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
June 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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post 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
¨ (Do not check if a smaller reporting company)
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 52,981,070 common units, 11,009,729 Series A Units, and 9,241,642 Series C Units of American Midstream Partners, LP outstanding as of August 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.

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
 
 
 
Page
Item 1.
 
 
 
 
 
 
Item 2.
Item 3.
Item 4.
Item 1.
Item 1A.
Item 6.

3


PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
American Midstream Partners, LP and Subsidiaries
Condensed Consolidated Balance Sheets
(Unaudited, In thousands)
 
June 30, 2018
 
December 31, 2017
 
 
 
 
Assets
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
17,037

 
$
8,782

Restricted cash
24,541

 
20,352

Accounts receivable, net of allowance for doubtful accounts of $372 and $225 as of June 30, 2018 and December 31, 2017, respectively
88,352

 
98,132

Inventory
2,661

 
2,966

Other current assets
30,570

 
23,420

Total current assets
163,161

 
153,652

Property, plant and equipment, net
992,659

 
1,095,585

Goodwill
51,723

 
128,866

Restricted cash-long term
5,058

 
5,045

Intangible assets, net
139,083

 
174,010

Investments in unconsolidated affiliates
331,530

 
348,434

Other assets, net
27,984

 
17,874

Assets held for sale
230,129

 
—

Total assets
$
1,941,327

 
$
1,923,466

Liabilities, Equity and Partners’ Capital
 
 
 
Current liabilities
 
 
 
Accounts payable
$
53,093

 
$
41,102

Accrued gas and crude oil purchases
15,862

 
19,986

Accrued expenses and other current liabilities
67,395

 
68,854

Current portion of long-term debt
3,624

 
7,551

Total current liabilities
139,974

 
137,493

Asset retirement obligations
67,358

 
66,194

Other long-term liabilities
15,426

 
2,080

Long-term debt
1,278,062

 
1,201,456

Deferred tax liability
8,628

 
8,123

Liabilities held for sale
2,237

 
—

Total liabilities
1,511,685

 
1,415,346

Commitments and contingencies (Note 18)


 


Convertible preferred units
317,180

 
317,180

Equity and partners’ capital
 
 
 
General Partner interests (965 and 965 units issued and outstanding as of June 30, 2018 and December 31, 2017, respectively)
(76,307
)
 
(96,552
)
Limited Partner interests (52,972 and 52,711 units issued and outstanding as of June 30, 2018 and December 31, 2017, respectively)
175,003

 
273,703

Accumulated other comprehensive income
23

 
28

Total partners’ capital
98,719

 
177,179

Noncontrolling interests
13,743

 
13,761

Total equity and partners’ capital
112,462

 
190,940

Total liabilities, equity and partners’ capital
$
1,941,327


$
1,923,466


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


4


American Midstream Partners, LP and Subsidiaries
Condensed Consolidated Statements of Operations
(Unaudited, in thousands, except per unit amounts)
 
 
Three months ended June 30,
 
Six months ended June 30,
 
 
2018
 
2017
 
2018
 
2017
Revenue:
 
 
 
 
 
 
 
 
Commodity sales
 
$
164,737

 
$
124,476

 
$
323,599

 
$
247,997

Services
 
55,835

 
37,355

 
102,741

 
77,547

     (Loss)/Gain on commodity derivatives, net
 
(355
)
 
199

 
(296
)
 
564

Total revenue
 
220,217

 
162,030

 
426,044

 
326,108

Operating expenses:
 
 
 
 
 
 
 
 
Costs of sales
 
161,508

 
115,020

 
311,674

 
230,488

Direct operating expenses
 
21,742

 
18,709

 
45,189

 
36,114

Corporate expenses
 
23,372

 
27,374

 
46,064

 
57,487

Depreciation, amortization and accretion
 
21,236

 
26,483

 
43,234

 
52,053

Loss/(Gain) on sale of assets, net
 
—

 
18

 
(95
)
 
(3
)
Total operating expenses
 
227,858

 
187,604

 
446,066

 
376,139

Operating loss
 
(7,641
)
 
(25,574
)
 
(20,022
)
 
(50,031
)
Other income (expense), net
 
 
 
 
 
 
 
 
     Interest expense, net of capitalized interest
 
(19,691
)
 
(17,122
)
 
(33,567
)
 
(35,078
)
Other income (expense), net
 
169

 
—

 
191

 
(37
)
Earnings in unconsolidated affiliates
 
10,446

 
17,552

 
23,119

 
32,954

Loss from continuing operations before income taxes
 
(16,717
)
 
(25,144
)
 
(30,279
)
 
(52,192
)
Income tax expense
 
(557
)
 
(757
)
 
(837
)
 
(1,880
)
Loss from continuing operations
 
(17,274
)
 
(25,901
)
 
(31,116
)
 
(54,072
)
Loss from discontinued operations
 
—

 
(1,801
)
 
—

 
(2,511
)
Net loss
 
(17,274
)
 
(27,702
)
 
(31,116
)
 
(56,583
)
Less: Net income attributable to noncontrolling interests
 
13

 
1,462

 
57

 
2,765

Net loss attributable to the Partnership
 
$
(17,287
)
 
$
(29,164
)
 
$
(31,173
)
 
$
(59,348
)
 
 
 
 
 
 
 
 
 
General Partner’s interest in net loss
 
$
(225
)
 
$
(375
)
 
$
(405
)
 
$
(795
)
Limited Partners’ interest in net loss
 
$
(17,062
)
 
$
(28,789
)
 
$
(30,768
)
 
$
(58,553
)
 
 
 
 
 
 
 
 
 
Distribution declared per common unit (Note 15)
 
$
0.1031

 
$
0.4125

 
$
0.5156

 
$
0.8250

Limited Partners’ net loss per common unit:
 
 
Basic and diluted:
 
 
 
 
 
 
 
 
Loss from continuing operations
 
$
(0.48
)
 
$
(0.69
)
 
$
(0.89
)
 
$
(1.41
)
Loss from discontinued operations
 
—

 
(0.03
)
 
—

 
(0.05
)
Net loss per common unit
 
$
(0.48
)
 
$
(0.72
)
 
$
(0.89
)
 
$
(1.46
)
 
 
 
 
 
 
 
 
 
Weighted average number of common units outstanding:
Basic and diluted
 
52,969

 
51,870

 
52,869

 
51,870


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



5


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






Three months ended June 30,
 
Six months ended June 30,
 
2018
 
2017
 
2018
 
2017
Net loss
$
(17,274
)
 
$
(27,702
)
 
$
(31,116
)
 
$
(56,583
)
Unrealized gain (loss) related to postretirement benefit plan
11

 
24

 
(5
)
 
42

Comprehensive loss
(17,263
)
 
(27,678
)
 
(31,121
)
 
(56,541
)
Less: Comprehensive income attributable to noncontrolling interests
13

 
1,462

 
57

 
2,765

Comprehensive loss attributable to the Partnership
$
(17,276
)
 
$
(29,140
)
 
$
(31,178
)
 
$
(59,306
)

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



6


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
(795
)
 
(58,553
)
 
—

 
(59,348
)
 
2,765

 
(56,583
)
Contributions
23,130

 
4,000

 
—

 
27,130

 
—

 
27,130

Distributions
(594
)
 
(63,574
)
 
—

 
(64,168
)
 
—

 
(64,168
)
Contributions from NCI owners
—

 
—

 
—

 
—

 
296

 
296

Distributions to NCI owners
—

 
—

 
—

 
—

 
(1,795
)
 
(1,795
)
LTIP vesting
(4,633
)
 
4,633

 
—

 
—

 
—

 
—

Tax netting repurchase
—

 
(1,642
)
 
—

 
(1,642
)
 
—

 
(1,642
)
Equity compensation expense
3,873

 
1,360

 
—

 
5,233

 
—

 
5,233

Post-retirement benefit plan
—

 
—

 
42

 
42

 
—

 
42

Balances at June 30, 2017
$
(26,664
)

$
502,311


$
2


$
475,649


$
18,021

 
$
493,670

 
 
 
 
 
 
 
 
 
 
 
 
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
)
Net (loss) income
(405
)
 
(30,768
)
 
—

 
(31,173
)
 
57

 
(31,116
)
Contributions
23,264

 
—

 
—

 
23,264

 
—

 
23,264

Distributions
(795
)
 
(60,088
)
 
—

 
(60,883
)
 
—

 
(60,883
)
Distributions to NCI owners
—

 
—

 
—

 
—

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

 
—

 
(38
)
 
—

 
(38
)
LTIP vesting
(3,836
)
 
3,836

 
—

 
—

 
—

 
—

Tax netting repurchase
—

 
(1,128
)
 
—

 
(1,128
)
 
—

 
(1,128
)
Equity compensation expense
2,194

 
—

 
—

 
2,194

 
—

 
2,194

Post-retirement benefit plan

—

 
—

 
(5
)
 
(5
)
 
—

 
(5
)
Balances at June 30, 2018
$
(76,307
)
 
$
175,003

 
$
23

 
$
98,719

 
$
13,743

 
$
112,462


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



7

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

 
Six months ended June 30,

 
2018
 
2017
Cash flows from operating activities
 

 

Net loss
 
$
(31,116
)
 
$
(56,583
)
Adjustments to reconcile net loss to net cash provided by operating activities including discontinued operations:
 

 

Depreciation, amortization and accretion
 
43,234

 
59,521

Amortization of debt issuance costs
 
2,649

 
2,456

Amortization of weather derivative premium
 
550

 
475

Unrealized (gain) loss on derivatives contracts, net
 
(5,851
)
 
3,020

Non-cash compensation expense
 
2,194

 
5,233

Gain on sale of assets, net
 
(95
)
 
(176
)
Corporate overhead support
 
—

 
4,000

Other non-cash items
 
(22
)
 
1,906

   Earnings in unconsolidated affiliates
 
(23,119
)
 
(32,954
)
Distributions from unconsolidated affiliates
 
21,404

 
32,954

Deferred tax expense
 
505

 
1,250

Bad debt expense
 
406

 
515

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

Accounts receivable
 
5,019

 
8,761

Inventory
 
(519
)
 
(1,738
)
Risk management assets and liabilities
 
(989
)
 
(1,157
)
Other current assets
 
(4,640
)
 
(6,447
)
Other assets, net
 
(3,565
)
 
147

Accounts payable
 
13,858

 
(12,069
)
Accrued gas and crude oil purchases
 
(4,052
)
 
6,320

Accrued expenses and other current liabilities
 
(6,903
)
 
13,216

Asset retirement obligations
 
(7
)
 
(45
)
Other liabilities
 
19

 
(247
)
Net cash provided by operating activities
 
8,960


28,358

 
 
 
 
 
Cash flows from investing activities
 
 
 

Acquisitions, net of cash acquired and settlements
 
—

 
(32,000
)
Contributions to unconsolidated affiliates
 
(2,946
)
 
—

Additions to property, plant and equipment and other
 
(56,533
)
 
(44,039
)
Proceeds from disposals of property, plant and equipment
 
8

 
121

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

 
150

Distributions from unconsolidated affiliates, return of capital
 
23,150

 
5,440

Net cash used in investing activities
 
(36,321
)
 
(70,328
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

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



 
Six months ended June 30,

 
2018
 
2017
Cash flows from financing activities
 
 
 

Contributions
 
23,264

 
23,130

Distributions
 
(52,529
)
 
(60,494
)
Contribution from noncontrolling interest owners
 
—

 
296

Distributions to noncontrolling interests owners
 
(75
)
 
(1,795
)
LTIP tax netting unit repurchase
 
(1,128
)
 
(1,642
)
Payment of debt issuance costs
 
(2,742
)
 
(2,116
)
Payment of long-term debt
 
(644
)
 
(1,078
)
Payment of 3.97% Senior Notes
 
(878
)
 
—

Payments of other debt
 
(4,316
)
 
(3,447
)
Payments of credit agreement
 
(187,200
)
 
(383,908
)
Borrowings on credit agreement
 
265,600

 
173,700

Other
 
830

 
—

Net cash provided by (used in) financing activities
 
40,182

 
(257,354
)
 
 
 
 
 
Net increase (decrease) in cash, cash equivalents, and restricted cash
 
12,821


(299,324
)
Cash, cash equivalents, and restricted cash, beginning of period
 
34,179

 
329,230

Cash, cash equivalents, and restricted cash, end of period
 
$
47,000

 
$
29,906

 
 
 
 
 
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
 
$
17,037

 
$
5,903

Cash included in assets held for sale
 
364

 
—

Restricted cash - current
 
24,541

 
18,965

Restricted cash - non-current
 
5,058

 
5,038

Total cash, cash equivalents and restricted cash, end of period
 
$
47,000

 
$
29,906


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 77.0% directly owned by High Point Infrastructure Partners, LLC (“HPIP”) and 23.0% 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 specialty chemical products and 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 (“Annual Report”) 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, steam heating and truck weighing at our marine terminals. 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. There was no impact of the retrospective adoption of this ASU on the Partnership’s Condensed Consolidated Statements of Cash Flows.

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




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 2016-15 and ASU 2016-18 as of January 1, 2018. Previously reported financial statements have been adjusted to reflect the above changes, as follows (in thousands):
 
Six months ended June 30, 2017

Condensed Consolidated Statements of Cash Flows
As Previously Reported
 
Effect of Adoption
 
As Adjusted
Cash flows from operating activities
 
 
 
 
 
Net loss
$
(56,583
)
 
$
—

 
$
(56,583
)
Adjustments to reconcile net loss to net cash provided by operating activities including discontinued operations
78,200

 
—

 
78,200

Restricted cash, short-term
(3,135
)
(1 
) 
3,135

(1 
) 
—

Changes in operating assets and liabilities, net of effects of assets acquired and liabilities assumed (excluding restricted cash)
6,794

(1 
) 
(53
)
(1 
) 
6,741

          Net cash provided by (used in) operating activities
25,276

 
3,082

 
28,358

Cash flows from investing activities
 
 
 
 
 
Restricted cash
302,643

(1 
) 
(302,643
)
(1 
) 
—

Other investing activities (excluding restricted cash)
(70,328
)
 
—

 
(70,328
)
          Net cash provided by (used in) investing activities
232,315

 
(302,643
)
 
(70,328
)
Cash flows from financing activities
 
 
 
 
 
Other financing activities
(257,354
)
 
—

 
(257,354
)
          Net cash used in financing activities (excluding restricted cash)
(257,354
)
 
—

 
(257,354
)
          Net increase (decrease) in cash, cash equivalents, and restricted cash
237

 
(299,561
)
 
(299,324
)
Cash, cash equivalents and Restricted Cash
 
 
 
 
 
     Beginning of period
5,666

 
323,564

 
329,230

     End of period
$
5,903

 
$
24,003

 
$
29,906

_____________________________________________ 
(1) ASU 2016-18 adjustment to move restricted cash to be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the condensed consolidated statement of cash flows.

