Cypress Environmental Partners (CELPQ) 10-Q 2019 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(MARK ONE)

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

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 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	(I.R.S. Employer
incorporation or organization)	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 every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  Yes ☒     No ☐  

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

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

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

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

As of November 5, 2019, the registrant had 12,067,482 common units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:     None.

CYPRESS ENERGY PARTNERS, L.P.

Table of Contents

		Page
PART I – FINANCIAL INFORMATION
ITEM 1.	Unaudited Condensed Consolidated Financial Statements	5
	Unaudited Condensed Consolidated Balance Sheets as of September 30, 2019 and December 31, 2018	5
	Unaudited Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2019 and 2018	6
	Unaudited Condensed Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended September 30, 2019 and 2018	7
	Unaudited Condensed Consolidated Statements of Owners’ Equity for the Nine Months Ended September 30, 2019 and 2018	8
	Unaudited Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2019 and 2018	10
	Notes to the Unaudited Condensed Consolidated Financial Statements	11
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
ITEM 3.	Quantitative and Qualitative Disclosures about Market Risk	47
ITEM 4.	Controls and Procedures	47
PART II – OTHER INFORMATION
ITEM 1.	Legal Proceedings	47
ITEM 1A.	Risk Factors	48
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	48
ITEM 3.	Defaults upon Senior Securities	48
ITEM 4.	Mine Safety Disclosures	48
ITEM 5.	Other Information	48
ITEM 6.	Exhibits	49
SIGNATURES		50

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;

● “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 General Partner;

● “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 November 5, 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; and

● “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 September 30, 2019 and December 31, 2018

(in thousands)

	September 30,			December 31,
	2019			2018
ASSETS
Current assets:
Cash and cash equivalents	$	12,735		$	15,380
Trade accounts receivable, net		69,672			48,789
Prepaid expenses and other		958			1,396
Total current assets		83,365			65,565
Property and equipment:
Property and equipment, at cost		25,394			23,988
Less:  Accumulated depreciation		13,134			11,266
Total property and equipment, net		12,260			12,722
Intangible assets, net		20,737			22,759
Goodwill		50,334			50,294
Finance lease right-of-use assets, net		596			—
Operating lease right-of-use assets		3,068			—
Debt issuance costs, net		869			1,260
Other assets		513			253
Total assets	$	171,742		$	152,853
LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable	$	7,191		$	4,848
Accounts payable - affiliates		4,429			4,060
Accrued payroll and other		17,996			12,276
Income taxes payable		902			737
Finance lease obligations		167			90
Operating lease obligations		453			—
Total current liabilities		31,138			22,011
Long-term debt		80,929			76,129
Finance lease obligations		366			248
Operating lease obligations		2,551			—
Other noncurrent liabilities		205			178
Total liabilities		115,189			98,566
Commitments and contingencies - Note 7
Owners’ equity:
Partners’ capital:
Common units (12,065 and 11,947 units outstanding at September 30, 2019 and December 31, 2018, respectively)		36,352			34,677
Preferred units (5,769 units outstanding at September 30, 2019 and December 31, 2018)		44,291			44,291
General partner		(25,876	)		(25,876	)
Accumulated other comprehensive loss		(2,515	)		(2,414	)
Total partners’ capital		52,252			50,678
Noncontrolling interests		4,301			3,609
Total owners’ equity		56,553			54,287
Total liabilities and owners’ equity	$	171,742		$	152,853

 See accompanying notes. 

5  

CYPRESS ENERGY PARTNERS, L.P.

Unaudited Condensed Consolidated Statements of Operations

For the Three and Nine Months Ended September 30, 2019 and 2018

(in thousands, except per unit data)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2019			2018			2019			2018
Revenue	$	108,934		$	84,778		$	310,401		$	226,072
Costs of services		93,533			71,870			270,170			194,092
Gross margin		15,401			12,908			40,231			31,980
Operating costs and expense:
General and administrative		6,557			6,064			18,946			17,341
Depreciation, amortization and accretion		1,116			1,124			3,329			3,368
Gain on asset disposals, net		—			(822	)		(23	)		(4,137	)
Operating income		7,728			6,542			17,979			15,408
Other (expense) income:
Interest expense, net		(1,376	)		(1,283	)		(4,102	)		(4,907	)
Debt issuance cost write-off		—			—			—			(114	)
Foreign currency (losses) gains		(47	)		97			138			(354	)
Other, net		82			95			220			302
Net income before income tax expense		6,387			5,451			14,235			10,335
Income tax expense		907			497			1,731			865
Net income		5,480			4,954			12,504			9,470
Net income attributable to noncontrolling interests		634			289			692			673
Net income attributable to partners / controlling interests		4,846			4,665			11,812			8,797
Net income attributable to preferred unitholder		1,033			1,045			3,099			1,412
Net income attributable to common unitholders	$	3,813		$	3,620		$	8,713		$	7,385
Net income per common limited partner unit:
Basic	$	0.32		$	0.30		$	0.72		$	0.62
Diluted	$	0.26		$	0.26		$	0.65		$	0.59
Weighted average common units outstanding:
Basic		12,065			11,940			12,030			11,924
Diluted		18,350			18,141			18,207			14,970

See accompanying notes.

6  

CYPRESS ENERGY PARTNERS, L.P.

Unaudited Condensed Consolidated Statements of Comprehensive Income

For the Three and Nine Months Ended September 30, 2019 and 2018

(in thousands)

	Three Months Ended					Nine Months Ended
	September 30					September 30
	2019		2018			2019			2018
Net income	$	5,480	$	4,954		$	12,504		$	9,470
Other comprehensive income (loss) - foreign currency translation		34		(71	)		(101	)		61
Comprehensive income	$	5,514	$	4,883		$	12,403		$	9,531
Comprehensive income attributable to preferred unitholders		1,033		1,045			3,099			1,412
Comprehensive income attributable to noncontrolling interests		634		289			692			673
Comprehensive income attributable to common unitholders	$	3,847	$	3,549		$	8,612		$	7,446

See accompanying notes.

7  

CYPRESS ENERGY PARTNERS, L.P.

Unaudited Condensed Consolidated Statements of Owners’ Equity

For the Nine Months Ended September 30, 2019 and 2018

(in thousands)

	Nine Months Ended September 30, 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
Net income for the period April 1, 2019 through June 30, 2019		4,333			1,033			—			—			277			5,643
Foreign currency translation adjustment		—			—			—			(63	)		—			(63	)
Distributions		(2,531	)		(1,033	)		—			—			—			(3,564	)
Equity-based compensation		174			—			—			—			—			174
Taxes paid related to net share settlement of equity-based compensation		(1	)		—			—			—			—			(1	)
Owners’ equity at June 30, 2019		34,820			44,291			(25,876	)		(2,549	)		3,667			54,353
Net income for the period July 1, 2019 through September 30, 2019		3,813			1,033			—			—			634			5,480
Foreign currency translation adjustment		—			—			—			34			—			34
Distributions		(2,534	)		(1,033	)		—			—			—			(3,567	)
Equity-based compensation		303			—			—			—			—			303
Taxes paid related to net share settlement of equity-based compensation		(50	)		—			—			—			—			(50	)
Owners’ equity at September 30, 2019	$	36,352		$	44,291		$	(25,876	)	$	(2,515	)	$	4,301		$	56,553

8  

	Nine Months Ended September 30, 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
Net income for the period April 1, 2018 through June 30, 2018		3,040			367			—			—			149			3,556
Issuance of preferred units, net		—			43,269			—			—			—			43,269
Foreign currency translation adjustment		—			—			—			30			—			30
Distributions		(2,506	)		—			—			—			—			(2,506	)
Equity-based compensation		335			—			—			—			—			335
Taxes paid related to net share settlement of equity-based compensation		(1	)		—			—			—			—			(1	)
Owners’ equity at June 30, 2018		33,852			43,636			(25,876	)		(2,545	)		4,302			53,369
Net income for the period July 1, 2018 through September 30, 2018		3,620			1,045			—			—			289			4,954
Issuance of preferred units, net		—			(10	)		—			—			—			(10	)
Foreign currency translation adjustment		—			—			—			(71	)		—			(71	)
Distributions		(2,506	)		—			—			—			(985	)		(3,491	)
Equity-based compensation		361			—			—			—			—			361
Taxes paid related to net share settlement of equity-based compensation		(61	)		—			—			—			—			(61	)
Owners’ equity at September 30, 2018	$	35,266		$	44,671		$	(25,876	)	$	(2,616	)	$	3,606		$	55,051

See accompanying notes.

9  

CYPRESS ENERGY PARTNERS, L.P.

Unaudited Condensed Consolidated Statements of Cash Flows

For the Nine Months Ended September 30, 2019 and 2018

(in thousands)

	Nine Months Ended September 30
	2019			2018
Operating activities:
Net income	$	12,504		$	9,470
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and accretion		4,153			4,186
Gain on asset disposals, net		(23	)		(4,137	)
Interest expense from debt issuance cost amortization		391			429
Debt issuance cost write-off		—			114
Equity-based compensation expense		746			908
Equity in earnings of investee		(84	)		(169	)
Distributions from investee		75			113
Foreign currency (gains) losses, net		(138	)		354
Changes in assets and liabilities:
Trade accounts receivable		(20,879	)		(9,395	)
Prepaid expenses and other		121			891
Accounts payable and accounts payable - affiliates		2,288			(1,117	)
Accrued payroll and other		5,735			5,246
Income taxes payable		166			62
Net cash provided by operating activities		5,055			6,955
Investing activities:
Proceeds from fixed asset disposals		39			12,762
Purchases of property and equipment		(1,518	)		(5,466	)
Net cash (used in) provided by investing activities		(1,479	)		7,296
Financing activities:
Issuance of preferred units, net of issuance costs		—			43,259
Borrowings on credit facility		7,800			—
Repayments of credit facility and long-term debt		(3,000	)		(60,771	)
Repayments on finance lease obligations		(139	)		(8	)
Debt issuance cost payments		—			(1,327	)
Taxes paid related to net share settlement of equity-based compensation		(209	)		(131	)
Distributions		(10,674	)		(8,501	)
Net cash used in financing activities		(6,222	)		(27,479	)
Effect of exchange rates on cash		1			11
Net decrease in cash and cash equivalents and restricted cash equivalents		(2,645	)		(13,217	)
Cash and cash equivalents (including restricted cash equivalents of $551 at December 31, 2018 and $490 at December 31, 2017), beginning of period		15,931			24,998
Cash and cash equivalents (including restricted cash equivalents of $551 at September 30, 2019 and September 30, 2018), end of period	$	13,286		$	11,781
Non-cash items:
Accounts payable excluded from capital expenditures	$	453		$	75
Acquisitions of finance leases included in liabilities	$	338		$	335

See accompanying notes.

