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 SeptemberJune 30, 20172018

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

 

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

 

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

 

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

 

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

(Do not check if a smaller reporting company)

Large accelerated filer  Accelerated filer Non-accelerated filer Smaller reporting company Emerging growth company
(Do not check if a smaller reporting 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 NovemberAugust 7, 2017,2018, the registrant had 11,889,95811,933,522 common units outstanding.

 

DOCUMENTS INCORPORATED BY REFERENCE:     None.

 

 

 

 

 

CYPRESS ENERGY PARTNERS, L.P.

 

Table of Contents

 

  Page
PART I – FINANCIAL INFORMATION 
  
ITEM 1.Condensed Consolidated Financial Statements5
   
Condensed Consolidated Balance Sheets as of SeptemberJune 30, 20172018 and December 31, 201620175
   
Condensed Consolidated Statements of Operations for the Three and NineSix Months Ended SeptemberJune 30, 20172018 and 2016201765
   
Condensed Consolidated Statements of Comprehensive Income (Loss) for the Three and NineSix Months Ended SeptemberJune 30, 20172018 and 201620177
   
Condensed Consolidated Statements of Cash Flows for the NineSix Months Ended SeptemberJune 30, 20172018 and 201620178
   
Condensed Consolidated Statement of Owners’ Equity for the NineSix Months Ended SeptemberJune 30, 201720189
   
Notes to the Condensed Consolidated Financial Statements10
   
ITEM 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations3425
   
ITEM 3.Quantitative and Qualitative Disclosures about Market Risk5548
   
ITEM 4.Controls and Procedures5549
   
PART II – OTHER INFORMATION 
ITEM 1.Legal Proceedings56
   
ITEM 1A.1.Risk FactorsLegal Proceedings5649
   
ITEM 1A.Risk Factors50
ITEM 2.Unregistered Sales of Equity Securities and Use of Proceeds5650
   
ITEM 3.Defaults upon Senior Securities5650
   
ITEM 4.Mine Safety Disclosures5650
   
ITEM 5.Other Information5650
   
ITEM 6.Exhibits5751
   
SIGNATURES5852

 

2  

 

 

NAMES OF ENTITIES

 

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

 

References to:

 

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

 

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

 

 CES LLC” refers to Cypress Energy Services, LLC, a wholly owned subsidiary that performs management services for our salt water disposal (“SWD”) facilities, as well as a third party facility;

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

 

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

 

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

 

 Holdings II” refers to Cypress Energy Holdings II, LLC, the owner of 5,610,549 common units, representing 47.2%47.0% of our outstanding common units;

 

 ISIntegrity Services” refers to our Integrity Services business segment;

 

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

 

 PISPipeline Inspection” refers to our Pipeline Inspection Services business segment;

   

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

 

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

 

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

 

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

 

 TIR-PUC” refers to Tulsa Inspection Resources – PUC, LLC, a subsidiary of TIR LLC that has elected to be treated as a corporation for federal income tax purposes; and

 W&ESWater Services” refers to our Water and Environmental Services business segment.

 

3  

 

 

CAUTIONARY REMARKS REGARDING FORWARD-LOOKING STATEMENTS

   

The information discussed in this Quarterly Report on Form 10-Q includes “forward-looking statements.”  These forward-looking statements are identified by their use of terms and phrases such as “may,” “expect,” “estimate,” “project,” “plan,” “believe,” “intend,” “achievable,” “anticipate,” “continue,” “potential,” “should,” “could,” and similar terms and phrases.  Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties and we can give no assurance that such expectations or assumptions will be achieved.  Important factors that could cause actual results to differ materially from those in the forward-looking statements are described under “Item 1A – Risk Factors” and “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 20162017 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 SeptemberJune 30, 20172018 and December 31, 20162017

 (in(in thousands, except unit data)

 

 September 30, December 31, 
 2017 2016  June 30, December 31, 
       2018 2017 
ASSETS                
Current assets:                
Cash and cash equivalents $19,238  $26,693  $10,499  $24,508 
Trade accounts receivable, net  49,945   38,482   47,692   41,693 
Prepaid expenses and other  1,610   1,042   1,040   2,294 
Assets held for sale     2,172 
Total current assets  70,793   66,217   59,231   70,667 
Property and equipment:                
Property and equipment, at cost  20,355   22,459   23,057   22,700 
Less: Accumulated depreciation  8,634   7,840   9,991   9,312 
Total property and equipment, net  11,721   14,619   13,066   13,388 
Intangible assets, net  26,180   29,624   24,114   25,477 
Goodwill  55,430   56,903   50,344   53,435 
Debt issuance costs, net  1,498    
Other assets  188   149   266   236 
Total assets $164,312  $167,512  $148,519  $163,203 
                
LIABILITIES AND OWNERS’ EQUITY                
Current liabilities:                
Accounts payable $2,171  $1,690  $3,404  $3,757 
Accounts payable - affiliates  3,568   1,638   3,966   3,173 
Accrued payroll and other  12,242   7,585   11,163   9,109 
Liabilities held for sale     97 
Income taxes payable  748   1,011   346   646 
Current portion of long-term debt     136,293 
Total current liabilities  18,729   11,924   18,879   153,075 
Long-term debt  136,142   135,699   76,129    
Deferred tax liabilities     362 
Asset retirement obligations  161   139   142   143 
Total liabilities  155,032   148,124   95,150   153,218 
                
Commitments and contingencies - Note 9        
Commitments and contingencies - Note 8        
                
Owners’ equity:                
Partners’ capital:                
Common units (11,889,958 and 5,945,348 units outstanding at September 30, 2017 and December 31, 2016, respectively)  34,133   (7,722)
Subordinated units (5,913,000 units outstanding at December 31, 2016)     50,474 
Common units (11,933,522 and 11,889,958 units outstanding at June 30, 2018 and December 31, 2017, respectively)  33,852   34,614 
Preferred units (5,769,231 units outstanding at June 30, 2018)  43,636    
General partner  (25,876)  (25,876)  (25,876)  (25,876)
Accumulated other comprehensive loss  (2,725)  (2,538)  (2,545)  (2,677)
Total partners’ capital  5,532   14,338   49,067   6,061 
Noncontrolling interests  3,748   5,050   4,302   3,924 
Total owners’ equity  9,280   19,388   53,369   9,985 
Total liabilities and owners’ equity $164,312  $167,512  $148,519  $163,203 

See accompanying notes.


5  

 CYPRESS ENERGY PARTNERS, L.P.

 Unaudited Condensed Consolidated Statements of Operations

 For the Three and NineSix Months Ended SeptemberJune 30, 20172018 and 20162017

 (in thousands, except unit and per unit data)

 Three Months Ended
September 30,
 Nine Months Ended
September 30,
          
 2017 2016 2017 2016  Three Months Ended June 30, Six Months Ended June 30, 
             2018 2017 2018 2017 
Revenues $77,682  $81,806  $216,971  $227,591 
            
Revenue $76,468  $74,567  $141,294  $139,289 
Costs of services  68,292   71,880   192,643   202,540   65,525   65,958   122,222   124,351 
Gross margin  9,390   9,926   24,328   25,051   10,943   8,609   19,072   14,938 
                                
Operating costs, expenses and other:                
Operating costs and expense:                
General and administrative  5,574   5,056   16,013   16,805   5,822   5,329   11,277   10,439 
Depreciation, amortization and accretion  1,184   1,214   3,561   3,685   1,110   1,206   2,244   2,377 
Impairments        3,598   10,530            3,598 
Losses on asset disposals, net  208      95    
Gain on asset disposals, net  (1,606)  (113)  (3,315)  (113)
Operating income (loss)  2,424   3,656   1,061   (5,969)  5,617   2,187   8,866   (1,363)
                                
Other (expense) income:                                
Interest expense, net  (1,907)  (1,641)  (5,411)  (4,878)  (1,668)  (1,795)  (3,624)  (3,504)
Foreign currency gains  557      824    
Debt issuance cost write-off  (114)     (114)   
Foreign currency gains (losses)  (117)  267   (451)  267 
Other, net  17   210   122   257   125   60   207   105 
Net income (loss) before income tax expense  1,091   2,225   (3,404)  (10,590)  3,843   719   4,884   (4,495)
Income tax expense  529   227   458   389 
Income tax expense (benefit)  287   222   368   (71)
Net income (loss)  562   1,998   (3,862)  (10,979)  3,556   497   4,516   (4,424)
                                
Net Income (loss) attributable to noncontrolling interests  8   81   (1,290)  (4,898)
Net income (loss) attributable to noncontrolling interests  149   (133)  384   (1,298)
Net income (loss) attributable to partners / controlling interests  554   1,917   (2,572)  (6,081)  3,407   630   4,132   (3,126)
                
Net loss attributable to general partner  (1,000)  (1,431)  (2,750)  (5,366)     (829)     (1,750)
Net income (loss) attributable to limited partners $1,554  $3,348  $178  $(715)  3,407   1,459   4,132   (1,376)
Net income attributable to preferred unitholder  367      367    
Net income (loss) attributable to common unitholders $3,040  $1,459  $3,765  $(1,376)
                                
Net income (loss) attributable to limited partners allocated to:                
Common unitholders $1,554  $1,676  $178  $(358)
Subordinated unitholders     1,672      (357)
 $1,554  $3,348  $178  $(715)
                
Net income (loss) per common limited partner unit                
Net income (loss) per common limited partner unit:                
Basic $0.13  $0.28  $0.02  $(0.06) $0.25  $0.12  $0.32  $(0.13)
Diluted $0.13  $0.27  $0.02  $(0.06) $0.24  $0.12  $0.31  $(0.13)
                                
Net income (loss) per subordinated limited partner unit - basic and diluted $  $0.28  $  $(0.06)
                
Weighted average common units outstanding                
Weighted average common units outstanding:                
Basic  11,884,196   5,939,158   10,902,838   5,930,718   11,933,390   11,880,452   11,916,127   10,404,026 
Diluted  11,994,881   6,158,961   11,111,454   5,930,718   14,298,409   12,002,538   13,323,692   10,404,026 
                                
Weighted average subordinated units outstanding - basic and diluted     5,913,000   974,670   5,913,000            1,470,083 

 

 See accompanying notes.

 


6  

 CYPRESS ENERGY PARTNERS, L.P.

 Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss)

 For the Three and NineSix Months Ended SeptemberJune 30, 20172018 and 20162017

 (in thousands)

           

 Three Months Ended
September 30,
 Nine Months Ended
September 30,
  Three Months Ended June 30, Six Months Ended June 30, 
 2017 2016 2017 2016  2018 2017 2018 2017 
                  
Net income (loss) $562  $1,998  $(3,862) $(10,979) $3,556  $497  $4,516  $(4,424)
Other comprehensive income (loss) -                
foreign currency translation  (207)  (71)  (187)  515 
Other comprehensive income (loss) - foreign currency translation  30   (42)  132   20 
                                
Comprehensive income (loss) $355  $1,927  $(4,049) $(10,464) $3,586  $455  $4,648  $(4,404)
                                
Comprehensive income attributable to preferred unitholders  367      367    
Comprehensive income (loss) attributable to noncontrolling interests  8   81   (1,290)  (4,898)  149   (133)  384   (1,298)
Comprehensive loss attributable to general partner  (1,000)  (1,431)  (2,750)  (5,366)     (829)     (1,750)
                                
Comprehensive income (loss) attributable to limited partners $1,347  $3,277  $(9) $(200)
Comprehensive income (loss) attributable to common unitholders $3,070  $1,417  $3,897  $(1,356)

 

 See accompanying notes. 


7  

 CYPRESS ENERGY PARTNERS, L.P.

 Unaudited Condensed Consolidated Statements of Cash Flows

 For the NineSix Months Ended SeptemberJune 30, 20172018 and 20162017

 (in thousands) 

 

 Nine Months Ended
September 30,
  Six Months Ended June 30, 
 2017 2016  2018 2017 
Operating activities:                
Net loss $(3,862) $(10,979)
Adjustments to reconcile net loss to net cash provided by operating activities:        
Net income (loss) $4,516  $(4,424)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:        
Depreciation, amortization and accretion  4,378   4,354   2,793   2,913 
Impairments  3,598   10,530      3,598 
(Gains) losses on asset disposals, net  95   (2)
Gain on asset disposals, net  (3,315)  (308)
Interest expense from debt issuance cost amortization  443   426   247   294 
Debt issuance cost write-off  114    
Equity-based compensation expense  1,136   829   547   766 
Equity in earnings of investee  (98)  (234)  (100)  (57)
Distributions from investee  75   138   63    
Deferred tax benefit, net  (361)  (39)     (358)
Non-cash allocated expenses  1,750   2,866      1,750 
Foreign currency gains  (824)   
Foreign currency (gains) losses, net  451   (267)
Changes in assets and liabilities:                
Trade accounts receivable  (11,583)  4,999   (6,059)  (4,727)
Prepaid expenses and other  (765)  1,053   1,358   (586)
Accounts payable and accrued payroll and other  6,552   3,802   1,744   3,920 
Income taxes payable  (271)  (84)  (300)  (802)
Net cash provided by operating activities  263  17,659   2,059   1,712 
                
Investing activities:                
Proceeds from fixed asset disposals, including insurance proceeds  1,578   3 
Purchase of property and equipment  (1,182)  (932)
Net cash provided by (used in) investing activities  396   (929)
Proceeds from fixed asset disposals  12,002   1,578 
Purchases of property and equipment  (3,936)  (380)
Net cash provided by investing activities  8,066   1,198 
                
Financing activities:                
Repayment of long-term debt     (4,000)
Issuance of preferred units, net of issuance costs  43,269    
Repayments of long-term debt  (60,771)   
Debt issuance cost payments  (1,250)   
Taxes paid related to net share settlement of equity-based compensation  (120)  (100)  (70)  (77)
Contributions attributable to general partner  1,000   2,500 
Distributions to limited partners  (9,813)  (14,439)  (5,004)  (7,318)
Distributions to noncontrolling members  (12)  (415)
Distributions to noncontrolling interests  (6)  (12)
Net cash used in financing activities  (8,945)  (16,454)  (23,832)  (7,407)
                
Effect of exchange rates on cash  831   477   (202)  271 
                
Net decrease in cash and cash equivalents  (7,455)  753 
Cash and cash equivalents, beginning of period  26,693   24,150 
Cash and cash equivalents, end of period $19,238  $24,903 
Net decrease in cash and cash equivalents and restricted cash equivalents  (13,909)  (4,226)
Cash and cash equivalents (including restricted cash equivalents of $490 at December 31, 2017 and December 31, 2016), beginning of period  24,998   27,183 
Cash and cash equivalents (including restricted cash equivalents of $590 at June 30, 2018 and $490 at June 30, 2017), end of period $11,089  $22,957 
                
Non-cash items:                
Changes in accounts payable excluded from capital expenditures $320  $76 
Accounts payable excluded from capital expenditures $1,288  $473 

 

 See accompanying notes.                


8  

 CYPRESS ENERGY PARTNERS, L.P.

 Unaudited Condensed Consolidated Statement of Owners’ Equity

 For the NineSix Months Ended SeptemberJune 30, 20172018

 (in thousands)

  

 General
Partner
 Common
Units
 Subordinated Units Accumulated Other Comprehensive Loss Noncontrolling Interests Total Owners’ Equity  Common
Units
 Preferred
Units
 General
Partner
 Accumulated Other Comprehensive Loss Noncontrolling Interests Total Owners’ Equity 
                          
Owners’ equity at December 31, 2016 $(25,876) $(7,722) $50,474  $(2,538) $5,050  $19,388 
Net income (loss) for the period January 1, 2017 through September 30, 2017  (2,750)  178         (1,290)  (3,862)
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 June 30, 2018  3,765   367         384   4,516 
Issuance of preferred units, net     43,269            43,269 
Foreign currency translation adjustment           (187)     (187)           132      132 
Contributions attributable to general partner  2,750               2,750 
Distributions to partners     (7,408)  (2,405)        (9,813)  (5,004)              (5,004)
Distributions to noncontrolling interests              (12)  (12)              (6)  (6)
Conversion of Subordinated Units to Common Units     48,111   (48,111)         
Equity-based compensation     1,094   42         1,136   547               547 
Taxes paid related to net share settlement of equity-based compensation     (120)           (120)  (70)              (70)
                                                
Owners’ equity at September 30, 2017 $(25,876) $34,133  $  $(2,725) $3,748  $9,280 
Owners’ equity at June 30, 2018 $33,852  $43,636  $(25,876) $(2,545) $4,302  $53,369 

 

See accompanying notes.


9  

CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

 

1.Organization and Operations

1.  Organization and Operations

 

Cypress Energy Partners, L.P. (the “Partnership”) is a Delaware limited partnership formed in 2013 to provide independent pipeline inspection and integrity services to producers, public utility companies, and pipeline companies and to provide salt watersaltwater disposal (“SWD”) and other water and environmental services to U.S. onshore oil and natural gas producers and trucking companies. Trading of our common units began January 15, 2014 on the New York Stock Exchange under the symbol “CELP”.

        

Our business is organized into the Pipeline Inspection Services (“PIS”Pipeline Inspection”), Integrity Services (“IS”Integrity Services”), and Water and Environmental Services (“W&ES”Water Services”) segments. PISThe Pipeline Inspection segment provides pipeline inspection and other services to energy exploration and production (“E&P”) companies, public utility companies, and midstream companies and their vendors throughout the United States and Canada. The inspectors of PISPipeline Inspection perform a variety of inspection services on midstream pipelines, gathering systems, and distribution systems, including data gathering and supervision of third-party construction, inspection, and maintenance and repair projects. ISThe Integrity Services segment provides independent integrity services to major natural gas and petroleum pipeline companies and to pipeline construction companies located throughoutin the United States. Field personnel in this segment primarily perform hydrostatic testing on newly-constructed and existing natural gas and petroleum pipelines. W&ES provides services to oil and natural gas producers and trucking companies through its ownership and operationThe Water Services segment is comprised of eight commercial SWDsaltwater disposal facilities in the Bakken Shale region of the Williston Basin in North DakotaDakota. These facilities provide services to oil and two SWD facilities in the Permian Basin in Texas.natural gas producers and trucking 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 containutilize oil skimming processes that remove oil from water delivered to the sites. We sell the oil produced from these skimming processes, which contributes to our revenues. In addition to these SWDsaltwater disposal facilities, we provide management and staffing services for an SWD facility pursuant to a management agreementsaltwater disposal facility in which we we own a 25% ownership interest (see Note 7).   We also own a 25% member interest in this managed SWD facility.

  

2.Basis of Presentation and Summary of Significant Accounting Policies

2.  Basis of Presentation and Summary of Significant Accounting Policies

   

Basis of Presentation

 

The Unaudited Condensed Consolidated Financial Statements as of Septemberand for the three months ended June 30, 2018 and 2017 and for the ninesix months ended SeptemberJune 30, 20172018 and 20162017 include our accounts and those of our controlled subsidiaries. Investments over which we exercise significant influence, but do not control, are accounted for using the equity method of accounting. All significant intercompany transactions and account balances have been eliminated in consolidation. The Unaudited Condensed Consolidated Balance Sheet at December 31, 20162017 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.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, 20162017 included in our Form 10-K. The results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

 

Use of Estimates in the Preparation of Financial Statements

 

The preparation of the Partnership’sour 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, 20162017 included in our Form 10-K.10-K, except for the adoption of Accounting Standards Update ("ASU") 2014-09 - Revenue from Contracts with Customers and ASU 2016-18 - Statement of Cash Flows - Restricted Cash on January 1, 2018. Under ASU 2014-09, an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.  Based on this new accounting guidance, our revenue is earned and recognized through the service offerings of our three reportable business segments.  Our sales contracts have terms of less than one year.  As such, we have used the practical expedient contained within the accounting guidance which exempts us from the requirement to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract with an original expected duration of one year or less. See Note 10 for disaggregated revenue reported by segment.  The adoption and application of this ASU had no effect on our Unaudited Condensed Consolidated Financial Statements, other than additional disclosures included in this Form 10-Q. Under ASU 2016-18, an entity is required to show changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents in the statement of cash flows.  The adoption and application of this ASU has modified the presentation of cash, cash equivalents, restricted cash, and restricted cash equivalents on our Unaudited Condensed Consolidated Statements of Cash Flows applied on a retrospective basis.


10  

CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

 

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. The Partnership determines allowances for bad debts based on management’s assessment of the creditworthiness of our customers.  Trade receivables are written off against the allowance when deemed uncollectible. Recoveries of trade receivables previously written off are recorded when cash is received. In the first quarter of 2017, we received $0.3 million on accounts receivable previously reserved, which we recorded as a reduction to general and administrative expense in our Unaudited Consolidated Statements of Operations.

 

Income Taxes

 

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

 

The income of Tulsa Inspection Resources – Canada, ULC, our Canadian subsidiary, is taxable in Canada. Tulsa Inspection Resources – PUC, LLC, a subsidiary of our PISPipeline Inspection segment that performs pipeline inspection services for utility customers, and Brown Integrity – PUC, LLC, a subsidiary in which we own a 51% owned subsidiary,membership interest, have elected to be taxed as corporations for U.S. federal income tax purposes, and therefore, these subsidiaries are subject to U.S. federal and state income tax. The amounts recognized as income tax expense (benefit), income taxes payable, and deferred tax assets / liabilities in our Unaudited Condensed Consolidated Financial Statements representinclude the Canadian income taxes and U.S. federal and state income taxes referred to above in this paragraph, as well as partnership-level taxes levied by various states, which include, most notably, franchise taxes assessed by the state of Texas.

 

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

  

Noncontrolling Interest

 

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

 

Property and Equipment

 

Property and equipment consists of land, land and leasehold improvements, buildings, facilities, wells and related equipment, computer and office equipment, and vehicles. We record property and equipment at cost. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repairs are expensed as incurred. We depreciate property and equipment on a straight-line basis over the estimated useful lives of the assets. Upon retirement or disposition of an asset, we remove the cost and related accumulated depreciation from the balance sheet and report the resulting gain or loss, if any, in the Unaudited Condensed Consolidated StatementStatements of Operations.


11  

CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

  

Identifiable Intangible Assets

 

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

 

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

 

Goodwill

 

Goodwill is not amortized, but is subject to an annual review for impairment on November 1 (or at other dates if events or changes in circumstances indicate that the carrying value of goodwill may be impaired) at a reporting unit level. The reporting units used to evaluate and measure goodwill for impairment are determined primarily from the manner in which the business that relates to the applicable goodwill is managed or operated. We have determined that our PIS, IS,Pipeline Inspection, Integrity Services, and W&ESWater Services segments are the appropriate reporting units for testing goodwill impairment.

  

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

 

Impairments of Long-Lived AssetsProperty and Equipment

 

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

 

Accrued Payroll and Other

 

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

 

 September 30,
2017
 December 31,
2016
  June 30, 2018 December 31, 2017 
  (in thousands)  (in thousands) 
             
Accrued payroll $9,975  $5,594  $9,276  $6,893 
Customer deposits  1,393   1,361   1,451   1,510 
Other  874   630   436   706 
 $12,242  $7,585  $11,163  $9,109 

 

Foreign Currency Translation

 

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


12  

CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

  

Our Unaudited Condensed Consolidated Balance Sheet at SeptemberJune 30, 20172018 includes $2.7$2.5 million of accumulated other comprehensive lossassociated 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’partners’ capital, which would be reported in the Unaudited Condensed Consolidated Statement of Operations as a reduction to net income.

