosures made are adequate to make the information not misleading. These interim Unaudited Condensed Consolidated Financial Statements should be read in conjunction with our audited financial statements as of and for the year ended December 31, 2017 included in our Form 10-K. The results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

Use of Estimates in the Preparation of Financial Statements

Use of Estimates in the Preparation of Financial Statements

The preparation of our Unaudited Condensed Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in these financial statements and accompanying notes. Actual results could differ from those estimates.

Significant Accounting Policies

Significant Accounting Policies

Our significant accounting policies are consistent with those disclosed in Note 2 to our audited financial statements as of and for the year ended December 31, 2017 included in our Form 10-K, except for the adoption of Accounting Standards Update (“ASU”) 2014-09 - Revenue from Contracts with Customers and ASU 2016-18 - Statement of Cash Flows - Restricted Cash on January 1, 2018. Under ASU 2014-09, an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Based on this new accounting guidance, our revenue is earned and recognized through the service offerings of our three reportable business segments. Our sales contracts have terms of less than one year. As such, we have used the practical expedient contained within the accounting guidance which exempts us from the requirement to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract with an original expected duration of one year or less. See Note 10 for disaggregated revenue reported by segment. The adoption and application of this ASU had no effect on our Unaudited Condensed Consolidated Financial Statements, other than additional disclosures included in this Form 10-Q. Under ASU 2016-18, an entity is required to show changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents in the statement of cash flows. The adoption and application of this ASU has modified the presentation of cash, cash equivalents, restricted cash, and restricted cash equivalents on our Unaudited Condensed Consolidated Statements of Cash Flows applied on a retrospective basis.

Accounts Receivable and Allowance for Bad Debts

Accounts Receivable and Allowance for Bad Debts

We grant unsecured credit to customers under normal industry standards and terms, and have established policies and procedures that allow for an evaluation of each of our customer’s creditworthiness. We typically receive payment from our customers 45 to 90 days after the services have been performed. The Partnership determines allowances for bad debts based on management’s assessment of the creditworthiness of our customers. Trade receivables are written off against the allowance when deemed uncollectible. Recoveries of trade receivables previously written off are recorded when cash is received. In the first quarter of 2017, we received $0.3 million on accounts receivable previously reserved, which we recorded as a reduction to general and administrative expense in our Unaudited Condensed Consolidated Statements of Operations.

Income Taxes

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, a subsidiary of our Pipeline Inspection segment that performs pipeline inspection services for utility customers, and Brown Integrity – PUC, LLC, a subsidiary in which we own a 51% membership interest, 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 tax. The amounts recognized as income tax expense (benefit), income taxes payable, and deferred tax assets / liabilities in our Unaudited Condensed Consolidated Financial Statements include the Canadian income taxes and U.S. federal and state income taxes referred to above, as well as partnership-level taxes levied by various states, which primarily include franchise taxes assessed by the state of Texas.

As a publicly-traded partnership, we are subject to a statutory requirement that 90% of our total gross income represent “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations, and Internal Revenue Service pronouncements), determined on a calendar-year basis. 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 each year since our initial public offering (“IPO”).

Noncontrolling Interest

Noncontrolling Interest

We own a 51% interest in Brown Integrity, LLC (“Brown”) and a 49% interest in CF Inspection Management, LLC (“CF Inspection”). The accounts of these subsidiaries are included in our Unaudited Condensed Consolidated Financial Statements. The portion of the net income (loss) of these entities that is attributable to outside owners is reported as net income (loss) attributable to noncontrolling interests in our Unaudited Condensed Consolidated Statements of Operations, and the portion of the net assets of these entities that is attributable to outside owners is reported as noncontrolling interests in our Unaudited Condensed Consolidated Balance Sheets.

Property and Equipment

Property and Equipment

Property and equipment consists of land, land and leasehold improvements, buildings, facilities, wells and related equipment, computer and office equipment, and vehicles. We record property and equipment at cost. Costs of 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 or disposition 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 Unaudited Condensed Consolidated Statements of Operations.

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 exceeds the future undiscounted cash flows expected from the asset, we recognize an impairment charge for the excess of the carrying value of the asset over its estimated fair value. Determinations as to whether and how much an asset is impaired involve 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.

