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 MARCH 31, 2019

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

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

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

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

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

Indicate by check mark 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 May 6, 2019, the registrant had 12,052,907 common units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:      None.

CYPRESS ENERGY PARTNERS, L.P.

Table of Contents

		Page
PART I – FINANCIAL INFORMATION		5
ITEM 1.	Unaudited Condensed Consolidated Financial Statements	5
	Unaudited Condensed Consolidated Balance Sheets as of March 31, 2019 and December 31, 2018	5
	Unaudited Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2019 and 2018	6
	Unaudited Condensed Consolidated Statements of Comprehensive Income for the Three Months Ended March 31, 2019 and 2018	7
	Unaudited Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2019 and 2018	8
	Unaudited Condensed Consolidated Statements of Owners’ Equity for the Three Months Ended March 31, 2019 and 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	40
ITEM 4.	Controls and Procedures	40
PART II – OTHER INFORMATION		41
ITEM 1.	Legal Proceedings	41
ITEM 1A.	Risk Factors	42
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	42
ITEM 3.	Defaults upon Senior Securities	42
ITEM 4.	Mine Safety Disclosures	42
ITEM 5.	Other Information	42
ITEM 6.	Exhibits	43
SIGNATURES		44

2  

NAMES OF ENTITIES

Unless the context otherwise requires, references in this 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 acquired May 1, 2015;

● “CEM LLC” refers to Cypress Energy Management, LLC, a wholly owned subsidiary of the General Partner;

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

● “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 and a Director of our Partnership;

● “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% of our outstanding common units as of May 6, 2019;

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

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

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

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

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

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

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, 2018, filed with the U.S. Securities and Exchange Commission (the “SEC”) on March 18, 2019, 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 March 31, 2019 and December 31, 2018

 (in thousands)

	March 31, 2019			December 31, 2018
ASSETS
Current assets:
Cash and cash equivalents	$	6,169		$	15,380
Trade accounts receivable, net		70,727			48,789
Prepaid expenses and other		1,135			1,396
Total current assets		78,031			65,565
Property and equipment:
Property and equipment, at cost		24,254			23,988
Less:  Accumulated depreciation		11,846			11,266
Total property and equipment, net		12,408			12,722
Intangible assets, net		22,085			22,759
Goodwill		50,322			50,294
Finance lease right-of-use assets, net		641			—
Operating lease right-of-use assets		3,328			—
Debt issuance costs, net		1,130			1,260
Other assets		461			253
Total assets	$	168,406		$	152,853
LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable	$	6,862		$	4,848
Accounts payable - affiliates		4,421			4,060
Accrued payroll and other		16,877			12,276
Income taxes payable		944			737
Finance lease obligations		165			90
Operating lease obligations		454			—
Total current liabilities		29,723			22,011
Long-term debt		83,129			76,129
Finance lease obligations		413			248
Operating lease obligations		2,798			—
Other noncurrent liabilities		179			178
Total liabilities		116,242			98,566
Commitments and contingencies - Note 7
Owners’ equity:
Partners’ capital:
Common units (12,053 and 11,947 units outstanding at March 31, 2019 and December 31, 2018, respectively)		32,845			34,677
Preferred units (5,769 units outstanding at March 31, 2019 and December 31, 2018)		44,291			44,291
General partner		(25,876	)		(25,876	)
Accumulated other comprehensive loss		(2,486	)		(2,414	)
Total partners’ capital		48,774			50,678
Noncontrolling interests		3,390			3,609
Total owners’ equity		52,164			54,287
Total liabilities and owners’ equity	$	168,406		$	152,853

See accompanying notes.

5  

CYPRESS ENERGY PARTNERS, L.P.

 Unaudited Condensed Consolidated Statements of Operations

 For the Three Months Ended March 31, 2019 and 2018

 (in thousands, except per unit data)

	Three Months Ended March 31,
	2019			2018
Revenue	$	90,376		$	64,826
Costs of services		80,353			56,697
Gross margin		10,023			8,129
Operating costs and expense:
General and administrative		6,231			5,455
Depreciation, amortization and accretion		1,104			1,134
Gain on asset disposals, net		(21	)		(1,709	)
Operating income		2,709			3,249
Other (expense) income:
Interest expense, net		(1,311	)		(1,956	)
Foreign currency gains (losses)		101			(334	)
Other, net		88			82
Net income before income tax expense		1,587			1,041
Income tax expense		206			81
Net income		1,381			960
Net (loss) income attributable to noncontrolling interests		(219	)		235
Net income attributable to partners / controlling interests		1,600			725
Net income attributable to preferred unitholder		1,033			—
Net income attributable to common unitholders	$	567		$	725
Net income per common limited partner unit (basic and diluted)	$	0.05		$	0.06
Weighted average common units outstanding:
Basic		11,971			11,899
Diluted		12,355			11,984

See accompanying notes.

6  

CYPRESS ENERGY PARTNERS, L.P.

 Unaudited Condensed Consolidated Statements of Comprehensive Income

 For the Three Months Ended March 31, 2019 and 2018

 (in thousands)

	Three Months Ended March 31,
	2019			2018
Net income	$	1,381		$	960
Other comprehensive (loss) income - foreign currency translation		(72	)		102
Comprehensive income		1,309			1,062
Comprehensive (loss) income attributable to noncontrolling interests		(219	)		235
Comprehensive income attributable to preferred unitholder		1,033			—
Comprehensive income attributable to common unitholders	$	495		$	827

See accompanying notes.

7  

CYPRESS ENERGY PARTNERS, L.P.

 Unaudited Condensed Consolidated Statements of Cash Flows

 For the Three Months Ended March 31, 2019 and 2018

 (in thousands)

	Three Months Ended March 31,
	2019			2018
Operating activities:
Net income	$	1,381		$	960
Adjustments to reconcile net income to net cash (used in) provided by operating activities:
Depreciation, amortization and accretion		1,376			1,418
Gain on asset disposals, net		(21	)		(1,709	)
Interest expense from debt issuance cost amortization		130			153
Equity-based compensation expense		269			212
Equity in earnings of investee		(29	)		(36	)
Distributions from investee		—			63
Foreign currency (gains) losses		(101	)		334
Changes in assets and liabilities:
Trade accounts receivable		(21,935	)		1,565
Prepaid expenses and other		6			762
Accounts payable and accounts payable - affiliates		1,905			1,811
Accrued payroll and other		4,562			1,168
Income taxes payable		207			82
Net cash (used in) provided by operating activities		(12,250	)		6,783
Investing activities:
Proceeds from fixed asset disposals, including insurance proceeds		21			3,957
Purchase of property and equipment, excluding finance leases		(372	)		(2,058	)
Net cash (used in) provided by investing activities		(351	)		1,899
Financing activities:
Borrowings on credit facility		7,000			—
Payments on credit facility		—			(4,000	)
Payments on finance lease obligations		(13	)		—
Taxes paid related to net share settlement of equity-based compensation		(158	)		(69	)
Distributions		(3,543	)		(2,504	)
Net cash provided by (used in) financing activities		3,286			(6,573	)
Effect of exchange rates on cash		104			(377	)
Net (decrease) increase in cash and cash equivalents and restricted cash		(9,211	)		1,732
Cash and cash equivalents, beginning of period (includes restricted cash equivalents of $551 at December 31, 2018 and $490 at December 31, 2017)		15,931			24,998
Cash and cash equivalents, end of period (includes restricted cash equivalents of $551 at March 31, 2019 and $590 at March 31, 2018)	$	6,720		$	26,730
Non-cash items:
Accounts payable excluded from capital expenditures	$	388		$	1,106
Acquisitions of property and equipment included in liabilities	$	293		$	—

See accompanying notes.

8  

CYPRESS ENERGY PARTNERS, L.P.