 

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

 

Subordination

With the payment of the 2016 fourth quarter distribution and the fulfillment of other requirements associated with the termination of the subordination period, the Partnership emerged from subordination effective February 14, 2017, and the 5,913,000 subordinated units converted into common units on a one-for-one basis.

New Accounting Standards

 

In 2017, the PartnershipOn January 1, 2018, we adopted the following new accounting standards issued by the Financial Accounting Standards Board (“FASB”):;

 

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

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

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

The FASB issued ASU 2016-02 – Leases in February 2016. This guidance attempts to increase transparency and comparability among organizations by recognizing certain lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between previous GAAP and this new guidance is the recognition on the balance sheet of certain lease assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP. The amendments in this ASU are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted. We are currently examining the guidance provided in the ASU and determining the impact this guidance will have on our Unaudited Condensed Consolidated Financial Statements.

The FASB issued ASU 2014-09 – Revenue from Contracts with Customers in May 2014. ASU 2014-09 is intended to clarify the principles for recognizing revenue and to develop a common standard for recognizing revenue for GAAP and International Financial Reporting Standards that is applicable to all organizations. This guidance requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to receive in exchange for those goods and services. It also requires additional disclosure about the nature, amount, timing, and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to obtain or fulfill a contract. We will be required to adoptadopted this standard in 2018 and to apply its provisions either retrospectively to each prior reporting period presented or prospectively with the cumulative effect of initially applying the ASU recognized at the date of initial application (modified retrospective method). Although we continue to evaluate the financial impact of this ASU on the Partnership, we currently plan to adopt thisnew standard utilizing the modified retrospective method and do not anticipate that thetransition approach. The adoption of this ASU will materiallyhad no effect on our Unaudited Condensed Consolidated Financial Statements other than additional disclosures included in the Form 10-Q.

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

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

The FASB issued ASU 2016-02 – Leases in February 2016 and has issued subsequent standard setting guidance related to the implementation of this ASU. This guidance attempts to increase transparency and comparability among organizations by recognizing certain lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between previous GAAP methodology and the method proposed by this new guidance is the recognition on the balance sheet of certain lease assets and lease liabilities by lessees for those leases that were classified as operating leases under previous GAAP. Entities are required to adopt this ASU using a modified retrospective approach, subject to certain optional practical expedients, and apply its provisions to leasing arrangement existing at or entered into after the earliest comparative period presented in the financial position, results of operations or cash flows.statements. The amendments in this ASU are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. We are currently evaluating the impact this ASU will have on our Unaudited Condensed Consolidated Balance Sheets.

 


13  

CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

  

3.Impairments

3.         Impairments

 

InDuring the first quarter ofthree months ended March 31, 2017, the largest customer of TIR-Canada, the Canadian subsidiary of our PISPipeline Inspection segment, completed a bid process and selected different service providers for its inspection projects. During the ninesix months ended SeptemberJune 30, 2017, pipeline inspection services to this customer accounted for approximately $18.8 million of revenue and $1.3 million of gross margin, which represented approximately 84%89% of the revenues and 89%94% of the gross margin of our Canadian operations (and approximately 9%14% of our consolidated revenues and 5%9% of our consolidated gross margin for the ninesix months ended SeptemberJune 30, 2017). In consideration of the loss of this contract, we recorded impairments to the carrying values of certain intangible assets of $1.3 million induring the first quarter ofthree months ended March 31, 2017. Of this amount, $1.1 million related to customer relationships and $0.2 million related to trade names. Based on discounted cash flow calculations, which represent Level 3 non-recurring fair value adjustments, we concluded the fair value of the customer relationships and trade names was zero, and thus, have written off the full amounts. We continue to perform inspection and integrity work for customers in Canada (including integrity work for the customer referred to above).Canada. 

 

InDuring the first quarter ofthree months ended March 31, 2017, we recorded an impairment of $0.7 million to the property, plant and equipment at one of our SWD facilities. We have temporarily shut down the operations at this facility because of low volumes due to competition in the area and due to low levels of exploration and production activity near the facility. Because of the decline in revenues and the temporary shutdown of the facility, we performed a discounted cash flow calculation, which represents a Level 3 non-recurring fair value adjustment, concluding that the fair value of the facility was limited to the fair value of the land. As such, we recorded an impairment to reduce theremaining $1.6 million carrying value of the facility to $0.1 million in the first quarter of 2017, all of which is attributable to land.

In the first quarter of 2017, we recorded an impairment of $1.6 million to the goodwill of our Integrity Services segment. Revenues of this segment were lower than we had expected for the first quarter of 2017. In addition, for this segment, the level of bidding activity for work is typically high in March and April once customers have finalized their budgets for the upcoming year. While we won bids on a number of projects, and our backlog began to improve, the improvement in the backlog was slower than we had originally anticipated and we revised downward our expectations of the near-term operating results of the segment. For our goodwill impairment assessment, we calculated anWe estimated the fair value of the Integrity Services segment usingutilizing the income approach (discounted cash flows valuation method), which is a discounted cash flow analysis. We prepared two calculationsLevel 3 input as defined in ASC 820 – Fair Value Measurement. Significant inputs in the valuation included projections of future revenue, anticipated operating costs and appropriate discount rates. Significant assumptions included a 2% annual growth rate of cash flows for the next twelve months, one of which represented our estimate of the high end of the range of probable cash flows and the other of which represented our estimate of the low range of probable cash flows. We estimated cash flows for the following four years assuming a 2% increase in each succeeding year, to account for estimated inflation, and calculated a terminal value using a Gordon Growth model. We then discounted the future cash flows at a discount rate of 18%. The mid-point ofWe determined through this analysis that the estimated fair values produced by these two calculations indicated that a full impairment of the value of the goodwill of the Integrity Services segment was warranted.fully impaired. These calculations represent Level 3 non-recurring fair value measurements. If anticipated operating results in this segment do not meet expectations, it is possible that finite-lived intangibles may also become impaired in the future.

In January 2017, a lightning strike at our Orla SWD facility initiated a fire that effectively destroyed the surface equipment at the facility. As a result, we wrote off the net book value of the surface equipment ($1.3 million) of the facility. In May 2017, we received $1.6 million of insurance proceeds. We recorded a gain of $0.3 million in losses on asset disposals, net on our Unaudited Condensed Consolidated Statement of Operations in the second quarter of 2017 for the difference between the proceeds received and the net book value of the property that was destroyed. During the nine months ended September 30, 2017, we incurred approximately $0.2 million of temporary setup and other costs associated with this incident that are not recoverable through insurance. These expenses are reported within losses on asset disposals, net in our Unaudited Condensed Consolidated Statement of Operations for the nine months ended September 30, 2017.measurement.

 

In July 2017, a lightning strike at our Grassy Butte SWD facility initiated a fire that effectively destroyed the surface equipment at the facility. As a result of previously-recorded impairments, the net book value of the property, plant and equipment at this facility was $0 at the time of the fire. During the three months ended September 30,March 31, 2017, we recorded $0.2an impairment of $0.7 million to the property and equipment at one of expense associated with cleanup costs that are not recoverable from insurance,our saltwater disposal facilities. We have experienced low volumes at his facility due to competition in the area and to low levels of exploration and production activity near the facility. The impairment reduced the carrying value of the facility to $0.1 million, all of which is reported within losses on asset disposals, net in our Unaudited Condensed Consolidated Statements of Operations. At September 30, 2017, we recorded a receivable of $0.1 million for expected insurance recoveries, which is reported within prepaid expenses and other on our Unaudited Condensed Consolidated Balance Sheet.  In November 2017, we reached agreement with an insurer under which we expectattributable to receive $0.7 million of insurance proceeds during the three months ending December 31, 2017 as partial payment for our property damage and property cleanup claims associated with this incident. We expect to record a $0.6 million gain upon receipt of these proceeds.land.

 


14  

CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

 

4.Credit Agreement

4.         Credit Agreement

 

We are party to aOn May 29, 2018, we entered into an amended and restated credit agreement (as amended and restated, the “Credit Agreement”) that provides up to $200.0$90.0 million in borrowing capacity, subject to certain limitations. The Credit Agreement includes a working capital revolving credit facility (“Working Capital Facility”), which provides up to $75.0 million in borrowing capacity to fund working capital needs,limitations, and an acquisition revolving credit facility (“Acquisition Facility”), which provides up to $125.0 million in borrowing capacity to fund acquisitions and expansion projects. In addition, the Credit Agreement provides forcontains an accordion feature that allows us to increase the availability under the facilities by an additional $125.0borrowing capacity to $110.0 million if the lenders agree to increase their commitments.commitments in the future or if other lenders join the facility. The Credit Agreement matures December 24, 2018.

Outstanding borrowings at September 30, 2017 and December 31, 2016May 29, 2021. The obligations under the Credit Agreement wereare secured by a first priority lien on substantially all of our assets. The credit agreement as follows: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”.

 

  September 30,
2017
  December 31,
2016
 
   (in thousands) 
         
Working Capital Facility $48,000  $48,000 
Acquisition Facility  88,900   88,900 
Total borrowings  136,900   136,900 
Debt issuance costs  (758)  (1,201)
Long-term debt $136,142  $135,699 

Outstanding borrowings at June 30, 2018 were $76.1 million and are reflected as long-term debt on the Unaudited Condensed Consolidated Balance Sheets beginning May 29, 2018. Debt issuance costs are reported as debt issuance costs, net on the Unaudited Condensed Consolidated Balance Sheets and total $1.5 million at June 30, 2018. Outstanding borrowings at December 31, 2017 were $136.9 million and are reflected net of debt issuance costs of $0.6 million as current portion of long-term debt on the Unaudited Condensed Consolidated Balance Sheet. The carrying value of the partnership’s long-term debt approximates fair value as the borrowings under the Credit Agreement are considered to be priced at market for debt instruments having similar terms and conditions (Level 2 of the fair value hierarchy).

 

Borrowings underWe incurred certain debt issuance costs associated with the Working Capital FacilityPrevious Credit Agreement, which we were amortizing on a straight-line basis over the life of the Previous Credit Agreement. Upon amending the Credit Agreement in May 2018, we wrote off $0.1 million of these debt issuance costs and reported this expense within debt issuance cost write-off in our Unaudited Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2018, which represented the portion of the unamortized debt issuance costs attributable to lenders who are limited by a monthly borrowing base calculation as definedno longer participating in the credit facility subsequent to the amendment. The remaining debt issuance costs associated with the Previous Credit Agreement. If, at any time, outstanding borrowings underAgreement, along with $1.3 million of debt issuance costs associated with the Working Capital Facility exceed our calculated borrowing base, a principal payment in the amount of the excess is due upon submission of the borrowing base calculation. Available borrowings under the Acquisition Facility may be limited by certain financial covenant ratios as defined in the Credit Agreement. The obligations under ouramended and restated Credit Agreement, are secured bybeing amortized on a first priority lien on substantially allstraight-line basis over the three-year term of our assets.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 1.25%1.5% to 2.75%3.0% per annum (“Base Rate Borrowing”) or (ii) an adjusted LIBOR rate plus a margin of 2.25%2.5% to 3.75%4.0% per annum (“LIBOR Borrowings”). The applicable margin is determined based on the leverage ratio of the Partnership, as defined in the Credit Agreement. Generally, the interest rate on our Credit Agreement borrowings ranged between 4.74% and 5.95% for the six months ended June 30, 2018 and 3.90% and 4.99%4.97% for the ninesix months ended SeptemberJune 30, 2017 and 3.54% and 4.28% for the nine months ended September 30, 2016.2017. Interest on Base Rate Borrowings is payable monthly. Interest on LIBOR Borrowings is paid upon maturity of the underlying LIBOR contract, but no less often than quarterly. Commitment fees are charged at a rate of 0.50% on any unused credit and are payable quarterly. Interest paid during the three months ended SeptemberJune 30, 20172018 and 20162017 was $1.7 million, and $1.6 million, respectively, including commitment fees. Interest paid during the ninesix months ended SeptemberJune 30, 2018 and 2017 and 2016 was $5.0$3.5 million and $4.3$3.3 million, respectively, including commitment fees.

 

OurThe Credit Agreement contains various customary affirmative and negative covenants and restrictive provisions. OurThe Credit Agreement also requires maintenance of certain financial covenants, including a combined total adjusted leverage ratio (as defined in ourthe Credit Agreement) of not more than 4.0 to 1.0 and an interest coverage ratio (as defined in ourthe Credit Agreement) of not less than 3.0 to 1.0. At SeptemberJune 30, 2017,2018, our combined total adjusted leverage ratio was 3.773.58 to 1.0 and our interest coverage ratio was 3.084.99 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 ourthe Credit Agreement, the lenders may declare any outstanding principal, of our Credit Agreement debt, 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 ourthe Credit Agreement. We were in compliance with all debt covenants as of SeptemberJune 30, 2017. Working capital borrowings, which are fully secured by our net working capital, are subject to a monthly borrowing base and are excluded from our debt compliance ratios.2018.

  

In addition, ourthe Credit Agreement restricts our ability to make distributions on, or redeem or repurchase, our equity interests.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 ourthe Credit Agreement, the borrowers and the guarantorswe are in compliance with the financial covenants in the borrowing base (which includes 100% of cash on hand) exceeds the amount of outstanding credit extensions under the Working Capital Facility byCredit Agreement, and we have at least $5.0 million andof unused capacity on the Credit Agreement at least $5.0 million in lender commitments are available to be drawn under the Working Capital Facility.time of the distribution.


15  

CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

 

Our Credit Agreement matures on December 24, 2018 and, although unfavorable financial results may impact our ability to meet our current debt covenants, we believe it is probable that we will be able to maintain compliance with the financial ratio covenants through the maturity date of the Credit Agreement through some combination of 1) improved operating results, 2) refinancing the Credit Agreement, and/or 3) future sponsor support from Holdings.5.          Income Taxes

 

We plan to improve our operating results through a combination of 1) enhanced business development efforts in our Pipeline Inspection Services and Integrity Services segments, including our continued focus on higher margin services, 2) the re-opening of our Orla, TX and our Grassy Butte, ND SWD facilities that were struck by lightning earlier this year; 3) enhancing our SWD activities due to additional drilling and completion activities in both the Permian and Bakken regions; and 4) capital expansion in our Water and Environmental Services segment (specifically, we are in the process of building a water gathering system at one of our North Dakota facilities).

In anticipation of the Credit Agreement maturing in December 2018, we have an executed mandate and term sheet with the lead bank in the Credit Agreement regarding a refinancing of the Credit Agreement, subject to syndication. The new credit agreement will require a reduction in our current outstanding debt balance and will have modified financial ratio covenants. The term sheet provides for conditions precedent to reduce the principal balance, which may include some combination of 1) using cash currently on the balance sheet; 2) issuing some sort of equity to the owners of Holdings or third parties; 3) issuing convertible debt to the owners of Holdings or third parties; 4) monetizing a portion of our investment-grade accounts receivable with Holdings or a third-party; and/or 5) asset sales of some of our SWD facilities. Although it is our intent to refinance our Credit Agreement under the executed term sheet, we can offer no assurances that the refinancing of our Credit Agreement will be consummated under terms acceptable to us given the conditions precedent outlined in the term sheet.

Holdings has continued to support the Partnership during the oil and gas economic downturn and has provided sponsor support of $6.3 million during the year ended December 31, 2016 and $2.8 million during the nine months ended September 30, 2017. The owners of Holdings, who collectively own approximately 64% of our common units, remain incentivized and have the financial wherewithal to continue to support us in order to maintain compliance with the financial ratio covenants through the maturity date of the Credit Agreement.

5.Income Taxes

The income tax expense (benefit) reported in our Unaudited Condensed Consolidated Statements of Operations for the three and ninesix months ended SeptemberJune 30, 20172018 and 20162017 differs from the statutory tax rate of 21% in 2018 and 35% in 2017 due to the fact that, as a partnership, we are generally not subject to U.S. federal or state income taxes. Our income tax provision relates primarily to our corporate subsidiaries that service public utility customers, which are subject to U.S. federal and state income taxes, our Canadian subsidiary, which is subject to Canadian federal and provincial income taxes, and to certain other state income taxes, including the Texas franchise tax.

 

6.         Equity

Series A Preferred Units

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

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

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

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

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

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

6.Equity Compensation16  

CYPRESS ENERGY PARTNERS, L.P.

 Notes to the Unaudited Condensed Consolidated Financial Statements

Earnings Per Unit

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

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

  Three Months Ended June 30,  Six Months Ended June 30, 
  2018  2017  2018  2017 
  (in thousands, except per unit data) 
             
Net income (loss) attributable to common unitholders $3,040  $1,459  $3,765  $(1,376)
Weighted average common units outstanding  11,933   11,880   11,916   10,404 
Basic net income (loss) per common limited partner unit $0.25  $0.12  $0.32  $(0.13)

The following summarizes the calculation of the diluted net income (loss) per common limited partner unit for the three and six months ended June 30, 2018 and 2017:

  Three Months Ended June 30,  Six Months Ended June 30, 
  2018  2017  2018  2017 
  (in thousands, except per unit data) 
             
Net income (loss) attributable to common unitholders $3,040  $1,459  $3,765  $(1,376)
Net income attributable to preferred unitholder  367      367    
Net income (loss) attributable to limited partners $3,407  $1,459  $4,132  $(1,376
                 
Weighted average common units outstanding  11,933   11,880   11,916   10,404 
Effect of dilutive securities             
Weighted average preferred units outstanding  2,029      1,020    
Long-term incentive plan unvested units  336   122   388    
Diluted weighted average common units outstanding  14,298   12,002   13,324   10,404 
Diluted net income (loss) per common limited partner unit $0.24  $0.12  $0.31  $(0.13)

For the six months ended June 30, 2017, we experienced a net loss attributable to common unitholders. The unvested equity compensation awards would have been antidilutive and, therefore, were not included in the computation of diluted net loss per common limited partner unit.

17  

CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

Cash Distributions

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

        Total Cash 
  Per Unit Cash  Total Cash  Distributions 
Payment Date Distributions  Distributions  to Affiliates (a) 
     (in thousands) 
Total 2014 Distributions  1.104646   13,064   8,296 
Total 2015 Distributions  1.625652   19,232   12,284 
Total 2016 Distributions  1.625652   19,258   12,414 
             
February 13, 2017  0.406413   4,823   3,107 
May 13, 2017  0.210000   2,495   1,606 
August 12, 2017  0.210000   2,495   1,607 
November 14, 2017  0.210000   2,497   1,608 
Total 2017 Distributions  1.036413   12,310   7,928 
             
February 14, 2018  0.210000   2,498   1,599 
May 15, 2018  0.210000   2,506   1,604 
August 14, 2018 (b)  0.210000   2,506   1,604 
Total 2018 Distributions (through August 14, 2018)  0.630000   7,510   4,807 
Total Distributions (through August 14, 2018 since IPO) $6.022363  $71,374  $45,729 

(a)    Approximately 64.0% of the Partnership’s outstanding common units at June 30, 2018 were held by affiliates.

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

18  

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

Equity Compensation

 

Our General Partner has adopted a long-term incentive plan (“LTIP”) that authorizes the issuance of up to 1,182,600 common units. Certain directors and employees of the Partnership have been awarded Phantom Restricted Units (“Units”) under the terms of the LTIP. The fair value of the awards is determined based on the quoted market value of the publicly-traded common units at each grant date, adjusted for certain discounts.a discount to reflect the fact that distributions are not paid on the restricted units during the vesting period. Compensation expense is recorded on a straight-line basis over the vesting period of theeach grant. We recorded expense of $1.1$0.5 million and $0.7$0.8 million during the ninesix months ended SeptemberJune 30, 20172018 and 2016,2017, respectively, related to the Unitunit awards. During November 2017, an officer with 76,345 unvested LTIP units resigned. During the three months ending December 31, 2017, we expect to record a reduction to expense of $0.3 million related to the forfeiture of these units upon this officer’s departure.

  

The following table summarizes the LTIP Unitunit activity for the ninesix months ended SeptemberJune 30, 20172018 and 2016:2017:

 

  Nine Months Ended September 30, 
  2017  2016 
             
   Number of Units   Weighted Average Grant Date Fair Value / Unit   Number of Units   Weighted Average Grant Date Fair Value / Unit 
                 
 Units at January 1  573,902  $9.86   361,698  $14.30 
 Units granted  249,120  $7.11   336,847  $6.34 
 Units vested and issued  (43,930) $16.56   (34,023) $10.33 
 Units forfeited  (39,722) $8.51   (62,951) $10.93 
 Units at June 30  739,370  $8.61   601,571  $10.42 

CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

  Six Months Ended June 30,  
  2018  2017 
     Weighted     Weighted 
     Average     Average 
     Grant     Grant 
  Number  Date Fair  Number  Date Fair 
  of Units  Value / Unit  of Units  Value / Unit 
Unvested units at January 1  664,509  $8.46   573,902  $9.86 
Unvested units granted  396,484  $3.24   246,200  $7.15 
Units vested  (54,763) $13.18   (30,657) $15.99 
Unvested units forfeited  (43,383) $5.82   (21,802) $8.21 
Unvested units at June 30  962,847  $6.16   767,643  $8.79 

 

The majority of the awards vest in three tranches, with one-third of the units vesting three years from the grant date, one-third vesting four years from the grant date, and one-third vesting five years from the grant date. However, certain of the awards have different, and typically shorter, vesting periods. For twoTwo of the grants, which total 77,495 units, vesting isvest three years from the grant date, contingent upon the recipient meeting certain performance targets. Distributions are not paid on unvested Units during the vesting period. Total unearned compensation associated with the Unit awardsLTIP was $3.8$3.6 million at SeptemberJune 30, 2017,2018, and the awards had an average remaining life of 2.292.41 years.

 

7.Related-Party Transactions19  

CYPRESS ENERGY PARTNERS, L.P.

 Notes to the Unaudited Condensed Consolidated Financial Statements

7.  Related-Party Transactions

 

Omnibus Agreement and Other Support from Holdings

 

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

 

 our payment of a quarterly administrative fee in the amount of $1.0 million to Holdings for providing certain partnership overhead services, including certain executive management services by certain officers and employees of our General Partner, and payroll services for substantially all employees required to manage and operate our businesses.Partner.  This fee also includes the incremental general and administrative expenses we incur as a result of being a publicly-traded partnership.  For the three months ended September 30, 2017, this fee was paid to Holdings in accordance with its terms and conditions.  For the six months ended June 30, 2017, and for the year ended December 31, 2016, Holdings provided sponsor support to the Partnershipus by waiving payment of the quarterly administrative fee;

 

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

 

 indemnification of us by Holdings for certain environmental and other liabilities, including events and conditions associated with the operation of assets that occurred prior to the closing of the IPO and our obligation to indemnify Holdings for events and conditions associated with the operation of our assets that occur after the closing of the IPO and for environmental liabilities related to our assets to the extent Holdings is not required to indemnify us.

 

So long as affiliates of Holdings control our General Partner, the omnibus agreement will remain in effect, unless we and Holdings agree to terminate it sooner. If affiliates of Holdings cease to control our General Partner, either party may terminate the omnibus agreement, provided that the indemnification obligations will remain in full force and effect in accordance with their terms. We and Holdings may agree to amend the omnibus agreement; however, amendments will also require the approval of the Conflicts Committee of our Board of Directors. As part of our new Credit Agreement, Holdings agreed to waive the omnibus fee to support us in the event our leverage ratio were to exceed 3.75 times our trailing twelve-month Adjusted EBITDA at any quarter-end during the term of the credit facility.