Identifiable Intangible Assets

Identifiable Intangible Assets

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

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 values of the assets to their fair values and record a corresponding impairment loss.

Goodwill

Goodwill

Goodwill is not amortized, but is subject to an annual review for impairment on November 1 (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 used to evaluate and measure goodwill for impairment are determined primarily from the manner in which the business that relates to the applicable goodwill is managed or operated. We have determined that our Pipeline Inspection, Pipeline & Process Services, and Water Services segments are the appropriate reporting units for testing goodwill impairment.

To perform a goodwill impairment assessment, we perform an analysis to assess whether it is more likely than not that the fair value of the reporting unit exceeds its carrying value. If we determine that it is more likely than not that the carrying value of the reporting unit exceeds its fair value, we reduce the carrying value of goodwill and record a corresponding impairment expense.

Accrued Payroll and Other

Accrued Payroll and Other

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

	September 30, 2018		December 31, 2017
	(in thousands)
Accrued payroll	$	11,148	$	6,893
Customer deposits		1,893		1,510
Other		1,091		706
	$	14,132	$	9,109

Foreign Currency Translation

Foreign Currency Translation

Our Unaudited Condensed 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 in which the applicable revenues and expenses were recorded.

Our Unaudited Condensed Consolidated Balance Sheet at September 30, 2018 includes $2.6 million of accumulated other comprehensive loss associated with accumulated currency translation adjustments, all of which relate to our Canadian operations. If at some point in the future we were to 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 Unaudited Condensed Consolidated Statement of Operations as a reduction to net income.

Our Canadian subsidiary has certain intercompany payables to our U.S.-based subsidiaries. These intercompany payables and receivables among our consolidated subsidiaries are eliminated in our Unaudited Condensed Consolidated Balance Sheets. Beginning April 1, 2017, we report currency translation adjustments on these intercompany payables and receivables within foreign currency gains (losses) in our Unaudited Condensed Consolidated Statements of Operations, with offsetting amounts reported within other comprehensive income (loss) in our Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss).

New Accounting Standards

New Accounting Standards

On January 1, 2018, we adopted the following new accounting standards issued by the Financial Accounting Standards Board (“FASB”);

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

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

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

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

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

In July 2018, the FASB issued ASU 2018-11 – Targeted Improvements which provides entities with a transition option to not restate the comparative periods for the effects of applying the new leasing standard (i.e. comparative periods presented in the Unaudited Condensed Consolidated Financial Statements will continue to be in accordance with Accounting Standards Codification 840).  We will adopt the new standard on the effective date of January 1, 2019 and expect to use a modified retrospective approach as permitted under ASU 2018-11.  We continue to evaluate the impact this ASU will have on our Unaudited Condensed Consolidated Balance Sheets related to the addition of the right-of-use asset and associated lease liability.  We expect the effects of implementing ASU 2016-02 will be material to our Unaudited Condensed Consolidated Balance Sheets and related disclosures, but immaterial to our Unaudited Condensed Consolidated Statements of Operations and Unaudited Condensed Consolidated Statements of Cash Flows. Liabilities recorded as a result of this standard will be excluded from the definition of indebtedness under our credit facility and therefore, will not adversely impact the leverage ratio under our credit facility.

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Basis of Presentation and Summary of Significant Accounting Policies (Tables)

9 Months Ended

Sep. 30, 2018

Accounting Policies [Abstract]

Schedule of accrued payroll and other

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

	September 30, 2018		December 31, 2017
	(in thousands)
Accrued payroll	$	11,148	$	6,893
Customer deposits		1,893		1,510
Other		1,091		706
	$	14,132	$	9,109

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Equity (Tables)

9 Months Ended

Sep. 30, 2018

Equity [Abstract]

Schedule of the calculation of the basic net income (loss) per common limited partner unit

The following summarizes the calculation of the basic net income per common limited partner unit for the three and nine months ended September 30, 2018 and 2017:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
	(in thousands, except per unit data)
Net income attributable to common unitholders	$	3,620	$	1,554	$	7,385	$	178
Weighted average common units outstanding		11,940		11,884		11,924		10,903
Basic net income per common limited partner unit	$	0.30	$	0.13	$	0.62	$	0.02