 Unaudited Condensed Consolidated Statements of Owners’ Equity

For the Three Months Ended March 31, 2019 and 2018 

 (in thousands)

	Three Months Ended March 31, 2019
	Common Units			Preferred Units			General Partner			Accumulated Other Comprehensive Loss			Noncontrolling Interests			Total Owners’ Equity
Owners’ equity at December 31, 2018	$	34,677		$	44,291		$	(25,876	)	$	(2,414	)	$	3,609		$	54,287
Net income (loss) for the period January 1, 2019 through March 31, 2019		567			1,033			—			—			(219	)		1,381
Foreign currency translation adjustment		—			—			—			(72	)		—			(72	)
Distributions		(2,510	)		(1,033	)		—			—			—			(3,543	)
Equity-based compensation		269			—			—			—			—			269
Taxes paid related to net share settlement of equity-based compensation		(158	)		—			—			—			—			(158	)
Owners’ equity at March 31, 2019	$	32,845		$	44,291		$	(25,876	)	$	(2,486	)	$	3,390		$	52,164

	Three Months Ended March 31, 2018
	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 March 31, 2018		725			—		—			—			235			960
Foreign currency translation adjustment		—			—		—			102			—			102
Distributions		(2,498	)		—		—			—			(6	)		(2,504	)
Equity-based compensation		212			—		—			—			—			212
Taxes paid related to net share settlement of equity-based compensation		(69	)		—		—			—			—			(69	)
Owners’ equity at March 31, 2018	$	32,984		$	—	$	(25,876	)	$	(2,575	)	$	4,153		$	8,686

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. (“we”, “us”, “our”, or 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, in-line inspection support, pig tracking, survey, data gathering, and supervision of third-party contractors. Our results in this segment are driven primarily by the number of inspectors that perform services for our customers and the fees that we charge for those services, which depend on the type, skills, technology, equipment, and number of inspectors used on a particular project, the nature of the project, and the duration of the project. The number of inspectors engaged on projects is driven by the type of project, prevailing market rates, the age and condition of customers’ assets including pipelines, gas plants, compression stations, storage facilities, and gathering and distribution systems including the legal and regulatory requirements relating to the inspection and maintenance of those assets. 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 that many of our customers develop yearly operating budgets and enter into contracts with us during the winter season for work to be performed during the remainder of the year. Additionally, inspection work throughout the United States during the winter months (especially in the northern states) may be hampered or delayed due to inclement weather.

The Pipeline & Process Services segment (formerly our Integrity Services segment) generates revenue primarily by providing essential 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 we developed and own. 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 6).

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 March 31, 2019 and 2018 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, 2018 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, 2018 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. Certain previously-reported amounts have been reclassified to conform to the current presentation.

10

CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

Use of Estimates in the Preparation of Financial Statements

The preparation of the 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, 2018 included in our Form 10-K, except for the adoption of Accounting Standards Update (“ASU”) 2016-02 – Leases on January 1, 2019.  We adopted the new standard on the effective date of January 1, 2019 and used a modified retrospective approach as permitted under ASU 2018-11. See Note 9 for lease disclosures. The effects of implementing ASU 2016-02 were material to our Consolidated Balance Sheets with the addition of right-of-use assets and associated lease liabilities, but immaterial to our Consolidated Statements of Operations and Consolidated Statements of Cash Flows.

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. We determine allowances for bad debts based on management’s assessment of the creditworthiness of our customers. Trade receivables are written off against the allowance when deemed uncollectible. Recoveries of trade receivables previously written off are recorded when cash is received.

Pacific Gas and Electric Bankruptcy

PG&E Corporation and its wholly-owned subsidiary Pacific Gas and Electric Company (collectively, “PG&E”) filed for bankruptcy protection on January 29, 2019.  PG&E is a significant customer that accounted for $43.4 million of the revenue and $6.4 million of the gross margin of our Pipeline Inspection segment during the year ended December 31, 2018. As of December 31, 2018, the assets on our Consolidated Balance Sheet included $10.3 million of accounts receivable from PG&E. We collected $1.0 million of this balance in January 2019 prior to PG&E’s bankruptcy filing. We generated $2.8 million of revenue from PG&E during the period from January 1, 2019 through January 28, 2019, bringing the total accounts receivable from PG&E to $12.1 million as of the date of the bankruptcy filing. 

We have continued to provide services to PG&E after the bankruptcy filing and began receiving payment for such services. We have not recorded an allowance against the accounts receivable from PG&E at March 31, 2019, as we do not believe it is probable that we will ultimately be unable to collect the full balance of the pre-petition receivables. However, due to uncertainties associated with the bankruptcy process, we cannot make assurances regarding the ultimate collection of these receivables nor can we make assurances regarding the timing of any such collections.

Revenue Recognition

Under Accounting Standards Codification (“ASC”) 606 - Revenue from Contracts with Customers, an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Based on this accounting guidance, our revenue is earned and recognized through the service offerings of our three reportable business segments. Our sales contracts generally have terms of less than one year. As such, we have used the practical expedient contained within the accounting guidance which exempts us from the requirement to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract with an original expected duration of one year or less. We apply judgment in determining whether we are the principal or the agent in instances where we utilize subcontractors to perform all or a portion of the work under our contracts. Based on the criteria in ASC 606, we have determined we are principal in all such circumstances. See Note 10 for disaggregated revenue reported by segment.

Pipeline Inspection - We generate revenue in the Pipeline Inspection segment primarily by providing inspection services on midstream pipelines, gathering systems and distributions systems, including data gathering and supervision of third-party construction, inspection, and maintenance and repair projects. We charge our customers on a per-inspector basis, including per diem charges, mileage, and other reimbursement items. Generally, revenues are recognized when the services are performed.

11

CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

Pipeline & Process Services - We generate revenue in the Pipeline & Process Services segment primarily by providing hydrostatic testing services to major natural gas and petroleum companies and pipeline construction companies of newly-constructed and existing natural gas and petroleum pipelines. We generally charge our customers in this segment on a fixed-bid basis, depending on the size and length of the pipeline being inspected, the complexity of services provided, and the utilization of our work force and equipment. Generally, revenues are recognized when the services are performed.

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 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 water. We also generate revenue managing a saltwater disposal facility for a fee. Water disposal revenues are recognized upon receipt of the wastewater at our disposal facilities. Revenues from sales of oil that is recovered in the process of treating wastewater are recognized when the oil is delivered to the customer. Management fee revenue is recorded when the services are performed.

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 on 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.

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CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

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:

	March 31, 2019		December 31, 2018
	(in thousands)
Accrued payroll	$	14,445	$	9,468
Customer deposits		1,202		1,202
Other		1,230		1,606
	$	16,877	$	12,276

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 March 31, 2019 includes $2.5 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 payables to our U.S.-based subsidiaries. These intercompany payables and receivables among our consolidated subsidiaries are eliminated on our Consolidated Balance Sheets. We report currency translation adjustments on these intercompany payables and receivables within foreign currency gains (losses) in our Consolidated Statements of Operations.

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CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

New Accounting Standards

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

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

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

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

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 2016-13 – Financial Instruments – Credit Losses in June 2016, which replaces the current “incurred loss” methodology for recognizing credit losses with an “expected loss” methodology. This guidance affects trade receivables, financial assets and certain other instruments that are not measured at fair value through net income. The amendments in this ASU are effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. We are currently evaluating the impact this ASU will have on our Unaudited Condensed Consolidated Financial Statements.

3. Debt

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 March 31, 2019 and December 31, 2018 were $83.1 million and $76.1 million, respectively, and are reflected as long-term debt on the Unaudited Condensed Consolidated Balance Sheets. Debt issuance costs are reported as debt issuance costs, net on the Unaudited Condensed Consolidated Balance Sheets and total $1.1 million and $1.3 million at March 31, 2019 and December 31, 2018, respectively. 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, 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.

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 CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

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 5.98% and 6.02% for the three months ended March 31, 2019 and 4.74% and 5.63% for the three months ended March 31, 2018. 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 March 31, 2019 and 2018 was $1.2 million and $1.8 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 March 31, 2019, our leverage ratio was 3.4 to 1.0 and our interest coverage ratio was 4.8 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 March 31, 2019.

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

In April 2019, we borrowed $0.8 million, increasing our total outstanding borrowings to $83.9 million as of May 13, 2019.

4. Income Taxes

The income tax expense reported in our Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2019 and 2018 differs from the statutory tax rate of 21% in 2018 and 2019 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.  

5. 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 an entity controlled by Charles C. Stephenson, Jr. (the “Purchaser”), an affiliate of our General Partner, where we issued and sold in a private placement 5,769,231 Series A Preferred Units representing limited partner interests in the Partnership (the “Preferred Units”) to the Purchaser for a cash purchase price of $7.54 per Preferred Unit, resulting in gross proceeds to the Partnership of $43.5 million. We used proceeds from the transaction to reduce outstanding borrowings on our revolving credit facility. Concurrent with the closing of this transaction, we entered into an amended and restated Credit Agreement dated as of May 29, 2018, to amend and restate the terms of our credit facility, as more fully described in Note 3.