 

Holdings incurred expenses of $0.9$0.8 million and $1.8 million on our behalf during the three and six months ended SeptemberJune 30, 2016, and $1.8 million and $2.9 million on our behalf during the nine months ended September 30, 2017, and 2016, respectively. These expenses are reported within general and administrative and within net loss attributable to general partner in the accompanying Unaudited Condensed Consolidated Statements of Operations and as contributions from general partner in the accompanying Unaudited Condensed Consolidated Statement of Owners’ Equity.Operations.

In addition to funding certain general and administrative expenses on our behalf, Holdings contributed $1.0 million and $0.5 million during the three months ended September 30, 2017 and 2016, respectively, and a total of $2.5 million in cash for the nine months ended September 30, 2016 attributable to the General Partner as a reimbursement of certain expenditures previously incurred by the Partnership. These payments are reflected as contributions attributable to general partner in the Unaudited Condensed Consolidated Statement of Owners’ Equity and as components of the net loss attributable to the general partner in the Unaudited Condensed Consolidated Statement of Operations for the three and nine month periods ended September 30, 2017 and 2016.

Total support from Holdings attributable to non-cash allocated expenses and the reimbursement of certain expenditures was $1.0 million and $2.8 million, respectively, for the three and nine months ended September 30, 2017 and $1.4 million and $5.4 million, respectively, for the three and nine months ended September 30, 2016.

 

Alati Arnegard, LLC

 

We provide management services to a 25% owned entity, Alati Arnegard, LLC (“Arnegard”("Arnegard")., an entity in which we hold a 25% membership interest. Management fee revenue earned from Arnegard totaled $0.2 million and $0.1 million for the three months ended SeptemberJune 30, 20172018 and 2016,2017, respectively, and $0.5 million and $0.4$0.3 million for the ninesix months ended SeptemberJune 30, 20172018 and 2016, respectively.2017. Accounts receivable from Arnegard were $0.1 million at SeptemberJune 30, 20172018 and December 31, 2016,2017, and are included in trade accounts receivable, net in the Unaudited Condensed Consolidated Balance Sheets.


CF Inspection Management, LLC

We have also entered into a joint venture with CF Inspection, a nationally-qualified woman-owned inspection firm affiliated with one of Holdings’ owners. We own 49% of CF Inspection and Cynthia A. Field, the daughter of Charles C. Stephenson, Jr., owns the remaining 51% of CF Inspection. For the six months ended June 30, 2018, CF Inspection represented approximately 3.2% of our consolidated revenue.

Sale of Preferred Equity

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

20  

CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

8.Earnings per Unit and Cash Distributions

Our net income (loss) is attributable and allocable to several types of owners. Income (loss) attributable to noncontrolling interests represents 49% of the income of Brown and 51% of the income of CF Inspection. Net loss attributable to the general partner includes expenses incurred by Holdings and not charged to us, as well as contributions for reimbursements of expenses made to us by Holdings. Income attributable to common and subordinated units represents the remaining net income (loss), after consideration of amounts attributable to noncontrolling interests and to the general partner; such amounts were allocated to common and subordinated units ratably based on the weighted-average number of such units outstanding during the relevant time period. In February 2017, all of the outstanding subordinated units converted into common units. Since the subordinated units did not share in the distribution of cash generated subsequent to December 31, 2016, we did not allocate any income or loss after that date to the subordinated units.

 

Diluted net income (loss) per common8.     Commitments and subordinated unit includes the dilutive impact of unvested unit awards granted as share-based compensation to employees and directors. Such awards had no dilutive effect during the nine months ended September 30, 2016 as we incurred net losses attributable to limited partners during those periods.Contingencies

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

Payment Date Per Unit Cash Distributions  Total Cash  Distributions  Total Cash  Distributions to Affiliates (a) 
  (in thousands) 
    
May 15, 2014 (b) $0.301389  $3,565  $2,264 
August 14, 2014  0.396844   4,693   2,980 
November 14, 2014  0.406413   4,806   3,052 
Total 2014 Distributions  1.104646   13,064   8,296 
             
February 14, 2015  0.406413   4,806   3,052 
May 14, 2015  0.406413   4,808   3,053 
August 14, 2015  0.406413   4,809   3,087 
November 13, 2015  0.406413   4,809   3,092 
Total 2015 Distributions  1.625652   19,232   12,284 
             
February 12, 2016  0.406413   4,810   3,107 
May 13, 2016  0.406413   4,812   3,099 
August 12, 2016  0.406413   4,817   3,103 
November 14, 2016  0.406413   4,819   3,105 
Total 2016 Distributions  1.625652   19,258   12,414 
             
February 13, 2017  0.406413   4,823   3,107 
May 15, 2017  0.210000   2,495   1,606 
August 14, 2017  0.210000   2,495   1,607 
November 14, 2017 (c)  0.210000   2,497   1,608 
   1.036413   12,310   7,928 
             
Total Distributions (through November 14, 2017 since IPO) $5.392363  $63,864  $40,922 

(a)Approximately 64.4% of the Partnership’s outstanding common units at September 30, 2017 were held by affiliates.
(b)Distribution was pro-rated from the date of our IPO through March 31, 2014.
(c)Third quarter 2017 distribution was declared and will be paid in the fourth quarter of 2017.

CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

9.Commitments and Contingencies

 

Security Deposits

 

We have various performance obligations which are secured with short-term security deposits (reflected as restricted cash equivalents on our Unaudited Condensed Consolidated Statements of Cash Flows) of $0.6 million and $0.5 million at SeptemberJune 30, 20172018 and December 31, 2016,2017, respectively, included in prepaid expenses and other on the Unaudited Condensed Consolidated Balance Sheets.

 

Employment Contract Commitments

 

We have an employment agreementsagreement with a certain membersmember of management. These agreements provideThis agreement provides for minimum annual compensation for specified terms, after which employment will continue on an “at will” basis. Certain agreements provideThe agreement provides for severance payments in the event of specified termination of employment. At SeptemberJune 30, 2017,2018, the aggregate commitment for future compensation and severance was approximately $0.7$0.5 million.

 

Compliance Audit Contingencies

 

Certain customer master service agreements (“MSA’s”) offer our customers the opportunity to perform periodic compliance audits, which include the examination of the accuracy of our invoices. Should our invoices be determined to be inconsistent with the MSA, the MSA’s may provide the customer the right to receive a credit or refund for any overcharges identified. At any given time, we mayAs of June 30, 2018 and December 31, 2017, there have multiple audits outstanding. At September 30, 2017, the Partnership had an estimated liability of $0.1 million recordedbeen no reserves established for suchcompliance audit contingencies.

  

Legal Proceedings

 

On July 3, 2014, a group of former minority shareholders of Tulsa Inspection Resources, Inc. (“TIR Inc.”), formerly an Oklahoma corporation, filed a civil actionFrom time to time, we are subject to legal proceedings and claims that arise in the United States District Court forordinary course of business. Currently, we are not a party to any material pending or overly threatened legal or governmental proceedings, other than proceedings and claims that arise in the Northern District of Oklahoma (the “District Court”) against TIR LLC, members of TIR LLC, and certain affiliates of TIR LLC’s members. TIR LLC is the successor in interest to TIR Inc., resulting from a merger of the entities. The former shareholders of TIR Inc. claim that they did not receive sufficient value for their sharesordinary course and are seeking compensatory and punitive damages. All claims against TIR LLC have been resolved by the District Court in TIR LLC’s favor, subjectincidental to appeal to the United States Court of Appeals for the Tenth Circuit, and plaintiffs have abandoned their claim for rescission of the merger. The remaining claims, none of which are asserted against the Partnership nor any subsidiary of the Partnership including TIR LLC, were adjudicated at jury trial that began on September 5, 2017. On September 14, 2017, the jury returned a unanimous verdict in favor of the defendants, finding that the value paid to the plaintiffs was fair and awarding them no damages.our business.

 

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 and9.     Sale of Saltwater Disposal Facilities

In May 2018, we sold our subsidiary Cypress Energy Partners – Orla SWD, LLC (“Orla”), which owns a saltwater disposal facility in Monahans, Texas, LLC failed to payan unrelated party for $8.0 million of cash proceeds. We recorded a classgain on this transaction of workers overtime in compliance with$1.6 million, which represents the Fair Labor Standards Act (“FLSA”) titled James Fithian, et al v. TIR LLC, et al inexcess of the United States District Court forcash proceeds over the Western Districtnet book value of Texas, Midland Division.assets sold. The plaintiff alleges he was a non-exempt employeenet book value of TIR LLC and that he and other potential class members were not paid overtime in compliance with the FLSA. The plaintiff seeksassets sold included $3.0 million of allocated goodwill, calculated based on the estimated fair value of the Orla facility relative to proceedthe estimated fair value of the Water Services reporting unit as a collective actionwhole. This calculation is considered Level 3 and to receive unpaid overtimethe fair values included in this calculation were determined utilizing discounted cash flows of the Orla facility and other monetary damages, including attorney’s fees. TIR LLC, CEM TIR andthe Water Services reporting unit as a whole as of the date of sale.

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

 

These gains, net of $0.1 million of charges related to the abandonment of a capital expansion project, are reported within Internal Revenue Service Auditgain on asset disposals, net on the Unaudited Condensed Consolidated Statements of Operations. We used the cash proceeds from these sales to repay $12.0 million of outstanding borrowings under our revolving credit facility.

 

21  

In January 2016, we received notice from the Internal Revenue Service (“IRS”) that conveyed its intent to audit the consolidated income tax return of one of our predecessor entities for the 2012 tax year. This audit concluded during the third quarter of 2017 with no material effect on the Partnership or its subsidiaries.


CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

 

10.Reportable Segments

10.  Reportable Segments

  

Our operations consist of three reportable segments: (i) Pipeline Inspection, Services (“PIS”), (ii) Integrity Services, (“IS”), and (iii) Water and Environmental Services (“W&ES”).Services.

 

PISPipeline Inspection This segment represents our pipeline inspection services operations. This segment provides independent inspection and integrity services to various energy, public utility, and pipeline companies. The inspectors in this segment perform a variety of inspection services on midstream pipelines, gathering and distribution systems, including data gathering and supervision of third-party construction, inspection, and maintenance and repair projects. Our results in this segment are driven primarily by the number and type of inspectors performing services for customers and the fees charged for those services, which depend on the nature and duration of the projects. Revenue and costs in this segment may be subject to seasonal variations and interim activity may not be indicative of yearly activity considering many of our customers develop yearly operating budgets and enter into contracts with us during the winter season for work to be performed during the remainder of the year.  Additionally, inspection work throughout the United States during the winter months (especially in the northern states) may be hampered or delayed considering sometimes inclement weather, thus affecting our revenue and costs.

 

IS Integrity Services– This segment provides independent hydrostatic testinghydro-testing integrity services to major natural gas and petroleum pipeline companies, and to pipeline construction companies located throughoutin the United States. Field personnel in this segment primarily perform hydrostatic testing on newly-constructed and existing natural gas and petroleum pipelines. Results in this segment are driven primarily by field personnel performing services for customers and the fees charged for those services, which depend on the nature, scope, and duration of the projects.  Revenue during the six months ended June 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).

 

W&ESWater Services This segment includes the operations of ten SWDeight saltwater disposal facilities and an ownership interest in one managed facility. Segment results are driven primarily by the volumes of water we inject into our SWDsaltwater disposal facilities and the fees we charge for our services. These fees are charged on a per-barrel basis and vary based on the quantity and type of 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) could affect drilling and trucking activity, and ultimately, our volumes, revenues and costs.

 

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


22  

CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

 

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

 

  PIS  IS  W&ES  Other  Total 
   (in thousands) 
Three months ended September 30, 2017                    
                     
Revenues $72,737  $2,834  $2,111  $  $77,682 
Costs of services  65,323   2,132   837      68,292 
Gross margin  7,414   702   1,274      9,390 
General and administrative  3,893 (a)  525 (a)  858   298  5,574 
Depreciation, amortization and accretion  577   157   450      1,184 
Losses on asset disposals, net        208      208 
Operating income (loss) $2,944  $20  $(242) $(298)  2,424 
Interest expense, net                  (1,907)
Foreign currency gains                  557 
Other, net                  17 
Net income before income tax expense                 $1,091 

(a)Amount includes $0.7 million and $0.3 million of administrative charges under the omnibus agreement charged directly to PIS and W&ES segments, respectivley.

Three months ended September 30, 2016                    
                     
Revenues $75,313  $4,525  $1,968  $  $81,806 
Costs of services  67,579   3,558   743      71,880 
Gross margin  7,734   967   1,225      9,926 
General and administrative  2,920   514   462   1,160(b)  5,056 
Depreciation, amortization and accretion  608   157   449      1,214 
Operating income (loss) $4,206  $296  $314  $(1,160) $3,656 
Interest expense, net                  (1,641)
Other, net                  210 
Net income before income tax expense                 $2,225 

(b)Amount includes $0.9 million of administrative charges incurred by Holdings on our behalf under the omnibus agreement not charged to separate segments.

CYPRESS ENERGY PARTNERS, L.P.

Notes to the Unaudited Condensed Consolidated Financial Statements

 PIS IS W&ES Other Total  Pipeline Integrity Water     
  (in thousands)  Inspection Services Services Other Total 
Nine months ended September 30, 2017                    
Three months ended June 30, 2018          (in thousands)          
                                        
Revenues $205,039  $5,927  $6,005  $  $216,971 
Revenue $70,365  $3,076  $3,027  $  $76,468 
Costs of services  185,308   5,005   2,330      192,643   62,475   2,091   959      65,525 
Gross margin  19,731   922   3,675      24,328   7,890   985   2,068      10,943 
General and administrative  10,212 (a)  1,488 (a)  1,651   2,662(b)  16,013   4,132 (a)  578   792 (b)  320   5,822 
Depreciation, amortization and accretion  1,755   471   1,335      3,561   573   148   389      1,110 
Impairments  1,329   1,581   688      3,598 
Losses on asset disposals, net  18      77      95 
Gain on asset disposal, net     (45)  (1,561)     (1,606)
Operating income (loss) $3,185  $304  $2,448  $(320)  5,617 
Interest expense, net                  (1,668)
Debt issuance cost write-off                  (114)
Foreign currency loss                  (117)
Other, net                  125 
Net income before income tax expense                 $3,843 
                    
Three months ended June 30, 2017                    
                    
Revenue $70,154  $2,397  $2,016  $  $74,567 
Costs of services  63,384   1,969   605      65,958 
Gross margin  6,770   428   1,411      8,609 
General and administrative  3,065   517   575   1,172(c)  5,329 
Depreciation, amortization and accretion  579   157   470      1,206 
(Gains) losses on asset disposals and insurance recoveries, net  18      (131)     (113)
Operating income (loss) $6,417  $(2,618) $(76) $(2,662)  1,061  $3,108  $(246) $497  $(1,172)  2,187 
Interest expense, net                  (5,411)                  (1,795)
Foreign currency gains                  824                   267 
Other, net                  122                   60 
Net loss before income tax expense                 $(3,404)
Net income before income tax expense                 $719 

 

(a)Amount includes $0.7 million andof the allocated quarterly administrative fee charged by Holdings specified in the omnibus agreement.
(b)Amount includes $0.3 million of the allocated quarterly administrative charges underfee charged by Holdings specified in the omnibus agreement charged directly to PIS and W&ES segments, respectively.agreement.
(b)(c) 

Amount includes $1.8$0.8 million of allocated general and administrative chargesexpenses incurred by Holdings on our behalf under the omnibus agreementbut not charged to separate segments.

us.  For the three months ended June 30, 2017, Holdings waived the administrative fee specified in the omnibus agreement.

 

Nine months ended September 30, 2016                    
                     
Revenues $209,632  $11,329  $6,630  $  $227,591 
Costs of services  189,788   9,668   3,084      202,540 
Gross margin  19,844   1,661   3,546      25,051 
General and administrative  9,439   2,388   1,501   3,477(c)  16,805 
Depreciation, amortization and accretion  1,834   502   1,349      3,685 
Impairments     8,411   2,119      10,530 
Operating income (loss) $8,571  $(9,640) $(1,423) $(3,477) $(5,969)
Interest expense, net                  (4,878)
Other, net                  257 
Net loss before income tax expense                 $(10,590)
23  

 

(c)Amount includes $2.9 million of administrative charges incurred by Holdings on our behalf under the omnibus agreement not charged to separate segments.

 

Total Assets                    
                     
September 30, 2017 $126,092  $9,979  $38,477  $(10,236) $164,312 
                     
December 31, 2016 $124,840  $12,079  $38,141  $(7,548) $167,512 

CYPRESS ENERGY PARTNERS, L.P.

 Notes to the Unaudited Condensed Consolidated Financial Statements

 

  Pipeline  Integrity  Water       
  Inspection  Services  Services  Other  Total 
  (in thousands) 
Six months ended June 30, 2018              
                
Revenue $128,332  $7,426  $5,536  $  $141,294 
Costs of services  114,955   5,248   2,019      122,222 
Gross margin  13,377   2,178   3,517      19,072 
General and administrative  7,891 (a)  1,123   1,628 (b)  635   11,277 
Depreciation, amortization and accretion  1,146   306   792      2,244 
Gain on asset disposal, net     (45)  (3,270)     (3,315)
Operating income (loss) $4,340  $794  $4,367  $(635)  8,866 
Interest expense, net                  (3,624)
Debt issuance cost write-off                  (114)
Foreign currency loss                  (451)
Other, net                  207 
Net income before income tax expense                 $4,884 
                     
Six months ended June 30, 2017                    
                     
Revenue $132,302  $3,093  $3,894  $  $139,289 
Costs of services  119,985   2,873   1,493      124,351 
Gross margin  12,317   220   2,401      14,938 
General and administrative  6,319   963   793   2,364(c)  10,439 
Depreciation, amortization and accretion  1,178   314   885      2,377 
Impairments  1,329   1,581   688      3,598 
(Gains) losses on asset disposals and insurance recoveries, net  18      (131)     (113)
Operating income (loss) $3,473  $(2,638) $166  $(2,364)  (1,363)
Interest expense, net                  (3,504)
Foreign currency gains                  267 
Other, net                  105 
Net loss before income tax expense                 $(4,495)
                     
Total Assets                    
                     
June 30, 2018 $111,402  $10,528  $24,278  $2,311  $148,519 
                     
December 31, 2017 (recast to exclude intercompany receivables) $120,368  $10,481  $31,472  $882  $163,203 

(a)Amount includes $1.4 million of allocated quarterly administrative fee charged by Holdings specified in the omnibus agreement.
(b)Amount includes $0.6 million of allocated quarterly administrative fee charged by Holdings specified in the omnibus agreement.
11.(c)Condensed Consolidating Financial InformationAmount includes $1.8 million of allocated general and administrative expenses incurred by Holdings but not charged to us.  For the six months ended June 30, 2017, Holdings waived the administrative fee specified in the omnibus agreement.

 

The following financial information reflects consolidating financial information of the Partnership and its wholly owned guarantor subsidiaries and non-guarantor subsidiaries for the periods indicated. The information is presented in accordance with the requirements of Rule 3-10 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of financial position, results of operations, or cash flows had the guarantor subsidiaries or non-guarantor subsidiaries operated as independent entities. The Partnership has not presented separate financial and narrative information for each of the guarantor subsidiaries or non-guarantor subsidiaries because it believes such financial and narrative information would not provide any additional information that would be material in evaluating the sufficiency of the guarantor subsidiaries and non-guarantor subsidiaries. The Partnership anticipates issuing debt securities that will be fully and unconditionally guaranteed by the guarantor subsidiaries. These debt securities will be jointly and severally guaranteed by the guarantor subsidiaries. There are no restrictions on the Partnership’s ability to obtain cash dividends or other distributions of funds from the guarantor subsidiaries.


24  

CYPRESS ENERGY PARTNERS, L.P.

 Notes to the Unaudited Condensed Consolidated Financial Statements

 

 Condensed Consolidating Balance Sheet

 As of September 30, 2017

 (in thousands) 

 

        Non-       
  Parent  Guarantors  Guarantors  Eliminations  Consolidated 
                
 ASSETS                    
 Current assets:                    
 Cash and cash equivalents $567  $10,005  $8,666  $  $19,238 
 Trade accounts receivable, net     46,295   3,770   (120)  49,945 
 Accounts receivable - affiliates     15,064      (15,064)   
 Prepaid expenses and other  324   1,253   33      1,610 
 Total current assets  891   72,617   12,469   (15,184)  70,793 
 Property and equipment:                    
 Property and equipment, at cost     17,338   3,017      20,355 
 Less:  Accumulated depreciation     7,205   1,429      8,634 
 Total property and equipment, net     10,133   1,588      11,721 
 Intangible assets, net     22,179   4,001      26,180 
 Goodwill     53,914   1,516      55,430 
 Investment in subsidiaries  24,953   (3,383)     (21,570)   
 Notes receivable - affiliates     13,845      (13,845)   
 Other assets     163   25      188 
 Total assets $25,844  $169,468  $19,599  $(50,599) $164,312 
                     
 LIABILITIES AND OWNERS’ EQUITY                    
 Current liabilities:                    
 Accounts payable $  $1,303  $868  $  $2,171 
 Accounts payable - affiliates  13,098      5,534   (15,064)  3,568 
 Accrued payroll and other  97   11,508   757   (120)  12,242 
 Income taxes payable     571   177      748 
 Total current liabilities  13,195   13,382   7,336   (15,184)  18,729 
 Long-term debt  (758)  131,400   5,500      136,142 
 Notes payable - affiliates        13,845   (13,845)   
 Deferred tax liabilities               
 Asset retirement obligations     161         161 
 Total liabilities  12,437   144,943   26,681   (29,029)  155,032 
                     
 Owners’ equity:                    
 Total partners’ capital  9,659   20,777   (7,082)  (17,822)  5,532 
 Non-controlling interests  3,748   3,748      (3,748)  3,748 
 Total owners’ equity  13,407   24,525   (7,082)  (21,570)  9,280 
 Total liabilities and owners’ equity $25,844  $169,468  $19,599  $(50,599) $164,312 

CYPRESS ENERGY PARTNERS, L.P.

 Notes to the Unaudited Condensed Consolidated Financial Statements

 Condensed Consolidating Balance Sheet

 As of December 31, 2016

 (in thousands) 

        Non-       
  Parent  Guarantors  Guarantors  Eliminations  Consolidated 
                
 ASSETS                    
 Current assets:                    
 Cash and cash equivalents $695  $20,251  $5,747  $  $26,693 
 Trade accounts receivable, net     33,046   6,125   (689)  38,482 
 Accounts receivable - affiliates     12,622      (12,622)   
 Prepaid expenses and other     996   46      1,042 
 Total current assets  695   66,915   11,918   (13,311)  66,217 
 Property and equipment:                    
 Property and equipment, at cost     19,366   3,093      22,459 
 Less:  Accumulated depreciation     6,798   1,042      7,840 
 Total property and equipment, net     12,568   2,051      14,619 
 Intangible assets, net     23,875   5,749      29,624 
 Goodwill     53,914   2,989      56,903 
 Investment in subsidiaries  29,454   (417)     (29,037)   
 Notes receivable - affiliates     13,662      (13,662)   
 Other assets     139   10      149 
 Total assets $30,149  $170,656  $22,717  $(56,010) $167,512 
                     
 LIABILITIES AND OWNERS’ EQUITY                    
 Current liabilities:                    
 Accounts payable $  $1,653  $712  $(675) $1,690 
 Accounts payable - affiliates  8,860      5,400   (12,622)  1,638 
 Accrued payroll and other  15   7,082   503   (15)  7,585 
 Income taxes payable     967   44      1,011 
 Total current liabilities  8,875   9,702   6,659   (13,312)  11,924 
 Long-term debt  (1,201)  131,400   5,500      135,699 
 Notes payable - affiliates        13,662   (13,662)   
 Deferred tax liabilities     8   354      362 
 Asset retirement obligations     139         139 
 Total liabilities  7,674   141,249   26,175   (26,974)  148,124 
                     
 Owners’ equity:                    
 Total partners’ capital  17,425   24,357   (3,458)  (23,986)  14,338 
 Non-controlling interests  5,050   5,050      (5,050)  5,050 
 Total owners’ equity  22,475   29,407   (3,458)  (29,036)  19,388 
 Total liabilities and owners’ equity $30,149  $170,656  $22,717  $(56,010) $167,512 

CYPRESS ENERGY PARTNERS, L.P.