Schedule of the calculation of the diluted net income (loss) per common limited partner unit

The following summarizes the calculation of the diluted net income per common limited partner unit for the three and nine months ended September 30, 2018 and 2017:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
	(in thousands, except per unit data)
Net income attributable to common unitholders	$	3,620	$	1,554	$	7,385	$	178
Net income attributable to preferred unitholder		1,045		—		1,412		—
Net income attributable to limited partners	$	4,665	$	1,554	$	8,797	$	178
Weighted average common units outstanding		11,940		11,884		11,924		10,903
Effect of dilutive securities:
Weighted average preferred units outstanding		5,769		—		2,628		—
Long-term incentive plan unvested units		431		111		418		208
Diluted weighted average common units outstanding		18,140		11,995		14,970		11,111
Diluted net income per common limited partner unit	$	0.26	$	0.13	$	0.59	$	0.02

Schedule of cash distributions declared and paid to our limited partners since our IPO

The following table summarizes the cash distributions declared and paid to our limited partners since our IPO.

					Total Cash
	Per Unit Cash		Total Cash		Distributions
Payment Date	Distributions		Distributions		to Affiliates (a)
			(in thousands)
Total 2014 Distributions		1.104646		13,064		8,296
Total 2015 Distributions		1.625652		19,232		12,284
Total 2016 Distributions		1.625652		19,258		12,414
February 13, 2017		0.406413		4,823		3,107
May 13, 2017		0.210000		2,495		1,606
August 12, 2017		0.210000		2,495		1,607
November 14, 2017		0.210000		2,497		1,608
Total 2017 Distributions		1.036413		12,310		7,928
February 14, 2018		0.210000		2,498		1,599
May 15, 2018		0.210000		2,506		1,604
August 14, 2018		0.210000		2,506		1,604
November 14, 2018 (b)		0.210000		2,509		1,606
Total 2018 Distributions		0.840000		10,019		6,413
Total Distributions (since IPO)	$	6.232363	$	73,883	$	47,335

(a) Approximately 63.9% of the Partnership’s outstanding common units at September 30, 2018 were held by affiliates.

(b) Third quarter 2018 distribution was declared and will be paid in the fourth quarter of 2018.

Schedule of the LTIP Unit activity

The following table summarizes the LTIP unit activity for the nine months ended September 30, 2018 and 2017:

	Nine Months Ended September 30,
	2018					2017
				Weighted					Weighted
				Average					Average
				Grant					Grant
	Number			Date Fair		Number			Date Fair
	of Units			Value / Unit		of Units			Value / Unit
Unvested units at January 1		664,509		$	8.46		573,902		$	9.86
Unvested units granted		396,484		$	3.24		249,120		$	7.11
Units vested		(75,222	)	$	13.56		(43,930	)	$	16.56
Unvested units forfeited		(85,092	)	$	7.07		(39,722	)	$	8.51
Unvested units at September 30		900,679		$	5.87		739,370		$	8.61

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Reportable Segments (Tables)

9 Months Ended

Sep. 30, 2018

Segment Reporting [Abstract]

Schedule of operating income (loss) by reportable segment and a reconciliation of segment operating income (loss) to net income (loss)

The following tables show operating income (loss) by reportable segment and a reconciliation of segment operating income (loss) to net income (loss) before income tax expense.

	Pipeline			Pipeline &			Water
	Inspection			Process Services			Services			Other			Total
Three months ended September 30, 2018
Revenue	$	77,606		$	3,881		$	3,325		$	(34	)	$	84,778
Costs of services		68,350			2,592			962			(34	)		71,870
Gross margin		9,256			1,289			2,363			—			12,908
General and administrative		4,422			592			774			276			6,064
Depreciation, amortization and accretion		571			143			410			—			1,124
(Gain) loss on asset disposal, net		(21	)		(32	)		(769	)		—			(822	)
Operating income (loss)	$	4,284		$	586		$	1,948		$	(276	)		6,542
Interest expense, net														(1,283	)
Foreign currency gains														97
Other, net														95
Net income before income tax expense													$	5,451
Three months ended September 30, 2017
Revenue	$	72,737		$	2,834		$	2,111		$	—		$	77,682
Costs of services		65,323			2,132			837			—			68,292
Gross margin		7,414			702			1,274			—			9,390
General and administrative		3,893			525			858			298			5,574
Depreciation, amortization and accretion		577			157			450			—			1,184
Losses on asset disposals, net		—			—			208			—			208
Operating income (loss)	$	2,944		$	20		$	(242	)	$	(298	)		2,424
Interest expense, net														(1,907	)
Foreign currency gains														557
Other, net														17
Net income before income tax expense													$	1,091

