Document


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 FORM 10-Q
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2018
or
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from        to        
Commission File Number: 001-35257
 
 AMERICAN MIDSTREAM PARTNERS, LP
(Exact name of registrant as specified in its charter)
amidlogo2017largea04.jpg
Delaware
27-0855785
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
 
 
2103 CityWest Boulevard
 
Building #4, Suite 800
 
Houston, TX 77042
(346) 241-3400
(Address of principal executive offices) (zip code)
(Registrant’s telephone number, including area code)
 


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.  ý Yes    ¨  No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  ý  Yes    ¨  No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
¨
Accelerated filer
ý
Non-accelerated filer
¨ 
Smaller reporting company
¨
 
 
Emerging growth company
¨
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  ¨  Yes    ý  No
There were 53,005,627 common units, 11,009,729 Series A Units and 9,241,642 Series C Units of American Midstream Partners, LP outstanding as of November 6, 2018. Our common units trade on the New York Stock Exchange under the ticker symbol “AMID.”





Glossary of Terms

The following is a list of terms used throughout this report:

Bbl         Barrels: 42 U.S. gallons measured at 60 degrees Fahrenheit.

Bbl/d        Barrels per day.

Btu
British thermal unit; a measurement of energy.

Condensate
Liquid hydrocarbons present in casing head gas that condense within the gathering system and are removed prior to delivery to the natural gas plant. This product is generally sold on terms more closely tied to crude oil pricing.

FERC         Federal Energy Regulatory Commission.

Fractionation    Process by which natural gas liquids are separated into individual components.

GAAP        Accounting principles generally accepted in the United States of America.

Gal         Gallons.

Mgal/d        Thousand gallons per day.

MBbl         Thousand barrels.

MBoe        Thousand barrels of oil equivalents.

MMBbl         Million barrels.

MMBbl/d    Million barrels per day.

MMBtu         Million British thermal units.

Mcf         Thousand cubic feet.

MMcf         Million cubic feet.
    
MMcf/d        Million cubic feet per day.

NGL or NGLs
Natural gas liquid(s): The combination of ethane, propane, normal butane, isobutane and natural gasoline that, when removed from natural gas, becomes liquid under various levels of higher pressure and lower temperature.

Throughput
The volume of natural gas and NGL transported or passing through a pipeline, plant, terminal or other facility during a particular period.

    


Table of Contents

TABLE OF CONTENTS
 
 
 
Page
Item 1.
 
 
 
 
 
 
Item 2.
Item 3.
Item 4.
Item 1.
Item 1A.
Item 6.

3
Table of Contents

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
American Midstream Partners, LP and Subsidiaries
Condensed Consolidated Balance Sheets
(Unaudited, In thousands)
 
September 30, 2018
 
December 31, 2017
Assets
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
22,758

 
$
8,782

Restricted cash
25,744

 
20,352

Accounts receivable, net of allowance for doubtful accounts of $706 and $225 as of September 30, 2018 and December 31, 2017, respectively
84,819

 
98,132

Inventory
3,080

 
2,966

Other current assets
25,971

 
23,420

Assets held for sale
126,690

 
—

Total current assets
289,062

 
153,652

Property, plant and equipment, net
993,920

 
1,095,585

Goodwill
51,723

 
128,866

Restricted cash-long term
5,068

 
5,045

Intangible assets, net
136,537

 
174,010

Investments in unconsolidated affiliates
336,789

 
348,434

Other assets, net
21,506

 
17,874

Total assets
$
1,834,605

 
$
1,923,466

Liabilities, Equity and Partners’ Capital
 
 
 
Current liabilities
 
 
 
Accounts payable
$
48,336

 
$
41,102

Accrued gas purchases
14,376

 
19,986

Accrued expenses and other current liabilities
116,141

 
68,854

Current portion of long-term debt
603,502

 
7,551

Liabilities held for sale
1,922

 
—

Total current liabilities
784,277

 
137,493

Asset retirement obligations
68,090

 
66,194

Other long-term liabilities
15,770

 
2,080

Long-term debt
501,219

 
1,201,456

Deferred tax liability
1,351

 
8,123

Total liabilities
1,370,707

 
1,415,346

 


 


Commitments and contingencies (Note 18)


 


 
 
 
 
Convertible preferred units
317,180

 
317,180

Equity and partners’ capital
 
 
 
General Partner interests (981 and 965 units issued and outstanding as of September 30, 2018 and December 31, 2017, respectively)
(66,254
)
 
(96,552
)
Limited Partner interests (52,990 and 52,711 units issued and outstanding as of September 30, 2018 and December 31, 2017, respectively)
199,173

 
273,703

Accumulated other comprehensive income
19

 
28

Total partners’ capital
132,938

 
177,179

Noncontrolling interests
13,780

 
13,761

Total equity and partners’ capital
146,718

 
190,940

Total liabilities, equity and partners’ capital
$
1,834,605


$
1,923,466


The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

4
Table of Contents

American Midstream Partners, LP and Subsidiaries
Condensed Consolidated Statements of Operations
(Unaudited, in thousands, except per unit amounts)
 
 
Three months ended September 30,
 
Nine months ended September 30,
 
 
2018
 
2017
 
2018
 
2017
Revenue:
 
 
 
 
 
 
 
 
Commodity sales
 
$
156,817

 
$
124,052

 
$
479,923

 
$
372,049

Services
 
45,763

 
38,835

 
148,997

 
116,382

     Loss on commodity derivatives, net
 
(234
)
 
(597
)
 
(530
)
 
(33
)
Total revenue
 
202,346

 
162,290

 
628,390

 
488,398

Operating expenses:
 
 
 
 
 
 
 
 
Costs of sales
 
150,274

 
112,398

 
461,948

 
342,886

Direct operating expenses
 
20,407

 
20,705

 
65,595

 
56,819

Corporate expenses
 
23,857

 
27,083

 
69,922

 
84,570

Termination fee
 
17,000

 
—

 
17,000

 
—

Depreciation, amortization and accretion
 
23,040

 
26,781

 
66,274

 
78,834

Gain on sale of assets, net
 
(99,396
)
 
(4,061
)
 
(99,491
)
 
(4,064
)
Total operating expenses
 
135,182

 
182,906

 
581,248

 
559,045

Operating income (loss)
 
67,164

 
(20,616
)
 
47,142

 
(70,647
)
Other income (expense), net
 
 
 
 
 
 
 
 
     Interest expense, net of capitalized interest
 
(22,267
)
 
(17,759
)
 
(55,834
)
 
(51,037
)
Other income (expense), net
 
(128
)
 
34,085

 
62

 
32,248

Earnings in unconsolidated affiliates
 
24,622

 
16,827

 
47,742

 
49,781

Income (loss) from continuing operations before income taxes
 
69,391

 
12,537

 
39,112

 
(39,655
)
Income tax expense
 
(31,208
)
 
(731
)
 
(32,045
)
 
(2,611
)
Income (loss) from continuing operations
 
38,183

 
11,806

 
7,067

 
(42,266
)
Income from discontinued operations, including gain on sale
 
—

 
44,696

 
—

 
42,185

Net income (loss)
 
38,183

 
56,502

 
7,067

 
(81
)
Net income attributable to noncontrolling interests
 
(25
)
 
(621
)
 
(83
)
 
(3,386
)
Net income (loss) attributable to the Partnership
 
$
38,158

 
$
55,881

 
$
6,984

 
$
(3,467
)
 
 
 
 
 
 
 
 
 
General Partner’s interest in net income (loss)
 
$
504

 
$
697

 
$
92

 
$
(98
)
Limited Partners’ interest in net income (loss)
 
$
37,654

 
$
55,184

 
$
6,892

 
$
(3,369
)
 
 
 
 
 
 
 
 
 
Distribution declared per common unit (Note 15)
 
$
0.1031

 
$
0.4125

 
$
0.6187

 
$
1.2375

 
 
 
 
 
 
 
 
 
Limited Partners’ net income (loss) per common unit:
 
 
Basic:
 
 
 
 
 
 
 
 
Income (loss) from continuing operations
 
$
0.56

 
$
0.05

 
$
(0.34
)
 
$
(1.35
)
Income from discontinued operations
 
—

 
0.86

 
—

 
0.81

Net income (loss) per common unit
 
$
0.56

 
$
0.91

 
$
(0.34
)
 
$
(0.54
)
 
 
 
 
 
 
 
 
 
Diluted:
 
 
 
 
 
 
 
 
Income (loss) from continuing operations
 
$
0.39

 
$
0.05

 
$
(0.34
)
 
$
(1.35
)
Income from discontinued operations
 
—

 
0.86

 
—

 
0.81

Net income (loss) per common unit
 
$
0.39

 
$
0.91

 
$
(0.34
)
 
$
(0.54
)
 
 
 
 
 
 
 
 
 
Weighted average number of common units outstanding:
Basic
 
52,984

 
52,021

 
52,917

 
52,021

Diluted
 
75,525

 
52,021

 
52,917

 
52,021

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

5
Table of Contents

American Midstream Partners, LP and Subsidiaries
Condensed Consolidated Statements of Comprehensive Income (Loss)
(Unaudited, in thousands)
 






 
Three months ended September 30,
 
Nine months ended September 30,
 
 
2018
 
2017
 
2018
 
2017
Net income (loss)
 
$
38,183

 
$
56,502

 
$
7,067

 
$
(81
)
Unrealized (loss) gain related to postretirement benefit plan
 
(4
)
 
—

 
(9
)
 
42

Comprehensive income (loss)
 
38,179

 
56,502

 
7,058

 
(39
)
Comprehensive income attributable to noncontrolling interests
 
(25
)
 
(621
)
 
(83
)
 
(3,386
)
Comprehensive income (loss) attributable to the Partnership
 
$
38,154

 
$
55,881

 
$
6,975

 
$
(3,425
)

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.



6
Table of Contents

American Midstream Partners, LP and Subsidiaries
Condensed Consolidated Statements of Changes in Equity and Partners’ Capital
(Unaudited, in thousands)
 


 
General
Partner
Interests
 
Limited
Partner
Interests
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Total Partners’ Capital
 
Non-
controlling Interests
 
Total Equity and Partners’ Capital
Balances at December 31, 2016
$
(47,645
)
 
$
616,087

 
$
(40
)
 
$
568,402

 
$
16,755

 
$
585,157

Net (loss) income
(98
)
 
(3,369
)
 
—

 
(3,467
)
 
3,386

 
(81
)
Contributions
38,270

 
4,000

 
—

 
42,270

 
—

 
42,270

Distributions
(976
)
 
(93,144
)
 
—

 
(94,120
)
 
—

 
(94,120
)
Contributions from NCI owners
—

 
—

 
—

 
—

 
296

 
296

Distributions to NCI owners
—

 
—

 
—

 
—

 
(1,777
)
 
(1,777
)
Distribution for acquisition of Delta House
(75,572
)
 
—

 
—

 
(75,572
)
 
—

 
(75,572
)
Issuance of common units for Panther acquisition
—

 
12,532

 
—

 
12,532

 
—

 
12,532

Acquisition of noncontrolling interest
—

 
(23,653
)
 
—

 
(23,653
)
 
(4,645
)
 
(28,298
)
LTIP vesting
(4,633
)
 
4,633

 
—

 
—

 
—

 
—

Tax netting repurchase
—

 
(1,642
)
 
—

 
(1,642
)
 
—

 
(1,642
)
Equity compensation expense
4,430

 
1,637

 
—

 
6,067

 
—

 
6,067

Post-retirement benefit plan
—

 
—

 
42

 
42

 
—

 
42

Balances at September 30, 2017
$
(86,224
)
 
$
517,081

 
$
2

 
$
430,859

 
$
14,015

 
$
444,874

 
 
 
 
 
 
 
 
 
 
 
 
Balances at December 31, 2017
$
(96,552
)
 
$
273,703

 
$
28

 
$
177,179

 
$
13,761

 
$
190,940

Cumulative effect of accounting change (Note 3)
(139
)
 
(10,552
)
 
—

 
(10,691
)
 
—

 
(10,691
)
Balances at January 1, 2018
(96,691
)
 
263,151

 
28

 
166,488

 
13,761

 
180,249

Net income
92

 
6,892

 
—

 
6,984

 
83

 
7,067

Contributions
31,786

 
—

 
—

 
31,786

 
—

 
31,786

Distributions
(978
)
 
(73,794
)
 
—

 
(74,772
)
 
—

 
(74,772
)
Contributions from NCI owners
—

 
—

 
—

 
—

 
11

 
11

Distributions to NCI owners
—

 
—

 
—

 
—

 
(75
)
 
(75
)
Distribution for acquisition of Trans-Union
(38
)
 
—

 
—

 
(38
)
 
—

 
(38
)
LTIP vesting
(3,954
)
 
3,954

 
—

 
—

 
—

 
—

Tax netting repurchase
—

 
(1,030
)
 
—

 
(1,030
)
 
—

 
(1,030
)
Equity compensation expense
3,529

 
—

 
—

 
3,529

 
—

 
3,529

Post-retirement benefit plan

—

 
—

 
(9
)
 
(9
)
 
—

 
(9
)
Balances at September 30, 2018
$
(66,254
)
 
$
199,173

 
$
19

 
$
132,938

 
$
13,780

 
$
146,718


The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.



7
Table of Contents

American Midstream Partners, LP and Subsidiaries
Condensed Consolidated Statements of Cash Flows
(Unaudited, in thousands)

 
Nine months ended September 30,

 
2018
 
2017
Cash flows from operating activities
 

 

Net income (loss)
 
$
7,067

 
$
(81
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities including discontinued operations:
 

 

Depreciation, amortization and accretion, including discontinued operations
 
66,274

 
88,700

Amortization of debt issuance costs
 
5,142

 
3,610

Amortization of weather derivative premium
 
797

 
753

Unrealized (gain) loss on derivatives contracts, net
 
(5,771
)
 
2,818

Non-cash compensation expense
 
3,529

 
6,067

Gain on MPOG acquisition
 
—

 
(32,383
)
Gain on sale of assets, net of transaction costs, including discontinued operations
 
(99,491
)
 
(50,580
)
Transaction costs associated with disposals of assets and business
 
(5,842
)
 
(2,545
)
Corporate overhead support
 
—

 
4,000

Other non-cash items
 
263

 
1,805

   Earnings in unconsolidated affiliates
 
(47,742
)
 
(49,781
)
Distributions from unconsolidated affiliates
 
41,775

 
40,415

Bad debt expense
 
739

 
37

Deferred tax (benefit) expense
 
(6,772
)
 
1,490

Changes in operating assets and liabilities, net of effects of acquisitions:
 
 
 

Accounts receivable
 
7,878

 
(3,476
)
Inventory
 
(1,222
)
 
(4,011
)
Risk management assets and liabilities
 
(989
)
 
(974
)
Other current assets
 
5,509

 
10,624

Other assets, net
 
(4,300
)
 
(1,994
)
Accounts payable
 
8,289

 
(17,419
)
Accrued gas and crude oil purchases
 
(5,502
)
 
8,805

Accrued expenses and other current liabilities
 
45,448

 
9,302

Asset retirement obligations
 
(2,985
)
 
(603
)
Other liabilities
 
850

 
426

Net cash provided by operating activities
 
12,944


15,005

 
 
 
 
 
Cash flows from investing activities
 
 
 

Acquisitions, net of cash acquired and settlements
 
—

 
(71,383
)
Contributions to unconsolidated affiliates
 
(5,867
)
 
(49,828
)
Additions to property, plant and equipment and other
 
(73,342
)
 
(66,039
)
Proceeds from disposals of assets and business
 
208,572

 
170,524

Insurance proceeds from involuntary conversion of property, plant and equipment
 
—

 
150

Distributions from unconsolidated affiliates, return of capital
 
22,485

 
18,562

Net cash provided by investing activities
 
151,848

 
1,986


8
American Midstream Partners, LP and Subsidiaries
Condensed Consolidated Statements of Cash Flows (Continued)
(Unaudited, in thousands)



 
Nine months ended September 30,

 
2018
 
2017
Cash flows from financing activities
 
 
 

Unitholder distributions for common control transactions
 
—

 
(75,572
)
Contributions
 
31,786

 
38,270

Distributions
 
(66,418
)
 
(88,851
)
Contribution from noncontrolling interest owners
 
11

 
296

Distributions to noncontrolling interests owners
 
(75
)
 
(1,777
)
LTIP tax netting unit repurchase
 
(1,030
)
 
(1,642
)
Payment of debt issuance costs
 
(4,701
)
 
(2,234
)
Payment of long-term debt
 
(792
)
 
(1,351
)
Payment of 3.97% Senior Notes
 
(1,316
)
 
—

Payments of other debt
 
(4,895
)
 
(3,732
)
Payments of credit agreement
 
(414,500
)
 
(546,408
)
Borrowings on credit agreement
 
316,600

 
367,809

Other
 
(71
)
 
86

Net cash used in financing activities
 
(145,401
)
 
(315,106
)
 
 
 
 
 
Net increase (decrease) in cash, cash equivalents and restricted cash
 
19,391


(298,115
)
Cash, cash equivalents and restricted cash, beginning of period
 
34,179

 
329,230

Cash, cash equivalents and restricted cash, end of period
 
$
53,570

 
$
31,115

 
 
 
 
 
Cash, cash equivalents and restricted cash, beginning of period
 
 
 
 
Cash and cash equivalents
 
$
8,782

 
$
5,666

Restricted cash - current
 
20,352

 
—

Restricted cash - non-current
 
5,045

 
323,564

Total cash, cash equivalents and restricted cash, beginning of period
 
$
34,179

 
$
329,230

 
 
 
 
 
Cash, cash equivalents and restricted cash, end of period
 
 
 
 
Cash and cash equivalents
 
$
22,758

 
$
6,739

Restricted cash - current
 
25,744

 
18,683

Restricted cash - non-current
 
5,068

 
5,693

Total cash, cash equivalents and restricted cash, end of period
 
$
53,570

 
$
31,115


The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.



9
American Midstream Partners, LP and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)




(1) Organization and Basis of Presentation

Organization

American Midstream Partners, LP (together with its consolidated subsidiaries, the “Partnership,” “we,” “us” or “our”) is a growth-oriented Delaware limited partnership that was formed in August 2009 to own, operate, develop and acquire a diversified portfolio of midstream energy assets. The Partnership’s general partner, American Midstream GP, LLC (the “General Partner”), is 77% directly owned by High Point Infrastructure Partners, LLC (“HPIP”) and 23% indirectly owned by Magnolia Infrastructure Holdings, LLC (“Magnolia”), both of which are affiliates of ArcLight Capital Partners, LLC (“ArcLight”). Our capital accounts consist of notional General Partner units and units representing limited partner interests.

We provide critical midstream infrastructure that links producers of natural gas, crude oil, NGLs, condensate and specialty chemicals to numerous intermediate and end-use markets. Through our five reportable segments, (1) Gas Gathering and Processing Services, (2) Liquid Pipelines and Services, (3) Natural Gas Transportation Services, (4) Offshore Pipelines and Services and (5) Terminalling Services, we engage in the business of gathering, treating, processing and transporting natural gas; gathering, transporting, storing, treating and fractionating NGLs; gathering, storing and transporting crude oil and condensates; and storing refined products. Most of our cash flow is generated from fee-based and fixed-margin compensation for gathering, processing, transporting and treating natural gas and crude oil; firm capacity reservation charges; interruptible transportation charges; guaranteed firm storage contracts; throughput fees and other optional charges associated with ancillary services.

Basis of presentation

The accompanying Condensed Consolidated Financial Statements are unaudited and have been prepared in accordance with Article 10 of Regulation S-X for interim financial information. Accordingly, they do not include all the information and notes required by GAAP for complete financial statements. In the opinion of our management, all adjustments, consisting only of normal recurring adjustments, considered necessary for a fair statement have been included. The results of operations for interim periods are not necessarily indicative of results of operations for a full year. These Condensed Consolidated Financial Statements should be read in conjunction with our Consolidated Financial Statements and Notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2017 filed with the U.S. Securities and Exchange Commission (the “SEC”) on April 9, 2018 (the “2017 Form 10-K”).

On April 15, 2013, ArcLight affiliates obtained control of our General Partner. We account for transactions between entities under common control at the affiliate's historical costs. For those transactions, our historical financial statements will be revised to include the results attributable to the assets acquired as if they were acquired on April 15, 2013 or the date the ArcLight affiliates obtained control of the assets or business acquired.

(2) Recent Accounting Pronouncements and Critical Accounting Policies

Standards Adopted in 2018

Revenue from Contracts with Customers (Topic 606) - In May 2014, the Financial Accounting Standards Board (the “FASB”) issued a new standard related to revenue recognition which supersedes most of the existing revenue recognition requirements in GAAP and requires entities to recognize revenue at an amount that reflects the consideration to which an entity expects to be entitled in exchange for transferring goods or services to a customer. It also requires significantly expanded disclosures regarding the qualitative and quantitative information of an entity’s nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.
The FASB has issued several amendments to the standard, including clarification on accounting for licenses of intellectual property, identifying performance obligations, reporting gross versus net revenue and narrow-scope revisions, and practical expedients.
We adopted the new standard on January 1, 2018 (the “initial application” date):
•
using the modified retrospective application, with no restatement of the comparative periods presented and a cumulative effect adjustment to retained earnings as of the date of adoption, and
•
disclosing the impact of the new standard in our Condensed Consolidated Financial Statements included in this report.

Our revenue is derived from the provision of gathering, processing, transportation, terminalling and storage services and the sale of commodities primarily to marketers and brokers, refiners and chemical manufacturers, utilities and power generation customers,

10
American Midstream Partners, LP and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



industrial users and local distribution companies. Beginning on January 1, 2018, we account for revenue from contracts with customers in accordance with Topic 606. The unit of account in Topic 606 is a performance obligation, which is a promise in a contract to transfer to a customer either a distinct good or service (or bundle of goods or services) or a series of distinct goods or services provided at a point in time or over a period of time. Topic 606 requires that a contract’s transaction price, which is the amount of consideration to which an entity expects to be entitled in exchange for transferring promised goods or services to a customer, is to be allocated to each performance obligation in the contract based on relative standalone selling prices and recognized as revenue when (point in time) or as (over time) the performance obligation is satisfied.

Commodity Sales - For the majority of our commodity sales contracts: (i) each unit of product is a separate performance obligation, since our promise is to sell multiple distinct units of product at a point in time, (ii) the transaction price principally consists of variable consideration, which is determinable on commodity index prices for the volume of the product sold to the customer that month and (iii) the transaction price is allocated to each performance obligation based on the product’s standalone selling price. Revenues from sales of commodities are recognized at the point in time when control of the commodity transfers to the customer, which generally occurs upon delivery of the product to the customer or its designee. Payment is generally received from the customer in the month following delivery. Contracts with customers have varying terms, including spot sales, month-to-month contracts and multi-year agreements.
In our Liquid Pipelines and Services segment, we enter into purchase and sales contracts as well as buy/sell contracts with counterparties, under which we gather and transport different types of crude oil and eventually sell the crude oil to either the same counterparty or different counterparties. For each of these arrangements, the Partnership assesses if control of the underlying commodity volumes transfer to the Partnership. Generally, the Partnership is unable to direct the use of the commodity volumes it purchases from the supplier because the Partnership is contractually required to redeliver an equivalent volume of the commodity back to the supplier or to a specified customer, therefore these arrangements are recorded on a net basis.
Occasionally, we enter into crude oil inventory exchange arrangements with the same counterparty where the purchase and sale of inventory are considered in contemplation of each other. These types of arrangements are accounted for as inventory exchanges and are recorded on a net basis.
Services - The Partnership provides gathering, processing, transportation, terminalling and storage services pursuant to a variety of contracts. Generally, for the majority of these contracts: (i) our promise is to transfer (or stand ready to transfer) a series of distinct integrated services over a period of time, which is a single performance obligation and (ii) the transaction price includes fixed or variable consideration, or both fixed and variable consideration. The amount of consideration is determinable at contract inception or at each month’s end based on our right to invoice at month end for the value of services provided to the customer in that month.
Revenue is recognized over the service period specified in the contract as the services are rendered using a time-based (passage of time) or units-based (units of service transferred) method for measuring provision of the services. Progress towards satisfying our performance obligation is based on the firm or interruptible nature of the promised service and the terms and conditions of the contract (such as contracts with or without makeup rights). Payment is generally received from the customer in the month of service or the month following the service. Contracts with customers generally are a combination of month-to-month and multi-year agreements.
Firm Services - Firm services are services that are promised to be available to the customer at all times during the term of the contract with limited exceptions. These agreements require customers to deliver, transport or throughput a minimum volume over an agreed upon period. Substantially all of such agreements are entered into with customers to economically support the return on our capital expenditure necessary to construct the related asset. Our firm service contracts are typically structured with take-or-pay or minimum volume provisions, which specify minimum service quantities a customer will pay for even if it chooses not to receive or use them in the specified service period (referred to as “deficiency quantities”).
Under firm service contracts, we record a receivable from the customer in the period that services are provided or when the transaction occurs, including amounts for deficiency quantities from customers associated with minimum volume commitments. If a customer has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty’s make-up right and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the customer’s ability to utilize the make-up right is remote.
Interruptible Services - Interruptible services are services provided to the extent that we have available capacity. Generally, we do not have an obligation to perform these services until we accept a customer’s periodic request for service. For the majority of these

11
American Midstream Partners, LP and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



contracts, the customer will pay only for the actual quantities of services it chooses to receive or use, and we typically recognize the transaction price as revenue as those units of service are transferred to the customer in the specified service period.
Gathering and Processing - Our Gas Gathering and Processing Services segment provides “wellhead-to-market” services to producers of natural gas and natural gas liquids, which include transporting raw natural gas from various receipt points through gathering systems, treating the raw natural gas, processing raw natural gas to separate the NGLs from the natural gas, fractionating NGLs and selling or delivering pipeline-quality natural gas and NGLs to various markets and pipeline systems. Services can be firm if subject to a minimum volume commitment or acreage dedication or interruptible when offered on an as requested, non-guaranteed basis. Revenue for fee-based gathering and processing services are valued based on the rate in effect for the month of service and is recognized in the month of service based on the volumes of natural gas we gather, process and fractionate. Under these arrangements, we may take control of: (i) none of the commodities we sell (i.e., residue gas or NGLs), (ii) a portion of the commodities we sell or (iii) all of the commodities we sell.
In those instances where we purchase and obtain control of the entire natural gas stream in our producer arrangements, we have determined these are contracts with suppliers rather than contracts with customers and therefore, these arrangements are not included in the scope of Topic 606. These supplier arrangements are subject to updated guidance in Accounting Standards Codification (“ASC”) 705, Cost of Sales and Services, whereby any embedded fees within such contracts, which historically have been reported as services revenue, are now reported as a reduction to cost of sales upon adoption of Topic 606.
In those instances where we remit all of the cash proceeds received from third parties for selling the extracted commodities to the producer, less the fees attributable to these arrangements, we have determined that the producer has control over these commodities. Upon adoption of Topic 606, we eliminated recording both sales revenue (natural gas and products) and cost of sales amounts and now only record fees attributable to these arrangements as service revenues.
In other instances where we do not obtain control of the extracted commodities we sell, we are acting as an agent for the producer and, upon adoption of Topic 606, we have continued to recognize services revenue for the net amount of consideration we retain in exchange for our service.
The Partnership may charge additional service fees to customers for a portion of the contract term (i.e., for the first year of a contract or until reaching a volume threshold) due to the significant upfront capital investment, and these fees are initially deferred and recognized to revenue over the expected period of customer benefit, generally the lesser of the expected contract term or the life of the related properties.
Transportation - Our transportation operations generally consist of fee-based activities associated with transporting crude oil, natural gas and NGL on pipelines, gathering systems and trucks. Revenues from pipeline tariffs and fees are associated with the transportation at a published tariff, as well as revenues associated with agreements for committed capacity on various assets. We primarily recognize pipeline tariff and fee revenues over time based on the volumes delivered and invoiced. The majority of our pipeline tariff and fee revenues are based on actual volumes and rates.
As is common in the pipeline transportation industry, our tariffs incorporate a loss allowance factor. The intent of the allowance in arrangements for the transportation of natural gas is to approximate the natural shrink that occurs when transporting the gas. For crude oil transportation arrangements, loss allowance provisions are immaterial to the Partnership. In the event the Partnership retains excess natural gas and crude oil and subsequently sells the commodity to a third party, the sale is recorded at that point in time as a commodity sale.
Terminalling and Storage - In our Terminalling Services segment, we generally receive fee-based compensation on guaranteed firm storage contracts, throughput fees charged to our customers when their products are either received or disbursed, and other operational charges associated with ancillary services provided to our customers, such as excess throughput and steam heating. Storage fees resulting from short-term and long-term contracts are typically recognized in revenue ratably over the term of the contract regardless of the actual storage capacity utilized.
Adoption of the new revenue standard resulted in changes to the timing of revenue recognition and in the reclassification between financial statement line items. See Note 3 - Revenue Recognition, for further discussion.
Statement of Cash Flows - In August 2016, the FASB issued Accounting Standards Update (“ASU”) No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”). ASU 2016-15 provides specific guidance on cash flow classification issues to reduce diversity in practice. In connection with the January 1, 2018 retrospective adoption of this ASU, for the nine months ended September 30, 2017, we reclassified $9.4 million in distributions

12
American Midstream Partners, LP and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



received from unconsolidated affiliates from operating cash inflows to investing cash inflows and reclassified $2.5 million of transaction costs associated the disposal of our Propane Business from an investing cash outflow to an operating cash outflow in our Condensed Consolidated Statements of Cash Flows.