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

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

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CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

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 are required to pay at least 2.5% in cash and will have the option to pay the remaining 7.0% in kind (in the form of issuing additional preferred units) for the first twelve quarters after the Closing Date.

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

Earnings Per Unit

Our net income is attributable and allocable to three ownership groups: (1) our preferred unitholder, (2) the noncontrolling interests in certain subsidiaries, and (3) 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 income attributable to common unitholders represents our remaining net income, after consideration of amounts attributable to our preferred unitholder and the noncontrolling interests.

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

	Three Months Ended March 31,
	2019		2018
	(in thousands, except per unit data)
Net income attributable to common unitholders	$	567	$	725
Weighted average common units outstanding		11,971		11,899
Basic net income per common limited partner unit	$	0.05	$	0.06

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

	Three Months Ended March 31,
	2019		2018
	(in thousands, except per unit data)
Net income attributable to common unitholders	$	567	$	725
Weighted average common units outstanding		11,971		11,899
Effect of dilutive securities:
Weighted average preferred units outstanding (a)		—		—
Long-term incentive plan unvested units		384		85
Diluted weighted average common units outstanding		12,355		11,984
Diluted net income per common limited partner unit	$	0.05	$	0.06

(a) For the three months ended March 31, 2019, the preferred units would have been antidilutive and therefore, were excluded from the computation of diluted net income per limited partner unit.

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CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

Distributions

The following table summarizes the cash distributions declared and paid, or expected to be paid, to our common partners for 2018 and 2019:

Payment Date	Per Unit Cash Distributions		Total Cash Distributions		Total Cash Distributions to Affiliates (a)
			(in thousands)
February 14, 2018	$	0.21	$	2,498	$	1,599
May 15, 2018		0.21		2,506		1,604
August 14, 2018		0.21		2,506		1,604
November 14, 2018		0.21		2,509		1,606
Total 2018 Distributions	$	0.84	$	10,019	$	6,413
February 14, 2019	$	0.21	$	2,510	$	1,606
May 15, 2019 (b)		0.21		2,531		1,622
Total 2019 Distributions (to date)	$	0.42	$	5,041	$	3,228

(a)	64% of the Partnership's outstanding common units at March 31, 2019 were held by affiliates.
(b)	First quarter 2019 distribution was declared and will be paid in the second quarter of 2019.

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

Payment Date	Total Cash Distributions		Total Paid-in-Kind Distributions		Total Distributions
			(in thousands)
November 14, 2018 (a)	$	1,412	$	—	$	1,412
Total 2018 Distributions	$	1,412	$	—	$	1,412
February 14, 2019	$	1,033	$	—	$	1,033
May 15, 2019 (b)		1,033		—		1,033
Total 2019 Distributions (to date)	$	2,066	$	—	$	2,066

(a)	This distribution represents the period from May 29, 2018 (date of preferred unit issuance) through September 30, 2018.
(b)	First quarter 2019 distribution will be paid in the second quarter of 2019.

Equity Compensation 

Our General Partner has adopted a long-term incentive plan (“LTIP”) that authorizes the issuance of up to 2.5 million common units. Certain directors and employees of the Partnership have been awarded Phantom Restricted Units (“Units”) under the terms of the LTIP. The fair value of each award is determined based on the quoted market value of the publicly-traded common units at the grant date, adjusted for a discount to reflect the fact that distributions are not paid on the Units during the vesting period. Compensation expense is recognized on a straight-line basis over the vesting period of the grant. We account for forfeitures of share-based awards when the forfeitures occur. We recorded expense of $0.3 million and $0.2 million during the three months ended March 31, 2019 and 2018, respectively, related to the unit awards.  We have historically granted annual LTIP awards to key employees in the second quarter of each year.

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CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

The following table summarizes the LTIP Unit activity for the three months ended March 31, 2019 and 2018:

	Three Months Ended March 31,
	2019					2018
	Number of Units			Weighted Average Grant Date Fair Value / Unit		Number of Units			Weighted Average Grant Date Fair Value / Unit
Units at January 1		974,709		$	5.76		664,509		$	8.42
Units granted		—					16,668		$	4.76
Units vested		(127,505	)	$	8.74		(54,306	)	$	13.14
Units forfeited		(35,872	)	$	5.82		(13,971	)	$	6.15
Units at March 31		811,332		$	5.29		612,900		$	8.00

The majority of the Unit awards vest in three tranches, with one-third of the units vesting three years from the grant date, one-third vesting four years from the grant date, and one-third vesting five years from the grant date. However, certain of the awards have different, and typically shorter, vesting periods. One grant, totaling 72,046 units, vests three years from the grant date, contingent upon the recipient meeting certain performance targets. Total unearned compensation associated with the LTIP at March 31, 2019 was $2.7 million with an average remaining life of 2.2 years.

6. Related-Party Transactions

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 an annual administrative fee in the amount of $4.5 million (or approximately $1.1 million per quarter) to Holdings, for providing certain partnership overhead services, including executive management services by certain officers 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;

● 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

● 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.

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CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

So long as Holdings controls our General Partner, the omnibus agreement will remain in full force and effect, unless we and Holdings agree to terminate it sooner. If Holdings ceases to control our General Partner, either party may terminate the omnibus agreement, provided that the indemnification obligations will remain in full force and effect in accordance with their terms. We and Holdings may agree to further amend the omnibus agreement; however, amendments that the General Partner determines are adverse to our unitholders will also require the approval of the Conflicts Committee of our Board of Directors. As part of our 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 facility.

Alati Arnegard, LLC

The Partnership provides management services to a 25% owned company, Alati Arnegard, LLC (“Arnegard”). We recorded earnings from this investment of less than $0.1 million for each of the three months ended March 31, 2019 and 2018.  These earnings are recorded in other, net in the Consolidated Statements of Operations and equity in earnings of investee in the Consolidated Statements of Cash Flows. Management fee revenue earned from Arnegard is included in revenue in the Consolidated Statements of Operations and totaled less than $0.1 million for each of the three months ended March 31, 2019 and 2018. Accounts receivable from Arnegard totaled $0.1 million at both March 31, 2019 and December 31, 2018, and is included in trade accounts receivable, net on the Consolidated Balance Sheets. Our investment in Arnegard totaled $0.3 million at both March 31, 2019 and December 31, 2018, and is included in other assets on the Consolidated Balance Sheets. 

CF Inspection Management, LLC

We have also entered into a joint venture with CF Inspection, a nationally-qualified woman-owned inspection firm affiliated with one of Holdings’ owners. CF Inspection allows us to offer various services to clients that require the services of an approved Women’s Business Enterprise (“WBE”), as CF Inspection is certified as a Women’s Business Enterprise by the Supplier Clearinghouse in California and as a National Women’s Business Enterprise by the Women’s Business Enterprise National Council. We own 49% of CF Inspection and Cynthia A. Field, an affiliate of Holdings and a Director of our Partnership, owns the remaining 51% of CF Inspection. For the three months ended March 31, 2019, CF Inspection represented approximately 2.6% of our consolidated revenue.

Sale of Preferred Equity

As described in Note 5, we issued and sold $43.5 million of preferred equity to an affiliate in May 2018.

7. Commitments and Contingencies

Security Deposits

The Partnership has various performance obligations which are secured with short-term security deposits (reflected as restricted cash equivalents in our Consolidated Statements of Cash Flows) totaling $0.6 million at March 31, 2019 and December 31, 2018. These amounts are included in prepaid expenses and other on the 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, or inaccurate, the MSA’s may provide the customer the right to receive a credit or refund for any overcharges identified. At any given time, we may have multiple audits ongoing. As of March 31, 2019 and December 31, 2018, we established a reserve of $0.1 million for potential liabilities related to these compliance audit contingencies.

Legal Proceedings

Fithian v. TIR LLC

On October 5, 2017, a former inspector for TIR LLC and Cypress 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.

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CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

On March 28, 2018, the court granted a joint stipulation of dismissal without prejudice in regard to TIR LLC and Cypress Energy Partners – Texas, LLC, as neither of those parties were employers of the plaintiff or the putative class members during the time period that is the subject of the lawsuit. On July 26, 2018, the plaintiff filed a motion for conditional class certification. CEM-TIR subsequently filed pleadings opposing the motion. On January 25, 2019, the court denied the plaintiff’s motion for conditional class certification. The court is in the process of rescheduling a hearing on defendant’s motion for a scheduling order and compel mediation.