	Pipeline			Pipeline &			Water
	Inspection			Process Services			Services			Other			Total
Nine months ended September 30, 2018
Revenue	$	205,938		$	11,307		$	8,861		$	(34	)	$	226,072
Costs of services		183,305			7,840			2,981			(34	)		194,092
Gross margin		22,633			3,467			5,880			—			31,980
General and administrative		12,313	(a)		1,715			2,402	(b)		911			17,341
Depreciation, amortization and accretion		1,717			449			1,202			—			3,368
Gains on asset disposals, net		(21	)		(77	)		(4,039	)		—			(4,137	)
Operating income (loss)	$	8,624		$	1,380		$	6,315		$	(911	)		15,408
Interest expense, net														(4,907	)
Debt issuance cost write-off														(114	)
Foreign currency losses														(354	)
Other, net														302
Net income before income tax expense													$	10,335
Nine months ended September 30, 2017
Revenue	$	205,039		$	5,927		$	6,005		$	—		$	216,971
Costs of services		185,308			5,005			2,330			—			192,643
Gross margin		19,731			922			3,675			—			24,328
General and administrative		10,212	(c)		1,488			1,651	(d)		2,662	(e)		16,013
Depreciation, amortization and accretion		1,755			471			1,335			—			3,561
Impairments		1,329			1,581			688			—			3,598
Losses on asset disposal, net		18			—			77			—			95
Operating income (loss)	$	6,417		$	(2,618	)	$	(76	)	$	(2,662	)		1,061
Interest expense, net														(5,411	)
Foreign currency gains														824
Other, net														122
Net loss before income tax expense													$	(3,404	)
Total Assets
September 30, 2018	$	116,510		$	9,365		$	24,939		$	1,461		$	152,275
December 31, 2017 (recast to exclude intercompany receivables)	$	120,368		$	10,481		$	31,472		$	882		$	163,203

(a)	Amount includes $2.1 million of the allocated quarterly administrative fee charged by Holdings specified in the omnibus agreement.
(b)	Amount includes $0.9 million of the allocated quarterly administrative fee charged by Holdings specified in the omnibus agreement.
(c)	Amount includes $0.7 million of the allocated quarterly administrative fee charged by Holdings specified in the omnibus agreement.
(d)	Amount includes $0.3 million of the allocated quarterly administrative fee charged by Holdings specified in the omnibus agreement.
(e)	Amount includes $1.8 million of allocated general and administrative expenses incurred by Holdings but not charged to us. For the six months ended June 30, 2017, Holdings waived the administrative fee specified in the omnibus agreement.

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Organization and Operations (Details Narrative) - N	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018
Equity interest salt water disposal facility	25.00%		25.00%
Water Services [Member]
Number of saltwater disposal facilities	8	10	9
Number of wholly-owned facilities			8
Number of pipelines connected to E&P customers to saltwater disposal facilities			10
Number of saltwater disposal facilities developed and owned by partnership			2
Produced water from disposal water (percent)			95.00%
Pipeline water delivered to saltwater disposal facilities (percent)			41.00%
Water Services [Member] | Minimum [Member]
Number of customers			75

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Basis of Presentation and Summary of Significant Accounting Policies (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Accounting Policies [Abstract]
Accrued payroll	$ 11,148	$ 6,893
Customer deposits	1,893	1,510
Other	1,091	706
Total	$ 14,132	$ 9,109