In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (“ASU 2016-18”), which requires amounts described as restricted cash and restricted cash equivalents to be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. A reconciliation between the balance sheet and the statement of cash flows must be disclosed when the balance sheet includes more than one line item for cash, cash equivalents, restricted cash and restricted cash equivalents.

We retrospectively adopted ASU 2016-18 as of January 1, 2018. For the nine months ended September 30, 2017, cash flows from operating activities have been adjusted to remove the impact of $3.5 million in restricted cash outflows, and cash flows from investing activities has been adjusted to remove the impact of $302.7 million in restricted cash inflows.

During the preparation of our third quarter of 2018 Condensed Consolidated Financial Statements, we identified an error in the presentation of distributions from unconsolidated affiliates in our Condensed Consolidated Statements of Cash Flows in our March 31, 2018 and June 30, 2018 Quarterly Reports on Form 10-Q. This error resulted in the overstatement of net cash provided by operating activities and a corresponding overstatement of net cash used in investing activities of $2.5 million for the three months ended March 31, 2018 and the understatement of net cash provided by operating activities and a corresponding understatement of net cash used in investing activities of $1.0 million for the six months ended June 30, 2018. This error also resulted in a $6.3 million overstatement of net cash provided by operating activities and a corresponding overstatement of net cash used in investing activities for the six months ended June 30, 2017 as presented in the June 30, 2018 Quarterly Report on Form 10-Q. These errors were corrected in the accompanying Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2018 and 2017. The errors were not considered material to the previously issued or current financial statements.

Stock Compensation - In May 2017, the FASB issued ASU No. 2017-09, Compensation - Stock Compensation (Topic 718): Scope of Modification Accounting (“ASU 2017-09”). ASU 2017-09 was issued with the intent to clarify the scope of modification accounting and when it should be applied to a change to the terms or conditions of a share-based payment award. Under the new guidance, modification accounting is required for all changes to share based payment awards, unless all the following conditions are met: (i) there is no change to the fair value of the award, (ii) the vesting conditions have not changed and (iii) the classification of the award as an equity instrument or a debt instrument has not changed. We adopted ASU 2017-09 on its effective date of January 1, 2018, and the adoption did not have a material impact on our Condensed Consolidated Financial Statements.

Income Taxes - In March 2018, the FASB issued ASU No. 2018-05, Income Taxes (Topic 740): Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118 (SEC Update) (“ASU 2018-05”), to provide guidance for companies that have not completed their accounting for the income tax effects of the Tax Cuts and Jobs Act (the “Act”) in the period of enactment. The measurement period begins in the reporting period that includes the Act’s enactment date of December 22, 2017, and ends when a company has obtained, prepared and analyzed the information needed to complete the accounting requirements under ASU 2018-05 and should not extend beyond one year from the enactment date. The impact of adopting the new guidance on our consolidated financial position, cash flows or results of operations, as well as on related disclosures was not material.

Standards Not Yet Adopted

Leases (Topic 842) - In February 2016, the FASB issued ASU No. 2016-02 (“Topic 842”) Leases, which supersedes the lease recognition requirements in ASC 840, Leases. Under the new guidance, for leases with a term longer than 12 months a lessee should recognize a lease liability and a right-of-use asset representing its right to use the underlying asset for the lease term. Topic 842 retains a classification distinction between finance leases and operating leases, with the classification affecting the pattern of expense recognition in the income statement. This ASU also requires enhanced disclosures. Early adoption is permitted. We are currently assessing the impact of this new guidance via review of existing contracts that may have a lease impact and other purchase obligations that contain embedded lease features, which are generally classified as operating leases under the existing guidance. We selected a third-party consulting firm to assist us with the adoption of the new guidance. We are implementing specialized software and developing policies based on reviews performed to date of existing arrangements. We intend to complete any required changes to our systems, software applications and processes, including updating our internal controls during 2018. In 2018, the FASB also issued ASU No. 2018-01, Land Easement Practical Expedient for Transition to Topic 842 and ASU No. 2018-11, Targeted Improvements. Under these updates, optional transition practical expedients are available i) whereby existing or expired land easements that were not previously accounted for as leases under Topic 840 are not required to be evaluated under Topic 842 and ii) lease and associated non-lease components are not required to be separated within a contract if certain criteria are met. In addition, under ASU No. 2018-11, companies may initially apply the new lease requirements at the effective date. We

13
American Midstream Partners, LP and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



intend to apply the new lease requirements as of January 1, 2019, recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption, and to apply the practical expedients. We are still in the process of quantifying the cumulative-effect adjustment.
Financial Instruments - In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”). This guidance will become effective for interim and annual periods beginning after December 15, 2019. We expect to adopt ASU 2016-13 on January 1, 2020, and we are currently evaluating the effect that adopting this guidance will have on our consolidated financial position, results of operations and cash flows.

Fair Value Measurement - In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurements (Topic 820): Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”). This guidance eliminates certain disclosure requirements for fair value measurements for all entities, requires public entities to disclose certain new information and modifies certain disclosure requirements. The FASB developed the amendments to Topic 820 as part of its broader disclosure framework project, which aims to improve the effectiveness of disclosures in the notes to financial statements by focusing on requirements that clearly communicate the most important information to users of the financial statements. This guidance will become effective for interim and annual periods beginning after December 15, 2019. We expect to adopt ASU 2018-13 on January 1, 2020, and we are currently evaluating the impact, if any, that adopting this guidance will have on our disclosures.

Cloud Computing Arrangements - In August 2018, the FASB issued ASU No. 2018-15, Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement that is a Service Contract ("ASU 2018-15"). The ASU aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The capitalized implementation costs of a hosting arrangement that is a service contract will be expensed over the term of the hosting arrangement. ASU 2018-15 is effective for annual and interim periods beginning after December 15, 2019. Early adoption is permitted, including adoption in any interim period. The amendments can be applied either retrospectively or prospectively to all implementation costs incurred after the adoption date. We expect to adopt ASU 2018-15 on January 1, 2020, and we are currently evaluating the impact, if any, that adopting this guidance will have on our accounting and disclosures.

Critical Accounting Policies and Estimates

See Item 7 section Critical Accounting Policies and Estimates and Item 1A. Risk Factors of the 2017 Form 10-K for additional information relating to our critical accounting policies and risk factors.

Goodwill - We record goodwill for the excess of the cost of an acquisition over the fair value of the net assets of the acquired business. Goodwill is reviewed for impairment at least annually, as of October 1st of each year, or more frequently if an event or change in circumstance indicates that an impairment may have occurred. We first assess qualitative factors to evaluate whether it is more likely than not that an impairment has occurred, and it is therefore necessary to perform the one-step quantitative goodwill impairment test. If the one-step quantitative goodwill impairment test indicates that the goodwill is impaired, an impairment loss is recorded, which is the difference between carrying value of the reporting unit and its fair value, with the impairment loss not to exceed the amount of goodwill recorded.

When performing a quantitative impairment test, the Partnership generally determines the fair value of its reporting units using a discounted cash flow method. In the event the Partnership enters into an agreement to sell all or substantially all of a reporting unit, the Partnership will utilize such information. While using the discounted cash flow method, we must make estimates of projected cash flows related to assets, which include, but are not limited to, assumptions about revenue growth rates, operating margins, weighted average costs of capital and future market conditions, the use or disposition of assets, estimated remaining life of assets and future expenditures necessary to maintain current operations. We also must make certain estimates and assumptions, including, among other things, changes in general economic conditions in regions in which our markets are located, the availability and prices of energy commodities (such as natural gas, crude oil and refined products), our ability to negotiate favorable sales agreements, the risks that natural gas exploration and production activities will not occur or be successful, our dependence on certain significant customers and producers of natural gas and competition from other companies.

Under the discounted cash flow method, the Partnership determines fair value based on estimated future cash flows and earnings before income tax, depreciation and amortization (“EBITDA”) of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflects the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one-year budgeted amounts and five-year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit

14
American Midstream Partners, LP and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



using growth rates that management believes are reasonably likely to occur. The annual budget process is typically completed near the annual goodwill impairment testing date, and management uses the most recent information for the annual impairment tests. The forecast is also subjected to a comprehensive update annually in conjunction with the annual budget process and is revised periodically to reflect new information and revised expectations.

The estimates of future cash flows and EBITDA are subjective in nature and are subject to impacts from the business risks described in Item 1A. Risk Factors of the 2017 Form 10-K. While we believe we have made reasonable estimates and assumptions based on available information to calculate the fair value, if future results are not consistent with our estimates, changes in fair value estimates could result in additional impairments in future periods that could be material to our results of operations.

As of December 31, 2017, we had $128.9 million of goodwill within seven reporting units. Of this amount, $46.8 million of goodwill for two reporting units was at risk of failing the one-step quantitative test.

Our Silver Dollar reporting unit in our Liquid Pipelines and Services segment had $35.7 million in goodwill as of December 31, 2017. As described in Note 10 - Goodwill and Intangible Assets, Net in our 2017 Form 10-K, we recorded an impairment on the Silver Dollar reporting unit during the fourth quarter of 2017; therefore, the fair value approximates the carrying value subsequent to impairment. The impairment taken in 2017 related primarily to cash flow assumptions included in our discounted cash flow analysis that were adversely impacted by delays in drilling and completions experienced by producers.

The Cushing reporting unit in our Terminalling Services segment had $11.1 million in goodwill as of December 31, 2017, and the fair value exceeded carrying value by approximately 7%. In our discounted cash flow analysis for 2017, we assumed lower utilization rates and cash flows due to required tank inspections through early 2019. The lower utilization was not previously expected, or reflected, in our assumptions. If the expected completion date of the inspections or future contracting rates should differ from the assumptions made in our 2017 analysis, the amount by which the estimated fair value exceeds carrying value could be negatively impacted.

As of September 30, 2018, we had $51.7 million of goodwill within three reporting units in our Condensed Consolidated Balance Sheet and $61.2 million of goodwill within two reporting units classified as held for sale. There were no triggering events during the nine months ended September 30, 2018 and, therefore, we have not quantitatively updated our assessments. We will perform our annual impairment test for goodwill as of October 1, 2018.
 
(3) Revenue Recognition

Effect of ASC Topic 606 Adoption - The effect of adopting Topic 606, due to the change in method to measure project progress, as discussed in Note 2 - Recent Accounting Pronouncements, is as follows (in thousands):

 
 
Three months ended September 30, 2018
 
Nine months ended September 30, 2018
 
 
As Reported
 
Adjustments
 
Amounts Without Adoption of Topic 606
 
As Reported
 
Adjustments
 
Amounts Without Adoption of Topic 606
Revenue
 
 
 
 
 
 
 
 
 
 
 
 
Commodity sales
 
$
156,817


$
10,388

 
$
167,205

 
$
479,923

 
$
28,165

 
$
508,088

Services
 
45,763

 
(9,965
)
 
35,798

 
148,997

 
(24,890
)
 
124,107

Operating expenses
 
 
 
 
 
 
 
 
 
 
 
 
Costs of sales
 
150,274

 
6,349

 
156,623

 
461,948

 
14,923

 
476,871

Direct operating expenses
 
20,407

 
(5,248
)
 
15,159

 
65,595

 
(10,254
)
 
55,341

Operating income
 
67,164

 
(678
)
 
66,486

 
47,142

 
(1,394
)
 
45,748

 
 
 
 
 
 
 
 
 
 
 
 
 
Net income attributable to the Partnership
 
38,158

 
(678
)
 
37,480

 
6,984

 
(1,394
)
 
5,590

 
 
 
 
 
 
 
 
 
 
 
 
 
General Partner’s interest in net income
 
504

 
(9
)
 
495

 
92

 
(18
)
 
74

Limited Partners’ interest in net income
 
37,654

 
(669
)
 
36,985

 
6,892

 
(1,376
)
 
5,516



15
American Midstream Partners, LP and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



 
 
As of September 30, 2018
                                   
 
As Reported
 
Adjustments
 
Amounts Without Adoption of Topic 606
Assets
 
 
 
 
 
 
Accounts receivable, net
 
$
84,819

 
$
(66,250
)
 
$
18,569

Unbilled revenue
 
—

 
66,250

 
66,250

Other current assets
 
25,971

 
(252
)
 
25,719

Other assets, net
 
21,506

 
(7,785
)
 
13,721

Liabilities
 
 
 
 
 
 
Accrued expenses and other current liabilities
 
116,141

 
(905
)
 
115,236

Liabilities held for sale
 
1,922

 
(665
)
 
1,257

Other long-term liabilities
 
15,770

 
(14,110
)
 
1,660


The majority of the adjustments in the table above were associated with our natural gas gathering and processing, transportation pipeline and terminalling revenues. The magnitude of the future effect of implementing Topic 606 is dependent on future customer volumes subject to the impacted contracts and commodity prices for those volumes.

Disaggregated Revenue

The following table presents our segment revenues from contracts with customers disaggregated by type of activity (in thousands):
 
Three months ended September 30, 2018
 
Gas Gathering and Processing Services
 
Liquid Pipelines and Services
 
Natural Gas Transportation Services
 
Offshore Pipelines and Services
 
Terminalling Services
 
Total
Commodity sales:
 
 
 
 
 
 
 
 
 
 
 
     Natural gas
$
2,672

 
$
—

 
$
5,988

 
$
2,207

 
$
—

 
$
10,867

     NGLs
24,338

 
—

 
—

 
54

 
—

 
24,392

     Condensate
14,994

 
—

 
—

 
343

 
—

 
15,337

     Crude oil
—

 
104,984

 
—

 
—

 
—

 
104,984

     Other sales (1)
365

 
—

 
1

 
19

 
852

 
1,237

 
42,369

 
104,984

 
5,989

 
2,623

 
852

 
156,817

Services:
 
 
 
 
 
 
 
 
 
 
 
     Gathering and processing
10,164

 
—

 
—

 
969

 
—

 
11,133

     Transportation
241

 
4,540

 
6,565

 
10,203

 
—

 
21,549

     Terminalling and storage
—

 
—

 
—

 
—

 
6,410

 
6,410

     Other services (2)
655

 
35

 
156

 
5,536

 
289

 
6,671

 
11,060

 
4,575

 
6,721

 
16,708

 
6,699

 
45,763

 
 
 
 
 
 
 
 
 
 
 
 
Revenues from contracts with customers
$
53,429

 
$
109,559

 
$
12,710

 
$
19,331

 
$
7,551

 
$
202,580


16
American Midstream Partners, LP and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



 
Nine months ended September 30, 2018
 
Gas Gathering and Processing Services
 
Liquid Pipelines and Services
 
Natural Gas Transportation Services
 
Offshore Pipelines and Services
 
Terminalling Services
 
Total
Commodity sales:
 
 
 
 
 
 
 
 
 
 
 
     Natural gas
$
8,099

 
$
—

 
$
18,098

 
$
7,231

 
$
—

 
$
33,428

     NGLs
63,547

 
—

 
—

 
125

 
—

 
63,672

     Condensate
34,796

 
—

 
—

 
440

 
—

 
35,236

     Crude oil
—

 
337,281

 
—

 
—

 
—

 
337,281

     Other sales (1)
690

 
—

 
7

 
83

 
9,526

 
10,306

 
107,132

 
337,281

 
18,105

 
7,879

 
9,526

 
479,923

Services:
 
 
 
 
 
 
 
 
 
 
 
     Gathering and processing
29,370

 
—

 
—

 
874

 
—

 
30,244

     Transportation
489

 
11,754

 
25,833

 
29,092

 
—

 
67,168

     Terminalling and storage
—

 
—

 
—

 
—

 
30,393

 
30,393

     Other services (2)
1,622

 
912

 
401

 
16,866

 
1,391

 
21,192

 
31,481

 
12,666

 
26,234

 
46,832

 
31,784

 
148,997

 
 
 
 
 
 
 
 
 
 
 
 
Revenues from contracts with customers
$
138,613

 
$
349,947

 
$
44,339

 
$
54,711

 
$
41,310

 
$
628,920

_________________________ 
(1) Other commodity sales for our Terminalling Services segment include sales of Refined Products and Marine Products terminals. See Note 4 - Acquisitions and Dispositions.
(2) Other services in our Offshore Pipelines and Services segment include asset management services.

Other Items in Revenue

The following table presents the reconciliation of our revenues from contracts with customers to segment revenues and total revenues as disclosed in our Condensed Consolidated Statements of Operations (in thousands):

 
Three months ended September 30, 2018
 
Gas Gathering and Processing Services
 
Liquid Pipelines and Services
 
Natural Gas Transportation Services
 
Offshore Pipelines and Services
 
Terminalling Services
 
Total
Revenues from contracts with customers
$
53,429

 
$
109,559

 
$
12,710

 
$
19,331

 
$
7,551

 
$
202,580

Loss on commodity derivatives, net
(93
)
 
(141
)
 
—

 
—

 
—

 
(234
)
     Total revenues of reportable segments
$
53,336

 
$
109,418

 
$
12,710

 
$
19,331

 
$
7,551

 
$
202,346

 
Nine months ended September 30, 2018
 
Gas Gathering and Processing Services
 
Liquid Pipelines and Services
 
Natural Gas Transportation Services
 
Offshore Pipelines and Services
 
Terminalling Services
 
Total
Revenues from contracts with customers
$
138,613

 
$
349,947

 
$
44,339

 
$
54,711

 
$
41,310

 
$
628,920

Loss on commodity derivatives, net
(385
)
 
(145
)
 
—

 
—

 
—

 
(530
)
     Total revenues of reportable segments
$
138,228

 
$
349,802

 
$
44,339

 
$
54,711

 
$
41,310

 
$
628,390

    
We may utilize derivative instruments in connection with contracts with customers. We purchase and take title to a portion of the NGLs and crude oil that we sell, which may expose us to changes in the price of these products in our sales markets. We do not take title to the natural gas we transport and therefore have no direct commodity price exposure to natural gas. Derivative gains or losses are not included as a component of revenue from contracts with customers, but are included in other items in revenue.


17
American Midstream Partners, LP and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



Contract Balances

Our contract assets and liabilities primarily relate to contracts where allocations of the transaction prices result in differences to the pattern and timing of revenue recognition as compared to contractual billings. Where payments are received in advance of recognition as revenue, contract liabilities are created. Where we have earned revenue and our right to invoice the customer is conditioned on something other than the passage of time, contract assets are created.

The following table presents the change in the contract assets and liability balances during the nine months ended September 30, 2018 (in thousands):
 
Contract Assets
 
Contract Liabilities
Balance at December 31, 2017
$
—

 
$
2,136

Topic 606 implementation
2,555

 
13,246

Amounts recognized as revenue
—

 
(2,155
)
Additions
5,482

 
3,250

Contract balances included in assets/liabilities held for sale
—

 
(665
)
Balances at September 30, 2018
$
8,037

 
$
15,812

 
 
 
 
Current
$
252

 
$
905

Non-current
7,785

 
14,907

Balances at September 30, 2018
$
8,037

 
$
15,812


As of September 30, 2018, in our Condensed Consolidated Balance Sheets, the current portion of contract assets is included as a component of Accounts Receivable, net of allowance for doubtful accounts, the non-current portion is included in Other assets, net; the current portion of contract liabilities is included in Accrued expenses and other current liabilities and the non-current portion is included in Other long-term liabilities.

Remaining Performance Obligations

The Partnership applies the practical expedients in Topic 606 and does not disclose consideration for remaining performance obligations with an original expected duration of one year or less or for variable consideration related to unsatisfied (or partially unsatisfied) performance obligations. The following table as of September 30, 2018, represents only revenue expected to be recognized from contracts where the price and quantity of the product or service are fixed:

 
Remainder of 2018
 
2019
 
2020
 
2021
 
2022
 
Thereafter
 
Total
Gathering and processing based on minimum volume commitments
$
3,065

 
$
12,667

 
$
12,667

 
$
12,644

 
$
12,391

 
$
18,289

 
$
71,723

Transportation agreements
5,523

 
19,604

 
18,690

 
18,507

 
18,428

 
193,484

 
274,236

Terminalling and storage throughput agreements(1)
972

 
3,644

 
2,419

 
2,113

 
1,005

 
—

 
10,153

Other
423

 
1,648

 
1,560

 
—

 
—

 
—

 
3,631

Total
$
9,983

 
$
37,563

 
$
35,336

 
$
33,264

 
$
31,824

 
$
211,773

 
$
359,743

_________________________ 
(1) Represents remaining performance obligations associated with assets held-for-sale.

Due to the application of the practical expedients, the table above represents only a portion of the Partnership’s expected future consolidated revenues and it is not necessarily indicative of the expected trend in total revenues for the Partnership. Certain contracts have not been presented in the table above due to the term being one year or less and due to variability in the amount of performance obligation remaining, variability in the timing of recognition or variability in consideration. Acreage dedications do require us to perform future services but do not contain a minimum level of services and are therefore excluded from this presentation. Long-term supply and logistics arrangements contain variable timing, volumes and/or consideration and are excluded from this presentation.

18
American Midstream Partners, LP and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)




(4) Acquisitions and Dispositions

Acquisitions

The 2017 acquisitions are as follows:

•
On March 8, 2017, we completed the acquisition of JP Energy Partners LP (“JPE”), an entity controlled by ArcLight affiliates, in a unit-for-unit exchange. As both we and JPE were controlled by ArcLight affiliates, the acquisition represented a transaction among entities under common control. The accompanying Condensed Consolidated Financial Statements and related Notes present the combined financial position, results of operations, cash flows and equity of JPE at historical cost.
•
On June 2, 2017, we acquired 100% of Viosca Knoll Gathering System (“VKGS”) from Genesis Energy, L.P. for total consideration of approximately $32 million in cash. This was accounted for as a business combination.
•
On August 8, 2017, we acquired 100% of the interest in Panther Offshore Gathering Systems, LLC (“POGS”), Panther Pipeline, LLC (“PPL”) and Panther Operating Company, LLC (“POC” and, together with POGS and PPL, “Panther”) from Panther Asset Management LLC for $60.9 million in cash, issuance of common units and other considerations. This was accounted for as a business combination.
•
On November 3, 2017, we completed the acquisition of 100% of the equity interests in Trans-Union Interstate Pipeline, LP (“Trans-Union”) from affiliates of ArcLight, for a total consideration of $49.4 million. The consideration consisted of $16.9 million cash funded from borrowings under our revolving credit facility and the assumption of $32.5 million of non-recourse debt. This was accounted for as an acquisition between entities under common control.

Additionally, we acquired the following interests in 2017 that are accounted for as investments in unconsolidated affiliates:

•
On August 8, 2017, we entered into a new joint venture agreement with Targa Midstream Services, LLC (“Targa”) by which our previously wholly owned subsidiary Cayenne Pipeline, LLC became the Cayenne joint venture between Targa and us.
•
On September 29, 2017, we acquired an additional 15.5% equity interest in Class A units of the Delta House platform (“Delta House”) from affiliates of ArcLight for total cash consideration of $125.4 million. 
•
On October 27, 2017, American Midstream Emerald, LLC, a wholly-owned subsidiary of the Partnership, entered into a purchase and sale agreement with Emerald Midstream, LLC, an ArcLight affiliate, to purchase an additional 17% equity interest in Destin for total cash consideration of $30.0 million.

For further discussion, see the Note 3 - Acquisitions in our 2017 Form 10-K. The proforma effects of the 2017 acquisitions were not material to our Condensed Consolidated Statements of Operations and therefore have not been presented separately.

Southcross Energy Partners, L.P. Merger Termination Fee

On October 31, 2017, we, our General Partner, our wholly owned subsidiary, Cherokee Merger Sub LLC, Southcross Energy Partners, L.P. (“SXE”) and Southcross Energy Partners GP, LLC, entered into an Agreement and Plan of Merger (the “SXE Merger Agreement”), and we, our General Partner and Southcross Holdings LP (“Holdings LP”) entered in to a Contribution Agreement (“Contribution Agreement”), for total consideration of $818 million. Under the Merger Agreement and the Contribution Agreement, we would have acquired SXE and substantially all the current subsidiaries of Holdings LP. The SXE Merger Agreement and the Contribution Agreement originally provided for an outside closing date of June 1, 2018. On June 1, 2018 the parties to the Merger Agreement and the Contribution Agreement agreed to extend such outside closing date to June 15, 2018 (the “Outside Closing Date”).