Sun Mountain LLC v. TIR-PUC

On February 27, 2019, Sun Mountain LLC (“Sun Mountain”), a subcontractor of TIR-PUC, filed a lawsuit alleging that TIR-PUC failed to pay invoices amounting to approximately $3.5 million for services subcontracted to Sun Mountain under TIR-PUC’s agreement to provide services to Pacific Gas and Electric Company. Sun Mountain filed the action in Federal District Court for the Northern District of Oklahoma. TIR-PUC denies that such amounts are owed, as conditions to TIR-PUC’s obligation to make the payments have not been met. The full amount of these invoices is included within accounts payable on the accompanying Consolidated Balance Sheets at March 31, 2019 and December 31, 2018. No estimate of potential loss can be determined at this time and TIR-PUC denies the claims.

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.

8. Sale of Saltwater Disposal Facility

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. This gain is reported within gain on asset disposals, net in our Consolidated Statement of Operations. 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. 

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 Pecos and Orla facilities generated revenues of $0.1 million and an operating loss of approximately $0.1 million during the three months ended March 31, 2018.

9. Leases

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

Practical Expedients and Accounting Policy Elections

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

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CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

Discount Rate

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

Operating Leases

Our operating leases include leases for office space and land lease agreements for four of our salt water disposal facilities. Our lease for our office space headquarters constitutes $3.1 million of our Operating ROU asset at March 31, 2019 of $3.3 million. The lease expires in November of 2024 unless terminated earlier with a payment of a penalty under certain circumstances specified in our lease. In the determination of the lease term for this lease, we concluded the lease term would go through November 2024 as it was not reasonably certain at the inception of the agreement that we would exercise any of the termination options in the agreement. As of March 31, 2019, the weighted average remaining lease term and weighted average discount rate for our operating leases was 5.8 years and 6.1%, respectively. Our operating leases are reflected as operating lease right-of-use assets within noncurrent assets and operating lease obligations within current and noncurrent liabilities on our Consolidated Balance Sheet at March 31, 2019.

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

Remainder of 2019	$	455
2020		680
2021		679
2022		679
2023		679
Thereafter		720
Total lease payments	$	3,892
Less imputed interest		(640	)
Total operating lease obligations	$	3,252

Finance Leases

Our finance leases primarily include leases for vehicles. As of March 31, 2019, the weighted average remaining lease term and weighted average discount rate for our finance leases was 3.6 years and 6.0%, respectively. Our finance leases are reflected as finance lease right-of-use assets, net within noncurrent assets and finance lease obligations within current and noncurrent liabilities on our Consolidated Balance Sheet at March 31, 2019.

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

Remainder of 2019	$	148
2020		182
2021		173
2022		114
2023		24
Thereafter		—
Total lease payments	$	641
Less imputed interest		(63	)
Total finance lease obligations	$	578

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CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

Lease Expense Components

During the three months ended March 31, 2019, our lease expense consists of the following components (in thousands):

	Three Months Ended March 31, 2019
Finance lease expense:
Amortization of right-of-use assets	$	32
Interest on lease liabilities		6
Operating lease expense		168
Short-term lease expense - general and administrative		22
Short-term lease expense - costs of services (a)		471
Variable lease expense		118
Sublease income - related parties		(10	)
Total lease expense	$	807

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

10. Reportable Segments

The Partnership’s operations consist of three reportable segments: (i) Pipeline Inspection Services (“Pipeline Inspection”), (ii) Pipeline & Process Services and (iii) Water and Environmental Services (“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 that many of our customers develop yearly operating budgets and enter into contracts with us during the winter season for work to be performed during the remainder of the year.  Additionally, inspection work throughout the United States during the winter months (especially in the northern states) may be hampered or delayed due to inclement weather, thus affecting our revenue and costs. We have constrained recognition of certain revenue until the expiration of a contract provision that gives a customer the opportunity to reopen negotiation of the fees paid for certain services. As of March 31, 2019 and December 31, 2018, we recognized a refund liability of $0.4 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 and costs in this segment may be subject to seasonal variations and interim activity may not be indicative of yearly activity, considering that many of our customers develop yearly operating budgets and enter into contracts with us during the winter season for work to be performed during the remainder of the year. Additionally, field work during the winter months may be hampered or delayed due to inclement weather. Revenue during the three months ended March 31, 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).

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CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

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. During the three months ended March 31, 2019, approximately 98% of our disposal water was produced water that is generated during production life of an oil and gas well and approximately 52% of our water was delivered via pipeline to our saltwater disposal facilities. 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 corporate and overhead items not specifically allocable to the other reportable segments.

23

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 before income tax expense.

	Pipeline Inspection		Pipeline & Process Services			Water Services			Other			Total
	(in thousands)
Three months ended March 31, 2019
Revenue	$	86,229	$	1,974		$	2,173		$	—		$	90,376
Costs of services		77,858		1,719			776			—			80,353
Gross margin		8,371		255			1,397			—			10,023
General and administrative		4,606		596			766			263			6,231
Depreciation, amortization and accretion		555		143			402			4			1,104
Gains on asset disposals, net		—		(21	)		—			—			(21	)
Operating income (loss)	$	3,210	$	(463	)	$	229		$	(267	)		2,709
Interest expense, net													(1,311	)
Gains on foreign currency													101
Other, net													88
Net income before income tax expense												$	1,587
Three months ended March 31, 2018
Revenue	$	57,967	$	4,350		$	2,509		$	—		$	64,826
Costs of services		52,480		3,157			1,060			—			56,697
Gross margin		5,487		1,193			1,449			—			8,129
General and administrative		3,759		545			836			315			5,455
Depreciation, amortization and accretion		573		158			403			—			1,134
Gains on asset disposals, net		—		—			(1,709	)		—			(1,709	)
Operating income (loss)	$	1,155	$	490		$	1,919		$	(315	)		3,249
Interest expense, net													(1,956	)
Losses on foreign currency													(334	)
Other, net													82
Net income before income tax expense												$	1,041
Total Assets
March 31, 2019	$	133,078	$	8,660		$	22,737		$	3,931		$	168,406
December 31, 2018	$	116,239	$	10,972		$	24,281		$	1,361		$	152,853

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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, 2018 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, 2018 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, 2018. 

Overview

We are a growth-oriented master limited partnership formed in September 2013 to provide services to the oil and gas industry. We provide independent pipeline inspection and integrity services to various energy exploration and production and midstream companies and their vendors throughout the United States and Canada through our Pipeline Inspection and Pipeline & Process Services segments. The Pipeline Inspection segment is comprised of the operations of our TIR Entities and the Pipeline & Process Services segment is comprised of the operations of Brown. We also provide saltwater disposal and other water and environmental services to U.S. onshore oil and natural gas producers and trucking companies through our Water Services segment. We operate nine (eight owned) saltwater disposal facilities, all of which are in the Bakken Shale region of the Williston Basin in North Dakota. We have a management agreement in place to provide staffing and management services to one 25%-owned saltwater disposal facility in the Bakken Shale region. In all of our business segments, we work closely with our customers to help them comply with increasingly complex and strict environmental and safety rules and regulations applicable to production and pipeline operations and to reduce their operating costs.

Ownership

As of March 31, 2019, Holdings owns 58% of the Partnership’s common units, while affiliates of Holdings own 6% of the Partnership’s common units, for a total ownership percentage of the Partnership’s common units of 64% 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 Holdings owns 100% of the preferred units.

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 an annual administrative fee in the amount of $4.5 million (or approximately $1.1 million per quarter) to Holdings, for providing certain partnership overhead services, including executive management services by certain officers 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;

● 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

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● 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 Holdings controls our General Partner, the omnibus agreement will remain in full force and effect, unless we and Holdings agree to terminate it sooner. If Holdings ceases to control our General Partner, either party may terminate the omnibus agreement, provided that the indemnification obligations will remain in full force and effect in accordance with their terms. We and Holdings may agree to further amend the omnibus agreement; however, amendments that the General Partner determines are adverse to our unitholders will also require the approval of the Conflicts Committee of our Board of Directors. As part of our 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 facility.

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. We also bill our customers for per diem charges, mileage, and other reimbursement items.

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 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 is usually lower than our recovery during the summer. 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.

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Pacific Gas and Electric Bankruptcy

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

PG&E is a significant customer that accounted for $43.4 million of the revenue and $6.4 million of the gross margin of our Pipeline Inspection segment during the year ended December 31, 2018. As of December 31, 2018, the assets on our Consolidated Balance Sheet included $10.3 million of accounts receivable from PG&E. We collected $1.0 million of this balance in January 2019 prior to PG&E’s bankruptcy filing. We generated $2.8 million of revenue from PG&E during the period from January 1, 2019 through January 28, 2019, bringing the total accounts receivable from PG&E to $12.1 million as of the date of the bankruptcy filing. Our relationship with PG&E remains strong. We have continued to provide services to PG&E after the bankruptcy filing and began receiving payment for such services.