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Basis of Presentation and Summary of Significant Accounting Policies (Details Narrative) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2018	Dec. 31, 2017
Threshold for nontaxation	90.00%
Accumulated other comprehensive loss	$ (2,616)	$ (2,677)
Accounts receivable previously reserved	$ 300
Minimum [Member]
Finite-lived intangible asset, useful life	5 years
Maximum [Member]
Finite-lived intangible asset, useful life	20 years
Pipeline Inspection [Member] | Brown Integrity - PUC, LLC [Member]
Subsidiary ownership interest	51.00%
Brown Integrity, LLC [Member]
Subsidiary ownership interest	51.00%
CF Inspection Management, LLC [Member]
Subsidiary ownership interest	49.00%

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Impairments (Details Narrative) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Sep. 30, 2018	Dec. 31, 2017	Jun. 30, 2017
Impairment of intangible assets	$ 1,300
Property, plant and equipment, net		$ 13,028	$ 13,388
Salt Water Disposal Facilities - PPE [Member]
Impairment of property, plant and equipment	700
Property, plant and equipment, net				$ 100
Pipeline Inspection [Member] | Customer Relationships [Member]
Impairment of intangible assets	1,100
Pipeline Inspection [Member] | Trade Names [Member]
Impairment of intangible assets	200
Pipeline And Process Services [Member]
Impairment of goodwill	$ 1,600
Pipeline And Process Services [Member] | Fair Value, Inputs, Level 3 [Member]
Annual growth rate	2.00%
Discount rate	18.00%

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Debt (Details Narrative) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Dec. 31, 2017 USD ($)
Long-term debt	$ 76,129		$ 76,129
Debt issuance costs, net	1,391		1,391
Long-term debt					$ 136,900
Debt issuance costs					600
Debt issuance cost write-off			$ 114
Debt amortized period			3 years
Accrued payroll and other	14,132		$ 14,132		9,109
Other non-current liabilities	369		369		$ 143
Amended and Restated Credit Agreement [Member]
Line of credit facility, maximum borrowing capacity	90,000		90,000
Debt issuance costs	1,300		1,300
Total borrowing capacity	$ 110,000		$ 110,000
Line of credit facility, commitment fee percentage			0.50%
Debt covenant total adjusted leverage ratio maximum			4.0
Debt covenant interest coverage ratio minimum			3.0
Total adjusted leverage ratio	3.38		3.38
Interest coverage ratio	5.24		5.24
Credit agreement minimum unused capacity at time of distributions	$ 5,000		$ 5,000
Accrued payroll and other	100		100
Other non-current liabilities	200		200
Line of Credit [Member]
Interest expense including commitment fee	$ 1,100	$ 1,700	$ 4,600	$ 5,000
Maximum [Member] | Base Rate [Member]
Spread on variable rate borrowings			3.00%
Maximum [Member] | LIBOR [Member]
Spread on variable rate borrowings			4.00%
Maximum [Member] | Line of Credit [Member]
Debt instrument, interest rate, effective percentage during period			5.95%	4.99%
Minimum [Member] | Base Rate [Member]
Spread on variable rate borrowings			1.50%
Minimum [Member] | LIBOR [Member]
Spread on variable rate borrowings			2.50%
Minimum [Member] | Line of Credit [Member]
Debt instrument, interest rate, effective percentage during period			4.74%	3.90%
Capital Lease Obligations [Member]
Interest rate of capital lease	6.16%		6.16%
Minimum lease payments December 31, 2019 through 2021	$ 100		$ 100
Capital Lease Obligations [Member] | Vehicles [Member]
Capital lease incurred	$ 300
Amortization period	4 years
Capital Lease Obligations [Member] | Maximum [Member]
Minimum lease payments 2018	$ 100		100
Capital Lease Obligations [Member] | Other Non-current Liabilities [Member]
Accrued payroll and other	200		200
Capital Lease Obligations [Member] | Accrued Payroll and Other [Member]
Capital lease obligation	$ 100		$ 100

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Income Taxes (Details Narrative)	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Income Tax Disclosure [Abstract]
Statutory tax rate	21.00%	35.00%	21.00%	35.00%

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Equity (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Equity [Abstract]
Net income attributable to common unitholders	$ 3,620	$ 1,554	$ 7,385	$ 178
Weighted average common units outstanding	11,940,032	11,884,196	11,924,183	10,902,838
Basic net income per common limited partner unit	$ 0.30	$ 0.13	$ 0.62	$ 0.02

