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 March 31, 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)
amidlogo2017largea03.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)
(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, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” or an “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):
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 52,858,782 common units, 11,009,729 Series A Units, and 9,241,642 Series C Units of American Midstream Partners, LP outstanding as of April 30, 2018. Our common units trade on the New York Stock Exchange under the ticker symbol “AMID.”




Glossary of Terms

As generally used in the energy industry and in this Quarterly Report on Form 10-Q (the “Quarterly Report”), the identified terms have the following meanings:

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

Bbl/d        Barrels per day.

Btu
British thermal unit; the approximate amount of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

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.

As used in this Quarterly Report, unless the context otherwise requires, “we,” “us,” “our,” the “Partnership” and similar terms refer to American Midstream Partners, LP, together with its consolidated subsidiaries.

2


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, except unit amounts)
 
March 31, 2018
 
December 31, 2017
Assets
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
8,191

 
$
8,782

Restricted cash
18,269

 
20,352

Accounts receivable, net of allowance for doubtful accounts of $312 and $225 as of March 31, 2018 and December 31, 2017, respectively
87,418

 
98,132

Inventory
4,795

 
2,966

Other current assets (Note 6)
25,265

 
23,420

Assets held for sale (Note 4)
129,247

 
—

Total current assets
273,185

 
153,652

Property, plant and equipment, net
1,080,897

 
1,095,585

Goodwill
67,985

 
128,866

Restricted cash-long term
5,048

 
5,045

Intangible assets, net
141,627

 
174,010

Investments in unconsolidated affiliates
339,271

 
348,434

Other assets, net
25,249

 
17,874

Total assets
$
1,933,262

 
$
1,923,466

Liabilities, Equity and Partners’ Capital
 
 
 
Current liabilities
 
 
 
Accounts payable
$
52,685

 
$
41,102

Accrued gas and crude oil purchases
14,925

 
19,986

Accrued expenses and other current liabilities
88,123

 
68,854

Current portion of long-term debt
5,058

 
7,551

Liabilities held for sale (Note 4)
3,337

 
—

Total current liabilities
164,128

 
137,493

Asset retirement obligations
66,894

 
66,194

Other long-term liabilities
15,542

 
2,080

3.77% Senior secured notes (Non-recourse)
54,682

 
55,198

8.50% Senior unsecured notes
418,078

 
418,421

Revolving credit facility
712,600

 
697,900

3.97% Trans-Union Secured Senior notes
29,486

 
29,937

Deferred tax liability
8,274

 
8,123

Total liabilities
1,469,684

 
1,415,346

Commitments and contingencies (Note 18)


 


Convertible preferred units
317,180

 
317,180

Equity and partners’ capital
 
 
 
General Partner interests (960 thousand and 965 thousand units issued and outstanding as of March 31, 2018 and December 31, 2017, respectively)
(88,746
)
 
(96,552
)
Limited Partner interests (52,853 thousand and 52,711 thousand units issued and outstanding as of March 31, 2018 and December 31, 2017, respectively)
221,346

 
273,703

Accumulated other comprehensive income
12

 
28

Total partners’ capital
132,612

 
177,179

Noncontrolling interests
13,786

 
13,761

Total equity and partners’ capital
146,398

 
190,940

Total liabilities, equity and partners’ capital
$
1,933,262


$
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 March 31,
 
2018
 
2017
Revenue:
 
 
 
Commodity sales
$
158,863

 
$
123,521

Services
46,906

 
40,192

     Gain on commodity derivatives, net
60

 
365

Total revenue
205,829


164,078

Operating expenses:
 
 
 
Costs of sales
150,166

 
115,468

Direct operating expenses
23,446

 
17,405

Corporate expenses
22,692

 
30,113

Depreciation, amortization and accretion
21,997

 
25,570

Gain on sale of assets, net
(95
)
 
(21
)
Total operating expenses
218,206


188,535

Operating loss
(12,377
)

(24,457
)
Other income (expense), net
 
 
 
     Interest expense, net of capitalized interest
(13,876
)
 
(17,956
)
Other income (expense), net
22

 
(37
)
Earnings in unconsolidated affiliates
12,673

 
15,402

Loss from continuing operations before income taxes
(13,558
)

(27,048
)
Income tax expense
(280
)
 
(1,123
)
Loss from continuing operations
(13,838
)

(28,171
)
Loss from discontinued operations
—

 
(710
)
Net loss
(13,838
)

(28,881
)
Less: Net income attributable to noncontrolling interests
45

 
1,303

Net loss attributable to the Partnership
$
(13,883
)

$
(30,184
)
 
 
 
 
General Partner’s interest in net loss
$
(181
)
 
$
(420
)
Limited Partners’ interest in net loss
$
(13,702
)
 
$
(29,764
)
 
 
 
 
Distribution declared per common unit
$
0.4125

 
$
0.4125

Limited Partners’ net loss per common unit:
 
 
Basic and diluted:
 
 
 
Loss from continuing operations
$
(0.42
)
 
$
(0.74
)
Loss from discontinued operations
—

 
(0.01
)
Net loss per common unit
$
(0.42
)

$
(0.75
)
Weighted average number of common units outstanding:
Basic and diluted
52,769

 
51,451

 
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 March 31,
 
2018
 
2017
Net loss
$
(13,838
)
 
$
(28,881
)
Unrealized gain (loss) related to postretirement benefit plan
(16
)
 
18

Comprehensive loss
(13,854
)

(28,863
)
Less: Comprehensive income attributable to noncontrolling interests
45

 
1,303

Comprehensive loss attributable to the Partnership
$
(13,899
)

$
(30,166
)
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 Partners’ Capital
and Noncontrolling Interests
(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 income (loss)
(420
)
 
(29,764
)
 
 
—

 
(30,184
)
 
1,303

 
(28,881
)
Issuance of common units, net of offering costs
—

 
(72
)
 
 
—

 
(72
)
 
—

 
(72
)
Contributions
123

 
4,000

 
 
—

 
4,123

 
—

 
4,123

Distributions
(282
)
 
(33,685
)
 
 
—

 
(33,967
)
 
—

 
(33,967
)
Distribution to noncontrolling interests (“NCI”) owners
—

 
—

 
 
—

 
—

 
(868
)
 
(868
)
Contributions from NCI owners
—

 
—

 
 
—

 
—

 
280

 
280

LTIP vesting
(2,135
)
 
2,135

 
 
—

 
—

 
—

 
—

Tax netting repurchase
—

 
(971
)
 
 
—

 
(971
)
 
—

 
(971
)
Equity compensation expense
3,304

 
733

 
 
—

 
4,037

 
—

 
4,037

Other comprehensive income
—

 
—

 
 
18

 
18

 
—

 
18

Balances at March 31, 2017
$
(47,055
)

$
558,463



$
(22
)

$
511,386


$
17,470

 
$
528,856

 
 
 
 
 
 
 
 
 
 
 
 
 
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
(181
)
 
(13,702
)
 
 
—

 
(13,883
)
 
45

 
(13,838
)
Contributions
9,870

 
—

 
 
—

 
9,870

 
—

 
9,870

Distributions
(392
)
 
(29,728
)
 
 
—

 
(30,120
)
 
—

 
(30,120
)
Distributions to NCI owners
—

 
—

 
 
—

 
—

 
(20
)
 
(20
)
Distribution for acquisition of Trans-Union
(38
)
 
—

 
 
—

 
(38
)
 
—

 
(38
)
LTIP vesting
(2,328
)
 
2,328

 
 
—

 
—

 
—

 
—

Tax netting repurchase
—

 
(703
)
 
 
—

 
(703
)
 
—

 
(703
)
Equity compensation expense
1,014

 
—

 
 
—

 
1,014

 
—

 
1,014

Other comprehensive income
—

 
—

 
 
(16
)
 
(16
)
 
—

 
(16
)
Balances at March 31, 2018
$
(88,746
)

$
221,346



$
12


$
132,612


$
13,786

 
$
146,398

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)

Three months ended March 31,

2018
 
2017
Cash flows from operating activities

 

Net loss
$
(13,838
)
 
$
(28,881
)
Adjustments to reconcile net loss to net cash provided by operating activities including discontinued operations:

 

Depreciation, amortization and accretion
21,997

 
29,351

Amortization of deferred financing costs
1,316

 
1,253

Amortization of weather derivative premium
278

 
257

Unrealized (gain) loss on derivatives contracts, net
(5,112
)
 