On July 29, 2018, following the expiration of the Outside Closing Date, we received notice of termination of the SXE Merger Agreement from SXE and notice of termination of the Contribution Agreement from Holdings LP. The terms of the Contribution Agreement required the payment to Holdings LP of a $17 million termination fee in the event Holdings LP terminated the Contribution Agreement after the Outside Closing Date due to our inability to obtain financing to close the SXE Transactions on terms reasonably acceptable to us. The termination fee serves as liquidated damages, was paid in August 2018 and is presented as Termination fee in the Condensed Consolidated Statements of Operations.


19
American Midstream Partners, LP and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



Dispositions

On June 16, 2018, we entered into a definitive agreement for the sale of our marine liquids terminals (the “Marine Products”) to institutional investors. The divestiture of the Marine Products, including the Harvey and Westwego terminals located in the Port of New Orleans, Louisiana and the Brunswick terminal located in the Port of Brunswick, Georgia, is a continuation of the Partnership's previously announced non-core asset divestiture program. On July 31, 2018, we completed the sale of Marine Products. Net proceeds from this disposition were $208.6 million, exclusive of $5.7 million in advisory fees and other costs, and were used to pay down the Credit Agreement (as defined in Note 13 - Debt Obligations). We recognized a $99.4 million gain, which is reflected in the Gain on Sale of Assets, Net in our Condensed Consolidated Statements of Operations. The tax expense associated with the gain was approximately $29.8 million and is included in Income tax expense in the Condensed Consolidated Statements of Operations. The sale of Marine Products did not meet the criteria for discontinued operations, as we believe the disposal does not represent a strategic shift that will have a major effect on our operations or financial results.

Assets Held for Sale

In the second quarter of 2017, we began executing a capital optimization strategy to simplify our business and redeploy capital from non-core assets toward higher return and growth opportunities. In addition to the sale of our propane business (“Propane Business”) discussed below under Discontinued Operations, we determined that our terminalling assets were not integral to our core strategies, and therefore, we began contemplating their disposition. We began actively marketing our Terminalling Services segment assets to use the proceeds to fund future acquisitions and growth projects.
On February 16, 2018, we entered into a definitive agreement for the sale of our refined products terminals (the “Refined Products”) to DKGP Energy Terminals LLC (“DKGP”), for $138.5 million in cash, subject to working capital adjustments. On August 1, 2018, we, and DKGP, announced the termination of the sales agreement for our Refined Products. We are continuing to market Refined Products.

The planned disposition of the Refined Products terminals does not meet the criteria for discontinued operations, as we believe the disposal does not represent a strategic shift that will have a major effect on our operations or financial results. As of September 30, 2018, Refined Products assets and liabilities are classified as current assets held for sale and current liabilities held for sale consistent with the classification of our revolving credit facility which matures September 5, 2019, as the net cash proceeds received from the sale are required to be repaid and reduce the aggregate commitments of our revolving credit facility. See Note 13 - Debt Obligations for more information. As of September 30, 2018, certain remaining assets in the Terminalling Services segment do not meet the criteria to be classified as held for sale, and are therefore excluded from being presented as held for sale.

Included in the disposal group are the following assets and liabilities at September 30, 2018 (in thousands):
 
Refined Products
 
 
Accounts receivable, net
$
2,170

Inventory
762

Other current assets
131

Property, plant and equipment, net
32,390

Goodwill
61,163

Intangible assets
29,403

Other non-current assets
671

     Total assets held for sale
$
126,690

 
 
Accounts payable
$
227

Accrued gas purchases
108

Accrued expenses and other current liabilities
1,097

Other long-term liabilities
490

     Total liabilities held for sale
$
1,922


20
American Midstream Partners, LP and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



Discontinued Operations

On September 1, 2017, we completed the disposition of our Propane Business pursuant to the Membership Interest Purchase Agreement dated July 21, 2017, between AMID Merger LP, a wholly owned subsidiary of the Partnership, and SHV Energy N.V. Through the transaction, we divested Pinnacle Propane’s 40 service locations; Pinnacle Propane Express’ cylinder exchange business and related logistics assets; and the Alliant Gas utility system. Prior to the sale, we moved the trucking business from the Propane Marketing Services segment to the Liquid Pipelines and Services segment. With the disposition of the Propane Business, we eliminated the Propane Marketing Services segment.

In connection with the transaction, we received approximately $170 million in cash, net of customary closing adjustments. We recorded a gain of $46.5 million, exclusive of of $2.5 million in advisory fees and other costs. We have reported the accounts and the results of our Propane Business, including the gain on sale, as Income from discontinued operations, including gain on sale in our Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2017.

Summarized financial information related to the Propane Business is set forth in the tables below (in thousands):
 
Three months ended September 30, 2017
 
Nine months ended September 30, 2017
Total revenue
$
20,458

 
$
87,615

Total operating expenses
22,489

 
92,196

     Operating loss
(2,031
)
 
(4,581
)
Other income
197

 
280

Income tax expense
(15
)
 
(59
)
Loss from discontinued operations
(1,849
)
 
(4,360
)
     Gain from the sale of discontinued operations
46,545

 
46,545

Income from discontinued operations, including gain on sale
$
44,696

 
$
42,185

 
 
 
 
Depreciation and amortization
$
2,355

 
$
9,823

Capital expenditures
$
722

 
$
3,143

 
 
 
 
Operating and investing non-cash items related to discontinued operations:
 
 
 
(Gain) loss on sales of assets, net
$
118

 
$
(55
)
Unrealized loss on derivative contracts, net
$
(526
)
 
$
530


(5) Inventory

Inventory consists of the following (in thousands):
 
 
September 30, 2018
 
December 31, 2017
Crude oil
 
$
2,416

 
$
1,553

NGLs
 
544

 
347

Refined products
 
—

 
934

Materials, supplies and equipment
 
120

 
132

Total inventory
 
$
3,080

 
$
2,966



21
American Midstream Partners, LP and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



(6) Other Current Assets

Other current assets consist of the following (in thousands):
 
September 30, 2018
 
December 31, 2017
Prepaid expenses
$
6,049

 
$
8,944

Current portion of deferred debt issuance costs (1)
5,057

 
—

Insurance receivables
649

 
1,741

Due from related parties
2,461

 
4,362

Other receivables
4,520

 
5,187

Risk management assets
7,235

 
3,186

   Total other current assets
$
25,971

 
$
23,420

___________________________________________________ 
(1) Related to our Credit Agreement. See Note 13 - Debt Obligations for discussion of our debt obligations.


(7) Risk Management Activities

We are exposed to certain market risks related to the volatility of commodity prices and changes in interest rates. To monitor and manage these market risks, we have established comprehensive risk management policies and procedures. We do not enter into derivative instruments for any purpose other than hedging commodity price risk, interest rate risk and weather risk. We do not speculate using derivative instruments.

Commodity Derivatives

To manage the impact of the risks associated with changes in the market price of NGL, crude oil and refined products in our day-to-day business, we use a combination of fixed price swaps and forward contracts.

Our forward contracts that qualify for the Normal Purchase Normal Sale (“NPNS”) exception under GAAP are recognized when the underlying commodity is delivered. In accordance with ASC 815, Derivatives and Hedging, if it is determined that a transaction designated as NPNS no longer meets the scope of the exception, the fair value of the related contract is recorded on the balance sheet (as an asset or liability) and the difference between the fair value and the contract amount is immediately recognized through earnings.

We measure our commodity derivatives at fair value using the income approach, which discounts the future net cash settlements expected under the derivative contracts to a present value. These valuations utilize indirectly observable (“Level 2”) inputs, including commodity prices observable at commonly quoted intervals.

The following table summarizes the net notional volumes of our outstanding commodity-related derivatives, excluding those contracts that qualified for the NPNS exception as of September 30, 2018 and December 31, 2017, none of which were designated as hedges for accounting purposes. We had no outstanding commodity-related derivatives as of December 31, 2017.
 
 
September 30, 2018
 
December 31, 2017
Commodity Swaps
 
Volume
 
Maturity
 
Volume
 
Maturity
NGLs Fixed Price (gallons)
 
831,600
 
January 2019
 
—
 
—
Crude Oil Basis (barrels)
 
93,000
 
December 2018
 
—
 
—

Interest Rate Swaps

To manage the impact of the interest rate risk associated with our Credit Agreement, we enter into interest rate swaps from time to time, effectively converting a portion of the cash flows related to our long-term variable rate debt into fixed rate cash flows.

As of both September 30, 2018 and December 31, 2017, we had a combined notional principal amount of $550.0 million of variable-to-fixed interest rate swap agreements. As of September 30, 2018, the maximum length of time over which we have hedged a portion of our exposure due to interest rate risk is through December 31, 2022.

22
American Midstream Partners, LP and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)




The fair value of our interest rate swaps was estimated using a valuation methodology based upon forward interest rates and volatility curves as well as other relevant economic measures, if necessary. Discount factors may be utilized to extrapolate a forecast of future cash flows associated with long dated transactions or illiquid market points. The inputs, which represent Level 2 inputs in the valuation hierarchy, are obtained from independent pricing service providers, and we have made no adjustments to those prices.

Weather Derivative

In the second quarters of 2018 and 2017, we entered into a yearly weather derivative arrangement to mitigate the impact of potential unfavorable weather on our operations under which we could receive payments totaling up to $20.0 million and $30.0 million, respectively, in the event that a hurricane of certain strength passes through the areas identified in the derivative agreement. The weather derivative, which is accounted for using the intrinsic value method, was entered into with a single counterparty, and we were not required to post collateral.

We paid $1.0 million and $1.1 million in premiums during the nine months ended September 30, 2018 and 2017, respectively. Premiums are amortized to Direct operating expenses on a straight-line basis over the one-year term of the contract. Unamortized amounts associated with the weather derivatives were $0.7 million and $0.5 million as of September 30, 2018 and December 31, 2017, respectively, and are included in Other current assets on the Condensed Consolidated Balance Sheets.

Financial Instruments Measured at Fair Value on a Recurring Basis - The following table summarizes the fair values of our derivative contracts (before netting adjustments) included in the Condensed Consolidated Balance Sheets (in thousands):
 
 
 
Asset Derivatives
 
Liability Derivatives
Type
Balance Sheet Classification
 
September 30,
2018
 
December 31, 2017
 
September 30,
2018
 
December 31, 2017
Commodity derivatives
Accrued expenses and other current liabilities
 
$
—

 
$
—

 
$
(352
)
 
$
—

 
 
 
 
 
 
 
 
 
 
Interest rate swaps
Other current assets
 
6,534

 
2,677

 
—

 
—

Interest rate swaps
Other assets, net
 
11,074

 
8,807

 
—

 
—

 
 
 
 
 
 
 
 
 
 
Weather derivatives
Other current assets
 
701

 
509

 
—

 
—

 
Total
 
$
18,309

 
$
11,993

 
$
(352
)
 
$
—

    
As of September 30, 2018 and December 31, 2017, there were no offsets to the fair value of our derivative assets and liabilities on a gross basis in the Condensed Consolidated Balance Sheets subject to enforceable master netting arrangements.

For each of the three and nine months ended September 30, 2018 and 2017, the realized and unrealized gains (losses) associated with our commodity, interest rate and weather derivative instruments were recorded in our Condensed Consolidated Statements of Operations as follows (in thousands):
 
Three months ended September 30,
 
Nine months ended September 30,
 
Realized
 
Unrealized
 
Realized
 
Unrealized
2018
 
 
 
 
 
 
 
Loss on commodity derivatives, net
$
(122
)
 
$
(112
)
 
$
(178
)
 
$
(352
)
Interest expense, net of capitalized interest
341

 
33

 
2,976

 
6,123

Direct operating expenses
(247
)
 
—

 
(797
)
 
—

 

 

 

 

2017
 
 
 
 
 
 
 
Loss on commodity derivatives, net
$
(51
)
 
$
(546
)
 
$
465

 
$
(498
)
Interest expense, net of capitalized interest
51

 
221

 
(19
)
 
(1,790
)
Direct operating expenses
(278
)
 
—

 
(753
)
 
—



23
American Midstream Partners, LP and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



Fair Value                     
Financial Instruments Not Measured at Fair Value on a Recurring Basis - The following table presents the carrying value and estimated fair value of our financial instruments that are not measured at fair value on a recurring basis as of September 30, 2018 and December 31, 2017. Short-term and long-term debt are recorded at amortized cost in the Condensed Consolidated Balance Sheets.
 
 
 
 
September 30, 2018
 
December 31, 2017
 
 
 
 
Carrying Amount
 
Fair Value
 
Carrying Amount
 
Fair Value
Non-Derivatives
 
 
 
 
 
 
 
 
 
Liabilities
 
 
 
 
 
 
 
 
 
 
8.5% Senior Unsecured Notes
 
$
418,989

 
$
427,154

 
$
418,421

 
$
437,062

 
 
3.77% Senior Secured Notes
 
55,342

 
49,792

 
56,005

 
53,845

 
 
3.97% Trans-Union Secured Senior Notes
 
30,390

 
27,118

 
31,692

 
30,221

 
 
Total
 
$
504,721

 
$
504,064

 
$
506,118

 
$
521,128


The fair value of debt instruments are valued using a market approach based on quoted prices for similar instruments traded in active markets and are classified as Level 2 within the fair value hierarchy. All financial instruments in the table above are classified as Level 2. The carrying value of amounts outstanding under the Credit Agreement approximates the related fair value, as interest charges vary with market rate conditions.

The carrying value of all non-derivative financial instruments included in current assets (including cash, cash equivalents, restricted cash and accounts receivable) and current liabilities (including accounts payable but excluding short-term debt) approximates the applicable fair value due to the short maturity of those instruments.

(8) Property, Plant and Equipment

Property, plant and equipment, net, consists of the following (in thousands):
 
Useful Life
(in years)
 
September 30,
2018
 
December 31,
2017
Land
Infinite
 
$
14,635

 
$
18,145

Construction in progress
N/A
 
54,584

 
55,622

Buildings and improvements
4 to 40
 
10,116

 
16,235

Transportation equipment
5 to 15
 
22,527

 
22,697

Processing and treating plants
8 to 40
 
123,901

 
123,138

Pipelines, compressors and right-of-way
3 to 40
 
1,022,034

 
974,301

Storage
3 to 40
 
44,418

 
146,105

Equipment
3 to 31
 
62,062

 
80,220

Total property, plant and equipment
 
 
1,354,277

 
1,436,463

Accumulated depreciation
 
 
(360,357
)
 
(340,878
)
Property, plant and equipment, net
 
 
$
993,920

 
$
1,095,585


At September 30, 2018 and December 31, 2017, gross property, plant and equipment included $376.4 million and $367.6 million, respectively, related to FERC regulated interstate and intrastate assets.

Depreciation expense totaled $17.6 million and $20.1 million for the three months ended September 30, 2018 and 2017, respectively, and $54.4 million and $56.9 million for the nine months ended September 30, 2018 and 2017, respectively. Capitalized interest was $0.7 million and $0.5 million for the three months ended September 30, 2018 and 2017, respectively, and $2.2 million and $2.0 million for the nine months ended September 30, 2018 and 2017, respectively.


24
American Midstream Partners, LP and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



(9) Goodwill and Intangible Assets

Goodwill consists of the following (in thousands):
 
September 30, 2018
 
December 31, 2017
Liquid Pipelines and Services
$
35,708

 
$
35,708

Terminalling Services
11,043

 
88,466

Offshore Pipelines and Services
4,972

 
4,692

Total
$
51,723

 
$
128,866


The decline in goodwill in our Terminalling Services segment relates to Marine Products which were sold on July 31, 2018 and Refined Products which were classified as held for sale at September 30, 2018. See Note 4 - Acquisitions and Dispositions for further discussion.

Intangible assets, net, consist of the following (in thousands):
 
September 30, 2018
 
Gross Carrying Amount
 
Accumulated Amortization
 
Net Carrying Amount
Customer relationships
$
64,745

 
$
(16,290
)
 
$
48,455

Customer contracts
94,693

 
(51,910
)
 
42,783

Dedicated acreage
42,546

 
(7,248
)
 
35,298

Collaborative arrangements
11,884

 
(2,051
)
 
9,833

Noncompete agreements
1,064

 
(1,064
)
 
—

Other
197

 
(29
)
 
168

Total
$
215,129

 
$
(78,592
)
 
$
136,537

 
 
 
 
 
 
 
December 31, 2017
 
Gross Carrying Amount
 
Accumulated Amortization
 
Net Carrying Amount
Customer relationships
$
110,483

 
$
(29,965
)
 
$
80,518

Customer contracts
94,692

 
(48,173
)
 
46,519

Dedicated acreage
42,547

 
(6,216
)
 
36,331

Collaborative arrangements
11,884

 
(1,415
)
 
10,469

Noncompete agreements
1,064

 
(1,064
)
 
—

Other
198

 
(25
)
 
173

Total
$
260,868

 
$
(86,858
)
 
$
174,010


These intangible assets have definite lives and are subject to amortization on a straight-line basis over their economic lives, currently ranging from approximately 5 years to 30 years.

Amortization expense related to our intangible assets totaled $2.5 million and $6.4 million for the three months ended September 30, 2018 and 2017, respectively, and $7.8 million and $20.6 million for the nine months ended September 30, 2018 and 2017, respectively. The estimated aggregate annual amortization expected to be recognized for the remainder of 2018 and each of the four succeeding fiscal years is $2.5 million, $10.2 million, $10.2 million, $10.2 million and $9.3 million, respectively.


25
American Midstream Partners, LP and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



(10) Investments in Unconsolidated Affiliates

The following table presents the activity in our equity method investments in unconsolidated affiliates (in thousands):
 
Delta House (1)
 
Emerald Transactions
 
 
 
 
 
FPS(2,4)
 
OGL(2,4)
 
Destin(4)
 
Tri-States(3)
 
Okeanos(4)
 
Wilprise(3)
 
Cayenne JV(3)
 
Total
Ownership % - December 31, 2017
35.7%
 
35.7%
 
66.7%
 
16.7%
 
66.7%
 
25.3%
 
50.0%
 
 
Ownership % - September 30, 2018
35.7%
 
35.7%
 
66.7%
 
16.7%
 
66.7%
 
25.3%
 
50.0%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balances at December 31, 2017
$
90,412

 
$
46,932

 
$
124,245

 
$
53,057

 
$
22,445

 
$
4,689

 
$
6,654

 
$
348,434

   Earnings in unconsolidated affiliates
14,892

 
8,204

 
8,543

 
2,983

 
8,225

 
664

 
4,231

 
47,742

   Contributions
847

 
6

 
—

 
—

 
—

 
—

 
4,020

 
4,873

   Distributions
(11,256
)
 
(12,076
)
 
(21,980
)
 
(4,701
)
 
(11,499
)
 
(848
)
 
(1,900
)
 
(64,260
)
Balances at September 30, 2018
$
94,895

 
$
43,066

 
$
110,808

 
$
51,339

 
$
19,171

 
$
4,505

 
$
13,005

 
$
336,789

___________________________________________________ 
(1) Represents direct and indirect ownership interests in Class A units and common units.
(2) FPS denotes Floating Production System LLC whereas OGL denotes Oil & Gas Lateral LLC.
(3) Included in our Liquid Pipelines and Services segment.
(4) Included in our Offshore Pipelines and Services segment.
 
The following tables present the summarized combined financial information for our equity investments (amounts represent 100% of investee financial information) (in thousands):
Balance Sheets:
 
September 30, 2018
 
December 31, 2017
Current assets
 
$
88,702

 
$
80,405

Non-current assets
 
1,257,275

 
1,288,862

Current liabilities
 
86,821

 
130,904

Non-current liabilities
 
470,391

 
436,584

 
 
Three months ended September 30,
 
Nine months ended
September 30,
Statements of Operations:
 
2018
 
2017(1)
 
2018
 
2017(1)
Revenue
 
$
85,504

 
$
105,621

 
$
194,193

 
$
308,987

Operating expenses
 
6,665

 
24,168

 
21,172

 
76,145

Net income
 
63,078

 
76,650

 
123,226

 
220,617

_________________________
(1) In August 2017, we acquired 100% of the interest in POGS, the outstanding interests in one of our equity investments. We have consolidated this entity from the acquisition date. See Note 4 - Acquisitions and Dispositions for further discussion.


26
American Midstream Partners, LP and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



(11) Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities consists of the following (in thousands):
 
 
September 30, 2018
 
December 31, 2017
Capital expenditures
 
$
9,069

 
$
10,721

Accrued interest
 
14,290

 
3,190

Convertible preferred unit distributions
 
8,354

 
—

Current portion of asset retirement obligation
 
3,764

 
6,416

Additional Blackwater acquisition consideration (see Note 19)
 
5,000

 
5,000

Taxes payable
 
42,350

 
5,263

Due to related parties
 
9,508

 
6,609

Royalties, gas imbalance and leases payables
 
5,734

 
7,905

Professional fees
 
4,587

 
1,848

Other
 
13,485

 
21,902

   Total accrued expenses and other current liabilities
 
$
116,141


$
68,854


The increase in taxes payable from period to period is primarily due to income taxes associated with our sale of Marine Products in the third quarter of 2018. See further discussion of the Marine Products sale in Note 4 - Acquisitions and Dispositions.

(12) Asset Retirement Obligations

We record a liability for the fair value of asset retirement obligations and conditional asset retirement obligations (collectively referred to as “AROs”) that we can reasonably estimate, on a discounted basis, in the period in which the liability is incurred. Generally, the fair value of the liability is calculated using discounted cash flow techniques and based on internal estimates and assumptions related to (i) future retirement costs, (ii) future inflation rates and (iii) credit adjusted risk-free interest rates. Significant increases or decreases in the assumptions would result in a significant change to the fair value measurement.

Certain assets related to our Offshore Pipelines and Services segment have regulatory obligations to perform remediation, and in some instances dismantlement and removal activities, when the assets are abandoned. These AROs include varying levels of activity including disconnecting inactive assets from active assets, cleaning and purging assets, and in some cases, completely removing the assets and returning the land to its original state. These assets have been in existence for many years and with regular maintenance will continue to be in service for many years to come. It is not possible to predict when demand for these transmission services will cease, however, we do not believe that such demand will cease for the foreseeable future. The majority of the current portion of our AROs, which is included in Accrued expenses and other current liabilities in our Condensed Consolidated Balance Sheets, is related to the retirement of the Midla pipeline. For further discussion related to the retirement of the Midla Pipeline, see the Note 14 - Debt Obligations in the 2017 Form 10-K.

27
American Midstream Partners, LP and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)




The following table presents activity in our asset retirement obligations for the nine months ended September 30, 2018 (in thousands):
Current portion
 
$
6,416

Non-current asset retirement obligation
 
66,194

Balances at December 31, 2017
 
72,610

Additions
 
260

Revision in estimate
 
(216
)
Disposals
 
(516
)
Expenditures
 
(3,149
)
Accretion expense
 
2,865

Balances at September 30, 2018
 
71,854

Current portion
 
(3,764
)
Non-current asset retirement obligation
 
$
68,090


We are required to establish security against potential obligations relating to the abandonment of certain transmission assets that may be imposed on the previous owner by applicable regulatory authorities. We have deposited $5.0 million with a third party to secure our performance on these potential obligations. Those deposits, in our Condensed Consolidated Balance Sheets as of September 30, 2018 and December 31, 2017, are included in Restricted cash-long term.

(13) Debt Obligations

Our outstanding debt consists of the following (in thousands):
 
September 30, 2018
 
December 31, 2017
Revolving credit facility
$
600,000

 
$
697,900

8.50% Senior unsecured notes, due 2021
425,000

 
425,000

3.77% Senior secured notes, due 2031 (non-recourse)
57,531

 
58,324

3.97% Senior secured notes, due 2032 (non-recourse)
30,709

 
32,025

Other debt
—

 
4,989

Total debt obligations
1,113,240

 
1,218,238

Unamortized debt issuance costs
(8,519
)
 
(9,231
)
Total debt
1,104,721

 
1,209,007

Current portion of long-term debt
(603,502
)
 
(7,551
)
Long term debt
$
501,219

 
$
1,201,456


AMID Revolving Credit Agreement
On June 29, 2018, we amended our revolving credit facility agreement, dated March 8, 2017 (the “Original Credit Agreement”), by entering into the First Amendment to Second Amended and Restated Credit Agreement (the “Amendment” and, the Original Credit Agreement as amended by the Amendment, the “Credit Agreement”; capitalized terms used but not defined herein shall have the meanings assigned thereto in the Credit Agreement) with a syndicate of lenders and Bank of America, N.A., as administrative agent.
The Credit Agreement matures on September 5, 2019, and is therefore being presented as a current liability in our Condensed Consolidated Balance Sheet as of September 30, 2018.
The Amendment adds a required prepayment in the amount equal to 100% of the net cash proceeds received from the Marine Products and Refined Products asset sales and any other disposition greater than $5 million as defined below. On July 31, 2018, we completed the sale of our Marine Products terminals. Net proceeds from this disposition were approximately $208.6 million, exclusive of $5.7 million in advisory fees and other costs, and were used to pay down the Credit Agreement.

28
American Midstream Partners, LP and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



The Amendment also amends our borrowing capacity as follows:
•
upon consummation of the Marine Products sale, the aggregate commitment under the Credit Agreement was automatically reduced by $200.0 million, such that total borrowing capacity under the Credit Agreement is $700.0 million as of September 30, 2018;
•
upon consummation of the Refined Products sale, the aggregate commitment under the Credit Agreement shall be automatically reduced by 50% of the net cash proceeds of such disposition; and
•
upon consummation of any disposition greater than $15 million, the aggregate commitment under the Credit Agreement shall be automatically reduced by 25% of the net cash proceeds of such disposition.

The Amendment adds a new pricing tier of LIBOR + 3.50% when Consolidated Total Leverage Ratio equals or exceeds 5.0:1.0. The Credit Agreement includes the following financial covenants, as amended by the Amendment and defined in the Credit Agreement, which financial covenants will be tested on a quarterly basis, for the fiscal quarter then ending:
 
Minimum Consolidated Interest Coverage Ratio
 
Maximum Consolidated Total Leverage Ratio
 
Maximum Consolidated Secured Leverage Ratio
June 30, 2018
2.50:1.00
 
6.15:1.00
 
4.00:1.00
September 30, 2018
2.00:1.00
 
6.25:1.00
 
3.75:1.00
December 31, 2018
1.75:1.00
 
5.50:1.00
 
3.50:1.00
March 31, 2019
1.75:1.00
 
5.00:1.00 (1)
 
3.50:1.00
June 30, 2019 and thereafter
2.00:1.00
 
5.00:1.00 (1)
 
3.50:1.00
___________________________
(1) 5.50:1.00 during a Specified Acquisition Period

As of September 30, 2018, we were in compliance with our Credit Agreement financial covenants, including those shown below:
Ratio
 
 
 
Actual
Consolidated Interest Coverage Ratio
 

 
2.37
Consolidated Total Leverage Ratio
 

 
5.65
Consolidated Secured Leverage Ratio
 

 
3.31

As of September 30, 2018, we had $600 million of borrowings, $39.0 million of letters of credit outstanding and $61.0 million of remaining borrowing capacity under the Credit Agreement, of which $41.0 million is currently available. For the nine months ended September 30, 2018 and 2017, the weighted average interest rate, excluding the impact of interest rate swaps, on borrowings under this facility was 6.23% and 4.85%, respectively.