On January 29, 2019, PG&E filed a motion with the bankruptcy court (the “Court”) requesting that the Court grant PG&E authority to pay certain pre-petition claims to certain key suppliers. The motion did not specify to which suppliers the motion would apply, but the motion described the nature of the work that those suppliers perform. Once such category includes “operational integrity suppliers”, which are those that provide “essential and specialized goods and services so that [PG&E] can provide safe and reliable…natural gas service to their customers’ homes and businesses, while remaining in compliance with all applicable state and federal laws and regulations.” The motion states that PG&E is working to develop a list of vendors that are subject to the motion. The motion indicates that PG&E would contact each such vendor and attempt to negotiate timely payment of a portion the pre-petition receivables owed to that vendor, in return for which the vendor would agree to continue to provide services to PG&E under the same terms that were in effect prior to the bankruptcy filing. Any pre-petition receivables not settled in this manner would continue to be subject to the claims resolution process in the bankruptcy proceeding. The Court granted this motion. Based on the nature of the services we provide to PG&E, which are mandated by state and federal requirements, which are critical to the safety of PG&E’s natural gas infrastructure, and which require specialized knowledge and certifications, we believe we could reasonably be included on the list of vendors that are subject to the order granting this motion. The motion included a limit on the combined amount of pre-petition claims that may be paid pursuant to the motion, which may be less than the total amount of pre-petition claims asserted by all vendors that may be subject to the motion. PG&E advised us that we have been approved to receive a payment under the operational integrity supplier order. Details regarding the amount of such award and associated release terms have not yet been finalized.

Also on January 29, 2019, PG&E filed a motion with the Court requesting that the Court grant PG&E authority to pay pre-petition claims to certain suppliers that have filed or could file liens on PG&E’s assets. The motion indicates that PG&E would contact each such vendor and offer to pay the vendor the pre-petition receivables owed to the vendor, in return for which the vendor would take whatever action was necessary to remove the liens. The Court granted this motion. We believe, based on the nature of the services we have provided to PG&E, that we have the right to file mechanics’ liens on PG&E’s natural gas distribution assets, and we have filed and perfected such liens in the 38 counties in which we performed services that are subject to our pre-petition receivables. We are working with PG&E to ensure they have all required information to support our liens as they work through their payment approval process. The motion included a limit on the combined amount of pre-petition claims that may be paid pursuant to the motion; at this time, we do not know the total amount of pre-petition claims asserted by all vendors that are subject to the motion or whether the combined amount of such claims exceeds the maximum amount allowed for under the motion.

We have not recorded an allowance against the accounts receivable from PG&E at March 31, 2019, as we do not believe it is probable that we will not be able to collect the full balance of the pre-petition receivables. However, due to uncertainties associated with the bankruptcy process, we cannot make assurances regarding the ultimate collection of these receivables nor can we make assurances regarding the timing of any such collections.

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Outlook

Overall

Revenues of our Pipeline Inspection segment increased from $58.0 million in the first quarter of 2018 to $86.2 million in the first quarter of 2019, an increase of 49%. This increase was due to growing demand for our services and increased business development efforts. During the fourth quarter of 2018, we began work on the largest contract in the 15-year history of TIR. Gross margins in this segment increased from $5.5 million in the first quarter of 2018 to $8.4 million in the first quarter of 2019, an increase of 53%.

Revenues of our Pipeline & Process services segment decreased from $4.4 million in the first quarter of 2018 to $2.0 million in the first quarter of 2019. The decrease was due primarily to adverse weather, which delayed several large projects that were scheduled to begin in the first quarter of 2019. We have a healthy backlog of projects that we began working on in the second quarter of 2019.

Revenues of our Water Services segment decreased from $2.5 million in the first quarter of 2018 to $2.2 million in the first quarter of 2019. The decrease in revenues is due in part to the sale of our Texas facilities in 2018, which generated $0.1 million in revenues during the first quarter of 2018. Revenues of our North Dakota facilities decreased by $0.2 million during the three months ended March 31, 2019 compared to the three months ended March 31, 2018, due primarily to a decrease of 0.2 million barrels in the volume of water processed. 

In 2018, Holdings completed two acquisitions. Both transactions require some repositioning before bringing the acquired assets into the Partnership. Holdings continues to make progress on both of these acquisitions and intends to offer them to the Partnership once it has accomplished certain developmental goals. If completed, the dropdown of the acquired assets would move us into several new lines of work, including water treatment, in-line inspection, equipment rental (which could be converted into a service business before offering this business to the Partnership), and offshore pipeline process services. We remain excited about entering the in-line inspection industry with next-generation technology capable of helping pipeline owners and operators better manage the integrity of their assets in both the energy and municipal water industries.

The long-term increasing demand for pipeline inspection, integrity services, and water solutions remains strong due to our nation’s aging pipeline infrastructure, and we believe we are well-positioned to capitalize on the opportunities that improving market conditions will create. The future dropdown of the acquired assets may also position us to eventually resume increasing our distributions. 

Our ownership interests remain fully aligned with our unitholders, as our General Partner and insiders collectively own 64% of our common units and an affiliate of our General Partner owns 100% of our preferred units.

Pipeline Inspection Services

Demand is growing for our Pipeline Inspection segment. We operate in a very large market, with more than 2,500 customer prospects who require federally and/or state-mandated inspection and integrity services. During the third quarter of 2018, we signed the largest contract in the 15-year history of TIR and began work on this project in the fourth quarter of 2018.

Our focus remains on 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 beginning to reinvest in their businesses following a difficult two-year economic downturn in the energy industry. 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 inspection services. However, a prolonged downturn in oil and natural gas prices could lead to a downturn in demand for our services.

Pipeline & Process Services

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

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Water Services

We continue to focus on produced water and pipeline water whenever possible. During the first quarter of 2019, 98% of our volumes were produced water and 52% of our volumes were delivered via ten pipelines, including two that we constructed and own. 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. 

Results of Operations

Consolidated Results of Operations

The following table summarizes our Unaudited Condensed Consolidated Statements of Operations for the three-month periods ended March 31, 2019 and 2018: 

	Three Months Ended March 31,
	2019			2018
	(in thousands)
Revenue	$	90,376		$	64,826
Costs of services		80,353			56,697
Gross margin		10,023			8,129
Operating costs and expense:
General and administrative - segment		5,968			5,140
General and administrative - corporate		263			315
Depreciation, amortization and accretion		1,104			1,134
Gain on asset disposals, net		(21	)		(1,709	)
Operating income		2,709			3,249
Other (expense) income:
Interest expense, net		(1,311	)		(1,956	)
Foreign currency gains (losses)		101			(334	)
Other, net		88			82
Net income before income tax expense		1,587			1,041
Income tax expense		206			81
Net income		1,381			960
Net (loss) income attributable to noncontrolling interests		(219	)		235
Net income attributable to partners / controlling interests		1,600			725
Net income attributable to preferred unitholder		1,033			—
Net income attributable to common unitholders	$	567		$	725

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

General and administrative – corporate. General and administrative expense – corporate includes equity-based compensation expense for certain employees and certain administrative expenses not directly attributable to the operating segments. 

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 from the three months ended March 31, 2018 to the three months ended March 31, 2019 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 three months ended March 31, 2019 and 2018 was $77.3 million and $133.3 million, respectively. The average interest rate on our borrowings increased from 5.15% during the quarter ended March 31, 2018 to 6.0% during the quarter ended March 31, 2019.

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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 on our Unaudited Condensed Consolidated Balance Sheets. We report currency translation adjustments on these intercompany payables and receivables within foreign currency gains (losses) in our Unaudited Condensed Statements of Operations. The net foreign currency gains during the three months ended March 31, 2019 resulted from the appreciation of the Canadian dollar relative to the U.S. dollar.

Other, net. Other income includes income associated with our 25% interest in a saltwater disposal facility, which we account for under the equity method.

Income tax expense (benefit). 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. Income tax expense increased from $0.1 million for the three months ended March 31, 2018 to $0.2 million for the three months ended March 31, 2019 primarily due to increased income in our U.S. corporate subsidiary that provides services to public utility customers and increases in revenue that is subject to the Texas franchise tax.