1,273

Non-cash compensation expense
1,014

 
4,037

Gain on sale of assets, net
(95
)
 
(228
)
Corporate overhead support
—

 
4,000

Other non-cash items
(15
)
 
1,965

   Earnings in unconsolidated affiliates
(12,673
)
 
(15,402
)
Distributions from unconsolidated affiliates
12,673

 
15,402

Deferred tax expense
151

 
678

Bad debt expense
87

 
830

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

Accounts receivable
7,251

 
266

Inventory
(3,399
)
 
(2,626
)
Other current assets
(4,174
)
 
3,114

Other assets, net
—

 
168

Accounts payable
11,200

 
(9,716
)
Accrued gas and crude oil purchases
(4,431
)
 
2,403

Accrued expenses and other current liabilities
2,623

 
994

Asset retirement obligations
(6
)
 
(41
)
Other liabilities
—

 
(250
)
Net cash provided by operating activities
14,847


8,847

 
 
 
 
Cash flows from investing activities

 

Contributions to unconsolidated affiliates
(987
)
 
—

Additions to property, plant and equipment and other
(25,946
)
 
(20,221
)
Proceeds from disposals of property, plant and equipment
8

 
51

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

 
150

Distributions from unconsolidated affiliates, return of capital
11,181

 
7,092

Net cash used in investing activities
(15,744
)
 
(12,928
)
 
 
 
 
Cash flows from financing activities

 

Proceeds from issuance of common units to public, net of offering costs
—

 
(72
)
Contributions
9,870

 
123

Distributions
(22,035
)
 
(32,198
)
Contribution from noncontrolling interest owners
—

 
280

Distributions to noncontrolling interests owners
(20
)
 
(868
)
LTIP tax netting unit repurchase
(703
)
 
(971
)
Payment of deferred financing costs
(1,085
)
 
(1,402
)
Payment of 3.77% Senior Notes
(507
)
 
—

Payment of 3.97% Senior Notes
(439
)
 
—

Payments of other debt
(1,893
)
 
(2,363
)
Payments of credit agreement
(119,700
)
 
(325,908
)
Borrowings on credit agreement
134,400

 
82,500


8



Three months ended March 31,

2018
 
2017
Other
338

 
(20
)
Net cash used in financing activities
(1,774
)

(280,899
)
 
 
 
 
Net decrease in cash, cash equivalents, and restricted cash
(2,671
)

(284,980
)
Cash, cash equivalents, and restricted cash, beginning of period
34,179

 
329,230

Cash, cash equivalents, and restricted cash, end of period
$
31,508

 
$
44,250

 
 
 
 
Cash and cash equivalents, beginning of period
8,782

 
5,666

Restricted cash, beginning of period
25,397

 
323,564

Cash, Cash equivalents and Restricted cash, beginning of period
34,179

 
329,230

 
 
 
 
Cash and cash equivalents, end of period
8,191

 
16,919

Restricted cash, end of period
23,317

 
27,331

Cash, Cash equivalents and Restricted cash, end of period
31,508

 
44,250

 
 
 
 
Net decrease in Cash, Cash equivalents and Restricted cash
$
(2,671
)
 
$
(284,980
)

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

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



(1) Organization and Basis of Presentation

Organization

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

We provide critical midstream infrastructure that links producers of natural gas, crude oil, NGLs, condensate and specialty chemicals to numerous intermediate and end-use markets. Through our five reportable segments, (1) gas gathering and processing services, (2) liquid pipelines and services, (3) natural gas transportation services, (4) offshore pipelines and services, and (5) terminalling services, we engage in the business of gathering, treating, processing and transporting natural gas; gathering, transporting, storing, treating and fractionating NGLs; gathering, storing and transporting crude oil and condensates and storing 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.

Our primary assets are strategically located in some of the most prolific onshore and offshore producing regions and key demand markets in the United States. Our gathering and processing assets are primarily located in (i) the Permian Basin of West Texas, (ii) the Cotton Valley/Haynesville Shale of East Texas, (iii) the Eagle Ford Shale of South Texas, (iv) the Bakken Shale of North Dakota, and (v) offshore in the Gulf of Mexico. Our transmission and terminal assets are in key demand markets in Oklahoma, Alabama, Arkansas, Louisiana, Mississippi and Tennessee and in the Port of New Orleans in Louisiana and the Port of Brunswick in Georgia.

Basis of presentation

The accompanying condensed consolidated financial statements have been prepared in accordance with GAAP for interim consolidated financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. They do not include all of the information and notes required by GAAP for annual consolidated financial statements and should therefore be read in conjunction with our annual consolidated financial statements and notes presented in our Annual Report on Form 10-K for the year ended December 31, 2017. In the opinion of management, the condensed consolidated financial statements contain all adjustments, consisting only of normal recurring adjustments, necessary to fairly state our financial position, results of operations and cash flows for the interim periods reported.

These condensed consolidated financial statements follow the same significant accounting policies as those included in our annual consolidated financial statements for the year ended December 31, 2017, except for the adoption of new standards. See Notes 2 and 3 for additional information on the adoption of new standards. Certain prior period amounts have been reclassified to conform to the current presentation.

The accompanying condensed consolidated financial statements include accounts of the Partnership and its consolidated subsidiaries. All significant inter-company accounts and transactions have been eliminated in the preparation of the accompanying condensed consolidated financial statements.
 
We may enter into transactions with ArcLight or its affiliates whereby we receive midstream assets or other businesses in exchange for cash or Partnership's equity. As the transactions are between entities under common control we account for the net assets acquired at the affiliate's historical cost basis, whether the transactions are considered assets or business acquisitions. In certain cases, our historical financial statements will be revised to include the results attributable to the assets acquired from the later of April 15, 2013 (the date ArcLight affiliates obtained control of our General Partner) or the date the ArcLight affiliates obtained control of the assets or business acquired.


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


(2) New Accounting Pronouncements

Adopted in 2018

The Partnership adopted Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers (Topic 606)” issued by the Financial Accounting Standards Board (FASB) on January 1, 2018. See Note 3 - Revenue Recognition for more information on the impact of its adoption.

In August 2016, the FASB issued 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 eight cash flow classification issues, including debt prepayment or debt extinguishment costs, to reduce diversity in practice. ASU 2016-15 is effective for interim and annual periods beginning after December 15, 2017. There was no impact of the retrospective adoption of this ASU on the Partnership’s condensed consolidated statement of cash flows.

In November 2016, the FASB issued ASU No. 2016-18 (“ASU 2016-18”), “Statement of Cash Flows (Topic 230): Restricted Cash”, 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. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017.

We adopted both ASU 2016-15 and ASU 2016-18 on its effective date of January 1, 2018 using the retrospective transition method. Upon adoption of the standards, the Partnership’s condensed consolidated statement of cash flows for the period ended March 31, 2017 was impacted as follows (in thousands):
 
Three months ended March 31, 2017

Condensed Consolidated Statement of Cash Flows
As Previously Reported
 
Effect of Adoption
 
As Adjusted
Cash flows from operating activities
 
 
 
 
 
Net loss
$
(28,881
)
 
$
—

 
$
(28,881
)
Adjustments to reconcile net loss to net cash provided by operating activities including discontinued operations (excluding ‘Other non-cash items’)
39,416

 
—

 
39,416

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

(1 
) 
—

Changes in operating assets and liabilities, net of effects of assets acquired and liabilities assumed (excluding ‘Restricted cash’)
(1,633
)
 
(55
)
(1 
) 
(1,688
)
          Net cash provided by (used in) operating activities
5,767

 
3,080

 
8,847

 
 
 
 
 
 
Cash flows from investing activities
 
 
 
 
 
Restricted cash
299,313

 
(299,313
)
(1 
) 
—

Other investing activities (excluding ‘Restricted cash’)
(12,928
)
 
 
 
(12,928
)
          Net cash provided by (used in) investing activities
286,385

 
(299,313
)
 
(12,928
)
 
 
 
 
 
 
Cash flows from financing activities
 
 
 
 
 
Other financing activities
(280,899
)
 
—

 
(280,899
)
          Net cash used in financing activities
(280,899
)
 
—

 
(280,899
)
          Net increase (decrease) in cash, cash equivalents, and restricted cash
11,253

 
(296,233
)
 
(284,980
)
 
 
 
 
 
 
Cash, cash equivalents and Restricted Cash
 
 
 
 
 
     Beginning of period
5,666

 
323,564

 
329,230

     End of period
$
16,919

 
$
27,331

 
$
44,250

_____________________________________________ 
(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.


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


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. The accounting update was adopted on its effective date January 1, 2018, on a prospective basis. Based on historical patterns of our unit-based awards, which did not involve material modifications, we do not expect the adoption of this accounting update to have a material impact on our consolidated financial position, cash flows or results of operations.