 Notes to the Unaudited Condensed Consolidated Financial Statements

 Condensed Consolidating Statement of Operations

 For the Three Months Ended September 30, 2017

 (in thousands) 

        Non-       
  Parent  Guarantors  Guarantors  Eliminations  Consolidated 
                
 Revenues $  $73,607  $7,762  $(3,687) $77,682 
 Costs of services     65,042   6,937   (3,687)  68,292 
 Gross margin     8,565   825      9,390 
                     
 Operating costs, expenses and other:                    
 General and administrative  297   4,617   660      5,574 
 Depreciation, amortization and accretion     1,027   157      1,184 
 Losses on asset disposals, net     208         208 
 Operating income (loss)  (297)  2,713   8      2,424 
                     
 Other (expense) income:                    
 Equity earnings (loss) in subsidiaries  920   (118)     (802)  
 Interest expense, net  (229)  (1,460)  (218)     (1,907)
 Foreign currency gains     141   416      557 
 Other, net     7   10      17 
 Net income (loss) before income tax expense  394   1,283   216   (802)  1,091 
 Income tax expense     425   104      529 
 Net income (loss)  394   858   112   (802)  562 
                     
 Net Income (loss) attributable to noncontrolling interests     8         8 
 Net income (loss) attributable to partners / controlling interests  394   850   112   (802)  554 
                     
 Net loss attributable to general partner  (1,000)           (1,000)
 Net income (loss) attributable to limited partners $1,394  $850  $112  $(802) $1,554 

CYPRESS ENERGY PARTNERS, L.P.

 Notes to the Unaudited Condensed Consolidated Financial Statements

 Condensed Consolidating Statement of Operations

 For the Three Months Ended September 30, 2016

 (in thousands) 

        Non-       
  Parent  Guarantors  Guarantors  Eliminations  Consolidated 
                
 Revenues $  $67,408  $18,540  $(4,142) $81,806 
 Costs of services     59,156   16,866   (4,142)  71,880 
 Gross margin     8,252   1,674      9,926 
                     
 Operating costs and expense:                    
 General and administrative  1,161   2,905   990      5,056 
 Depreciation, amortization and accretion     1,029   185      1,214 
 Operating (loss)  (1,161)  4,318   499      3,656 
                     
 Other income (expense):                    
 Equity earnings (loss) in subsidiaries  3,205   165      (3,370)   
 Interest expense, net  (224)  (1,226)  (191)     (1,641)
 Other, net     205   5      210 
 Net income (loss) before income tax expense  1,820   3,462   313   (3,370)  2,225 
 Income tax expense     176   51      227 
 Net income (loss)  1,820   3,286   262   (3,370)  1,998 
                     
 Net income attributable to non-controlling interests     81         81 
 Net income (loss) attributable to controlling interests  1,820   3,205   262   (3,370)  1,917 
                     
 Net (loss) attributable to general partner  (1,431)           (1,431)
 Net income (loss) attributable to limited partners $3,251  $3,205  $262  $(3,370) $3,348 

CYPRESS ENERGY PARTNERS, L.P.

 Notes to the Unaudited Condensed Consolidated Financial Statements

 Condensed Consolidating Statement of Operations

 For the Nine Months Ended September 30, 2017

 (in thousands) 

        Non-       
  Parent  Guarantors  Guarantors  Eliminations  Consolidated 
                
 Revenues $  $188,740  $35,572  $(7,341) $216,971 
 Costs of services     166,803   33,181   (7,341)  192,643 
 Gross margin     21,937   2,391      24,328 
                     
 Operating costs, expenses and other:                    
 General and administrative  2,662   10,975   2,376      16,013 
 Depreciation, amortization and accretion     3,071   490      3,561 
 Impairments     688   2,910      3,598 
 Losses on asset disposals, net     88   7      95 
 Operating income (loss)  (2,662)  7,115   (3,392)     1,061 
                     
 Other (expense) income:                    
 Equity earnings (loss) in subsidiaries  1,002   (3,008)     2,006    
 Interest expense, net  (682)  (4,128)  (601)     (5,411)
 Foreign currency gains     211   613      824 
 Other, net     103   19      122 
 Net income (loss) before income tax expense  (2,342)  293   (3,361)  2,006   (3,404)
 Income tax expense     581   (123)     458 
 Net income (loss)  (2,342)  (288)  (3,238)  2,006   (3,862)
                     
 Net Income (loss) attributable to noncontrolling interests     (1,290)        (1,290)
 Net income (loss) attributable to partners / controlling interests  (2,342)  1,002   (3,238)  2,006   (2,572)
                     
 Net loss attributable to general partner  (2,750)           (2,750)
 Net income (loss) attributable to limited partners $408  $1,002  $(3,238) $2,006  $178 

CYPRESS ENERGY PARTNERS, L.P.

 Notes to the Unaudited Condensed Consolidated Financial Statements

 Condensed Consolidating Statement of Operations

 For the Nine Months Ended September 30, 2016

 (in thousands) 

        Non-       
  Parent  Guarantors  Guarantors  Eliminations  Consolidated 
                
 Revenues $  $193,605  $44,734  $(10,748) $227,591 
 Costs of services     171,844   41,444   (10,748)  202,540 
 Gross margin     21,761   3,290      25,051 
                     
 Operating costs and expense:                    
 General and administrative  3,478   9,601   3,726      16,805 
 Depreciation, amortization and accretion     3,099   586      3,685 
 Impairments     2,119   8,411      10,530 
 Operating (loss)  (3,478)  6,942   (9,433)     (5,969)
                     
 Other income (expense):                    
 Equity earnings (loss) in subsidiaries  (1,889)  (9,999)     11,888    
 Interest expense, net  (664)  (3,607)  (607)     (4,878)
 Other, net     243   14      257 
 Net income (loss) before income tax expense  (6,031)  (6,421)  (10,026)  11,888   (10,590)
 Income tax expense     366   23      389 
 Net income (loss)  (6,031)  (6,787)  (10,049)  11,888   (10,979)
                     
 Net (loss) attributable to non-controlling interests     (4,898)        (4,898)
 Net income (loss) attributable to controlling interests  (6,031)  (1,889)  (10,049)  11,888   (6,081)
                     
 Net (loss) attributable to general partner  (5,366)           (5,366)
 Net income (loss) attributable to limited partners $(665) $(1,889) $(10,049) $11,888  $(715)

CYPRESS ENERGY PARTNERS, L.P.

 Notes to the Unaudited Condensed Consolidated Financial Statements

 Condensed Consolidating Statement of Comprehensive Income (Loss)

 For the Three Months Ended September 30, 2017

 (in thousands) 

        Non-       
  Parent  Guarantors  Guarantors  Eliminations  Consolidated 
                
 Net income (loss) $394  $858  $112  $(802) $562 
 Other comprehensive income (loss) -                    
 Foreign currency translation       (207)     (207)
                     
 Comprehensive income (loss) $394  $858  $(95 $(802) $355 
                     
 Comprehensive income (loss) attributable to noncontrolling interests     8         8 
 Comprehensive loss attributable to general partner  (1,000)           (1,000)
 Comprehensive income (loss) attributable to limited partners $1,394  $850  $(95) $(802) $1,347 

 Condensed Consolidating Statement of Comprehensive Income (Loss)

 For the Three Months Ended September 30, 2016

 (in thousands) 

        Non-       
  Parent  Guarantors  Guarantors  Eliminations  Consolidated 
                
 Net income (loss) $1,820  $3,286  $262  $(3,370) $1,998 
 Other comprehensive income (loss) -                    
 Foreign currency translation     (109)  38      (71)
                     
 Comprehensive income (loss) $1,820  $3,177  $300  $(3,370) $1,927 
                     
 Comprehensive income attributable to noncontrolling interests     81         81 
 Comprehensive loss attributable to general partner  (1,431)           (1,431)
 Comprehensive income (loss) attributable to limited partners $3,251  $3,096  $300  $(3,370) $3,277 

CYPRESS ENERGY PARTNERS, L.P.

 Notes to the Unaudited Condensed Consolidated Financial Statements

 Condensed Consolidating Statement of Comprehensive Income (Loss)

 For the Nine Months Ended September 30, 2017

 (in thousands) 

        Non-       
  Parent  Guarantors  Guarantors  Eliminations  Consolidated 
                
 Net income (loss) $(2,342) $(288) $(3,238) $2,006  $(3,862)
 Other comprehensive income -                    
 Foreign currency translation     (59)  (128)     (187)
                     
 Comprehensive income (loss) $(2,342) $(347) $(3,366) $2,006  $(4,049)
                     
 Comprehensive income (loss) attributable to noncontrolling interests     (1,290)        (1,290)
 Comprehensive loss attributable to general partner  (2,750)           (2,750)
 Comprehensive income (loss) attributable to limited partners $408  $943  $(3,366) $2,006  $(9)

 Condensed Consolidating Statement of Comprehensive Income (Loss)

 For the Nine Months Ended September 30, 2016

 (in thousands) 

        Non-       
  Parent  Guarantors  Guarantors  Eliminations  Consolidated 
                
 Net income (loss) $(6,031) $(6,787) $(10,049) $11,888  $(10,979)
 Other comprehensive income -                    
 Foreign currency translation     82   433      515 
                     
 Comprehensive income (loss) $(6,031) $(6,705) $(9,616) $11,888  $(10,464)
                     
 Comprehensive loss attributable to non-controlling interests     (4,898)        (4,898)
 Comprehensive loss attributable to general partner  (5,366)           (5,366)
 Comprehensive income (loss) attributable to controlling interests $(665) $(1,807) $(9,616) $11,888  $(200)

CYPRESS ENERGY PARTNERS, L.P.

 Notes to the Unaudited Condensed Consolidated Financial Statements

 Condensed Consolidating Statement of Cash Flows

 For the Nine Months Ended September 30, 2017

 (in thousands) 

        Non-       
  Parent  Guarantors  Guarantors  Eliminations  Consolidated 
                
 Operating activities:                    
 Net income (loss) $(2,342) $(288) $(3,238) $2,006  $(3,862)
 Adjustments to reconcile net income (loss) to cash provided by (used in) operating activities:                    
 Depreciation, amortization and accretion     3,484   894      4,378 
 Impairments     688   2,910      3,598 
 (Gain) loss on asset disposal     88   7      95 
 Interest expense from debt issuance cost amortization  443            443 
 Equity-based compensation expense  1,136            1,136 
 Equity in earnings of investee     (98)        (98)
 Distributions from investee     75         75 
 Equity earnings in subsidiaries  (1,002)  3,008      (2,006)   
 Deferred tax benefit, net     (8)  (353)     (361)
 Non-cash allocated expenses  1,750            1,750 
 Foreign currency gains     (211)  (613)    (824)
 Changes in assets and liabilities:                    
 Trade accounts receivable     (13,249)  2,235   (569)  (11,583)
 Receivables from affiliates     (2,442)     2,442    
 Prepaid expenses and other  (323)  (635)  11  182   (765)
 Accounts payable and accrued payroll and other  4,320   3,756   531   (2,055)  6,552 
 Income taxes payable     (396)  125      (271)
 Net cash provided by (used in) operating activities  3,982   (6,228)  2,509      263
                     
 Investing activities:                    
 Proceeds from fixed asset disposals     1,576   2      1,578 
 Purchases of property and equipment     (1,169)  (13)     (1,182)
 Net cash provided by (used in) investing activities     407   (11)     396 
                     
 Financing activities:                    
 Taxes paid related to net share settlement of equity-based compensation  (120)           (120)
 Contributions from general partner  1,000            1,000 
 Distributions from subsidiaries  4,823   (4,812)  (11)      
 Distributions to limited partners  (9,813)           (9,813)
 Distributions to non-controlling members        (12)     (12)
 Net cash used in financing activities  (4,110)  (4,812)  (23)     (8,945)
                     
 Effects of exchange rates on cash     387   444      831 
                     
 Net increase (decrease) in cash and cash equivalents  (128)  (10,246)  2,919      (7,455)
 Cash and cash equivalents, beginning of period  695   20,251   5,747      26,693 
 Cash and cash equivalents, end of period $567  $10,005  $8,666  $  $19,238 
                     
 Non-cash items:                    
 Changes in accounts payable excluded from capital expenditures $  $320  $  $  $320 

CYPRESS ENERGY PARTNERS, L.P.

 Notes to the Unaudited Condensed Consolidated Financial Statements

 Condensed Consolidating Statement of Cash Flows

 For the Nine Months Ended September 30, 2016

 (in thousands) 

        Non-       
  Parent  Guarantors  Guarantors  Eliminations  Consolidated 
                
 Operating activities:                    
 Net income (loss) $(6,031) $(6,787) $(10,049) $11,888  $(10,979)
 Adjustments to reconcile net income (loss) to cash provided by (used in) operating activities:                    
 Depreciation, amortization and accretion     3,379   975      4,354 
 Impairments     2,119   8,411      10,530 
 Gain on asset disposal        (2)     (2)
 Interest expense from debt issuance cost amortization  426            426 
 Equity-based compensation expense  829            829 
 Equity in earnings of investee     (234)        (234)
 Distributions from investee     138         138 
 Equity earnings in subsidiaries  1,889   9,999      (11,888)   
 Deferred tax benefit, net     (30)  (9)     (39)
 Non-cash allocated expenses  2,866            2,866 
 Changes in assets and liabilities:                    
 Trade accounts receivable     5,498   (2,326)  1,827   4,999 
 Receivables from affiliates     (2,401)     2,401    
 Prepaid expenses and other  (36)  (101)  217   973   1,053 
 Accounts payable and accrued payroll and other  2,791   3,435   2,812   (5,236)  3,802 
 Income taxes payable     (118)  (1)  35   (84)
 Net cash provided by operating activities  2,734   14,897   28      17,659 
                     
 Investing activities:                    
 Proceeds from fixed asset disposals        3      3 
 Purchases of property and equipment     (687)  (245)     (932)
 Net cash used in investing activities     (687)  (242)     (929)
                     
 Financing activities:                    
 Repayments of long-term debt     (4,000)        (4,000)
 Taxes paid related to net share settlement of equity awards  (100)           (100)
 Contribution attributable to general partner  2,500            2,500 
 Distributions from subsidiaries  9,622   (9,239)  (383)      
 Distributions to limited partners  (14,439)           (14,439)
 Distributions to non-controlling members        (415)     (415)
 Net cash used in financing activities  (2,417)  (13,239)  (798)     (16,454)
                     
 Effects of exchange rates on cash     82   395      477 
                     
 Net increase (decrease) in cash and cash equivalents  317   1,053   (617)     753 
 Cash and cash equivalents, beginning of period  378   19,570   4,202      24,150 
 Cash and cash equivalents, end of period $695  $20,623  $3,585  $  $24,903 
                     
 Non-cash items:                    
Accrued capital expenditures $  $12  $64  $  $76 

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, 20162017 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, 20162017 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 (“PIS”Pipeline Inspection”) segment is comprised of our investment in the TIR Entities; (2) our Integrity Services (“IS”Integrity Services”) segment, made up of our 51% ownership investment in Brown Integrity, LLC and; (3) our Water and Environmental Services (W&ES”(“Water Services”) segment, comprised of our investments in various salt watersaltwater disposal (“SWD”) facilities and activities related thereto. The financial information for PIS, ISPipeline Inspection, Integrity Services and W&ESWater 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, 2016.2017.

 

Overview

 

We are a growth-oriented master limited partnership formed in September 2013 to provide services to the oil and gas industry. We provide independent pipeline inspection and integrity services to midstream companies and their vendors, public utility companies, and energy exploration and production (“E&P”) companies, public utility companies, and midstream companies and their vendors in our PISPipeline Inspection and ISIntegrity Services segments throughout the United States and Canada. The PISPipeline Inspection segment is comprised of the operations of the TIR Entities and the ISIntegrity Services segment is comprised of the operations of Brown. We also provide SWDsaltwater disposal and other water and environmental services to U.S. onshore oil and natural gas producers and trucking companies through our W&ESWater Services segment. We operate ten SWDeight saltwater disposal facilities eight of which are located in the Bakken Shale region of the Williston Basin in North Dakota andDakota. We sold two of which aresaltwater disposal facilities located in the Permian Basin in west Texas.West Texas in the first half of 2018. We also have a management agreement in place to provide staffing and management services to an SWDa saltwater disposal facility in the Bakken Shale region (a facility in which we own a 25% interest). W&ESWater Services customers are oil and natural gas exploration and production companies and trucking companies operating in the regions that we serve. In all of our business segments, we work closely with our customers to help them comply with increasingly complex and strict environmental and safety rules and regulations applicable to production and pipeline operations, assisting in reducing their operating costs.

 

Ownership

 

As of SeptemberJune 30, 2017,2018, Holdings owns approximately 58.6%58.3% of the Partnership,Partnership's common units, while affiliates of Holdings own approximately 5.8%5.7% of the Partnership,Partnership's common units, for a total ownership percentage of the PartnershipPartnership's common units of approximately 64.4%64.0% by Holdings and its affiliates. Holdings’ ownership group also owns 100% of the General Partner and the incentive distribution rights.rights (“IDR’s”) and an affiliate of our General Partner 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 a quarterly administrative fee in the amount of $1.0 million to Holdings, for providing certain partnership overhead services, including certain executive management services by certain officers and employees of our General Partner, and payroll services for substantially all employees required to manage and operate our businesses.Partner. This fee also includes the incremental general and administrative expenses we incur as a result of being a publicly traded partnership.  For the three and six months ended SeptemberJune 30, 2017,2018, this fee was paid to Holdings in accordance with its terms and conditions.  For the three and six months ended June 30, 2017, and for the year ended December 31, 2016, Holdings provided sponsor support to the Partnership by waiving payment of the quarterly administrative fee;


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

 

 indemnification of us by Holdings for certain environmental and other liabilities, including events and conditions associated with the operation of assets that occurred prior to the closing of the IPO and our obligation to indemnify Holdings for events and conditions associated with the operation of our assets that occur after the closing of the IPO and for environmental liabilities related to our assets to the extent Holdings is not required to indemnify us.

 

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

 

Holdings incurred expenses of $0.9$0.8 million and $1.8 million on our behalf during the three and six months ended SeptemberJune 30, 2016, and $1.8 million and $2.9 million on our behalf during the nine months ended September 30, 2017, and 2016, respectively. These expenses are reported within general and administrative in the accompanying Unaudited Condensed Consolidated Statements of Operations and as contributions fromnet loss attributable to general partner in the accompanying Unaudited Condensed Consolidated StatementStatements of Owners’ Equity.Operations.

In addition to funding certain general and administrative expenses on our behalf, Holdings contributed $1.0 million and $0.5 million during the three months ended September 30, 2017 and 2016, respectively, and a total of $2.5 million for the nine months ended September 30, 2016 attributable to the General Partner as a reimbursement of certain expenditures previously incurred by the Partnership. These payments are reflected as contributions attributable to general partner in the Unaudited Condensed Consolidated Statement of Owners’ Equity and as components of the net loss attributable to the general partner in the Unaudited Condensed Consolidated Statement of Operations for the three and nine month periods ended September 30, 2017 and 2016.

Total support from Holdings attributable to non-cash allocated expenses and the reimbursement of certain expenditures was $1.0 million and $2.8 million, respectively, for the three and nine months ended September 30, 2017 and $1.4 million and $5.4 million, respectively, for the three and nine months ended September 30, 2016.

 

Pipeline Inspection Services

 

We generate revenue in the PISPipeline Inspection segment primarily by providing inspection services on midstream pipelines, gathering systems, and distribution systems, including data gathering and supervision of third-party construction, inspection, and maintenance and repair projects. Our results in this segment are driven primarily by the number of inspectors that perform services for our customers and the fees that we charge for those services, which depend on the type and number of inspectors used on a particular project, the nature of the project, and the duration of the project. The number of inspectors engaged on projects is driven by the type of project, prevailing market rates, the age and condition of customers’ midstream pipelines, gathering and distribution systems, and the legal and regulatory requirements relating to the inspection and maintenance of those assets. We charge our customers on a per-inspector basis, including per diem charges, mileage, and other reimbursement items.

 

Integrity Services

 

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

 

Water and Environmental Services

 

We generate revenue in the W&ESWater Services segment primarily by treating flowback and produced water and injecting the saltwater into our SWDsaltwater disposal facilities. Our results are driven primarily by the volumes of produced water and flowback water we inject into our SWDsaltwater disposal facilities and the fees we charge for these services. These fees are charged on a per-barrel basis under contracts that are short-term in nature and vary based on the quantity and type of saltwater disposed, competitive dynamics, and operating costs. In addition, for minimal marginal cost, we generate revenue by selling residual oil we recover from the water.saltwater. We also generate revenue managing an SWDa saltwater disposal facility for a fee.

 

The volumes of saltwater disposed at our SWDsaltwater disposal facilities are driven by water volumes generated from existing oil and natural gas wells during their useful lives and development drilling and production volumes from wells located near our facilities.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, (“NGLs”), the cost to drill and operate a well, the availability and cost of capital, and environmental and governmental regulations. We generally expect the level of drilling to correlate with long-term trends in prices of oil, natural gas, and NGLs.natural gas liquids.


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

 

Outlook

 

Overall

 

ForWe are encouraged by our PIS and IS business segments, revenues, margins, and margin percentages were higher in the third quarter of 2017 than they werepositive results in the second quarter of 2017, even though some projects were delayed due2018. All three of our business lines continued to Hurricane Harvey,show solid growth during the second quarter as anticipated. The strength of our recovery can be clearly seen in significant improvements in EBITDA and distributable cash flow compared with prior periods. Our pipeline inspection business, TIR, achieved an important milestone in June, celebrating its fifteenth anniversary. TIR has been profitable every year of its history, has proven its resiliency during the financial crisis and the recent energy downturn, and recorded over $268 million of revenue in the year ended December 31, 2017. During the second quarter, we completed our previously announced refinancing and have significantly reduced our debt by approximately 44% from the end of 2017. We now enjoy a much stronger balance sheet with a net leverage of approximately 3.09x EBITDA.

Our customers have recovered nicely from the downturn, benefitting from the material improvement in commodity prices that have led to increases in spending on maintenance and growth capital expenditures which, struckin turn, benefits our business. These fundamental improvements in the gulf coast in August 2017. This is generally consistent withenergy industry underpin the seasonality inherentconfidence we have in our business outlook. The last three years have been marked by the most significant energy downturn in whichgenerations, and we have capitalized on a number of competitive opportunities while simultaneously transforming our Company to be even more competitive in the third quarterbroad-based recovery that ultimately benefits our Company. We continue to expand our lines of each year is generally the strongest quarterbusiness and have reached new levels of the annualefficiency in all our activities as demonstrated in all three of our business cycle.segments. We believe that our PIScontinue to look at some exciting acquisition and IS segments will have many opportunities over the next several years, as many customer projects previously delayed have recently been approved. We have also invested in organic growth opportunities and have started two new business units this year, withremain ready to capture these opportunities coming from the latest business unit offering mechanical integrity services, a new line ofpositive market fundamentals. Demand for our inspection and integrity support. This new lineservices have remained strong. Our Pipeline Inspection and Integrity Services segments represented approximately 96% of business has already been awarded several new projects from investment-grade companies.our revenues and approximately 81% of our gross margin during the three months ended June 30, 2018.