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


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



Leases (Topic 842) - In February 2016, the FASB issued ASU No. 2016-02 (“Topic 842”) “Leases”, which supersedes the lease recognition requirements in ASC Topic 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 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 intend 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.
Financial Instruments - In June 2016, the FASB issued ASU No. 2016-13 (“ASU 2016-13”), “Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments”. 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.

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 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 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.


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



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, the Partnership had approximately $128.9 million of goodwill on its consolidated balance sheet within seven reporting units. Of this amount, approximately $46.8 million of goodwill in two reporting units was at risk of failing the one-step quantitative test.

Specifically, the Silver Dollar reporting unit in the Liquids Pipelines and Services segment had $35.7 million in goodwill. As described in Note 10 in our 2017 Form 10-K, we recorded an impairment on the Silver Dollar Reporting unit during the fourth quarter of 2017; hence, fair value approximates the adjusted net book value subsequent to impairment. The 2017 impairment 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 the Terminalling Services segment had $11.1 million in goodwill as of December 31, 2017, and fair value exceeded book value by 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 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 fair value exceeds book value could be negatively impacted.

As of June 30, 2018, the Partnership had approximately $51.7 million of goodwill on its consolidated balance sheet within five reporting units as two of the seven reporting units, as of December 31, 2017, are now classified as held for sale. There were no triggering events during the six months ended June 30, 2018 and, therefore, we have not quantitatively updated our assessments.
 
(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 June 30, 2018
 
Six months ended June 30, 2018
Condensed Consolidated Statements of Operations
 
As Reported
 
Adjustments
 
Amounts without Adoption of Topic 606
 
As Reported
 
Adjustments
 
Amounts without Adoption of Topic 606
Revenue
 
 
 
 
 
 
 
 
 
 
 
 
Commodity sales
 
$
164,737

 
$
12,535

 
$
177,272

 
$
323,599

 
$
17,777

 
$
341,376

Services
 
55,835

 
(12,304
)
 
43,531

 
102,741

 
(14,985
)
 
87,756

Operating expenses
 
 
 
 
 
 
 
 
 
 
 
 
Costs of sales
 
161,508

 
5,409

 
166,917

 
311,674

 
8,574

 
320,248

Direct operating expenses
 
21,742

 
(4,550
)
 
17,192

 
45,189

 
(5,006
)
 
40,183

Operating loss
 
(7,641
)
 
(628
)
 
(8,269
)
 
(20,022
)
 
(776
)
 
(20,798
)
Net loss attributable to the Partnership
 
(17,287
)
 
(628
)
 
(17,915
)
 
(31,173
)
 
(776
)
 
(31,949
)
 
 
 
 
 
 
 
 
 
 
 
 
 
General Partner’s interest in net loss
 
(225
)
 
(8
)
 
(233
)
 
(405
)
 
(10
)
 
(415
)
Limited Partners’ interest in net loss
 
(17,062
)
 
(620
)
 
(17,682
)
 
(30,768
)
 
(766
)
 
(31,534
)


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



 
 
As of June 30, 2018
Condensed Consolidated Balance Sheets
 
As Reported
 
Adjustments
 
Amounts without Adoption of Topic 606
Assets
 
 
 
 
 
 
Accounts receivable, net
 
$
88,352

 
$
(76,684
)
 
$
11,668

Unbilled revenue
 
—

 
76,684

 
76,684

Other current assets
 
30,570

 
(252
)
 
30,318

Other assets, net
 
27,984

 
(6,984
)
 
21,000

Liabilities
 
 
 
 
 
 
Other long-term liabilities
 
15,426

 
(13,865
)
 
1,561

Liabilities held for sale
 
2,237

 
(690
)
 
1,547


The majority of the adjustments in the table above were associated with our natural gas gathering and processing, transportation pipeline and our 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 June 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
$
3,521

 
$
—

 
$
5,473

 
$
2,587

 
$
—

 
$
11,581

     NGLs
18,059

 
—

 
—

 
33

 
—

 
18,092

     Condensate
14,154

 
—

 
—

 
63

 
—

 
14,217

     Crude oil
—

 
116,516

 
—

 
—

 
—

 
116,516

     Other sales (1)
635

 
—

 
2

 
24

 
3,670

 
4,331

 
 
 
 
 
 
 
 
 
 
 
 
Services:
 
 
 
 
 
 
 
 
 
 
 
     Gathering and processing
12,463

 
—

 
—

 
1,408

 
—

 
13,871

     Transportation
143

 
3,626

 
9,857

 
10,229

 
—

 
23,855

     Terminalling and storage
—

 
—

 
—

 
—

 
12,150

 
12,150

     Other services (2)
534

 
475

 
235

 
4,175

 
540

 
5,959

Revenues from contracts with customers
$
49,509

 
$
120,617

 
$
15,567

 
$
18,519

 
$
16,360

 
$
220,572


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



 
Six months ended June 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
$
5,427

 
$
—

 
$
12,110

 
$
5,024

 
$
—

 
$
22,561

     NGLs
39,209

 
—

 
—

 
71

 
—

 
39,280

     Condensate
19,802

 
—

 
—

 
97

 
—

 
19,899

     Crude oil
—

 
232,297

 
—

 
—

 
—

 
232,297

     Other sales (1)
818

 
—

 
6

 
64

 
8,674

 
9,562

 
 
 
 
 
 
 
 
 
 
 
 
Services:
 
 
 
 
 
 
 
 
 
 
 
     Gathering and processing
18,713

 
—

 
—

 
2,274

 
—

 
20,987

     Transportation
248

 
7,214

 
19,269

 
18,890

 
—

 
45,621

     Terminalling and storage
—

 
—

 
—

 
—

 
23,983

 
23,983

     Other services (2)
968

 
877

 
244

 
8,960

 
1,101

 
12,150

Revenues from contracts with customers
$
85,185

 
$
240,388

 
$
31,629

 
$
35,380

 
$
33,758

 
$
426,340

_________________________ 
(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 June 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
$
49,509

 
$
120,617

 
$
15,567

 
$
18,519

 
$
16,360

 
$
220,572

Loss on commodity derivatives, net
(294
)
 
(61
)
 
—

 
—

 
—

 
(355
)
     Total revenues of reportable segments
$
49,215

 
$
120,556

 
$
15,567

 
$
18,519

 
$
16,360

 
$
220,217

 
Six months ended June 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
$
85,185

 
$
240,388

 
$
31,629

 
$
35,380

 
$
33,758

 
$
426,340

Loss on commodity derivatives, net
(292
)
 
(4
)
 
—

 
—

 
—

 
(296
)
     Total revenues of reportable segments
$
84,893

 
$
240,384

 
$
31,629

 
$
35,380

 
$
33,758

 
$
426,044

    
We may utilize derivatives 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 it is 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 six months ended June 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
—

 
(1,463
)
Additions
4,681

 
2,661

Contract balances included in assets/liabilities held for sale
—

 
(690
)
Balance at June 30, 2018
$
7,236

 
$
15,890

 
 
 
 
Current
$
252

 
$
1,194

Noncurrent
6,984

 
14,696

Balance at June 30, 2018
$
7,236

 
$
15,890


As of June 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 noncurrent portion is included in Other assets, net; the current portion of contract liabilities is included in Accrued expenses and other current liabilities and the noncurrent 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 June 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
$
6,165

 
$
12,738

 
$
12,738

 
$
12,715

 
$
12,461

 
$
19,116

 
$
75,933

Transportation agreements
11,232

 
20,163

 
19,225

 
19,029

 
18,943

 
193,731

 
282,323

Terminalling and storage throughput agreements
7,070

 
12,896

 
6,204

 
2,694

 
1,582

 
—

 
30,446

Other
846

 
1,648

 
1,560

 
—

 
—

 
—

 
4,054

Total(1)
$
25,313

 
$
47,445

 
$
39,727

 
$
34,438

 
$
32,986

 
$
212,847

 
$
392,756

_________________________ 
(1) Includes consideration for 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 do not meet the requirements for presentation 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 $32.0 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 approximately $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 approximately $49.4 million. The consideration consisted of approximately $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 approximately $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 17.0% 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 2017 acquisitions were not material to our Condensed Consolidated Statements of Operations and therefore have not been presented separately.

Planned Dispositions

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 the terminalling assets were not integral to our core strategies; therefore, we began contemplating their disposition. We actively began marketing our Terminalling Services segment assets to use the proceeds to fund future acquisitions and growth projects.
In the first half of 2018, we entered into definitive agreements for the sale of the following businesses:
•
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 $138.5 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. We are continuing to market the Refined Products terminals. We continue to present the assets and liabilities of the Refined Products as held for sale. See Note 22 - Subsequent Events for additional information regarding the sale of Refined Products.


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



•
On June 16, 2018, we entered into a definitive agreement for the sale of our marine liquids terminals (the “Marine Products”) to institutional investors for approximately $210.0 million in cash, subject to working capital adjustments. The divestiture of the Marine Products, including the Harvey and Westwego terminals located in the Port of New Orleans 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. Accordingly, we have presented the Marine Products assets and liabilities as held for sale as of June 30, 2018. See Note 22 - Subsequent Events for additional information regarding the sale of Marine Products.

The planned dispositions of the Refined Products and Marine Products terminals do not meet the criteria for discontinued operations, as we believe the sale of Refined Products and Marine Products will not significantly impact our results of operations or financial condition. As of June 30, 2018, certain remaining assets in the Terminalling Services segment do not meet the criteria to be classified as held for sale.

Included in the disposal groups are the following assets and liabilities at June 30, 2018 (in thousands):
 
Refined Products
 
Marine Products
 
 
 
Business(1)
 
Business(2)
 
Total
 
 
 
 
 
 
Cash and cash equivalents
$
—

 
$
364

 
$
364

Accounts receivable, net
1,834

 
2,521

 
4,355

Inventory
506

 
31

 
537

Other current assets
213

 
144

 
357

Property, plant and equipment, net
32,332

 
84,661

 
116,993

Goodwill
61,163

 
16,262

 
77,425

Intangible assets
29,403

 
—

 
29,403

Other non-current assets
692

 
3

 
695

     Total assets held for sale
$
126,143

 
$
103,986

 
$
230,129

 
 
 
 
 


Accounts payable
$
44

 
$
152

 
$
196

Accrued gas purchases
72

 
—

 
72

Accrued expenses and other current liabilities
991

 
406

 
1,397

Other long-term liabilities
572

 
—

 
572

     Total liabilities held for sale
$
1,679

 
$
558

 
$
2,237

_________________________
(1)Net income from continuing operations before income taxes for the Refined Products Business were as follows:
•
$4.3 million and $1.6 million for the three months ended June 30, 2018 and 2017, respectively; and
•
$6.7 million and $3.4 million for the six months ended June 30, 2018 and 2017, respectively.
(2)Net income from continuing operations before income taxes for the Marine Products Business were as follows:
•
$3.5 million and $2.5 million for the three months ended June 30, 2018 and 2017, respectively; and
•
$5.1 million and $5.2 million for the six months ended June 30, 2018 and 2017, respectively.

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 $170.0 million in cash, net of customary closing adjustments. We recorded a gain of $47.4 million, net of $2.5 million of transaction costs, which was included in (Gains) losses on sale of assets

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



and business in our Condensed Consolidated Statement of Operations in the period ended September 30, 2017. We have reported the accounts and the results of our Propane Business as discontinued operations in our Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2017.

Summarized financial information related to the Propane Business is set forth in the tables below (in thousands):
 
Three months ended June 30,
 
Six months ended June 30,
 
2017
 
2017
Total revenue
$
31,603

 
$
67,157

Total operating expenses
33,402

 
69,707

     Operating loss
(1,799
)
 
(2,550
)
Other income
42

 
83

Income tax expense
(44
)
 
(44
)
     Loss from discontinued operations
$
(1,801
)
 
$
(2,511
)
 


 
 
Depreciation and amortization
$
3,687

 
$
7,468

Capital expenditures
$
1,302

 
$
2,421

 
 
 
 
Operating non-cash items
 
 
 
Unrealized loss on derivative contracts, net
$
(60
)
 
$
(961
)

(5) Inventory

Inventory consists of the following (in thousands):
 
 
June 30, 2018
 
December 31, 2017
Crude oil
 
$
2,184

 
$
1,553

NGLs
 
357

 
347

Refined products
 
—

 
934

Materials, supplies and equipment
 
120

 
132

Total inventory
 
$
2,661

 
$
2,966


(6) Other Current Assets

Other current assets consist of the following (in thousands):
 
June 30, 2018
 
December 31, 2017
Prepaid expenses
$
7,196

 
$
8,944

Insurance receivables
881

 
1,741

Due from related parties
6,773

 
4,362

Other receivables
8,801

 
5,187

Risk management assets
6,919

 
3,186

   Total other current assets
$
30,570

 
$
23,420


(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.


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



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 swap 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 June 30, 2018 and December 31, 2017, none of which were designated as hedges for accounting purposes.
 
 
June 30, 2018
 
December 31, 2017
Commodity Swaps
 
Volume
 
Maturity
 
Volume
 
Maturity
NGLs Fixed Price (gallons)
 
2,188,200
 
January 2019
 
—
 
—

Interest Rate Swaps

To manage the impact of the interest rate risk associated with our Credit Agreement, as defined in Note 13 - Debt Obligations, 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 June 30, 2018, and December 31, 2017, we had a combined notional principal amount of $550.0 million respectively of variable-to-fixed interest rate swap agreements. As of June 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.

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 three and six months ended June 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 approximately $0.9 million and $0.5 million as of June 30, 2018 and December 31, 2017, respectively, and are included in Other current assets on the Condensed Consolidated Balance
Sheets.


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



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
 
June 30,
2018
 
December 31, 2017
 
June 30,
2018
 
December 31, 2017
Commodity derivatives
Accrued expenses and other current liabilities
 
$
—

 
$
—

 
$
(240
)
 
$
—

 
 
 
 
 
 
 
 
 
 
Interest rate swaps
Other current assets
 
5,970

 
2,677

 
—

 
—

Interest rate swaps
Other assets net
 
11,605

 
8,807

 
—

 
—

 
 
 
 
 
 
 
 
 
 
Weather derivatives
Other current assets
 
949

 
509

 
—

 
—

 
Total
 
$
18,524

 
$
11,993

 
$
(240
)
 
$
—

    
As of June 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 six months ended June 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 June 30,
 
Six months ended June 30,
Statement of Operations Classification
Realized
 
Unrealized
 
Realized
 
Unrealized
2018
 
 
 
 
 
 
 
Loss on commodity derivatives, net
$
(174
)
 
$
(181
)
 
$
(56
)
 
$
(240
)
Interest expense
1,285

 
920

 
2,635

 
6,091

Direct operating expenses
(272
)
 
—

 
(550
)
 
—

Total gain on derivatives recognized in net loss
$
839

 
$
739

 
$
2,029

 
$
5,851

2017
 
 
 
 
 
 
 
Gains (losses) on commodity derivatives, net
$
192

 
$
7

 
$
613

 
$
(49
)
Interest expense
—

 
(1,693
)
 
(70
)
 
(2,010
)
Direct operating expenses
(218
)
 
—

 
(475
)
 
—

Total (loss) gain on derivatives recognized in net loss
$
(26
)
 
$
(1,686
)
 
$
68

 
$
(2,059
)

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 June 30, 2018 and December 31, 2017. Short-term and long-term debt are recorded at amortized cost in the Condensed Consolidated Balance Sheets.
 