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)”, 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 No. 2018-05/Topic 740 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 immaterial.

Standards Not Yet Adopted

In February 2016, the FASB issued ASU No. 2016-02 (Topic 842) "Leases", which supersedes the lease recognition requirements in Accounting Standards Codification (“ASC”) Topic 840, "Leases". Under ASU No. 2016-02, lessees are required to recognize assets and liabilities on the balance sheet for most leases and to provide enhanced disclosures. Leases will continue to be classified as either finance or operating. ASU No. 2016-02 is effective for annual reporting periods, and interim periods within those years beginning after December 15, 2018. Entities are required to use a modified retrospective approach for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements, and there are certain optional practical expedients that an entity may elect to apply. Full retrospective application is prohibited, and early adoption by public entities is permitted. We are in the process of evaluating the impact of ASU No. 2016-02 on our consolidated financial statements as we will be required to reflect our various lease obligations and associated asset use rights on our consolidated balance sheets. The adoption may also impact our debt covenant compliance and may require us to modify or replace certain of our existing information systems. We are finalizing our selection of a third-party consulting firm to assist us with the adoption of the new guidance and are currently in the Impact Assessment phase. We are not yet able to determine whether the adoption of this standard will have a material impact on our consolidated financial statements and related disclosures, including additional changes, if any, to our accounting system to capture data for disclosure purposes. We will adopt the guidance on its effective date January 1, 2019.
In January 2018, the FASB issued ASU No. 2018-01, “Leases - Land Easement Practical Expedient for Transition to Topic 842” to provide an optional transition practical expedient to forego evaluation under Topic 842 of existing or expired land easements that were not previously accounted for as leases under the current guidance found in Topic 840. An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 beginning at the date that the entity adopts Topic 842. An entity that does not elect this practical expedient should evaluate all existing or expired land easements in connection with the adoption of the new lease requirements in Topic 842 to assess whether they meet the definition of a lease. As discussed above, we are finalizing our selection of a third-party consulting firm to assist us with the adoption of the new guidance and are currently in the Impact Assessment phase. We are not yet able to determine whether we would elect this practical expedient or whether the adoption of this standard will have a material impact on our consolidated financial position, results of operations and cash flows, as well as related disclosures, including additional changes, if any, to our accounting system to capture data for disclosure purposes. We will adopt this on its effective date January 1, 2019.

In June 2016, the FASB issued 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 this ASU 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.







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



(3) Revenue Recognition

Adoption of Topic 606

ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606)”, supersedes previous revenue recognition guidance, establishes a principle-based model to be applied to all contracts with customers and introduces enhanced disclosure requirements. It also requires the use of more estimates and judgments than the previous standards. We adopted the new standard and the series of related accounting standard updates that followed (collectively referred to as “Topic 606”) on January 1, 2018, using the modified retrospective method applied to those contracts which were not completed as of January 1, 2018 and any new contracts entered into after January 1, 2018. Under this method, the financial information of previous years has not been adjusted.

While the Partnership does not expect future net earnings to be materially impacted by revenue recognition timing changes, we recognized the cumulative effect of the adoption as a decrease in the opening balance of partners' capital of approximately $10.7 million. The adjustment was primarily related to four contracts where the allocation of the transaction prices resulted in changes to the pattern and timing of revenue recognition for those contracts as compared to the cash received for certain up-front fees for capital recovery as well as contracts with tiered fee structures.

The following tables summarize the impacts of adopting Topic 606 on the Partnership’s condensed consolidated financial statements as of and for the three months ended March 31, 2018, adjusting for the differences between revenue as reported following adoption of Topic 606 and revenue as it would have been reported under previous standards (in thousands):
 
Three months ended March 31, 2018
Condensed Consolidated Statement of Income
As Reported
 
Adjustments
 
Amounts without Adoption of Topic 606
Revenue
 
 
 
 
 
Commodity sales
$
158,863

 
$
5,242

 
$
164,105

Services
46,906

 
(2,681
)
 
44,225

Operating expenses
 
 
 
 
 
Costs of sales
150,166

 
3,165

 
153,331

Direct operating expenses
23,446

 
(456
)
 
22,990

Operating loss
(12,377
)
 
(148
)
 
(12,525
)
Net loss attributable to the Partnership
$
(13,883
)
 
$
(148
)
 
$
(14,031
)
 
 
 
 
 
 
General Partner’s interest in net loss
$
(181
)
 
$
(2
)
 
$
(183
)
Limited Partners’ interest in net loss
(13,702
)
 
(146
)
 
(13,848
)


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


 
As of March 31, 2018
Condensed Consolidated Balance Sheet (in thousands)
As Reported
 
Adjustments
 
Amounts without Adoption of Topic 606
Assets
 
 
 
 
 
Accounts receivable, net
$
87,418

 
$
(67,553
)
 
$
19,865

Unbilled revenue
—

 
67,553

 
67,553

Other current assets
25,265

 
—

 
25,265

Other noncurrent assets
25,249

 
(3,419
)
 
21,830

Liabilities
 
 
 
 
 
Accrued expenses and other current liabilities
88,123

 
—

 
88,123

Liabilities held for sale
3,337
 
(459
)
 
2,878

Other noncurrent liabilities
15,542

 
(13,503
)
 
2,039

Equity and partners’ capital
 
 

 
 
General partner interests
$
(88,746
)
 
$
137

 
$
(88,609
)
Limited partner interests
221,346

 
10,406

 
231,752


The majority of the adjustments in the table above were associated with our natural gas gathering, processing and transportation revenues and our terminalling and storage 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. While reported revenues and expenses can be materially reduced, these presentation changes may not materially impact net earnings.

Revenue from Contracts with Customers

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, 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 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.

Under Topic 606, we disaggregate our revenues for disclosure purposes by segment and type of activity. These categories depict how the nature, amount, timing and uncertainty of revenues and cash flows are affected by economic factors. Our business activities are conducted through our five reportable segments, shown below. See Note 21 - Reportable Segments for further discussion of our reportable segments. The following table presents our segment revenues from contracts with customers disaggregated by type of activity (in thousands):

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


 
Three months ended March 31, 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
$
1,906

 
$
—

 
$
6,637

 
$
2,437

 
$
—

 
$
10,980

     NGLs
21,150

 
—

 
—

 
38

 
—

 
21,188

     Condensate
5,648

 
—

 
—

 
34

 
—

 
5,682

     Crude oil
—

 
115,782

 
—

 
—

 
—

 
115,782

     Other sales (1)
183

 
—

 
4

 
40

 
5,004

 
5,231

 
 
 
 
 
 
 
 
 
 
 
 
Services:
 
 
 
 
 
 
 
 
 
 
 
     Gathering and processing
6,250

 
—

 
—

 
866

 
—

 
7,116

     Transportation
105

 
3,588

 
9,412

 
8,661

 
—

 
21,766

     Terminalling and storage
—

 
—

 
—

 
—

 
11,833

 
11,833

     Other services (2)
434

 
403

 
10

 
4,783

 
561

 
6,191

Revenues from contracts with customers
$
35,676

 
$
119,773

 
$
16,063

 
$
16,859

 
$
17,398

 
$
205,769

(1) Other commodity sales for our Terminalling Services segment include sales of refined product. The Partnership is actively marketing for sale all of its assets in the Terminalling Services segment. See Note 4 - Acquisitions and Dispositions.
(2) Other services in our Offshore Pipelines and Services segment include asset management services.

Commodity Sales

The Partnership sells various commodities as shown in the table above. Generally, 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 contracts 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.

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 end based on our right to invoice at month end for the value of services provided to the customer that month.

The transaction price is recognized as revenue 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

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


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 and 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. At March 31, 2018, customer deficiencies associated with firm services were immaterial.

Interruptible Services

Interruptible services are the opposite of firm services in that such services are 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 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

In our Gas Gathering and Processing Services segment, we purchase gas volumes from producers at the wellhead, production facility, or at receipt points on our systems typically at an index price, and charge the producer fees associated with the downstream gathering and processing services. 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 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.

    

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


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.