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 three months ended March 31, 2019, substantially all of our gross income, which consisted of approximately $73.9 million of revenue (exclusive of the income generated by our taxable corporate subsidiaries), represented “qualifying income”.

Net (loss) income 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 (loss) income attributable to noncontrolling interest in our Unaudited Condensed Consolidated Statements of Operations.

Segment Operating Results

Pipeline Inspection

The following table summarizes the operating results of the Pipeline Inspection segment for the three months ended March 31, 2019 and 2018. 

	Three Months Ended March 31,
	2019		% of Revenue			2018		% of Revenue			Change			% Change
	(in thousands, except average revenue and inspector data)
Revenue	$	86,229				$	57,967				$	28,262			48.8	%
Costs of services		77,858					52,480					25,378			48.4	%
Gross margin		8,371		9.7	%		5,487		9.5	%		2,884			52.6	%
General and administrative		4,606		5.3	%		3,759		6.5	%		847			22.5	%
Depreciation, amortization and accretion		555		0.6	%		573		1.0	%		(18	)		(3.1	)%
Operating income	$	3,210		3.7	%	$	1,155		2.0	%	$	2,055			177.9	%
Operating Data
Average number of inspectors		1,432					1,030					402			39.1	%
Average revenue per inspector per week	$	4,682				$	4,377				$	305			7.0	%
Revenue variance due to number of inspectors											$	24,221
Revenue variance due to average revenue per inspector											$	4,041

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Revenue. Revenue increased $28.3 million during the three months ended March 31, 2019 compared to the three months ended March 31, 2018, due to an increase in the average number of inspectors engaged (an increase of 402 inspectors accounting for $24.2 million of the revenue increase) and an increase in the average revenue billed per inspector (accounting for $4.1 million of the revenue increase). Revenue attributable to our U.S. operations increased $28.9 million during the three months ended March 31, 2019 compared to the three months ended March 31, 2018, due to increased activity by our clients and increased business development efforts. During the fourth quarter of 2018, we began work on the largest contract award in our history, a pipeline project that is expected to continue throughout 2019. Revenues of our subsidiary that serves public utility customers increased by $4.2 million during the three months ended March 31, 2019 compared to the three months ended March 31, 2018. These increases were partially offset by a decrease of $0.6 million in revenues attributable to our Canadian operations due to a decrease in the average number of inspectors employed during the period.  The increase in average revenue per inspector is due to changes in customer mix. Fluctuations in the average revenue per inspector are expected, given that we charge different rates for different types of inspectors and different types of inspection services. We continue to compete with many other competitors on quality, service, price, safety, and training.

Costs of services. Costs of services increased $25.4 million during the three months ended March 31, 2019 compared to the three months ended March 31, 2018, primarily related to an increase in the average number of inspectors employed during the period.

Gross margin. Gross margin increased $2.9 million during the three months ended March 31, 2019 compared to the three months ended March 31, 2018. The gross margin percentage improved to 9.7% in 2019, compared to 9.5% in 2018. The increase in gross margin percentage is due to changes in the mix of services provided. During the three months ended March 31, 2019, we generated increased revenues from our public utility and nondestructive examination service lines, which typically generate higher margins.

General and administrative. General and administrative expenses increased by $0.8 million during the three months ended March 31, 2019 compared to the three months ended March 31, 2018. Compensation expense increased approximately $0.4 million due to an increase in personnel to support our growing businesses. Professional fees increased by $0.3 million, due to legal costs associated with certain employment-related lawsuits and claims and to legal advisory costs related to the bankruptcy of one of our largest customers. The administrative fee charged by Holdings increased by $0.1 million, as a result of an inflation adjustment called for in our agreement with Holdings.

Depreciation, amortization and accretion. Depreciation, amortization and accretion expense during the three months ended March 31, 2019 was not significantly different from depreciation, amortization and accretion expense during the three months ended March 31, 2018.

Operating income. Operating income increased by $2.1 million during the three months ended March 31, 2019 compared to the three months ended March 31, 2018, due primarily to an increase in gross margin, which was partially offset by an increase in general and administrative expense. 

Pipeline & Process Services

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

	Three Months Ended March 31,
	2019			% of Revenue			2018		% of Revenue			Change			% Change
	(in thousands, except average revenue and inspector data)
Revenue	$	1,974					$	4,350				$	(2,376	)		(54.6	)%
Costs of services		1,719						3,157					(1,438	)		(45.5	)%
Gross margin		255			12.9	%		1,193		27.4	%		(938	)		(78.6	)%
General and administrative		596			30.2	%		545		12.5	%		51			9.4	%
Depreciation, amortization and accretion		143			7.2	%		158		3.6	%		(15	)		(9.5	)%
Gain on asset disposals, net		(21	)		-1.1	%		—					(21	)
Operating (loss) income	$	(463	)		(23.5	)%	$	490		11.3	%	$	(953	)		(194.5	)%
Operating Data
Average number of field personnel		28						24					4			16.7	%
Average revenue per field personnel per week	$	5,483					$	14,097				$	(8,614	)		(61.1	)%
Revenue variance due to number of field personnel												$	282
Revenue variance due to average revenue per field personnel												$	(2,658	)

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Revenue. Revenue decreased $2.4 million during the three months ended March 31, 2019 compared to the three months ended March 31, 2018. The decrease in revenue from the first quarter of 2018 to the first quarter of 2019 was primarily due to adverse weather, which delayed several large projects that were scheduled to begin in the first quarter of 2019. Revenue during the three months ended March 31, 2018 included $0.3 million associated with additional billings on a project that we completed in the fourth quarter of 2018 (we recognized the revenue upon receipt of customer acknowledgment of the additional fees). Business has historically been slower in the first and fourth quarters of the year as a result of factors such as weather and the budgeting cycles of our customers. 

Costs of services. Cost of services decreased $1.4 million during the three months ended March 31, 2019 compared to the three months ended March 31, 2018, due to a decrease in revenue.

Gross margin. Gross margin decreased approximately $0.9 million during the three months ended March 31, 2019 compared to the three months ended March 31, 2018. 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 less utilized during the three months ended March 31, 2019 due to adverse weather, the gross margin percentage was lower.

General and administrative. General and administrative expenses primarily include compensation expense for office employees and general office expenses. General and administrative expense during the three months ended March 31, 2019 was not significantly different than general and administrative expense during the three months ended March 31, 2018. 

Depreciation, amortization and accretion. Depreciation, amortization and accretion expense includes depreciation of property and equipment and amortization of intangible assets associated with customer relationships, trade names, and noncompete agreements. Depreciation, amortization and accretion expense during the three months ended March 31, 2019 was not significantly different than depreciation, amortization and accretion expense during the three months ended March 31, 2018.

Operating income. Operating income decreased by $1.0 million during the three months ended March 31, 2019 compared to the three months ended March 31, 2018, due primarily to a decrease in gross margin of $0.9 million.

Water Services

The following table summarizes the operating results of the Water Services segment for the three months ended March 31, 2019 and 2018.

	Three Months Ended March 31,
	2019		% of Revenue			2018			% of Revenue			Change			% Change
	(in thousands, except per barrel data)
Revenue	$	2,173				$	2,509					$	(336	)		(13.4	)%
Costs of services		776					1,060						(284	)		(26.8	)%
Gross margin		1,397		64.3	%		1,449			57.8	%		(52	)		(3.6	)%
General and administrative		766		35.3	%		836			33.3	%		(70	)		(8.4	)%
Depreciation, amortization and accretion		402		18.5	%		403			16.1	%		(1	)		(0.2	)%
Gain on asset disposals, net		—					(1,709	)		(68.1	)%		1,709			(100.0	)%
Operating income	$	229		10.5	%	$	1,919			76.5	%	$	(1,690	)		(88.1	)%
Operating Data
Total barrels of saltwater disposed		2,814					3,075						(261	)		(8.5	)%
Average revenue per barrel disposed (a)	$	0.77				$	0.82					$	(0.04	)		(5.0	)%
Revenue variance due to barrels disposed												$	(213	)
Revenue variance due to revenue per barrel												$	(123	)

(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 decreased by $0.3 million during the three months ended March 31, 2019 compared to the three months ended March 31, 2018. Revenues during the three months ended March 31, 2018 included $0.1 million from our Texas facilities, which included management fees associated with a transition services agreement related to the sale in January 2018 of our Pecos, Texas facility and revenues from our Orla, Texas facility, which was sold in May 2018. Revenues of our North Dakota facilities decreased by approximately $0.2 million during the three months ended March 31, 2019 compared to the three months ended March 31, 2018, due primarily to a decrease of 0.2 million in the volume of water processed. 