10  

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

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

The Pipeline & Process Services segment (formerly our Integrity Services segment) generates revenue primarily by providing essential environmental services including hydrostatic testing services and chemical cleaning to energy companies and pipeline construction companies 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 Environmental 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 environmental 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 September 30, 2019 and for the three and nine months ended September 30, 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. All 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.

11  

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

Significant Accounting Policies

Our significant accounting policies are consistent with those disclosed in Note 2 to our audited financial statements as of and for the year ended December 31, 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 included the addition of right-of-use assets and associated lease liabilities to our Unaudited Condensed Consolidated Balance Sheets, but were immaterial to our Unaudited Condensed Consolidated Statements of Operations and Unaudited Condensed 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. During the second quarter of 2019, we recorded an allowance of $0.1 million against the accounts receivable from a customer of the Environmental Services segment. Also, during the second quarter of 2019, we received $0.1 million from a former customer of the Environmental Services segment on accounts receivable that we had previously written off. As of September 30, 2019 and December 31, 2018, we had an allowance for doubtful accounts of $0.2 million and less than $0.1 million, respectively.

Pacific Gas and Electric Bankruptcy

PG&E Corporation and its wholly-owned subsidiary Pacific Gas and Electric Company (collectively, “PG&E”) filed for bankruptcy protection on January 29, 2019. 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. In October 2019, we reached an agreement to collect $1.7 million of the pre-petition receivables from PG&E under a court-approved program to pay certain pre-petition claims to certain vendors in advance of PG&E's emergence from bankruptcy, which will bring the total remaining pre-petition receivables from PG&E to $10.4 million.

We have continued to provide services to PG&E after the bankruptcy filing and have been receiving prompt payment for these services. We have not recorded an allowance against the accounts receivable from PG&E at September 30, 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.

Sanchez Bankruptcy

Our former customer, Sanchez Energy Corporation and certain of its affiliates (collectively, “Sanchez”) filed for bankruptcy protection in August 2019. As of September 30, 2019, our Unaudited Condensed Consolidated Balance Sheet included $0.5 million of pre-petition accounts receivable from Sanchez. We have recorded an allowance of less than $0.1 million at September 30, 2019 against the accounts receivable from Sanchez. We do not believe it is probable that we will be unable to collect the remaining $0.4 million balance of the pre-petition receivables. However, due to uncertainties associated with the bankruptcy process, we cannot make assurances regarding the ultimate collection of these receivables nor can we make assurances regarding the timing of any such collections.

12  

CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

Accrued Payroll and Other

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

	September 30, 2019		December 31, 2018
	(in thousands)
Accrued payroll	$	15,387	$	9,468
Customer deposits		1,160		1,202
Other		1,449		1,606
	$	17,996	$	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 September 30, 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 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 Consolidated Statements of Operations.

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 Unaudited Condensed Consolidated Financial Statements will continue to be in accordance with Accounting Standards Codification 840). We adopted the new standard on the effective date of January 1, 2019 and used a modified retrospective approach as permitted under ASU 2018-11. The effects of implementing ASU 2016-02 included the addition of right-of-use assets and associated lease liabilities to our Unaudited Condensed Consolidated Balance Sheets, but were immaterial to our Unaudited Condensed Consolidated Statements of Operations and Unaudited Condensed Consolidated Statements of Cash Flows. The cumulative effect adjustment was not material to partners' capital on our Unaudited Condensed Consolidated Balance Sheet. Upon adoption, we recorded operating lease right-of-use assets of $3.5 million and current and noncurrent operating lease obligations of $0.5 million and $3.0 million, respectively. Liabilities recorded as a result of this standard are excluded from the definition of indebtedness under our credit facility, and therefore do not adversely impact the leverage ratio under our credit facility.

13  

CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

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

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

The FASB issued ASU 2018-15 – Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract in August 2018. This guidance requires a customer in a cloud computing arrangement to follow the internal use software guidance in ASC 350-40 to determine which costs should be capitalized as assets or expensed as incurred. The amendments in this ASU are effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. We plan to adopt this guidance prospectively from the date of adoption (January 1, 2020) and do not believe this new guidance will have a material impact 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 provided up to $90.0 million in borrowing capacity, subject to certain limitations. The Credit Agreement contains an accordion feature that allowed us to increase the borrowing capacity to $110.0 million if new lenders joined the facility. In October 2019, two new lenders joined the facility, and on October 25, 2019, we accordingly increased the total borrowing capacity to $110.0 million. The three-year Credit Agreement matures May 29, 2021. The obligations under the Credit Agreement are secured by a first priority lien on substantially all of our assets. The credit agreement as it existed prior to the May 29, 2018 amendment will hereinafter be referred to as the “Previous Credit Agreement” or, together with the Credit Agreement, as the “Credit Agreements”.

Outstanding borrowings at September 30, 2019 and December 31, 2018 were $80.9 million and $76.1 million, respectively, and are reflected as long-term debt on the Unaudited Condensed Consolidated Balance Sheets. We also had $0.5 million of finance lease liabilities at September 30, 2019 that count as indebtedness under the Credit Agreement. Debt issuance costs are reported as debt issuance costs, net on the Unaudited Condensed Consolidated Balance Sheets and total $0.9 million and $1.3 million at September 30, 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.

All borrowings under the Credit Agreement bear interest, at our option, on a leveraged based grid pricing at (i) a base rate plus a margin of 1.5% to 3.0% per annum (“Base Rate Borrowing”) or (ii) an adjusted LIBOR rate plus a margin of 2.5% to 4.0% per annum (“LIBOR Borrowings”). The applicable margin is determined based on the leverage ratio of the Partnership, as defined in the Credit Agreement.

The interest rate on our borrowings ranged between 5.54% and 6.02% for the nine months ended September 30, 2019 and 4.74% and 5.95% for the nine months ended September 30, 2018. As of September 30, 2019, the interest rate in effect on our outstanding borrowings was 5.54%. 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, including commitment fees, was $1.3 million and $1.1 million for the three months ended September 30, 2019 and 2018, respectively. Interest paid, including commitment fees, was $3.7 million and $4.6 million for the nine months ended September 30, 2019 and 2018, respectively.

The Credit Agreement contains various customary covenants and restrictive provisions. The Credit Agreement also requires maintenance of certain financial covenants at each quarter end, including a leverage ratio (as defined in the Credit Agreement) of not more than 4.0 to 1.0 and an interest coverage ratio (as defined in the Credit Agreement) of not less than 3.0 to 1.0. At September 30, 2019, our leverage ratio was 2.8 to 1.0 and our interest coverage ratio was 6.4 to 1.0, pursuant to the Credit Agreement. Upon the occurrence and during the continuation of an event of default, subject to the terms and conditions of the Credit Agreement, the lenders may declare any outstanding principal, together with any accrued and unpaid interest, to be immediately due and payable and may exercise the other remedies set forth or referred to in the Credit Agreement. We were in compliance with all debt covenants as of September 30, 2019.

14  

CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

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. As of September 30, 2019, we had $8.5 million of unused borrowing capacity under the Credit Agreement. In October 2019, our unused borrowing capacity increased to $28.5 million when two new lenders joined the Credit Agreement.

4. Income Taxes

The income tax expense reported in our Unaudited Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2019 and 2018 differs from the statutory tax rate of 21% 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.

As a publicly-traded partnership, we are subject to a statutory requirement that 90% of our total gross income represents “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.

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.

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. We 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 attributable to noncontrolling interests represents 49% of the income generated by Brown and 51% of the income 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.

15  

CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

Basic net income per common limited partner unit is calculated as net income attributable to common unitholders divided by the basic weighted average common units outstanding. Diluted net income per common limited partner unit includes the net income attributable to preferred unitholder and the dilutive effect of the potential conversion of the preferred units and the dilutive effect of the unvested equity compensation.

The following table summarizes the calculation of the basic net income per common limited partner unit for the three and nine months ended September 30, 2019 and 2018:

	Three Months Ended September 30				Nine Months Ended September 30
	2019		2018		2019		2018
	(in thousands, except per unit data)
Net income attributable to common unitholders	$	3,813	$	3,620	$	8,713	$	7,385
Weighted average common units outstanding		12,065		11,940		12,030		11,924
Basic net income per common limited partner unit	$	0.32	$	0.30	$	0.72	$	0.62

The following table summarizes the calculation of the diluted net income per common limited partner unit for the three and nine months ended September 30, 2019 and 2018:

	Three Months Ended September 30				Nine Months Ended September 30
	2019		2018		2019		2018
	(in thousands, except per unit data)
Net income attributable to common unitholders	$	3,813	$	3,620	$	8,713	$	7,385
Net income attributable to preferred unitholder		1,033		1,045		3,099		1,412
Net income attributable to limited partners	$	4,846	$	4,665	$	11,812	$	8,797
Weighted average common units outstanding		12,065		11,940		12,030		11,924
Effect of dilutive securities:
Weighted average preferred units outstanding		5,769		5,769		5,769		2,628
Long-term incentive plan unvested units		516		431		408		418
Diluted weighted average common units outstanding		18,350		18,140		18,207		14,970
Diluted net income per common limited partner unit	$	0.26	$	0.26	$	0.65	$	0.59

Cash Distributions

The following table summarizes the cash distributions declared and 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		0.21		2,531		1,622
August 14, 2019		0.21		2,534		1,624
November 14, 2019 (b)		0.21		2,534		1,627
Total 2019 Distributions (to date)	$	0.84	$	10,109	$	6,479

(a) 64% of the Partnership’s outstanding common units at September 30, 2019 were held by affiliates.

(b) Third quarter 2019 distribution was declared and will be paid in the fourth quarter of 2019.