Senior Unsecured Notes

Our senior unsecured notes include an optional redemption whereby we may elect to redeem the notes, in whole or in part from time-to-time, for a premium. On and after December 15, 2018, we may redeem all or a part of the 8.50% Senior Notes, at the redemption prices set forth below, plus accrued and unpaid interest, if redeemed during the twelve-month period beginning on December 15 of the years indicated below:
Year
Percentage
2018
104.250%
2019
102.125%
2020 and thereafter
100.000%

See Note 14 - Debt Obligations in our 2017 Form 10-K for additional information relating to our outstanding debt.


29
American Midstream Partners, LP and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



Going Concern Assessment and Management’s Plans

Pursuant to FASB ASC 205-40, we are required to assess our ability to continue as a going concern for a period of one year from the date of the issuance of these financial statements. Substantial doubt about an entity’s ability to continue as a going concern exists when relevant conditions and events, considered in the aggregate, indicate that it is probable that the entity will be unable to meet its obligations as they become due within one year from the financial statement issuance date. As discussed above in “AMID Revolving Credit Agreement”, our Credit Agreement matures on September 5, 2019 and has not been renewed as of the date of the issuance of these financial statements. 

As discussed in Note 19 - Related Party Transactions, on September 28, 2018, the Board of Directors of our General Partner received a non-binding proposal from Magnolia, an affiliate of ArcLight to acquire the common units that it does not already own. The transaction is currently in the due diligence phase and requires approval of the Conflicts Committee of the Board of Directors. As a result of this ongoing process, management has deferred finalization of a renewal of the Credit Agreement.

While the Partnership intends to renew or extend the terms of its Credit Agreement, until such time as we have executed an agreement to refinance or extend the maturity of our Credit Agreement, we cannot conclude that it is probable we will do so, and accordingly, this raises substantial doubt about our ability to continue as a going concern.

(14) Convertible Preferred Units

Our convertible preferred units consist of the following (in thousands):
 
Series A
 
Series C
 
Total
 
Units
 
$
 
Units
 
$
 
$
December 31, 2017
10,719

 
$
191,798

 
8,965

 
$
125,382

 
$
317,180

Paid in kind unit distributions
291

 
—

 
277

 
—

 
—

September 30, 2018
11,010

 
$
191,798

 
9,242

 
$
125,382

 
$
317,180


Affiliates of our General Partner hold and participate in quarterly distributions on our convertible preferred units, with such distributions being made in cash, paid-in-kind units or a combination thereof at the election of the Board of Directors of our General Partner (the “Board”). The convertible preferred unitholders have the right to receive cumulative distributions in the same priority and prior to any other distributions made in respect of any other partnership interests.

To the extent that any portion of a quarterly distribution on our convertible preferred units to be paid in cash exceeds the amount of cash available for such distribution, the amount of cash available will be paid to our convertible preferred unitholders on a pro rata basis while the difference between the distribution and the available cash will accrue interest until paid.

Series A-1 Convertible Preferred Units

On April 15, 2013, the Partnership, our General Partner and AIM Midstream Holdings LLC entered into agreements with HPIP, pursuant to which HPIP acquired 90% of our General Partner and all of our subordinated units from AIM Midstream Holdings, LLC and contributed the High Point System, our 574 mile transmission system located in southeast Louisiana and the Gulf of Mexico, and $15.0 million in cash to us in exchange for 5,142,857 of our Series A-1 Units.

The holders of Series A-1 Units receive quarterly distributions prior to any distributions to our common unitholders. The quarterly distributions on the Series A-1 Units are equal to the greater of $0.4125 per unit or the declared distribution to common unitholders. The Series A-1 Units may be converted into common units, subject to customary anti-dilutive adjustments, at the option of the unitholders at any time. As of September 30, 2018, the conversion price was $15.10 and the conversion ratio is 1:1.1589.

30
American Midstream Partners, LP and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)




Series A-2 Convertible Preferred Units

On March 30, 2015 and June 30, 2015, we entered into two Series A-2 Convertible Preferred Unit Purchase Agreements with Magnolia Infrastructure Partners, an affiliate of HPIP pursuant to which we issued, in separate private placements, newly-designated Series A-2 Units (the “Series A-2 Units”) representing limited partnership interests in the Partnership. As a result, the Partnership issued a total of 2,571,430 Series A-2 Units for approximately $45 million in aggregate proceeds during the year ended December 31, 2015. The Series A-2 Units will participate in distributions of the Partnership along with common units in a manner identical to the existing Series A-1 Units (together with the Series A-2 Units, the “Series A Units”), with such distributions being made in cash or with paid-in-kind Series A Units at the election of the Board.

On July 27, 2015, we amended our Partnership Agreement to grant us the right (the “Call Right”) to require the holders of the Series A-2 Units to sell, assign and transfer all or a portion of the then-outstanding Series A-2 Units to us for a purchase price of $17.50 per Series A-2 Unit (subject to appropriate adjustment for any equity distribution, subdivision or combination of equity interests in the Partnership). We may exercise the Call Right at any time, in connection with our or our affiliates’ acquisition of assets or equity from ArcLight Energy Partners Fund V, L.P., or one of its affiliates, for a purchase price in excess of $100.0 million. We may not exercise the Call Right with respect to any Series A-2 Units that a holder has elected to convert into common units on or prior to the date we have provided notice of our intent to exercise the Call Right, and we may also not exercise the Call Right if doing so would result in a default under any of our or our affiliates’ financing agreements or obligations. As of September 30, 2018, the conversion price was $15.10 and the conversion ratio is 1:1.1589.

Series C Convertible Preferred Units

On April 25, 2016, we issued 8,571,429 Series C Units to an ArcLight affiliate in connection with the purchase of membership interests in certain midstream entities.

The Series C Units have voting rights that are identical to the voting rights of the common units and will vote with the common units as a single class on an as-converted basis, with each Series C Unit initially entitled to one vote for each common unit into which such Series C Unit is convertible. The Series C Units also have separate class voting rights on any matter, including a merger, consolidation or business combination, that adversely affects, amends or modifies any of the rights, preferences, privileges or terms of the Series C Units. The Series C Units are convertible in whole or in part into common units at any time. The number of common units into which a Series C Unit is convertible will be an amount equal to the sum of $14.00 plus all accrued and accumulated but unpaid distributions, divided by the conversion price. The sale of the Series C Units was exempt from registration under the Securities Act of 1933, as amended (the “Securities Act”) pursuant to Rule 4(a)(2) under the Securities Act.

In the event that we issue, sell or grant any common units or convertible securities at an indicative per common unit price that is less than $14.00 per common unit (subject to customary anti-dilution adjustments), then the conversion price will be adjusted according to a formula to provide for an increase in the number of common units into which Series C Units are convertible. As of September 30, 2018, the conversion price was $13.27 and the conversion ratio is 1:1.0550.

In connection with the issuance of the Series C Units, we issued the holders a warrant to purchase up to 800,000 common units at an exercise price of $7.25 per common unit (the “Series C Warrant”). The Series C Warrant is subject to standard anti-dilution adjustments and is exercisable for a period of seven years.

The fair value of the Series C Warrant was determined using a market approach that utilized significant inputs which are not observable in the market and thus represent a Level 3 measurement as defined by ASC 820, Fair Value Measurements and Disclosures. The estimated fair value of $4.41 per warrant unit was determined using a Black-Scholes model and the following significant assumptions: (i) a dividend yield of 18%, (ii) common unit volatility of 42% and (iii) the seven-year term of the warrant to arrive at an aggregate fair value of $4.5 million.

As conversion is at the option of the holder and redemption is contingent upon a future event, which is outside the control of the Partnership, the Series A-1, A-2 and C Units have been classified as mezzanine equity in the Condensed Consolidated Balance Sheets.

(15) Partners’ Capital

Our capital accounts are comprised of 1.3% notional General Partner interests and 98.7% limited partner interests as of September 30, 2018. Our limited partners have limited rights of ownership as provided for under our Partnership Agreement and the right to

31
American Midstream Partners, LP and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



participate in our distributions. Our General Partner manages our operations and participates in our distributions, including certain incentive distributions pursuant to the incentive distribution rights that are non-voting limited partner interests held by our General Partner. Pursuant to our Partnership Agreement, our General Partner participates in losses and distributions based on its interest. The General Partner’s participation in the allocation of losses and distributions is not limited, and therefore, such participation can result in a deficit to its capital account. As such, allocation of losses and distributions, including distributions for previous transactions between entities under common control, has resulted in a deficit to the General Partner’s capital account included in our Condensed Consolidated Balance Sheets.

Outstanding Units

The following table presents unit activity (in thousands):
 
 
General
Partner Units
 
Limited Partner Units
Balances at December 31, 2017
 
965

 
52,711

LTIP units vesting
 
—

 
279

Issuance of GP units
 
16

 
—

Balances at September 30, 2018
 
981

 
52,990


General Partner Units

In order for our General Partner to maintain its ownership percentage in us, our General Partner paid $0.1 million and $3.9 million for the issuance of 16,326 and 272,811 additional notional General Partner units for the nine months ended September 30, 2018 and 2017, respectively.

Distributions

Preferred Units

Under the Partnership’s agreement of limited partnership, the Partnership is obligated to pay cumulative distributions each quarter on the Series A preferred units (which consists of the Series A-1 and A-2) and Series C preferred units in an amount equal to the greater of $0.4125, or the distribution declared on the common units. As such, the distributions are accrued at each quarter-end (the “reporting quarter”) based on the subsequent board approval of the distribution method (in the “subsequent quarter”), which may be settled in cash or paid-in-kind (“PIK”) units. To the extent the distribution is to be settled in cash, the distributions are accrued in the reporting quarter and the cash is paid in the subsequent quarter. To the extent the distribution is to be settled in PIK units, the distribution is recognized directly to equity in the reporting quarter.

Limited Partner Units (Common Units)

The following table reflects distributions declared and paid through September 30, 2018 (in thousands, except per unit data):
Date Declared
 
Distribution Payment Date
 
Period for which Distribution Relates
 
General Partner
 
Limited Partner
 
Total Cash Distributions
 
Cash Distributions Per Common Unit
July 27, 2018
 
August 14, 2018
 
Second Quarter of 2018
 
$
72

 
$
5,463

 
$
5,535

 
$
0.1031

April 26, 2018
 
May 15, 2018
 
First Quarter of 2018
 
$
287

 
$
21,853

 
$
22,140

 
$
0.4125

January 26, 2018
 
February 14, 2018
 
Fourth Quarter of 2017
 
$
290

 
$
21,745

 
$
22,035

 
$
0.4125


On October 25, 2018, we announced that the Board of Directors of our general partner declared a quarterly cash distribution of $0.1031 per common unit, which represents the distribution for the third quarter of 2018 and will be paid in the fourth quarter of 2018. See Note 22 - Subsequent Events for more information.

32
American Midstream Partners, LP and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



The following table details cash distributions paid or accrued as of, and for, the three and nine months ended September 30, 2018 (in thousands):
 
 
Three months ended September 30,
 
Nine months ended September 30,
 
 
2018
 
2017
 
2018
 
2017
Series A Units
 
 
 
 
 
 
 
 
Cash paid
 
$
4,542

 
$
2,145

 
$
9,084

 
$
6,790

Accrued (1)
 
4,542

 
4,105

 
4,542

 
4,105

Paid-in-kind units
 
—

 
1,924

 
3,767

 
6,838

 
 
 
 
 
 
 
 
 
Series C Units
 
 
 
 
 
 
 
 
Cash paid
 
$
3,812

 
$
3,627

 
$
7,624

 
$
10,880

Accrued (1)
 
3,812

 
4,150

 
3,812

 
4,150

Paid-in-kind units
 
—

 
—

 
4,309

 
—

 
 
 
 
 
 
 
 
 
Series D Units
 
 
 
 
 
 
 
 
Cash paid
 
$
—

 
$
963

 
$
—

 
$
2,888

 
 
 
 
 
 
 
 
 
Limited Partners’ Units(2)
 
 
 
 
 
 
 
 
Cash paid
 
$
5,463

 
$
21,345

 
$
49,061

 
$
67,648

 
 
 
 
 
 
 
 
 
General Partner’s Units(3)
 
 
 
 
 
 
 
 
Cash paid
 
$
72

 
$
277

 
$
649

 
$
645

 
 
 
 
 
 
 
 
 
Summary
 
 
 
 
 
 
 
 
Cash paid
 
$
13,889

 
$
28,357

 
$
66,418

 
$
88,851

Accrued (1)
 
8,354

 
8,255

 
8,354

 
8,255

Paid-in-kind units
 
—

 
1,924

 
8,076

 
6,838

__________________________
(1) Can be paid in either Cash, PIK or a combination of both. PIK payments on the Series C Units require consent of the holder.
(2) Limited Partner distributions do not include $5.5 million and $21.7 million of distributions declared in the fourth quarter which relate to the third quarter of 2018 and 2017, respectively.
(3) General Partner distributions do not include $0.1 million and $0.3 million of distributions declared in the fourth quarter which relate to the third quarter of 2018 and 2017, respectively.  

Fair Value Determination of PIK of Preferred Units

The fair value of the PIK distributions was determined using the market and income approaches, requiring significant inputs that are not observable in the market and thus represent a Level 3 measurement. Under the income approach, the fair value estimates for all periods presented were based on (i) present value of estimated future contracted distributions, (ii) option values ranging from $0.31 per unit to $2.05 per unit using a Black-Scholes model, (iii) assumed discount rates ranging from 5.80% to 6.23%, and (iv) assumed growth rates of 1.0%.

(16) Net Income (Loss) per Limited Partner Unit

As discussed in Note 4 - Acquisitions and Dispositions, the JPE Merger on March 8, 2017 was a combination between entities under common control. As a result, prior periods were retrospectively adjusted to furnish comparative information. Accordingly, the prior period earnings combining both entities were allocated among our General Partner and common unitholders assuming JPE units were converted into our common units in the comparative historical periods.

33
American Midstream Partners, LP and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



The calculation of basic and diluted limited partners' net income (loss) per common unit is summarized below (in thousands, except per unit amounts):
 
Three months ended September 30,
 
Nine months ended September 30,
 
2018
 
2017
 
2018
 
2017
Income (loss) from continuing operations
$
38,183

 
$
11,806

 
$
7,067

 
$
(42,266
)
Net income attributable to noncontrolling interests
(25
)
 
(621
)
 
(83
)
 
(3,386
)
Net income (loss) from continuing operations attributable to the Partnership
38,158

 
11,185

 
6,984

 
(45,652
)
 
 
 
 
 
 
 
 
Distributions on Series A Units
(4,542
)
 
(4,105
)
 
(13,626
)
 
(12,472
)
Distributions on Series C Units
(3,812
)
 
(4,150
)
 
(11,437
)
 
(11,403
)
Distributions on Series D Units
—

 
—

 
—

 
(1,925
)
General Partner's distribution
(73
)
 
(287
)
 
(434
)
 
(763
)
General Partner's share in undistributed (loss) income
(303
)
 
210

 
683

 
1,729

Income (loss) from continuing operations attributable to Limited Partners
29,428

 
2,853

 
(17,830
)
 
(70,486
)
Income from discontinued operations, net of tax
—

 
44,696

 
—

 
42,185

Net income (loss) attributable to Limited Partners
$
29,428

 
$
47,549

 
$
(17,830
)
 
$
(28,301
)
 
 
 
 
 
 
 
 
Weighted average number of common units outstanding:
 
 
 
 
 
 
 
Basic
52,984

 
52,021

 
52,917

 
52,021

Potentially dilutive common unit equivalents(1)
22,541

 
—

 
—

 
—

Diluted
75,525

 
52,021

 
52,917

 
52,021

 
 
 
 
 
 
 
 
Limited Partners' net income (loss) per common unit - Basic and Diluted
 
 
 
 
 
 
 
Basic:
 
 
 
 
 
 
 
Income (loss) from continuing operations
$
0.56

 
$
0.05

 
$
(0.34
)
 
$
(1.35
)
Income (loss) from discontinued operations
—

 
0.86

 
—

 
0.81

Net income (loss)
$
0.56

 
$
0.91

 
$
(0.34
)
 
$
(0.54
)
 
 
 
 
 
 
 
 
Diluted:
 
 
 
 
 
 
 
Income (loss) from continuing operations
$
0.39

 
$
0.05

 
$
(0.34
)
 
$
(1.35
)
Income (loss) from discontinued operations
—

 
0.86

 
—

 
0.81

Net income (loss)
$
0.39

 
$
0.91

 
$
(0.34
)
 
$
(0.54
)
_____________________________________
(1) Potential common unit equivalents were antidilutive for the three months ended September 30, 2017 and for the nine months ended September 30, 2018 and 2017. As a result, 24.9 million potential common unit equivalents for the three months ended September 30, 2017 and 23.4 million potential common unit equivalents and 24.8 million potential common unit equivalents for the nine months ended September 30, 2018 and 2017, respectively, have been excluded from the determination of diluted limited partners' net income (loss) per common unit.

(17) Incentive Compensation

All equity-based awards issued under the long-term incentive plan (“LTIP”) consist of either restricted (“RSUs”) or performance-based (“PSUs”) phantom units, or option grants. Future awards may be granted at the discretion of the Compensation Committee of the Board and subject to approval by the Board.

As of September 30, 2018, there were 3,763,750 common units available for future grants under the LTIP.


34
American Midstream Partners, LP and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



The following table presents the components of equity-based compensation expense for the three and nine months ended September 30, 2018 and 2017 (in thousands):
 
Three months ended September 30,
 
Nine months ended September 30,
 
2018
 
2017
 
2018
 
2017
Grant Type:
 
 
 
 
 
 
 
RSU
$
1,083

 
$
815

 
$
2,616

 
$
6,010

PSU
237

 
—

 
867

 
—

Options
15

 
19

 
46

 
57

Total
$
1,335

 
$
834

 
$
3,529

 
$
6,067

 
 
 
 
 
 
 
 

During the nine months ended September 30, 2018, we granted 818,357 RSU’s at a weighted-average fair value per unit of $8.54, vested 351,166 RSU’s at a weighted-average fair value per unit of $6.26 and forfeited 356,479 RSU’s at a weighted-average fair value per unit of $6.62. Unrecognized compensation expense related to RSU’s was $8.6 million at September 30, 2018.

During the nine months ended September 30, 2018, we did not grant any options or performance-based awards under our LTIP. Unrecognized compensation expense related to options and performance-based awards was $0.1 million and $4.9 million, respectively, at September 30, 2018.

Defined Contribution Plan

For the three and nine months ended September 30, 2018 and 2017, compensation expense associated with our 401(k)-defined contribution plan’s employer matching was $0.6 million and $0.5 million, respectively, and $1.8 million and $1.4 million, respectively. There was no change to the defined contribution plan.

Cash Retention Plan

On September 2, 2018, the Partnership implemented a long-term cash retention award for all employees holding RSU’s under the Partnership’s LTIP. At each future vesting date of time-based unvested phantom units outstanding on July 28, a cash award in the amount of $6.00 per phantom unit will also be earned.  Holders of PSU’s were not included in the cash retention award. The expense associated with this award will be recognized over the service period.  During the three months ended September 30, 2018, approximately $0.9 million related to this plan was included in Corporate expenses in the Condensed Consolidated Statements of Operations.

(18) Commitments and Contingencies

Legal Proceedings

We are not currently party to any pending litigation or governmental proceedings, other than ordinary routine litigation incidental to our business. While the ultimate impact of any proceedings cannot be predicted with certainty, our management believes that the resolution of any of our pending proceedings will not have a material adverse effect on our financial condition or results of operations.

Environmental Matters

We are subject to federal and state laws and regulations relating to the protection of the environment. Environmental risk is inherent in our operations and we could, at times, be subject to environmental cleanup and enforcement actions. We attempt to manage this environmental risk through appropriate environmental policies and practices to minimize any impact our operations may have on the environment.

(19) Related Party Transactions

To the extent applicable, our discussion below includes the nature of our relationship and activities that we had with our related parties, as defined by ASC 850, Related Party Disclosures, for the nine months ended September 30, 2018 and 2017 and the

35
American Midstream Partners, LP and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



outstanding balances as of September 30, 2018 and December 31, 2017. Balances associated with our investments in unconsolidated affiliates are disclosed in Note 10 - Investments in unconsolidated affiliates.

Blackwater Midstream Holdings, LLC

In December 2013, we acquired Blackwater Midstream Holdings, LLC (“Blackwater”) from an affiliate of ArcLight. The acquisition agreement included a provision whereby an ArcLight affiliate would be entitled to an additional $5.0 million of merger consideration based on Blackwater meeting certain operating targets. At September 30, 2018, we have $5.0 million accrued to the ArcLight affiliate which is included in Accrued expense and other current liabilities in the accompanying Condensed Consolidated Balance Sheets. Final resolution of the merger consideration will be determined in the fourth quarter of 2018 in connection with the sale of Marine Products.

Republic Midstream, LLC

Republic Midstream, LLC (“Republic”), is an entity owned by ArcLight to which we historically charged a monthly fee of approximately $0.1 million. The services agreement with Republic terminated according to its terms in September 2017 and services are no longer provided to Republic. As of December 31, 2017, we had an accounts receivable balance due from Republic of $0.8 million which is included in Other current assets in the accompanying Condensed Consolidated Balance Sheets.

Magnolia Infrastructure Holdings, LLC

On September 28, 2018, the Board of Directors of our General Partner received a non-binding proposal from Magnolia, pursuant to which Magnolia would acquire all common units of the Partnership that Magnolia and its affiliates do not already own in exchange for $6.10 per common unit. If approved, it is currently expected that the transaction would be effected through a merger of the Partnership with a subsidiary of ArcLight. The transaction, as proposed, is subject to a number of contingencies, including Magnolia's completion of due diligence, the approval of the Conflicts Committee, the approval by holders of a majority of the outstanding common units of the Partnership and the satisfaction of any conditions to the consummation of a transaction set forth in any definitive agreement concerning the transaction. There can be no assurance that definitive agreement will be executed or that any transaction will materialize.

General Partner

During the nine months ended September 30, 2018, our General Partner paid $31.8 million related to Corporate overhead support which was presented as part of the contribution line item in Cash flows from financing activities in our Condensed Consolidated Statements of Cash Flows. As of September 30, 2018, and December 31, 2017, we had $7.9 million and $6.5 million, respectively, of accounts payable due to our General Partner, which has been recorded in Accrued expenses and other current liabilities and relates primarily to compensation. This payable/receivable is generally settled on a quarterly basis related to the foregoing transactions.

On March 11, 2018, the Partnership and Magnolia entered into a Capital Contribution Agreement (the “Capital Contribution Agreement”) to provide additional capital and overhead support to us during the first three quarters of 2018 in connection with temporary curtailment of production flows at Delta House. Pursuant to the Capital Contribution Agreement, Magnolia has agreed to provide quarterly capital contributions, in an amount to be agreed, up to the difference between the actual cash distribution received by us on account of our interest in Delta House and the quarterly cash distribution expected to be received had the production flows to Delta House not been curtailed. In accordance with this agreement, Magnolia paid a capital contribution of $9.4 million in the second quarter of 2018. Subsequent to June 30, 2018, in accordance with this agreement, Magnolia paid a capital contribution of $8.3 million in August 2018. Both of these capital contributions are included in the $31.8 million related to Corporate overhead support discussed above.

Destin and Okeanos

On November 1, 2016, we became operator of the Destin and Okeanos pipelines and entered into operating and administrative management agreements under which our affiliates pay a monthly fee for general and administrative services provided by us. In addition, the affiliates reimburse us for certain transition related expenses. For the nine months ended September 30, 2018, and 2017, we recognized $1.9 million of management fee income for each respective period. For Destin, we had an outstanding accounts payable balance of $0.6 million as of September 30, 2018, which is included in Accrued expenses and other current liabilities and an outstanding accounts receivable balance of $0.5 million as of December 31, 2017, which is included in Other current assets in the accompanying Condensed Consolidated Balance Sheets. For Okeanos, we had an outstanding accounts receivable balance of

36
American Midstream Partners, LP and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



$0.1 million and $0.4 million as of September 30, 2018 and December 31, 2017, respectively, which is included in Other current assets in the accompanying Condensed Consolidated Balance Sheets.

Consolidated Asset Management Services, LLC ("CAMS")

Dan Revers, a director of our General Partner, indirectly owns in excess of 10% of CAMS, which, through various subsidiaries or affiliates, provides pipeline integrity services to the Partnership and subleases an office space from the Partnership. During the nine months ended September 30, 2018 and 2017, the Partnership was invoiced by CAMS $0.2 million for each respective period and had no outstanding accounts receivable balance as of September 30, 2018 or December 31, 2017.

Other Related Party Transactions

Michael D. Rupe, the brother of Ryan Rupe (the Partnership’s Vice President - Natural Gas Services and Offshore Pipelines), is the Chief Financial Officer of CIMA Energy Ltd., a crude oil and natural gas marketing company (“CIMA”). The Partnership regularly engages in purchases and sales of crude oil and natural gas with CIMA. During the nine months ended September 30, 2018, the Partnership invoiced CIMA $1.7 million and received invoicing from CIMA of $3.5 million in connection with such transactions. For the nine months ended September 30, 2017, the Partnership invoiced CIMA $6.2 million and received invoices from CIMA of $3.7 million for services. As of September 30, 2018, and December 31, 2017, the Partnership had minimal outstanding amounts due from CIMA.

During September and October 2017, under a transition services agreement, the Partnership made payments on behalf of AMID Merger GP II, LLC related to the Propane Business sale. As of September 30, 2018, and December 31, 2017, we had an outstanding accounts receivable balance related to these payments of $1.1 million and $2.5 million, respectively, which is included in Other current assets in the accompanying Condensed Consolidated Balance Sheets.

For additional information on Related Parties, see Note 21 - Related Party Transactions, in our 2017 Form 10-K.