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 statement of operations (in thousands):
 
Three months ended March 31, 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
$
35,676

 
$
119,773

 
$
16,063

 
$
16,859

 
$
17,398

 
$
205,769

Gains (losses) on commodity derivatives, net
2

 
58

 
—

 
—

 
—

 
60

     Total revenues of reportable segments
$
35,678

 
$
119,831

 
$
16,063

 
$
16,859

 
$
17,398

 
$
205,829

    
We may utilize derivatives 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 revenue is not included as a component of revenue from contracts with customers, but is included in other items in revenue.

Contract Balances

Our contract balances primarily consist of customer receivables and contract assets and liabilities. Trade accounts receivable, net consists of the following as presented on our condensed consolidated balance sheet (in thousands):
 
March 31, 2018
Receivables arising from revenue contracts
 
     Unbilled customer receivables
$
67,553

     Billed customer receivables
20,177

     Allowance for doubtful accounts
(312
)
          Accounts receivable, net
$
87,418


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.

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



The following table presents the change in the contract assets and liability balances during the three months ended March 31, 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
—

 
(502
)
Additions
864

 
1,205

Total balance at March 31, 2018
3,419

 
16,085

Classified as held for sale
—

 
(708
)
Balance at March 31, 2018
$
3,419

 
$
15,377

 
 
 
 
Current
—

 
998

Noncurrent
3,419

 
14,379

Balance at March 31, 2018
$
3,419

 
$
15,377


In our condensed consolidated balance sheet as of March 31, 2018, current portions of contract assets are included in other current assets, noncurrent portions of contract assets are included in other (noncurrent) assets, current portions of contract liabilities are included in other current liabilities and noncurrent portions of contract liabilities are 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. Therefore, the following table as of March 31, 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 revenues supported by minimum volume commitments
$
9,252

 
$
12,743

 
$
12,743

 
$
12,720

 
$
12,467

 
$
19,155

 
$
79,080

Transportation agreements
15,921

 
19,233

 
18,475

 
18,207

 
18,100

 
190,416

 
280,352

Terminalling and storage throughput agreements
10,821

 
12,823

 
6,220

 
2,715

 
1,593

 
—

 
34,172

Other
1,170

 
1,560

 
1,560

 
—

 
—

 
—

 
4,290

Total
$
37,164

 
$
46,359

 
$
38,998

 
$
33,642

 
$
32,160

 
$
209,571

 
$
397,894


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.

(4) Acquisitions and Dispositions

Acquisitions

As more fully described in our Annual Report for the year ended December 31, 2017, during 2017, the Partnership completed various acquisitions, the results of which are fully reflected in the first quarter of 2018, but are not reflected in the comparable period of 2017 due to the closing dates of the acquisitions. The pro forma effects of these acquisitions were immaterial

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


to our condensed consolidated statement of operations for the three months ended March 31, 2017 and, therefore, have not been separately disclosed.
Acquisitions accounted for as business combinations included the following:

•
On June 2, 2017, we acquired 100% of the Viosca Knoll Gathering System (“VKGS”) from Genesis Energy, L.P. for total consideration of approximately $32 million in cash.
•
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.
•
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.

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 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 consideration of $30.0 million. Prior to 2017, we acquired other interests from Emerald, as detailed in Note 10 - Investments in Unconsolidated Affiliates, collectively referred to as the “Emerald Transactions.”

              During the three months ended March 31, 2018, there were no acquisitions. 

Planned Dispositions

Business Held for Sale

During 2017, the Partnership began actively marketing for sale all of its assets in the Terminalling Services segment as part of its plan to divest certain non-core assets and utilize the proceeds to fund future acquisitions and growth projects. On February 16, 2018, the Partnership entered into a definitive agreement for the sale of our refined products terminals (the "Refined Products Business") to DKGP Energy Terminals LLC, a joint venture between Delek Logistics Partners, LP and Green Plains Partners LP, for approximately $138.5 million in cash, subject to working capital adjustments. Accordingly, we have presented the assets and liabilities of the Refined Products Business as held for sale. The Refined Products Business is a portion of the Terminalling Services segment consisting of two terminal facilities located in Caddo Mills, Texas and North Little Rock, Arkansas. As such, this planned disposition does not meet the criteria for discontinued operations.

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


In view of the planned sale, which remains subject to customary closing conditions, we have classified our assets and liabilities of the Refined Products Business in current assets and liabilities held for sale on our condensed consolidated balance sheet.  On May 11, 2018, we received notification that the Federal Trade Commission had requested additional information and documentary materials with respect to the planned sale.  We and the counterparties to this planned transaction are reviewing this request and will be working to coordinate an appropriate response.
Included in the disposal group are the following assets and liabilities (in thousands):
 
March 31, 2018
Accounts receivable, net
$
3,376

Inventory
1,571

Other current assets
893

Property, plant and equipment, net
32,129

Goodwill
61,163

Intangible assets
29,403

Other non-current assets
712

     Total assets held for sale
$
129,247

 
 
Accounts payable
$
1,219

Accrued gas purchases
630

Accrued expenses and other current liabilities
881

Contract liabilities, long-term
607

     Total liabilities held for sale
$
3,337


Net income from continuing operations before income taxes for the Refined Products Business was $2.4 million and $1.8 million for the three months ended March 31, 2018 and 2017, respectively.

Discontinued Operations

On September 1, 2017, the Partnership completed the disposition of its propane business (the “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, the Partnership 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 and business line item on the Partnership's consolidated statement of operations in the period ended September 30, 2017. The Partnership has reported the accounts and the results of our Propane Business as discontinued operations in our condensed consolidated statements of operations for the three months ended March 31, 2017.


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


Summarized financial information related to the Propane Business is set forth in the tables below (in thousands):
 
Three months ended March 31, 2017
Total revenue
$
35,554

Total operating expenses
36,305

     Operating loss
(751
)
Other income
41

Income tax expense
—

     Loss from discontinued operations before taxes
$
(710
)
 
 
Partnership’s loss from discontinued operations, net of tax
$
(710
)
 
 
Depreciation and amortization
$
3,781

Capital expenditures
$
1,119

 
 
Operating non-cash items
 
Unrealized gain loss on derivative contracts, net
$
901



(5) Inventory

Inventory consists of the following (in thousands):
 
 
March 31, 2018
 
December 31, 2017
Crude oil
 
$
4,378

 
$
1,553

NGLs
 
282

 
347

Refined products
 
—

 
934

Materials, supplies and equipment
 
135

 
132

Total inventory
 
$
4,795

 
$
2,966




(6) Other Current Assets

Other current assets consist of the following (in thousands):
 
March 31, 2018
 
December 31, 2017
Prepaid insurance
$
6,341

 
$
8,944

Insurance receivables
1,741

 
1,741

Due from related parties
5,427

 
4,362

Other receivables
6,393

 
5,187

Risk management assets
5,363

 
3,186

   Total other current assets
$
25,265


$
23,420



(7) Risk Management Activities


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


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

Commodity Derivatives

To manage the impact of the risks associated with changes in the market price of NGL, crude oil, refined products and natural gas purchases and sales 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 physical transaction 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 contractual terms and 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 March 31, 2018 and December 31, 2017, none of which were designated as hedges for accounting purposes.
 
 
March 31, 2018
 
December 31, 2017
Commodity Swaps
 
Volume
 
Maturity
 
Volume
 
Maturity
NGLs Fixed Price (gallons)
 
1,407,000

 
January 2019
 
—
 
—
Crude Oil Fixed Price (barrels)
 
17,000

 
April 2018
 
—
 
—

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 March 31, 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 March 31, 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 services, and we have made no adjustments to those prices.