16  

CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

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

Payment Date	Cash Distributions		Paid-in-Kind Distributions		Total Distributions
	(in thousands)
November 14, 2018 (a)	$	1,412	$	—	$	1,412
Total 2018 Distributions	$	1,412	$	—	$	1,412
February 14, 2019	$	1,033	$	—	$	1,033
May 15, 2019		1,033		—		1,033
August 14, 2019		1,033		—		1,033
November 14, 2019 (b)		1,033		—		1,033
Total 2019 Distributions	$	4,132	$	—	$	4,132

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

(b) Third quarter 2019 distribution was declared and will be paid in the fourth 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 in the form of time-based unit awards (“Service Units”), performance-based unit awards (“Performance Units”) and market-based unit awards (“Market Units”). We recorded expense of $0.7 million and $0.9 million during the nine months ended September 30, 2019 and 2018, respectively, related to the Unit awards.

Time-Based Unit Awards – The majority of the Service Units vest in three tranches, with one-third of the units vesting three years from the grant date, one-third vesting four years from the grant date, and one-third vesting five years from the grant date, contingent only on the continued service of the recipients through the vesting dates. However, certain of the Service Units have different, and typically shorter, vesting periods. The fair value of the Service Units is determined based on the quoted market value of the publicly-traded common units at the grant date, adjusted for a discount to reflect the fact that distributions are not paid on the Service Units during the vesting period. We recognize compensation expense on a straight-line basis over the vesting period of the grant. We account for forfeitures when they occur. Total unearned compensation associated with the Service Units at September 30, 2019 was $2.7 million with an average remaining life of 2.1 years. The following table summarizes the activity of the Service Units for the nine months ended September 30, 2019 and 2018:

	Nine Months Ended September 30,
	2019					2018
				Weighted					Weighted
				Average					Average
				Grant					Grant
	Number			Date Fair		Number			Date Fair
	of Units			Value / Unit		of Units			Value / Unit
Unvested units at January 1		873,061		$	5.83		587,014		$	8.56
Units granted		201,306		$	4.40		396,484		$	3.24
Units vested		(140,556	)	$	8.56		(68,038	)	$	14.10
Units forfeited		(61,774	)	$	6.22		(44,383	)	$	5.76
Unvested units at September 30		872,037		$	5.04		871,077		$	5.85

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

17  

CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

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

Total unearned compensation associated with the Performance Units at September 30, 2019 was $0.4 million with an average remaining life of 2.88 years. The unvested Performance Units at September 30, 2019 also include one grant of 72,046 units that vests in November 2021, contingent upon the recipient meeting certain specified performance targets. The following table summarizes the activity of the Performance Units for the nine months ended September 30, 2019 and 2018:

	Nine Months Ended September 30,
	2019					2018
				Weighted					Weighted
				Average					Average
				Grant					Grant
	Number			Date Fair		Number			Date Fair
	of Units			Value / Unit		of Units			Value / Unit
Unvested units at January 1		101,648		$	5.11		77,495		$	7.75
Units granted		89,402		$	4.19		—		$	—
Units vested		(6,167	)	$	6.54		(7,184	)	$	8.49
Units forfeited		(24,310	)	$	6.45		(40,709	)	$	8.49
Unvested units at September 30		160,573		$	4.34		29,602		$	6.54

18  

CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

Market-Based Unit Awards – In the third quarter of 2019, we granted Units that are subject to market conditions in addition to the service condition (the “Market Units”). One-half of the Market Units will vest in April 2022, April 2023, April 2024, or not at all, depending on the market value of our common units relative to specified targets on those dates. These Market Units had an estimated fair value on the grant date of $3.51 per unit and will be expensed over a derived service period of 2.73 years. One-half of the Market Units will vest in April 2022, April 2023, April 2024, or not at all, depending on the yield on our common units relative to specified targets on those dates. These Market Units granted in 2019 had an estimated fair value on the grant date of $3.58 per unit and will be expensed over a derived service period of 2.73 years. Compensation expense is recognized on a straight-line basis over a derived service period, regardless of when, if ever, the market condition is satisfied. Total unearned compensation associated with the Market Units at September 30, 2019 was $0.3 million with an average remaining life of 2.5 years. The following table summarizes the activity of the Market Units for the nine months ended September 30, 2019:

	Nine Months Ended September 30, 2019
				Weighted
				Average
				Grant
	Number			Date Fair
	of Units			Value / Unit
Unvested units at January 1		—
Units granted		89,403		$	3.54
Units vested		—
Units forfeited		(875	)	$	3.54
Unvested units at September 30		88,528		$	3.54

6. Related-Party Transactions

Omnibus Agreement and Other Support from Holdings

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

● our payment of 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; and

● 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.

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

In an effort to simplify this arrangement so it will be easier for investors to understand, in November 2019, with the approval of the Conflicts Committee of the Board of Directors, we and Holdings agreed to terminate the management fee provisions of the Omnibus Agreement, effective December 31, 2019. Beginning on January 1, 2020, the executive management services and other general and administrative expenses that Holdings currently incurs and charges to us via the annual administrative fee will be charged directly to us as they are incurred. Under our current cost structure, we expect these direct expenses to be lower than the annual administrative fee that we are currently paying, although we expect to experience more variability in our quarterly general and administrative expense when we are incurring the expenses directly than when we paid a consistent administrative fee each quarter.

Alati Arnegard, LLC

The Partnership provides management services to a 25% owned company, Alati Arnegard, LLC (“Arnegard”), which is part of the Environmental Services segment. We recorded earnings from this investment of less than $0.1 million and $0.2 million for the nine months ended September 30, 2019 and 2018, respectively. These earnings are recorded in other, net in the Unaudited Condensed Consolidated Statements of Operations and equity in earnings of investee in the Unaudited Condensed Consolidated Statements of Cash Flows. Management fee revenue earned from Arnegard is included in revenue in the Unaudited Condensed Consolidated Statements of Operations and totaled $0.5 million for each of the nine months ended September 30, 2019 and 2018. Accounts receivable from Arnegard totaled $0.1 million at both September 30, 2019 and December 31, 2018, and is included in trade accounts receivable, net on the Unaudited Condensed Consolidated Balance Sheets. Our investment in Arnegard was $0.3 million at September 30, 2019 and December 31, 2018, and is included in other assets on the Unaudited Condensed Consolidated Balance Sheets.

19  

CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

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 and a Director of our General Partner. CF Inspection allows us to offer various services to clients that require the services of an approved Women’s Business Enterprise (“WBE”), as CF Inspection is certified as a Women’s Business Enterprise by the Supplier Clearinghouse in California and as a National Women’s Business Enterprise by the Women’s Business Enterprise National Council. We own 49% of CF Inspection and Cynthia A. Field, an affiliate of Holdings and a Director of our General Partner, owns the remaining 51% of CF Inspection. For the nine months ended September 30, 2019, CF Inspection, which is part of the Pipeline Inspection segment, represented approximately 3.0% 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 that are secured with short-term security deposits (reflected as restricted cash equivalents in our Unaudited Condensed Consolidated Statements of Cash Flows) totaling $0.6 million at September 30, 2019 and December 31, 2018. These amounts are included in prepaid expenses and other on the Unaudited Condensed Consolidated Balance Sheets.

Compliance Audit Contingencies

Certain customer master service agreements (“MSA’s”) offer our customers the opportunity to perform periodic compliance audits, which include the examination of the accuracy of our invoices. Should our invoices be determined to be inconsistent with the MSA, 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 September 30, 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 alleged he was a non-exempt employee of CEM TIR and that he and other potential class members were not paid overtime in compliance with the FLSA. The plaintiff sought to proceed as a collective action and to receive unpaid overtime and other monetary damages, including attorney’s fees. The Partnership, TIR LLC, CEM TIR and Cypress Energy Partners – Texas, LLC denied the claims.

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

20  

CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

Sun Mountain LLC v. TIR-PUC

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

Other

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

8. Sale of Saltwater Disposal Facilities

In 2018, we sold our subsidiaries Cypress Energy Partners – Orla SWD, LLC (“Orla”) and Cypress Energy Partners – Pecos SWD, LLC (“Pecos”), each of which owned a saltwater disposal facility in Texas, in separate transactions to unrelated parties for a combined $12.2 million of cash proceeds and a royalty interest in the future revenues of the Pecos facility. We recorded a combined gain on these transactions of $3.6 million during the nine months ended September 30, 2018, which represented the excess of the cash proceeds over the net book value of the assets sold. These gains are reported within gain on asset disposals, net in our Unaudited Condensed Consolidated Statements of Operations. The net book value of the assets sold included $5.0 million of allocated goodwill, calculated based on the estimated fair value of the Orla and Pecos facilities relative to the estimated fair value of the Environmental Services reporting unit as a whole. This calculation is considered Level 3 and the fair values included in this calculation were determined utilizing estimated discounted cash flows of the Orla and Pecos facilities and the Environmental Services reporting unit as a whole as of the date of sale. We used the proceeds from these transactions to reduce our outstanding debt.

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.

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.

21  

CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

Operating Leases

Our operating leases include leases for office space and land lease agreements for four of our saltwater disposal facilities. Our lease for our office space headquarters constitutes $2.9 million of our Operating ROU asset at September 30, 2019 of $3.1 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 continue 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 September 30, 2019, the weighted average remaining lease term and weighted average discount rate for our operating leases was 5.4 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 Unaudited Condensed Consolidated Balance Sheet at September 30, 2019.

Our operating lease obligations at September 30, 2019 with terms that are greater than one year mature as follows (in thousands):

Remainder of 2019	$	109
2020		680
2021		679
2022		679
2023		679
Thereafter		720
Total lease payments	$	3,546
Less imputed interest		(542	)
Total operating lease obligation	$	3,004

Finance Leases

Our finance leases primarily include leases for vehicles. As of September 30, 2019, the weighted average remaining lease term and weighted average discount rate for our finance leases was 3.2 years and 5.9%, 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 Unaudited Condensed Consolidated Balance Sheet at September 30, 2019. Our finance lease obligations at September 30, 2019 with terms that are greater than one year mature as follows (in thousands):

Remainder of 2019	$	50
2020		193
2021		184
2022		124
2023		33
Thereafter		—
Total lease payments	$	584
Less imputed interest		(51	)
Total finance lease obligation	$	533

22  

CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

Lease Expense Components

During the nine months ended September 30, 2019, our lease expense consists of the following components (in thousands):

	Nine Months Ended
	September 30, 2019
Finance lease expense:
Amortization of right-of-use assets	$	124
Interest on lease liabilities		23
Operating lease expense		507
Short-term lease expense - general and administrative		77
Short-term lease expense - costs of services (a)		2,397
Variable lease expense		7
Sublease income - related parties		(25	)
Total lease expense	$	3,110

(a) These short-term lease expenses are included in costs of services within our Unaudited Condensed Consolidated Statement of Operations. These expenses include 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 (“Environmental Services”).