 
 
 
June 30, 2018
 
December 31, 2017
 
 
 
 
Carrying Amount
 
Fair Value
 
Carrying Amount
 
Fair Value
Non-Derivatives
 
 
 
 
 
 
 
 
 
Liabilities
 
 
 
 
 
 
 
 
 
 
8.5% Senior Unsecured Notes
 
$
418,537

 
$
420,137

 
$
418,421

 
$
437,062

 
 
3.77% Senior Secured Notes
 
55,447

 
50,822

 
56,005

 
53,845

 
 
3.97% Trans-Union Secured Senior Notes
 
30,824

 
28,053

 
31,692

 
30,221

 
 
Total
 
$
504,808

 
$
499,012

 
$
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 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.

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




The carrying value of all non-derivative financial instruments included in current assets (including cash, cash equivalents and 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)
 
June 30,
2018
 
December 31,
2017
Land
Infinite
 
$
14,635

 
$
18,145

Construction in progress
N/A
 
52,811

 
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
 
123,210

 
123,138

Pipelines, compressors and right-of-way
3 to 40
 
1,004,992

 
974,301

Storage
3 to 40
 
46,398

 
146,105

Equipment
3 to 31
 
61,353

 
80,220

Total property, plant and equipment
 
 
1,336,042

 
1,436,463

Accumulated depreciation
 
 
(343,383
)
 
(340,878
)
Property, plant and equipment, net
 
 
$
992,659

 
$
1,095,585


At June 30, 2018 and December 31, 2017, gross property, plant and equipment included $374.2 million and $367.6 million, respectively, related to our FERC regulated interstate and intrastate assets.

Depreciation and amortization expense totaled $18.2 million and $18.3 million for the three months ended June 30, 2018 and 2017, respectively, and $36.8 million and $36.8 million for both the six months ended June 30, 2018 and 2017. Capitalized interest was $0.9 million and $0.5 million for the three months ended June 30, 2018 and 2017, respectively, and $1.5 million and $1.5 million for the six months ended June 30, 2018 and 2017, respectively.

(9) Goodwill and Intangible Assets

Goodwill consists of the following (in thousands):
 
June 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 change in the Terminalling Services segment goodwill relates to the Refined Products and the Marine Products which were classified as held for sale at June 30, 2018. See Note 4 - Acquisitions and Dispositions for further discussion.

Intangible assets, net consists of customer relationships, dedicated acreage agreements, collaborative arrangements, noncompete agreements and trade names. 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.



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



Intangible assets, net, consist of the following (in thousands):

 
June 30, 2018
 
Gross carrying amount
 
Accumulated amortization
 
Net carrying amount
Customer relationships
$
64,745

 
$
(15,548
)
 
$
49,197

Customer contracts
94,692

 
(50,664
)
 
44,028

Dedicated acreage
42,547

 
(6,904
)
 
35,643

Collaborative arrangements
11,884

 
(1,839
)
 
10,045

Noncompete agreements
1,064

 
(1,064
)
 
—

Other
198

 
(28
)
 
170

Total
$
215,130

 
$
(76,047
)
 
$
139,083

 
 
 
 
 
 
 
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


Amortization expense related to our intangible assets totaled $2.5 million and $7.6 million for the three months ended June 30, 2018 and 2017, respectively, and $5.2 million and $14.2 million for the six months ended June 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 $5.1 million, $10.2 million, $10.2 million, $10.2 million and $9.3 million, respectively.

(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 % - 12/31/2017
35.7%
 
35.7%
 
66.7%
 
16.7%
 
66.7%
 
25.3%
 
50.0%
 
 
Ownership % - 6/30/2018
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
5,267

 
3,916

 
4,449

 
1,880

 
4,781

 
510

 
2,316

 
23,119

   Contributions
826

 
—

 
—

 
—

 
—

 
—

 
3,705

 
4,531

   Distributions
(6,246
)
 
(7,972
)
 
(17,872
)
 
(3,316
)
 
(8,010
)
 
(538
)
 
(600
)
 
(44,554
)
Balances at June 30, 2018
$
90,259

 
$
42,876

 
$
110,822

 
$
51,621

 
$
19,216

 
$
4,661

 
$
12,075

 
$
331,530

___________________________________________________ 
(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.
 

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



The following tables present the summarized combined financial information for our equity investments (amounts represent 100% of investee financial information) (in thousands):
Balance Sheets:
June 30, 2018
 
December 31, 2017
Current assets
$
65,283

 
$
80,405

Non-current assets
1,272,593

 
1,288,862

Current liabilities
117,591

 
130,904

Non-current liabilities
447,654

 
436,584

 
Three months ended June 30,
 
Six months ended June 30,
Statements of Operations:
2018
 
2017(1)
 
2018
 
2017(1)
Revenue
$
51,790

 
$
105,373

 
$
108,689

 
$
203,366

Operating expenses
8,213

 
25,781

 
14,507

 
51,977

Net income
27,303

 
76,414

 
60,149

 
145,532

_________________________
(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.

(11) Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities consists of the following (in thousands):
 
 
June 30, 2018
 
December 31, 2017
Capital expenditures
 
$
8,137

 
$
10,721

Accrued interest
 
6,485

 
3,190

Convertible preferred unit distributions
 
8,474

 
—

Current portion of asset retirement obligation
 
6,416

 
6,416

Additional Blackwater acquisition consideration
 
5,000

 
5,000

Taxes payable
 
3,676

 
5,263

Due to related parties
 
5,225

 
6,609

Royalties, gas imbalance and leases payables
 
6,423

 
7,905

Professional fees
 
4,566

 
1,848

Other
 
12,993

 
21,902

   Total accrued expenses and other current liabilities
 
$
67,395


$
68,854


(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 Sheet, 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.

26
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 six months ended June 30, 2018 (in thousands):
Non-current balance
 
$
66,194

Current balance
 
6,416

Balances at December 31, 2017
 
72,610

Additions
 
260

Expenditures
 
(7
)
Accretion expense
 
911

Balances at June 30, 2018
 
73,774

     Less: current portion
 
6,416

Noncurrent asset retirement obligation
 
$
67,358


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 June 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):
 
June 30, 2018
 
December 31, 2017
Revolving credit facility
$
776,300

 
$
697,900

8.50% Senior unsecured notes, due 2021
425,000

 
425,000

3.77% Senior secured notes, due 2031 (non-recourse)
57,679

 
58,324

3.97% Senior secured notes, due 2032 (non-recourse)
31,148

 
32,025

Other debt
579

 
4,989

Total debt obligations
1,290,706

 
1,218,238

Unamortized debt issuance costs
(9,020
)
 
(9,231
)
Total debt
1,281,686

 
1,209,007

Less: Current portion, including unamortized debt issuance costs
(3,624
)
 
(7,551
)
Long term debt
$
1,278,062

 
$
1,201,456


AMID Revolving Credit Agreement
On June 29, 2018, we amended our $900 million revolving credit facility agreement, dated March 8, 2017 (the “Original Credit Agreement”), by entering into that certain 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 the Marine Products and Refined Products asset sales and any other disposition greater than $5 million.
Among other things, the Amendment also amends our borrowing capacity as follows:
•
upon consummation of the Marine Products sale, the aggregate commitments under the Credit Agreement shall be automatically reduced by $200.0 million;
•
upon consummation of the Refined Products sale, the aggregate commitments 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 commitments under the Credit Agreement shall be automatically reduced by 25% of the net cash proceeds of such disposition.

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




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

The revolving credit facility is scheduled to mature on September 5, 2019.

As of June 30, 2018, after giving effect to the amendments to the ratios, we were in compliance with our Credit Agreement financial covenants, including those shown below:
Ratio
 
 
 
Actual
Minimum Consolidated Interest Coverage Ratio
 

 
3.11
Maximum Allowable Consolidated Total Leverage Ratio
 

 
5.42
Maximum Allowable Consolidated Secured Leverage Ratio
 

 
3.50

As of June 30, 2018, we had approximately $776.3 million of borrowings, $39.0 million of letters of credit outstanding under the Credit Agreement and approximately $71.6 million of available borrowing capacity which can be increased up to $84.7 million, conditional upon compliance with existing covenants. For the first half of 2018 and 2017, the weighted average interest rate on borrowings under this facility was approximately 5.81% and 4.67%, 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.

(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

 
—

 
—

June 30, 2018
11,010

 
$
191,798

 
9,242

 
$
125,382

 
$
317,180



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



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 distributions prior to any distributions to our common unitholders. The 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 June 30, 2018, the conversion price was $15.11, and the conversion ratio is 1:1.1582.

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 $45.0 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 June 30, 2018, the conversion price was $15.11, and the conversion ratio is 1:1.1582.

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

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



according to a formula to provide for an increase in the number of common units into which Series C Units are convertible. As of June 30, 2018, the conversion price was $13.28, and the conversion ratio is 1:1.0542.

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” (“ASC 820”). 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 approximately 1.3% notional General Partner interests and 98.7% limited partner interests as of June 30, 2018. Our limited partners have limited rights of ownership as provided for under our Partnership Agreement and the right to 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 Interest
 
Limited Partner Interest
Balances at December 31, 2017
 
965

 
52,711

LTIP vesting
 
—

 
261

Balances at June 30, 2018
 
965

 
52,972


General Partner Units

In order for our General Partner to maintain its ownership percentage in us, our General Partner paid $3.9 million for the issuance of 272,811 additional notional General Partner units for the six months ended June 30, 2017. We issued 300 additional General Partner units for the three and six months ended June 30, 2018.



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



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 June 30, 2018 (in thousands, except per unit data):
Date Declared
 
Distribution Payment Date
 
General Partner
 
Limited Partner
 
Total Cash Distributions
 
Cash Distributions Per Common Unit
April 26, 2018
 
May 15, 2018
 
$
287

 
$
21,853

 
$
22,140

 
$
0.4125

January 26, 2018
 
February 14, 2018
 
$
290

 
$
21,745

 
$
22,035

 
$
0.4125


On July 27, 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 second quarter of 2018 and will be paid in the third quarter of 2018. See Note 22 - Subsequent Events for more information.

31
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 six months ended June 30, 2018 (in thousands):
 
 
Three months ended June 30,
 
Six months ended June 30,
 
 
2018
 
2017
 
2018
 
2017
Series A Units
 
 
 
 
 
 
 
 
Cash Paid
 
$
4,542

 
$
2,117

 
$
4,542

 
$
4,644

Accrued (1)
 
4,542

 
4,069

 
4,542

 
4,069

Paid-in-kind units
 
—

 
2,181

 
3,767

 
4,914

 
 
 
 
 
 
 
 
 
Series C Units
 
 
 
 
 
 
 
 
Cash Paid
 
3,812

 
3,627

 
3,812

 
7,254

Accrued (1)
 
3,812

 
3,627

 
3,812

 
3,627

Paid-in-kind units
 
—

 
—

 
4,309

 
—

 
 
 
 
 
 
 
 
 
Series D Units
 
 
 
 
 
 
 
 
Cash Paid
 
—

 
963

 
—

 
1,925

Accrued
 
—

 
963

 
—

 
963

 
 
 
 
 
 
 
 
 
Limited Partners’ Units(2)
 
 
 
 
 
 
 
 
Cash Paid
 
21,853

 
21,390

 
43,598

 
46,303

 
 
 
 
 
 
 
 
 
General Partners’ Units(3)
 
 
 
 
 
 
 
 
Cash Paid
 
287

 
201

 
577

 
368

 
 
 
 
 
 
 
 
 
Summary
 
 
 
 
 
 
 
 
Cash Paid
 
$
30,494

 
$
28,298

 
$
52,529

 
$
60,494

Accrued (1)
 
8,354

 
8,659

 
8,354

 
8,659

Paid-in-kind units
 
—

 
2,181

 
8,076

 
4,914

__________________________
(1) Can be paid in either Cash, PIK or a combination of both.
(2) Limited Partner distributions do not include $5.5 million and $21.4 million of distributions declared in the third quarter which relate to the second 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 third quarter which relate to the second 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 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 Partners and common unitholders assuming JPE units were converted into our common units in the comparative historical periods.

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




The calculation of basic and diluted limited partners' net loss per common unit is summarized below (in thousands, except per unit amounts):
 
Three months ended June 30,
 
Six months ended June 30,
 
2018
 
2017
 
2018
 
2017
Loss from continuing operations
$
(17,274
)
 
$
(25,901
)
 
$
(31,116
)
 
$
(54,072
)
Less: Net income attributable to noncontrolling interests
13

 
1,462

 
57

 
2,765

Loss attributable to the Partnership
(17,287
)
 
(27,363
)
 
(31,173
)
 
(56,837
)
Less:
 
 
 
 
 
 
 
Distributions on Series A Units
4,542

 
4,069

 
9,084

 
8,367

Distributions on Series C Units
3,812

 
3,627

 
7,624

 
7,254

Distributions on Series D Units
—

 
963

 
—

 
1,925

General Partner's distribution
72

 
277

 
361

 
476

General Partner's share in undistributed loss
(403
)
 
(784
)
 
(986
)
 
(1,541
)
Loss attributable to Limited Partners
(25,310
)
 
(35,515
)
 
(47,256
)
 
(73,318
)
Loss from discontinued operations, net of tax
—

 
(1,801
)
 
—

 
(2,511
)
Net loss attributable to Limited Partners
$
(25,310
)
 
$
(37,316
)
 
$
(47,256
)
 
$
(75,829
)
 
 
 
 
 
 
 
 
Weighted average number of common units outstanding - Basic and Diluted
52,969

 
51,870

 
52,869

 
51,870

 
 
 
 
 
 
 
 
Limited Partners' net loss per common unit - Basic and Diluted
 
 
 
 
 
 
 
Loss from continuing operations
$
(0.48
)
 
$
(0.69
)
 
$
(0.89
)
 
$
(1.41
)
Loss from discontinued operations
—

 
(0.03
)
 
—

 
(0.05
)
Net loss (1)
$
(0.48
)
 
$
(0.72
)
 
$
(0.89
)
 
$
(1.46
)
_____________________________________
(1) Potential common unit equivalents are antidilutive for all periods presented and, as a result, 23.9 million and 24.0 million potential common unit equivalents for the three and six months ended June 30, 2018 and 2017, respectively and have been excluded from the determination of diluted limited partners' net 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 June 30, 2018, there were 3,665,180 common units available for future grants under the LTIP.