(20) Supplemental Cash Flow Information

Supplemental cash flows and non-cash transactions consist of the following (in thousands):
 
 
Nine months ended September 30,
 
 
2018
 
2017
Supplemental cash flow information
 
 
 
 
Cash paid for interest
 
$
49,294

 
$
40,885

Supplemental non-cash information
 
 
 
 
Investing
 
 
 
 
Increase (decrease) in accrued property, plant and equipment purchases
 
(1,652
)
 
(15,112
)
Accrued contributions to unconsolidated affiliates
 
(89
)
 
—

Financing
 
 
 
 
Issuance of common units for the Panther acquisition
 
—

 
12,532

Contributions from an affiliate holding limited partner interests
 
—

 
4,000

Accrued distributions on convertible preferred units
 
8,354

 
8,255

Paid-in-kind distributions on convertible preferred units
 
8,076

 
6,838


(21) Reportable Segments

Our operations are organized into five reportable segments: (1) Gas Gathering and Processing Services, (2) Liquid Pipelines and Services, (3) Natural Gas Transportation Services, (4) Offshore Pipelines and Services and (5) Terminalling Services. We disclose the results of each of our operating segments in accordance with ASC 280, Segment Reporting (“ASC 280”).

Each of our operating segments is managed by a senior executive reporting directly to our Chief Executive Officer, the chief operating decision maker (“CODM”). Our Chief Executive Officer evaluates the performance of our reportable segments primarily on the basis of segment gross margin, which is our segment measure of profitability.


37
American Midstream Partners, LP and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



Our CODM uses gross margin as the primary measure for reviewing our segments’ profitability and therefore, in accordance with ASC 280, we have presented gross margin for each segment. For segments other than Terminalling Services, we define segment gross margin as total revenue plus unconsolidated affiliate earnings less unrealized gains (losses) on commodity derivatives, construction and operating management agreement income and the cost of sales. Gross margin for Terminalling Services also deducts direct operating expense, which includes direct labor, general materials and supplies and direct overhead.


The following tables set forth our segment information for the three and nine months ended September 30, 2018 and 2017 (in thousands):
 
Three months ended September 30, 2018
 
Gas Gathering and Processing Services
 
Liquid Pipelines and Services
 
Natural Gas Transportation Services
 
Offshore Pipelines and Services
 
Terminalling Services
 
Total
Revenue
$
53,429

 
$
109,559

 
$
12,710

 
$
19,331

 
$
7,551

 
$
202,580

Loss on commodity derivatives, net
(93
)
 
(141
)
 
—

 
—

 
—

 
(234
)
Total revenue
53,336


109,418


12,710


19,331


7,551

 
202,346

 
 
 
 
 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
 
 
 
 
Cost of sales
37,917

 
103,345

 
5,502

 
1,959

 
1,551

 
150,274

Direct operating expenses
—

 
—

 
—

 
—

 
2,152

 
20,407

Corporate expenses
 
 
 
 
 
 
 
 
 
 
23,857

Termination fee
 
 
 
 
 
 
 
 
 
 
17,000

     Depreciation, amortization and accretion expense
 
 
 
 
 
 
 
 
 
 
23,040

Gain on sale of assets, net
 
 
 
 
 
 
 
 
 
 
(99,396
)
Total operating expenses

 

 

 

 

 
135,182

Operating income

 

 

 

 

 
67,164

Other income (expense), net
 
 
 
 
 
 
 
 
 
 
 
     Interest expense, net of capitalized interest
 
 
 
 
 
 
 
 
 
 
(22,267
)
     Other expense, net
 
 
 
 
 
 
 
 
 
 
(128
)
     Earnings in unconsolidated affiliates
—

 
3,172

 
—

 
21,450

 
—

 
24,622

Income from continuing operations before income taxes

 

 

 

 

 
69,391

Income tax expense
 
 
 
 
 
 
 
 
 
 
(31,208
)
Income from continuing operations
 
 
 
 
 
 
 
 
 
 
38,183

     Net income attributable to non-controlling interests
 
 
 
 
 
 
 
 
 
 
(25
)
Net income attributable to the Partnership
 
 
 
 
 
 
 
 
 
 
$
38,158

 
 
 
 
 
 
 
 
 
 
 
 
Segment gross margin
$
15,421

 
$
9,351

 
$
7,044

 
$
38,823

 
$
3,848

 
 


38
American Midstream Partners, LP and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



 
Three months ended September 30, 2017
 
Gas Gathering and Processing Services
 
Liquid Pipelines and Services
 
Natural Gas Transportation Services
 
Offshore Pipelines and Services
 
Terminalling Services
 
Total
Revenue
$
37,287

 
$
87,022

 
$
11,131

 
$
14,360

 
$
13,087

 
$
162,887

Loss on commodity derivatives, net
(65
)
 
(532
)
 
—

 
—

 
—

 
(597
)
Total revenue
37,222

 
86,490

 
11,131

 
14,360

 
13,087

 
162,290

 
 
 
 
 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
 
 
 
 
Cost of sales
24,492

 
80,510

 
5,692

 
558

 
1,146

 
112,398

Direct operating expenses


 


 


 


 
3,432

 
20,705

Corporate expenses
 
 
 
 
 
 
 
 
 
 
27,083

     Depreciation, amortization and accretion expense
 
 
 
 
 
 
 
 
 
 
26,781

Gain on sale of assets, net
 
 
 
 
 
 
 
 
 
 
(4,061
)
Total operating expenses

 

 

 

 

 
182,906

Operating loss

 

 

 

 

 
(20,616
)
Other income (expenses), net
 
 
 
 
 
 
 
 
 
 
 
     Interest expense, net of capitalized interest
 
 
 
 
 
 
 
 
 
 
(17,759
)
     Other income, net
 
 
 
 
 
 
 
 
 
 
34,085

     Earnings in unconsolidated affiliates
—

 
1,317

 
—

 
15,510

 
—

 
16,827

Income from continuing operations before income taxes

 

 

 

 

 
12,537

Income tax expense
 
 
 
 
 
 
 
 
 
 
(731
)
Income from continuing operations
 
 
 
 
 
 
 
 
 
 
11,806

Income from discontinued operations, including gain on disposition
 
 
 
 
 
 
 
 
 
 
44,696

Net income
 
 
 
 
 
 
 
 
 
 
56,502

     Net income attributable to non-controlling interests
 
 
 
 
 
 
 
 
 
 
(621
)
Net income attributable to the Partnership
 
 
 
 
 
 
 
 
 
 
$
55,881

 
 
 
 
 
 
 
 
 
 
 
 
Segment gross margin
$
12,761

 
$
7,808

 
$
5,356

 
$
29,312

 
$
8,509

 
 







39
American Midstream Partners, LP and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



 
Nine months ended September 30, 2018
 
Gas Gathering and Processing Services
 
Liquid Pipelines and Services
 
Natural Gas Transportation Services
 
Offshore Pipelines and Services
 
Terminalling Services
 
Total
Revenue
$
138,613

 
$
349,947

 
$
44,339

 
$
54,711

 
$
41,310

 
$
628,920

Loss on commodity derivatives, net
(385
)
 
(145
)
 
—

 
—

 
—


(530
)
Total revenue
138,228

 
349,802

 
44,339

 
54,711

 
41,310

 
628,390

 
 
 
 
 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
 
 
 
 
Cost of sales
95,921

 
333,342

 
16,628

 
6,105

 
9,952


461,948

Direct operating expenses
—

 
—

 
—

 
—

 
10,605


65,595

Corporate expenses
 
 
 
 
 
 
 
 
 
 
69,922

Termination fee
 
 
 
 
 
 
 
 
 
 
17,000

     Depreciation, amortization and accretion expense
 
 
 
 
 
 
 
 
 
 
66,274

Gain on sale of assets, net
 
 
 
 
 
 
 
 
 
 
(99,491
)
Total operating expenses

 

 

 

 

 
581,248

Operating income

 

 

 

 

 
47,142

Other income (expense), net
 
 
 
 
 
 
 
 
 
 
 
     Interest expense, net of capitalized interest
 
 
 
 
 
 
 
 
 
 
(55,834
)
     Other income, net
 
 
 
 
 
 
 
 
 
 
62

     Earnings in unconsolidated affiliates
—

 
7,878

 
—

 
39,864

 
—

 
47,742

Income from continuing operations before income taxes

 

 

 

 

 
39,112

Income tax expense
 
 
 
 
 
 
 
 
 
 
(32,045
)
Net income
 
 
 
 
 
 
 
 
 
 
7,067

     Net income attributable to non-controlling interests
 
 
 
 
 
 
 
 
 
 
(83
)
Net income attributable to the Partnership
 
 
 
 
 
 
 
 
 
 
$
6,984

 

 

 

 

 

 
 
Segment gross margin
$
42,613

 
$
24,365

 
$
27,384

 
$
88,470

 
$
20,753

 
 

40
American Midstream Partners, LP and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



 
Nine months ended September 30, 2017
 
Gas Gathering and Processing Services
 
Liquid Pipelines and Services
 
Natural Gas Transportation Services
 
Offshore Pipelines and Services
 
Terminalling Services
 
Total
Revenue
$
111,001

 
$
253,590

 
$
34,966

 
$
41,330

 
$
47,544

 
$
488,431

(Loss) gain on commodity derivatives, net
(170
)
 
137

 
—

 
—

 
—

 
(33
)
Total revenue
110,831

 
253,727

 
34,966

 
41,330

 
47,544

 
488,398

 
 
 
 
 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
 
 
 
 
Cost of sales
74,261

 
236,896

 
17,630

 
6,487

 
7,612

 
342,886

Direct operating expenses
—

 
—

 
—

 
—

 
9,503

 
56,819

Corporate expenses
 
 
 
 
 
 
 
 
 
 
84,570

     Depreciation, amortization and accretion expense
 
 
 
 
 
 
 
 
 
 
78,834

Gain on sale of assets, net
 
 
 
 
 
 
 
 
 
 
(4,064
)
Total operating expenses

 

 

 

 

 
559,045

Operating loss

 

 

 

 

 
(70,647
)
Other income (expenses), net
 
 
 
 
 
 
 
 
 
 
 
     Interest expense, net of capitalized interest
 
 
 
 
 
 
 
 
 
 
(51,037
)
     Other income, net
 
 
 
 
 
 
 
 
 
 
32,248

     Earnings in unconsolidated affiliates
—

 
3,886

 
—

 
45,895

 
—

 
49,781

Loss from continuing operations before income taxes

 

 

 

 

 
(39,655
)
Income tax expense
 
 
 
 
 
 
 
 
 
 
(2,611
)
Loss from continuing operations
 
 
 
 
 
 
 
 
 
 
(42,266
)
Income from discontinued operations, including gain on disposition
 
 
 
 
 
 
 
 
 
 
42,185

Net loss
 
 
 
 
 
 
 
 
 
 
(81
)
     Net income attributable to non-controlling interests
 
 
 
 
 
 
 
 
 
 
(3,386
)
Net loss attributable to the Partnership
 
 
 
 
 
 
 
 
 
 
$
(3,467
)
 
 
 
 
 
 
 
 
 
 
 
 
Segment gross margin
$
36,663

 
$
21,209

 
$
17,106

 
$
80,738

 
$
30,429

 
 


    





41
American Midstream Partners, LP and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



A reconciliation of total assets by segment to the amounts included in the Condensed Consolidated Balance Sheets follows (in thousands):
 
September 30,
 
December 31,
 
2018
 
2017
Segment assets:
 
 
 
Gas Gathering and Processing Services
$
397,726

 
$
404,872

Liquid Pipelines and Services
370,833

 
359,646

Natural Gas Transportation Services
267,185

 
268,991

Offshore Pipelines and Services
525,493

 
553,213

Terminalling Services 
187,779

 
293,085

Other (1)
85,589

 
43,659

Total assets
$
1,834,605

 
$
1,923,466

 
 
 
 
Investment in unconsolidated affiliates:
 
 
 
Liquid Pipelines and Services
$
68,849

 
$
64,399

Offshore Pipelines and Services
267,940

 
284,035

Total investment in unconsolidated affiliates
$
336,789

 
$
348,434

________________________ 
(1) Other assets consists primarily of corporate assets not allocable to segments, such as leasehold improvements and other current assets.

The following table sets forth capital expenditures for the three and nine months ended September 30, 2018 and 2017 by segment (in thousands):     
 
Three months ended September 30,
 
Nine months ended September 30,
 
2018
 
2017
 
2018
 
2017
Capital expenditures
 
 
 
 
 
 
 
Gas Gathering and Processing Services
$
11,603

 
$
4,788

 
$
24,914

 
$
13,315

Liquid Pipelines and Services
1,468

 
1,301

 
12,649

 
2,677

Natural Gas Transportation Services
1,554

 
6,431

 
4,045

 
30,797

Offshore Pipelines and Services
155

 
2,283

 
20,491

 
3,417

Terminalling Services 
691

 
3,954

 
6,813

 
6,795

Corporate
1,358

 
1,235

 
4,430

 
4,882

Total capital expenditures(1)
$
16,829

 
$
19,992

 
$
73,342

 
$
61,883

_____________________________________
(1) Capital expenditures exclude expenditures made for the Propane Business of $0.7 million and $3.1 million for the three and nine months ended September 30, 2017, respectively, as the business was sold in 2017.

(22) Subsequent Events

Distribution

On October 25, 2018, we announced that the Board of Directors of our General Partner declared a quarterly cash distribution of $0.1031 per common unit, or $0.4125 per common unit annualized, with respect to the third quarter of 2018, which is consistent with our second quarter of 2018 per common unit distribution. The distribution will be paid on November 14, 2018 to unitholders of record as of the close of business on November 6, 2018.

Ajax Settlement

American Midstream Permian, LLC and Ajax Resources, LLC (“Ajax”) are parties to a Gas Processing and Gathering Agreement, dated October 1, 2013, pursuant to which American Midstream Permian, LLC’s Yellow Rose System gathers and processes Ajax’s production from its dedicated acreage in the Permian Basin.  On June 13, 2016, the Partnership filed a Petition, Application for Temporary Restraining Order and Temporary Injunction in District Court for Harris County, Texas seeking to enjoin Ajax from terminating the Agreement. On December 13, 2017, Ajax sent the Partnership a notice stating that following an audit conducted pursuant to the Agreement, it concluded that the Partnership underpaid Ajax during the period between January 2015 and May

42
American Midstream Partners, LP and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



2017, and Ajax requested that the Partnership pay for the alleged damages. On September 25, 2018, Ajax filed an answer and counterclaim to the Partnership’s Petition asserting that the Partnership breached the Agreement with Ajax and seeking damages in the amount of $4.7 million plus attorneys’ fees. On October 23, 2018, the parties agreed to settle this matter, and the Partnership made a $2.0 million payment to Ajax in exchange for Ajax’s release of all claims against the Partnership. On October 26, 2018, the parties filed a Joint Motion for Dismissal with Prejudice with the court.  The Partnership accrued an amount equal to $2.0 million for this matter in the third quarter of 2018.



43
Table of Contents

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

The following management’s discussion and analysis of our financial condition and results of operations should be read in conjunction with the unaudited Condensed Consolidated Financial Statements and the related notes thereto included elsewhere in this Quarterly Report on Form 10-Q (“Quarterly Report”) and the audited Consolidated Financial Statements and notes thereto and management’s discussion and analysis of financial condition and results of operations as of and for the year ended December 31, 2017 included in our Annual Report on Form 10-K as filed with the Securities and Exchange Commission (“SEC”) on April 9, 2018 (“2017 Form 10-K”). This discussion contains forward-looking statements that reflect management’s current views with respect to future events and financial performance. Our actual results may differ materially from those anticipated in these forward-looking statements or as a result of certain factors such as those set forth below under the caption “Forward-Looking Statements.”

Forward-Looking Statements

Our reports, filings and other public announcements may from time to time contain statements that do not directly or exclusively relate to historical facts. Such statements are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). You can typically identify forward-looking statements by the use of words such as "may," "could," “intend,” “will,” “would,” "project," "believe," "anticipate," "expect," "estimate," "potential," "plan," "forecast" and other similar words.

All statements that are not statements of historical facts, including statements regarding our future financial position, business strategy, budgets, projected costs and plans, and objectives of management for future operations, are forward-looking statements.

These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. These risks and uncertainties, many of which are beyond our control, include, but are not limited to, the risks set forth in Item 1A - Risk Factors of our 2017 Form 10-K as well as the following risks and uncertainties:

•
our ability to execute on our capital allocation strategy, including sales of non-core assets, receipt of expected proceeds, distribution levels and reduction in leverage;
•
the impact of the unsolicited offer from Magnolia to acquire all common units it and its affiliates do not already own and the process resulting therefrom;
•
our ability to timely and successfully identify, consummate and integrate acquisitions and organic growth projects, including the realization of all anticipated benefits of any such transactions;
•
our ability to refinance our credit facility before its scheduled maturity in September 2019 on terms acceptable to us, or at all, and the associated costs;
•
our ability to maintain compliance with financial covenants and ratios in our revolving credit facility;
•
any adverse impact of our doubt as to our ability to continue as a going concern;
•
our ability to generate sufficient cash from operations to pay distributions to unitholders and our Board’s discretionary determination as to the level of cash distributions to unitholders;
•
our ability to access capital to fund growth, including new and amended credit facilities and access to the debt and equity markets, which will depend on general market conditions;
•
the demand for natural gas, refined products, condensate or crude oil and NGL products by the petrochemical, refining or other industries;
•
the performance of certain of our current and future projects and unconsolidated affiliates that we do not control and disruptions to cash flows from our joint ventures due to operational or other issues that are beyond our control;
•
severe weather and other natural phenomena, including their potential impact on demand for the commodities we sell and the operation of company-owned and third party-owned infrastructure;
•
security threats such as terrorist attacks and cybersecurity breaches, against, or otherwise impacting, our facilities and systems;
•
general economic, market and business conditions, including industry changes and the impact of consolidations and changes in competition;
•
the level of creditworthiness of counterparties to transactions;
•
the amount of collateral required to be posted from time to time in our transactions;
•
the level and success of natural gas and crude oil drilling around our assets and our success in connecting natural gas and crude oil supplies to our gathering and processing systems;
•
the timing and extent of changes in natural gas, crude oil, NGLs and other commodity prices, interest rates and demand for our services;
•
our success in risk management activities, including the use of derivative financial instruments to hedge commodity, interest rate and weather risks;

44


•
our dependence on a relatively small number of customers for a significant portion of our gross margin;
•
our ability to renew our gathering, processing, transportation and terminal contracts;
•
our ability to successfully balance our purchases and sales of natural gas;
•
our ability to grow through contributions from affiliates, acquisitions and internal growth projects;
•
the impact or outcome of any legal proceedings;
•
the level of support provided by our sponsor;
•
the cost and effectiveness of our remediation efforts with respect to the material weaknesses discussed in Part II, Item 9A - Controls and Procedures of our 2017 Form 10-K; and
•
costs associated with compliance with environmental, health and safety, and pipeline regulations.

Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and, therefore, we cannot assure you that the forward-looking statements included in this Quarterly Report will prove to be accurate. Some of these and other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described in Item 1A - Risk Factors of our 2017 Form 10-K. Statements in this Quarterly Report speak as of the date of this Quarterly Report. Except as may be required by applicable securities laws, we undertake no obligation to publicly update or advise investors of any change in any forward-looking statement, whether as a result of new information, future events or otherwise.

Overview

We are a growth-oriented Delaware limited partnership formed in August 2009 to own, operate, develop and acquire a diversified portfolio of midstream energy assets. We provide critical midstream infrastructure that links producers of natural gas, crude oil, NGLs, condensate and specialty chemicals to numerous intermediate and end-use markets. Through our five reportable segments, (i) Gas Gathering and Processing Services, (ii) Liquid Pipelines and Services, (iii) Natural Gas Transportation Services, (iv) Offshore Pipelines and Services and (v) Terminalling Services, we engage in the business of gathering, treating, processing and transporting natural gas; gathering, transporting, storing, treating and fractionating NGLs; gathering, storing and transporting crude oil and condensates; and storing refined products.

Recent Developments

•
On September 28, 2018, the Board of Directors of our General Partner received a non-binding proposal from Magnolia Infrastructure Holdings, LLC (“Magnolia”), an affiliate of ArcLight Capital Partners, LLC (“ArcLight”), pursuant to which Magnolia would acquire all common units of the Partnership that Magnolia and its affiliates do not already own in exchange for $6.10 per common unit. If approved, it is currently expected that the transaction would be effected through a merger of the Partnership with a subsidiary of ArcLight. The transaction, as proposed, is subject to a number of contingencies, including Magnolia's completion of due diligence, the approval of the Conflicts Committee, the approval by holders of a majority of the outstanding common units of the Partnership and the satisfaction of any conditions to the consummation of a transaction set forth in any definitive agreement concerning the transaction. There can be no assurance that definitive documentation will be executed or that any transaction will materialize.

•
During the first nine months of 2018, we entered into definitive agreements for the sale of certain of our businesses as follows:

◦
On February 16, 2018, we entered into a definitive agreement for the sale of our refined products terminals (the “Refined Products”) to DKGP Energy Terminals LLC (“DKGP”), for approximately $139 million in cash, subject to working capital adjustments. During June 2018, we were notified that the Federal Trade Commission was requesting additional information and documentary materials with respect to the planned sale. On August 1, 2018, we and DKGP announced the termination of the agreement. We are continuing to market Refined Products and present the assets and liabilities of Refined Products as held for sale.

◦
On June 18, 2018, we entered into a definitive agreement for the sale of our marine products terminals (the "Marine Products") to institutional investors for approximately $210 million in cash, subject to working capital adjustments. The divestiture of Marine Products, including the Harvey and Westwego terminals located in the Port of New Orleans in Louisiana, and the Brunswick terminal located in the Port of Brunswick in Georgia, is a continuation of the Partnership’s previously announced non-core asset divestiture program.

On July 31, 2018, we completed the sale of Marine Products. Net proceeds from this disposition were $208.6 million, exclusive of $5.7 million in advisory fees and other costs, and were used to repay borrowings outstanding under our Credit Agreement.


45


•
On October 31, 2017, we, our General Partner, our wholly owned subsidiary, Cherokee Merger Sub LLC, Southcross Energy Partners, L.P. (“SXE”) and Southcross Energy Partners GP, LLC, entered into an Agreement and Plan of Merger (the “SXE Merger Agreement”), and we, our General Partner and Southcross Holdings LP (“Holdings LP”) entered in to a Contribution Agreement (“Contribution Agreement”), for total consideration of $818 million. Under the Merger Agreement and the Contribution Agreement, we would have acquired SXE and substantially all the current subsidiaries of Holdings LP. The SXE Merger Agreement and the Contribution Agreement originally provided for an outside closing date of June 1, 2018. On June 1, 2018 the parties to the Merger Agreement and the Contribution Agreement agreed to extend such outside closing date to June 15, 2018 (the “Outside Closing Date”).

On July 29, 2018, following the expiration of the Outside Closing Date, we received notice of termination of the SXE Merger Agreement from SXE and notice of termination of the Contribution Agreement from Holdings LP. The terms of the Contribution Agreement required the payment to Holdings LP of a $17 million termination fee in the event Holdings LP terminated the Contribution Agreement after the Outside Closing Date due to our inability to obtain financing to close the SXE Transactions on terms reasonably acceptable to us. The termination fee serves as liquidated damages. The termination fee was paid in August 2018.

Financial Highlights

Financial highlights for the three months ended September 30, 2018 include the following:

•
Net income attributable to the Partnership was $38.2 million for the three months ended September 30, 2018 as compared to $55.9 million for the same period in 2017.
•
Adjusted EBITDA was $35.2 million for the three months ended September 30, 2018, a decrease of 17% compared to the third quarter of 2017.
•
Distributable cash flow was $4.5 million for the three months ended September 30, 2018, compared to $22.1 million for the same period in 2017.
•
Total segment gross margin was $74.5 million for the three months ended September 30, 2018, an increase of 17% as compared to the third quarter of 2017.
    
Adjusted EBITDA, distributable cash flow and total segment gross margin are each non-GAAP measures. Please see Non-GAAP Financial Measures for a definition and reconciliation to the most comparable GAAP measure.

Operational highlights for the three months ended September 30, 2018, include the following:

•
Continued producer development across the Partnership’s Eagle Ford gathering and processing assets contributed to a 30% increase in throughput volumes over the third quarter of 2017.
•
Increased activity in the deep-water Gulf of Mexico drove a 23% increase in natural gas throughput volumes on the Partnership’s consolidated offshore assets over the third quarter of 2017.
•
Continued strength across the Partnership’s natural gas transportation assets, with volumes increasing 71% from the same period in the prior year, driven by the acquisition of Trans-Union pipeline.
•
Strong producer activity across the Partnership’s East Texas and Permian assets contributed to an 18% increase in NGL production volumes over the third quarter of 2017.
•
Active drilling programs in and around the Partnership’s Bakken assets drove a 97% increase in throughput volumes over the second quarter of 2018.
•
Current production flows on Delta House are approximately 90 MBoe/d.


Non-GAAP Financial Measures

Total segment gross margin, operating margin, Adjusted EBITDA and Distributable Cash Flow (“DCF”) are performance measures that are non-GAAP financial measures. Each has important limitations as an analytical tool because they exclude some, but not all, items that affect the most directly comparable GAAP financial measures. Management compensates for the limitations of these non-GAAP measures as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these data points into management’s decision-making process.

You should not consider total segment gross margin, operating margin, Adjusted EBITDA or DCF in isolation or as a substitute for, or more meaningful than analysis of, our results as reported under GAAP. Total segment gross margin, operating margin, Adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry. Our definitions of

46


these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

Adjusted EBITDA

Adjusted EBITDA is a supplemental non-GAAP financial measure used by our management and external users of our financial statements, such as investors, commercial banks, research analysts and others, to assess: the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; the ability of our assets to generate cash flow to make cash distributions to our unitholders and our General Partner; our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.

We define Adjusted EBITDA as net income (loss) attributable to the Partnership, plus depreciation, amortization and accretion expense (“DAA”) excluding noncontrolling interest share of DAA, interest expense, net of capitalized interest excluding unrealized gain (loss) on interest rate swaps, amortization of deferred financing costs, debt issuance costs paid during the period,  unrealized gains (losses)  on derivatives, non-cash charges such as non-cash equity compensation expense and charges that are unusual such as transaction expenses primarily associated with our acquisitions, income tax expense, distributions from unconsolidated affiliates and General Partner’s contribution, less earnings in unconsolidated affiliates, discontinued operations, gains (losses) that are unusual, such as gain on revaluation of equity interest and gain (loss) on sale of assets, net and other non-recurring items that impact our business, such as construction and operating management agreement income (“COMA”) and other post-employment benefits plan net periodic benefit.

The GAAP measure most directly comparable to our performance measure Adjusted EBITDA is Net income (loss) attributable to the Partnership.