Pipeline Inspection – We generate revenue in this segment primarily by providing essential environmental services including inspection and integrity services on a variety of infrastructure assets including midstream pipelines, gathering systems, and distribution systems. Services include non-destructive examination, 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. Revenue and costs in this segment may be subject to seasonal variations and interim activity may not be indicative of yearly activity, considering that many of our customers develop yearly operating budgets and enter into contracts with us for work to be performed during the remainder of the year. Additionally, inspection work throughout the United States during the winter months (especially in the northern states) may be hampered or delayed due to inclement weather, thus affecting our revenue and costs. During the three months ended September 30, 2019 and 2018, we recognized $0.2 million and $0.5 million of revenue, respectively, on services performed in previous years. We had constrained recognition of this revenue until the expiration of a contract provision that had given the customer the opportunity to reopen negotiation of the fee paid for the services. As of September 30, 2019 and December 31, 2018, we recognized a refund liability of $0.4 million for revenue associated with such variable consideration. In October 2019, we received a signed contract modification from one of our customers for a price increase that is retroactive to June 2019. We will record $0.6 million as a catch-up adjustment to revenue in the fourth quarter of 2019 related to this retroactive price increase.

Pipeline & Process Services – This segment provides essential environmental services including hydrostatic testing services and chemical cleaning to energy companies and pipeline construction companies of newly-constructed and existing pipelines and related infrastructure. We generally charge our customers in this segment on a fixed-bid basis, depending on the size and length of the pipeline being tested, the complexity of services provided, and the utilization of our work force and equipment. Our results in this segment are driven primarily by the number of field personnel that perform services for our customers and the fees that we charge for those services, which depend on the type and number of field personnel used on a particular project, the type of equipment used and the fees charged for the utilization of that equipment, and the nature and duration of the project. Revenue and costs in this segment may be subject to seasonal variations and interim activity may not be indicative of yearly activity, considering that many of our customers develop yearly operating budgets and enter into contracts with us for work to be performed during the remainder of the year. Additionally, field work during the winter months may be hampered or delayed due to inclement weather. Revenue during the nine months ended September 30, 2018 included $0.3 million associated with additional billings on a project that we completed in the fourth quarter of 2017 (we recognized the revenue upon receipt of customer acknowledgment of the additional fees).

23  

CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

Environmental 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 nine months ended September 30, 2019, 92% of our volumes from our wholly-owned facilities were produced water and 41% of our volumes from our wholly-owned facilities were delivered via ten pipelines, including two that we constructed and own. Of the disposal volumes from Arnegard, a 25% owned company, 95% of the volumes were produced water and 61% were delivered via pipeline during the nine months ended September 30, 2019. Our saltwater disposal facilities provide essential environmental 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.

24  

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 to net income before income tax expense.

	Pipeline Inspection			Pipeline & Process Services			Environmental Services			Other			Total
	(in thousands)
Three months ended September 30, 2019
Revenue	$	99,684		$	6,199		$	3,051		$	—		$	108,934
Costs of services		88,597			4,146			790			—			93,533
Gross margin		11,087			2,053			2,261			—			15,401
General and administrative		4,890			612			731			324			6,557
Depreciation, amortization and accretion		556			144			412			4			1,116
Operating income (loss)	$	5,641		$	1,297		$	1,118		$	(328	)		7,728
Interest expense, net														(1,376	)
Foreign currency gains														(47	)
Other, net														82
Net income before income tax expense													$	6,387
Three months ended September 30, 2018
Revenue	$	77,606		$	3,881		$	3,325		$	(34	)	$	84,778
Costs of services		68,350			2,592			962			(34	)		71,870
Gross margin		9,256			1,289			2,363			—			12,908
General and administrative		4,422			592			774			276			6,064
Depreciation, amortization and accretion		571			143			410			—			1,124
Gains on asset disposals, net		(21	)		(32	)		(769	)		—			(822	)
Operating income (loss)	$	4,284		$	586		$	1,948		$	(276	)		6,542
Interest expense, net														(1,283	)
Foreign currency loss														97
Other, net														95
Net income before income tax expense					��								$	5,451

25  

CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

	Pipeline Inspection			Pipeline & Process Services			Envirionmental Services			Other			Total
	(in thousands)
Nine months ended September 30, 2019
Revenue	$	289,919		$	12,554		$	7,928		$	—		$	310,401
Costs of services		259,015			8,893			2,262			—			270,170
Gross margin		30,904			3,661			5,666			—			40,231
General and administrative		14,101			1,842			2,269			734			18,946
Depreciation, amortization and accretion		1,667			430			1,221			11			3,329
Gain on asset disposal, net		—			(23	)		—			—			(23	)
Operating income (loss)	$	15,136		$	1,412		$	2,176		$	(745	)		17,979
Interest expense, net														(4,102	)
Foreign currency gains														138
Other, net														220
Net income before income tax expense													$	14,235
Nine months ended September 30, 2018
Revenue	$	205,938		$	11,307		$	8,861		$	(34	)	$	226,072
Costs of services		183,305			7,840			2,981			(34	)		194,092
Gross margin		22,633			3,467			5,880			—			31,980
General and administrative		12,313			1,715			2,402			911			17,341
Depreciation, amortization and accretion		1,717			449			1,202			—			3,368
Gain on asset disposals, net		(21	)		(77	)		(4,039	)		—			(4,137	)
Operating income (loss)	$	8,624		$	1,380		$	6,315		$	(911	)		15,408
Interest expense, net														(4,907	)
Debt issuance cost write-off														(114	)
Foreign currency loss														(354	)
Other, net														302
Net income before income tax expense													$	10,335
Total Assets
September 30, 2019	$	132,360		$	12,072		$	22,757		$	4,553		$	171,742
December 31, 2018	$	116,239		$	10,972		$	24,281		$	1,361		$	152,853

26  

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

The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control, including, among other things, the risk factors discussed in “Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 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 Services (“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 (“Environmental 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 Environmental 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 environmental services to energy and utility companies. We offer essential services that help protect the environment and ensure sustainability. As a master limited partnership traded on the New York Stock Exchange (“NYSE”) (NYSE: CELP) we hold ourselves to the high standards of the Securities and Exchange Commission, Environmental Protection Agency, Department of Transportation, various state regulators, and the NYSE.

We provide a wide range of environmental services including independent inspection, integrity, and support services for pipeline and energy infrastructure owners and operators and public utilities. We also provide water pipelines, hydrocarbon recovery, disposal, and water treatment services.

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 Environmental 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.

In all of our business segments, we work closely with our customers to help them protect the environment, property, and people. Our wide range of services also help our clients comply with increasingly complex federal and state environmental and safety rules and regulations. Our environmental services are required services under various federal and state laws.

Many clients encourage supplier diversity, and some encourage the use of minority-owned businesses as suppliers. To support clients seeking a minority qualified vendor solution we have formed a strategic partnership with CF Inspection that allows us to offer our services to clients that require the services of an approved Women’s Business Enterprise (“WBE”). CF Inspection is certified as a WBE by the Supplier Clearinghouse in California and as a National Women’s Business Enterprise by the Women’s Business Enterprise National Council.

Cypress has a very experienced management team and board of directors with decades of industry experience and expertise.

Ownership

As of September 30, 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; and

● 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.

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

27  

In an effort to simplify this arrangement so it will be easier for investors to understand, in November 2019, with the approval of the Conflicts Committee of the Board of Directors, we and Holdings agreed to terminate the management fee provisions of the Omnibus Agreement, effective December 31, 2019. Beginning on January 1, 2020, the executive management services and other general and administrative expenses that Holdings currently incurs and charges to us via the annual administrative fee will be charged directly to us as they are incurred. Under our current cost structure, we expect these direct expenses to be lower than the annual administrative fee that we are currently paying, although we expect to experience more variability in our quarterly general and administrative expense when we are incurring the expenses directly than when we paid a consistent administrative fee each quarter.

Pipeline Inspection

We generate revenue in the Pipeline Inspection segment primarily by providing essential environmental services including inspection and integrity services on a variety of infrastructure assets including midstream pipelines, gathering systems, and distribution systems. Services include non-destructive examination, 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 who 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, the age and condition of customers’ assets (including pipelines, gas plants, compression stations, storage facilities, and gathering and distribution systems), and 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 environmental services including hydrostatic testing services and chemical cleaning to energy companies and pipeline construction companies on newly-constructed and existing pipelines and related infrastructure. We generally charge our customers in this segment on a fixed-bid basis, with the price depending on the size and length of the pipeline being tested, the complexity of services provided, and the utilization of our work force and equipment. Our results in this segment are driven primarily by our ability to win bids for projects and the resulting utilization of our personnel and equipment.

Environmental Services

We generate revenue in the Environmental 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 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 sale 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 can decrease based on the following factors, among others: an increase in pipeline water as operators control the flow of pipeline water and an increase in residual oil recovered in saltwater by producers prior to delivering the saltwater to us for treatment.

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.

28  

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 Unaudited Condensed 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 have been receiving prompt 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. In October 2019, we reached an agreement to collect $1.7 million of the pre-petition receivables from PG&E under this program in advance of PG&E’s emergence from bankruptcy, which will bring the total remaining pre-petition receivables from PG&E to $10.4 million.

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.

In September 2019, PG&E filed a Plan of Reorganization with the Court. PG&E has stated that it hopes to emerge from bankruptcy on or before June 30, 2020. Another party has filed a competing Plan of Reorganization with the Court. Both of these plans call for the payment in full, with interest, of all pre-petition trade claims. These plans are subject to review and approval by the Court. An active market exists for the purchase and sale of pre-petition claims.

We have not recorded an allowance against the accounts receivable from PG&E at September 30, 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.

Sanchez Bankruptcy

Our former customer, Sanchez Energy Corporation and certain of its affiliates (collectively, “Sanchez”) filed for bankruptcy protection in August 2019. As of September 30, 2019, our Unaudited Condensed Consolidated Balance Sheet included $0.5 million of pre-petition accounts receivable from Sanchez. We believe, based on the nature of the services we have provided to Sanchez, that we have the right to file liens on Sanchez’s assets, and we have filed and perfected such liens. The liens secure $0.4 million of the pre-petition accounts receivable. We do not believe it is probable that we will be unable to collect the $0.4 million of pre-petition receivables that are subject to these liens. We have recorded an allowance of less than $0.1 million at September 30, 2019 against the remaining accounts receivable from Sanchez. 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.