The following table presents the components of equity-based compensation expense for the three and six months ended June 30, 2018 and 2017 (in thousands):

 
Three months ended June 30,
 
Six months ended June 30,
 
2018
 
2017
 
2018
 
2017
Grant Type:
 
 
 
 
 
 
 
RSU
$
835

 
$
1,177

 
$
1,534

 
$
5,195

PSU
330

 
—

 
630

 
—

Options
15

 
19

 
30

 
38

Total
$
1,180

 
$
1,196

 
$
2,194

 
$
5,233



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



During the six months ended June 30, 2018, we granted 809,357 RSU’s at a weighted-average fair value per unit of $8.56, vested 336,211 RSU’s at a weighted-average fair value per unit of $6.26 and forfeited 253,245 RSU’s at a weighted-average fair value per unit of $5.87. Unrecognized compensation expense related to RSU’s was $10.2 million at June 30, 2018.

During the six months ended June 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 $5.6 million, respectively, at June 30, 2018.

Defined Contribution Plan

For the three and six months ended June 30, 2018 and 2017, compensation expense associated with our 401(k)-defined contribution plan’s employer matching was $0.5 million and $0.4 million, respectively, and $1.3 million and $0.9 million, respectively. There was no change to the defined contribution plan.

(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, as of and for the six months ended June 30, 2018 and 2017 and the outstanding balances as of June 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 June 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 third 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 June 30, 2018, and December 31, 2017, we had an accounts receivable balance due from Republic of $0.1 million and $0.8 million, respectively, which is included in Other current assets in the accompanying Condensed Consolidated Balance Sheets.


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



General Partner

During the first half of 2018, our General Partner paid $23.3 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 June 30, 2018, and December 31, 2017, we had $5.2 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, 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 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 agreed to a 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.

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 six months ended June 30, 2018, and 2017, we recognized $1.3 million and $1.2 million of management fee income, respectively, for each period. As of June 30, 2018, and December 31, 2017, we had an outstanding accounts receivable balance of $4.0 million and $0.9 million, 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 six months ended June 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 June 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 six months ended June 30, 2018, the Partnership invoiced CIMA $1.1 million and received invoicing from CIMA of $2.7 million in connection with such transactions. For the six months ended June 30, 2017, the Partnership invoiced CIMA $2.5 million and received invoices from CIMA of $2.6 million for services. As of June 30, 2018, and December 31, 2017, the Partnership had $0.1 million outstanding amounts due to/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 June 30, 2018, and December 31, 2017, we had an outstanding accounts receivable balance related to these payments of $2.5 million 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.


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



(20) Supplemental Cash Flow Information

Supplemental cash flows and non-cash transactions consist of the following (in thousands):
 
 
Six months ended June 30,
 
 
2018
 
2017
Supplemental cash flow information
 
 
 
 
Interest payments, net of capitalized interest
 
$
36,778

 
$
27,324

Supplemental non-cash information
 
 
 
 
Investing
 
 
 
 
Increase (decrease) in accrued property, plant and equipment purchases
 
(2,584
)
 
(3,131
)
Accrued contributions to unconsolidated affiliates
 
(1,585
)
 
—

Financing
 
 
 
 
Contributions from an affiliate holding limited partner interests
 
—

 
4,000

Accrued distributions on convertible preferred units
 
8,354

 
8,659

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

 
4,914


(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.

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.

Our chief operating decision maker 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 (i) total revenue plus unconsolidated affiliate earnings less (ii) 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.



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



The following tables set forth our segment information for the three and six months ended June 30, 2018 and 2017 (in thousands):
 
Three months ended June 30, 2018
 
Gas Gathering and Processing Services
 
Liquid Pipelines and Services
 
Natural Gas Transportation Services
 
Offshore Pipelines and Services
 
Terminalling Services
 
Total
Revenue
$
49,509

 
$
120,617

 
$
15,567

 
$
18,519

 
$
16,360

 
$
220,572

Gain (loss) on commodity derivatives, net
(294
)
 
(61
)
 
—

 
—

 
—

 
(355
)
Total revenue
49,215


120,556


15,567


18,519


16,360

 
220,217

 
 
 
 
 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
 
 
 
 
Cost of Sales
34,948

 
115,193

 
5,839

 
2,150

 
3,378

 
161,508

Direct operating expenses
—

 
—

 
—

 
—

 
4,131

 
21,742

Corporate expenses
 
 
 
 
 
 
 
 
 
 
23,372

     Depreciation, amortization and accretion expense
 
 
 
 
 
 
 
 
 
 
21,236

Total operating expenses

 

 

 

 

 
227,858

Operating income (loss)

 

 

 

 

 
(7,641
)
Other income (expense), net
 
 
 
 
 
 
 
 
 
 
 
     Interest expense, net of capitalized interest
 
 
 
 
 
 
 
 
 
 
(19,691
)
     Other income (expense), net
 
 
 
 
 
 
 
 
 
 
169

     Earnings in unconsolidated affiliates
—

 
2,485

 
—

 
7,961

 
—

 
10,446

Income (loss) from continuing operations before income taxes

 

 

 

 

 
(16,717
)
Income tax expense
 
 
 
 
 
 
 
 
 
 
(557
)
Loss from continuing operations
 
 
 
 
 
 
 
 
 
 
(17,274
)
Less: Net income attributable to non-controlling interests
 
 
 
 
 
 
 
 
 
 
13

Net loss attributable to the Partnership
 
 
 
 
 
 
 
 
 
 
$
(17,287
)
 
 
 
 
 
 
 
 
 
 
 
 
Segment gross margin
$
14,539

 
$
7,744

 
$
9,653

 
$
24,330

 
$
8,851

 
 


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



 
Three months ended June 30, 2017
 
Gas Gathering and Processing Services
 
Liquid Pipelines and Services
 
Natural Gas Transportation Services
 
Offshore Pipelines and Services
 
Terminalling Services
 
Total
Revenue
$
39,307

 
$
83,157

 
$
11,397

 
$
12,139

 
$
15,831

 
$
161,831

Gain (loss) on commodity derivatives, net
(98
)
 
297

 
—

 
—

 
—

 
199

Total revenue
39,209

 
83,454

 
11,397

 
12,139

 
15,831

 
162,030

 
 
 
 
 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
 
 
 
 
Cost of Sales
26,582

 
78,101

 
5,678

 
2,586

 
2,073

 
115,020

Direct operating expenses
—

 
—

 
—

 
—

 
2,998

 
18,709

Corporate expenses
 
 
 
 
 
 
 
 
 
 
27,374

     Depreciation, amortization and accretion expense
 
 
 
 
 
 
 
 
 
 
26,483

Gain on sale of assets, net
 
 
 
 
 
 
 
 
 
 
18

Total operating expenses

 

 

 

 

 
187,604

Operating income (loss)

 

 

 

 

 
(25,574
)
Other income (expenses), net
 
 
 
 
 
 
 
 
 
 
 
     Interest expense, net of capitalized interest
 
 
 
 
 
 
 
 
 
 
(17,122
)
     Earnings in unconsolidated affiliates
—

 
1,482

 
—

 
16,070

 
—

 
17,552

Income (loss) from continuing operations before income taxes

 

 

 

 

 
(25,144
)
Income tax expense
 
 
 
 
 
 
 
 
 
 
(757
)
Loss from continuing operations
 
 
 
 
 
 
 
 
 
 
(25,901
)
Loss from discontinued operations
 
 
 
 
 
 
 
 
 
 
(1,801
)
Net loss
 
 
 
 
 
 
 
 
 
 
(27,702
)
Less: Net income attributable to non-controlling interests
 
 
 
 
 
 
 
 
 
 
1,462

Net loss attributable to the Partnership
 
 
 
 
 
 
 
 
 
 
$
(29,164
)
 
 
 
 
 
 
 
 
 
 
 
 
Segment gross margin
$
12,651

 
$
6,765

 
$
5,631

 
$
25,623

 
$
10,760

 
 







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



 
Six months ended June 30, 2018
 
Gas Gathering and Processing Services
 
Liquid Pipelines and Services
 
Natural Gas Transportation Services
 
Offshore Pipelines and Services
 
Terminalling Services
 
Total
Revenue
$
85,185

 
$
240,388

 
$
31,629

 
$
35,380

 
$
33,758

—

$
426,340

Gain (loss) on commodity derivatives, net
(292
)
 
(4
)
 
—

 
—

 
—

—

(296
)
Total revenue
84,893

 
240,384

 
31,629

 
35,380

 
33,758

 
426,044

 
 
 
 
 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
 
 
 
 
Cost of Sales
58,003

 
229,998

 
11,126

 
4,146

 
8,401

—

311,674

Direct operating expenses
—

 
—

 
—

 
—

 
8,453

—

45,189

Corporate expenses
 
 
 
 
 
 
 
 
 
—

46,064

     Depreciation, amortization and accretion expense
 
 
 
 
 
 
 
 
 
 
43,234

Gain on sale of assets, net
 
 
 
 
 
 
 
 
 
 
(95
)
Total operating expenses

 

 

 

 

 
446,066

Operating income (loss)

 

 

 

 

 
(20,022
)
Other income (expense), net
 
 
 
 
 
 
 
 
 
 
 
     Interest expense, net of capitalized interest
 
 
 
 
 
 
 
 
 
 
(33,567
)
     Other income (expense), net
 
 
 
 
 
 
 
 
 
 
191

     Earnings in unconsolidated affiliates
—

 
4,706

 
—

 
18,413

 
—

—

23,119

Loss from continuing operations before income taxes

 

 

 

 

 
(30,279
)
Income tax expense
 
 
 
 
 
 
 
 
 
 
(837
)
Loss from continuing operations
 
 
 
 
 
 
 
 
 
 
(31,116
)
Net loss
 
 
 
 
 
 
 
 
 
 
(31,116
)
Less: Net income attributable to non-controlling interests
 
 
 
 
 
 
 
 
 
—

57

Net loss attributable to the Partnership
 
 
 
 
 
 
 
 
 
 
$
(31,173
)
 

 

 

 

 

—

 
Segment gross margin
$
27,193

 
$
15,014

 
$
20,340

 
$
49,647

 
$
16,904

 
 

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



 
Six months ended June 30, 2017
 
Gas Gathering and Processing Services
 
Liquid Pipelines and Services
 
Natural Gas Transportation Services
 
Offshore Pipelines and Services
 
Terminalling Services
 
Total
Revenue
$
73,714

 
$
166,568

 
$
23,835

 
$
26,970

 
$
34,457

 
$
325,544

Gain (loss) on commodity derivatives, net
(105
)
 
669

 
—

 
—

 
—

 
564

Total revenue
73,609

 
167,237

 
23,835

 
26,970

 
34,457

 
326,108

 
 
 
 
 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
 
 
 
 
Cost of Sales
49,769

 
156,386

 
11,938

 
5,929

 
6,466

 
230,488

Direct operating expenses
—

 
—

 
—

 
—

 
6,071

 
36,114

Corporate expenses
 
 
 
 
 
 
 
 
 
 
57,487

     Depreciation, amortization and accretion expense
 
 
 
 
 
 
 
 
 
 
52,053

Gain on sale of assets, net
 
 
 
 
 
 
 
 
 
 
(3
)
Total operating expenses

 

 

 

 

 
376,139

Operating income (loss)

 

 

 

 

 
(50,031
)
Other income (expenses), net
 
 
 
 
 
 
 
 
 
 
 
     Interest expense, net of capitalized interest
 
 
 
 
 
 
 
 
 
 
(35,078
)
     Other income (expense), net
 
 
 
 
 
 
 
 
 
 
(37
)
     Earnings in unconsolidated affiliates
—

 
2,569

 
—

 
30,385

 
—

 
32,954

Loss from continuing operations before income taxes

 

 

 

 

 
(52,192
)
Income tax expense
 
 
 
 
 
 
 
 
 
 
(1,880
)
Loss from continuing operations
 
 
 
 
 
 
 
 
 
 
(54,072
)
Loss from discontinued operations
 
 
 
 
 
 
 
 
 
 
(2,511
)
Net loss
 
 
 
 
 
 
 
 
 
 
(56,583
)
Less: Net income attributable to non-controlling interests
 
 
 
 
 
 
 
 
 
 
2,765

Net loss attributable to the Partnership
 
 
 
 
 
 
 
 
 
 
$
(59,348
)
 
 
 
 
 
 
 
 
 
 
 
 
Segment gross margin
$
23,902

 
$
13,401

 
$
11,750

 
$
51,426

 
$
21,920

 
 


    





40
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):
 
June 30,
 
December 31,
 
2018
 
2017
Segment assets:
 
 
 
Gas Gathering and Processing Services
$
388,147

 
$
404,872

Liquid Pipelines and Services
374,668

 
359,646

Offshore Pipelines and Services
521,710

 
553,213

Natural Gas Transportation Services
266,972

 
268,991

Terminalling Services 
289,226

 
293,085

Other (1)
100,604

 
43,659

Total assets
$
1,941,327

 
$
1,923,466

 
 
 
 
Investment in equity method investees:
 
 
 
Liquid Pipelines and Services
$
68,357

 
$
64,399

Offshore Pipelines and Services
263,173

 
284,035

Total Investment in equity method investees
$
331,530

 
$
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 six months ended June 30, 2018 and 2017 by segment (in thousands):     
 
Three months ended June 30,
 
Six months ended June 30,
 
2018
 
2017
 
2018
 
2017
Capital expenditures
 
 
 
 
 
 
 
Gas Gathering and Processing Services
$
6,657

 
$
4,143

 
$
13,311

 
$
8,526

Liquid Pipelines and Services
4,767

 
1,005

 
11,180

 
1,376

Offshore Pipelines and Services
14,004

 
1,611

 
20,354

 
1,134

Natural Gas Transportation Services
1,154

 
14,138

 
2,492

 
24,366

Terminalling Services 
2,416

 
1,031

 
6,122

 
2,841

Corporate
1,592

 
1,015

 
3,074

 
3,645

Total capital expenditures(1)
$
30,590

 
$
22,943

 
$
56,533

 
$
41,888

_____________________________________
(1) Capital expenditures exclude expenditures made for the Propane Business of approximately $1.3 million and $2.2 million for the three and six months ended June 30, 2017, respectively, as the business was sold in 2017.

(22) Subsequent Events

Distribution

On July 27, 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 second quarter of 2018. The quarterly cash distribution, per common unit, for the second quarter of 2018 represents a reduction in the quarterly common unit distribution from prior quarters as part of our capital allocation strategy we announced in July 2018. The distribution will be paid on August 14, 2018 to unitholders of record as of the close of business on August 6, 2018.