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Equity (Details 1) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Equity [Abstract]
Net income attributable to common unitholders	$ 3,620	$ 1,554	$ 7,385	$ 178
Net income attributable to preferred unitholder	1,045		1,412
Net income attributable to limited partners	$ 4,665	$ 1,554	$ 8,797	$ 178
Weighted average common units outstanding	11,940,032	11,884,196	11,924,183	10,902,838
Effect of dilutive securities
Weighted average preferred units outstanding	5,769,000		2,628,000
Long-term incentive plan unvested units	431,000	111,000	418,000	208,000
Diluted weighted average common units outstanding	18,140,691	11,994,881	14,970,334	11,111,454
Diluted net income per common limited partner unit	$ 0.26	$ 0.13	$ 0.59	$ 0.02

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Equity (Details 2) - USD ($) $ / shares in Units, $ in Thousands																	10 Months Ended		12 Months Ended								55 Months Ended
	Nov. 14, 2018		Aug. 14, 2018		May 15, 2018		Feb. 14, 2018		Nov. 14, 2017		Aug. 12, 2017		May 13, 2017		Feb. 13, 2017		Nov. 14, 2018		Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014		Nov. 14, 2018
Per Unit Cash Distribution (in dollars per share)	$ 0.210000		$ 0.210000		$ 0.210000		$ 0.210000		$ 0.210000		$ 0.210000		$ 0.210000		$ 0.406413		$ 0.840000		$ 1.036413		$ 1.625652		$ 1.625652		$ 1.104646		$ 6.232363
Total Cash Distribution	$ 2,509	[1]	$ 2,506		$ 2,506		$ 2,498		$ 2,497		$ 2,495		$ 2,495	[2]	$ 4,823		$ 10,019		$ 12,310		$ 19,258		$ 19,232		$ 13,064		$ 73,883
Affiliated Entity [Member]
Total Cash Distribution	$ 1,606	[1]	$ 1,604	[2]	$ 1,604	[2]	$ 1,599	[2],[3]	$ 1,608	[2]	$ 1,607	[2]	$ 1,606	[1],[2]	$ 3,107	[2]	$ 6,413	[2]	$ 7,928	[2]	$ 12,414	[2]	$ 12,284	[2]	$ 8,296	[2]	$ 47,335	[2]

[1] Third quarter 2018 distribution was declared and will be paid in the fourth quarter of 2018.

[2] Approximately 63.9% of the Partnership's outstanding units at June 30, 2018 were held by affiliates.

[3] First quarter 2018 distribution was declared and will be paid in the second quarter of 2018.

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Equity (Details 3) - $ / shares	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Unvested units at beginning	664,509	573,902
Unvested units granted	396,484	249,120
Units vested	(75,222)	(43,930)
Unvested units forfeited	(85,092)	(39,722)
Unvested units at ending	900,679	739,370
Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]
Unvested units at beginning	$ 8.46	$ 9.86
Unvested units granted	3.24	7.11
Units vested	13.56	16.56
Unvested units forfeited	7.07	8.51
Unvested units at ending	$ 5.87	$ 8.61

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Equity (Details Narrative) - USD ($) $ / shares in Units, $ in Thousands		9 Months Ended
	May 29, 2018	Sep. 30, 2018	Sep. 30, 2017	Nov. 01, 2018
Share-based compensation expense		$ 908	$ 1,136
Percentage of partnership units held by affiliates		63.90%
Brown Integrity, LLC [Member]
Percentage of income attributable to noncontrolling interests		49.00%
CF Inspection Management, LLC [Member]
Percentage of income attributable to noncontrolling interests		51.00%
Long Term Incentive Plan [Member]
Shares authorized under plan		1,182,600
Share-based compensation expense		$ 900	$ 1,100
Number of units which have specific performance vesting terms		29,602
Compensation cost not yet recognized		$ 3,300
Period for recognition of compensation cost		2 years 3 months 22 days
Long Term Incentive Plan [Member] | Tranche One [Member]
Percentage of awards vesting		33.33%
Vesting period		3 years
Long Term Incentive Plan [Member] | Tranche Two [Member]
Percentage of awards vesting		33.33%
Vesting period		4 years
Long Term Incentive Plan [Member] | Tranche Three [Member]
Percentage of awards vesting		33.33%
Vesting period		5 years
Preferred Units [Member]
Annual rate of return of Preferred Units (percent)		9.50%
Dividend distribution to be paid in cash (percent)		2.50%
Dividend distribution to be paid in kind (percent)		7.00%
Preferred Units [Member] | Private Placement [Member]
Number of units issued and sold in a private placement	5,769,231
Price per unit (in dollars per unit)	$ 7.54
Proceeds of units sold in a private placement	$ 43,500
Value of additional preferred units per right to exercise an option	$ 6,500
Preferred Units [Member] | Private Placement [Member] | Redemption Period Third [Member]
Redemption price as percent of issue price	101.00%
Preferred Units [Member] | Private Placement [Member] | Redemption Period Two [Member]
Redemption price as percent of issue price	105.00%
Preferred Units [Member] | Private Placement [Member] | Redemption Period One [Member]
Redemption price as percent of issue price	100.00%
Additional amount in redemption of preferred units	$ 200
Subsequent Event [Member] | Preferred Units [Member]
Distributions payable				$ 1,400