Distributable Cash Flow

DCF is a significant performance metric used by us and by external users of the Partnership's financial statements, such as investors, commercial banks and research analysts, to compare basic cash flows generated by us to the cash distributions we expect to pay the Partnership's unitholders. Using this metric, management and external users of the Partnership's financial statements can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. DCF is also an important financial measure for the Partnership's unitholders since it serves as an indicator of the Partnership's success in providing a cash return on investment. Specifically, this financial measure may indicate to investors whether we are generating cash flow at a level that can sustain the Partnership's quarterly distribution rates. DCF is also a quantitative standard used throughout the investment community with respect to publicly traded partnerships and limited liability companies because the value of a unit of such an entity is generally determined by the unit's yield (which in turn is based on the amount of cash distributions the entity pays to a unitholder). DCF will not reflect changes in working capital balances.

We define DCF as Adjusted EBITDA less interest expense net of capitalized interest excluding unrealized gain (loss) on interest rate swaps and letter of credit fees, maintenance capital expenditures and distributions related to the Series A, Series C and Series D convertible preferred units. The GAAP financial measure most comparable to DCF is Net income (loss) attributable to the Partnership.

Total Segment Gross Margin and Operating Margin

Total segment gross margin and operating margin are non-GAAP supplemental measures that we use to evaluate our performance.

For segments other than Terminalling Services, we define segment gross margin as total revenue plus unconsolidated affiliate earnings less unrealized gains (losses) on commodity derivatives, construction and operating management agreement income and the cost of sales. Gross margin for Terminalling Services also deducts direct operating expense which includes direct labor, general materials and supplies, and direct overhead. We define operating margin as total segment gross margin less other direct operating expenses. The GAAP measure most directly comparable to total segment gross margin and operating margin is Net income (loss) attributable to the Partnership. For a reconciliation of total segment gross margin and operating margin to Net income (loss) attributable to the Partnership, see Note About Non-GAAP Financial Measures below.

Total segment gross margin is useful to investors and the Partnership’s management in understanding our operating performance because it measures the operating results of our segments before certain non-cash items, such as depreciation and amortization, and certain expenses that are generally not controllable by our business segment development managers (who are responsible for

47


revenue generation at the segment level), such as certain operating costs, general and administrative expenses, interest expense and income taxes. Operating margin is useful to investors and the Partnership’s management for similar reasons except that operating margin includes all direct operating expenses, which allows the Partnership’s management to assess the performance of our consolidated operating managers (who are responsible for cost management at the Partnership level). In addition, because these operating measures exclude interest expense and income taxes, they are useful for investors because they remove potential distortions between periods caused by factors such as financing and capital structures and changes in tax laws and positions.

Note about Non-GAAP Financial Measures

Total segment gross margin, operating margin, Adjusted EBITDA and DCF are performance measures that are non-GAAP financial measures. Each has important limitations as an analytical tool because it excludes some, but not all, items that affect the most directly comparable GAAP financial measures. Management compensates for the limitations of these non-GAAP measures as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these data points into management’s decision-making process.

You should not consider total segment gross margin, operating margin, Adjusted EBITDA or DCF in isolation or as a substitute for, or more meaningful than analysis of, our results as reported under GAAP. Total segment gross margin, operating margin, Adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry. Our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

The following tables reconcile the non-GAAP financial measures of total segment gross margin, operating margin, Adjusted EBITDA and DCF to its nearest GAAP measure, Net income (loss) attributable to the Partnership, (in thousands):

 
Three months ended September 30,
 
Nine months ended September 30,
Reconciliation of Total Segment Gross Margin to Net Income (Loss) Attributable to the Partnership:
 
2018
 
2017
 
2018
 
2017

 
 
 
 
 
 
 
 
Gas Gathering and Processing Services segment gross margin
 
$
15,421

 
$
12,761

 
$
42,613

 
$
36,663

Liquid Pipelines and Services segment gross margin
 
9,351

 
7,808

 
24,365

 
21,209

Natural Gas Transportation Services segment gross margin
 
7,044

 
5,356

 
27,384

 
17,106

Offshore Pipelines and Services segment gross margin
 
38,823

 
29,312

 
88,470

 
80,738

Terminalling Services segment gross margin (1)
 
3,848

 
8,509

 
20,753

 
30,429

Total segment gross margin
 
74,487

 
63,746

 
203,585

 
186,145

Direct operating expenses
 
(18,254
)
 
(17,274
)
 
(54,991
)
 
(47,316
)
Operating margin
 
56,233

 
46,472

 
148,594

 
138,829


 
 
 
 
 
 
 
 
Loss on commodity derivatives, net
 
(234
)
 
(597
)
 
(530
)
 
(33
)
Corporate expenses
 
(23,857
)
 
(27,083
)
 
(69,922
)
 
(84,570
)
Termination fee
 
(17,000
)
 
—

 
(17,000
)
 
—

Depreciation, amortization and accretion expense
 
(23,040
)
 
(26,781
)
 
(66,274
)
 
(78,834
)
Gain on sale of assets, net
 
99,396

 
4,061

 
99,491

 
4,064

Interest expense, net of capitalized interest
 
(22,267
)
 
(17,759
)
 
(55,834
)
 
(51,037
)
Other income
 
160

 
34,224

 
587

 
31,926

Income tax expense
 
(31,208
)
 
(731
)
 
(32,045
)
 
(2,611
)
Net income from discontinued operations, net of tax
 
—

 
44,696

 
—

 
42,185

Net income attributable to noncontrolling interests
 
(25
)
 
(621
)
 
(83
)
 
(3,386
)
Net income (loss) attributable to the Partnership
 
$
38,158

 
$
55,881

 
$
6,984

 
$
(3,467
)
_______________________
(1) Segment Gross Margin for our Terminalling Services segment includes Direct operating expenses. For additional information related to our operating segments, as well as a reconciliation of Segment Gross Margin to Income from continuing operations before income taxes, see Note 21 - Reportable Segments, to our Condensed Consolidated Financial Statements.



48


 

 
Three months ended September 30,
 
Nine months ended September 30,

 
2018
 
2017
 
2018
 
2017
Reconciliation of Net Income (Loss) Attributable to the Partnership to Adjusted EBITDA and DCF:
 
 
 
 
 
 
 
 
Net income (loss) attributable to the Partnership
 
$
38,158

 
$
55,881

 
$
6,984

 
$
(3,467
)
Depreciation, amortization and accretion expense
 
23,040

 
26,781

 
66,274

 
78,834

Noncontrolling interest share of depreciation, amortization and accretion expense
 
—

 
(96
)
 
—

 
(661
)
Interest expense, net of capitalized interest
 
22,267

 
17,759

 
55,834

 
51,037

Amortization of deferred financing costs
 
(2,493
)
 
(1,154
)
 
(5,142
)
 
(3,610
)
Unrealized loss (gain) on interest rate swaps
 
33

 
(1,646
)
 
6,123

 
(3,658
)
Debt issuance costs paid
 
1,959

 
119

 
4,701

 
2,235

Unrealized losses (gains) on derivatives, net
 
79

 
325

 
(5,771
)
 
2,288

Non-cash equity compensation expense
 
1,335

 
835

 
3,529

 
6,067

Transaction expenses
 
7,105

 
10,470

 
22,922

 
31,155

Termination fee
 
17,000

 
—

 
17,000

 
—

Income tax expense
 
31,209

 
731

 
32,045

 
2,611

Discontinued operations
 
—

 
(44,745
)
 
—

 
(36,247
)
Distributions from unconsolidated affiliates
 
19,705

 
20,582

 
64,260

 
58,976

General Partner contribution
 
—

 
9,870

 
17,732

 
34,614

Earnings in unconsolidated affiliates
 
(24,622
)

(16,827
)
 
(47,742
)
 
(49,781
)
COMA
 
(167
)
 
(91
)
 
(346
)
 
(257
)
Other income
 
5

 
—

 
(39
)
 
—

Gain on revaluation of equity interest
 
—

 
(32,383
)
 
—

 
(32,383
)
Gain on sale of assets, net
 
(99,396
)
 
(4,061
)
 
(99,491
)
 
(4,064
)
Adjusted EBITDA
 
$
35,217

 
$
42,350

 
$
138,873

 
$
133,689

 
 
 
 
 
 
 
 
 
Interest expense, net of capitalized interest
 
(22,267
)
 
(17,759
)
 
(55,834
)
 
(51,037
)
Amortization of deferred financing costs
 
2,493

 
1,154

 
5,142

 
3,610

Unrealized (loss) gain on interest rate swaps
 
(33
)
 
1,646

 
(6,123
)
 
3,658

Letter of credit fees
 
—

 
(11
)
 
21

 
210

Maintenance capital
 
(2,553
)
 
(2,449
)
 
(9,631
)
 
(6,570
)
Preferred unit distributions
 
(8,354
)
 
(2,870
)
 
(25,061
)
 
(16,311
)
Distributable cash flow
 
$
4,503

 
$
22,061

 
$
47,387

 
$
67,249


General Trends and Outlook

In July 2018, the Partnership announced a revised capital allocation strategy that is intended to reduce leverage, provide capital for strategic growth opportunities and create long-term value. As part of the revised capital allocation strategy, the Partnership has determined the most prudent sources of accretive growth capital are proceeds from the sale of non-core assets and the retention of an increased portion of operating cash flow through the reduction of its common unit distribution. Together, cash flow retention and asset sales are expected to enable the Partnership to reallocate capital to meaningful growth opportunities, while promoting balance sheet flexibility, substantially reducing indebtedness and minimizing the need to raise external equity capital.

During the remainder of 2018, our business objectives will continue to focus on maintaining stable cash flows from our existing assets, executing our capital optimization strategy to simplify our business and redeploy capital from non-core assets towards higher return and growth opportunities to increase our long-term cash flows. We believe the key elements to stable cash flows are the diversity of our asset portfolio and our fee-based business which represents a significant portion of our expected gross margins.


49


During 2018, we anticipate to incur between $14 million and $19 million for capital maintenance, and between $100 million and $120 million for capital expansion primarily including the East Texas NGL Value Chain consolidation, the build-out of the Lavaca system and other organic growth projects.

We expect our business to continue to be affected by the key trends, outlook and developments discussed in this report and in our 2017 Form 10-K, to the extent not superseded by information in this report, within Management’s Discussion and Analysis of Financial Condition and Results of Operations — General Trends and Outlook. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions prove to be incorrect, our actual results may vary materially from our expected results.
 
Results of Operations — Consolidated

To supplement our financial information presented in accordance with GAAP, our management uses additional measures known as “non-GAAP financial measures”, to evaluate past performance and prospects for the future. Management views these metrics as important factors in evaluating our profitability and reviews these measurements at least monthly for consistency and trend analysis. These metrics include throughput volumes, storage utilization, total segment gross margin, operating margin, direct operating expenses on a segment basis, and Adjusted EBITDA and DCF on a company-wide basis.

Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017

The results of operations for the three months ended September 30, 2018 and 2017 are presented in the tables below (in thousands, except percentages):
 
 
Three months ended September 30,
 
 
2018
 
2017
 
Change
 
%
 
 
 
 
 
 
 
 
 
Revenue
 
$
202,346

 
$
162,290

 
$
40,056

 
25
 %
Operating expenses:
 
 
 
 
 
 
 
 
Cost of sales
 
150,274

 
112,398

 
37,876

 
34
 %
Direct operating expenses
 
20,407

 
20,705

 
(298
)
 
(1
)%
Corporate expenses
 
23,857

 
27,083

 
(3,226
)
 
(12
)%
Termination fee
 
17,000

 
—

 
17,000

 
*

Depreciation, amortization and accretion expense
 
23,040

 
26,781

 
(3,741
)
 
(14
)%
Gain on sale of assets, net
 
(99,396
)
 
(4,061
)
 
(95,335
)
 
*

Total operating expenses
 
135,182

 
182,906

 
(47,724
)
 
(26
)%
Operating income (loss)
 
67,164

 
(20,616
)
 
87,780

 
426
 %
Other income (expense), net
 
 
 
 
 
 
 
 
Interest expense, net of capitalized interest
 
(22,267
)
 
(17,759
)
 
(4,508
)
 
25
 %
Other income (expense), net
 
(128
)
 
34,085

 
(34,213
)
 
*

Earnings in unconsolidated affiliates
 
24,622

 
16,827

 
7,795

 
46
 %
Income from continuing operations before income taxes
 
69,391

 
12,537

 
56,854

 
(453
)%
Income tax expense
 
(31,208
)
 
(731
)
 
(30,477
)
 
*

Income from continuing operations
 
38,183

 
11,806

 
26,377

 
223
 %
Income from discontinued operations, including gain on sale
 
—

 
44,696

 
(44,696
)
 
*

Net income
 
38,183

 
56,502

 
(18,319
)
 
(32
)%
Net income attributable to noncontrolling interests
 
(25
)
 
(621
)
 
596

 
96
 %
Net income attributable to the Partnership
 
$
38,158

 
$
55,881

 
$
(17,723
)
 
(32
)%
 
 
 
 
 
 
 
 

Non-GAAP Financial Measures
 
 
 
 
 
 
 

Total Segment gross margin (1)
 
$
74,487

 
$
63,746

 
$
10,741

 
17
 %
Adjusted EBITDA (2)
 
$
35,217

 
$
42,350

 
$
(7,133
)
 
(17
)%
____________________________________ 

50


* Not a meaningful percentage
(1) For reconciliation of Total Segment gross margin to its nearest GAAP measure, Income from continuing operations before income taxes, see table in Non-GAAP Financial Measures.
(2) See table in Non-GAAP Financial Measures for a reconciliation of Adjusted EBITDA to its nearest GAAP measure.

Net income attributable to the Partnership for the three months ended September 30, 2018 was $38.2 million, a decrease of $17.7 million, or 32%, from the same period in the prior year, primarily due to:
    
•
a $17.0 million termination fee from the termination of the SXE Merger Agreement in 2018;
•
a $34.2 million reduction in other income for the fair value adjustment recorded in 2017 from the acquisition of the remaining interests of MPOG; and
•
a $44.7 million reduction in income from discontinued operations, including gain on sale, which related to our Propane Business that was sold in the third quarter of 2017.

The above items, which negatively impacted Net income attributable to the Partnership between periods, was partially offset by:

•
increased revenues from both commodity sales and services, partially offset by higher cost of sales associated with higher revenues and increased operating expenses; and
•
the $99.4 million gain on sale of Marine Products in the third quarter of 2018 offset by a $30.5 million increase in income tax expense for the period.
 
Total Segment gross margin for the three months ended September 30, 2018 was $74.5 million, an increase of $10.7 million, or 17%, from the same period in the prior year. The increase was primarily due to higher segment gross margin in our Natural Gas Transportation Services, Gas Gathering and Processing Services, Offshore Pipelines and Services, and Liquid Pipelines and Services segments offset by declines in our Terminalling Services segment.

Adjusted EBITDA for the three months ended September 30, 2018 was $35.2 million, a decrease of $7.1 million, or 17%, from the same period in the prior year. The decrease in Adjusted EBITDA was primarily due to declines in Net income attributable to the Partnership as discussed above.

We distributed $5.5 million to holders of our common units, or $0.1031 per common unit, during the three months ended September 30, 2018, which represents the distribution for the second quarter of 2018.

Please see Results of Operations - Segment Results for a discussion of revenues, cost of sales, direct operating expenses and earnings in unconsolidated affiliates related to our segments.

Corporate expenses. Corporate expenses for the three months ended September 30, 2018 were $23.9 million, a decrease of $3.2 million, or 12%, from the same period in the prior year, primarily due to $4.5 million in lower transaction related costs, offset by $0.9 million in higher accounting and financing costs and $0.4 million increase in higher contractor and consultant costs.
Termination fee. The termination fee for the three months ended September 30, 2018 was $17.0 million due to the termination of the SXE Merger Agreement.

Depreciation, amortization and accretion. Depreciation, amortization and accretion expense for the three months ended September 30, 2018 was $23.0 million, a decrease of $3.7 million, or 14%, from the same period in the prior year, primarily due to $2.8 million in decreased amortization as a result of the accelerated amortization of Cushing customer contracts in 2017, $2.7 million in Marine and Refined Products terminals being classified as assets held for sale, $1.4 million in decreased depreciation and amortization due to the 2017 year-end impairments, and $1.0 million in decreased depreciation due to assets reaching the end of their depreciable lives in 2017. This was partially offset by an increase of $1.9 million due to the acquisition of Panther companies and Trans-Union pipeline in the third and fourth quarters of 2017, and $2.3 million due to the revision of the High Point ARO estimate at year-end 2017.

Interest expense, net of capitalized interest. Interest expense for the three months ended September 30, 2018 was $22.3 million, an increase of $4.5 million, or 25%, from the same period in the prior year, primarily due to higher interest of $3.4 million on the 8.50% Senior Notes, as a result of the $125.0 million bond offering in the fourth quarter of 2017 and higher interest on our revolving credit facility due to higher interest rates in 2018 compared to 2017.


51


Other income (expense), net. Other income (expense), net for the three months ended September 30, 2018 was $0.1 million, a decrease of $34.2 million, from the same period in the prior year, primarily due to the fair value adjustment recorded on the 2017 acquisition of the remaining interests of MPOG.

Income from discontinued operations. Income from discontinued operations for the three months ended September 30, 2017 was associated with our Propane Business that was sold in September 2017.

Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017

The results of operations for the nine months ended September 30, 2018 and 2017 are presented in the tables below (in thousands, except percentages):
 
Nine months ended September 30,
 
2018
 
2017
 
Change
 
%
 
 
 
 
 
 
 
 
Revenue
$
628,390

 
$
488,398

 
$
139,992

 
29
 %
Operating expenses:
 
 
 
 
 
 
 
Cost of sales
461,948

 
342,886

 
119,062

 
35
 %
Direct operating expenses
65,595

 
56,819

 
8,776

 
15
 %
Corporate expenses
69,922

 
84,570

 
(14,648
)
 
(17
)%
Termination fee
17,000

17,000

—

—

17,000

 
*

Depreciation, amortization and accretion
66,274

 
78,834

 
(12,560
)
 
(16
)%
(Gain) on sale of assets, net
(99,491
)
 
(4,064
)
 
(95,427
)
 
*

Total operating expenses
581,248

 
559,045

 
22,203

 
4
 %
Operating income (loss)
47,142

 
(70,647
)
 
117,789

 
167
 %
Other income (expense), net
 
 
 
 
 
 
 
Interest expense, net of capitalized interest
(55,834
)
 
(51,037
)
 
(4,797
)
 
9
 %
Other income, net
62

 
32,248

 
(32,186
)
 
*

Earnings in unconsolidated affiliates
47,742

 
49,781

 
(2,039
)
 
(4
)%
Income (loss) from continuing operations before income taxes
39,112

 
(39,655
)
 
78,767

 
199
 %
Income tax expense
(32,045
)
 
(2,611
)
 
(29,434
)
 
*

Income (loss) from continuing operations
7,067

 
(42,266
)
 
49,333

 
117
 %
Income from discontinued operations, including gain on sale
—

 
42,185

 
(42,185
)
 
(100
)%
Net income (loss)
7,067

 
(81
)
 
7,148

 
*

Net income attributable to noncontrolling interests
(83
)
 
(3,386
)
 
3,303

 
98
 %
Net income (loss) attributable to the Partnership
$
6,984

 
$
(3,467
)
 
$
10,451

 
301
 %
 
 
 
 
 
 
 
 
Non-GAAP Financial Measures
 
 
 
 
 
 
 
Total Segment gross margin (1)
$
203,585

 
$
186,145

 
$
17,440

 
9
 %
Adjusted EBITDA (2)
$
138,873

 
$
133,689

 
$
5,184

 
4
 %
____________________________
* Not a meaningful percentage
(1) For reconciliation of Total Segment gross margin to its nearest GAAP measure, Income from continuing operations before income taxes, see table in Non-GAAP Financial Measures.
(2) See table in Non-GAAP Financial Measures for a reconciliation of adjusted EBITDA to its nearest GAAP measure.

Net income (loss) attributable to the Partnership for the nine months ended September 30, 2018 was $7.0 million, an increase of $10.5 million, or 301%, from the same period in the prior year, primarily due to:

•
increased revenues from both commodity sales and services, partially offset by higher cost of sales associated with higher revenues and increased operating expenses; and
•
the $99.4 million gain on sale of Marine Products in the third quarter of 2018 offset by a $29.4 million increase in income tax expense for the period.

52



The above items, which increased Net income attributable to the Partnership between periods, was partially offset by:

•
a $17.0 million termination fee from the termination of the SXE Merger Agreement in 2018;
•
a $32.2 million reduction in other income for the fair value adjustment recorded in 2017 from the acquisition of the remaining interests of MPOG; and
•
a $42.2 million reduction in income from discontinued operations, including gain on sale, which related to our Propane Business that was sold in the third quarter of 2017.

Total Segment gross margin for the nine months ended September 30, 2018 was $203.6 million, an increase of $17.4 million, or 9%, from the same period in the prior year. The increase was primarily due to higher segment gross margin in our Natural Gas Transportation Services, Gas Gathering and Processing Services, Offshore Pipelines and Services, and Liquid Pipelines and Services segments offset by declines in our Terminalling Services segment.

Adjusted EBITDA for the nine months ended September 30, 2018 was $138.9 million, an increase of $5.2 million, or 4%, from the same period in the prior year. The increase in Adjusted EBITDA was primarily due to improvements in Net income attributable to the Partnership as discussed above.

We distributed $49.1 million, or $0.9281 per common unit, during the nine months ended September 30, 2018, which represents the distribution for the fourth quarter of 2017 and the first two quarters of 2018.

Please see Results of Operations - Segment Results for a discussion of revenues, cost of sales, direct operating expenses and earnings in unconsolidated affiliates.

Corporate expenses. Corporate expenses for the nine months ended September 30, 2018 were $69.9 million, a decrease of $14.6 million, or 17%, from the same period in the prior year, primarily due to reductions of $7.5 million in transaction related costs, $2.7 million in legal fees, $2.3 million in office expenses, $1.0 million in travel and entertainment expenses, $0.6 million in environmental and safety costs and $0.5 million in insurance costs.

Termination fee. The termination fee for the nine months ended September 30, 2018 was $17.0 million due to the termination of the SXE Merger Agreement.

Depreciation, amortization and accretion. Depreciation, amortization and accretion expense for the nine months ended September 30, 2018 was $66.3 million, a decrease of $12.6 million, or 16%, from the same period in the prior year, primarily due to $9.9 million in decreased amortization as a result of the accelerated amortization of Cushing customer contracts in 2017, $5.1 million in Marine and Refined Products terminals being classified as assets held for sale and $4.0 million in decreased depreciation and amortization due to the 2017 year-end impairments. This was partially offset by an increase of $5.7 million due to the acquisition of Panther companies and Trans-Union pipeline in the third and fourth quarters of 2017.

Interest expense, net of capitalized interest. Interest expense for the nine months ended September 30, 2018 was $55.8 million, an increase of $4.8 million, or 9%, from the same period in the prior year, primarily due to the higher interest charges of $9.7 million on the 8.50% Senior Notes, as a result of the $125.0 million bond offering in the fourth quarter of 2017, higher interest expense on our revolving credit facility of $6.3 million due to higher interest rates in 2018 compared to 2017, offset by the favorable position of our interest rate swaps in the amount of $10.9 million.

Other income, net. Other income, net for the nine months ended September 30, 2018 was $0.1 million, a decrease of $32.2 million, from the same period in the prior year, primarily due to the fair value adjustment recorded on the 2017 acquisition of the remaining interests of MPOG.

53


Results of Operations — Segment Results

Gas Gathering and Processing Services Segment

Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017

The table below contains key segment performance indicators for the three months ended September 30, 2018 and 2017 related to our Gas Gathering and Processing Services segment (in thousands except operating and percentages).
 
 
Three months ended September 30,
 
 
2018
 
2017
 
Change
 
%
Segment Financial and Operating Data:
 
 
 
 
 
 
 
 
Financial data:
 
 
 
 
 
 
 
 
Commodity sales
 
$
42,369

 
$
31,651

 
$
10,718

 
34
 %
Services
 
11,060

 
5,636

 
5,424

 
96
 %
Revenue from operations
 
53,429

 
37,287

 
16,142

 
43
 %
Gain (loss) on commodity derivatives, net
 
(93
)
 
(65
)
 
(28
)
 
43
 %
Segment revenue
 
53,336

 
37,222

 
16,114

 
43
 %
Cost of sales
 
37,917

 
24,492

 
13,425

 
55
 %
Direct operating expenses
 
6,099

 
8,655

 
(2,556
)
 
(30
)%
Other financial data:
 

 
 
 
 
 
 
Segment gross margin (1)
 
$
15,421

 
$
12,761

 
$
2,660

 
21
 %
Operating data:
 
 
 
 
 
 
 
 
Average throughput (MMcf/d)
 
183.3

 
201.0

 
(17.7
)
 
(9
)%
Average plant inlet volume (MMcf/d) (2)
 
46.2

 
94.9

 
(48.7
)
 
(51
)%
Average gross NGL production (Mgal/d) (2)
 
362.9

 
324.3

 
38.6

 
12
 %
Average gross condensate production (Mgal/d) (2)
 
103.5

 
57.5

 
46.0

 
80
 %
 _______________________
(1) See Note 21 - Reportable Segments for a reconciliation of Segment Gross Margin to Income from continuing operations before income taxes.
(2) Excludes volumes and gross production under our elective processing arrangements.

Commodity sales. Commodity sales for the three months ended September 30, 2018 were $42.4 million, an increase of $10.7 million, or 34%, from the same period in the prior year, as a result of the following:

•
increased sales of NGLs, natural gas and condensate at the Longview Plant for $12.2 million primarily due to higher prices partially offset by slightly lower volumes;
•
an NGL component cash out on our West Texas pipeline of $5.2 million;
•
increase in sales at the Chatom-Bazor Ridge facility of approximately $2.4 million due to NGL deliveries from a new producer as well as increased NGL and condensate pricing;
•
increased sales of NGLs, natural gas and condensate at the Yellow Rose facility in the amount of $1.4 million primarily as a result of new marketing contracts; and
•
the increases noted above were partially offset by a $10.3 million reduction in Commodity Sales due to our adoption of Topic 606, in which we determined that certain percentage of proceeds (“POP”) contracts should be recorded on a net basis instead of a gross basis.

Services. Services for the three months ended September 30, 2018 were $11.1 million, an increase of $5.4 million, or 96%, from the same period in the prior year, due to increased fee revenue on Chapel Hill, Yellow Rose and Lavaca of $2.0 million. Additionally, as a result of our adoption of Topic 606, we have determined that certain POP contracts should be recorded on a net basis, resulting in a $3.9 million increase in Services revenue.

Cost of sales. Cost of sales for the three months ended September 30, 2018 were $37.9 million, an increase of $13.4 million, or 55%, from the same period in the prior year, primarily due to increased sales of NGLs, natural gas and condensate sales at the Longview, Yellow Rose and Chatom-Bazor Ridge facilities of $19.9 million, partially offset by $6.4 million due to the adoption of Topic 606 as discussed above.