 

For our Pipeline Inspection Services segment,The average inspector headcount was higher infrom U.S. operations of 1,183 during the thirdsecond quarter of 2017 than it2018 was a 9.8% increase from the U.S. inspector headcount during second quarter 2017. Revenues and gross margins during 2018 have also benefitted from two new service lines that we developed in 2017. Our gross margin percentage continues to improve (11.2% in the second quarter of 2017, despite2018, compared to 9.5% in the lossfirst quarter of over 200 inspectors2018 and 9.7% in Canada earlier this year. We have continued tothe second quarter of 2017) as a result of our focus on our nondestructive examination business, staking, and mechanical integrity, businesses and the revenues of these business lines were higher in the third quarter 2017 than in any previous quarter. These businesses typically generate higher margins than our legacy inspection business. We expect revenues of our Canadian operations to be much lower in the future than they have been in the recent past due to the loss of low margin work from our largest Canadian customer at the end of the second quarter. We continue to support this customer with higher margin integrityhigher-margin services.

 

Revenues of our 51% owned Integrity Services segment of $7.4 million during the first six months of 2018 were considerably higher than revenues of $3.1 million during the first six months of 2017. Our margin percentage of 29.3% in 2018 was also considerably higher than the margin percentage of 7.1% in the thirdfirst six months of 2017.

Our Water Services segment continues to benefit from higher rig counts, activity, and oil prices. Revenues from our North Dakota operations continue to significantly improve ($3.0 million during the second quarter of 2017 than they were2018, compared to $2.4 million during the first quarter of 2018 and $1.5 million during the second quarter of 2017), due to increased customer activity and the completion in January 2018 of a new pipeline gathering system into one of our facilities.

We also sold our two saltwater disposal facilities in West Texas earlier this year on attractive terms, and now operate our Water Services segment solely in the Bakken region of North Dakota, where we believe we have better economies of scale. We currently operate nine saltwater disposal facilities with nine different connected pipelines. Approximately 43% of our water disposal volumes in the second quarter of 2017, as our utilization rate significantly improved and our backlog has remained healthy. Earlier in 2017, we hired new business development personnel to assist in2018 were received via these efforts and we have seen some successful increases in backlog forpipelines, with additional pipelines currently under development. During the fourthsecond quarter of 2017 and the first quarter of 2018. We continue to bid on numerous upcoming work opportunities and remain focused on winning more of these bids in an on-going effort to increase our volume and backlog.

Revenues2018, approximately 90% of our Water and Environmental Services segment were 5% higher in third quarter 2017 than in the second quarter. Two of our facilities are located in the Permian basin, which has experienced an increase in production activity. The remainder of our facilities are in the Bakken region, where the recovery of production activity has been slower. However, through the nine months ended September 30, 2017, a substantial amount of acquisition activity has occurred with private equity backed energy companies acquiring both production and acreage in the Bakken with plans to increase drilling which, in turn, will create substantial amounts of new water for disposal. Additionally, in both regions, a significant number of wells have been drilled but not yet completed. Once producers complete these wells, we expect to have the opportunity to generate additional volumes and revenues. As previously disclosed, two of our facilities were struck by lightning and one remains out of service. Our Orla, Texas facility should be fully rebuilt and open for regular business in December, and we continue to work with our insurance company on the covered loss at our Grassy Butte facility in North Dakota. We also continue to work on the growth capital expenditure development of awas produced water gathering system that will connect three large five well pads into one of our existing facilities in the Bakken for a large public energy company.

Despite the low commodity prices of recent years, we maintained positive operating cash flows during the year ended December 31, 2016 and expect to generate positive operating cash flows for the year ending December 31, 2017.from completed oil wells.

 

We continue to evaluate several interestingpursue acquisition opportunities, including continued due diligence of one sizable exclusive opportunity currently under a letter of intent. Areas of focusopportunities. The previously-announced strategic alternatives process continues as well. We continue to be traditional midstream opportunitiesbelieve the long-term increasing demand for inspection and opportunities inintegrity services and water solutions remains strong due to our existing lines of business. Holdings remains willing to deploy capital to assist us in acquiring attractive assets that may be larger than what we can currently acquire independently, with plans to offer those assets to us as drop-down opportunities.nation’s aging pipeline infrastructure, growing production, and increasing governmental regulations.

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Pipeline Inspection Services

Demand is once again growing for our pipeline inspection services, as wePipeline Inspection segment. We operate in a very large market, with well over 1,000 customer prospects that we do not currently serve who require federalfederally and/or state mandatedstate-mandated inspection and integrity services. During the second quarter of 2018 we added 5  new customers.

 

AnA Stifel energy research analyst recently published the following multi-year pipeline industry update that is summarized below:

 

2017 Forecast: Estimated 2017 pipeline spending of $25.5 billion, a 5.1% increase over 2016 levels of $24.2 billion. This follows very strong growth of 25.2% in 2016. With this update, essentially shifted all pipeline construction activity that has not yet begun, or is firmly scheduled to begin in the next two months, into future years.

2018 Forecast: TrackingStifel is tracking $38.5 billion of pipeline/midstream infrastructure spending proposed for 2018. On a probability-weighted basis, forecastedStifel forecasts all-in potential 2018 spending of $33.1 billion, or a 30.2% year-to-year increase.increase year over year. If only highest confidence Tier 1 projects were to move forward, this would produce 13.7% year-to-year growth. Layering in moderate confidence Tier 2 projects, the growth forecast rises to 25.3%.

 

2019 and beyond: AnticipatedStifel anticipates 2019 spending will reflect growth over 2018 levels. Given that the databaseStifel’s projections only includesinclude announced, named pipeline projects, theStifel's tracker currently reflects a decline in proposed activity in 2019 and 2020. This is a function of the timing of project announcements, and is expected to rise throughthroughout 2018. Virtually every industry contact/contact and source along the supply chain, including equipment providers, engineers and construction sources, are suggestingsuggest that 2019 could postshow continued growth offfrom the record activity of a record 2018.

 

Bidding and award activity is accelerating following delays related to the lack of a quorum at FERC. Recall thatDuring the first half of 2017, the Federal Energy Regulatory Commission (“FERC”) lacked a quorum for roughly 6 months, delayingwhich delayed large project approval activity in the first half of 2017.approval. The FERC’s quorum was re-established on August 10, 2017, with the swearing-in of Robert Powelson. At the time theFERC's quorum was re-established, it was estimated that approximately $14 billion of pipeline projects had been backlogged. FERC is beginning to take action on the queue, with NEXUS, Atlantic Coast, and the Mountain Valley Pipelines approved in October.October of 2017.

 

TrackingContinued growth in the award of large pipeline projects. Stifel is tracking nearly $30 billion in projects that could be awarded over the next approximately 12 months and believebelieves that at least $4.5 billion worth of projects isare currently out to bid. This bodes well forcould result in additional large pipeline project awards for contractors in late 2017/early 2018.throughout 2018, which would benefit our inspection and integrity segments. Developers are concerned about procuring quality construction partners, given that the industry is likely to reach full utilization in 2018. This generally bodes well for contractor pricing, terms, and conditions.conditions, which could then result in favorable pricing, terms and conditions for us.

Our continued focus remains on both maintenance and integrity work on existing pipelines as well as work on new projects. The majority of our existing and potential customers are once again investing in their businesses following a difficult economic downturn. We continue to focus on new lines of business to serve our existing customers, including mechanical integrity and pipeline pig cleaning, and decontamination services. The majority of our clients are public, investment-grade companies with long planning cycles that lead to healthy backlogs of new long-term projects and existing pipeline networks that also require inspection and integrity services. We believe that with regulatory requirements, andcoupled with the aging pipeline infrastructure, mean that, regardless of low commodity prices or low oil demand, our customers will still require our regulatory inspection services.  Therefore, the PISPipeline Inspection business is more insulated from changes in commodity prices in the near term than it has been the case in the past. However, a prolonged depression in oil and natural gas prices could lead to a downturn in demand for our services as was the case in recent years. 

 

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The two year downturn in energy prices required many of our customers that rely more heavily on commodity prices to focus on reducing their operating costs, leverage, and in many cases they delayed or cancelled new projects. Several clients have sought to reduce the rates paid to inspectors to reduce their inspection costs. We have recently renewed several sizable existing contracts and are bidding on several new contracts. However, we continue to see certain of our customers’ projects slipping past original start dates as a result of permitting or other delays. This has improved substantially following the change in the FERC administration as noted above. Year to date in 2017, we added 26 new customers. 

 

Integrity Services

 

Brown, our 51% owned hydrostatic testinghydrotesting business unit, has seen a significant improvement through 2017 in its utilization rate and backlog.rates in 2018. Brown had a difficult year in 2016, which forced us to implement aggressive measures to manage and reduce its cost structure. We have recently hiredbelieve our new business development personnel who are focusedstrategy is working, and we plan to continue to focus on the potential synergies that may develop between ISthis segment and our other current customers, of the Partnership, as well as the growth and nurturenurturing of Brown’s historical, ongoing business. The initial results have been encouraging and the new construction projects referenced above should significantly benefit Brown. Brown operated in 13 states during 2016, compared with over 40 states that the TIR Entities (through our PIS segment) operated in throughout 2016. Year-to-date inIn 2017, Brown has worked in 15 states and has successfully obtained new business from TIR relationships. Brown’s revenues and gross margins improved in the third quarter along with its backlog.first half of 2018 compared to the first half of 2017. Brown continues to enjoy an excellent reputation in the industry and has a substantial amount of new work that it is currently bidding to win. Year-to-date in 2017, Brown added 10 new customers.

 

Water and Environmental Services

 

Quarterly volumes in our W&ESOur Water Services segment grew 5%disposed of 3.6 million barrels of saltwater during the second quarter of 2018, which was an increase over the prior2.2 million barrels disposed during the second quarter despite two of 2017 (exclusive of the volumes relating to our Texas facilities, having been hit by lightning earlierwhich were sold in the year.2018). Our average revenue per barrel held steady at $0.68increased to $0.85 (inclusive of water disposal, oil reclamation, and management fees) in the second quarter of 2018, an increase over the average revenue per barrel (inclusive of disposal fees, residual oil sales, and management fees).$0.68 during the second quarter of 2017, due in part to an increase in revenues associated with the gathering system that we placed into service in January 2018. Drilling activity has improved dramatically following the downturn and the lowlows that occurred in May 2016. AsBaker Hughes North America Rotary Rig Count had the following information as of the end of October 2017, as reported publicly by Baker Hughes:July 20, 2018:

  

Total USThe U.S. rig count of 909,totaled 1,046, including 379 in the Permian basin and 4956 in the Williston basin/basin of the Bakken;

 

Rigs haveThe U.S. rig count has increased 125%159%, or 505642 rigs, from the May 2016 trough of 404;404 rigs; and

 

Rigs still remainThe U.S. rig count remains down 52.9%46%, or 1,022885 rigs, from the September 2014 peak of 1,931.1,931 rigs.

 

Crude oil prices have also improved,increased, and at the end of October, WTIin July 2018 NYMEX Near Month crude exceeded $54$69.00 per barrel of oil.barrel. The decline in the market price of crude oil whichthat began in the second half of 2014 has had an adverse impact on our volumes and revenues over the last three years. The resultant slowdown in exploration and production activity led to lower new drilling activity, volumes, and commodity prices from sales of crude oil we recover from the water we process. In addition, many of our E&P customers requested pricing concessions to help them cope with the lower commodity prices and the market became over supplied relative to activity levels. In the majority of the basins in the country, new SWDsaltwater disposal facilities were developed to support previous rig counts and activity levels prior to the sharp contraction in activity and commodity prices. These events have led to excess SWDsaltwater disposal facility supply relative to current demand in many locations, including the Bakken, and the Permian that in turn has led to aggressive pricing.

 

We have always focused on produced water and piped water whenever possible instead of trucked flowback water, and therefore we believe we have been less impacted than many of our competitors during the oil and gas economic downturn.competitors. During the second quarter of 2018, 90% of our volumes were produced water and approximately 45%43% of our water was receivedvolumes were delivered via pipelines. In the second quarter of 2016, we took aggressive actions to reduce operating costs in an effort to offset the financial impact of continued depressed market volumes and prices, and continue to see the positive results of those actions, including gross margins exceeding 60%. Additionally, weWe continue to focus on piped water opportunities to secure additional long-term volumes of produced water for the life of the oil and gas wells’ production and currently are working on a growth capital expenditure project to develop a water gathering system that will connect to 15 oil wells for a public energy company in the Bakken. We also provide management services for a Bakken SWD facility in which we also own a 25% interest.production.

 

We continue to actively pursue the right acquisition opportunities with the same discipline that protected the Partnershipus during a heated market in 2014 and 2013 that drove up valuations to unsustainable levels leading to many bankruptcies and restructurings. We also continue to evaluate and compete for some interesting opportunities for pipelines and new SWDsaltwater disposal facilities directly with E&P companies seeking to monetize their midstream assets or minimize their spending on infrastructure required to support their production. We continue to work collaboratively with our customers to help them address the volatility in commodity prices and their need to reduce operating expenses. We also continue to carefully evaluate market pricing on a facility-by-facility basis to ensure we remain competitive.

 

In JanuaryJuly of 2017, a lightning strike at our Orla, TexasGrassy Butte saltwater disposal facility was struck by lightning. Theinitiated a fire that destroyed the surface storage equipment at the facility. It did not damage our pumps, electrical, housing, office, or downhole facilities were not damaged and wefacilities. We had insurance covering the surface facilities with a reasonable deductible. We do not carry business interruption insurance given its costs, waiting periods,rebuilt and coverages. Within two weeks,reopened the Grassy Butte facility re-opened with temporary surface facilities.in June 2018.

In January of 2018, we sold our subsidiary that owned a saltwater disposal facility in Pecos, Texas to an unrelated party. We have begun the redevelopment process with insurancereceived $4.0 million of cash proceeds and plan to have this facility fully functional in December. We continue to take both piped and trucked water with temporary facilities. In July 2017, a lightning strike at our Grassy Butte, North Dakota SWD facility initiated a fire that effectively destroyed the surface storage equipment at the facility, but it did not damage our pumps, electrical, housing, office, or downhole facilities. The facility has been closed while we negotiate our insurance claim. We have reached an agreement with the insurance carrier and plan to commence reconstruction with the intent to open for business againperpetual royalty interest in the first quarterfuture revenues of 2018.the facility. In May of 2018, we sold our subsidiary that owns a saltwater disposal facility in Orla, Texas to an unrelated party for $8.0 million.

 


29  

Results of Operations

 

Consolidated Results of Operations

 

The following table summarizes our Unaudited Condensed Consolidated Statements of Operations for the three and ninesix month periods ended SeptemberJune 30, 20172018 and 2016:2017:

 

 Three Months Ended
September 30,
 Nine Months Ended
September 30,
  Three Months Ended June 30, Six Months Ended June 30, 
 2017 2016 2017 2016  2018 2017 2018 2017 
   (in thousands)    

 (in thousands)

 
                
Revenues $77,682  $81,806  $216,971  $227,591 
Revenue $76,468  $74,567  $141,294  $139,289 
Costs of services  68,292   71,880   192,643   202,540   65,525   65,958   122,222   124,351 
Gross margin  9,390   9,926   24,328   25,051   10,943   8,609   19,072   14,938 
                                
Operating costs and expense:                                
General and administrative - segment  5,276   3,896   13,351   13,328   5,502   4,157   10,642   8,075 
General and administrative - corporate  298   1,160   2,662   3,477   320   1,172   635   2,364 
Depreciation, amortization and accretion  1,184   1,214   3,561   3,685   1,110   1,206   2,244   2,377 
Impairments        3,598   10,530            3,598 
Losses on asset disposals, net  208      95    
Gain on asset disposals, net  (1,606)  (113)  (3,315)  (113)
Operating income (loss)  2,424   3,656   1,061   (5,969)  5,617   2,187   8,866   (1,363)
                                
Other income (expense):                
Other (expense) income:                
Interest expense, net  (1,907)  (1,641)  (5,411)  (4,878)  (1,668)  (1,795)  (3,624)  (3,504)
Foreign currency gains  557      824    
Debt issuance cost write-off  (114)     (114)   
Foreign currency gains (losses)  (117)  267   (451)  267 
Other, net  17   210   122   257   125   60   207   105 
Net income (loss) before income tax expense  1,091   2,225   (3,404)  (10,590)  3,843   719   4,884   (4,495)
Income tax expense  529   227   458   389 
Income tax expense (benefit)  287   222   368   (71)
Net income (loss)  562   1,998   (3,862)  (10,979)  3,556   497   4,516   (4,424)
                                
Net income (loss) attributable to noncontrolling interests  8   81   (1,290)  (4,898)  149   (133)  384   (1,298)
Net income (loss) attributable to partners / controlling interests  554   1,917   (2,572)  (6,081)  3,407   630   4,132   (3,126)
                                
Net loss attributable to general partner  (1,000)  (1,431)  (2,750)  (5,366)     (829)     (1,750)
Net income (loss) attributable to limited partners $1,554  $3,348  $178  $(715)  3,407   1,459   4,132   (1,376)
Net income attributable to preferred unitholder  367      367    
Net income (loss) attributable to common unitholders $3,040  $1,459  $3,765  $(1,376)

 

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

General and administrative – corporate. General and administrative-corporateadministrative - corporate decreased by $1.7 million for the six months ended June 30, 2018 compared to the six months ended June 30, 2017, due primarily to the waiving of the two $1.0 million quarterly administrative fees due to the omnibus administrative expense charge of $1.0 million that was incurredHoldings in the third quartersix months ended June 30, 2017. Amounts in the six months ended June 30, 2017 include $1.8 million of 2017 and recorded in general and administrative-segment in 2017.  This omnibus administrative expense was waived by the sponsor in 2016. Amounts recorded in general and administrative-corporate include administrative expenses incurred by Holdings on our behalf (andthat they elected not charged to us)charge us. During each of the first two quarters of 2018, we paid the $1.0 million administrative fee, and this expense is reported in general and administrative – segment in the table above ($1.4 million of which was allocated to the Pipeline Inspection segment and $0.6 million of which was allocated to the Water Services segment).

 

Interest expense. Interest expense primarily consists of interest on borrowings under our Credit Agreement, as well as amortization of debt issuance costs and unused commitment fees. Interest expense increased from 2016for the six months ended June 30, 2017 to 2017the six months ended June 30, 2018 primarily due to an increase in interest rates. This increase was partially offset by a decrease in interest expense resulting from a reduction in the borrowings outstanding under 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. 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 ninesix months ended SeptemberJune 30, 2018 and 2017 and 2016 was $136.9$121.1 million and $137.6$136.9 million, respectively. The average interest rate on our borrowings has increased from 4.08%4.48% in the ninesix months ended SeptemberJune 30, 20162017 to 4.62%5.32% in the ninesix months ended SeptemberJune 30, 2017.2018. 

30  

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

 

Foreign currency gains.gains (losses). During the threeOur Canadian subsidiary has certain intercompany payables to our U.S.-based subsidiaries. Such intercompany payables and nine months ended September 30,receivables among our consolidated subsidiaries are eliminated in our Unaudited Condensed Consolidated Balance Sheets. Beginning April 1, 2017, we recorded $0.6 million and $0.8 million, respectively, of income associated withreport currency translation adjustments on these intercompany balances amongpayables and receivables within foreign currency gains (losses) in our consolidated subsidiaries.Unaudited Condensed Consolidated Statements of Operations. The net foreign currency losses during the six months ended June 30, 2018 resulted from the depreciation of the Canadian dollar relative to the U.S. dollar. The net foreign currency gains during the six months ended June 30, 2017 resulted from the appreciation of the Canadian dollar relative to the U.S. dollar.

 

Other, net. Other income includesprimarily consists of income associated with our 25% interest in an SWDa saltwater disposal facility, which we account for under the equity method.method, royalty income, and interest income.


Income tax expense. Income tax expense includes income taxes related to two of our taxable corporate subsidiaries in the United States and one taxable corporate subsidiary in Canada (two in our PISPipeline Inspection segment and one in our ISIntegrity Services segment), as well as business activity, gross margin, and franchise taxes incurred in certain states. 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.

 

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

 

Net loss attributable to general partner. The net loss attributable to the general partner during the three and ninesix months ended SeptemberJune 30, 2017 and 2016 consists of expenses that Holdings incurred on our behalf. Since Holdings did not charge us for these expenses, we recorded these expenses as an equity contribution from our general partner.

Net income attributable to preferred unitholder. On May 29, 2018, we issued and sold $43.5 million of preferred equity. The net lossholder of the preferred units is entitled to an annual return of 9.5% on this investment. The earnings attributable to the general partner in the three and nine months ended September 30, 2017 also includes $1.0 million of cash support provided by the General Partner for reimbursement of expenses. The net loss attributable to the general partner in the three and nine months ended September 30, 2016 also includes $0.5 million and $2.5 million, respectively, of cash support provided by the General Partner for reimbursement of expenses.preferred unitholder reflects this return.

31  

 

Segment Operating Results

 

Pipeline Inspection Services (PIS)

 

The following table summarizes the operating results of the PISPipeline Inspection segment for the three months ended SeptemberJune 30, 20172018 and 2016.2017.  

 

 Three Months Ended September 30, 
 2017 % of Revenue 2016 % of Revenue Change % Change  Three Months Ended June 30, 
 (in thousands, except average revenue and inspector data)  2018 % of
Revenue
 2017 % of
Revenue
 Change % Change 
    (in thousands, except average revenue and inspector data) 
Revenue $72,737      $75,313      $(2,576)  (3.4)% $70,365      $70,154      $211   0.3%
Costs of services  65,323       67,579       (2,256)  (3.3)%  62,475       63,384       (909)  (1.4)%
Gross margin  7,414   10.2%  7,734   10.3%  (320)  (4.1)%  7,890   11.2%  6,770   9.7%  1,120   16.5%
                                                
General and administrative  3,893   5.4%  2,920   3.9%  973   33.3%  4,132   5.9%  3,065   4.4%  1,067   34.8%
Depreciation, amortization and accretion  577   0.8%  608   0.8%  (31)  (5.1)%
Depreciation and amortization   573   0.8%  579   0.8%  (6)  (1.0)%
Losses on asset disposals, net         18   0.0%  (18)  (100.0)%
Operating income $2,944   4.0% $4,206   5.6% $(1,262)  (30.0)% $3,185   4.5% $3,108   4.4% $77   2.5%
                                                
Operating Data                                                
Average number of inspectors  1,211       1,231       (20)  (1.6)%  1,188       1,186       2   0.2%
Average revenue per inspector per week $4,570      $4,655      $(85)  (1.8)% $4,556      $4,550      $6   0.1%
                        
Revenue variance due to number of inspectors                 $(1,201)                     $118     
Revenue variance due to average revenue per inspector                 $(1,375)                     $93     

32  

 

Revenues.Revenue. Revenues decreased $2.6Revenue of the Pipeline Inspection segment increased $0.2 million during the three months ended SeptemberJune 30, 20172018 compared to the three months ended SeptemberJune 30, 2016,2017, due to slight increases in the average number of inspectors engaged (an increase of 2 inspectors accounting for $0.1 million of the revenue increase) and in the average revenue billed per inspector (accounting for $0.1 million of the revenue increase).