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Related-Party Transactions (Details Narrative) $ in Thousands		1 Months Ended	3 Months Ended		9 Months Ended
	May 29, 2018 USD ($)	May 31, 2018 USD ($)	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Dec. 31, 2017 USD ($)
Alati Arnegard LLC [Member]
Subsidiary ownership interest					25.00%
Management fee revenue from related parties			$ 200	$ 200	$ 500	$ 500
Accounts receivable from related parties			100		100		$ 100
General Partner [Member] | Omnibus Agreement [Member]
Quarterly administrative fee			$ 1,000		$ 1,000
Non-cash allocated costs						$ 1,800
General Partner [Member] | Omnibus Agreement [Member] | Minimum [Member]
Line of credit borrowing capacity - multiple of Adjusted EBITDA			3.75		3.75
Preferred Units [Member] | Private Placement [Member]
Proceeds of units sold in a private placement	$ 43,500
Preferred Units [Member] | Affiliated Entity [Member] | Private Placement [Member]
Proceeds of units sold in a private placement		$ 43,500

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Related-Party Transactions (Details Narrative 1) - CF Inspection Management, LLC [Member]	9 Months Ended
	Sep. 30, 2018
Ownership interest	49.00%
Revenues [Member]
Concentration percentage	3.40%
Cynthia A. Fields [Member]
Ownership interest	51.00%

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Commitments and Contingencies (Details Narrative) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Master Service Agreement Compliance Audits [Member]
Compliance audit contigencies reserve	$ 100	$ 0
Performance Obligation [Member]
Short-term security deposits	$ 600	$ 500

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Sale of Salt Water Disposal Facility (Details Narrative) - USD ($) $ in Thousands	1 Months Ended		3 Months Ended		9 Months Ended
	May 31, 2018	Jan. 31, 2018	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Allocated goodwill			$ 50,370		$ 50,370		$ 53,435
Gain on asset disposals			822	$ (208)	4,137	$ (95)
Cash proceeds from settlement of litigation related to lightning strikes			400
Water Services [Member]
Gain on asset disposals			769		$ 4,039
Water Services [Member] | Pecos SWD, LLC [Member]
Cash proceeds from sale of subsidiary		$ 4,000
Allocated goodwill		2,000
Gain on asset disposals		$ 1,800
Water Services [Member] | Orla SWD, LLC [Member]
Cash proceeds from sale of subsidiary	$ 8,200
Allocated goodwill	3,000
Gain on asset disposals	$ 1,800		$ 200