Outlook

Overall

Revenues of our Pipeline Inspection segment increased from $77.6 million during the three months ended September 30, 2018 to $99.7 million during the three months ended September 30, 2019, an increase of 28%. This increase was due to high demand for our services and increased business development efforts. During the fourth quarter of 2018, we began work on the largest contract in the 16-year history of TIR. The headcount for this project peaked in the second quarter of 2019, and we expect the project to continue, with declining headcounts, throughout the remainder of 2019. Gross margins in this segment increased from $9.3 million during the three months ended September 30, 2018 to $11.1 million during the three months ended September 30, 2019, an increase of 20%. During the three months ended September 30, 2019, we generated an increased percentage of our revenue from inspection services (due in part to the pipeline inspection project that represented the largest contract award in our history), which typically carry lower margins than integrity services. The resulting decrease in gross margin percentage was partially offset by increased activity in our business that serves public utility customers, as these services typically generate higher margins than our other inspection services.

Revenues of our Pipeline & Process Services segment increased from $3.9 million during the three months ended September 30, 2018 to $6.2 million during the three months ended September 30, 2019, an increase of 60%. Revenues of this segment benefitted from several large projects that were scheduled to begin in the first quarter of 2019, but were delayed by adverse weather. Gross margins in this segment increased from $1.3 million during the three months ended September 30, 2018 to $2.1 million during the three months ended September 30, 2019, an increase of 59%.

29  

Revenues of our Environmental Services segment decreased from $3.3 million during the three months ended September 30, 2018 to $3.1 million during the three months ended September 30, 2019, a decrease of 8%. The decrease in revenues was due to a decrease of 0.3 million barrels in the volume of water processed, a decrease in pipeline transportation fees, and lower crude oil prices on our oil sales.

In 2018, Holdings completed two acquisitions to further broaden our suite of environmental services that we offer both the municipal water and energy industries. 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 purchase of the acquired assets would move us into several new lines of work, including water treatment, in-line inspection (“ILI”), 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 high resolution magnetic flux leakage ILI technology, capable of helping pipeline owners and operators better manage the integrity of their assets in both the energy and municipal water industries.

The U.S. Pipeline and Hazardous Materials Safety Administration ("PHMSA") recently finalized a rule that significantly revises certain aspects of the hazardous liquid pipeline safety regulations codified at Title 49 Code of Federal Regulations Parts 190-199. Nearly nine years in the making, the final rule is PHMSA's response to several significant hazardous liquid pipeline accidents that have occurred in recent years, most notably the 2010 crude oil spill near Marshall, Michigan. The final rule also addresses 2011 and 2016 outstanding congressional mandates and U.S. Government Accountability Office recommendations.

A version of this rule was initially scheduled for publication in the Federal Register in the last week of the prior presidential administration in 2017. It was held back as a result of the regulatory freeze and subsequent deregulatory review by the Trump administration, which removed certain of the requirements of the prior rule in the recent final rule.

Effective July 1, 2020, this rule expands requirements to address risks to pipelines outside of environmentally sensitive and populated areas, requiring the performance of periodic integrity assessments and the use of leak detection systems for all regulated hazardous liquids pipelines (except for offshore gathering and regulated rural gathering lines). In addition, the rule makes changes to the integrity management requirements, including revising data integration requirements and emphasizing the use of in-line inspection technology.

The long-term increasing demand for environmental services such as pipeline inspection, integrity services, and water solutions remains strong due to our nation’s aging pipeline infrastructure, and we believe we continue to be well-positioned to capitalize on these opportunities. Our ownership interests continue to remain fully aligned with our unitholders, as our General Partner and insiders collectively own 76% of our total common and preferred units.

Pipeline Inspection

Demand has been strong for our Pipeline Inspection segment. We operate in a very large market, with more than 3,000 customer prospects who require federally and/or state-mandated inspection and integrity services. During the third quarter of 2018, we signed the largest contract in the 16-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. 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. Although the first and fourth quarters of each year are typically slower as a result of seasonal fluctuations in activity, we entered the fourth quarter of 2019 with a strong backlog of new projects.

Environmental Services

We continue to focus on produced water and pipeline water whenever possible. During the nine months ended September 30, 2019, 92% of our volumes from our wholly-owned facilities were produced water and 41% of our volumes from our wholly-owned facilities were delivered via ten pipelines, including two that we constructed and own. Of the disposal volumes from Arnegard, a 25% owned company, 95% of the volumes were produced water and 61% were delivered via pipeline during the nine months ended September 30, 2019. 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.

30  

Results of Operations

Consolidated Results of Operations

The following table summarizes our Unaudited Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2019 and 2018:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(in thousands)
Revenue	$	108,934		$	84,778		$	310,401		$	226,072
Costs of services		93,533			71,870			270,170			194,092
Gross margin		15,401			12,908			40,231			31,980
Operating costs and expense:
General and administrative - segment		6,233			5,788			18,212			16,430
General and administrative - corporate		324			276			734			911
Depreciation, amortization and accretion		1,116			1,124			3,329			3,368
Gain on asset disposals, net		—			(822	)		(23	)		(4,137	)
Operating income		7,728			6,542			17,979			15,408
Other (expense) income:
Interest expense, net		(1,376	)		(1,283	)		(4,102	)		(4,907	)
Debt issuance cost write-off		—			—			—			(114	)
Foreign currency gains (losses)		(47	)		97			138			(354	)
Other, net		82			95			220			302
Net income before income tax expense		6,387			5,451			14,235			10,335
Income tax expense		907			497			1,731			865
Net income		5,480			4,954			12,504			9,470
Net income attributable to noncontrolling interests		634			289			692			673
Net income attributable to partners / controlling interests		4,846			4,665			11,812			8,797
Net income attributable to preferred unitholder		1,033			1,045			3,099			1,412
Net income attributable to common unitholders	$	3,813		$	3,620		$	8,713		$	7,385

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 nine months ended September 30, 2018 to the nine months ended September 30, 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 nine months ended September 30, 2019 and 2018 was $81.6 million and $105.9 million, respectively. The average interest rate on our borrowings increased from 5.42% during the nine months ended September 30, 2018 to 5.97% during the nine months ended September 30, 2019.

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

31  

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 Consolidated Statements of Operations. The net foreign currency gains during the nine months ended September 30, 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 $0.9 million for the nine months ended September 30, 2018 to $1.7 million for the nine months ended September 30, 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 represents “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations, and Internal Revenue Service pronouncements), determined on a calendar-year basis. Income generated by taxable corporate subsidiaries is excluded from this calculation. During the nine months ended September 30, 2019, substantially all of our gross income, which consisted of approximately $245.5 million of revenue (exclusive of the income generated by our taxable corporate subsidiaries), represented “qualifying income”.

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

Net income attributable to preferred unitholder. On May 29, 2018, we issued and sold $43.5 million of preferred equity. The holder of the preferred units is entitled to an annual return of 9.5% on this investment. The earnings attributable to the preferred unitholder reflects this return.

32  

Segment Operating Results

Pipeline Inspection

The following table summarizes the operating results of the Pipeline Inspection segment for the three months ended September 30, 2019 and 2018.

	Three Months Ended September 30,
	2019		% of Revenue	2018			% of Revenue	Change			% Change
	(in thousands, except average revenue and inspector data)
Revenue	$	99,684		$	77,606			$	22,078		28.4%
Costs of services		88,597			68,350				20,247		29.6%
Gross margin		11,087	11.1%		9,256		11.9%		1,831		19.8%
General and administrative		4,890	4.9%		4,422		5.7%		468		10.6%
Depreciation and amortization		556	0.6%		571		0.7%		(15	)	(2.6)%
Gains on asset disposals, net		—			(21	)	0.0%		21		(100.0)%
Operating income	$	5,641	5.7%	$	4,284		5.5%	$	1,357		31.7%
Operating Data
Average number of inspectors		1,540			1,263				277		21.9%
Average revenue per inspector per week	$	4,925		$	4,675			$	250		5.3%
Revenue variance due to number of inspectors								$	17,927
Revenue variance due to average revenue per inspector								$	4,151

Revenue. Revenue increased $22.1 million during the three months ended September 30, 2019 compared to the three months ended September 30, 2018, due to an increase in the average number of inspectors engaged (an increase of 277 inspectors accounting for $17.9 million of the revenue increase) and an increase in the average revenue billed per inspector (accounting for $4.2 million of the revenue increase). Revenue attributable to our U.S. operations increased $22.3 million during the three months ended September 30, 2019 compared to the three months ended September 30, 2018, due to increased activity by our clients and increased business development efforts. During the fourth quarter of 2018, we began work on the largest contract award in our history. The headcount for this pipeline inspection project peaked in the second quarter of 2019, and we expect the project to continue, with declining headcounts, throughout 2019. Revenues of our subsidiary that serves public utility customers increased by $3.0 million during the three months ended September 30, 2019 compared to the three months ended September 30, 2018. The increase in average revenue per inspector is due to changes in customer mix. Fluctuations in the average revenue per inspector are expected, given that we charge different rates for different types of inspectors and different types of inspection services.

Costs of services. Costs of services increased $20.2 million during the three months ended September 30, 2019 compared to the three months ended September 30, 2018, primarily related to an increase in the average number of inspectors employed during the period.

Gross margin. Gross margin increased $1.8 million during the three months ended September 30, 2019 compared to the three months ended September 30, 2018. The gross margin percentage was 11.1% in 2019, compared to 11.9% in 2018. The decrease in gross margin percentage is due to changes in the mix of services provided. During the three months ended September 30, 2019, we generated an increased percentage of our revenue from inspection services, which typically carry lower margins than integrity services. This was due in part to an inspection project that represented the largest contract award in our history. The resulting decrease in gross margin percentage was partially offset by increased activity in our business that serves public utility customers, as these services typically generate higher margins than our other inspection services.

Gross margin during the three months ended September 30, 2019 and 2018 benefited from the fact that we recognized $0.2 million and $0.5 million, respectively, of revenue on services performed in previous years. We had constrained recognition of this revenue until the expiration of a contract provision that had given the customer the opportunity to reopen negotiation of the fee paid for the services.

In October 2019, we received a signed contract modification from one of our customers for a price increase that is retroactive to June 2019. We will record $0.6 million as catch-up adjustment to revenue in the fourth quarter of 2019 related to this retroactive price increase. In 2018, we received the signed contract modification for this annual price increase during the three months ended September 30, 2018, and we recognized the related revenue during the three months ended September 30, 2018.