Termination of Merger

On July 29, 2018, we received notice of termination of the Agreement and Plan of Merger, dated as of October 31, 2017, from Southcross Energy Partners, L.P. and notice of termination of the Contribution Agreement, dated as of October 31, 2017, from Southcross Holdings LP. Under the terms of the Contribution Agreement, Southcross Holdings LP is entitled to receive a $17 million reverse termination fee. The termination fee serves as liquidated damages and was paid in August 2018.


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



Marine Products Disposition

On July 31, 2018, we completed the previously announced sale of our Marine Products. 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 paydown the Credit Agreement.

Termination of Sale
On August 1, 2018, we and DKGP announced the termination of the sales agreement for the sale of our Refined Products. We are continuing to market the Refined Products terminals. See Note 4 - Acquisitions and Dispositions for additional information.


42


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 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 Annual Report on Form 10-K (the "Annual Report") 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:
•
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 maintain compliance with financial covenants and ratios in our revolving credit facility;
•
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;
•
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;

43


•
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 Annual Report; 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 Annual Report. 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 specialty chemical products and refined products.

Recent Developments

•
In the first half 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 $139.0 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 the Refined Products terminals. We continue to present the assets and liabilities of the 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 the Marine Products, including the Harvey and Westwego terminals located in the Port of New Orleans 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 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.

•
Southcross Energy Partners, L.P. Merger - 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 obtaining financing to close the SXE Transactions

44


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 June 30, 2018 include the following:

•
Net loss attributable to the Partnership was $17.3 million for the three months ended June 30, 2018 as compared to net loss attributable to the Partnership of $29.2 million for the same period in 2017.
•
Adjusted EBITDA was $51.2 million for the three months ended June 30, 2018, an increase of 15% compared to the second quarter of 2017.
•
Total segment gross margin was $65.1 million for the three months ended June 30, 2018, an increase of 6% as compared to the second quarter of 2017.

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

•
Continued increase in producer activity across the gathering and processing segment contributed to a 9% increase in throughput volumes over the first quarter of 2018.
•
Increased activity in the deep-water Gulf of Mexico drove a 19% increase in natural gas throughput volumes on the Partnership’s consolidated offshore assets over first quarter 2018.
•
Cayenne pipeline continued to outperform with a 50% increase in volumes from prior quarter and is currently operating at name plate capacity of 40,000 Bbls/d.
•
Delta House volumes continue to increase with the completion of maintenance work and current production is approximately 80% of capacity.
•
Strong performance across the Partnership’s natural gas transportation assets, with volumes increasing 51% from the prior year, driven by strong demand and the acquisition of Trans-Union pipeline.
•
Continuing to organically grow American Midstream through systematic capital redeployment to facilitate additional cash flow.

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 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.

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 non-controlling interest share of DAA, interest expense, net of capitalized interest excluding realized gain (loss) on interest rate swaps, 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

45


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 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 or support an increase in 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 realized gain (loss) on interest rate swaps and letter of credit fees, maintenance capital expenditures, and distributions related to the Series A and Series C 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 (i) total revenue plus unconsolidated affiliate earnings less (ii) 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 segment gross margin and operating margin is Net loss attributable to the Partnership. For a reconciliation of total segment gross margin and operating margin to Net 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 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 may be defined differently by other companies in our industry. Our definitions of these

46


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 loss attributable to the Partnership, (in thousands):

 
Three months ended June 30,
 
Six months ended June 30,
Reconciliation of Total Segment Gross Margin to Net loss attributable to the Partnership:
 
2018
 
2017
 
2018
 
2017

 
 
 
 
 
 
 
 
Gas Gathering and Processing Services segment gross margin
 
$
14,539

 
$
12,651

 
$
27,193

 
$
23,902

Liquid Pipelines and Services segment gross margin
 
7,744

 
6,765

 
15,014

 
13,401

Natural Gas Transportation Services segment gross margin
 
9,653

 
5,631

 
20,340

 
11,750

Offshore Pipelines and Services segment gross margin
 
24,330

 
25,623

 
49,647

 
51,426

Terminalling Services segment gross margin (1)
 
8,851

 
10,760

 
16,904

 
21,920

Total segment gross margin
 
65,117

 
61,430

 
129,098

 
122,399

Less:
 
 
 
 
 
 
 
 
Direct operating expenses
 
17,611

 
15,711

 
36,736

 
30,043

Operating Margin
 
47,506

 
45,719

 
92,362

 
92,356

Plus:
 
 
 
 
 
 
 
 
(Loss) gain on commodity derivatives, net
 
(355
)
 
199

 
(296
)
 
564

Less:
 
 
 
 
 
 
 
 
Corporate expenses
 
23,372

 
27,374

 
46,064

 
57,487

Depreciation, amortization and accretion expense
 
21,236

 
26,483

 
43,234

 
52,053

Gain (loss) on sale of assets, net
 
—

 
18

 
(95
)
 
(3
)
Interest expense
 
19,691

 
17,122

 
33,567

 
35,078

Other income
 
(169
)
 
—

 
(191
)
 
(37
)
Construction and operating management income
 
(262
)
 
65

 
(234
)
 
534

Income tax expense
 
557

 
757

 
837

 
1,880

Loss from discontinued operations, net of tax
 
—

 
1,801

 
—

 
2,511

Net income attributable to noncontrolling interests
 
13

 
1,462

 
57

 
2,765

Net loss attributable to the Partnership
 
$
(17,287
)
 
$
(29,164
)
 
$
(31,173
)
 
$
(59,348
)
_______________________
(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 its nearest GAAP measure, Income from continuing operations before income taxes, see Note 21 - Reportable Segments, to our Condensed Consolidated Financial Statements.


 







47



Three months ended June 30,
 
Six months ended June 30,

2018
 
2017
 
2018
 
2017
Reconciliation of Net loss attributable to the Partnership to Adjusted EBITDA and DCF:
 
 
 
 
 
 
 
Net loss attributable to the Partnership
$
(17,287
)
 
$
(29,164
)
 
$
(31,173
)
 
$
(59,348
)
Add:
 
 
 
 
 
 
 
Depreciation, amortization and accretion expense excluding non-controlling interest share
21,236

 
26,198

 
43,234

 
51,488

Interest expense, net of capitalized interest excluding realized gain (loss) on interest rate swaps and amortization of deferred financing costs
19,277

 
13,870

 
37,009

 
30,611

Debt issuance costs paid
1,657

 
714

 
2,742

 
2,116

Unrealized losses (gains) on derivatives, net
(739
)
 
1,686

 
(5,851
)
 
2,059

Non-cash equity compensation expense
1,180

 
1,195

 
2,194

 
5,233

Transaction expenses
6,938

 
12,067

 
15,816

 
20,685

Income tax expense
557

 
757

 
837

 
1,880

Discontinued operations
—

 
3,789

 
—

 
8,687

Distributions from unconsolidated affiliates
20,700

 
15,900

 
44,554

 
38,394

General Partner contribution
8,315

 
15,130

 
17,732

 
24,744

Deduct:
 
 
 
 
 
 
 
Earnings in unconsolidated affiliates
10,446


17,552

 
23,119

 
32,954

Gain on sale of assets
—


—

 
95

 
—

Construction and operating management income
148

 
50

 
223

 
513

Adjusted EBITDA
$
51,240

 
$
44,540

 
$
103,657

 
$
93,082

Deduct:
 
 
 
 
 
 
 
Interest expense, net of capitalized interest excluding realized gain (loss) on interest rate swaps and letter of credit fees

(19,298
)
 
(13,937
)
 
(36,987
)
 
(30,651
)
Maintenance capital
(2,576
)
 
(2,113
)
 
(7,079
)
 
(4,121
)
Preferred distribution
(8,354
)
 
(6,734
)
 
(16,708
)
 
(13,441
)
Distributable Cash Flow
$
21,012

 
$
21,756

 
$
42,883

 
$
44,869


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.

We expect to continue to pursue a multi-faceted growth strategy, which includes maximizing drop down opportunities provided by our relationship with ArcLight, capitalizing on organic expansion and pursuing strategic third-party acquisitions in order to grow our cash flows. We expect commodity prices in 2018 to increase compared to 2017, and as a result we expect producer and supplier activities to be impacted, which may increase the growth rate of our Gas Gathering and Processing Services and Natural Gas Transportation Services segments.


48


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 and outlook discussed below and in our Annual Report, under the caption “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 on at least monthly for consistency and trend analysis. These metrics include throughput volumes, storage utilization, segment gross margin, total segment gross margin, operating margin, direct operating expenses on a segment basis, Adjusted EBITDA and DCF on a company-wide basis.

The results of operations for the periods discussed are presented in the tables below:
 
 
Three months ended June 30,
 
 
2018
 
2017
 
Change
 
%
 
 
(In thousands, except percentages)
 
 
 
 
 
 
 
 
 
Revenue
 
$
220,217

 
$
162,030

 
$
58,187

 
36
 %
Cost of sales
 
161,508

 
115,020

 
46,488

 
40
 %
Direct operating expenses
 
21,742

 
18,709

 
3,033

 
16
 %
Corporate expenses
 
23,372

 
27,374

 
(4,002
)
 
(15
)%
Depreciation, amortization and accretion expense
 
21,236

 
26,483

 
(5,247
)
 
(20
)%
Loss on sale of assets, net
 
—

 
18

 
(18
)
 
(100
)%
Operating loss
 
(7,641
)
 
(25,574
)
 
17,933

 
70
 %
Interest expense, net of capitalized interest
 
(19,691
)
 
(17,122
)
 
(2,569
)
 
15
 %
Other income, net
 
169

 
—

 
169

 
—

Earnings in unconsolidated affiliates
 
10,446

 
17,552

 
(7,106
)
 
(40
)%
Income tax expense
 
(557
)
 
(757
)
 
200

 
(26
)%
Loss from continuing operations
 
(17,274
)
 
(25,901
)
 
8,627

 
33
 %
Loss from discontinued operations
 
—

 
(1,801
)
 
1,801

 
(100
)%
Net loss
 
(17,274
)
 
(27,702
)
 
10,428

 
38
 %
Less: Net income attributable to non-controlling interests
 
13

 
1,462

 
(1,449
)
 
(99
)%
Net loss attributable to the Partnership
 
$
(17,287
)
 
$
(29,164
)
 
$
11,877

 
41
 %
 
 
 
 
 
 
 
 

Non-GAAP Financial Measures
 
 
 
 
 
 
 

Segment gross margin (1)
 
$
65,117

 
$
61,430

 
$
3,687

 
6
 %
Adjusted EBITDA (2)
 
$
51,240

 
$
44,540

 
$
6,700

 
15
 %
____________________________________ 
(1) For reconciliation of Segment Gross Margin to its nearest GAAP measure, Income from continuing operations before income taxes, see Note 21 - Reportable Segments to our Condensed Consolidated Financial Statements.
(2) See table in Non-GAAP Financial Measures for a reconciliation of Adjusted EBITDA to its nearest GAAP measure.


49


 
Six months ended June 30,
 
2018
 
2017
 
Change
 
%
 
(In thousands, except percentages)
 
 
 
 
 
 
 
 
Revenue
$
426,044

 
$
326,108

 
$
99,936

 
31
 %
Cost of sales
311,674

 
230,488

 
81,186

 
35
 %
Direct operating expenses
45,189

 
36,114

 
9,075

 
25
 %
Corporate expenses
46,064

 
57,487

 
(11,423
)
 
(20
)%
Depreciation, amortization and accretion expense
43,234

 
52,053

 
(8,819
)
 
(17
)%
(Gain) on sale of assets, net
(95
)
 
(3
)
 
(92
)
 
—

Operating income (loss)
(20,022
)
 
(50,031
)
 
30,009

 
60
 %
Interest expense, net of capitalized interest
(33,567
)
 
(35,078
)
 
1,511

 
(4
)%
Other income (expense), net
191

 
(37
)
 
228

 
—

Earnings in unconsolidated affiliates
23,119

 
32,954

 
(9,835
)
 
(30
)%
Income tax expense
(837
)
 
(1,880
)
 
1,043

 
(55
)%
Loss from continuing operations
(31,116
)
 
(54,072
)
 
22,956

 
42
 %
Loss from discontinued operations
—

 
(2,511
)
 
2,511

 
(100
)%
Net loss
(31,116
)
 
(56,583
)
 
25,467

 
45
 %
Less: Net income attributable to non-controlling interests
57

 
2,765

 
(2,708
)
 
(98
)%
Net loss attributable to the Partnership
$
(31,173
)
 
$
(59,348
)
 
$
28,175

 
47
 %
 
 
 
 
 
 
 
 
Non-GAAP Financial Measures
 
 
 
 
 
 
 
Segment gross margin (1)
$
129,098

 
$
122,399

 
$
6,699

 
5
 %
Adjusted EBITDA (2)
$
103,657

 
$
93,082

 
$
10,575

 
11
 %
____________________________
(1) For reconciliation of Segment Gross Margin to its nearest GAAP measure, Income from continuing operations before income taxes, see Note 21 - Reportable Segment, to our Condensed Consolidated Financial Statements.
(2) See table in Non-GAAP Financial Measures for a reconciliation of adjusted EBITDA to its nearest GAAP measure.

Net loss attributable to the Partnership decreased by $11.9 million to $17.3 million or 41% for the three months ended June 30, 2018, as compared to $29.2 million for the same period in 2017, primarily reflecting increased revenues from both commodity sales and services, partially offset by higher operating expenses, mainly due to cost of sales increases associated with higher revenues, and lower earnings in unconsolidated affiliates. Net loss attributable to the Partnership decreased by $28.2 million to $31.2 million for the six months ended June 30, 2018, as compared to $59.3 million for the same period in 2017, primarily reflecting increased revenues from both commodity sales and services partially offset by higher operating expenses, mainly due to cost of sales increases associated with higher revenues, and lower earnings in unconsolidated affiliates.

Segment gross margin increased by $3.7 million, or 6%, to $65.1 million for the three months ended June 30, 2018 compared to $61.4 million for the three months ended June 30, 2017. The increase of $3.7 million for the three months ended June 30, 2018 was primarily due to higher segment gross margin in our Natural Gas Transportation Services, Gas Gathering and Processing Services and Liquid Pipelines and Services segments offset by decreases in our Offshore Pipelines and Services and Terminalling Services segments. Segment gross margin increased by $6.7 million to $129.1 million for the six months ended June 30, 2018 compared to $122.4 million for the six months ended June 30, 2017. The increase of $6.7 million for the six months ended June 30, 2018 was primarily due to higher segment gross margin in our Natural Gas Transportation Services, Gas Gathering and Processing Services and Liquid Pipelines and Services segments offset by decreases in our Offshore Pipelines and Services and Terminalling Services segments.