54


Direct operating expenses. Direct operating expenses for the three months ended September 30, 2018 were $6.1 million, a decrease of $2.6 million, or 30%, from the same period in the prior year, mainly due to $2.1 million in lower operating expenses at Longview and Lavaca facilities and $0.5 million in lower outside services at Longview and Chapel Hill facilities.

Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017

The table below contains key segment performance indicators for the nine months ended September 30, 2018 and 2017 related to our Gas Gathering and Processing Services segment (in thousands except operating data and percentages).
 
 
Nine months ended September 30,
 
 
2018
 
2017
 
Change
 
%
Segment Financial and Operating Data:
 
 
 
 
 
 
 
 
Financial data:
 
 
 
 
 
 
 
 
Commodity sales
 
$
107,132

 
$
94,074

 
$
13,058

 
14
 %
Services
 
31,481

 
16,927

 
14,554

 
86
 %
Revenue from operations
 
138,613

 
111,001

 
27,612

 
25
 %
Gain (loss) on commodity derivatives, net
 
(385
)
 
(170
)
 
(215
)
 
126
 %
Segment revenue
 
138,228

 
110,831

 
27,397

 
25
 %
Cost of sales
 
95,921

 
74,261

 
21,660

 
29
 %
Direct operating expenses
 
18,705

 
24,766

 
(6,061
)
 
(24
)%
Other financial data:
 
 
 
 
 


 


Segment gross margin (1)
 
$
42,613

 
$
36,663

 
$
5,950

 
16
 %
Operating data:
 
 
 
 
 


 


Average throughput (MMcf/d)
 
172.9

 
205.0

 
(32.1
)
 
(16
)%
Average plant inlet volume (MMcf/d) (2)
 
44.8

 
100.0

 
(55.2
)
 
(55
)%
Average gross NGL production (Mgal/d) (2)
 
319.1

 
340.0

 
(20.9
)
 
(6
)%
Average gross condensate production (Mgal/d) (2)
 
84.7

 
73.0

 
11.7

 
16
 %
 _______________________
(1) See Note 21 - Reportable Segments for a reconciliation of Segment Gross Margin to Income from continuing operations before income taxes.
(2) Excludes volumes and gross production under our elective processing arrangements.

Commodity sales. Commodity sales for the nine months ended September 30, 2018 were $107.1 million, an increase of $13.1 million, or 14%, from the same period in the prior year, as a result of the following:

•
increased sales of NGLs, natural gas and condensate at the Longview Plant of $17.0 million primarily due to higher prices partially offset by slightly lower volumes;
•
increased marketing activity of $11.0 million due to new contracts and higher prices entered into in 2018;
•
an NGL component cash out on our West Texas pipeline of $5.2 million;
•
increase in sales at the Chatom-Bazor Ridge facility of approximately $3.9 million due to NGL deliveries from a new producer as well as increased NGL and condensate pricing;
•
increased sales of NGLs, natural gas and condensate at the Yellow Rose facility in the amount of $4.9 million primarily as a result of increased higher quality throughput and improved recoveries; and
•
the increases noted above were partially offset by a $28.3 million reduction in Commodity Sales due to our adoption of Topic 606, in which we determined that certain percentage of proceeds (“POP”) contracts should be recorded on a net basis instead of a gross basis.

Services. Services for the nine months ended September 30, 2018 were $31.5 million, an increase of $14.6 million, or 86%, from the same period in the prior year, due to increased fee revenue primarily on Yellow Rose and Lavaca of $3.3 million. Additionally, as a result of our adoption of Topic 606, we have determined that certain POP contracts should be recorded on a net basis, resulting in a $11.6 million increase in Services revenue.

Cost of sales. Cost of sales for the nine months ended September 30, 2018 were $95.9 million, an increase of $21.7 million, or 29%, from the same period in the prior year, primarily due to increased sales of NGLs, natural gas and condensate sales at the Longview, Yellow Rose and Chatom-Bazor Ridge facilities of $38.3 million These increases were partially offset by $15.5 million due to Topic 606 implementation as discussed above.


55


Direct operating expenses. Direct operating expenses for the nine months ended September 30, 2018 were $18.7 million, a decrease of $6.1 million, or 24%, from the same period in the prior year, primarily due to $2.0 million in lower operating expenses at Burns Point, Lavaca and Chatom-Bazor Ridge, $1.5 million in lower outside services at Longview, Yellow Rose and Chapel Hill facilities, $1.1 million in lower salaries and wages related to Chatom-Bazor Ridge and Lavaca, and $1.0 million in lower leases and rent at Lavaca and Chatom-Bazor Ridge and $0.5 million in lower environmental costs for Chapel Hill, Longview and Chatom-Bazor Ridge facilities.

Liquid Pipelines and Services Segment

Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017

The table below contains key segment performance indicators for the three months ended September 30, 2018 and 2017 related to our Liquid Pipelines and Services segment (in thousands except operating data and percentages).
 
 
Three months ended September 30,
 
 
2018
 
2017
 
Change
 
%
Segment Financial and Operating Data:
 
 
 
 
 
 
 
 
Financial data:
 
 
 
 
 


 


Commodity sales
 
$
104,984

 
$
82,948

 
$
22,036

 
27
 %
Services
 
4,575

 
4,074

 
501

 
12
 %
Revenue from operations
 
109,559

 
87,022

 
22,537

 
26
 %
Loss on commodity derivatives, net
 
(141
)
 
(532
)
 
391

 
(73
)%
Earnings in unconsolidated affiliates
 
3,172

 
1,317

 
1,855

 
141
 %
Segment revenue
 
112,590

 
87,807

 
24,783

 
28
 %
Cost of sales
 
103,345

 
80,510

 
22,835

 
28
 %
Direct operating expenses
 
2,465

 
2,438

 
27

 
1
 %
Other financial data:
 
 
 
 
 


 


Segment gross margin (1)
 
$
9,351

 
$
7,808

 
$
1,543

 
20
 %
Operating data (2)
:
 
 
 
 
 


 


Average throughput Pipeline (Bbl/d)
 
37,542

 
35,403

 
2,139

 
6
 %
Average throughput Truck (Bbl/d)
 
3,007

 
2,632

 
375

 
14
 %
_______________________
(1) See Note 21 - Reportable Segments for a reconciliation of Segment Gross Margin to Income from continuing operations before income taxes.
(2) Excludes volumes from our equity investments.

Commodity sales. Commodity sales for the three months ended September 30, 2018 were $105.0 million, an increase of $22.0 million, or 27%, from the same period in the prior year, primarily due to a $12.4 million increase on COSL as a result of increased volumes and $20.5 million due to a higher favorable average price increase of $11.35/Bbl in the third quarter of 2018 compared to the prior year period. These increases were partially offset by $5.6 million as a result of changing the recording of a contract from a gross to net basis and $5.6 million as a result of lower volumes of sour crude being processed in 2018.
    
Services. Services for the three months ended September 30, 2018 were $4.6 million, an increase of $0.5 million, or 12%, from the same period in the prior year, due to higher trucking volumes offset by lower third-party dispatch fees due to increased intercompany hauling.

Earnings in unconsolidated affiliates. Earnings in unconsolidated affiliates for the three months ended September 30, 2018 were $3.2 million, an increase of $1.9 million, or 141%, from the same period in the prior year, primarily due to our 50% interest in Cayenne Pipeline, which began operating in January 2018.

Cost of sales. Cost of sales for the three months ended September 30, 2018 were $103.3 million, an increase of $22.8 million, or 28%, from the same period in the prior year, resulting from higher volumes and higher prices achieved on the COSL assets of $33.0 million, partially offset by $5.3 million as a result of lower volumes of sour crude being processed in 2018 and $5.6 million in lower costs as a result of the adoption of Topic 606.


56


Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017

The table below contains key segment performance indicators for the nine months ended September 30, 2018 and 2017 related to our Liquid Pipelines and Services segment (in thousands except operating data and percentages).
 
 
Nine months ended September 30,
 
 
2018
 
2017
 
Change
 
%
Segment Financial and Operating Data:
 
 
 
 
 
 
 
 
Financial data:
 
 
 
 
 
 
 
 
Commodity sales
 
$
337,281

 
$
241,459

 
$
95,822

 
40
 %
Services
 
12,666

 
12,131

 
535

 
4
 %
Revenue from operations
 
349,947

 
253,590

 
96,357

 
38
 %
(Loss) gain on commodity derivatives, net
 
(145
)
 
137

 
(282
)
 
(206
)%
Earnings in unconsolidated affiliates
 
7,878

 
3,886

 
3,992

 
103
 %
Segment revenue
 
357,680

 
257,613

 
100,067

 
39
 %
Cost of sales
 
333,342

 
236,896

 
96,446

 
41
 %
Direct operating expenses
 
7,603

 
7,137

 
466

 
7
 %
Other financial data:
 
 
 
 
 
 
 
 
Segment gross margin (1)
 
$
24,365

 
$
21,209

 
$
3,156

 
15
 %
Operating data (2)
:
 
 
 
 
 
 
 
 
Average throughput Pipeline (Bbl/d)
 
36,621

 
33,837

 
2,784

 
8
 %
Average throughput Truck (Bbl/d)
 
3,367

 
2,048

 
1,319

 
64
 %
_______________________
(1) See Note 21 - Reportable Segments for a reconciliation of Segment Gross Margin to Income from continuing operations before income taxes.
(2) Excludes volumes from our equity investments.

Commodity sales. Commodity sales for the nine months ended September 30, 2018 were $337.3 million, an increase of $95.8 million, or 40%, from the same period in the prior year, primarily due to an $21.0 million increase on COSL as a result of increased volumes and $75.2 million due to a higher favorable average price increase of $14.23/Bbl in the first nine months of 2018 compared to the prior year period.

Services. Services for the nine months ended September 30, 2018 were $12.7 million, an increase of $0.5 million, or 4%, from the same period in the prior year, due to higher trucking volumes offset by lower third-party dispatch fees due to increased intercompany hauling.

Earnings in unconsolidated affiliates. Earnings in unconsolidated affiliates for the nine months ended September 30, 2018 were $7.9 million, an increase of $4.0 million, or 103%, from the same period in the prior year, primarily due to our 50% interest in Cayenne Pipeline which began operating in January 2018.

Cost of sales. Cost of sales for the nine months ended September 30, 2018 were $333.3 million, an increase of $96.4 million, or 41%, from the same period in the prior year, primarily resulting from higher volumes and higher prices achieved on the COSL assets of $92.7 million and increased trucking volumes and related expenses of $3.8 million.

Direct operating expenses. Direct operating expenses for the nine months ended September 30, 2018 were $7.6 million, an increase of $0.5 million, or 7%, from the same period in the prior year, mainly due to $0.3 million in higher outside services and $0.2 million in higher leases and rents related to COSL West Texas assets.


57


Natural Gas Transportation Services Segment

Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017

The table below contains key segment performance indicators for the three months ended September 30, 2018 and 2017 related to our Natural Gas Transportation Services segment (in thousands except operating data and percentages).
 
Three months ended September 30,
 
2018
 
2017
 
Change
 
%
Segment Financial and Operating Data:
 
 
 
 
 
 
 
Financial data:
 
 
 
 


 


Commodity sales
$
5,989

 
$
6,175

 
$
(186
)
 
(3
)%
Services
6,721

 
4,956

 
1,765

 
36
 %
Segment revenue
12,710

 
11,131

 
1,579

 
14
 %
Cost of sales
5,502

 
5,692

 
(190
)
 
(3
)%
Direct operating expenses
1,993

 
2,240

 
(247
)
 
(11
)%
Other financial data:
 
 
 
 


 


Segment gross margin (1)
$
7,044

 
$
5,356

 
$
1,688

 
32
 %
Operating data:
 
 
 
 
 
 
 
Average throughput (MMcf/d)
679.7

 
396.2

 
283.5

 
72
 %
 _______________________
(1) See Note 21 - Reportable Segments for a reconciliation of Segment Gross Margin to Income from continuing operations before income taxes.

Commodity sales. Commodity sales for the three months ended September 30, 2018 were $6.0 million, a decrease of $0.2 million, or 3%, from the same period in the prior year, primarily due to lower market pricing related to the Magnolia system.

Services. Services for the three months ended September 30, 2018 were $6.7 million, an increase of $1.8 million, or 36%, from the same period in the prior year, primarily due to our acquisition of Trans-Union in the fourth quarter of 2017.

Cost of sales. Cost of sales for the three months ended September 30, 2018 were $5.5 million, a decrease of $0.2 million, or 3%, from the same period in the prior year, primarily attributed to lower market prices and volumes.

Direct operating expenses. Direct operating expenses for the three months ended September 30, 2018 were $2.0 million, a decrease of $0.3 million, or 11%, from the same period in the prior year, primarily due to lower operating expenses related to Bamagas facilities.

58


Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017

The table below contains key segment performance indicators for the nine months ended September 30, 2018 and 2017 related to our Natural Gas Transportation Services segment (in thousands except operating data and percentages).
 
Nine months ended September 30,
 
2018
 
2017
 
Change
 
%
Segment Financial and Operating Data:
 
 
 
 
 
 
 
Financial data:
 
 
 
 
 
 
 
Commodity sales
$
18,105

 
$
19,485

 
$
(1,380
)
 
(7
)%
Services
26,234

 
15,481

 
10,753

 
69
 %
Segment revenue
44,339

 
34,966

 
9,373

 
27
 %
Cost of sales
16,628

 
17,630

 
(1,002
)
 
(6
)%
Direct operating expenses
5,477

 
5,403

 
74

 
1
 %
Other financial data:
 
 
 
 


 


Segment gross margin (1)
$
27,384

 
$
17,106

 
$
10,278

 
60
 %
Operating data:
 
 
 
 


 


Average throughput (MMcf/d)
700.9

 
383.1

 
317.8

 
83
 %
 _______________________
(1) See Note 21 - Reportable Segments for a reconciliation of Segment Gross Margin to Income from continuing operations before income taxes.

Commodity sales. Commodity sales for the nine months ended September 30, 2018 were $18.1 million, a decrease of $1.4 million, or 7%, from the same period in the prior year, primarily due to a decrease in volumes and prices related to the Magnolia system.

Services. Services for the nine months ended September 30, 2018 were $26.2 million, an increase of $10.8 million, or 69%, from the same period in the prior year, primarily due to an increase of $6.3 million resulting from our Trans-Union acquisition in the fourth quarter of 2017, an increase in imbalance activity of $1.8 million, an increase of $1.5 million due to our adoption of Topic 606 and an increase in management fees of $1.2 million.

Cost of sales. Cost of sales for the nine months ended September 30, 2018 were $16.6 million, a decrease of $1.0 million, or 6%, from the same period in the prior year, primarily due to lower volumes and prices related to the Magnolia system.



59


Offshore Pipelines and Services Segment

Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017

The table below contains key segment performance indicators for the three months ended September 30, 2018 and 2017 related to our Offshore Pipelines and Services segment (in thousands except operating data and percentages).
 
Three months ended September 30,
 
2018
 
2017
 
Change
 
%
Segment Financial and Operating Data:
 
 
 
 
 
 
 
Financial data:
 
 
 
 
 
 
 
Commodity sales
$
2,623

 
$
2,182

 
$
441

 
20
%
Services
16,708

 
12,178

 
4,530

 
37
%
Revenue from operations
19,331

 
14,360

 
4,971

 
35
%
Earnings in unconsolidated affiliates
21,450

 
15,510

 
5,940

 
38
%
Segment revenue
40,781

 
29,870

 
10,911

 
37
%
Cost of sales
1,959

 
558

 
1,401

 
251
%
Direct operating expenses
7,698

 
3,940

 
3,758

 
95
%
Other financial data:
 
 
 
 


 


Segment gross margin (1)
$
38,823

 
$
29,312

 
$
9,511

 
32
%
Operating data (2):
 
 
 
 


 


Average throughput (MMcf/d)
294.7

 
257.0

 
38

 
15
%
_______________________
(1) See Note 21 - Reportable Segments for a reconciliation of Segment Gross Margin to Income from continuing operations before income taxes.
(2) Excludes volumes from our unconsolidated affiliates.

Commodity sales. Commodity sales for the three months ended September 30, 2018 were $2.6 million, an increase of $0.4 million, or 20%, from the same period in the prior year, primarily due to increased sales from our acquisition of Panther in the third quarter of 2017 partially offset by a reduction of sales from lower volumes on our Gloria-Lafitte system due to less refinery load.

Services. Services for the three months ended September 30, 2018 were $16.7 million, an increase of $4.5 million, or 37%, from the same period in the prior year, primarily due to the impact of the adoption of Topic 606 of $5.0 million and additional volumes due to product rerouted from the Williams system at High Point Gas Gathering for $1.7 million. These increases were partially offset by lower guaranteed revenue of $1.2 million on our American Panther system and shipper imbalances on our Gloria-Lafitte system which reduced revenues by $0.8 million.
 
Earnings in unconsolidated affiliates. Earnings in unconsolidated affiliates for the three months ended September 30, 2018 were $21.5 million, an increase of $5.9 million, or 38%, from the same period in the prior year. This increase was primarily due to a 17% increase in equity ownership in Destin acquired in October 2017 combined with an increase in production volumes between periods from both Destin and Okeanos. Additionally, in September 2017, we acquired an additional 15.5% equity interest in Delta House. The impact of the increase in ownership in Delta House was partially offset by lower volumes in 2018 as compared to the prior year from a temporary curtailment of production flows as certain third-party owned upstream infrastructure required remediation work.

Cost of sales. Cost of sales for the three months ended September 30, 2018 were $2.0 million, an increase of $1.4 million, or 251%, from the same period in the prior year, primarily due to increased costs from Panther, which was acquired in the third quarter of 2017, of $1.0 million and shipper imbalances of $1.2 million. These increases in costs were partially offset by reductions from decreased production on our Gloria-Lafitte system of $0.7 million.

Direct operating expenses. Direct operating expenses for the three months ended September 30, 2018 were $7.7 million, an increase of $3.8 million, or 95%, from the same period in the prior year, primarily due to increases of $1.8 million in reimbursable direct operating expenses that were grossed up due to the adoption of Topic 606, $0.7 million in salaries and wages, $0.6 million in outside services and other operating expenses, $0.5 million in lease and rent expenses, and $0.2 million in repairs and maintenance costs related to the High Point system, Panther companies and Gloria-Lafitte.


60


Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017

The table below contains key segment performance indicators for the nine months ended September 30, 2018 and 2017 related to our Offshore Pipelines and Services segment (in thousands except operating data and percentages).
 
Nine months ended September 30,
 
2018
 
2017
 
Change
 
%
Segment Financial and Operating Data:
 
 
 
 
 
 
 
Financial data:
 
 
 
 
 
 
 
Commodity sales
$
7,879

 
$
8,385

 
$
(506
)
 
(6
)%
Services
46,832

 
32,945

 
13,887

 
42
 %
Revenue from operations
54,711

 
41,330

 
13,381

 
32
 %
Earnings in unconsolidated affiliates
39,864

 
45,895

 
(6,031
)
 
(13
)%
Segment revenue
94,575

 
87,225

 
7,350

 
8
 %
Cost of sales
6,105

 
6,487

 
(382
)
 
(6
)%
Direct operating expenses
23,205

 
10,010

 
13,195

 
132
 %
Other financial data:
 
 
 
 


 


Segment gross margin (1)
$
88,470

 
$
80,738

 
$
7,732

 
10
 %
Operating data (2):
 
 
 
 


 


Average throughput (MMcf/d)
308.0

 
328.0

 
(20.0
)
 
(6
)%
_______________________
(1) See Note 21 - Reportable Segments for a reconciliation of Segment Gross Margin to Income from continuing operations before income taxes.
(2) Excludes volumes from our unconsolidated affiliates.

Commodity sales. Commodity sales for the nine months ended September 30, 2018 were $7.9 million, a decrease of $0.5 million, or 6%, from the same period in the prior year, primarily due to lower volumes at our Gloria-Lafitte system partially offset by an increase in sales from the acquisition of Panther in the third quarter of 2017.

Services. Services for the nine months ended September 30, 2018 were $46.8 million, an increase of $13.9 million, or 42%, from the same period in the prior year, primarily due to the impact of the adoption of Topic 606 of $8.9 million, $1.4 million from the acquisitions in the third quarter of 2017 and additional volumes due to product rerouted from the Williams system at High Point Gas Gathering for $4.8 million. These increases were partially offset by shipper imbalances on our Gloria-Lafitte system which reduced revenues by $0.8 million.

Earnings in unconsolidated affiliates. Earnings in unconsolidated affiliates for the nine months ended September 30, 2018 were $39.9 million, a decrease of $6.0 million, or 13%, from the same period in the prior year, primarily due to a temporary curtailment of production flows on Delta House as certain third-party owned upstream infrastructure required remediation work. The decrease in earnings due to the production curtailment at Delta House was partially offset by the acquisition of an additional 15.5% equity interest in Delta House in September 2017, as well as a 17% increase in equity ownership in Destin which we acquired in October 2017 combined with an increase in production volumes between periods from both Destin and Okeanos.

Cost of sales. Cost of sales for the nine months ended September 30, 2018 were $6.1 million, a decrease of $0.4 million, or 6%, from the same period in the prior year, primarily due to reductions from decreased production on our Gloria-Lafitte system of $3.3 million, partially offset by increased costs from Panther, which was acquired in the third quarter of 2017, of $3.0 million.

Direct operating expenses. Direct operating expenses for the nine months ended September 30, 2018 were $23.2 million, an increase of $13.2 million, or 132%, from the same period in the prior year, primarily due to increases of $4.1 million in reimbursable direct operating expenses that were grossed up due to the adoption of Topic 606, $2.3 million in salaries and wages, $1.8 million in leases and rent costs, $1.7 million in insurance costs, $1.7 million in other operating expenses, $0.9 million in outside services, and $0.7 million in repairs and maintenance costs.


61


Terminalling Services Segment

Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017

The table below contains key segment performance indicators for the three months ended September 30, 2018 and 2017 related to our Terminalling Services segment (in thousands except operating data and percentages).
 
Three months ended September 30,
 
2018
 
2017
 
Change
 
%
Segment Financial and Operating Data:
 
 
 
 
 
 
 
Financial data:
 
 
 
 
 
 
 
Commodity sales
$
852

 
$
1,094

 
$
(242
)
 
(22
)%
Services
6,699

 
11,993

 
(5,294
)
 
(44
)%
Segment revenue
7,551

 
13,087

 
(5,536
)
 
(42
)%
Cost of sales
1,551

 
1,146

 
405

 
35
 %
Direct operating expenses
2,152

 
3,432

 
(1,280
)
 
(37
)%
Other financial data:
 
 
 
 


 


Segment gross margin (1)
$
3,848

 
$
8,509

 
$
(4,661
)
 
(55
)%
Operating data:
 
 
 
 


 


Contracted capacity (Bbl)
800,000
 
3,000,000
 
(2,200,000
)
 
(73
)%
Design capacity (Bbl) (2)(3)
3,000,000
 
3,000,000
 
—

 
—

Storage utilization (2)(3)
26.7
%
 
100.0
%
 
(73.3
)%
 
(73
)%
__________________
(1) See Note 21 - Reportable Segments for a reconciliation of Segment Gross Margin to Income from continuing operations before income taxes.
(2) Excludes terminals in our Refined Products as they have been classified as assets held for sale.
(3) Excludes storage utilization associated with our Marine Products.

Commodity sales. Commodity sales for the three months ended September 30, 2018 were $0.9 million, a decrease of $0.2 million, or 22%, from the same period in the prior year, driven by lower prices and volumes at the North Little Rock terminals, partially offset by increases at Caddo Mills.

Services. Services for the three months ended September 30, 2018 were $6.7 million, a decrease of $5.3 million, or 44%, from the same period in the prior year. The decline in services revenues were primarily driven by the sale of the Blackwater assets during the third quarter of 2018 which experienced a $3.5 million reduction in services revenue between periods. Additionally, services revenue was impacted by a $1.7 million reduction in storage and utilization at our Cushing terminal due to tank maintenance and a new contract with lower storage and rate terms.

Cost of sales. Cost of sales for the three months ended September 30, 2018 were $1.6 million, an increase of $0.4 million, or 35%, from the same period in the prior year, primarily due to volumetric loss at the Cushing terminals.

Direct operating expenses. Direct operating expenses for the three months ended September 30, 2018 were $2.2 million, a decrease of $1.3 million, or 37%, from the same period in the prior year, mainly due to the sale of Marine Products in the third quarter of 2018.



62


Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017

The table below contains key segment performance indicators for the nine months ended September 30, 2018 and 2017 related to our Terminalling Services segment (in thousands except operating data and percentages).

 
Nine months ended September 30,
 
2018
 
2017
 
Change
 
%
Segment Financial and Operating Data:
 
 
 
 
 
 
 
Financial data:
 
 
 
 
 
 
 
Commodity sales
$
9,526

 
$
8,644

 
$
882

 
10
 %
Services
31,784

 
38,900

 
(7,116
)
 
(18
)%
Segment revenue
41,310

 
47,544

 
(6,234
)
 
(13
)%
Cost of sales
9,952

 
7,612

 
2,340

 
31
 %
Direct operating expenses
10,605

 
9,503

 
1,102

 
12
 %
Other financial data:
 
 
 
 


 


Segment gross margin (1)
$
20,753

 
$
30,429

 
$
(9,676
)
 
(32
)%
Operating data:
 
 
 
 


 


Contracted capacity (Bbl)
1,866,667
 
3,000,000
 
(1,133,333
)
 
(38
)%
Design capacity (Bbl) (2)(3)
3,000,000
 
3,000,000
 
—

 
—

Storage utilization (2)(3)
62.2
%
 
100.0
%
 
(37.8
)%
 
(38
)%
__________________
(1) See Note 21 - Reportable Segments for a reconciliation of Segment Gross Margin to Income from continuing operations before income taxes.
(2) Excludes terminals in our Refined Products as they have been classified as assets held for sale.
(3) Excludes storage utilization associated with our Marine Products.

Commodity sales. Commodity sales for the nine months ended September 30, 2018 were $9.5 million, an increase of $0.9 million, or 10%, from the same period in the prior year, driven by higher prices, partially offset by lower volumes at the Caddo Mills and North Little Rock terminals.

Services. Services for the nine months ended September 30, 2018 were $31.8 million, a decrease of $7.1 million, or 18%, from the same period in the prior year. The decline in services revenues were primarily driven by a $6.1 million reduction in storage and utilization at our Cushing terminal due to tank maintenance and a new contract with lower storage and rate terms, combined with the sale of the Blackwater assets during the third quarter of 2018 which experienced a $3.3 million reduction in services revenue between periods. These decreases were partially offset by $2.6 million increase due to the adoption of Topic 606.