General and administrative. General and administrative expenses increased by $0.5 million during the three months ended September 30, 2019 compared to the three months ended September 30, 2018. Compensation expense increased approximately $0.1 million due primarily to increased incentive compensation expense resulting from the improved performance of the business. Professional fees increased by $0.3 million, due to legal costs associated with certain employment-related lawsuits and claims. 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.

33  

Depreciation, amortization and accretion. Depreciation, amortization and accretion expense during the three months ended September 30, 2019 was not significantly different from depreciation, amortization and accretion expense during the three months ended September 30, 2018.

Operating income. Operating income increased by $1.4 million during the three months ended September 30, 2019 compared to the three months ended September 30, 2018, due primarily to an increase in gross margin, which was partially offset by an increase in general and administrative expense.

The following table summarizes the operating results of the Pipeline Inspection segment for the nine months ended September 30, 2019 and 2018.

	Nine Months Ended September 30,
	2019		% of Revenue	2018			% of Revenue	Change			% Change
	(in thousands, except average revenue and inspector data)
Revenue	$	289,919		$	205,938			$	83,981		40.8%
Costs of services		259,015			183,305				75,710		41.3%
Gross margin		30,904	10.7%		22,633		11.0%		8,271		36.5%
General and administrative		14,101	4.9%		12,313		6.0%		1,788		14.5%
Depreciation and amortization		1,667	0.6%		1,717		0.8%		(50	)	(2.9)%
Gains on asset disposals, net		—			(21	)	0.0%		21		(100.0)%
Operating income	$	15,136	5.2%	$	8,624		4.2%	$	6,512		75.5%
Operating Data
Average number of inspectors		1,548			1,160				388		33.4%
Average revenue per inspector per week	$	4,802		$	4,552			$	250		5.5%
Revenue variance due to number of inspectors								$	72,662
Revenue variance due to average revenue per inspector								$	11,319

Revenue. Revenue of the Pipeline Inspection segment increased $84.0 million during the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018, due to an increase in the average number of inspectors engaged (an increase of 388 inspectors accounting for $72.7 million of the revenue increase) and an increase in the average revenue billed per inspector (accounting for $11.3 million of the revenue increase). Revenue attributable to our U.S. operations increased $85.0 million during the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018, due to increased activity by our clients and increased business development efforts. During the fourth quarter of 2018, we began work on the largest contract award in our history. The headcount for this pipeline inspection project peaked in the second quarter of 2019, and we expect the project to continue, with declining headcounts, throughout 2019. Revenues of our subsidiary that serves public utility customers increased by $12.6 million during the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018. These increases were partially offset by a decrease of $1.0 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.

Costs of services. Costs of services increased $75.7 million during the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018, primarily related to an increase in the average number of inspectors employed during the period.

Gross margin. Gross margin increased $8.3 million during the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018. The gross margin percentage was 10.7% in 2019, compared to 11.0% in 2018. The decrease in gross margin percentage is due to changes in the mix of services provided. During the nine months ended September 30, 2019, we generated an increased percentage of our revenue from inspection services, which typically carry lower margins than integrity services. This was due in part to an inspection project that represented the largest contract award in our history. The resulting decrease in gross margin percentage was partially offset by increased activity in our business that serves public utility customers, as these services typically generate higher margins than our other inspection services.

34  

Gross margin during the nine months ended September 30, 2019 and 2018 benefited from the fact that we recognized $0.2 million and $0.5 million, respectively, of revenue on services performed in previous years. We had constrained recognition of this revenue until the expiration of a contract provision that had given the customer the opportunity to reopen negotiation of the fee paid for the services.

In October 2019, we received a signed contract modification from one of our customers for a price increase that is retroactive to June 2019. We will record $0.6 million as a catch-up adjustment to revenue in the fourth quarter of 2019 related to this retroactive price increase. In 2018, we received the signed contract modification for this annual price increase during the nine months ended September 30, 2018, and we recognized the related revenue during the nine months ended September 30, 2018.

General and administrative. General and administrative expenses increased by $1.8 million during the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018. Compensation expense increased by $0.9 million due to an increase in personnel to support our growing businesses and to increased incentive compensation expense resulting from the improved performance of our business. Professional fees increased by $0.6 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 $0.3 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 nine months ended September 30, 2019 was not significantly different from depreciation, amortization and accretion expense during the nine months ended September 30, 2018.

Operating income. Operating income increased by $6.5 million during the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018, due primarily to the increase in gross margin, partially offset by an increase in general and administrative expenses.

Pipeline & Process Services

The following table summarizes the results of the Pipeline & Process Services segment for the three months ended September 30, 2019 and 2018.

	Three Months Ended September 30,
	2019		% of Revenue	2018			% of Revenue	Change		% Change
	(in thousands, except average revenue and inspector data)
Revenue	$	6,199		$	3,881			$	2,318	59.7%
Costs of services		4,146			2,592				1,554	60.0%
Gross margin		2,053	33.1%		1,289		33.2%		764	59.3%
General and administrative		612	9.9%		592		15.3%		20	3.4%
Depreciation, amortization and accretion		144	2.3%		143		3.7%		1	0.7%
Gain on asset disposals, net		—			(32	)	(0.8)%		32	(100.0)%
Operating income	$	1,297	20.9%	$	586		15.1%	$	711	121.3%
Operating Data
Average number of field personnel		29			23				6	26.1%
Average revenue per field personnel per week	$	16,264		$	12,839			$	3,425	26.7%
Revenue variance due to number of field personnel								$	1,283
Revenue variance due to average revenue per field personnel								$	1,035

Revenue. Revenue increased $2.3 million during the three months ended September 30, 2019 compared to the three months ended September 30, 2018. Revenues of this segment benefitted from several large projects that were scheduled to begin earlier in 2019, but were delayed by adverse weather.

Costs of services. Cost of services increased by $1.6 million during the three months ended September 30, 2019 compared to the three months ended September 30, 2018, due to an increase in revenues.

Gross margin. Gross margin increased by $0.8 million during the three months ended September 30, 2019 compared to the three months ended September 30, 2018. The increase in gross margin was due to an increase in revenue.

35  

General and administrative. General and administrative expenses primarily include compensation expense for office employees and general office expenses. These expenses remained relatively consistent from the three months ended September 30, 2019 compared to the three months ended September 30, 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 September 30, 2019 was not significantly different from depreciation, amortization and accretion expense during the three months ended September 30, 2018.

Operating income. Operating income increased by $0.7 million during the three months ended September 30, 2019 compared to the three months ended September 30, 2018. The increase was primarily due to higher gross margin of $0.8 million.

The following table summarizes the results of the Pipeline & Process Services segment for the nine months ended September 30, 2019 and 2018.

	Nine Months Ended September 30,
	2019			% of Revenue	2018			% of Revenue	Change			% Change
	(in thousands, except average revenue and inspector data)
Revenue	$	12,554			$	11,307			$	1,247		11.0%
Costs of services		8,893				7,840				1,053		13.4%
Gross margin		3,661		29.2%		3,467		30.7%		194		5.6%
General and administrative		1,842		14.7%		1,715		15.2%		127		7.4%
Depreciation, amortization and accretion		430		3.4%		449		4.0%		(19	)	(4.2)%
Gain on asset disposals, net		(23	)	(0.2)%		(77	)	(0.7)%		54		(70.1)%
Operating income	$	1,412		11.2%	$	1,380		12.2%	$	32		2.3%
Operating Data
Average number of field personnel		28				22				6		27.3%
Average revenue per field personnel per week	$	11,496			$	13,178			$	(1,682	)	(12.8)%
Revenue variance due to number of field personnel									$	2,690
Revenue variance due to average revenue per field personnel									$	(1,443	)

Revenue. Revenue increased by approximately $1.3 million during the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018. The increase in revenue was due to increased success in winning bids for large projects. Revenue during the nine months ended September 30, 2018 included $0.3 million associated with additional billings on a project that we completed in the fourth quarter of 2017 (we recognized the revenue upon receipt of customer acknowledgment of the additional fees).

Costs of services. Cost of services increased $1.1 million during the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018, due to an increase in revenues.

Gross margin. Gross margin increased $0.2 million during the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018. The decrease is gross margin percentage was due in part to $0.3 million of revenue recognized during the nine months ended September 30, 2018 associated with additional billings on a project that we completed in the fourth quarter of 2017.

General and administrative. General and administrative expenses primarily include compensation expense for office employees and general office expenses. These expenses increased by $0.1 million during the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018, due primarily to an increase in employee compensation expenses.

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 nine months ended September 30, 2019 was not significantly different from depreciation, amortization and accretion expense during the nine months ended September 30, 2018.

36  

Operating income. Operating income increased by less than $0.1 million during the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018. This increase was due to higher gross margins of $0.2 million partially offset by an increase of $0.1 million in general and administrative expenses.

Environmental Services

The following table summarizes the operating results of the Environmental Services segment for the three months ended September 30, 2019 and 2018.

	Three Months Ended September 30,
	2019		% of Revenue	2018			% of Revenue	Change			% Change
	(in thousands, except per barrel data)
Revenue	$	3,051		$	3,325			$	(274	)	(8.2)%
Costs of services		790			962				(172	)	(17.9)%
Gross margin		2,261	74.1%		2,363		71.1%		(102	)	(4.3)%
General and administrative		731	24.0%		774		23.3%		(43	)	(5.6)%
Depreciation, amortization and accretion		412	13.5%		410		12.3%		2		0.5%
Gain on asset disposals, net		—			(769	)	(23.1)%		769		(100.0)%
Operating income	$	1,118	36.6%	$	1,948		58.6%	$	(830	)	(42.6)%
Operating Data
Total barrels of saltwater disposed		3,989			4,276				(287	)	(6.7)%
Average revenue per barrel disposed (a)	$	0.76		$	0.78			$	(0.02	)	(2.6)%
Revenue variance due to barrels disposed								$	(214	)
Revenue variance due to revenue per barrel								$	(60	)

(a) Average revenue per barrel disposed is calculated by dividing revenues (which includes disposal revenues, residual oil sales and management fees) by the total barrels of saltwater disposed.