For the three months ended June 30, 2018, Adjusted EBITDA increased by $6.7 million to $51.2 million, or 15%, compared to the same period in 2017. The increase was primarily due to improvements in Net loss attributable to the Partnership from an increase in revenues partially offset by increased operating expenses. For the six months ended June 30, 2018, Adjusted EBITDA increased by $10.6 million to $103.7 million, or 11%, compared to the same period in 2017. The increase was primarily due to improvements in Net loss attributable to the Partnership caused by an increase in revenues partially offset by increased operating expenses.

50



We distributed $21.9 million to holders of our common units, or $0.4125 per common unit, during the three months ended June 30, 2018, which represents the distribution for the first quarter of 2018, and we distributed $43.6 million, or $0.8250 per common unit, during the six months ended June 30, 2018, which represents the distribution for the fourth quarter of 2017 and the first quarter of 2018.

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

Revenue. Our total revenue for the three months ended June 30, 2018 was $220.2 million compared to $162.0 million for the three months ended June 30, 2017. This increase of $58.2 million was primarily due to the following:

•
an increase in our Liquid Pipelines and Services segment revenue of $37.0 million was primarily due to an $8.6 million increase from increased volumes in our Crude Oil Supply and Logistics business (“COSL”) from Shell and Phillips 66 and $31.7 million due to a higher favorable average price increase of $17.20/Bbl partially offset by the impact of Topic 606 totaling $2.1 million.
•
an increase in our Gas Gathering and Processing Services segment revenue of $10.0 million primarily due to higher pricing for NGLs, natural gas and condensate at the Longview Plant of $5.3 million, higher revenue at the Chatom-Bazor Ridge facility due to increased supply of separator liquids of $3.0 million and new contracts at our Yellow Rose facility in the amount of $2.4 million.
•
an increase in our Offshore Pipelines and Services segment revenue of $6.4 million primarily due to the impact of acquiring the remaining interest in the Viosca Knoll Gathering System (“VKGS”) in 2017.

Cost of Sales. Our purchases of natural gas, NGLs, condensate and crude oil for the three months ended June 30, 2018 were $161.5 million compared to $115.0 million for the three months ended June 30, 2017. The increase of $46.5 million was primarily due to the new connection with Hunt and Henry Resources in our Liquid Pipelines and Services segment and higher crude oil pricing of $37.1 million, increases of $8.2 million from our Gas Gathering and Processing Services segment due to higher sales at our Longview and Yellow Rose plants and $1.0 million from higher prices and volumes at the Chatom-Bazor Ridge facility. These increases were partially offset by a decrease in our Natural Gas Transportation Services segment of $3.4 million due to lower market prices and imbalances of $3.4 million.

Direct Operating Expenses. Direct operating expenses for the three months ended June 30, 2018 were $21.7 million compared to $18.7 million for the three months ended June 30, 2017. This increase of $3.0 million was mainly due to acquisitions during 2017 of which $1.6 million related to Panther's entities, $1.2 million for VKGS and $0.2 million from the Trans-Union Pipeline.

Corporate Expenses. Corporate expenses for the three months ended June 30, 2018 were $23.4 million compared to $27.4 million for the three months ended June 30, 2017. This decrease of $4.0 million was primarily due to reductions of $1.0 million in legal fees, $0.6 million reduction in office rent expense, $0.5 million in insurance costs, $0.3 million in environmental costs, and the remaining balance of $1.6 million in lower transaction related costs.
Depreciation, Amortization and Accretion. Depreciation, amortization and accretion expense for the three months ended June 30, 2018 was $21.2 million compared to $26.5 million for the three months ended June 30, 2017. This decrease of $5.2 million was primarily due to $5.9 million in Marine and Refined Products terminals being classified as assets held for sale and $1.4 million in decreased depreciation and amortization due to the 2017 year-end impairments. This was offset by an increase of $2.0 million due to the acquisitions in the second and third quarters of 2017.

Interest Expense, net of capitalized interest. Interest expense for the three months ended June 30, 2018 was $19.7 million compared to $17.1 million for the three months ended June 30, 2017. The increase of $2.6 million was primarily due to higher interest charges of $3.2 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 expense on our revolving credit facility of $3.3 million due to increased revolver borrowings outstanding, offset by the favorable position of our interest rate swaps in the amount of $3.7 million. The outstanding balance on our revolving credit facility was $776.3 million as of June 30, 2018.
 
Earnings in Unconsolidated Affiliates. Earnings in unconsolidated affiliates for the three months ended June 30, 2018 was $10.4 million compared to $17.6 million for the three months ended June 30, 2017. This decrease of $7.1 million was primarily due to temporary curtailment of production flows at Delta House as certain third party-owned upstream infrastructure required remedial work. This remediation is scheduled to be completed later in 2018, at which time full production is anticipated to resume flowing into Delta House.


51


Loss from Discontinued Operations. Loss from discontinued operations for the three months ended June 30, 2017 was associated with our Propane Business which was discontinued in September 2017.

Six Months Ended June 30, 2018 Compared to Six Months Ended June 30, 2017

Revenue. Our total revenue for the six months ended June 30, 2018 was $426.0 million compared to $326.1 million for the six months ended June 30, 2017. This increase of $99.9 million was primarily due to the following:

•
an increase in our Gas Gathering and Processing Services segment of $11.3 million primarily due to higher sales at the Longview Plant and Yellow Rose facility of $14.3 million, increased sales of approximately $1.7 million at the Mesquite Plant due to the stabilizer being down for most of the first half of 2017, new marketing contracts of $3.3 million offset by the impact of the implementation of Topic 606 by $8.0 million.

•
an increase in our Liquid Pipelines and Services segment revenue of $75.3 million was primarily due to an higher prices and volume of $63.2 million on COSL, and an increase of $15.1 million due to higher volume and prices on crude oil sales contracts. These increases were partially offset by $5.3 million as a result of implementing Topic 606.

•
an increase in our Natural Gas Transportation Services segment revenue of $7.8 million driven by an increase of $5.5 million as a result of our Trans Union acquisition in the fourth quarter of 2017 and increased marketing activity partially offset by lower market prices of $1.2 million related to the Magnolia system.

•
an increase in our Offshore Pipelines and Services segment of $6.1 million was primarily due to the impact of acquiring the remaining interests in MPOG (MPOG was formerly owned at 66.7%) and POC in 2017 of $4.8 million, results from VKGS totaling $3.0 million, partially offset by a reduction in operating fees and guaranteed revenue of $1.2 million on American Panther and no plant thermal reduction (“PTR”) fees on High Point Gas Transmission (“HPGT”) for $0.5 million.
    
•
a decrease in our Terminalling Services segment revenue of $0.7 million was driven by a $4.4 million reduction in storage and utilization at our Cushing terminal due to tank maintenance and a new contract with lower storage and rate terms partially offset by a $1.1 million increase in throughput revenues at our Caddo Mills terminal as a result of facility enhancements and $2.6 million increase as a result of adopting Topic 606.

Cost of Sales. Our purchases of natural gas, NGLs, condensate and crude for the six months ended June 30, 2018 was $311.7 million compared to $230.5 million for the six months ended June 30, 2017. This increase of $81.2 million was mostly due to higher NGL, natural gas and condensate purchases of $8.2 million due to an increase in throughput at the Longview Plant and new marketing contracts, increased crude oil prices and volumes in our Liquid Pipelines and Services segment driven by favorable market conditions resulting in increased producer activity for $61.1 million, higher volumes and pricing relate to marketing contracts of $15.0 million partially offset by a decrease of $5.0 million as a result of implementing Topic 606.
 
Direct Operating Expenses. Direct operating expenses for the six months ended June 30, 2018 were $45.2 million compared to $36.1 million for the six months ended June 30, 2017. This increase of $9.1 million was primarily due to acquisitions during 2017 resulting in an $8.4 million increase in direct operating expenses ($5.7 million from Panther's entities, $2.4 million from VKGS and $0.3 million from Trans-Union Pipeline). The additional increase of $0.7 million related to repair and maintenance and other operating expenses at the High Point and Harvey terminals facility.

Corporate Expenses. Corporate expenses for the six months ended June 30, 2018 were $46.1 million compared to $57.5 million for the six months ended June 30, 2017. This decrease of $11.4 million was primarily due to reductions of $3.2 million in salaries and wages due to lower equity and stock-based compensation, $1.8 million reduction in contractors and consultants costs, $1.5 million in lower office rent and utilities expenses, $0.9 million in legal fees, $0.8 million in insurance costs, $0.5 million in environmental costs, $0.5 million in lower communication costs (after discontinuing JPEP’s legacy cellular and landline services), and the remaining balance of $2.2 million in lower transaction related costs.

Depreciation, Amortization and Accretion. Depreciation, amortization and accretion expense for the six months ended June 30, 2018 was $43.2 million compared to $52.1 million for the six months ended June 30, 2017. This decrease of $8.8 million was primarily due to $9.6 million in Marine and Refined Products terminals being classified as assets held for sale and $3.8 million in decreased depreciation and amortization due to the 2017 year-end impairments and adjustments. This was offset by an increase of $4.5 million due to the acquisitions in the second and third quarters of 2017.


52


Interest Expense, net of capitalized interest. Interest expense for the six months ended June 30, 2018 was $33.6 million compared to $35.1 million for the six months ended June 30, 2017. This decrease of $1.5 million was primarily due to the favorable position of our interest rate swaps in the amount of $10.6 million and the reduced interest expense of $1.9 million related to the acceleration of deferred financing costs due to the settlement of the JPE debt in March 2017, partially offset by the higher interest charges of $6.2 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 expense on our revolving credit facility of $4.4 million due to increased revolver borrowings outstanding.

Earnings in Unconsolidated Affiliates. Earnings in unconsolidated affiliates for the six months ended June 30, 2018 was $23.1 million compared to $33.0 million for the six months ended June 30, 2017. This decrease of $9.8 million was primarily due to temporary curtailment of production flows at Delta House as certain third party-owned upstream infrastructure required remedial work. This remediation is scheduled to be completed later in 2018, at which time full production is anticipated to resume flowing into Delta House. This decrease of $13.6 million due to Delta House was partially offset by increased earnings of new well start ups at Okeanos and fully consolidating MPOG in 2018 and to the Cayenne Pipeline, in which we have a 50% interest, that began operating in January 2018.

Results of Operations — Segment Results

Gas Gathering and Processing Services Segment

The table below contains key segment performance indicators related to our Gas Gathering and Processing Services segment (in thousands except operating and pricing data).
 
Three months ended June 30,
 
Six months ended June 30,
 
2018
 
2017
 
2018
 
2017
Segment Financial and Operating Data:
 
 
 
 
 
 
 
Gas Gathering and Processing Services segment
 
 
 
 
 
 
 
Financial data:
 
 
 
 
 
 
 
Commodity sales
$
36,369

 
$
33,650

 
$
65,256

 
$
62,423

Services
13,140

 
5,657

 
19,929

 
11,291

Revenue from operations
49,509

 
39,307

 
85,185

 
73,714

Gain (loss) on commodity derivatives, net
(294
)
 
(98
)
 
(292
)
 
(105
)
Segment revenue
49,215

 
39,209

 
84,893

 
73,609

Cost of sales
34,948

 
26,582

 
58,003

 
49,769

Direct operating expenses
5,736

 
8,045

 
12,606

 
16,110

Other financial data:
 
 
 
 
 
 
 
Segment gross margin (1)
$
14,539

 
$
12,651

 
$
27,193

 
$
23,902

Operating data:
 
 
 
 
 
 
 
Average throughput (MMcf/d)
174.6

 
209.0

 
167.6

 
208.3

Average plant inlet volume (MMcf/d) (2)
46.4

 
104.5

 
44.1

 
103.9

Average gross NGL production (Mgal/d) (2)
331.4

 
398.8

 
296.9

 
348.2

Average gross condensate production (Mgal/d) (2)
81.6

 
79.8

 
75.1

 
80.9

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

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

Commodity sales. Commodity sales revenue for the three months ended June 30, 2018 was $36.4 million compared to $33.7 million for the three months ended June 30, 2017. The increase of $2.7 million resulted from a combination of the following:

•
increased sales of NGLs, natural gas and condensate at the Longview Plant for $8.3 million primarily due to higher prices partially offset by slightly lower volumes.

53


•
increased sales of NGLs, natural gas and condensate in the Permian at the Yellow Rose facility in the amount of $2.4 million primarily as a result of new marketing contracts that began in the late fourth quarter of 2017.
•
increase in sales at the Chatom-Bazor Ridge facility of approximately $3.0 million due to increased supplies of separator liquids from a new producer partially offset by lower NGL and natural gas sales of approximately $0.7 million and $0.6 million, respectively.
•
increased sales of $0.2 million and $0.3 million at Chapel Hill and Mesquite facilities, respectively, due to higher pricing and increased production at Mesquite facility due the stabilizer being fully operational in 2018.
•
increased sales of $2.2 million as a result of new marketing contracts starting in early 2018.
•
the increases noted above were essentially offset by decreases in average throughput and plant inlet volumes from our Burns Point facility being down in 2018, decreases in NGL volumes at the Longview and Chatom-Bazor Ridge facilities due to lower volumes received from certain producers, weather and plant outages, and a $11.9 million reduction in Commodity Sales due to implementation 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. This determination resulted in a reduction in Commodity sales, partially offset by an increase in Services revenue, and a corresponding Cost of Sales reduction associated with these POP contracts. Total segment gross margin was not impacted by the implementation of Topic 606.

Services revenue. Segment services revenue for the three months ended June 30, 2018 was $13.1 million compared to $5.7 million for the three months ended June 30, 2017. Service revenue increased by $7.5 million, primarily due to higher amounts of recovered product and compression fees on Yellow Rose of $0.8 million partially offset by reduced fees of $0.4 million as a result of a plant outage at Chatom Bazor-Ridge. While these two items offset each other, as a result of Topic 606 implementation, we have determined that certain POP contracts should be recorded on a net basis, resulting in a $6.3 million increase in Services revenue.

Cost of Sales. Purchases of natural gas, NGLs and condensate for the three months ended June 30, 2018 were $34.9 million, compared to $26.6 million for the three months ended June 30, 2017. The increase of $8.4 million was primarily due to increased sales of NGLs, natural gas and condensate sales at the Longview and Chatom-Bazor Ridge Plants of approximately $5.5 million and $1.5 million, respectively, and increased sales of NGLs and condensate at Yellow Rose of $1.3 million. New marketing contracts in 2018 increased purchases by $5.6 million offset by $5.6 million due to Topic 606 implementation as discussed above.