Weather Derivative

In the second quarter of 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 $30.0 million 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 no premiums during each of the three months ended March 31, 2018 and 2017. 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 $0.2 million and $0.5 million as of March 31, 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)


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
 
March 31,
2018
 
December 31, 2017
 
March 31,
2018
 
December 31, 2017
Commodity derivatives
Other current assets
 
$
5

 
$
—

 
$
—

 
$
—

Commodity derivatives
Accrued expenses and other current liabilities
 
—

 
—

 
(64
)
 
—

 
 
 
 
 
 
 
 
 
 
Interest rate swaps
Other current assets
 
$
5,132

 
$
2,678

 
$
—

 
$
—

Interest rate swaps
Other assets net
 
11,524

 
8,807

 
—

 
—

 
 
 
 
 
 
 
 
 
 
Weather derivatives
Other current assets
 
$
231

 
$
509

 
$
—

 
$
—

 
Total
 
$
16,892

 
$
11,994

 
$
(64
)
 
$
—


The following tables present the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset in the condensed consolidated balance sheets that are subject to enforceable master netting arrangements (in thousands):
 
 
Gross Risk Management Position
 
Netting Adjustments
 
Net Risk Management Position
Balance Sheet Classification
 
March 31,
2018
 
December 31, 2017
 
March 31,
2018
 
December 31, 2017
 
March 31,
2018
 
December 31, 2017
Other current assets
 
$
5,368

 
$
3,187

 
$
(5
)
 
$
—

 
$
5,363

 
$
3,187

Other (noncurrent) assets, net
 
11,524

 
8,807

 
—

 
—

 
11,524

 
8,807

Total assets
 
$
16,892

 
$
11,994

 
$
(5
)
 
$
—

 
$
16,887

 
$
11,994

 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued expenses and other current liabilities
 
$
(64
)
 
$
—

 
$
5

 
$
—

 
$
(59
)
 
$
—

Total liabilities
 
$
(64
)
 
$
—

 
$
5

 
$
—

 
$
(59
)
 
$
—


For each of the three months ended March 31, 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 March 31,
Statement of Operations Classification
Realized
 
Unrealized
2018
 
 
 
Gains (losses) on commodity derivatives, net
$
119

 
$
(59
)
Interest expense
1,350

 
5,171

Direct operating expenses
(278
)
 
—

Total
$
1,191

 
$
5,112

2017
 
 
 
Gains (losses) on commodity derivatives, net
$
420

 
$
(55
)
Interest expense
(65
)
 
(317
)
Direct operating expenses
(257
)
 
—

Total
$
98

 
$
(372
)


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


(8) Property, Plant and Equipment

Property, plant and equipment, net, consists of the following (in thousands):
 
Useful Life
(in years)
 
March 31,
2018
 
December 31,
2017
Land
Infinite
 
$
16,366

 
$
18,145

Construction in progress
N/A
 
83,013

 
55,622

Buildings and improvements
4 to 40
 
15,476

 
16,235

Transportation equipment
5 to 15
 
22,597

 
22,697

Processing and treating plants
8 to 40
 
123,580

 
123,138

Pipelines, compressors and right-of-way
3 to 40
 
975,213

 
974,301

Storage
3 to 40
 
124,037

 
146,105

Equipment
3 to 31
 
61,935

 
80,220

Total property, plant and equipment
 
 
1,422,217

 
1,436,463

Accumulated depreciation
 
 
(341,320
)
 
(340,878
)
Property, plant and equipment, net
 
 
$
1,080,897

 
$
1,095,585


At March 31, 2018 and December 31, 2017, gross property, plant and equipment included $369.5 million and $367.6 million, respectively, related to our FERC regulated interstate and intrastate assets.

Depreciation and amortization expense totaled $18.6 million and $18.5 million for the three months ended March 31, 2018 and 2017, respectively. Capitalized interest was $0.6 million and $1.0 million the three months ended March 31, 2018 and 2017, respectively.

(9) Goodwill and Intangible Assets

Goodwill consists of the following (in thousands):
 
March 31, 2018
 
December 31, 2017
Liquid Pipelines and Services
$
35,710

 
$
35,708

Terminalling Services
27,303

 
88,466

Offshore Pipeline and Services
4,972

 
4,692

Total
$
67,985

 
$
128,866


The change in goodwill in our Terminalling Services segment relates to goodwill on our Refined Products Business that was classified as held for sale at March 31, 2018, see Note 4 - Acquisitions and Dispositions.

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.

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

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


 
March 31, 2018
 
Gross carrying amount
 
Accumulated amortization
 
Net carrying amount
Customer relationships
$
64,744

 
$
(14,806
)
 
$
49,938

Customer contracts
94,692

 
(49,420
)
 
45,272

Dedicated acreage
42,547

 
(6,560
)
 
35,987

Collaborative arrangements
11,884

 
(1,627
)
 
10,257

Noncompete agreements
1,064

 
(1,064
)
 
—

Other
198

 
(25
)
 
173

Total
$
215,129

 
$
(73,502
)
 
$
141,627

 
 
 
 
 
 
 
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 $2.7 million and $6.6 million for the three months ended March 31, 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 $7.6 million, $10.2 million, $10.2 million, $10.2 million and $9.3 million, respectively.

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



(10) Investments in unconsolidated affiliates

The following table presents the activity in our equity method investments in unconsolidated affiliates (in thousands):

 
Delta House (1)
 
Emerald Transactions
 
 
 
 
 
FPS(3)
 
OGL(3)
 
Destin(3)
 
Tri-States(2)
 
Okeanos(3)
 
Wilprise(2)
 
Cayenne JV(2)
 
Total
Ownership % - 12/31/2017
35.7
%
 
35.7
%
 
66.7
%
 
16.7
%
 
66.7
%
 
25.3%
 
50.0
%
 
 
Ownership % - 3/31/2018
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
3,227

 
2,715

 
2,377

 
854

 
2,132

 
258

 
1,110

 
12,673

     Contributions
—

 
—

 
—

 
—

 
—

 
—

 
2,018

 
2,018

     Distributions
(2,247
)
 
(4,278
)
 
(10,734
)
 
(2,034
)
 
(4,378
)
 
(183
)
 
—

 
(23,854
)
Balances at March 31, 2018
$
91,392

 
$
45,369

 
$
115,888

 
$
51,877


$
20,199


$
4,764


$
9,782


$
339,271

___________________________________________________ 
(1) Represents direct and indirect ownership interests in Class A units and common units. FPS denotes Floating Production System LLC whereas OGL denotes Oil & Gas Lateral LLC.
(2) Included in our Liquid Pipelines and Services segment.
(3) Included in our Offshore Pipelines and Services segment.
 

The following tables present the summarized combined financial information for our equity investments (amounts represent 100% of investee financial information) (in thousands):

Balance Sheets:
March 31, 2018
 
December 31, 2017
Current assets
$
64,381

 
$
80,405

Non-current assets
1,279,417

 
1,288,862

Current liabilities
114,724

 
130,904

Non-current liabilities
$
438,496

 
$
436,584


 
Three months ended March 31,
Statements of Operations:
2018
 
2017
Revenue
$
56,898

 
$
93,870

Operating expenses
6,292

 
8,436

Net income
$
32,845

 
$
69,285




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



(11) Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities consists of the following (in thousands):
 
 
March 31, 2018
 
December 31, 2017
Capital expenditures
 
$
20,880

 
$
10,721

Accrued interest
 
15,590

 
3,190

Convertible preferred unit distributions
 
8,354

 
—

Employee compensation
 
149

 
90

Current portion of asset retirement obligation
 
6,416

 
6,416

Additional Blackwater acquisition consideration
 
5,000

 
5,000

Transaction costs
 
3,732

 
3,408

Customer deposits
 
1,136

 
1,109

Taxes payable
 
4,018

 
5,263

Due to related parties
 
3,212

 
6,609

Deferred financing costs
 
—

 
266

Contingent liabilities associated with VKGS and Panther
 
2,098

 
2,099

Royalties, gas imbalance and leases payables
 
7,119

 
7,905

Professional fees
 
2,024

 
1,848

Accrued corporate expenses
 
1,697

 
2,487

Accrued operating expenses
 
4,881

 
6,609

Other
 
1,817

 
5,834

   Total accrued expenses and other current liabilities
 
$
88,123


$
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 discussed in Note 13 - Debt Obligations.

    










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


The following table presents activity in our asset retirement obligations for the three months ended March 31, 2018 (in thousands):
Non-current balance
$
66,194

Current balance
6,416

Balances at December 31, 2017
$
72,610

Additions
260

Expenditures
—

Accretion expense
440

Balances at March 31, 2018
$
73,310

     Less: current portion
6,416

Noncurrent asset retirement obligation
$
66,894

___________________________________________________ 
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. These deposits are included in Restricted cash-long term in our condensed consolidated balance sheets as of March 31, 2018 and December 31, 2017.