The average revenue per barrel decreased during the three months ended March 31, 2019 compared to the three months ended March 31, 2018, due primarily to approximately $0.1 million of management fees recorded in 2018 associated with a transition services agreement related to the sale of the Pecos, Texas facility.

Costs of services. Costs of services decreased by $0.3 million during the three months ended March 31, 2019 compared to the three months ended March 31, 2018. The decrease was due to a decrease in the volume of salt water disposed, the sale of our Texas facilities, and approximately $0.1 million of expense associated with the cleanup and remediation of a saltwater spill at one of our facilities in North Dakota during the first quarter of 2018.

Gross margin. Gross margin during the three months ended March 31, 2019 was similar to the gross margin during the three months ended March 31, 2018, due primarily to a $0.3 million decrease in revenue, partially offset by a $0.3 million decrease in cost of services. 

General and administrative. General and administrative expense includes 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 March 31, 2019 compared to the three months ended March 31, 2018 due primarily to decreased compensation costs.

Depreciation, amortization and accretion. Depreciation, amortization and accretion expense during the three months ended March 31, 2019 was not significantly different than depreciation, amortization and accretion expense during the three months ended March 31, 2018.

Gain on asset disposals, net. We recorded a gain of $1.8 million on the January 2018 sale of our Pecos, Texas facility. During the three months ended March 31, 2018, we recorded a loss of $0.1 million upon the abandonment of a capital expansion project.

Operating income. Operating income decreased by $1.7 million during the three months ended March 31, 2019 compared to the three months ended March 31, 2018, due primarily to a $1.8 million gain from the sale of our Pecos, Texas saltwater disposal facility in January of 2018.

Adjusted EBITDA

We define Adjusted EBITDA as net income; plus interest expense; depreciation, amortization and accretion expenses; income tax expense; impairments; non-cash allocated expenses; and equity-based compensation expense; less certain other unusual or non-recurring items. We define Adjusted EBITDA attributable to limited partners as net income attributable to limited partners; plus interest expense attributable to limited partners; depreciation, amortization and accretion expenses attributable to limited partners; impairments attributable to limited partners; income tax expense attributable to limited partners; non-cash allocated expenses attributable to limited partners; and equity-based compensation attributable to limited partners; less certain other unusual or non-recurring items attributable to limited partners. We define Distributable Cash Flow as Adjusted EBITDA attributable to limited partners; less cash interest paid, cash income taxes paid, maintenance capital expenditures, and cash distributions on preferred equity. Adjusted EBITDA, Adjusted EBITDA attributable to limited partners, and Distributable Cash Flow are used as supplemental financial measures by management and by external users of our financial statements, such as investors and commercial banks, to assess: 

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

● 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.

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

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

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

Reconciliation of Net Income to Adjusted EBITDA and Distributable Cash Flow
	Three Months ended March 31,
	2019			2018
	(in thousands)
Net income	$	1,381		$	960
Add:
Interest expense		1,311			1,956
Depreciation, amortization and accretion		1,376			1,418
Income tax expense		206			81
Equity based compensation		269			212
Foreign currency losses		—			334
Less:
Gains on asset disposals, net		—			1,709
Foreign currency gains		101			—
Adjusted EBITDA	$	4,442		$	3,252
Adjusted EBITDA attributable to noncontrolling interests		(89	)		386
Adjusted EBITDA attributable to limited partners / controlling interests	$	4,531		$	2,866
Less:
Preferred unit distributions		1,033			—
Cash interest paid, cash taxes paid, maintenance capital expenditures		1,218			1,936
Distributable cash flow	$	2,280		$	930

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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 March 31,
	2019		2018
	(in thousands)
Net income attributable to limited partners	$	1,600	$	725
Add:
Interest expense attributable to limited partners		1,311		1,956
Depreciation, amortization and accretion attributable to limited partners		1,249		1,275
Income tax expense attributable to limited partners		203		73
Equity based compensation attributable to limited partners		269		212
Foreign currency losses attributable to limited partners		—		334
Less:
Gains on asset disposals, net attributable to limited partners		—		1,709
Foreign currency gains attributable to limited partners		101		—
Adjusted EBITDA attributable to limited partners		4,531		2,866
Less:
Preferred unit distributions		1,033		—
Cash interest paid, cash taxes paid and maintenance capital expenditures attributable to limited partners		1,218		1,936
Distributable cash flow	$	2,280	$	930

Reconciliation of Net Cash Flows (Used In) Provided by Operating
Activities to Adjusted EBITDA and Distributable Cash Flow
	Three Months ended March 31,
	2019			2018
	(in thousands)
Cash flows (used in) provided by operating activities	$	(12,250	)	$	6,783
Changes in trade accounts receivable, net		21,935			(1,565	)
Changes in prepaid expenses and other		(6	)		(762	)
Changes in accounts payable and accounts payable - affiliates		(1,905	)		(1,811	)
Changes in accrued liabilities and other		(4,562	)		(1,168	)
Change in income taxes payable		(207	)		(82	)
Interest expense (excluding non-cash interest)		1,181			1,803
Income tax expense (excluding deferred tax benefit)		206			81
Other		50			(27	)
Adjusted EBITDA	$	4,442		$	3,252
Adjusted EBITDA attributable to noncontrolling interests		(89	)		386
Adjusted EBITDA attributable to limited partners / controlling interests	$	4,531		$	2,866
Less:
Preferred unit distributions		1,033			—
Cash interest paid, cash taxes paid, maintenance capital expenditures		1,218			1,936
Distributable cash flow	$	2,280		$	930

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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, 2018), 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 March 31, 2019, our sources of liquidity included:

● $6.2 million cash on the balance sheet at March 31, 2019 (inclusive of cash attributable to the noncontrolling interest holders);

● available borrowings under our Credit Agreement of $6.3 million at March 31, 2019; and

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

At-the-Market Equity Program

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

Distributions

Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all 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 cash distributions declared and paid, or expected to be paid, to our common unitholders for 2018 and 2019:

Payment Date	Per Unit Cash Distributions		Total Cash Distributions		Total Cash Distributions to Affiliates (a)
			(in thousands)
February 14, 2018	$	0.21	$	2,498	$	1,599
May 15, 2018		0.21		2,506		1,604
August 14, 2018		0.21		2,506		1,604
November 14, 2018		0.21		2,509		1,606
Total 2018 Distributions	$	0.84	$	10,019	$	6,413
February 14, 2019	$	0.21	$	2,510	$	1,606
May 15, 2019 (b)		0.21		2,531		1,622
Total 2019 Distributions (to date)	$	0.42	$	5,041	$	3,228

(a)	64% of the Partnership's outstanding common units at March 31, 2019 were held by affiliates.
(b)	First quarter 2019 distribution was declared and will be paid in the second quarter of 2019.

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

Payment Date	Total Cash Distributions		Total Paid-in-Kind Distributions		Total Distributions
			(in thousands)
November 14, 2018 (a)	$	1,412	$	—	$	1,412
Total 2018 Distributions	$	1,412	$	—	$	1,412
February 14, 2019	$	1,033	$	—	$	1,033
May 15, 2019 (b)		1,033		—		1,033
Total 2019 Distributions (to date)	$	2,066	$	—	$	2,066

(a)	This distribution represents the period from May 29, 2018 (date of preferred unit issuance) through September 30, 2018.
(b)	First quarter 2019 distribution will be paid in the second quarter of 2019.

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 March 31, 2019 and December 31, 2018 were $83.1 million and $76.1 million, respectively, and are reflected as long-term debt on the Unaudited Condensed Consolidated Balance Sheets. Debt issuance costs are reported as debt issuance costs, net on the Unaudited Condensed Consolidated Balance Sheets and totaled $1.1 million and $1.3 million at March 31, 2019 and December 31, 2018, respectively. 

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, 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.

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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 5.98% and 6.02% for the three months ended March 31, 2019 and 4.74% and 5.63% for the three months ended March 31, 2018. 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 March 31, 2019 and 2018 was $1.2 million and $1.8 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 March 31, 2019, our leverage ratio was 3.4 to 1.0 and our interest coverage ratio was 4.8 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 March 31, 2019.

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

Cash Flows

The following table sets forth a summary of the net cash and cash equivalents and restricted cash provided by (used in) operating, investing, and financing activities for the three months ended March 31, 2019 and 2018.