Direct Operating Expenses. Direct operating expenses for the three months ended June 30, 2018 was $5.7 million compared to $8.0 million for the three months ended June 30, 2017. The $2.3 million decrease was mainly due to $0.5 million lower leases and rents at Chapel Hill, Lavaca and Chatom facilities, $0.5 million in lower outside services at Longview and Yellow Rose facilities, and $0.5 million in lower salaries and wages at Longview, Chatom and Bazor Ridge facilities. The remaining variance of $0.8 million was due to other operating expenses throughout the Gas Gathering and Processing segment.

Six Months Ended June 30, 2018 Compared to Six Months Ended June 30, 2017

Commodity sales. Commodity sales revenue for the six months ended June 30, 2018 was $65.3 million compared to $62.4 million for the six months ended June 30, 2017. This increase of $2.8 million resulted from a combination of the following:

•
increased sales of NGLs and condensate at the Longview Plant of $10.5 million due primarily to higher prices in the current year and three new contracts, two of which began in the first quarter of 2018.
•
increased sales of NGLs and condensate at the Yellow Rose facility of $3.8 million primarily due to higher volumes.
•
increased sales of approximately $1.7 million at the Mesquite Plant due to the stabilizer being down for most of the first half of 2017.
•
increased sales of NGLs of approximately $3.3 million as a result of new marketing contracts that began in the fourth quarter of 2017.
•
the increases noted above were essentially offset by decreases in average throughput and plant inlet volumes from our Burns Point facility being down in 2018, decreases in NGL volumes at the Longview and Chatom-Bazor Ridge facilities due to lower volumes received from certain producers, weather and plant outages, and a $16.4 million reduction in Commodity Sales due to implementation of Topic 606 in which we determined that certain POP contracts should be recorded on a net basis instead of a gross basis. This determination resulted in a reduction in Commodity Sales, partially offset by an increase in Services revenue, and a corresponding Cost of Sales reduction associated with these POP contracts. Total segment gross margin was not impacted by the implementation of Topic 606.

Services revenue. Segment services revenue for the six months ended June 30, 2018 was $19.9 million compared to $11.3 million for the six months ended June 30, 2017. The increase of approximately $8.6 million was primarily due to the impact of implementing Topic 606 in the amount of $7.6 million, increased service fees of $0.9 million at the Lavaca plant from increased throughput from new wells partially offset by the impact of $0.3 million from a Longview XTO contract that was changed from

54


a service contract to a product purchase in March of 2017 and lower service fees of approximately $0.5 million as a result of a plant outage at the Chatom-Bazor Ridge facility.

Cost of Sales. Purchases of natural gas, NGLs and condensate for the six months ended June 30, 2018 were $58.0 million compared to $49.8 million for the six months ended June 30, 2017. This increase of $8.2 million was primarily due to increased NGL sales from new marketing contracts of $8.2 million, increased sales of NGLs, increased natural gas, marketing and condensate sales at the Longview Plant of $7.4 million, increased sales of NGLs at Yellow Rose of $1.6 million, and increased volumes and prices of $1.0 million at the Chatom/Bazor Ridge and Glade Crossing facilities. These increases were offset by $10 million due to Topic 606 implementation as discussed above.

Direct Operating Expenses. Direct operating expenses of $12.6 million for six months ended June 30, 2018, a decrease from $16.1 million for the six months ended June 30, 2017. The $3.5 million decrease was mainly due to $1.0 million decrease in outside services, $0.8 million decrease in leases and rents, $0.8 million in lower salaries and wages, and $0.4 million in lower environmental costs. The remaining variance of $0.5 million was due to lower operating expenses mainly at the Longview, Lavaca, Chapel Hill, Chatom-Bazor Ridge and Yellow Rose facilities.

Liquid Pipelines and Services Segment

The table below contains key segment performance indicators related to our Liquid Pipelines and Services segment (in thousands except operating and pricing data).
 
Three months ended June 30,
 
Six months ended June 30,
 
2018
 
2017
 
2018
 
2017
Segment Financial and Operating Data:
 
 
 
 
 
 
 
Liquid Pipelines and Services segment
 
 
 
 
 
 
 
Financial data:
 
 
 
 
 
 
 
Commodity sales
$
116,516

 
$
79,566

 
$
232,297

 
$
158,511

Services
4,101

 
3,591

 
8,091

 
8,057

Revenue from operations
120,617

 
83,157

 
240,388

 
166,568

Gain on commodity derivatives, net
(61
)
 
297

 
(4
)
 
669

Earnings in unconsolidated affiliates
2,485

 
1,482

 
4,706

 
2,569

Segment revenue
123,041

 
84,936

 
245,090

 
169,806

Cost of sales
115,193

 
78,101

 
229,998

 
156,386

Direct operating expenses
2,352

 
2,248

 
5,138

 
4,700

Other financial data:
 
 
 
 
 
 
 
Segment gross margin (1)
$
7,744

 
$
6,765

 
$
15,014

 
$
13,401

Operating data (2)
:
 
 
 
 
 
 
 
Average throughput Pipeline (Bbls/d)
37,199

 
32,957

 
36,153

 
33,020

Average throughput Truck (Bbls/d)
3,180

 
1,943

 
3,567

 
1,751

_______________________
(1) See Note 21 - Reportable Segments for a reconciliation of Segment Gross Margin to its nearest GAAP measure, Income from continuing operations before income taxes.
(2) These volumes exclude volumes from our equity investments.

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

Commodity sales. Segment revenue from crude oil for the three months ended June 30, 2018 was $116.5 million compared to $79.6 million for the three months ended June 30, 2017. The increase of $37.0 million was primarily due to an $8.6 million increase on COSL as a result of increased volume from Shell and Phillips 66 and $31.7 million due to a higher favorable average price increase of $17.20/Bbl in the second quarter of 2018 compared to the second quarter of 2017. These increases were partially offset by $2.1 million as a result of changing the recording of a contract from a gross to net basis and $1.1million as a result of lower volumes of sour crude being processed in 2018.
    

55


Services revenue. Segment services revenue for the three months ended June 30, 2018 was $4.1 million compared to $3.6 million for the three months ended June 30, 2017. An increase of $0.5 million was 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 June 30, 2018 was $2.5 million compared to $1.5 million for the three months ended June 30, 2017. The increase of $1.0 million was primarily due to the Cayenne Pipeline in which we have a 50% interest that began operating in January 2018.

Cost of Sales. Purchases of crude oil for the three months ended June 30, 2018 was $115.2 million compared to $78.1 million for the three months ended June 30, 2017. The increase of $37.1 million resulted from higher volumes primarily due to the new connection with Hunt and Henry Resources that began in December 2017 and higher crude oil pricing.

Direct Operating Expenses. Direct operating expenses were $2.4 million for the three months ended June 30, 2018, an increase from $2.2 million for the three months ended June 30, 2017, mainly due to $0.1 million in higher salaries and wages and $0.1 million in higher leases and rents related to Silver Dollar Pipeline and the Trucking business (COSL Texas Panhandle).

Six Months ended June 30, 2018 Compared to Six Months ended June 30, 2017

Commodity Sales. Segment revenue from crude oil for the six months ended June 30, 2018 was $232.3 million compared to $158.5 million for the six months ended June 30, 2017. The increase of $73.8 million was primarily due to higher prices and volume of $63.2 million on COSL, an increase of $15.1 million due to higher volume and prices on crude oil sales contracts. These increases were partially offset by $5.3 million as a result of implementing Topic 606.

Earnings in Unconsolidated Affiliates. Earnings in unconsolidated affiliates for the six months ended June 30, 2018 was $4.7 million compared to $2.6 million for the six months ended June 30, 2017. The increase of $2.1 million was primarily due to the Cayenne Pipeline, in which we have a 50% interest, that began operating in January 2018.

Cost of Sales. Purchases of crude oil for the six months ended June 30, 2018 was $230.0 million compared to $156.4 million for the six months ended June 30, 2017. The increase of $73.6 million was primarily due to the increase in crude prices and crude sales volumes driven by favorable market conditions resulting in higher realized crude prices and increased producer activity of $61.1 million for COSL, higher volumes and pricing related to marketing contracts of $15.0 million, increased trucking volumes and related expenses of $1.4 million and a decrease of $5.0 million as a result of implementing Topic 606.

Direct Operating Expenses. Direct operating expenses were $5.1 million for the six months ended June 30, 2018, an increase from $4.7 million for the six months ended June 30, 2017. The difference was mainly due to $0.2 million in higher salaries and wages and $0.2 million in higher leases and rents related to Silver Dollar Pipeline and the Trucking business (COSL Texas Panhandle).


56


Natural Gas Transportation Services Segment

The table below contains key segment performance indicators related to our Natural Gas Transportation Services segment (in thousands except operating and pricing data).
 
Three months ended June 30,
 
Six months ended June 30,
 
2018
 
2017
 
2018
 
2017
Segment Financial and Operating Data:
 
 
 
 
 
 
 
Natural Gas Transportation Services segment
 
 
 
 
 
 
 
Financial data:
 
 
 
 
 
 
 
Commodity sales
$
5,475

 
$
6,442

 
$
12,116

 
$
13,310

Services
10,092

 
4,955

 
19,513

 
10,525

Segment revenue
15,567

 
11,397

 
31,629

 
23,835

Cost of sales
5,839

 
5,678

 
11,126

 
11,938

Direct operating expenses
1,812

 
1,928

 
3,485

 
3,163

Other financial data:
 
 
 
 
 
 
 
Segment gross margin (1)
$
9,653

 
$
5,631

 
$
20,340

 
$
11,750

Operating data:
 
 
 
 
 
 
 
Average throughput (MMcf/d)
614.1

 
407.3

 
711.7

 
398.5

 _______________________
(1) See Note 21 - Reportable Segments for a reconciliation of Segment Gross Margin to its nearest GAAP measure, Income from continuing operations before income taxes.

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

Commodity Sales. Segment sales of natural gas, NGLs and condensate for the three months ended June 30, 2018 were $5.5 million compared to $6.4 million for the three months ended June 30, 2017. The decrease was primarily due to lower market pricing.

Services revenue. Segment services revenue for the three months ended June 30, 2018 was $10.1 million compared to $5.0 million for the three months ended June 30, 2017. The increase of $5.1 million was primarily due to increased volumes related to our acquisition of Trans-Union in the fourth quarter of 2017.

Cost of Sales. Purchases of natural gas, NGLs and condensate for the three months ended June 30, 2018 were $5.8 million as compared to $5.7 million for the three months ended June 30, 2017. The increase of $0.2 million can be primarily attributed to $0.9 million related to lower market prices and imbalances on a number of our systems totaling $2.3 million.

Direct Operating Expenses. Direct operating expenses for the three months ended June 30, 2018 were $1.8 million compared to $1.9 million for the three months ended June 30, 2017. The decrease of $0.1 million was primarily due to line loss related to Midla Pipeline.

Six Months Ended June 30, 2018 Compared to Six Months Ended June 30, 2017

Commodity Sales. Segment sales of natural gas, NGLs and condensate for the six months ended June 30, 2018 were $12.1 million compared to $13.3 million for the six months ended June 30, 2017. The decrease of $1.2 million was primarily due to a decrease in market prices related to the Magnolia system.

Services revenue. Segment services revenue for the six months ended June 30, 2018 was $19.5 million compared to $10.5 million for the six months ended June 30, 2017. This increase of $9.0 million was primarily due to an increase of $3.2 million resulting from higher volumes related to our Trans Union acquisition in the fourth quarter of 2017, an increase in marketing activity of $1.2 million and an increase of $0.9 million due to the implementation of accounting Topic 606.

Cost of Sales. Purchases of natural gas, NGLs and condensate for the six months ended June 30, 2018 were $11.1 million as compared to $11.9 million for the six months ended June 30, 2017. This decrease of $0.8 million was primarily due to lower

57


market prices of $1.1 million related to the Magnolia system and imbalances of approximately $1.9 million on a number of our systems.

Direct Operating Expenses. Direct operating expenses for the six months ended June 30, 2018 were $3.5 million compared to $3.2 million for the six months ended June 30, 2017. The increase of $0.3 million was primarily due to property tax adjustments and repair and maintenance costs.

Offshore Pipelines and Services Segment

The table below contains key segment performance indicators related to our Offshore Pipelines and Services segment (in thousands except operating and pricing data).
 
Three months ended June 30,
 
Six months ended June 30,
 
2018
 
2017
 
2018
 
2017
Segment Financial and Operating Data:
 
 
 
 
 
 
 
Offshore Pipelines and Services segment
 
 
 
 
 
 
 
Financial data:
 
 
 
 
 
 
 
Commodity sales
$
2,707

 
$
2,440

 
$
5,256

 
$
6,203

Services
15,812

 
9,699

 
30,124

 
20,767

Revenue from operations
18,519

 
12,139

 
35,380

 
26,970

Earnings in unconsolidated affiliates
7,961

 
16,070

 
18,413

 
30,385

Segment revenue
26,480

 
28,209

 
53,793

 
57,355

Cost of sales
2,150

 
2,586

 
4,146

 
5,929

Direct operating expenses
7,711

 
3,490

 
15,507

 
6,070

Other financial data:
 
 
 
 
 
 
 
Segment gross margin (1)
$
24,330

 
$
25,623

 
$
49,647

 
$
51,426

Operating data (2):
 
 
 
 
 
 
 
Average throughput (MMcf/d)
326.7

 
322.3

 
314.8

 
363.0

_______________________
(1) See Note 21 - Reportable Segments for a reconciliation of Segment Gross Margin to its nearest GAAP measure, Income from continuing operations before income taxes.
(2) These volumes exclude Equity Investment volumes.

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

Commodity Sales. Segment sales of natural gas, NGLs and condensate for the three months ended June 30, 2018 was $2.7 million compared to $2.4 million for the three months ended June 30, 2017. The increase of $0.3 million was 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 revenue. Segment services revenue for the three months ended June 30, 2018 was $15.8 million compared to $9.7 million for the three months ended June 30, 2017. The increase of $6.1 million was primarily due to the impact of acquisitions in the second and third quarters of 2017 of $7.8 million partially offset by a reduction in operating fees and guaranteed revenue, due to a contract change in the first quarter of 2018 on American Panther of $1.2 million and a reduction of other fees at High Point Gas Transmission for $0.5 million.

Earnings in unconsolidated affiliates. Earnings for the three months ended June 30, 2018 were $8.0 million compared to $16.1 million for the three months ended June 30, 2017. The decrease of $8.1 million was primarily due to temporary curtailment of production flows on Delta House as certain third party-owned upstream infrastructure required remediation work. Additionally, Destin was also impacted for $0.9 million and these decreases were partially offset by increased earnings of $0.5 million as a result of new well activity on Okeanos and $0.4 million as a result of MPOG no longer being an unconsolidated affiliate.