Revenue attributable to our U.S. operations increased $6.7 million during the three months ended June 30, 2018 compared to the three months ended June 30, 2017, due to increased activity by our clients and increased business development efforts, including the expansion of the non-destructive examination business and the formation of two new lines of businesses. This increase was partially offset by a decrease of $6.5 million in revenues attributable to our Canadian operations, due primarily to the loss of our largest Canadian customer in the second quarter of 2017 (this customer completed a bidding process and awarded new contracts to other service providers at rates that were lower than we were willing to accept).

Average revenue per inspector fluctuates 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. Competition remains intense in the industry, which continues to exert pressure on rates.

Costs of services. Costs of services decreased $0.9 million during the three months ended June 30, 2018 compared to the three months ended June 30, 2017, due to fluctuations in our costs related to the different types of inspection services we provide.

Gross margin. Gross margin increased $1.1 million during the three months ended June 30, 2018 compared to the three months ended June 30, 2017. The gross margin percentage improved to 11.2% in the second quarter of 2018, compared to 9.7% in the second quarter of 2017. The increase in gross margin percentage is due to changes in the mix of services provided and the loss of low margin work that was generated in Canada during 2017. In addition, during the three months ended June 30, 2018, we generated more revenues from our public utility and nondestructive examination service lines, which typically produce higher margins.

General and administrative. General and administrative expenses increased by $1.1 million during the three months ended June 30, 2018 compared to the three months ended June 30, 2017, due primarily to $0.7 million of expense associated with the administrative fee charged by Holdings that was recorded by our Pipeline Inspection segment. During the three months ended June 30, 2017, Holdings waived this administrative fee. Compensation expense associated with our U.S. operations increased by approximately $0.4 million during the three months ended June 30, 2018, due to an increase in personnel to support our growing businesses. These increases were partially offset by a decrease of $0.3 million in general and administrative expenses related to our Canadian operations as a result of reduced business activity.

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

Operating income. Operating income increased $0.1 million during the three months ended June 30, 2018 compared to the three months ended June 30, 2017, due primarily to the increase in gross margin, partially offset by an increase in general and administrative expenses (primarily related to our payment of the administrative fee charged by Holdings in the second quarter of 2018, which was waived in the second quarter of 2017). 

33  

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

  Six Months Ended June 30, 
  2018  % of Revenue  2017  % of Revenue  Change  % Change 
  (in thousands, except average revenue and inspector data) 
Revenue $128,332      $132,302      $(3,970)  (3.0)%
Costs of services  114,955       119,985       (5,030)  (4.2)%
Gross margin  13,377   10.4%  12,317   9.3%  1,060   8.6%
                         
General and administrative  7,891   6.1%  6,319   4.8%  1,572   24.9%
Depreciation and amortization  1,146   0.9%  1,178   0.9%  (32)  (2.7)%
Impairments         1,329   1.0%  (1,329)  (100.0)%
Losses on asset disposals, net         18   0.0%  (18)  (100.0)%
Operating income $4,340   3.4% $3,473   2.6% $867   25.0%
                         
Operating Data                        
Average number of inspectors  1,109       1,135       (26)  (2.3)%
                         
Average revenue per inspector per week $4,475      $4,508      $(33)  (0.7)%
Revenue variance due to number of inspectors                 $(3,009)    
Revenue variance due to average revenue per inspector                 $(961)    

Revenue. Revenue of the Pipeline Inspection segment decreased $4.0 million during the six months ended June 30, 2018 compared to the six months ended June 30, 2017, due to a decrease in the average number of inspectors engaged (a decrease of 2026 inspectors accounting for a $1.2$3.0 million of the revenue decrease) and a reductiondecrease in the average revenue billed for eachper inspector (accounting for a $1.4$1.0 million of the revenue decrease).

 

Revenues ofRevenue attributable to our Canadian business decreased $8.6U.S. operations increased $16.2 million during the threesix months ended SeptemberJune 30, 20172018 compared to the threesix months ended SeptemberJune 30, 2016,2017, due to increased activity by our clients and increased business development efforts, including the expansion of the non-destructive examination business and the formation of two new lines of businesses. This increase was offset by a decrease of $20.2 million in revenues attributable to our Canadian operations, due primarily to the loss of a majorour largest Canadian customer in the second quarter of 2017. This decrease was partially offset by an increase of $6.0 million in our U.S. domestic business lines, including increases of $1.3 million in our public utility business2017 (this customer completed a bidding process and $0.8 million in nondestructive examinationawarded new contracts to other service line during the three months ended September 30, 2017 comparedproviders at rates that were lower than we were willing to the three months ended September 30, 2016.


Costs of services. Costs of services decreased $2.3 million during the three months ended September 30, 2017 compared to the three months ended September 30, 2016, corresponding to the decrease in revenue.

Gross margin. Gross margin decreased $0.3 million during the three months ended September 30, 2017 compared to the three months ended September 30, 2016, due to lower revenues and a slightly decreased margin percentage.

General and administrative. General and administrative expenses increased $1.0 million, of which $0.7 million was due to the omnibus administrative expense charge incurred and allocated to the segments in the third quarter of 2017 that was waived by Holdings in 2016 and recorded in general and administrative-corporate.

Depreciation and amortization. Depreciation and amortization expense during the third quarter of 2017 was not significantly different from depreciation and amortization expense during the third quarter of 2016.

Operating income. Operating income decreased $1.3 million during the three months ended September 30, 2017 compared to the three months ended September 30, 2016, due primarily to the increased general and administrative expenses and the decreased gross margin in the third quarter of 2017 compared to the third quarter of 2016. 

The following table summarizes the operating results of the PIS segment for the nine months ended September 30, 2017 and 2016.  

  Nine Months Ended September 30, 
  2017  % of Revenue  2016  % of Revenue  Change  % Change 
  (in thousands, except average revenue and inspector data) 
    
Revenue $205,039      $209,632      $(4,593)  (2.2)%
Costs of services  185,308       189,788       (4,480)  (2.4)%
Gross margin  19,731   9.6%  19,844   9.5%  (113)  (0.6)%
                         
General and administrative  10,212   5.0%  9,439   4.5%  773   8.2%
Depreciation, amortization and accretion  1,755   0.9%  1,834   0.9%  (79)  (4.3)%
Impairments  1,329   0.6%     0.0%  1,329     
Losses on asset disposals and insurance recoveries, net  18   0.0%     0.0%  18     
Operating income $6,417   3.1% $8,571   4.1% $(2,154)  (25.1)%
                         
Operating Data                        
                         
Average number of inspectors  1,160       1,165       (5)  (0.4)%
Average revenue per inspector per week $4,532      $4,597      $(65)  (1.4)%
                         
Revenue variance due to number of inspectors                 $(884)    
Revenue variance due to average revenue per inspector                 $(3,709)    

40

Revenues. Revenues decreased $4.6 million during the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016, primarily due to a decrease in the average number of inspectors engaged (a decrease of 5 inspectors accounting for a $0.9 million revenue decrease) and a reduction in the average revenue billed for each inspector (accounting for a $3.7 million revenue decrease)accept). We continue to focus on areas of inspection that are less impacted by economic conditions, such as maintenance projects and projects associated with public utility companies, to help mitigate the decline in revenues associated with new construction projects. Revenues of our nondestructive examination service line increased by $2.9 million during the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016.

 

The decline in average revenue per inspector is due to changes in customer mix. Fluctuations in the average revenue per inspector per year are expected, given that we charge different rates for different types of inspectors and different types of inspection services. Competition remains strongintense in the industry, which continues to exert downward pressure on rates.

 

Costs of services. Costs of services decreased $4.5$5.0 million during the ninesix months ended SeptemberJune 30, 20172018 compared to the ninesix months ended SeptemberJune 30, 2016,2017, due primarily to lower revenues.fewer inspectors in the field, consistent with the decrease in revenue during the same period and fluctuations in our costs related different types of inspection services we provide.

  

Gross margin. Gross margin remained relatively consistentincreased $1.1 million during the ninesix months ended SeptemberJune 30, 20172018 compared to the ninesix months ended SeptemberJune 30, 2016. Gross2017. The gross margin percentage changes can be attributableimproved to 10.4% in 2018, compared to 9.3% in 2017. The increase in gross margin percentage is due to changes in the mix of services provided.provided and the loss of low margin work that was generated in Canada. In addition, during the six months ended June 30, 2018, we generated more revenues from our public utility and nondestructive examination service lines, which typically produce higher margins.

 

General and administrative.General and administrative expenses increased $0.8by $1.6 million during the six months ended June 30, 2018 compared to the three months ended June 30, 2017, due primarily to $1.4 million of expense associated with the administrative fee charged by Holdings that was recorded by our Pipeline Inspection segment. During the six months ended June 30, 2017, Holdings waived this administrative fee. Compensation expense associated with our U.S. operations increased approximately $0.4 million during the six months ended June 30, 2018, due to the omnibus administrative expense charge incurred and allocatedan increase in personnel to the segments in the third quartersupport our growing businesses. These increases were partially offset by a decrease of 2017 that was waived by Holdings in 2016 and recorded$0.4 million in general and administrative-corporate.administrative expenses related to our Canadian operations as a result of reduced business activity. 

34  

 

Depreciation and amortization. Depreciation and amortization expense during the ninesix months ended SeptemberJune 30, 20172018 was not significantly different from depreciation and amortization expense during the ninesix months ended SeptemberJune 30, 2016.2017.

  

Impairments. During the first quarter of 2017, the largest customer of our Canadian subsidiary completed a bid process and selected different service providers for its inspection contracts. In consideration of the loss of this contract, we recorded impairments to the carrying values of certain intangible assets of $1.3 million in the first quarter of 2017. Of this amount, $1.1 million related to customer relationships and $0.2 million related to trade names.

 

Operating income. Operating income decreased $2.2increased by $0.9 million during the ninesix months ended SeptemberJune 30, 20172018 compared to the ninesix months ended SeptemberJune 30, 2016,2017, due primarily to $1.3 million of impairments and to anthe increase in generalgross margin and the absence of impairment expense in 2018 that incurred in 2017, partially offset by our payment of the quarterly administrative costsfees charged by Holdings in 2018, which fees were waived in the first two quarters of $0.8 million. 2017.


35  

Integrity Services (IS)

 

The following table summarizes the results of the ISIntegrity Services segment for the three months ended SeptemberJune 30, 20172018 and 2016.2017. 

 

 Three Months Ended September 30, 
 2017 % of Revenue 2016 % of Revenue Change % Change  Three Months Ended June 30, 
 (in thousands, except average revenue and inspector data)  2018 % of Revenue 2017 % of Revenue Change % Change 
              (in thousands, except average revenue and inspector data) 
Revenue $2,834      $4,525      $(1,691)  (37.4)% $3,076      $2,397      $679   28.3%
Costs of services  2,132       3,558       (1,426)  (40.1)%  2,091       1,969       122   6.2%
Gross margin  702   24.8%  967   21.4%  (265)  (27.4)%  985   32.0%  428   17.9%  557   130.1%
                                                
General and administrative  525   18.5%  514   11.4%  11   2.1%  578   18.8%  517   21.6%  61   11.8%
Depreciation, amortization and accretion  157   5.5%  157   3.5%     0.0%
Depreciation and amortization  148   4.8%  157   6.5%  (9)  (5.7)%
Gain on asset disposals, net  (45)  (1.5)%         (45)    
Operating income (loss) $20   0.7% $296   6.5% $(276)  (93.2)% $304   9.9% $(246)  (10.3)% $550   (223.6)%
                                                
Operating Data                                                
Average number of field personnel  21       25       (4)  (16.0)%  22       18       4   22.2%
Average revenue per field personnel per week $10,268      $13,772      $(3,504)  (25.4)% $10,755      $10,244      $511   5.0%
Revenue variance due to number of field personnel                 $(540)                     $559     
Revenue variance due to average revenue per field personnel                 $(1,151)                     $120     

Revenue. Revenues decreased approximately $1.7Revenue increased $0.7 million during the three months ended SeptemberJune 30, 20172018 compared to the three months ended SeptemberJune 30, 20162017. The Integrity Services segment won more bids for large projects, and as a result, employee utilization was significantly higher in the second quarter of 2018 than in the second quarter of 2017. The increase in successful bids was due to a $0.5 million decrease in the average number of field personnel engaged in customer projectsimproving market conditions and a decrease in the average revenue charged per field personnel of $1.2 million. Revenues during the three months ended September 30, 2017 continued to be adversely affected by a slowdown in new projects by our customers and by the loss during 2016 of keyimproved business development employees. Earlier in 2017, we hired new business development personnel to assist in these efforts and we have seen some success via increases in backlog for the fourth quarter of 2017 and the first quarter of 2018.efforts.

 

Costs of services. Cost of services decreased approximately $1.4increased $0.1 million during the three months ended SeptemberJune 30, 20172018 compared to the three months ended SeptemberJune 30, 2016, consistent with the decrease2017, due to an increase in revenue.revenues.

  

Gross margin. Gross margin decreased approximately $0.3increased $0.6 million during the three months ended SeptemberJune 30, 20172018 compared to the three months ended SeptemberJune 30, 2016, due2017. The employees of the Integrity Services segment who perform work in the field are full-time employees, and therefore represent fixed costs (in contrast to the employees of the Pipeline Inspection segment who perform work in the field, most of whom only earn wages when they are performing work for a customer and whose wages are primarily to lower revenues, partially offset by an improvedvariable costs). Because these employees were more fully utilized during the three months ended June 30, 2018, the gross margin percentage.percentage was higher.

 

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 SeptemberJune 30, 20172018 compared to the three months ended SeptemberJune 30, 2016.2017.

 

Depreciation and amortization. Depreciation expense includes depreciation of property and equipment and amortization of intangible assets associated with customer relationships, trade names, and noncompete agreements. Depreciation and amortization expense during the three months ended SeptemberJune 30, 20172018 was not significantly different from depreciation and amortization expense during the three months ended SeptemberJune 30, 2016.2017.

 

Operating income (loss). Operating income (loss) decreased $0.3increased by $0.6 million during the three months ended SeptemberJune 30, 20172018 compared to the three months ended SeptemberJune 30, 2016,2017, due primarily to the decrease inhigher gross margin.margins of $0.6 million.


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The following table summarizes the results of the ISIntegrity Services segment for the ninesix months ended SeptemberJune 30, 20172018 and 2016.2017. 

 

 Nine Months Ended September 30, 
 2017 % of Revenue 2016 % of Revenue Change % Change  Six Months Ended June 30, 
 (in thousands, except average revenue and inspector data)  2018 % of Revenue 2017 % of Revenue Change % Change 
    (in thousands, except average revenue and inspector data) 
Revenue $5,927      $11,329      $(5,402)  (47.7)% $7,426      $3,093      $4,333   140.1%
Costs of services  5,005       9,668       (4,663)  (48.2)%  5,248       2,873       2,375   82.7%
Gross margin  922   15.6%  1,661   14.7%  (739)  (44.5)%  2,178   29.3%  220   7.1%  1,958   890.0%
                                                
General and administrative  1,488   25.1%  2,388   21.1%  (900)  (37.7)%  1,123   15.1%  963   31.1%  160   16.6%
Depreciation, amortization and accretion  471   7.9%  502   4.4%  (31)  (6.2)%
Depreciation and amortization  306   4.1%  314   10.2%  (8)  (2.5)%
Gain on asset disposals, net  (45)  (0.6)%         (45)    
Impairments  1,581   26.7%  8,411   74.2%  (6,830)  (81.2)%         1,581   51.1%  (1,581)  (100.0)%
Operating loss $(2,618)  (44.2)% $(9,640)  (85.1)% $7,022   (72.8)%
Operating income (loss) $794   10.7% $(2,638)  (85.3)% $3,432   (130.1)%
                                                
Operating Data                                                
Average number of field personnel  18       24       (6)  (25.0)%  22       17       5   29.4%
                                                
Average revenue per field personnel per week $8,443      $12,059      $(3,616)  (30.0)% $13,054      $7,036      $6,018   85.5%
Revenue variance due to number of field personnel                 $(1,976)                     $1,688     
Revenue variance due to average revenue per field personnel                 $(3,426)                     $2,645     

Revenue. Revenues decreased approximately $5.4Revenue increased $4.3 million during the ninesix months ended SeptemberJune 30, 20172018 compared to the ninesix months ended SeptemberJune 30, 2016. Approximately $2.0 million of the decrease2017. The Integrity Services segment won more bids for large projects, and as a result, employee utilization was significantly higher in 2018 than in 2017. The increase in successful bids was due to improving market conditions and to improved business development efforts. Revenue during the six months ended June 30, 2018 included $0.3 million associated with additional billings on a decreaseproject that we completed in the average numberfourth quarter of field personnel engaged in2017 (we recognized the revenue upon receipt of customer projects and approximately $3.4 millionacknowledgment of the decrease was due to a decrease in the average revenue per field personnel generated. Revenues during the nine months ended September 30, 2017 have been adversely affected by a slowdown in new projects by our customers and by the loss during 2016 of key business development employees.additional fees).

 

Costs of services. Cost of services decreased approximately $4.7increased $2.4 million during the ninesix months ended SeptemberJune 30, 20172018 compared to the ninesix months ended SeptemberJune 30, 2016,2017, due primarily to the slowdownan increase in business activity.revenues.

 

Gross margin. Gross margin decreased approximately $0.7increased $2.0 million during the ninesix months ended SeptemberJune 30, 20172018 compared to the ninesix months ended SeptemberJune 30, 2016, due2017. The employees of the Integrity Services segment who perform work in the field are full-time employees, and therefore represent fixed costs (in contrast to the employees of the Pipeline Inspection segment who perform work in the field, most of whom only earn wages when they are performing work for a customer and whose wages are primarily to lower revenues, partially offset by an improvedvariable costs). Because these employees were more fully utilized during the six months ended June 30, 2018, the gross margin percentage. percentage was higher.

 

General and administrative. General and administrative expenses primarily include compensation expense for office employees and general office expenses. These expenses decreasedincreased by $0.9$0.2 million during the ninesix months ended SeptemberJune 30, 20172018 compared to the ninesix months ended SeptemberJune 30, 2016,2017, due primarily to cost-cutting measures we implemented in responseincreased costs related to the continued low-revenue environment. These measures included the closure of one office location.business development personnel and efforts.


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Depreciation and amortization. Depreciation expense includes depreciation of property and equipment and amortization of intangible assets associated with customer relationships, trade names, and noncompete agreements. Depreciation and amortization expense during the ninesix months ended SeptemberJune 30, 20172018 was not significantly different from depreciation and amortization expense during the ninesix months ended SeptemberJune 30, 2016.2017.

 

Impairments. During the first quarter of 2017, we recorded ana full impairment to the goodwill of $1.6 millionthe Integrity Services segment. Although we had recently won bids on a number of projects and our backlog had begun to goodwill. Duringimprove, the nine months ended September 30, 2016,improvement in the backlog had been slower than we recorded an impairmenthad anticipated, and accordingly, we revised downward our expectations of $8.4 million to goodwill. Asthe near-term operating results of March 31, 2017, goodwill in this segment was fully impaired.the segment. 

 

Operating loss.income (loss). Operating loss decreasedincome increased by $7.0$3.4 million during the ninesix months ended SeptemberJune 30, 20172018 compared to the ninesix months ended SeptemberJune 30, 2016,2017. This increase was due primarilyin part to a lower goodwill impairment chargehigher gross margins of $6.8$2.0 million and, lower general and administrative expensesin part, to the absence of $0.9 million, partially offset by a $0.7 million decreaseany impairment expense in the gross margin.six months ended June 30, 2018 compared to $1.6 million of impairment expense recorded during the six months ended June 30, 2017.

 

Water & Environmental Services (W&ES)

 

The following table summarizes the operating results of the W&ESWater Services segment for the three months ended SeptemberJune 30, 20172018 and 2016.2017.

 

  Three Months Ended September 30, 
  2017  % of Revenue  2016  % of Revenue  Change  % Change 
  (in thousands, except per barrel data) 
    
Revenue $2,111      $1,968      $143   7.3%
Costs of services  837       743       94   12.7%
Gross margin  1,274   60.4%  1,225   62.2%  49   4.0%
                         
General and administrative  858   40.6%  462   23.5%  396   85.7%
Depreciation, amortization and accretion  450   21.3%  449   22.8%  1   0.2%
Losses on asset disposals, net  208   9.9%         208     
Operating income (loss) $(242)  (11.5)% $314   16.0% $(556)  (177.1)%
                         
Operating Data                        
Total barrels of saltwater disposed  3,102       2,937       165   5.6%
Average revenue per barrel disposed (a) $0.68      $0.67      $0.01   2.0%
Revenue variance due to barrels disposed                 $111     
Revenue variance due to revenue per barrel                 $32     
(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. Revenues increased $0.1 million during the three months ended September 30, 2017 compared to the three months ended September 30, 2016, due primarily to a 5.6% increase in the volume of saltwater disposed. The increase in volume was due primarily to increased flowback volumes at one of our facilities in North Dakota. Average revenue per barrel was relatively consistent. Oil revenue represented approximately 5.7% of total revenue during the three months ended September 30, 2017 and 2016.

The increase in revenues was partially offset by interruptions associated with lightning strikes and fires at our facility in Orla, Texas in January 2017 and at our Grassy Butte facility in North Dakota in July 2017. We re-established temporary operations at the Orla facility soon after that incident, and the incidents did have an adverse effect on the revenues of these facilities.


Costs of services. Costs of services increased $0.1 million during the three months ended September 30, 2017 compared to the three months ended September 30, 2016, relatively consistent with the increase in revenues.

Gross margin. Gross margin remained relatively consistent during the three months ended September 30, 2017 compared to the three months ended September 30, 2016.

General and administrative. General and administrative expenses include general office overhead expenses such as salary costs, insurance, property taxes, royalty expenses, and other miscellaneous expenses. General and administrative expenses increased $0.4 million, primarily due to the omnibus administrative expense charge incurred and allocated to the segments in the third quarter of 2017 that was waived by Holdings in 2016 and recorded in general and administrative-corporate.

Depreciation, amortization and accretion. Depreciation, amortization and accretion expense during the three months ended September 30, 2017 was not significantly different from depreciation and amortization expense during the three months ended September 30, 2016.

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

Operating income (loss). Our W&ES segment generated an operating loss of $0.2 million during the three months ended September 30, 2017 compared to operating income of $0.3 million during the three months ended September 30, 2016. This decrease in operating income (loss) was primarily due to an increase in general and administrative costs of $0.4 million and losses on asset disposals, net of $0.2 million.


The following table summarizes the operating results of the W&ES segment for the nine months ended September 30, 2017 and 2016.