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Reportable Segments (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018		Sep. 30, 2017		Dec. 31, 2017
Revenues	$ 84,778	$ 77,682	$ 226,072		$ 216,971
Costs of services	71,870	68,292	194,092		192,643
Gross margin	12,908	9,390	31,980		24,328
General and administrative	6,064	5,574	17,341		16,013
Depreciation, amortization and accretion	1,124	1,184	3,368		3,561
Impairments					3,598
Losses on asset disposal, net					95
(Gain) loss on asset disposal, net	(822)	208	(4,137)		95
Operating income (loss)	6,542	2,424	15,408		1,061
Interest expense, net	(1,283)	(1,907)	(4,907)		(5,411)
Debt issuance cost write-off			(114)
Foreign currency gains	97	557	(354)		824
Other, net	95	17	302		122
Net loss before income tax expense	5,451	1,091	10,335		(3,404)
Total assets	152,275		152,275				$ 163,203
Pipeline Inspection [Member]
Revenues	77,606	72,737	205,538		205,039
Costs of services	68,350	65,323	183,305		185,308
Gross margin	8,856	7,414	22,233		19,731
General and administrative	4,422	3,893	12,313	[1]	10,212	[2]
Depreciation, amortization and accretion	571	577	1,717		1,755
Impairments					1,329
Losses on asset disposal, net					18
(Gain) loss on asset disposal, net	(21)		(21)
Operating income (loss)	3,884	2,944	8,224		6,417
Total assets	116,510		116,510				120,368
Pipeline And Process Services [Member]
Revenues	3,881	2,834	11,307		5,927
Costs of services	2,592	2,132	7,840		5,005
Gross margin	1,289	702	3,467		922
General and administrative	592	525	1,715		1,488
Depreciation, amortization and accretion	143	157	449		471
Impairments					1,581
(Gain) loss on asset disposal, net	(32)		(77)
Operating income (loss)	586	20	1,380		(2,618)
Total assets	9,365		9,365				10,481
Water Services [Member]
Revenues	3,325	2,111	8,861		6,005
Costs of services	962	837	2,981		2,330
Gross margin	2,363	1,274	5,880		3,675
General and administrative	774	858	2,402	[3]	1,651	[4]
Depreciation, amortization and accretion	410	450	1,202		1,335
Impairments					688
Losses on asset disposal, net		208			77
(Gain) loss on asset disposal, net	(769)		(4,039)
Operating income (loss)	1,948	(242)	6,315		(76)
Total assets	23,919		23,919				31,472
Other Segments [Member]
Revenues	(34)		(34)
Costs of services	(34)		(34)
General and administrative	276	298	911		2,662	[5]
Operating income (loss)	(276)	$ (298)	(911)		$ (2,662)
Total assets	$ 2,481		$ 2,481				$ 882

[1] Amount includes $2.1 million of the allocated quarterly administrative fee charged by Holdings specified in the omnibus agreement.

[2] Amount includes $0.7 million of the allocated quarterly administrative fee charged by Holdings specified in the omnibus agreement.

[3] Amount includes $0.6 million of allocated quarterly administrative fee charged by Holdings specified in the omnibus agreement.

[4] Amount includes $0.3 million of the allocated quarterly administrative fee charged by Holdings specified in the omnibus agreement.

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

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Reportable Segments (Details Narrative) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018 USD ($) N	Sep. 30, 2017 USD ($) N	Sep. 30, 2018 USD ($) N		Sep. 30, 2017 USD ($)
General and administrative expenses	$ 6,064	$ 5,574	$ 17,341		$ 16,013
Number of reportable segments | N			3
Omnibus Agreement [Member]
General and administrative expenses		800			700
Pipeline Inspection [Member]
General and administrative expenses	4,422	3,893	$ 12,313	[1]	10,212	[2]
Refund liability	200		200
Pipeline Inspection [Member] | Omnibus Agreement [Member]
Administrative fee charged			2,100		700
Pipeline And Process Services [Member]
General and administrative expenses	592	525	1,715		1,488
Recognition of deferred revenue	500
Water Services [Member]
General and administrative expenses	$ 774	$ 858	$ 2,402	[3]	1,651	[4]
Number of commercial saltwater disposal (SWD) facilities | N	8	10	9
Number of managed facilities, equity owned | N	1
Water Services [Member] | Omnibus Agreement [Member]
Administrative fee charged			$ 900		$ 300

[1] Amount includes $2.1 million of the allocated quarterly administrative fee charged by Holdings specified in the omnibus agreement.

[2] Amount includes $0.7 million of the allocated quarterly administrative fee charged by Holdings specified in the omnibus agreement.

[3] Amount includes $0.6 million of allocated quarterly administrative fee charged by Holdings specified in the omnibus agreement.

[4] Amount includes $0.3 million of the allocated quarterly administrative fee charged by Holdings specified in the omnibus agreement.