	Three Months Ended March 31,
	2019			2018
	(in thousands)
Net cash (used in) provided by operating activities	$	(12,250	)	$	6,783
Net cash (used in) provided by investing activities		(351	)		1,899
Net cash provided by (used in) financing activities		3,286			(6,573	)
Effect of exchange rates on cash		104			(377	)
Net (decrease) increase in cash and cash equivalents and restricted cash	$	(9,211	)	$	1,732

Net cash (used in) provided by operating activities. Net operating cash outflows for the three months ended March 31, 2019 were $12.3 million, consisting of a net income of $1.4 million plus non-cash expenses of $1.6 million, which was offset by net changes in working capital of $15.3 million. Non-cash expenses included depreciation, amortization and accretion, and equity-based compensation expense, among others. The net change in working capital includes a net increase of $21.9 million in accounts receivable partially offset by a net increase of approximately $6.6 million in current liabilities. During periods of revenue growth, changes in working capital typically reduce operating cash flows, based on the fact that we pay our employees before we collect our accounts receivable from our customers. During the first quarter of 2019, we experienced a significant increase in inspector headcount that required the use of working capital. In addition, as described above under “Overview”, the collection of approximately $12.1 million of accounts receivable has been delayed as a result of the bankruptcy of our customer PG&E.

Net operating cash inflows for the three months ended March 31, 2018 were $6.8 million, consisting of a net income of $1.0 million plus non-cash expenses of $0.4 million and net changes in working capital of $5.4 million. Non-cash expenses included depreciation, amortization and accretion, and gain on asset disposals, net, among others. The change in working capital includes a net decrease of $1.6 million in accounts receivable, a net decrease of $0.7 million in prepaid expenses and other and a net increase of $3.1 million in current liabilities. 

Net cash (used in) provided by investing activities. Net cash outflows from investing activities for the three months ended March 31, 2019 were $0.4 million, consisting primarily of the purchase of equipment to support our nondestructive examination business and costs associated with a new software system for payroll and human resources management that we are in the process of implementing.

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Cash provided by investing activities during the three months ended March 31, 2018 includes proceeds of $4.0 million from the sale of our Pecos, Texas saltwater disposal facility, partially offset by capital expenditures of approximately $2.1 million. Capital expenditures during the three months ended March 31, 2018 consisted primarily of costs to rebuild our Orla, Texas facility, which was subsequently sold in May 2018, and costs to complete the gathering system at our Williams, North Dakota facility. 

Net cash provided by (used in) financing activities. Financing cash inflows for the three months ended March 31, 2019 primarily consisted of $7.0 million of borrowings on our revolving credit facility to fund working capital needs of our Pipeline Inspection business. Financing cash outflows for the three months ended March 31, 2019 primarily consisted of $2.5 million of common unit distributions and $1.0 million of preferred unit distributions.

Financing cash outflows for the three months ended March 31, 2018 primarily consisted of $2.5 million of distributions to common unitholders and a $4.0 million payment on our revolving credit facility.

Working Capital

Our working capital (defined as net current assets less net current liabilities) was $48.3 million at March 31, 2019. Our Pipeline Inspection and Pipeline & Process Services segments have substantial working capital needs as they generally pay their inspectors and field personnel on a weekly basis, but typically receive payment from their customers 45 to 90 days after the services have been performed. Please read “Risk Factors — Risks Related to Our Business — The working capital needs of the Pipeline Inspection segment are substantial, 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, 2018.”

As described above under “Overview”, we had accounts receivable of $12.1 million at January 29, 2019 from PG&E, which represents a pre-petition claim in PG&E’s bankruptcy filing, that remains uncollected as of March 31, 2019. Although we do not believe it is probable that we will not be able to collect the full amount of these pre-petition receivables, the timing of collection of these receivables is unknown. We believe that we have sufficient liquidity, in the form of cash on hand and available capacity on our revolving credit facility, to meet our working capital needs while the PG&E bankruptcy process runs its course. However, the delay in collecting these receivables has required us to maintain a larger outstanding debt balance on the revolving credit facility than otherwise would have been required and leaves us with less flexibility to pursue growth opportunities than we otherwise would have enjoyed.  

Capital Expenditures

We generally have small capital expenditure requirements compared to many other master limited partnerships. Our Water Services segment 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. Our Pipeline Inspection segment does not generally require significant capital expenditures, other than in the nondestructive examination service line, which has acquired field equipment to support its growing revenues. Our Pipeline & Process Services segment has both maintenance and growth capital needs for heavy equipment and vehicles in order to perform hydrostatic testing and other integrity procedures. Our partnership agreement requires that we categorize our capital expenditures as either maintenance capital expenditures or expansion capital expenditures. 

● Maintenance capital expenditures are those cash expenditures that will enable us to maintain our operating capacity or operating income over the long-term. Maintenance capital expenditures include expenditures to maintain equipment reliability, integrity, and safety, as well as to address environmental laws and regulations. Maintenance capital expenditures were $0.1 million for the three months ended March 31, 2019 and 2018.

● 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 $0.3 million and $1.9 million for the three months ended March 31, 2019 and 2018, respectively.

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.

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Contractual Obligations

Contractual obligations as reported in our Annual Report on Form 10-K for the year ended December 31, 2018 had not changed significantly as of March 31, 2019. See Note 9 for disclosures of our lease commitments.

Off-Balance Sheet Arrangements

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

Critical Accounting Policies

There have been no material changes in our critical accounting policies and procedures during the three months ended March 31, 2019. 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, 2018.

Recent Accounting Standards

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

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

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

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

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 2016-13 – Financial Instruments – Credit Losses in June 2016, which replaces the current “incurred loss” methodology for recognizing credit losses with an “expected loss” methodology. This guidance affects trade receivables, financial assets and certain other instruments that are not measured at fair value through net income. The amendments in this ASU are effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. We are currently evaluating the impact this ASU will have on our Unaudited Condensed Consolidated Financial Statements.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

There have been no material changes to our exposure to market risk since December 31, 2018.

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.

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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 March 31, 2019 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. During late 2018, we signed agreements with a software provider and with a system integration advisor under which we will implement a new software system for payroll and human resources management. We expect to implement the new system on January 1, 2020 and will develop, test, and apply internal control procedures related to this payroll and human resources management system as deemed necessary.

PART II – OTHER INFORMATION

Item1.   Legal Proceeding

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 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, the plaintiff filed a motion for conditional class certification. CEM-TIR subsequently filed pleadings opposing the motion. On January 25, 2019, the court denied the plaintiff’s motion for conditional class certification. The court is in the process of rescheduling a hearing on defendant’s motion for a scheduling order and compel mediation.

Sun Mountain LLC v. TIR-PUC

On February 27, 2019, Sun Mountain LLC (“Sun Mountain”), a subcontractor of TIR-PUC, filed a lawsuit alleging that TIR-PUC failed to pay invoices amounting to approximately $3.5 million for services subcontracted to Sun Mountain under TIR-PUC’s agreement to provide services to Pacific Gas and Electric Company. Sun Mountain filed the action in Federal District Court for the Northern District of Oklahoma. TIR-PUC denies that such amounts are owed, as conditions to TIR-PUC’s obligation to make the payments have not been met. The full amount of these invoices is included within accounts payable on the accompanying Consolidated Balance Sheets at March 31, 2019 and December 31, 2018. No estimate of potential loss can be determined at this time and TIR-PUC denies the claims.

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.

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We are not a party to any other material pending or overtly threatened legal or governmental proceedings, other than proceedings and claims that arise in the ordinary course and are incidental to our business.

Item 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, 2018.

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

None.

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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 Amended and Restated Agreement of Limited Partnership of Cypress Energy Partners, L.P. dated as of January 21, 2014 (incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed on January 27, 2014)
3.2	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)
3.3	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)
3.4	Certificate of Limited Partnership of Cypress Energy Partners, L.P. (incorporated by reference to Exhibit 3.7 of our Registration Statement on Form S-1/A filed on December 17, 2013)
3.5	Certificate of Formation of Cypress Energy Partners GP, LLC (incorporated by reference to Exhibit 3.5 of our Registration Statement on Form S-1/A filed on December 17, 2013)
10.1	First Amendment to the Cypress Energy Partners, L.P. 2013 Long-Term Incentive Plan (incorporated by reference to Exhibit 99.1 of our Current Report on Form 8-K filed on March 18, 2019)
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 Accounting 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 Accounting 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 May 13, 2019.

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

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