 Nine Months Ended September 30, 
 2017 % of Revenue 2016 % of Revenue Change % Change  Three Months Ended June 30, 
 (in thousands, except per barrel data)  2018 % of Revenue 2017 % of Revenue Change % Change 
              (in thousands, except per barrel data) 
Revenue $6,005      $6,630      $(625)  (9.4)% $3,027      $2,016      $1,011   50.1%
Costs of services  2,330       3,084       (754)  (24.4)%  959       605       354   58.5%
Gross margin  3,675   61.2%  3,546   53.5%  129   3.6%  2,068   68.3%  1,411   70.0%  657   46.6%
                                                
General and administrative  1,651   27.5%  1,501   22.6%  150   10.0%  792   26.2%  575   28.5%  217   37.7%
Depreciation, amortization and accretion  1,335   22.2%  1,349   20.3%  (14)  (1.0)%  389   12.9%  470   23.3%  (81)  (17.2)%
Impairments  688   11.5%  2,119   32.0%  (1,431)  (67.5)%
Losses on asset disposals, net  77   1.3%         77     
Operating loss $(76)  (1.3)% $(1,423)  (21.5)% $1,347   (94.7)%
Gain on asset disposals, net  (1,561)  (51.6)%  (131)  (6.5)%  (1,430)  1091.6%
Operating income $2,448   80.9% $497   24.7% $1,951   392.6%
                                                
Operating Data                                                
Total barrels of saltwater disposed  8,841       9,917       (1,076)  (10.9)%  3,577       2,966       611   20.6%
Average revenue per barrel disposed (a) $0.68      $0.67      $0.01   2.0% $0.85      $0.68      $0.17   25.0%
Revenue variance due to barrels disposed                 $(719)                     $415     
Revenue variance due to revenue per barrel                 $94                      $596     

 

(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. Revenues decreasedRevenue of the Water Services segment increased by $0.6$1.0 million during the ninethree months ended SeptemberJune 30, 20172018 compared to the ninethree months ended SeptemberJune 30, 2016,2017, due primarily due to a 10.9% decrease21% increase in the volume of saltwater disposed. The decreasedisposed and an increase in the average revenue per barrel disposed of 25%.

Volumes at our North Dakota facilities increased by 1.4 million barrels. Approximately 0.6 million barrels of this increase related to our Williams, North Dakota facility, due to an agreement with a customer that developed new producing wells in 2017 near our facility. During January 2018, we completed construction of a gathering system to this customer’s production fields. Increases in volumes was due primarily to reduced exploration and production activity inat certain of our other North Dakota facilities as a result of low commodity prices. Average revenue per barrel remained relatively consistent from 2016 to 2017. Oil revenue represented approximately 7.5% of total revenue during the nine months ended September 30, 2017 compared to 5.5% during the nine months ended September 30, 2016.

In addition, businessincreased customer activity was interruptedwere partially offset by a lightning strike and fire at our facilitydecrease in Orla, Texas in January 2017 andvolumes of 0.2 million barrels at our Grassy Butte facility, in North Dakotawhich was struck by lightning in July of 2017. The resulting fire destroyed the surface equipment of this facility. We re-established temporary operations at the Orlarebuilt and reopened this facility soon after that incident, but the incidents did have an adverse effect on the revenues of these facilities. Revenues at the Orla facility were $0.3 million lower and revenues at our Grassy Butte facility were $0.1 million lower during the nine months ended September 30, 2017 than during the nine months ended September 30, 2016.in June 2018.

 

Volumes at our Texas facilities decreased by 0.8 million barrels during the three months ended June 30, 2018 compared to the three months ended June 30, 2017. This was due to the sale in January 2018 of our Pecos facility and the sale in May 2018 of our Orla facility. All of our remaining facilities are located in North Dakota.

The average revenue per barrel increased during the three months ended June 30, 2018 compared to the three months ended June 30, 2017, due in part to increased revenues from our new gathering system. 

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Costs of services. Costs of services decreasedincreased by $0.8$0.4 million during the ninethree months ended SeptemberJune 30, 20172018 compared to the ninethree months ended SeptemberJune 30, 2016,2017. The increase was due primarilyin part to cost reduction measures that we implemented in mid-2016 in responsean expense accrual of $0.1 million related to adverse market conditions. These measures included the temporary suspensioncleanup and remediation of activitysaltwater spills at two of our facilities and investments in automation at other facilities.North Dakota.

 

Gross margin. Gross margin increased by $0.1$0.7 million betweenduring the ninethree months ended SeptemberJune 30, 20172018 compared to the ninethree months ended SeptemberJune 30, 2016. A decrease2017, due to a $1.0 million increase in revenues of $0.6 million wasrevenue, partially offset by a decrease$0.4 million increase in costscost of services of $0.8 million.services. 

 

General and administrative. General and administrative expenses include general office overhead expenses such as salary costs, insurance, property taxes, royalty expenses, and other miscellaneous expenses. These expenses increased by $0.2 million during the three months ended June 30, 2018 compared to the three months ended June 30, 2017, primarily as a result of a $0.3 million administrative fee charged by Holdings (Holdings waived this administrative fee during the three months ended June 30, 2017).

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

Gain on asset disposals, net. We recorded a gain of $1.6 million upon the May 2018 sale of our Orla, Texas facility. During the three months ended June 30, 2017, we recorded a gain of $0.3 million upon the receipt of insurance proceeds for a property damage claim related to a January 2017 lightning strike and fire at our Orla facility, which was partially offset by $0.2 million of non-reimbursable costs associated with the fire.

Operating income. Our Water Services segment generated operating income of $2.4 million during the three months ended June 30, 2018 compared to operating income of $0.5 million during the three months ended June 30, 2017. The increase in operating income was due in part to a $1.6 million gain from the sale of our Orla, Texas saltwater disposal facility in May of 2018 and an increase of $0.7 million in the segment’s gross margin, partially offset by an increase of $0.2 million in general and administrative expenses.

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

  Six Months Ended June 30, 
  2018  % of Revenue  2017  % of Revenue  Change  % Change 
  (in thousands, except per barrel data) 
Revenue $5,536      $3,894      $1,642   42.2%
Costs of services  2,019       1,493       526   35.2%
Gross margin  3,517   63.5%  2,401   61.7%  1,116   46.5%
                         
General and administrative  1,628   29.4%  793   20.4%  835   105.3%
Depreciation, amortization and accretion  792   14.3%  885   22.7%  (93)  (10.5)%
Impairments         688   17.7%  (688)  (100.0)%
Gain on asset disposals, net  (3,270)  (59.1)%  (131)  (3.4)%  (3,139)  2396.2 %
Operating income $4,367   78.9% $166   4.3% $4,201   2530.7%
                         
Operating Data                        
Total barrels of saltwater disposed  6,652       5,739       913   15.9%
Average revenue per barrel disposed (a) $0.83      $0.68      $0.15   23.0%
Revenue variance due to barrels disposed                 $619     
Revenue variance due to revenue per barrel                 $1,023     

(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.

39  

Revenue. Revenue of the Water Services segment increased by $1.6 million during the six months ended June 30, 2018 compared to the six months ended June 30, 2017, due primarily to a 16% increase in the volume of salt water disposed and an increase in the average revenue per barrel disposed of approximately 22%.

Volumes at our North Dakota facilities increased by 2.3 million barrels. Approximately 1.2 million barrels of this increase related to our Williams, North Dakota facility, due to an agreement with a customer that developed new producing wells in 2017 near our facility. During January 2018, we completed construction of a gathering system to this customer’s production fields. Increases in volumes at certain of our other North Dakota facilities as a result of increased customer activity were partially offset by a decrease in volumes of 0.3 million barrels at our Grassy Butte facility, which was struck by lightning in July of 2017. The resulting fire destroyed the surface equipment of this facility. We rebuilt and reopened this facility in June 2018.

Volumes at our Texas facilities decreased by 1.4 million barrels during the six months ended June 30, 2018 compared to the six months ended June 30, 2017. This was due to the sale in January 2018 of our Pecos facility and the sale in May 2018 of our Orla facility. All of our remaining facilities are located in North Dakota.

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

Costs of services. Costs of services increased by $0.5 million during the six months ended June 30, 2018 compared to the six months ended June 30, 2017. The increase was due in part to expenses of $0.2 million related to the cleanup and remediation of saltwater spills at certain of our facilities in North Dakota.

Gross margin. Gross margin increased $1.1 million during the six months ended June 30, 2018 compared to the six months ended June 30, 2017, due primarily to a $1.6 million increase in revenue, partially offset by a $0.5 million increase in cost of services. 

General and administrative.General and administrative expenses include general overhead expenses such as salary costs, insurance, property taxes, royalty expenses, and other miscellaneous expenses. These expenses increased by $0.8 million during the ninesix months ended SeptemberJune 30, 2018 compared to the six months ended June 30, 2017. Of this increase, $0.6 million related to an administrative fee charged by Holdings (Holdings waived this administrative fee during the six months ended June 30, 2017). In addition, general and administrative expense during the six months ended June 30, 2017 were reduced by $0.3 million related to theupon collection of an account receivable on which we had previously recorded a valuation allowance and increased by a $0.3 million omnibus administrative expense charge incurred and allocated to the segments in the third quarter of 2017 that was waived by Holdings in 2016 and recorded in general and administrative-corporate.allowance.


Depreciation, amortization and accretion. Depreciation, amortization and accretion expense during the ninesix months ended SeptemberJune 30, 20172018 was not significantly different from depreciation and amortization expense during the ninesix months ended SeptemberJune 30, 2016.2017.

 

40  

Impairments. In the first quarter of 2017, we recorded an impairment of $0.7 million to the property, plant and equipment at one of our SWDsaltwater disposal facilities. We have experienced low volumes at this facility due to competition in the area and to low levels of exploration and production activity near the facility. In the second quarter of 2016, we recorded an impairment of $2.1 million to the property, plant and equipment at one of our SWD facilities. 

 

LossesGain on asset disposals, net. During the threesix months ended SeptemberJune 30, 2018, we recorded a gain of $1.6 million on the sale of our Orla, Texas facility, a gain of $1.8 million on the sale of our Pecos, Texas facility, and a loss of $0.1 million on the abandonment of a capital expansion project.

During the six months ended June 30, 2017, we recorded a lossgain of $0.1$0.3 million upon the receipt of insurance proceeds for a property damage claim related to the lightning strikesstrike and firesfire at twoour Orla facility, which was partially offset by $0.2 million of our SWD facilities, which primarily represent non-reimbursable costs associated with these incidents.  This loss was net of a $0.3 million gain that we recorded upon receipt of proceeds from a property damage insurance claim related to the Orla, Texas facility.fire.

 

Operating loss.income. Our W&ESWater Services segment generated an operating lossincome of $0.1$4.4 million during the ninesix months ended SeptemberJune 30, 20172018 compared to an operating lossincome of $1.4$0.2 million during the ninesix months ended SeptemberJune 30, 2016.2017. The decreaseincrease in operating income was due in part to gains of $3.4 million from the sales of our saltwater disposal facilities in Texas, an increase of $1.1 million in the operating loss was primarily due to a decreasesegment’s gross margin, and impairments of $1.4$0.7 million recorded in impairments.2017, partially offset by an increase of $0.8 in general and administrative expenses.

 

Adjusted EBITDA

 

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

  

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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


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Reconciliation of Net Loss to Adjusted EBITDA and to Distributable Cash Flow

             
  Three Months ended September 30,  Nine Months ended September 30, 
  2017  2016  2017  2016 
     (in thousands)    
          
 Net income (loss) $562  $1,998  $(3,862) $(10,979)
 Add:                
Interest expense  1,907   1,641   5,411   4,878 
Depreciation, amortization and accretion  1,465   1,447   4,378   4,354 
Impairments        3,598   10,530 
Income tax expense  529   227   458   389 
Non-cash allocated expenses     931   1,750   2,866 
Equity based compensation  371   322   1,137   829 
Losses on asset disposals, net  208      77    
 Less:                
Foreign currency gains  557      824    
 Adjusted EBITDA $4,485  $6,566  $12,123  $12,867 
                 
 Adjusted EBITDA attributable to general partner  (1,000)  (500)  (1,000)  (2,500)
 Adjusted EBITDA attributable to non-controlling interests  163   294   (73)  (137)
 Adjusted EBITDA attributable to limited partners / controlling interests $5,322  $6,772  $13,196  $15,504 
                 
 Less:                
 Cash interest paid, cash taxes paid, maintenance capital expenditures  1,910   1,671   6,380   5,058 
 Distributable cash flow $3,412  $5,101  $6,816  $10,446 

 

Reconciliation of Net LossIncome (Loss) to Adjusted EBITDA to Distributable Cash Flow

  Three Months Ended June 30,  Six Months Ended June 30, 
  2018  2017  2018  2017 
  (in thousands) 
       
Net income (loss) $3,556  $497  $4,516  $(4,424)
Add:                
Interest expense  1,668   1,795   3,624   3,504 
Debt issuance cost write-off  114      114    
Depreciation, amortization and accretion  1,375   1,481   2,793   2,913 
Impairments           3,598 
Income tax expense (benefit)  287   222   368   (71)
Non-cash allocated expenses     829      1,750 
Equity-based compensation  335   409   547   766 
Foreign currency losses  117      451    
 Less:                
Foreign currency gains     267      267 
Gains on asset disposals, net  1,561   131   3,270   131 
 Adjusted EBITDA $5,891  $4,835  $9,143  $7,638 
                 
 Adjusted EBITDA attributable to noncontrolling interests  278   12   664   (236)
 Adjusted EBITDA attributable to limited partners / controlling interests $5,613  $4,823  $8,479  $7,874 
                 
 Less:                
 Cash interest paid, cash taxes paid, maintenance capital expenditures  2,492   2,723   4,428   4,470 
 Distributable cash flow $3,121  $2,100  $4,051  $3,404 

Reconciliation of Net Income (Loss) Attributable to Limited Partners to Adjusted

EBITDA Attributable to Limited Partners and Distributable Cash Flow 

  Three Months Ended June 30,  Six Months Ended June 30, 
  2018  2017  2018  2017 
  (in thousands) 
                 
 Net income (loss) attributable to limited partners $3,407  $1,459  $4,132  $(1,376)
 Add:                
 Interest expense attributable to limited partners  1,668   1,795   3,624   3,504 
 Debt issuance cost write-off attributable to limited partners  114      114    
 Depreciation, amortization and accretion attributable to limited partners  1,252   1,340   2,527   2,630 
 Impairments attributable to limited partners           2,823 
 Income tax expense attributable to limited partners  281   218   354   (75)
 Equity based compensation attributable to limited partners  335   409   547   766 
 Foreign currency losses attributable to limited partners  117      451    
 Less:                
 Foreign currency gains attributable to limited partners     267      267 
 Gains on asset disposals attributable to limited partners, net  1,561   131   3,270   131 
 Adjusted EBITDA attributable to limited partners  5,613   4,823   8,479   7,874 
 Less:                
Cash interest paid, cash taxed paid and maintenance capital expenditures attributable to limited partners  2,492   2,723   4,428   4,470 
 Distributable cash flow $3,121  $2,100  $4,051  $3,404 

42  

Reconciliation of Net Cash Provided by Operating Activities to Adjusted

EBITDA to Distributable Cash Flow

 

  Three Months ended September 30,  Nine Months ended September 30, 
  2017  2016  2017  2016 
     (in thousands)    
             
 Net income (loss) attributable to limited partners $1,554  $3,348  $178  $(715)
 Add:                
 Interest expense attributable to limited partners  1,907   1,578   5,411   4,690 
 Depreciation, amortization and accretion attributable to limited partners  1,322   1,306   3,952   3,921 
 Impairments attributable to limited partners        2,823   6,409 
 Income tax expense attributable to limited partners  517   218   442   370 
 Equity based compensation attributable to limited partners  371   322   1,137   829 
 Losses on asset disposals attributable to limited partners, net  208      77    
 Less:                
 Foreign currency gains attributable to limited partners  557      824    
 Adjusted EBITDA attributable to limited partners  5,322   6,772   13,196   15,504 
                 
 Less:                
 Cash interest paid, cash taxed paid and maintenance capital expenditures attributable to limited partners  1,910   1,671   6,380   5,058 
 Distributable cash flow $3,412  $5,101  $6,816  $10,446 

Reconciliation of Cash Flows Provided by Operating Activities to Adjusted EBITDA and to Distributable Cash Flow        

 Nine Months ended September 30,  Six Months ended June 30, 
 2017 2016  2018 2017 
 (in thousands)  (in thousands) 
             
Cash flows provided by operating activities $263 $17,659  $2,059  $1,712 
Changes in trade accounts receivable, net  11,583   (4,999)  6,059   4,727 
Changes in prepaid expenses and other  765   (1,053)  (1,358)  586 
Changes in accounts payable and accrued liabilities  (6,552)  (3,802)  (1,744)  (3,920)
Changes in income taxes payable  271   84 
Change in income taxes payable  300   802 
Interest expense (excluding non-cash interest)  4,968   4,452   3,377   3,210 
Income tax expense (excluding deferred tax benefit)  819   428   368   287 
Other  6   98   82   234 
Adjusted EBITDA $12,123  $12,867  $9,143  $7,638 
                
Adjusted EBITDA attributable to general partner  (1,000)  (2,500)
Adjusted EBITDA attributable to noncontrolling interests  (73)  (137)  664   (236)
Adjusted EBITDA attributable to limited partners / controlling interests $13,196  $15,504  $8,479  $7,874 
                
Less:                
Cash interest paid, cash taxes paid, maintenance capital expendirures  6,380   5,058 
Cash interest paid, cash taxes paid, maintenance capital expenditures  4,428   4,470 
Distributable cash flow $6,816  $10,446  $4,051  $3,404 

 

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 that may include pipeline inspection companies and SWDsaltwater disposal facilities or expanding our existing assets and offerings in our current operations. In addition, the working capital needs of the PISPipeline 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 PISPipeline Inspection segment are substantial”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, 2016)2017), which could require us to seek additional financing that we may not be able to obtain on satisfactory terms, or at all. Consequently, our ability to develop and maintain sources of funds to meet our capital requirements is critical to our ability to meet our growth objectives.

 

At SeptemberJune 30, 2017,2018, our sources of liquidity included:

 

 $19.210.5 million cash on the balance sheet at SeptemberJune 30, 2017;2018;

 

 available borrowings under our Credit Agreement of $63.1$13.9 million at SeptemberJune 30, 20172018 that are limited by certain borrowing base computations and financial covenant ratios as outlined in the agreement;Credit Agreement; and

 

 issuance of equity and/or debt securities. We filed a Securities Registration Statement with the Securities and Exchange Commission on June 8, 2015securities, subject to register $1.0 billion in securities, which we may issue in any combination of equity orour debt securities from time to time in one or more offerings.covenants.


43  

On October 27, 2017, our Board of Directors declared a distribution of $0.21 per common unit ($0.84 annualized), payable on November 14, 2017 to owners of record on November 7, 2017. If this distribution level is maintained through the fourth quarter of 2017, it will provide approximately $9.3 million of internally generated capital on an annualized basis to provide increased liquidity, reduce leverage, invest in selected growth projects in the future, and strengthen the Company’s balance sheet compared to the previous distribution level of $0.406413 per unit per quarter ($1.63 annualized). This action should provide a sound catalyst to reducing our currently elevated cost of capital by de-levering and improving increased distribution coverage to our unitholders. We are confident these actions support the long-term interests of our unitholders, employees, and other stakeholders. We continue to see encouraging signs with some new customers and are focused on organic growth, and improved SWD asset utilization in an effort to improve cash flow that will, in turn, contribute to the improvement of all of our financial ratios. We continue to believe the fundamental demand for increased inspection and water disposal remains strong over the long-term, but the recovery has been slower than previously anticipated.

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.

The following table summarizes the distributions declared since our IPO:

 

        Total Cash 
  Per Unit Cash  Total Cash  Distributions 
Payment Date Distributions  Distributions  to Affiliates (a) 
     (in thousands) 
          
May 15, 2014 (b) $0.301389  $3,565  $2,264 
August 14, 2014  0.396844   4,693   2,980 
November 14, 2014  0.406413   4,806   3,052 
Total 2014 Distributions  1.104646   13,064   8,296 
             
February 14, 2015  0.406413   4,806   3,052 
May 14, 2015  0.406413   4,808   3,053 
August 14, 2015  0.406413   4,809   3,087 
November 13, 2015  0.406413   4,809   3,092 
Total 2015 Distributions  1.625652   19,232   12,284 
             
February 12, 2016  0.406413   4,810   3,107 
May 13, 2016  0.406413   4,812   3,099 
August 12, 2016  0.406413   4,817   3,103 
November 14, 2016  0.406413   4,819   3,105 
Total 2016 Distributions  1.625652   19,258   12,414 
             
February 13, 2017  0.406413   4,823   3,107 
May 15, 2017  0.210000   2,495   1,606 
August 14, 2017  0.210000   2,495   1,607 
November 14, 2017 (c)  0.210000   2,497   1,608 
  1.036413   12,310   7,928 
            
Total Distributions (through November 14, 2017 since IPO) $5.392363  $63,864  $40,922 
        Total Cash 
  Per Unit Cash  Total Cash  Distributions 
Payment Date Distributions  Distributions  to Affiliates (a) 
     (in thousands) 
 Total 2014 Distributions $1.104646  $13,064  $8,296 
 Total 2015 Distributions  1.625652   19,232   12,284 
 Total 2016 Distributions  1.625652   19,258   12,414 
             
 February 13, 2017  0.406413   4,823   3,107 
 May 13, 2017  0.210000   2,495   1,606 
 August 12, 2017  0.210000   2,495   1,607 
 November 14, 2017  0.210000   2,497   1,608 
Total 2017 Distributions  1.036413   12,310   7,928 
             
 February 14, 2018  0.210000   2,498   1,599 
 May 15, 2018  0.210000   2,506   1,604 
August 14, 2018 (b) 0.210000   2,506   1,604 
  Total 2018 Distributions (through August 14, 2018)  0.630000   7,510   4,807 
Total Distributions (through August 14, 2018 since IPO) $6.022363  $71,374  $45,729 

 

(a)Approximately 64.4%64.0% of the Partnership’s outstanding common units at SeptemberJune 30, 20172018 were held by affiliates.
(b)Distribution was pro-rated from the date of our IPO through March 31, 2014.
(c)Third Second quarter 20172018 distribution was declared and will be paid in the fourththird quarter of 2017.2018. 

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


44  

Our Credit Agreement

 

We are party to aOn May 29, 2018, we entered into an amended and restated credit agreement (as amended and restated, the “Credit Agreement”) that provides up to $200.0$90.0 million in borrowing capacity, subject to certain limitations. The Credit Agreement includes a working capital revolving credit facility (“Working Capital Facility”), which provides up to $75.0 million in borrowing capacity to fund working capital needs,limitations, and an acquisition revolving credit facility (“Acquisition Facility”), which provides up to $125.0 million in borrowing capacity to fund acquisitions and expansion projects. In addition, the Credit Agreement provides forcontains an accordion feature that allows us to increase the availability under the facilities by an additional $125.0borrowing capacity to $110.0 million if the lenders agree to increase their commitments.commitments in the future or if other lenders join the facility. The Credit Agreement matures December 24, 2018, and we are currently in discussions with the leader of the lending syndicate of our Credit Agreement about refinancing the Credit Agreement.

Outstanding borrowings at September 30, 2017 and December 31, 2016May 29, 2021. The obligations under the Credit Agreement wereare secured by a first priority lien on substantially all of our assets. The credit agreement as follows: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”.

 

  September 30,
2017
  December 31,
2016
 
  (in thousands) 
       
Working Capital Facility $48,000  $48,000 
Acquisition Facility  88,900   88,900 
Total borrowings  136,900   136,900 
Debt issuance costs  (758)  (1,201)
Long-term debt $136,142  $135,699 

Outstanding borrowings at June 30, 2018 were $76.1 million and are reflected as long-term debt on the Unaudited Condensed Consolidated Balance Sheets beginning May 29, 2018. Debt issuance costs are reported as debt issuance costs, net on the Unaudited Condensed Consolidated Balance Sheets and total $1.5 million at June 30, 2018. Outstanding borrowings at December 31, 2017 were $136.9 million and are reflected net of debt issuance costs of $0.6 million as current portion of long-term debt on the Unaudited Condensed Consolidated Balance Sheet. The carrying value of ourthe partnership’s long-term debt approximates fair value as the borrowings under the Credit Agreement are considered to be priced at market for debt instruments having similar terms and conditions (Level 2 of the fair value hierarchy).