(13) Debt Obligations

Our outstanding debt consists of the following (in thousands):
 
March 31, 2018
 
December 31, 2017
Revolving credit facility
$
712,600

 
$
697,900

8.50% Senior unsecured notes, due 2021
425,000

 
425,000

3.77% Senior secured notes, due 2031 (non-recourse)
57,817

 
58,324

3.97% Senior secured notes, due 2032 (non-recourse)
31,586

 
32,025

Other debt (1)
2,431

 
4,989

Total debt obligations
1,229,434

 
1,218,238

Unamortized debt issuance costs (2)
(9,530
)
 
(9,231
)
Total debt
1,219,904

 
1,209,007

Less: Current portion, including unamortized debt issuance costs
(5,058
)
 
(7,551
)
Long term debt
$
1,214,846

 
$
1,201,456

___________________________
(1) Other debt includes miscellaneous long-term obligations, which are reported in Other liabilities line items on our condensed consolidated balance sheets.

(2) Unamortized debt issuance costs related to the revolving credit facility are included in our condensed consolidated balance sheets in Other assets, net.


AMID Revolving Credit Agreement

On March 8, 2017, the Partnership, along with other subsidiaries of the Partnership (collectively, the “Borrowers”) entered into the Second Amended and Restated Credit Agreement, with Bank of America N.A., as Administrative Agent, Collateral Agent and L/C Issuer, Wells Fargo Bank, National Association, as Syndication Agent, and other lenders (the “Credit Agreement” or “revolving credit facility”), which increased the Borrowers’ borrowing capacity thereunder from $750.0 million to $900.0 million and provided for an accordion feature that will permit, subject to customary conditions, the borrowing capacity under the facility to be increased to a maximum of $1.1 billion. The $900 million in lending commitments under the Credit Agreement includes a $30 million sublimit for borrowings by Blackwater Investments, Inc. and a $100 million sublimit for letters of credit. The Credit Agreement matures on September 5, 2019. All obligations under the Credit Agreement and the guarantees of those obligations are secured, subject to certain exceptions, by a first-priority lien on and security interest in (i) substantially all of the Borrowers’ assets and the assets of certain of the subsidiaries of the Partnership and (ii) the capital stock of certain of the Partnership’s subsidiaries.

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



We can elect to have loans under our Credit Agreement bear interest either at (a) a Eurodollar-based rate, plus a margin ranging from 2.00% to 3.25% depending on our total leverage ratio then in effect, or (b) a base rate which is a fluctuating rate per annum equal to the highest of (i) the Federal Funds Rate plus 0.50%, (ii) the rate of interest in effect for such day as publicly announced from time to time by Bank of America as its "prime rate," and (iii) a Eurodollar-based rate plus 1.00%, in each case of clause (i)-(iii), plus a margin ranging from 1.00% to 2.25% depending on the total leverage ratio then in effect. We also pay a commitment fee ranging from 0.375% to 0.50% per annum, depending on our total leverage ratio then in effect, on the undrawn portion of the revolving loan under the Credit Agreement.

Borrowings under the Second Amended and Restated Credit Agreement are guaranteed on a senior unsecured basis by certain of our subsidiaries (the “Guarantors”). The guarantees by the Guarantors are full and unconditional and joint and several among the Guarantors. The terms of the Credit Agreement include covenants that restrict our ability to make cash distributions and acquisitions in some circumstances. The remaining principal balance and any accrued and unpaid interest will be due and payable in full at maturity, on September 5, 2019.

The Credit Agreement contains certain financial covenants that are applicable as of the end of any fiscal quarter, including a consolidated total leverage ratio which requires our indebtedness not to exceed 5.00 times adjusted consolidated EBITDA (provided that the minimum consolidated total leverage may be increased to 5.50 times adjusted consolidated EBITDA in connection with the closing of certain material acquisitions as of the end of the quarter during which such acquisition closes, and as of the end of the subsequent two quarters), a consolidated secured leverage ratio which requires our secured indebtedness not to exceed 3.50 times adjusted consolidated EBITDA, and a minimum interest coverage ratio that requires our adjusted consolidated EBITDA to exceed consolidated interest charges by not less than 2.50 times. In the first three quarters of 2017, we were in compliance with the total leverage ratio covenant of 5.50 times, 5.50 times and 5.00 times, for quarter periods ended March 31, 2017, June 30, 2017 and September 30, 2017, respectively, as described above. During the fourth quarter of 2017, we elected to be in a Specified Acquisition Period, as defined in Section 7.19 Financial Covenants of the Credit Agreement, which enables us to use a ratio of 5.50 times for the fourth quarter of 2017 as well as the first and second quarters of 2018.

As of March 31, 2018, our consolidated total leverage ratio was 5.19, our consolidated secured leverage ratio was 3.30, and our interest coverage ratio was 3.43, all of which were in compliance with the related covenants of our Credit Agreement. At March 31, 2018, letters of credit outstanding under the Credit Agreement were $31.0 million. As of March 31, 2018, we had approximately $712.6 million of borrowings outstanding.

The carrying value of amounts outstanding under the Credit Agreement approximates the related fair value, as interest charges vary with market rates conditions.

Our ability to maintain compliance with the leverage and interest coverage ratios included in the Credit Agreement may be subject to, among other things, the timing and success of initiatives we are pursuing, which may include expansion capital projects, acquisitions or drop down transactions, as well as the associated financing for such initiatives. The terms of the Credit Agreement also include covenants that restrict our ability to make cash distributions and acquisitions in some circumstances. If required, ArcLight , which controls the General Partner of the Partnership, has confirmed its intent to provide financial support for the Partnership to maintain compliance with the covenants contained in the Credit Agreement through April 10, 2019.

8.50% Senior Unsecured Notes

On December 28, 2016, the Partnership and American Midstream Finance Corporation, our wholly-owned subsidiary (the “Co-Issuer” and together with the Partnership, the “Issuers”), completed the issuance and sale of $300 million aggregate principal amount of their 8.50% Senior Notes due 2021 (the "8.50% Senior Notes"). The 8.50% Senior Notes are jointly and severally guaranteed by the Guarantors. The 8.50% Senior Notes rank equal in right of payment with all existing and future senior indebtedness of the Issuers, and senior in right of payment to any future subordinated indebtedness of the Issuers. The 8.50% Senior Notes were issued at par and provided approximately $294.0 million in proceeds, after deducting the initial purchasers' discount of $6.0 million. The Partnership also incurred $2.7 million of direct issuance costs resulting in net proceeds related to the 8.50% Senior Notes of $291.3 million.

The 8.50% Senior Notes were offered and sold to qualified institutional buyers in the United States pursuant to Rule 144A under the Securities Act, and to persons, other than U.S. persons, outside the United States pursuant to Regulation S under the Securities Act. Upon the closing of the JPE Merger and the satisfaction of other conditions related thereto, the restricted cash was released from escrow and was used to repay the JPE’s revolving credit facility and to reduce borrowings under the Partnership’s Credit Agreement.

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


 
On December 19, 2017, the Issuers completed the issuance and sale of an additional $125 million in aggregate principal amount of 8.50% Senior Notes (the “Additional Issuance”), net of issuance cost of approximately $3.0 million. The Additional Issuance was offered and sold to qualified institutional buyers in the United States pursuant to Rule 144A under the Securities Act, and to persons, other than U.S. persons, outside the United States pursuant to Regulation S under the Securities Act. None of the 8.50% Senior Notes, including the Additional Issuance, have been registered under the Securities Act.

The 8.50% Senior Notes will mature on December 15, 2021 and interest on the Additional Issuance will accrue from December 15, 2017. Interest on the 8.50% Senior Notes is payable in cash semiannually in arrears on each June 15 and December 15, with interest payable on the Additional Issuance commencing June 15, 2018. Interest will be payable to holders of record on the June 1 and December 1 immediately preceding the related interest payment date and will be computed on the basis of a 360-day year consisting of twelve 30-day months. Pursuant to the registration rights agreements entered into in connection with the issuances of the 8.50% Senior Notes, additional interest on the 8.50% Senior Notes accrues at 0.25% per annum for the first 90-day period following December 23, 2017 and by an additional 0.25% per annum with respect to each subsequent 90-day period, up to a maximum additional rate of 1.00% per annum over 8.50%, until we complete an exchange offer for the 8.50% Senior Notes.

At any time prior to December 15, 2018, the Issuers may redeem up to 35% of the aggregate principal amount of 8.50% Senior Notes, at a redemption price of 108.50% of the principal amount, plus accrued and unpaid interest to the redemption date, in an amount not greater than the net cash proceeds of one or more equity offerings by the Partnership, provided that:

•
at least 65% of the aggregate principal amount of the 8.50% Senior Notes remains outstanding immediately after such redemption (excluding 8.50% Senior Notes held by the Partnership and its subsidiaries); and

•
the redemption occurs within 180 days of the closing of each such equity offering.