Cost of sales. Cost of sales for the nine months ended September 30, 2018 were $10.0 million, an increase of $2.3 million, or 31%, from the same period in the prior year, primarily due to an increase in volumetric loss of $0.5 million at the Cushing terminals and the adoption of Topic 606 which increased costs by approximately $1.6 million.

Direct operating expenses. Direct operating expense for the nine months ended September 30, 2018 were $10.6 million, an increase of $1.1 million, or 12%, from the same period in the prior year, primarily due $1.0 million in higher reimbursable costs on Marine Products.

Liquidity and Capital Resources

Overview

Our business is capital intensive and requires significant investment for the maintenance of existing assets and the acquisition and development of new systems and facilities.


63


Our primary sources of liquidity are:

•
cash flows from operating activities;
•
cash distributions from our unconsolidated affiliates;
•
borrowings under our Credit Agreement;
•
proceeds from private and public offerings of debt;
•
issuances of letters of credit in lieu of prepayments;
•
issuances of additional common units, preferred units or other securities;
•
proceeds from asset rationalization; and
•
cash and liquidity support from ArcLight and/or its affiliates.

Not all of these sources will be available to us at all times, or on terms acceptable to us. However, we believe cash generated from these sources will be sufficient to meet our short-term working capital requirements, medium-term maintenance capital expenditure requirements and quarterly cash distributions for the next twelve months. In the event these sources are not sufficient, we would pursue other sources of cash funding, including, but not limited to, additional forms of secured or unsecured debt or preferred equity financing, if available. In addition, we would reduce non-essential capital expenditures, controllable direct operating expenses and corporate expenses, as necessary, and our Partnership Agreement allows us to reduce or eliminate quarterly distributions on our common units. We plan to finance our growth capital expenditures primarily from the sale of non-core assets and through additional forms of debt or equity financing, if possible. Availability and terms of any financing or asset sales depend on market and other conditions, many of which are beyond our control. We may not be able to access financing or complete asset sales as, and when, desired.

Changes in natural gas, crude oil, NGL and condensate prices and the terms of our contracts may have a direct impact on our generation and use of cash from operations due to their impact on net income (loss), along with the resulting changes in working capital. In the past, we mitigated a portion of our anticipated commodity price risk associated with the volumes from our gathering and processing activities with fixed price commodity swaps. For additional information regarding our derivative activities, see the information provided under Part I, Item 3, Quantitative and Qualitative Disclosures about Market Risk in our 2017 Form 10-K.

The counterparties to certain of our commodity swap contracts are investment-grade rated financial institutions. Under these contracts, we may be required to provide collateral to the counterparties in the event that our potential payment exposure exceeds a predetermined collateral threshold. Collateral thresholds are set by us and each counterparty, as applicable, in the master contract that governs our financial transactions based on our and the counterparty’s assessment of creditworthiness. The assessment of our position with respect to the collateral thresholds is determined on a counterparty by counterparty basis and is impacted by the representative forward price curves and notional quantities under our swap contracts. Due to the interrelation between the representative natural gas and crude oil forward price curves, it is not practical to determine a single pricing point at which our swap contracts will meet the collateral thresholds as we may transact multiple commodities with the same counterparty. Depending on daily commodity prices, the amount of collateral posted can go up or down on a daily basis.

AMID Revolving Credit Agreement
On June 29, 2018, we amended our revolving credit facility agreement, dated March 8, 2017 (the “Original Credit Agreement”), by entering into the First Amendment to Second Amended and Restated Credit Agreement (the “Amendment” and, the Original Credit Agreement as amended by the Amendment, the “Credit Agreement”; capitalized terms used but not defined herein shall have the meanings assigned thereto in the Credit Agreement) with a syndicate of lenders and Bank of America, N.A., as administrative agent.

The Amendment adds a required prepayment event in an amount equal to 100% of the net cash proceeds received from Marine Products and Refined Products asset sales and any other disposition greater than $5 million. On July 31, 2018, we completed the sale of Marine Products. Net proceeds from this disposition were $208.6 million, exclusive of $5.7 million in advisory fees and other costs and were used to pay down the Credit Agreement.

The Amendment also amends our borrowing capacity as follows:

•
upon consummation of the Marine Products sale, the aggregate commitment under the Credit Agreement was automatically reduced by $200 million, such that total borrowing capacity under the Credit Agreement is now $700.0 million as of September 30, 2018;
•
upon consummation of the Refined Products sale, the aggregate commitment under the Credit Agreement shall be automatically reduced by 50% of the net cash proceeds of such disposition; and

64


•
upon consummation of any disposition greater than $15 million, the aggregate commitment under the Credit Agreement shall be automatically reduced by 25% of the net cash proceeds of such disposition.

The Credit Agreement matures on September 5, 2019, and is therefore being presented as a current liability in our Condensed Consolidated Balance Sheet as of September 30, 2018. We expect to execute a new revolving credit facility prior to the maturity of the Credit Agreement.
The Amendment adds a new pricing tier of LIBOR + 3.50% when Consolidated Total Leverage Ratio equals or exceeds 5.0:1.0. The Credit Agreement includes the following financial covenants, as amended by the Amendment and defined in the Credit Agreement, which financial covenants will be tested on a quarterly basis, for the fiscal quarter then ending:
 
Consolidated Interest Coverage Ratio
 
Consolidated Total Leverage Ratio
 
Consolidated Secured Leverage Ratio
June 30, 2018
2.50:1.00
 
6.15:1.00
 
4.00:1.00
September 30, 2018
2.00:1.00
 
6.25:1.00
 
3.75:1.00
December 31, 2018
1.75:1.00
 
5.50:1.00
 
3.50:1.00
March 31, 2019
1.75:1.00
 
5.00:1.00 (1)
 
3.50:1.00
June 30, 2019 and thereafter
2.00:1.00
 
5.00:1.00 (1)
 
3.50:1.00
_________________________
(1)  5.50:1.00 during a Specified Acquisition Period

As of September 30, 2018, we were in compliance with our Credit Agreement financial covenants, including those shown below:

Ratio
 
Actual
Consolidated Interest Coverage Ratio
 
2.37
Consolidated Total Leverage Ratio
 
5.65
Consolidated Secured Leverage Ratio
 
3.31

As of September 30, 2018, we had $600 million of borrowings, $39.0 million of letters of credit outstanding and $61.0 million of remaining borrowing capacity under the Credit Agreement, of which $41.0 million is currently available. For the nine months ended September 30, 2018 and 2017, the weighted average interest rate on borrowings under this facility was 6.23% and 4.85%, respectively.

On July 31, 2018, we completed the previously announced sale of our Marine Products terminalling business. Net proceeds from this disposition were approximately $208.6 million, exclusive of $5.7 million in advisory fees and other costs, and were used to repay borrowings outstanding under our Credit Agreement. See Note 4 - Acquisitions and Dispositions for additional information .

For additional information, see Note 13 - Debt Obligations to the accompanying Condensed Consolidated Financial Statements and Note 14 - Debt Obligations in our 2017 Form 10-K for additional information relating to our outstanding debt.

Acquisition Support and Reimbursement

During 2017, affiliates of ArcLight agreed and provided distribution support of $25.0 million pursuant to the support agreement that was executed in conjunction with the JPE Merger.  For further information related to the JPE Merger and distribution support agreement see Note 3 - Acquisitions in our 2017 Form 10-K. On March 11, 2018, the Partnership and Magnolia, an affiliate of ArcLight, entered into a Capital Contribution Agreement (the “Capital Contribution Agreement”) to provide additional capital and overhead support to us during the first three quarters of 2018 in connection with temporary curtailment of production flows at the Delta House platform (“Delta House”).  Pursuant to the Capital Contribution Agreement, Magnolia has agreed to provide quarterly capital contributions, in an amount to be agreed, up to the difference between the actual cash distribution received by us from Delta House and the quarterly cash distribution expected to be received had the production flows to Delta House not been curtailed. Subsequent to March 31, 2018, in accordance with this agreement, Magnolia agreed to an additional capital contribution of $9.4 million, which was paid in the second quarter of 2018. Subsequent to June 30, 2018, in accordance with this agreement, Magnolia agreed to a capital contribution of $8.3 million, which was paid in August 2018.

65



Working Capital

Our working capital requirements are primarily driven by changes in accounts receivable and accounts payable. These changes are impacted to a certain extent by changes in the prices of commodities that we buy and sell. In general, our working capital requirements increase in periods of rising commodity prices and decrease in periods of declining commodity prices. However, our working capital needs do not necessarily change at the same rate as commodity prices as both accounts receivable and accounts payable are impacted by the same commodity prices. In addition, the timing of payments received from our customers or paid to our suppliers can also cause fluctuations in working capital as we settle with most of our larger suppliers and customers on a monthly basis and often near the end of the month. We expect that our future working capital requirements will be impacted by these same factors.

We had a working capital deficit of $495.2 million as of September 30, 2018 due to the presentation of our revolving credit facility, which matures on September 5, 2019, as a short term liability. As discussed above, we expect to execute a new revolving credit facility prior to the maturity of our current agreement. As of December 31, 2017, we had working capital of $16.2 million.

Cash Flows

The following table reflects cash flows for the applicable periods (in thousands):
 
 
Nine months ended September 30,
 
 
2018
 
2017
Net cash provided by (used in):
 
 
 
 
Operating activities
 
$
12,944

 
$
15,005

Investing activities
 
151,848

 
1,986

Financing activities
 
(145,401
)
 
(315,106
)
Net decrease in cash, cash equivalents and restricted cash
 
$
19,391

 
$
(298,115
)

Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017

Operating Activities. During the nine months ended September 30, 2018, cash provided by operating activities was $12.9 million, a decrease of $2.1 million, as compared to the same period last year. The decrease in cash flows from operating activities resulted primarily from changes in operating assets and liabilities during the periods presented.
Investing Activities. During the nine months ended September 30, 2018, net cash provided by investing activities was $151.8 million, an increase of $149.9 million as compared to the same period last year. The increase in cash flows provided by investing activities was primarily from a reduction in acquisition activity of $71.4 million, a reduction in cash contributions to our unconsolidated affiliates of $44.0 million, an increase in proceeds from the disposal of property, plant and equipment of $38.0 million, partially offset by an increase in capital expenditures of $7.3 million.
Financing Activities. During the nine months ended September 30, 2018, net cash used in financing activities was $145.4 million, a decrease of $169.7 million as compared to the same period last year. The decline in cash used in financing activities was primarily driven by net reductions of our Credit Agreement of $97.9 million in 2018 as compared to net reductions of $178.6 million in the prior period, combined with a decrease in cash distributions to our General Partner of $75.6 million from 2017 for common control transactions associated with Delta House and a $22.4 million reduction in unitholder distributions between periods.

Distributions to our unitholders

In accordance with our Partnership Agreement, after making distributions to holders of our outstanding preferred units, we make distributions to our common unitholders of record within 45 days following the end of each quarter. Such distributions are determined each quarter by the Board based on the Board’s consideration of our financial position, earnings, cash flow, current and future business needs and other relevant factors at that time. The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record net losses for financial reporting purposes and may not make cash distributions during periods when we record net income for financial reporting purposes. In July 2018, we revised our capital allocation strategy, which included retaining an increased portion of operating cash flow through the reduction of common unit distributions.


66


We intend to pay a quarterly distribution for the foreseeable future although we do not have a legal obligation to make distributions except as provided in our Partnership Agreement. We are, however, subject to business and operational risks that could adversely affect our cash flow and ability to fund future distributions. Please read Risk Factors - Risks Related to Our Business - We may not have sufficient cash from operations to enable us to pay distributions to holders of our common units in our 2017 Form 10-K.

Distributable cash flow is an important non-GAAP supplemental measure used to compare basic cash flows generated by us in each period to the cash distributions paid to unitholders with respect to such period. The following displays our distribution coverage for the distributions paid with respect to the periods presented (in thousands):
  
 
Three months ended September 30,
 
Nine months ended September 30,
 
 
2018
 
2017
 
2018
 
2017
Adjusted EBITDA
 
$
35,217

 
$
42,350

 
$
138,873

 
$
133,689

 
 
 
 
 
 
 
 
 
Interest expense, net of capitalized interest
 
(22,267
)
 
(17,759
)
 
(55,834
)
 
(51,037
)
Amortization of deferred financing costs
 
2,493

 
1,154

 
5,142

 
3,610

Unrealized (loss) gain on interest rate swaps
 
(33
)
 
1,646

 
(6,123
)
 
3,658

Letter of credit fees
 
—

 
(11
)
 
21

 
210

Maintenance capital
 
(2,553
)
 
(2,449
)
 
(9,631
)
 
(6,570
)
Preferred unit distributions
 
(8,354
)
 
(2,870
)
 
(25,061
)
 
(16,311
)
Distributable cash flow
 
$
4,503

 
$
22,061

 
$
47,387

 
$
67,249

 
 
 
 
 
 
 
 
 
Limited Partner distributions
 
$
5,463

 
$
21,345

 
$
49,061

 
$
67,648

 
 
 
 
 
 
 
 
 
Distribution coverage
 
0.8
x
 
1.0
x
 
1.0
x
 
1.0
x

During the three months ended September 30, 2018, we paid a total of $5.5 million of distributions to our unitholders associated with the second quarter of 2018. This was made possible primarily by cash on hand plus distributions received relating to our unconsolidated affiliates and distribution support pursuant to our sponsor’s agreement to offset the shortfall at Delta House.

To create long-term value and balance sheet flexibility, we continually evaluate our capital allocation strategy.  In July 2018, we revised our capital allocation strategy, which includes:
•
continue to identify and sell non-core assets;
•
use part of assets sales proceeds to deleverage the company;
•
retain an increased portion of operating cash flow through the reduction of common unit distribution;
•
invest in assets core to our business; and
•
continue to develop infrastructure along the Gulf Coast.

We believe cash flow retention and asset sales will enable us to reallocate capital to meaningful growth opportunities, promote balance sheet flexibility and reduce indebtedness. In addition, the improved financial metrics should reduce our borrowing costs.

On October 25, 2018, we announced that the Board of Directors of our General Partner declared a quarterly cash distribution of $0.1031 per common unit, or $0.4125 per common unit annualized, with respect to the third quarter of 2018. The distribution will be paid on November 14, 2018 to unitholders of record as of the close of business on November 6, 2018. The quarterly cash distribution for the third quarter of 2018 is consistent with our second quarter of 2018 per common unit distribution. We and the Board of Directors of our General Partner will continue to evaluate our distribution policy as we execute our plans for growth, deleveraging and capital access.

Capital Requirements

For the three and nine months ended September 30, 2018, capital expenditures totaled $16.8 million and $73.3 million, respectively. This included expansion capital expenditures of $13.8 million and $61.0 million, maintenance capital expenditures of $2.6 million and $9.6 million, and reimbursable project expenditures (capital expenditures for which we expect to be reimbursed for all or part of the expenditures by a third party) of $0.5 million and $2.7 million, respectively, for the three and nine months ended September 30, 2018.

67


Going Concern Assessment and Management’s Plans

Pursuant to FASB ASC 205-40, we are required to assess our ability to continue as a going concern for a period of one year from the date of the issuance of these financial statements. Substantial doubt about an entity’s ability to continue as a going concern exists when relevant conditions and events, considered in the aggregate, indicate that it is probable that the entity will be unable to meet its obligations as they become due within one year from the financial statement issuance date. As discussed above in “AMID Revolving Credit Agreement”, our Credit Agreement matures on September 5, 2019 and has not been renewed as of the date of the issuance of these financial statements. 

As discussed in Note 19 - Related Party Transactions, on September 28, 2018, the Board of Directors of our General Partner received a non-binding proposal from Magnolia, an affiliate of ArcLight to acquire the common units that it does not already own. The transaction is currently in the due diligence phase and requires approval of the Conflicts Committee of the Board of Directors. As a result of this ongoing process, management has deferred finalization of a renewal of the Credit Agreement. Until we have greater clarity regarding the potential buyout offer from ArcLight, management has purposefully delayed maturity extensions and other balance sheet modifications due to unreasonable costs and burdens to the company. However, we expect to make any renewals, extensions or appropriate capital structure adjustments necessary to maintain adequate liquidity to conduct normal operations for the foreseeable future.

While the Partnership intends to renew or extend the terms of its Credit Agreement, until such time as we have executed an agreement to refinance or extend the maturity of our Credit Agreement, we cannot conclude that it is probable we will do so, and accordingly, this raises substantial doubt about our ability to continue as a going concern.


Critical Accounting Estimates

See Note 2 - Recent Accounting Pronouncements to the accompanying Condensed Consolidated Financial Statements for a discussion of the potential impact of recent accounting standards on our unaudited Condensed Consolidated Financial Statements and an update to our critical accounting policy related to Goodwill.

For a discussion of the impact of our other critical accounting policies and estimates on our Consolidated Financial Statements, refer to Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations included in our 2017 Form 10-K.

Off-Balance Sheet Arrangements

There were no material changes to off-balance sheet arrangements during the nine months ended September 30, 2018.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to certain market risks that are inherent in our financial instruments and arise from changes in commodity prices and interest rates. We do not hold or purchase financial instruments or derivative financial instruments for trading purposes. A discussion of our market risk exposure in financial instruments is presented below.

For an in-depth discussion of our market risks, See Item 7A. Quantitative and Qualitative Disclosures about Market Risk in our Annual Report on Form 10-K for the year ended December 31, 2017.

Commodity Price Risk

We manage exposure to commodity price risk in our business segments through the structure of our sales and supply contracts and through a managed hedging program. Our risk management policy permits the use of financial instruments to reduce the exposure to changes in commodity prices that occur in the normal course of business but prohibits the use of financial instruments for trading or to speculate on future changes in commodity prices. See Note 7 - Risk Management Activities to our Condensed Consolidated Financial Statements included in Part I, Item I of this Quarterly Report on Form 10-Q for additional information.

We have entered into contracts to hedge a portion of our NGL and crude oil exposure in 2018. As of September 30, 2018, we have not been required to post collateral with our counterparties. The counterparties are not required to post collateral with us in connection with their derivative positions. Netting agreements are in place with our counterparties that permit us to offset our commodity derivative asset and liability positions.


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Sensitivity analysis - The table below summarizes our commodity-related financial derivative instruments and fair values, as well as the effect on fair value of an assumed hypothetical 10% change in the underlying price of the commodity (in thousands).

Commodity Swaps
 
Fair Value Asset (Liability)
 
Effect of 10% Price Increase
 
Effect of 10% Price Decrease
NGLs Fixed Price (gallons)
 
$(352)
 
$(4,423)
 
$(9,541)

Interest Rate Risk

Our revolving credit facility bears interest at a variable rate and exposes us to interest rate risk. To manage the impact of the interest rate risk associated with our Credit Agreement, we enter into interest rate swaps from time to time, effectively converting a portion of the cash flows related to our long-term variable-rate debt into fixed-rate cash flows. For the quarter ended September 30, 2018, we had exposure to changes in interest rates on our indebtedness associated with our Credit Agreement.

As of September 30, 2018, we had a combined notional principal amount of $550.0 million of variable to fixed interest rate swap agreements. As of September 30, 2018, the maximum length of time over which we have hedged a portion of our exposure due to interest rate risk is through December 31, 2022. Based on our unhedged interest rate exposure to variable rate debt outstanding as of September 30, 2018, a hypothetical increase or decrease in interest rates by 1.0% would have changed our interest expense by $0.5 million for the nine months ended September 30, 2018.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We maintain a system of disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit to the SEC under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms, and that such information is accumulated and communicated to the management of our General Partner, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

As of the end of the period covered by this report, we carried out an evaluation, with the participation of our principal executive officer and principal financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act). Based on our evaluation, our principal executive officer and principal financial officer concluded that the Partnership’s disclosure controls and procedures were not effective as of September 30, 2018, as a result of the material weaknesses in internal control over financial reporting that remain outstanding from prior periods.

Progress towards Material Weakness Remediation
In prior filings, we identified and reported material weaknesses in the Company’s internal control over financial reporting which still exist as of September 30, 2018. We have formulated our remediation plan and are developing and executing testing procedures. In response to the identified material weaknesses, our management, with oversight from our audit committee, has dedicated resources to improve our control environment and to remedy the identified material weaknesses.
While plans have been made to enhance our internal control over financial reporting relating to the material weaknesses, management continues to implement and test our processes and procedures and additional time is required to complete implementation and to assess and ensure the sustainability of these procedures. Management believes these actions will be effective in remediating the material weaknesses described above and will continue to devote significant time and attention to these remediation efforts. However, the material weaknesses cannot be considered remediated until the applicable controls operate for a sufficient period of time and management has concluded, through testing, that these controls are operating effectively.

Changes in internal control over financial reporting

There were no changes in internal control over financial reporting that occurred during the quarter ended September 30, 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

The certifications of our principal executive officer and principal financial officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a) are filed with this Quarterly Report as Exhibits 31.1 and 31.2. The certifications of our principal executive officer and principal financial officer pursuant to 18 U.S.C. Section 1350 are furnished with this Quarterly Report as Exhibits 32.1 and 32.2.


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Table of Contents

PART II. OTHER INFORMATION

Item 1. Legal Proceedings
While the ultimate impact of any proceedings cannot be predicted with certainty, our management believes that the resolution of any of our pending proceedings will not have a material adverse effect on our financial condition or results of operations. See Note 18 - Commitments and Contingencies in the Condensed Consolidated Financial Statements included in this report for additional information.

Item 1A. Risk Factors

In addition to the information about our business, financial conditions and results of operations set forth in this Quarterly Report on Form 10-Q, careful consideration should be given to the risk factors discussed under the caption Risk Factors in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2017 and the risk factor described below. Such risks are not the only risks we face. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also have a material adverse effect on our business or our operations.

There can be no assurance that the unsolicited offer from ArcLight to acquire all common units not owned by it will be agreed upon, approved and ultimately consummated, and the terms of any such transaction may differ materially from those originally proposed by ArcLight.

On September 28, 2018, the Board of Directors of our General Partner received a non-binding proposal from Magnolia, an affiliate of ArcLight, pursuant to which Magnolia would acquire all of our common units that Magnolia and its affiliates do not already own in exchange for $6.10 per common unit.

The transaction, as proposed, is subject to negotiation. Any definitive agreement with respect to such transaction is subject to approval by the Board of Directors of the General Partner and unitholder approvals. Such definitive agreement would be expected to contain customary closing conditions, including standard regulatory notifications and approvals.

As a result, we cannot predict whether the terms of such transaction will be agreed upon by ArcLight and the Conflicts Committee of the Board of Directors of the General Partner, or whether any such transactions would be approved by the requisite votes of our unitholders.

We also cannot predict the timing, final structure or other terms of any potential transaction, and the terms of any such transaction may differ materially from those originally proposed by ArcLight. The pendency of any such proposed transaction may have had, and may continue to have, an adverse impact on the market price of our common units.

In addition, we expect to incur a number of non-recurring transaction-related costs associated with negotiating the proposed transaction and may have difficulty motivating and retaining employees. Furthermore, the process of negotiating the proposed transaction can divert management attention and resources.

If we are unable to repay, extend or refinance our existing and future debt as it becomes due on terms reasonably acceptable to us, or at all, we may be unable to continue as a going concern.

Absent any action with respect to the repayment or refinancing of our existing indebtedness or any waivers or amendments to the agreements governing our existing indebtedness, our Credit Agreement is scheduled to mature on September 5, 2019.  Although we are actively engaged with the Credit Agreement lender group, we may not be able to extend, replace or refinance our existing Credit Agreement on terms reasonably acceptable to us, or at all, with our current lender group or with replacement lenders. If we are able to obtain replacement financing, it may be more costly or on terms more burdensome than our current Credit Agreement. In addition, we may not be able to access other external financial resources sufficient to enable us to repay the debt outstanding under our Credit Agreement upon its maturity. If we fail to satisfy our obligations with respect to our indebtedness or fail to comply with the financial and other restrictive covenants contained in the Credit Facility or other agreements governing our indebtedness, an event of default could result, which could permit acceleration of such debt and acceleration of our other debt. Any accelerated debt would become immediately due and payable.






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---Item 6. Exhibits
Exhibit
Number
Exhibit
Amendment No. 1 to Contribution Agreement, dated June 1, 2018, by and among American Midstream Partners, LP, American Midstream GP, LLC and Southcross Holdings LP (incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on June 1, 2018).
Certificate of Limited Partnership of American Midstream Partners, LP (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 (Commission File No. 333-173191) filed on March 31, 2011).
Fifth Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP, dated April 25, 2016 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on April 29, 2016).
Amendment No. 1 to Fifth Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP, effective May 1, 2016 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on June 22, 2016).

Amendment No. 2 to Fifth Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP, dated October 31, 2016 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on November 4, 2016).
Amendment No. 3 to Fifth Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP, dated March 8, 2017 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on March 8, 2017).
Composite Fifth Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP, including Amendment No. 1, Amendment No. 2 and Amendment No. 3 (incorporated by reference to Exhibit 3.19 to the Annual Report on Form 10-K (Commission File No. 001-35257) filed on March 28, 2017).
Amendment No. 4 to Fifth Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP, dated May 25, 2017 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on May 31, 2017).
Amendment No. 5 to Fifth Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP, dated June 30, 2017 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on July 14, 2017).
Amendment No. 6 to Fifth Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP, dated September 7, 2017 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on September 11, 2017).
Amendment No. 7 to Fifth Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP, dated October 26, 2017 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on October 30, 2017).
Amendment No. 8 to Fifth Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP, dated January 25, 2018 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on January 31, 2018).
Amendment No. 9 to the Fifth Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP, dated as of May 3, 2018 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on May 4, 2018).
Certificate of Formation of American Midstream GP, LLC (incorporated by reference to Exhibit 3.4 to the Registration Statement on Form S-1 (Commission File No. 333-173191) filed on March 31, 2011).
Fourth Amended and Restated Limited Liability Company Agreement of American Midstream GP, LLC (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on August 15, 2017).

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Table of Contents

**101.INS
XBRL Instance Document
**101.SCH
XBRL Taxonomy Extension Schema Document
**101.CAL
XBRL Taxonomy Extension Calculation Linkbase Document
**101.DEF
XBRL Taxonomy Extension Definition Linkbase Document
**101.LAB
XBRL Taxonomy Extension Label Linkbase Document
**101.PRE
XBRL Taxonomy Extension Presentation Linkbase Document
 
 
*
Filed herewith.
**
Furnished herewith.

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SIGNATURES
Pursuant to the requirements 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.
Date: November 9, 2018
 
AMERICAN MIDSTREAM PARTNERS, LP
 
 
By:
American Midstream GP, LLC, its General Partner
 
 
By:
/s/ Lynn L. Bourdon III
 
Lynn L. Bourdon III
 
Chairman, President and Chief Executive Officer
 
(Principal Executive Officer)
 
 
By:
/s/ Eric T. Kalamaras
 
Eric T. Kalamaras
 
Senior Vice President and Chief Financial Officer
 
(Principal Financial Officer)


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