 

Borrowings underWe incurred certain debt issuance costs associated with the Working Capital FacilityPrevious Credit Agreement, which we were amortizing on a straight-line basis over the life of the Previous Credit Agreement. Upon amending the Credit Agreement in May 2018, we wrote off $0.1 million of these debt issuance costs and reported this expense within debt issuance cost write-off in our Unaudited Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2018, which represented the portion of the unamortized debt issuance costs attributable to lenders who are limited by a monthly borrowing base calculation as definedno longer participating in the credit facility subsequent to the amendment. The remaining debt issuance costs associated with the Previous Credit Agreement. If, at any time, outstanding borrowings underAgreement, along with $1.3 million of debt issuance costs associated with the Working Capital Facility exceed our calculated borrowing base, a principal payment in the amount of the excess is due upon submission of the borrowing base calculation. Available borrowings under the Acquisition Facility may be limited by certain financial covenant ratios as defined in the Credit Agreement. The obligations under ouramended and restated Credit Agreement, are secured bybeing amortized on a first priority lien on substantially allstraight-line basis over the three-year term of our assets.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 1.25%1.5% to 2.75%3.0% per annum (“Base Rate Borrowing”) or (ii) an adjusted LIBOR rate plus a margin of 2.25%2.5% to 3.75%4.0% per annum (“LIBOR Borrowings”). The applicable margin is determined based on the leverage ratio of the Partnership, as defined in the Credit Agreement. Generally, the interest rate on our Credit Agreement borrowings ranged between 4.74% and 5.95% for the six months ended June 30, 2018 and 3.90% and 4.99%4.97% for the ninesix months ended SeptemberJune 30, 2017 and 3.54% and 4.28% for the nine months ended September 30, 2016.2017. Interest on Base Rate Borrowings is payable monthly. Interest on LIBOR Borrowings is paid upon maturity of the underlying LIBOR contract, but no less often than quarterly. Commitment fees are charged at a rate of 0.50% on any unused credit and are payable quarterly. Interest paid during the three months ended SeptemberJune 30, 20172018 and 20162017 was $1.7 million, and $1.6 million, respectively, including commitment fees. Interest paid during the ninesix months ended SeptemberJune 30, 2018 and 2017 and 2016 was $5.0$3.5 million and $4.3$3.3 million, respectively, including commitment fees.

 

OurThe Credit Agreement contains various customary affirmative and negative covenants and restrictive provisions. OurThe Credit Agreement also requires maintenance of certain financial covenants, including a combined total adjusted leverage ratio (as defined in ourthe Credit Agreement) of not more than 4.0 to 1.0 and an interest coverage ratio (as defined in ourthe Credit Agreement) of not less than 3.0 to 1.0. At SeptemberJune 30, 2017,2018, our combined total adjusted leverage ratio was 3.773.58 to 1.0 and our interest coverage ratio was 3.084.99 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 ourthe Credit Agreement, the lenders may declare any outstanding principal, of our Credit Agreement debt, 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 ourthe Credit Agreement. We were in compliance with all debt covenants as of SeptemberJune 30, 2017. Working capital borrowings, which are fully secured by our net working capital, are subject2018 and expect to a monthly borrowing base and are excluded from ourbe in compliance with all debt compliance ratios.covenants for the twelve months following the submission of this Form 10-Q.

  

In addition, ourthe Credit Agreement restricts our ability to make distributions on, or redeem or repurchase, our equity interests.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 ourthe Credit Agreement, the borrowers and the guarantorswe are in compliance with the financial covenants in the borrowing base (which includes 100% of cash on hand) exceeds the amount of outstanding credit extensions under the Working Capital Facility byCredit Agreement, and we have at least $5.0 million and at least $5.0 million in lender commitments are available to be drawn under the Working Capital Facility.


Our Credit Agreement maturesof unused capacity on December 24, 2018 and, although unfavorable financial results may impact our ability to meet our current debt covenants, we believe it is probable that we will be able to maintain compliance with the financial ratio covenants through the maturity date of the Credit Agreement through some combinationat the time of 1) improved operating results, 2) refinancing the Credit Agreement, and/or 3) future sponsor support from Holdings.distribution.

 

We plan to improve our operating results through a combination of 1) enhanced business development efforts in our Pipeline Inspection Services and Integrity Services segments, including our continued focus on higher margin services, 2) the re-opening of our Orla, TX and our Grassy Butte, ND SWD facilities that were struck by lightning earlier this year; 3) enhancing our SWD activities due to additional drilling and completion activities in both the Permian and Bakken regions; and 4) capital expansion in our Water and Environmental Services segment (specifically, we are in the process of building a water gathering system at one of our North Dakota facilities).

45  

 

In anticipation of the Credit Agreement maturing in December 2018, we have an executed mandate and term sheet with the lead bank in the Credit Agreement regarding a refinancing of the Credit Agreement, subject to syndication. The new credit agreement will require a reduction in our current outstanding debt balance and will have modified financial ratio covenants. The term sheet provides for conditions precedent to reduce the principal balance, which may include some combination of 1) using cash currently on the balance sheet; 2) issuing some sort of equity to the owners of Holdings or third parties; 3) issuing convertible debt to the owners of Holdings or third parties; 4) monetizing a portion of our investment-grade accounts receivable with Holdings or a third-party; and/or 5) asset sales of some of our SWD facilities. Although it is our intent to refinance our Credit Agreement under the executed term sheet, we can offer no assurances that the refinancing of our Credit Agreement will be consummated under terms acceptable to us given the conditions precedent outlined in the term sheet.

Holdings has continued to support the Partnership during the oil and gas economic downturn and has provided sponsor support of $6.3 million during the year ended December 31, 2016 and $2.8 million during the nine months ended September 30, 2017. The owners of Holdings, who collectively own approximately 64% of our common units, remain incentivized and have the financial wherewithal to continue to support us in order to maintain compliance with the financial ratio covenants through the maturity date of 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 ninesix months ended SeptemberJune 30, 20172018 and 2016.2017.

 

 Nine Months Ended
September 30,
 
 2017 2016  Six Months Ended June 30, 
 (in thousands)  2018 2017 
     (in thousands) 
Net cash provided by operating activities $263 $17,659  $2,059  $1,712 
Net cash provided by (used in) investing activities  396   (929)
Net cash provided by investing activities  8,066   1,198 
Net cash used in financing activities  (8,945)  (16,454)  (23,832)  (7,407)
Effect of exchange rates on cash  831   477   (202)  271 
Net increase (decrease) in cash and cash equivalents $(7,455) $753 
Net decrease in cash and cash equivalents (including restricted cash equivalents) $(13,909) $(4,226)

 

Net cash provided by operating activities. Net operating cash provided by operating activitiesinflows for the ninesix months ended SeptemberJune 30, 2017 was $0.32018 were $2.1 million, consisting of a net lossincome of $3.9$4.5 million plus non-cash expenses of $10.2$0.8 million, less net changes in working capital of $6.0$3.3 million. The largest non-cash expense was depreciation, amortization, and accretion expense of $2.8 million, (including analthough non-cash expenses were partially offset by net gains on asset disposals of $3.3 million. The net change in working capital includes a net increase of $6.1 million in accounts receivable, of $11.5 million and an increasea decrease in prepaid expenses and other of $0.8$1.4 million, partially offset by anand a net increase of $1.4 million in current liabilitiesliabilities.

Net operating cash inflows for the six months ended June 30, 2017 were $1.7 million, consisting of $6.3a net loss of $4.4 million, plus non-cash expenses of $8.3 million (including impairments of $3.6 million). The, less a net increase in working capital during the nine months ended September 30, 2017 was due, in part, to revenue growth.of $2.2 million. Non-cash expenses included depreciation, amortization and accretion, and impairment expense, among others. Non-cash expenses also included expenses attributable to the Partnershipus that were paid by Holdings and recorded as an equity contribution in the Partnership’sour financial statements.

Net operating cash provided by operations for the nine months ended September 30, 2016 of $17.7 million included $11.0 million of net loss, $18.9 million of non-cash expenses (including impairments of $10.5 million) and $9.8 million of net changes in working capital. 

 

Net cash provided by (used in) investing activities. Cash provided by (used in)During the six months ended June 30, 2018, cash inflows from investing activities forincluded proceeds of $12.0 million related to the ninesales of our Orla and Pecos saltwater disposal facilities. Cash outflows from investing activities included $3.9 million of capital expenditures, which related primarily to the construction of a gathering system at one of our facilities in North Dakota, the rebuild of the Orla, Texas facility prior to its sale, and the rebuild of the Grassy Butte, North Dakota facility (the surface equipment at both the Orla and Grassy Butte facilities were destroyed by fires in 2017 resulting from lightning strikes).

During the six months ended SeptemberJune 30, 2017, cash inflows from investing activities consisted primarily consists of $1.6 million of insurance proceeds associated with property damage and clean-up activities that resulted from athe lightning strike and fire at our SWD facilityOrla, Texas facility.  Cash used in Orla, TX, offset byinvesting activities related to capital expenditures. Capital expenditures, during the nine months ended September 30, 2017which consisted primarily of equipment purchases, muchmany of which waswere to support increasing revenues in our Pipeline Inspection Services segment’s non-destructive examination business and improvements to one of our SWD facilities in anticipation of building a gathering system from production sites to the facility.  Capital expenditures during the nine months ended September 30, 2016 were made primarily in our Pipeline Inspection Services segment’s non-destructive examination business.

 

Net cash used in financing activities. Financing cash outflows forDuring the ninesix months ended SeptemberJune 30, 20172018, 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 consistedincluded $60.8 million of $9.8payments 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, and $5.0 million of distributions to limited partners, offset by a contribution attributable to our general partner of $1.0 million. Financingcommon unitholders.

During the six months ended June 30, 2017, financing cash outflows for the nine months ended September 30, 2016 included $14.4consisted primarily of $7.3 million of distributions to limited partners, $0.4 million of distributions to noncontrolling interest owners, and a $4.0 million payment on our Working Capital Facility, partially offset by contributions attributable to our general partner totaling $2.5 million.common unitholders.

 

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Working Capital

 

Our working capital was $52.1$40.4 million at SeptemberJune 30, 2017. Working capital increased from December 31, 2016 to September 30, 2017 due primarily to increased accounts receivable, partially offset by increased accrued liabilities2018. Our Pipeline Inspection and a decreased cash balance. Business activity in our PIS and IS segments is typically higher during the second and third quarters of a year, and during this time working capital typically increases. Our PIS and ISIntegrity Services segments have substantial working capital needs, as we generally pay our inspectors and field personnel on a weekly basis, but typically receive payment from our customers 45 to 90 days after the services have been performed. We utilize borrowings under our Credit Agreement to fund the working capital needs of these segments. These borrowings reduce the amount of credit available for other uses, such as acquisitions and growth projects, and increasesincreased interest expense, thereby reducing cash flow. Please read “Risk Factors — Risks Related to Our Business — The working capital needs of the PISPipeline Inspection segment are substantial which could require usand will continue to seek additional financing that webe 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 not be ablelimit our flexibility to obtain on satisfactory terms, or at all”financing and to pursue other business opportunities” in our Annual Report on Form 10-K for the year ended December 31, 2016.2017.

 

Capital Expenditures

  

W&ESWater Services has capital needs requiring investment for the maintenance of existing SWDsaltwater disposal facilities and the acquisition or construction and development of new SWDsaltwater disposal facilities. Our PISPipeline Inspection segment does not generally require significant capital expenditures, other than in the nondestructive examination service line, which has been acquiring field equipment to support its growing revenues. ISIntegrity Services has capital needs for heavy equipment in order to perform hydrostatic testing 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 tankage, workovers, pipelines, pumps, and other improvement of existing capital assets, including the construction or development of new capital assets to replace our existing saltwater disposal systems as they become obsolete.  Other examples of maintenance capital expenditures are expenditures to repair, refurbish, and replace tubing and packers on the SWDsaltwater disposal well itself to maintain equipment reliability, integrity, and safety, as well as to address environmental laws and regulations.  Maintenance capital expenditures were $0.2$0.1 million and less than $0.1 million for the three months ended SeptemberJune 30, 20172018 and 2016,2017, respectively, and $0.3 million and $0.2$0.1 million for the ninesix months ended SeptemberJune 30, 20172018 and 2016,2017, respectively.

 

 Expansion capital expenditures are those capital expenditures that we expect will increase our operating capacity or operating income over the long-term.  Expansion capital expenditures include the acquisition of assets or businesses and the construction or development of additional saltwater disposal capacity, to the extent such expenditures are expected to expand our long-term operating capacity or operating income.  Expansion capital expenditures were $0.5$1.7 million and $0.8$3.6 million for the three and ninesix months ended SeptemberJune 30, 2017,2018, respectively and $0.1 million and $0.5$0.3 million for the three and ninesix months ended SeptemberJune 30, 2016,2017, 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

 

We have $136.9$76.1 million of borrowings under our Credit Agreement as of SeptemberJune 30, 2017.2018. Additionally, we have long-term office and other lease obligations totaling approximately $4.7$4.2 million (including extensions),as of June 30, 2018, payable through calendar year 2042.2026. The office lease for our headquarters represents approximately $4.0 million of our total operating lease obligation. We can exit this lease after 18 months after the inception date (the original lease term is 84 months) with the payment of a penalty.

 

Off-Balance Sheet Arrangements

 

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

 

Critical Accounting Policies

 

OurThere have been no material changes in our critical accounting policies are consistent with those disclosedand procedures during the three months ended June 30, 2018. For more information, please read our disclosure of critical accounting policies in Note 2 included inItem 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations of our audited financial statements as of andAnnual Report on Form 10-K for the year ended December 31, 2016 included in our Form 10-K and also as outlined in Note 2 of our Unaudited Condensed Financial Statements as of for2017, filed with the three and nine months ended September 30, 2017 included in our Form 10-Q.SEC on March 23, 2018. 

 

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Recent Accounting Standards

 

In 2017, the Partnership2018, we adopted the following new accounting standards issued by the Financial Accounting Standards Board (“FASB”);

 

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

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

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

The FASB issued ASU 2016-02 – Leases in February 2016. This guidance attempts to increase transparency and comparability among organizations by recognizing certain lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between previous GAAP and this new guidance is the recognition on the balance sheet of certain lease assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP. The amendments in this ASU are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted. We are currently examining the guidance provided in the ASU and determining the impact this guidance will have on our Unaudited Condensed Consolidated Financial Statements.

The FASB issued ASU 2014-09 – Revenue from Contracts with Customers in May 2014. ASU 2014-09 is intended to clarify the principles for recognizing revenue and to develop a common standard for recognizing revenue for GAAP and International Financial Reporting Standards that is applicable to all organizations. This guidance requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to receive in exchange for those goods and services. It also requires additional disclosure about the nature, amount, timing, and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to obtain or fulfill a contract. We will beadopted this new standard on January 1, 2018 utilizing the modified retrospective transition approach. The adoption of this ASU had no effect on our Unaudited Condensed Consolidated Financial Statements other than additional disclosures included in the Form 10-Q.

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

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

The FASB issued ASU 2016-02 – Leases in February 2016 and has issued subsequent guidance related to the implementation of this ASU. This guidance attempts to increase transparency and comparability among organizations by recognizing certain lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between previous GAAP methodology and the method proposed by this new guidance is the recognition on the balance sheet of certain lease assets and lease liabilities by lessees for those leases that were classified as operating leases under previous GAAP. Entities are required to adopt this standard in 2018ASU using a modified retrospective approach, subject to certain optional practical expedients, and to apply its provisions either retrospectively to each prior reportingleasing arrangement existing at or entered into after the earliest comparative period presented or prospectively with the cumulative effect of initially applying the ASU recognized at the date of initial application (modified retrospective method). Although we continue to evaluatein the financial impact ofstatements. The amendments in this ASU onare effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. We are currently evaluating the Partnership, we currently plan to adopt this standard utilizing the modified retrospective method and do not anticipate that the adoption ofimpact this ASU will materially impacthave on our financial position, results of operations or cash flows.Unaudited Condensed Consolidated Balance Sheets.

 

Item 3.Item 3.Quantitative and Qualitative Disclosures about Market Risk

 

There have been no material changes to the Partnership’s exposure to market risk since December 31, 2016.2017.

 

We continue to have exposure to changes in interest rates on our indebtedness associated with our Credit Agreement.  We may implement swap or cap structures to mitigate our exposure to interest rate risk; however, we do not currently have any swaps or cap structures in place.  Accordingly, as of June 30, 2018, our exposure consists of floating interest rate changes on the outstanding borrowings under our Credit Agreement of $76.1 million.  A hypothetical change in interest rates of 1.0% would result in an increase or decrease of our annual interest expense of approximately $0.8 million.

The credit markets have recently experienced historical lows in interest rates.  As the overall economy strengthens, it is possible that monetary policy will continue to tighten further, resulting in higher interest rates to counter possible inflation as has been evidenced by recent interest rate hikes by the Federal Reserve. Interest rates on floating rate credit facilities and future debt offerings could be higher than current levels, causing our financing costs to increase accordingly.

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Item 4.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 FinancialAccounting Officer, as well asand 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 Securities and Exchange Commission’sSEC’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 FinancialAccounting Officer as appropriate, to allow timely decisions regarding required disclosure.

 

Based upon that evaluation, our management, including our Chief Executive Officer and Chief FinancialAccounting 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.

 

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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 SeptemberJune 30, 20172018 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

PART II - OTHER INFORMATION  

Item 1.Legal Proceedings

 

Stuart v. TIRItem 1.      Legal Proceedings

In July 2014, a group of former minority shareholders of Tulsa Inspection Resources, Inc. (“TIR Inc.”), formerly an Oklahoma corporation, filed a civil action in the United States District Court for the Northern District of Oklahoma (the “District Court”) against TIR LLC, members of TIR LLC, and certain affiliates of TIR LLC’s members.  TIR LLC is the successor in interest to TIR Inc., resulting from a merger between the entities.  The former shareholders in TIR Inc. claim that they did not receive sufficient value for their shares and are seeking compensatory and punitive damages.  All claims against TIR LLC have been resolved by the District Court in TIR LLC’s favor, subject to appeal to the United States Court of Appeals for the Tenth Circuit, and plaintiffs have abandoned their claim for rescission of the merger.  The remaining claims, none of which are asserted against the Partnership nor any subsidiary of the Partnership including TIR LLC, were adjudicated at jury trial that began on September 5, 2017. On September 14, 2017, the jury returned a unanimous verdict in favor of the defendants, finding that the value paid to the plaintiffs was fair and awarding them no damages.

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 alleges he was a non-exempt employee of TIR LLC and that he and other potential class members were not paid overtime in compliance with the FLSA. The plaintiff seeks to proceed as a collective action and to receive unpaid overtime and other monetary damages, including attorney’s fees. TIR LLC, CEM TIR and Cypress Energy Partners – Texas, LLC deny the claims.

 

Other

 

From time to time, we are subject to legal proceedings and claims that arise in the ordinary course of business. Like other organizations, our operations are subject to extensive and rapidly changing federal and state environmental, health and safety and other laws and regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities.

 

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

 

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Item 1A.Item 1A.Risk Factors

 

There have been no material changes with respect to the risk factors disclosed in our Annual Report on Form 10-K for the year ended December 31, 2016.2017.

 

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

 

None.None

 

Item 3.Defaults upon Senior Securities

 

None.

 

Item 4.Mine Safety Disclosures

 

Not applicable.

 

Item 5.Other Information

 

On November 8, 2017 the Board of Directors of the General Partner reappointed Jeffrey Herbers as the Chief Accounting Officer of the General Partner and increased his duties such that he will act as the principal accounting officer and interim principal financial officer of the General Partner, effective as of November 26, 2017.

Mr. Herbers, age 40, has served the General Partner as the Chief Accounting Officer since September 2016.  Prior to his employment with the General Partner, Mr. Herbers served as sole member of Jeff Herbers PLLC from December 2015 until September 2016 and, prior to that role, served as the Chief Accounting Officer of the general partner of NGL Energy Partners LP from February 2012 until November 2015.  Mr. Herbers holds a B.B.A. in accounting from the University of Tulsa.

There are no family relationships between Mr. Herbers and and director or other executive officer of the General Partner, and he was not selected by the General Partner's board of directors to serve in any capacity pursuant to any arrangement or understanding with any person.  Mr. Herbers has no direct or indirect material interest in any transaction required to be disclosed pursuant to Item 404(a) of Regulation S-K.None.

 

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Item 6.Item 6.Exhibits

 

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

 

Exhibit

Number

 Description
   
3.1 First Amendment to First Amended and Restated Agreement of Limited Partnership of Cypress Energy Partners, L.P. dated as of January 21, 2014May 29, 2018 (incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed on January 27, 2014)May 31, 2018)
   
3.2 Amended and Restated Limited Liability Company Agreement of Cypress Energy Partners GP, LLC dated as of January 21, 2014 (incorporated by reference to Exhibit 3.2 of our Current Report on Form 8-K filed on January 27, 2014)
   
31.1*

10.1

 Series A Preferred Unit Purchase Agreement Between Cypress Energy Partners, L.P. and Stephenson Equity, Co. No. 3, dated as of May 29, 2018 (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed on May 31, 2018)
10.2Series A Preferred Unit Purchase Agreement Between Cypress Energy Partners, L.P. and Stephenson Equity, Co. No. 3, dated as of May 29, 2018 (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed on May 31, 2018) Amended and Restated Credit Agreement, dated as of May 29, 2018, by and amoung Cypress Energy Partners, L.P., certain of its affiliates as co-borrowers and guarantors, Deutsche Bank AG, New York Branch, as lender, issuing bank, swing line lender and collateral agent, the other lenders from time to time party thereto, and Deutsche Bank Trust Company Americas, as the administrative agent (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed on May 31, 2018)
31.1*Chief Executive Officer Certification Pursuant to Exchange Act Rule 13a-14(a) or Rule 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
   
31.2* ChiefPrincipal 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** ChiefPrincipal Financial Officer Certification Pursuant to Exchange Act Rule 13a-14(b) or Rule 15d-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code, as Adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
   
101 INS* XBRL Instance Document
   
101 SCH* XBRL Schema Document
   
101 CAL* XBRL Calculation Linkbase Document
   
101 DEF* XBRL Definition Linkbase Document
   
101 LAB* XBRL Label Linkbase Document
   
101 PRE* XBRL Presentation Linkbase Document

 

*Filed herewith.
**Furnished herewith.

      

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SIGNATURES

 

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Tulsa, State of Oklahoma, on NovemberAugust 14, 2017.2018.

 

Cypress Energy Partners, L.P. 
   
By:Cypress Energy Partners GP, LLC, its general partner 
   
/s/ Peter C. Boylan III 
By:Peter C. Boylan III 
Title:Chief Executive Officer 
   
/s/  G. Les Austin /s/ Jeffrey A. Herbers 
By:G. Les AustinJeffrey A. Herbers 
Title:Chief Accounting Officer
(Principal Accounting Officer and Interim Principal Financial OfficerOfficer) 

 

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