Revenue. Revenue decreased by $0.3 million during the three months ended September 30, 2019 compared to the three months ended September 30, 2018. The decrease in revenues was due to a decrease of 0.3 million barrels in the volume of water processed, a decrease in pipeline transportation fees, and lower crude oil prices on our oil sales. The decrease in volume resulted from a slowdown in exploration and production activity in the areas near our facilities.

The average revenue per barrel decreased during the three months ended September 30, 2019 compared to the three months ended September 30, 2018, due in part to the fact that transportation fees on piped water represented a smaller percentage of the total volumes in 2019 than in 2018, and in part to a scheduled decrease in pricing on pipeline transportation fees into one of our facilities and due in part to lower crude oil prices on our oil sales.

Costs of services. Costs of services decreased by $0.2 million during the three months ended September 30, 2019 compared to the three months ended September 30, 2018. The decrease was due to a decrease of $0.1 million in variable expenses such as chemicals and utilities as a result in the decrease in volumes processed and a decrease of $0.1 million in repairs and maintenance expense.

Gross margin. Gross margin decreased by $0.1 million during the three months ended September 30, 2019 compared to the three months ended September 30, 2018, due primarily to a $0.3 million decrease in revenue, partially offset by a $0.2 million decrease in cost of services.

General and administrative. General and administrative expenses include general overhead expenses such as salary costs, insurance, property taxes, royalty expenses, and other miscellaneous expenses. These expenses remained relatively consistent from the three months ended September 30, 2019 compared to the three months ended September 30, 2018.

Depreciation, amortization and accretion. Depreciation, amortization and accretion expense during the three months ended September 30, 2019 was not significantly different from depreciation, amortization and accretion expense during the three months ended September 30, 2018.

37  

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

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

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

Operating income. Operating income decreased by $0.8 million during the three months ended September 30, 2019 compared to the three months ended September 30, 2018. The decrease in operating income was primarily due to $0.8 million of gains on asset disposals during the three months ended September 30, 2018.

The following table summarizes the operating results of the Environmental Services segment for the nine months ended September 30, 2019 and 2018.

	Nine Months Ended September 30,
	2019		% of Revenue	2018			% of Revenue	Change			% Change
	(in thousands, except per barrel data)
Revenue	$	7,928		$	8,861			$	(933	)	(10.5)%
Costs of services		2,262			2,981				(719	)	(24.1)%
Gross margin		5,666	71.5%		5,880		66.4%		(214	)	(3.6)%
General and administrative		2,269	28.6%		2,402		27.1%		(133	)	(5.5)%
Depreciation, amortization and accretion		1,221	15.4%		1,202		13.6%		19		1.6%
Gain on asset disposals, net		—			(4,039	)	(45.6)%		4,039		(100.0)%
Operating income	$	2,176	27.4%	$	6,315		71.3%	$	(4,139	)	(65.5)%
Operating Data
Total barrels of saltwater disposed		10,322			10,928				(606	)	(5.5)%
Average revenue per barrel disposed (a)	$	0.77		$	0.81			$	(0.04	)	(4.9)%
Revenue variance due to barrels disposed								$	(500	)
Revenue variance due to revenue per barrel								$	(433	)

(a) Average revenue per barrel disposed is calculated by dividing revenues (which includes disposal revenues, residual oil sales and management fees) by the total barrels of saltwater disposed.

Revenue. Revenue decreased by $0.9 million during the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018. Revenues during the nine months ended September 30, 2018 included $0.2 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 $0.7 million during the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018, due to a decrease of 0.5 million barrels in the volume of water processed, a decrease in pipeline transportation fees, and lower prices on our crude oil sales. The decrease in volume resulted from a slowdown in exploration and production activity in the areas near our facilities.

The average revenue per barrel decreased during the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018, due in part 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, due in part to the fact that transportation fees on piped water represented a smaller percentage of the total volumes in 2019 than in 2018, due in part to a scheduled decrease in pricing on pipeline transportation fees into one of our facilities and in part to lower crude oil prices on our oil sales.

Costs of services. Costs of services decreased by $0.7 million during the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018. The decrease was due to a decrease of $0.2 million in variable expenses such as chemicals and utilities as a result of the decrease in volumes processed, a decrease of $0.1 million resulting from the sale in 2018 of our two facilities in Texas, a decrease of $0.2 million in repairs and maintenance expense, and approximately $0.2 million of expense associated with the cleanup and remediation of a saltwater spill at one of our facilities in North Dakota during 2018.

38  

Gross margin. Gross margin decreased during the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018, due primarily to a $0.9 million decrease in revenue, partially offset by a $0.7 million decrease in cost of services.

General and administrative. General and administrative expenses primarily include compensation expense for office employees and general office expenses. These expenses decreased by $0.1 million during the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018, due primarily to a decrease in employee compensation expenses.

Depreciation, amortization and accretion. Depreciation, amortization and accretion expense during the nine months ended September 30, 2019 was not significantly different from depreciation, amortization and accretion expense during the nine months ended September 30, 2018.

Gain on asset disposals, net. During the nine months ended September 30, 2018, we recorded a gain of $1.8 million on the sale of our facility in Orla, Texas and a gain of $1.8 million on the sale of our facility in Pecos, Texas. During the nine months ended September 30, 2018, we received proceeds of $0.4 million from the settlement of litigation related to lightning strikes that occurred in 2017 at our facilities in Orla, Texas and Grassy Butte, North Dakota. This litigation related to the non-performance of certain equipment we had purchased to protect the facilities. During the nine months ended September 30, 2018, we collected $0.1 million of insurance proceeds, which represented the final payment on a property damage insurance claim related to the Grassy Butte facility. These gains were partially offset by a loss of $0.1 million on the abandonment of a capital expansion project.

Operating income. Operating income decreased by $4.1 million during the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018. The decrease in operating income was due in part to gains of $4.0 million from asset disposals, partially offset by a loss of $0.1 million on the abandonment of a capital expansion project.

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.

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 similarly titled measures of other companies, thereby diminishing their utility.

39  

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 September 30,				Nine Months ended September 30,
	2019		2018		2019		2018
	(in thousands)
Net income	$	5,480	$	4,954	$	12,504	$	9,470
Add:
Interest expense		1,376		1,283		4,102		4,907
Debt issuance cost write-off		—		—		—		114
Depreciation, amortization and accretion		1,391		1,393		4,155		4,186
Income tax expense		907		497		1,731		865
Equity-based compensation		303		361		746		908
Foreign currency losses		47		—		—		354
Less:
Foreign currency gains		—		97		138		—
Gain on asset disposals, net		—		769		—		4,039
Adjusted EBITDA	$	9,504	$	7,622	$	23,100	$	16,765
Adjusted EBITDA attributable to noncontrolling interests		783		412		1,114		1,076
Adjusted EBITDA attributable to limited partners / controlling interests	$	8,721	$	7,210	$	21,986	$	15,689
Less:
Preferred unit distributions		1,033		—		3,099		—
Cash interest paid, cash taxes paid, maintenance capital expenditures		1,922		1,469		5,604		5,897
Distributable cash flow	$	5,766	$	5,741	$	13,283	$	9,792

Reconciliation of Net Income Attributable to Limited Partners to Adjusted

EBITDA Attributable to Limited Partners and Distributable Cash Flow

	Three Months ended September 30,				Nine Months ended September 30,
	2019		2018		2019		2018
	(in thousands)
Net income attributable to limited partners	$	4,846	$	4,665	$	11,812	$	8,797
Add:
Interest expense attributable to limited partners		1,376		1,283		4,102		4,907
Debt issuance cost write-off attributable to limited partners		—		—		—		114
Depreciation, amortization and accretion attributable to limited partners		1,255		1,277		3,759		3,804
Income tax expense attributable to limited partners		894		490		1,705		844
Equity based compensation attributable to limited partners		303		361		746		908
Foreign currency losses attributable to limited partners		47		—		—		354
Less:
Foreign currency gains attributable to limited partners		—		97		138		—
Gain on asset disposals attributable to limited partners, net		—		769		—		4,039
Adjusted EBITDA attributable to limited partners		8,721		7,210		21,986		15,689
Less:
Preferred unit distributions		1,033		—		3,099		—
Cash interest paid, cash taxes paid and maintenance capital expenditures attributable to limited partners		1,922		1,469		5,604		5,897
Distributable cash flow	$	5,766	$	5,741	$	13,283	$	9,792

40  

Reconciliation of Net Cash Provided by Operating Activities to Adjusted

EBITDA and Distributable Cash Flow

	Nine Months ended September 30,
	2019			2018
	(in thousands)
Cash flows provided by operating activities	$	5,055		$	6,955
Changes in trade accounts receivable, net		20,879			9,395
Changes in prepaid expenses and other		(121	)		(891	)
Changes in accounts payable and accrued liabilities		(8,023	)		(4,129	)
Change in income taxes payable		(166	)		(62	)
Interest expense (excluding non-cash interest)		3,711			4,478
Income tax expense (excluding deferred tax benefit)		1,731			865
Other		34			154
Adjusted EBITDA	$	23,100		$	16,765
Adjusted EBITDA attributable to noncontrolling interests		1,114			1,076
Adjusted EBITDA attributable to limited partners / controlling interests	$	21,986		$	15,689
Less:
Preferred unit distributions		3,099			—
Cash interest paid, cash taxes paid, maintenance capital expenditures		5,604			5,897
Distributable cash flow	$	13,283		$	9,792

41  

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 September 30, 2019, our sources of liquidity included:

● $12.7 million cash on the balance sheet at September 30, 2019;

● available borrowings under our Credit Agreement of $8.5 million at September 30, 2019; and

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

In October 2019, two new lenders joined the Credit Agreement, which increased the total borrowing capacity from $90.0 million to $110.0 million. This increased our unused borrowing capacity from $8.5 million to $28.5 million. At September 30, 2019, we had $81.5 million of borrowings outstanding (inclusive of finance leases). At each quarter end, our borrowing capacity is limited to four times trailing-twelve-month EBITDA (as defined in the Credit Agreement); at September 30, 2019, trailing-twelve-month EBITDA (as defined in the Credit Agreement) was $29.4 million.

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 of our available cash to unitholders of record on the applicable record date.

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

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

42  

The following table summarizes the cash distributions declared and 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		0.21		2,531		1,622
August 14, 2019		0.21		2,534		1,624
November 14, 2019 (b)		0.21		2,534		1,627
Total 2019 Distributions	$	0.84	$	10,109	$	6,479

(a)	64% of the Partnership’s outstanding common units at September 30, 2019 were held by affiliates.
(b)	Third quarter 2019 distribution was declared and will be paid in the fourth quarter of 2019.