Cost of Sales. Purchases of natural gas, NGLs and condensate for the three months ended June 30, 2018 were $2.2 million compared to $2.6 million for the three months ended June 30, 2017. The decrease of $0.4 million was primarily due to the reductions from

58


decreased production at Mud Lake on our Gloria system partially offset by increases due to the Panther acquisition in the third quarter of 2017.

Direct Operating Expenses. Direct operating expenses were $7.7 million for three months ended June 30, 2018 and $3.5 million for the three months ended June 30, 2017. The increase of $4.2 million was primarily due increases in operating costs related to the acquisitions in 2017, comprised of $2.6 million for Panther’s entities and $1.2 million for VKGS, and $0.4 million in repair and maintenance and other operating expenses related to High Point System.

Six Months Ended June 30, 2018 Compared to Six Months Ended June 30, 2017
    
Commodity Sales. Segment sales of natural gas, NGLs and condensate for the six months ended June 30, 2018 was $5.3 million compared to $6.2 million for the six months ended June 30, 2017. This decrease of $0.9 million was primarily due to lower volumes sold to the Phillips 66 Refinery on our Gloria system for $2.6 million partially offset by a $1.6 million increase in sales from the acquisition of Panther in the third quarter of 2017.

Services revenue. Segment services revenue for the six months ended June 30, 2018 was $30.1 million compared to $20.8 million for the six months ended June 30, 2017. This increase of $9.4 million was primarily due to the impact of acquisitions in the second and third quarters of 2017 of $14.8 million partially offset by a reduction in operating fees and guaranteed revenue due to a contract change in the first quarter of 2018 on American Panther of $2.9 million and $2.5 million on HPGT as a result of lower fees.

Earnings in unconsolidated affiliates. Earnings for the six months ended June 30, 2018 were $18.4 million compared to $30.4 million for the six months ended June 30, 2017. The decrease of $12.0 million was primarily due to temporary curtailment of production flows on Delta House as certain third party-owned upstream infrastructure required remediation work. Additionally, Destin was also impacted for $0.7 million and these decreases were partially offset by increased earnings of $1.0 million as a result of new well activity on Okeanos and $0.5 million as a result of MPOG no longer being an unconsolidated affiliate.

Cost of Sales. Purchases of natural gas, NGLs and condensate for the six months ended June 30, 2018 were $4.1 million compared to $5.9 million for the six months ended June 30, 2017. This decrease of $1.8 million was primarily due to the reductions from decreased production at Mud Lake on our Gloria system of $3.2 million offset by a $0.6 million imbalance; imbalance activity at High Point Gas Gathering, L.L.C. (“HPGG”) and High Point Gas Transmission, L.L.C. (“HPGT”) of $1.0 million, offset by an increase of $1.8 million due to the Panther acquisition in the third quarter of 2017.

Direct Operating Expenses. Direct operating expenses of $15.5 million and $6.1 million for the six months ended June 30, 2018 and 2017. This increase of $9.4 million was mainly due to $8.2 million in operating costs related to the acquisitions in 2017, comprised of $5.7 million for Panther’s entities and $2.5 million for VKGS. Additionally, an increase of $0.6 million due to higher insurance costs, $0.4 million related to High Point System repair and maintenance projects. The remaining variance of $0.2 million was due to weather derivatives and line pack adjustments.


59


Terminalling Services Segment

The table below contains key segment performance indicators related to our Terminalling Services segment (in thousands except operating data).
 
Three months ended June 30,
 
Six months ended June 30,
 
2018
 
2017
 
2018
 
2017
Segment Financial and Operating Data:
 
 
 
 
 
 
 
Terminalling Services segment
 
 
 
 
 
 
 
Financial data:
 
 
 
 
 
 
 
Commodity sales
$
3,670

 
$
2,378

 
$
8,674

 
$
7,550

Services
12,690

 
13,453

 
25,084

 
26,907

Segment revenue
16,360

 
15,831

 
33,758

 
34,457

Cost of sales
3,378

 
2,073

 
8,401

 
6,466

Direct operating expenses
4,131

 
2,998

 
8,453

 
6,071

Other financial data:
 
 
 
 
 
 
 
Segment gross margin (1)
$
8,851

 
$
10,760

 
$
16,904

 
$
21,920

Operating data:
 
 
 
 
 
 
 
Contracted capacity (Bbls)
4,574,767
 
5,139,367
 
4,574,767
 
5,219,517
Design capacity (Bbls) (2)
5,417,467
 
5,400,800
 
5,409,133
 
5,400,800
Storage utilization (3)
84.4
%
 
95.2
%
 
84.6
%
 
96.6
%
Terminalling and Storage throughput (Bbls/d)
61,405

 
60,711

 
59,100

 
116,990

__________________
(1) See Note 21 - Reportable Segments for a reconciliation of Segment Gross Margin to its nearest GAAP measure, Income from continuing operations before income taxes.
(2) Excludes terminals in our Refined Products and Marine Products as they have been classified as assets held for sale.
(3) Excludes storage utilization associated with our discontinued operations.

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

Commodity Sales. Segment commodity sales for the three months ended June 30, 2018 was $3.7 million compared to $2.4 million for the three months ended June 30, 2017. The increase of $1.3 million was driven by higher prices at the Caddo Mills and North Little Rock terminals.

Services Revenue. Segment services revenue for the three months ended June 30, 2018 was $12.7 million compared to $13.5 million for the three months ended June 30, 2017. The decrease of $0.8 million was primarily driven by a $2.2 million reduction in storage and utilization at our Cushing terminal due to tank maintenance and a new contract with lower storage and rate terms, partially offset by an increase in storage fees of $0.7 million at the Harvey terminal, a $0.2 million increase in throughput revenues at our Caddo Mills terminal as a result of facility enhancements.

Cost of Sales. Segment purchases of NGLs for the three months ended June 30, 2018 were $3.4 million compared to $2.1 million for the three months ended June 30, 2017. The increase of $1.3 million was primarily due to higher prices of $0.6 million at the Caddo Mills and North Little Rock terminals and the adoption of Topic 606 impacting cost by $0.6 million.

Direct Operating Expenses. Segment direct operating expenses for the three months ended June 30, 2018 were $4.1 million compared to $3.0 million for the three months ended June 30, 2017. This increase of $1.1 million was mainly due to an increase in direct operating expenses at the Harvey, North Little Rock and Brunswick facilities, which was comprised of $0.6 million in other operating expenses such as supplies, tooling and environmental, and $0.3 million in outside services and security contractors, and $0.2 million in utilities and taxes.


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Six Months Ended June 30, 2018 Compared to Six Months Ended June 30, 2017

Commodity Sales. Segment commodity sales for the six months ended June 30, 2018 were $8.7 million compared to $7.6 million for the six months ended June 30, 2017. The increase of $1.1 million was driven by higher prices at the Caddo Mills and North Little Rock terminals.

Services Revenue. Segment services revenue for the six months ended June 30, 2018 was $25.1 million compared to $26.9 million for the six months ended June 30, 2017. The decrease of $1.8 million was primarily driven by a $4.4 million reduction in storage and utilization at our Cushing terminal due to tank maintenance and a new contract with lower storage and rate terms, partially offset by a $2.5 million increase as a result of adopting Topic 606.

Cost of Sales. Segment purchases of NGLs for the six months ended June 30, 2018 was $8.4 million compared to $6.5 million for the six months ended June 30, 2017. The increase of $1.9 million was primarily due to the higher costs related to volumes sold at the Caddo Mills and North Little Rock terminals and the adoption of Topic 606 increasing costs by approximately $1.6 million.

Direct Operating Expenses. Segment direct operating expense for the six months ended June 30, 2018 was $8.5 million compared to $6.1 million for the six months ended June 30, 2017. This increase of $2.4 million was mainly due to an increase at the Harvey, North Little Rock, Westwego and Brunswick facilities, which was comprised of $1.0 million in outside services (security contractors and general repair and maintenance costs), $0.4 million in utilities and taxes and $1.0 million in higher reimbursable costs at Harvey, Westwego and Brunswick facilities.

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.

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.

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. 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. Availability and terms of any financing depend on market and other conditions, many of which are beyond our control. We may not be able to access financing 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

61


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.

On June 29, 2018, we amended our $900 million revolving credit facility agreement, dated March 8, 2017 (the “Original Credit Agreement”), by entering into that certain 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 the Marine Terminals and Refined Products asset sales and any other disposition greater than $5 million.

Among other things, the Amendment also amends our borrowing capacity as follows:

•
upon consummation of the Marine Terminals sale, the aggregate commitments under the Credit Agreement shall be automatically reduced by $200 million;
•
upon consummation of the Refined Products sale, the aggregate commitments 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 commitments 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:
 
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

The revolving credit facility is scheduled to mature on September 5, 2019.

As of June 30, 2018, after giving effect to the amendments to the ratios, we were in compliance with our Credit Agreement financial covenants, including those shown below:

Ratio
 
 
 
Actual
Minimum Consolidated Interest Coverage Ratio
 
 
 
3.11
Maximum Allowable Consolidated Total Leverage Ratio
 
 
 
5.42
Maximum Allowable Consolidated Secured Leverage Ratio
 
 
 
3.50


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As of June 30, 2018, we had approximately $776.3 million of borrowings, $39.0 million of letters of credit outstanding under the Credit Agreement and approximately $71.6 million of available borrowing capacity which can be increased up to $84.7 million, conditional upon compliance with future covenants. For the first half of 2018 and 2017 the weighted average interest rate on borrowings under this facility was approximately 5.81% and 4.67%, 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.

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.

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. Our working capital was $23.2 million and $16.2 million as of June 30, 2018 and December 31, 2017, respectively.

Cash Flows

The following table reflects cash flows for the applicable periods (in thousands):
 
 
Six months ended June 30,
 
 
2018
 
2017
Net cash provided by (used in):
 
 
 
 
Operating activities
 
$
8,960

 
$
28,358

Investing activities
 
(36,321
)
 
(70,328
)
Financing activities
 
40,182

 
(257,354
)
Net decrease in cash, cash equivalents and restricted cash
 
$
12,821

 
$
(299,324
)

Six Months Ended June 30, 2018 Compared to Six Months Ended June 30, 2017

Operating Activities. During the six months ended June 30, 2018, we had $9.0 million of cash provided by operating activities, a decrease of $19.4 million as compared to $28.4 million in the same period in 2017. The decrease in cash flows from operating activities resulted primarily from a decline in distributions from unconsolidated affiliates of $11.6 million and a net decrease in operating assets and liabilities of $8.5 million.

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Investing Activities. During the six months ended June 30, 2018, net cash used in investing activities was $36.3 million, a decrease of $34.0 million as compared to the same period of 2017. The decline in cash flows used in investing activities was driven primarily from a reduction in acquisition activity in 2018 of $32.0 million, an increase in net cash distributions from our unconsolidated affiliates of $14.8 million, offset by an increase in capital expenditures of $12.5 million.
Financing Activities. During the six months ended June 30, 2018, net cash provided by financing activities was $40.2 million as compared to net cash used in financing activities of $257.4 million in the same period in 2017. The change was primarily driven by an increase in net borrowings from our Credit Agreement of $78.4 million in 2018, as compared to a net repayment on our Credit Agreement in 2017 of $210.2 primarily from the $199.5 pay down and termination of the JPE Revolver in March 2017, combined with a decrease in cash distributions of $8.0 million 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.

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 (“DCF”) 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 June 30,
 
Six Months ended June 30,
 
 
2018
 
2017
 
2018
 
2017
Adjusted EBITDA
 
$
51,240

 
$
44,540

 
$
103,657

 
$
93,082

Deduct:
 
 
 
 
 
 
 
 
Interest expense, net of capitalized interest excluding unrealized gain (loss) on interest rate swaps, amortization of deferred financing costs and letter of credit fees

 
(19,298
)
 
(13,937
)
 
(36,987
)
 
(30,651
)
Maintenance capital
 
(2,576
)
 
(2,113
)
 
(7,079
)
 
(4,121
)
Preferred distribution
 
(8,354
)
 
(6,734
)
 
(16,708
)
 
(13,441
)
Distributable Cash Flow
 
$
21,012

 
$
21,756

 
$
42,883

 
$
44,869

 
 
 
 
 
 
 
 
 
Limited Partner Distributions
 
$
5,463

 
$
21,390

 
$
27,319

 
$
46,303

 
 
 
 
 
 
 
 
 
Distribution Coverage
 
3.8
x
 
1.0
x
 
1.6
x
 
1.0
x

During the three months ended June 30, 2018, we paid a total of approximately $21.9 million of distributions to our unitholders associated with the first 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 noncore 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;

64


•
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 July 27, 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 second quarter of 2018. The distribution will be paid on August 14, 2018 to unitholders of record as of the close of business on August 6, 2018. The quarterly cash distribution for the second quarter of 2018 represents a reduction in the quarterly common unit distribution from prior quarters as a part of our revised capital allocation strategy we announced in July 2018. 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 six months ended June 30, 2018, capital expenditures totaled $30.6 million and $56.5 million, respectively. This included expansion capital expenditures of $27.5 million and $47.2 million, maintenance capital expenditures of $2.6 million and $7.1 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 $2.3 million, respectively, for the three and six months ended June 30, 2018.

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 six months ended June 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 2017 Form 10-K.

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 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 June 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.

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).


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Commodity Swaps
 
Fair Value Asset (Liability)
 
Effect of 10% Price Increase
 
Effect of 10% Price Decrease
NGLs Fixed Price (gallons)
 
$(240)
 
$(517)
 
$40

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 June 30, 2018, we had exposure to changes in interest rates on our indebtedness associated with our Credit Agreement.

As of June 30, 2018, we had a combined notional principal amount of $550.0 million of variable to fixed interest rate swap agreements. As of June 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 June 30, 2018, a hypothetical increase or decrease in interest rates by 1.0% would have changed our interest expense by $2.3 million for the six months ended June 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 June 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 June 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, 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 June 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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Other Information

A copy of the Audit Committee charter is available on our website at http://www.americanmidstream.com/investor-relations/corporate-governance/governance-overview/default.aspx pursuant to Rule 303A.07 of the New York Stock Exchange Listed Company Manual.

Additionally, we have made the following disclosure available on our website at http://www.americanmidstream.com/investor-relations/corporate-governance/committee-composition/default.aspx pursuant to Rule 303A.03 of the New York Stock Exchange Listed Company Manual.
 
Currently, Mr. Erhard presides at the executive sessions of the non-management directors and the chairman of the Audit Committee, Mr. Tywoniuk, presides at the executive sessions of the independent directors.

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, careful consideration should be given to the risk factors discussed under the caption “Risk Factors” in Part I, Item 1A of our Annual Report in 2017 Form 10-K. 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.


67


---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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**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.

69


SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this Quarterly Report to be signed on its behalf by the undersigned thereunto duly authorized.
Date: August 14, 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)


70