On and after December 15, 2018, the Issuers may redeem all or a part of the 8.50% Senior Notes, at the redemption prices (expressed as percentages of principal amount) 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%

The Indenture restricts the Partnership’s ability and the ability of certain of its subsidiaries to, among other things: (i) incur, assume or guarantee additional indebtedness, issue any disqualified stock or issue preferred units, (ii) create liens to secure indebtedness, (iii) pay distributions on equity securities, redeem or repurchase equity securities or redeem or repurchase subordinated securities, (iv) make investments, (v) restrict distributions, loans or other asset transfers from restricted subsidiaries, (vi) consolidate with or merge with or into, or sell substantially all of its properties to, another person, (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries, (viii) enter into transactions with affiliates, (ix) engage in certain business activities and (x) enter into sale and leaseback transactions. These covenants are subject to a number of important exceptions and qualifications. If at any time the 8.50% Senior Notes are rated investment grade by either Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services and no Default or Event of Default (as each are defined in the Indenture) has occurred and is continuing, many of such covenants will terminate and the Partnership and its subsidiaries will cease to be subject to such covenants.
The carrying value of the 8.50% Senior Notes as of March 31, 2018 is $418.1 million, which approximates the fair value as of that date of $430.4 million. This estimate was based on similar private placement transactions along with changes in market interest rates which represent a Level 2 measurement.


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





3.77% Senior Secured Notes

On September 30, 2016, Midla Financing, LLC ("Midla Financing"), American Midstream (Midla), LLC (“Midla”), and MLGT and together with Midla, (the "Note Guarantors"), entered into the 3.77% Senior Note Purchase and Guaranty Agreement (the “Note Purchase Agreement”) with certain institutional investors (the “Purchasers”) whereby Midla Financing issued $60.0 million in an aggregate principal amount of 3.77% Senior Notes (non-recourse) due June 30, 2031. Principal and interest on the 3.77% Senior Notes is payable in installments on the last business day of each quarter beginning June 30, 2017 with the remaining balance payable in full on June 30, 2031. The average quarterly principal payment is approximately $1.1 million. The 3.77% Senior Notes were issued at par and provided net proceeds of approximately $57.7 million, net of debt issuance costs of $2.3 million.

Net proceeds from the 3.77% Senior Notes are restricted and will be used to fund project costs incurred in connection with the construction of the Midla-Natchez Line, the retirement of Midla’s existing 1920’s pipeline, the move of our Baton Rouge operations to the MLGT system, and the reconfiguration of the DeSiard compression system and all related ancillary facilities. These proceeds can also be used to pay costs incurred in connection with the issuance of the 3.77% Senior Notes, and for the general corporate purposes of Midla Financing. As of March 31, 2018, Restricted cash includes $15.2 million from the issuance of the 3.77% Senior Notes.

The Note Purchase Agreement includes representations and warranties, affirmative and negative covenants (including financial covenants), and events of default that are customary for a transaction of this type. Midla Financing must maintain a debt service reserve account containing six months of principal and interest payments.

In connection with the Note Purchase Agreement, the Note Guarantors guaranteed the payment in full of all Midla Financing’s obligations under the Note Purchase Agreement. Also, Midla Financing and the Note Guarantors granted a security interest in substantially all of their tangible and intangible personal property, including the membership interests in each Note Guarantor held by Midla Financing, and Midla Holdings pledged the membership interests in Midla Financing to the Collateral Agent. The 3.77% Senior Notes are non-recourse to the Partnership.

As of March 31, 2018, the fair value of the 3.77% Senior Notes was $51.8 million. This estimate was based on similar private placement transactions along with changes in market interest rates which represent a Level 2 measurement.

3.97% Trans-Union Secured Senior Notes

On May 10, 2016, Trans-Union Interstate Pipeline, LP ("Trans-Union") entered into an agreement with certain institutional investors in the insurance business represented by Babson Capital Management LLC whereby Trans-Union issued $35.0 million in an aggregate principal amount of 3.97% Senior Secured Notes ("Trans-Union Senior Notes") due December 31, 2032. Principal and interest on the Trans-Union Senior Notes is payable in installments on the last business day of each quarter beginning June 30, 2016 with the remaining balance payable in full on December 31, 2032. The average quarterly principal payment is approximately $0.5 million. The Trans-Union Senior Notes were originally issued at par and provided net proceeds of approximately $34.6 million after deducting related issuance cost of approximately $0.4 million. The Partnership assumed the Trans-Union Senior Notes following the Trans-Union acquisition on November 3, 2017. As of March 31, 2018, the fair value of the 3.97% Senior Notes was approximately $28.7 million. This estimate was based on similar private placement transactions along with changes in market interest rates which represent a Level 2 measurement.


(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

—

 
—

March 31, 2018
11,010

$
191,798

 
9,242

$
125,382

 
$
317,180


31
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 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 become arrearages and 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 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 March 31, 2018, the conversion price was $15.16 and the conversion ratio is 1 to 1.1483.

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 of Directors of our General Partner.

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 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 March 31, 2018, the conversion price was $15.16 and the conversion ratio is 1 to 1.1483.

    
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.


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


In the event that we issue, sell or grant any common units or convertible securities at an indicative per common unit price that is less than $14.00 per common unit (subject to customary anti-dilution adjustments), then the conversion price will be adjusted according to a formula to provide for an increase in the number of common units into which Series C Units are convertible. As of March 31, 2018, the conversion price was $13.33 and the conversion ratio is 1 to 1.0448.

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. 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 March 31, 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
 
—

 
142

Balances at March 31, 2018
 
965

 
52,853



General Partner Units

In order for our General Partner to maintain its ownership percentage in us, our general partner paid $0.1 million for the issuance of 8,665 additional notional General Partner units for the three months ended March 31, 2017. We received no such proceeds from our General Partner and issued no additional General Partner units for the three months ended March 31, 2018.

Distributions

Preferred Units

Distributions are accrued in the current quarter under the terms of the Partnership’s Fifth Amended and Restated Agreement of Limited Partnership, as amended. Such distributions are generally declared and paid in the following quarter in the form of cash or paid-in-kind (“PIK”) units, or any combination thereof.

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



Distributions for the first quarter 2018 were accrued and were paid fully in cash in the second quarter 2018. Distributions in the first quarter 2017 reflect both cash and PIK payments made for distributions that were accrued in the fourth quarter 2016, and the accrual of cash and PIK units that were paid in the second quarter 2017.

Limited Partner Units (Common Units)

The distribution related to the Limited Partner units, which was declared and paid in the first quarter 2018, was 100% cash.

We made the following distributions (in thousands):

 
 
Three months ended March 31,
 
 
2018
 
2017
Series A Units
 
 
 
 
Cash Paid
 
$
—

 
$
2,527

Accrued (1)
 
4,542

 
4,296

Paid-in-kind units
 
—

 
2,733

 
 
 
 
 
Series C Units
 
 
 
 
Cash Paid
 
—

 
3,627

Accrued (1)
 
3,812

 
3,627

Paid-in-kind units
 
—

 
—

 
 
 
 
 
Series D Units
 
 
 
 
Cash Paid
 
—

 
962

Accrued
 
—

 
962

 
 
 
 
 
Limited Partner Units
 
 
 
 
Cash Paid
 
21,745

 
24,915

 
 
 
 
 
General Partner Units
 
 
 
 
Cash Paid
 
290

 
167

 
 
 
 
 
Summary
 
 
 
 
Cash Paid
 
22,035

 
32,198

Accrued (1)
 
8,354

 
8,885

Paid-in-kind units
 
—

 
2,733

(1) Can include either Cash, PIK or a combination of both.
    
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 which are not observable in the market and thus represent a Level 3 measurement as defined by ASC 820. 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 $2.83 per unit using a Black-Scholes model, (iii) assumed discount rates ranging from 5.57% to 6.23% and (iv) assumed growth rates of 1.0%.



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


(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.