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

Payment Date	Cash Distributions		Paid-in-Kind Distributions		Total Distributions
	(in thousands)
November 14, 2018 (a)	$	1,412	$	—	$	1,412
Total 2018 Distributions	$	1,412	$	—	$	1,412
February 14, 2019	$	1,033	$	—	$	1,033
May 15, 2019		1,033		—		1,033
August 14, 2019		1,033		—		1,033
November 14, 2019 (b)		1,033		—		1,033
Total 2019 Distributions	$	4,132	$	—	$	4,132

(a)	This distribution relates to the period from May 29, 2018 (date of preferred unit issuance) through September 30, 2018.
(b)	Third quarter 2019 distribution was declared and will be paid in the fourth 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 provided up to $90.0 million in borrowing capacity, subject to certain limitations. The Credit Agreement contains an accordion feature that allowed us to increase the borrowing capacity to $110.0 million if new lenders joined the facility. In October 2019, two new lenders joined the facility, which increased the total borrowing capacity to $110.0 million. The three-year Credit Agreement matures May 29, 2021. The obligations under the Credit Agreement are secured by a first priority lien on substantially all of our assets. The credit agreement as it existed prior to the May 29, 2018 amendment will hereinafter be referred to as the “Previous Credit Agreement” or, together with the Credit Agreement, as the “Credit Agreements”.

Outstanding borrowings at September 30, 2019 and December 31, 2018 were $80.9 million and $76.1 million, respectively, and are reflected as long-term debt on the Unaudited Condensed Consolidated Balance Sheets. We also had $0.5 million of finance lease liabilities at September 30, 2019 that count as indebtedness under the Credit Agreement. Debt issuance costs are reported as debt issuance costs, net on the Unaudited Condensed Consolidated Balance Sheets and total $0.9 million and $1.3 million at September 30, 2019 and December 31, 2018, respectively.

43  

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.

All borrowings under the Credit Agreement bear interest, at our option, on a leveraged based grid pricing at (i) a base rate plus a margin of 1.5% to 3.0% per annum (“Base Rate Borrowing”) or (ii) an adjusted LIBOR rate plus a margin of 2.5% to 4.0% per annum (“LIBOR Borrowings”). The applicable margin is determined based on the leverage ratio of the Partnership, as defined in the Credit Agreement.

The interest rate on our borrowings ranged between 5.54% and 6.02% for the nine months ended September 30, 2019 and 4.74% and 5.95% for the nine months ended September 30, 2018. As of September 30, 2019, the interest rate in effect on outstanding borrowings was 5.54%. 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, including commitment fees, was $1.3 million and $1.1 million for the three months ended September 30, 2019 and 2018, respectively. Interest paid, including commitment fees, was $3.7 million and $4.6 million for the nine months ended September 30, 2019 and 2018, respectively.

The Credit Agreement contains various customary covenants and restrictive provisions. The Credit Agreement also requires maintenance of certain financial covenants at each quarter end, including a leverage ratio (as defined in the Credit Agreement) of not more than 4.0 to 1.0 and an interest coverage ratio (as defined in the Credit Agreement) of not less than 3.0 to 1.0. At September 30, 2019, our leverage ratio was 2.8 to 1.0 and our interest coverage ratio was 6.4 to 1.0, pursuant to the Credit Agreement. Upon the occurrence and during the continuation of an event of default, subject to the terms and conditions of the Credit Agreement, the lenders may declare any outstanding principal, together with any accrued and unpaid interest, to be immediately due and payable and may exercise the other remedies set forth or referred to in the Credit Agreement. We were in compliance with all debt covenants as of September 30, 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. As of September 30, 2019, we had $8.5 million of unused borrowing capacity under the Credit Agreement. In October 2019, our unused borrowing capacity increased to $28.5 million when two new lenders joined the Credit Agreement.

Cash Flows

The following table sets forth a summary of the net cash provided by (used in) operating, investing, and financing activities for the nine months ended September 30, 2019 and 2018.

	Nine Months Ended September 30
	2019			2018
	(in thousands)
Net cash provided by operating activities	$	5,055		$	6,955
Net cash (used in) provided by investing activities		(1,479	)		7,296
Net cash used in financing activities		(6,222	)		(27,479	)
Effect of exchange rates on cash		1			11
Net decrease in cash and cash equivalents	$	(2,645	)	$	(13,217	)

Net cash provided by operating activities. Net operating cash outflows for the nine months ended September 30, 2019 were $5.1 million, consisting of net income of $12.5 million plus non-cash expenses of $5.1 million, which was partially offset by net changes in working capital of $12.6 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 $20.9 million in accounts receivable, a net decrease of $0.1 million in prepaid expenses and other, partially offset by a net increase of $8.2 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 accounts receivable from our customers. During the nine months ended September 30, 2019, we experienced a significant increase in inspector headcount in our Pipeline Inspection segment 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.

44  

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

Net cash (used in) provided by investing activities. Net cash outflows from investing activities for the nine months ended September 30, 2019 were $1.5 million, consisting primarily of the purchase of equipment to support the nondestructive examination activities of our Pipeline Inspection segment and costs associated with a new software system for payroll and human resources management that we are in the process of implementing.

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

Net cash used in financing activities. Financing cash inflows for the nine months ended September 30, 2019 primarily consisted of $4.8 million of net borrowings on our revolving credit facility to fund working capital needs of our Pipeline Inspection segment. Financing cash outflows for the nine months ended September 30, 2019 primarily consisted of $7.6 million of common unit distributions and $3.1 million of preferred unit distributions.

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

Working Capital

Our working capital (defined as net current assets less net current liabilities) was $52.2 million at September 30, 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”, at September 30, 2019, we had accounts receivable of $12.1 million from PG&E that represents a pre-petition claim in PG&E’s bankruptcy filing. 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. During October 2019, we reached an agreement to collect $1.7 million of the pre-petition receivables from PG&E under a court-approved program to pay certain pre-petition claims to certain vendors in advance of PG&E’s emergence from bankruptcy, which will bring the total remaining pre-petition receivables from PG&E to $10.4 million.

Capital Expenditures

We generally have small capital expenditure requirements compared to many other master limited partnerships. Our Environmental Services segment has minimal capital expenditure requirements for the maintenance of existing saltwater disposal facilities. Our Pipeline Inspection segment does not generally require significant capital expenditures, although we acquire field equipment to support our nondestructive examination activities. 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 $0.2 million and $0.5 million for the three and nine months ended September 30, 2019, respectively, and $0.3 million and $0.6 million for the three and nine months ended September 30, 2018, respectively.

45  

● 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 $1.2 million for the three and nine months ended September 30, 2019, respectively, and $1.3 million and $4.9 million for the three and nine months ended September 30, 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.

Contractual Obligations

Contractual obligations as reported in our Annual Report on Form 10-K for the year ended December 31, 2018 have not changed significantly as of September 30, 2019. See Note 3 for disclosures regarding our revolving credit facility. See Note 9 for disclosures regarding our lease commitments.

Off-Balance Sheet Arrangements

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

Critical Accounting Policies

There have been no material changes in our critical accounting policies and procedures during the nine months ended September 30, 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 Unaudited Condensed 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 Unaudited Condensed Consolidated Balance Sheets with the addition of right-of-use assets and associated lease liabilities, but immaterial to our Unaudited Condensed Consolidated Statements of Operations and Unaudited Condensed 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.

46  

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. In August 2019, The FASB issued a proposal to delay the implementation of this new guidance for smaller reporting companies until fiscal years beginning after December 15, 2022, including interim periods within those fiscal years. The FASB expects to issue a final ASU with their decision in November 2019. We are currently evaluating the impact this ASU will have on our Unaudited Condensed Consolidated Financial Statements.

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

Disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed in Partnership reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed in the Partnership reports filed under the Exchange Act is accumulated and communicated to management, including the Partnership’s Chief Executive Officer and Chief Financial Officer as appropriate, to allow timely decisions regarding required disclosure. Based upon that evaluation, our management, including our Chief Executive Officer and Chief Financial Officer concluded that, as of the end of the period covered by this report, the Partnership’s disclosure controls and procedures were effective to provide reasonable assurance that financial information was processed, recorded and reported accurately.

Changes in Internal Control over Financial Reporting

There was no change in our internal control over financial reporting that occurred during the three months ended September 30, 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

Item 1. Legal Proceedings

Fithian v. TIR LLC

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

47  

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

Sun Mountain LLC v. TIR-PUC

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

Other

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

Item 1A. Risk Factors

Except as set forth below, 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.

In the ordinary course of our business, we may become subject to lawsuits, indemnity, or other claims, which could materially and adversely affect our business, financial condition, results of operations, profitability, cash flows, and growth prospects.

From time to time, we are subject to various claims, lawsuits and other legal proceedings brought or threatened against us in the ordinary course of our business. These actions and proceedings may seek, among other things, compensation for alleged personal injury, workers' compensation, employment discrimination and other employment-related damages, breach of contract, property damage, environmental liabilities, multiemployer pension plan withdrawal liabilities, punitive damages and civil penalties or other losses, liquidated damages, consequential damages, or injunctive or declaratory relief. We have been and may in the future be subject to litigation involving allegations of violations of the Fair Labor Standards Act and state wage and hour laws. In addition, we generally indemnify our customers for claims related to the services we provide and actions we take under our contracts, including claims regarding the Fair Labor Standards Act and state wage and hour laws, and, in some instances, we may be allocated risk through our contract terms for actions by our customers or other third parties.

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

48  

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*	Chief Financial Officer Certification Pursuant to Exchange Act Rule 13a-14(a) or Rule 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1**	Chief Executive Officer Certification Pursuant to Exchange Act Rule 13a-14(b) or Rule 15d-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code, as Adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2**	Chief Financial Officer Certification Pursuant to Exchange Act Rule 13a-14(b) or Rule 15d-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code, as Adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101 INS*	XBRL Instance Document
101 SCH*	XBRL Schema Document
101 CAL*	XBRL Calculation Linkbase Document
101 DEF*	XBRL Definition Linkbase Document
101 LAB*	XBRL Label Linkbase Document
101 PRE*	XBRL Presentation Linkbase Document

* Filed herewith.

** Furnished herewith.

49  

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Tulsa, State of Oklahoma, on November 12, 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 and Principal Accounting Officer

50