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 March 31,
 
2018
 
2017
Loss from continuing operations
$
(13,838
)
 
$
(28,171
)
Less: Net income attributable to noncontrolling interests
45

 
1,303

Loss attributable to the Partnership
(13,883
)
 
(29,474
)
Less:
 
 
 
Distributions on Series A Units
4,542

 
4,296

Distributions on Series C Units
3,812

 
3,627

Distributions on Series D Units
—

 
962

General Partner's distribution
290

 
200

General Partner's share in undistributed loss
(583
)
 
(560
)
Loss attributable to Limited Partners
(21,944
)
 
(37,999
)
Loss from discontinued operations, net of tax
—

 
(710
)
Net loss attributable to Limited Partners
$
(21,944
)
 
$
(38,709
)
 
 
 
 
Weighted average number of common units outstanding - Basic and Diluted
52,769

 
51,451

 
 
 
 
Limited Partners' net loss per common unit - Basic and Diluted
 
 
 
Loss from continuing operations
$
(0.42
)
 
$
(0.74
)
Loss from discontinued operations
—

 
(0.01
)
Net loss (1)
$
(0.42
)
 
$
(0.75
)
_____________________________________
(1) Potential common unit equivalents are antidilutive for all periods presented and, as a result, have been excluded from the determination of diluted limited partners' net loss per common unit.

(17) Incentive Compensation

Unit-based Compensation

All equity-based awards issued under the long-term incentive plan (“LTIP”) consist of phantom units, distribution equivalent rights (“DERs”) or option grants. DERs and options have been granted on a limited basis to executives. Future awards may be granted at the discretion of the Compensation Committee of our General Partner’s Board of Directors (the “Board”) and subject to approval by the Board.

At March 31, 2018, there were 4,308,985 common units available for future grants under the LTIP.

Phantom Unit Awards. Under the LTIP, phantom units typically vest in increments of 25% on each grant anniversary date and do not contain any vesting requirements other than continued employment.

During the three months ended March 31, 2018 there were 38,000, 154,693 and 193,698 of phantom units granted, forfeited and vested, respectively, which weighted-average grant date fair value per unit was $11.88, $7.12 and $4.49, respectively.

The fair value of our phantom units (“RSUs”) is based on the fair value of our common units at the grant date, discounted to reflect the fact that the RSUs are not eligible for the quarterly distribution prior to complete vesting (usually 25% per year over 4 years). Compensation expenses related to RSUs were $0.7 million and $4.0 million for the three months ended March 31, 2018 and 2017, respectively, and are included in Corporate expenses and Direct operating expenses in our condensed consolidated statements of operations and Equity compensation expense in our condensed consolidated statements of changes in partners’ capital and noncontrolling interests.

Option to Purchase Common Units

There were no grants of options in the quarter ended March 31, 2018. The compensation expense related to option awards for each of the three months ended March 31, 2018 and 2017 was immaterial. As of March 31, 2018, there were 245,000 unvested options the unrecognized compensation expense of which was $0.1 million.

Performance Based Awards (PSUs)

There were no new grants of PSUs during the first quarter of 2018. The compensation expense related to PSU awards for the three months ended March 31, 2018 and 2017 was $0.3 million and zero, respectively. As of March 31, 2018, there were 524,000 unvested PSUs the unrecognized compensation expense of which was $5.9 million.

Defined Contribution Plan

For the three months ended March 31, 2018 and 2017, the compensation expense associated with our defined contribution plan 401(k)’s employer matching was $0.8 million and $0.5 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.

Other Commitments

The expenses associated with our operating leases and service contracts for the three months ended March 31, 2018 and 2017 was $2.6 million and $1.9 million, respectively.

(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 and required by ASC 850 - Related Party Disclosures, as of and for the three months ended March 31, 2018 and 2017 and the outstanding balances as of March 31, 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

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


consideration based on Blackwater meeting certain operating targets. We determined that it was probable the operating targets would be met in 2018 and have kept a $5.0 million accrued distribution to the ArcLight affiliate which is included in Accrued expense and other current liabilities in the accompanying consolidated balance sheets.

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 March 31, 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 balance sheets.

General Partner

Our General Partner paid $9.9 million related to corporate overhead support which was presented as part of the contribution line item in Cash flows from financing activities in our consolidated statements of cash flows. As of March 31, 2018 and December 31, 2017, we had $3.7 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 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 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. 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.

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 three months ended March 31, 2018 and 2017, we recognized $0.6 million of management fee income for each respective period. As of March 31, 2018 and December 31, 2017, we had an outstanding accounts receivable balance of $2.5 million and $0.9 million, respectively, which is included in Other current assets in the accompanying balance sheets.

Consolidated Asset Management Services, LLC ("CAMS")

Dan Revers, a director of our General Partner, indirectly owns in excess of 22% 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 three months ended March 31, 2018 and 2017, the Partnership was invoiced by CAMS $0.1 million for each respective period, and had no outstanding accounts receivable balance as of March 31, 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 three months ended March 31, 2018, the Partnership invoiced CIMA $2.1 million and received invoicing from CIMA of $0.7 million in connection with such transactions. For the three months ended March 31, 2017, the Partnership invoiced CIMA $1.4 million and received invoices from CIMA of $0.7 million for services. As of March 31, 2018 and December 31, 2017, the Partnership had no outstanding amounts due from or to 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 March 31, 2018 and December 31, 2017, we had an

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


outstanding accounts receivable balance related to these payments of $2.5 million, respectively, which is included in Other current assets in the accompanying balance sheets.


(20) Supplemental Cash Flow Information

Supplemental cash flows and non-cash transactions consist of the following (in thousands):

 
Three months ended March 31,
 
2018
 
2017
Supplemental cash flow information
 
 
 
Interest payments, net of capitalized interest
$
6,927

 
$
12,610

Supplemental non-cash information
 
 
 
Investing
 
 
 
Increase in accrued property, plant and equipment purchases
$
10,159

 
$
2,233

Financing
 
 
 
Contributions from an affiliate holding limited partner interests
$
—

 
$
4,000

Accrued distributions on convertible preferred units
$
8,354

 
$
8,885

Paid-in-kind distributions on convertible preferred units
$
—

 
$
2,733


(21) Reportable Segments

Our operations are located in the United States and are organized into five reportable segments. These segments have been identified based on the differing products and services, regulatory environments and expertise required for these operations. See Note 3 - Revenue Recognition for a summary of the types of products and services from which each segment derives its revenues.

Segment Gross Margin

Our Chief Executive Officer serves as our Chief Operating Decision Maker and evaluates the performance of our reportable segments primarily on the basis of segment gross margin, which is our segment measure of profitability.

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.

A reconciliation from Total segment gross margin to Net loss attributable to the Partnership for the periods presented is below (in thousands):

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



Three months ended March 31,

2018
 
2017
Reconciliation of Total Segment Gross Margin to Net loss attributable to the Partnership:


 
 
Gas Gathering and Processing Services segment gross margin
$
12,653

 
$
11,251

Liquid Pipelines and Services segment gross margin
7,271

 
6,634

Natural Gas Transportation Services segment gross margin
10,688

 
6,119

Offshore Pipelines and Services segment gross margin
25,316

 
25,802

Terminalling Services segment gross margin (1)
8,053

 
11,160

Less:
 
 
 
Direct operating expenses (2)
19,124

 
14,332

Plus:
 
 
 
Unrealized gain on commodity derivatives, net
60

 
365

Less:
 
 
 
Corporate expenses
22,692

 
30,113

Depreciation, amortization and accretion expense
21,997

 
25,570

Gain on sale of assets, net
(95
)
 
(21
)
Interest expense
13,876

 
17,956

Other (income) expense
(22
)
 
37

Other, net
27

 
392

Income tax expense
280

 
1,123

Loss from discontinued operations, net of tax
—

 
710

Net income attributable to noncontrolling interests
45

 
1,303

Net loss attributable to the Partnership
$
(13,883
)
 
$
(30,184
)
_____________________________________
(1) Direct operating expenses related to our Terminalling Services segment of $4.3 million and $3.1 million for the three months ended March 31, 2018 and 2017, respectively, are included within the calculation of Terminalling Services segment gross margin.
(2)
Direct operating expenses include Gas Gathering and Processing Services segment direct operating expenses of $6.7 million and $8.1 million, Liquid Pipelines and Services segment direct operating expenses of $3.0 million and $2.5 million, Natural Gas Transportation Services segment direct operating expenses of $1.7 million and $1.2 million and Offshore Pipelines and Services segment direct operating expenses of $7.8 million and $2.6 million for the three months ended March 31, 2018 and 2017, respectively.

    

38
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 months ended March 31, 2018 and 2017 (in thousands):
 
Three months ended March 31, 2018
 
Gas Gathering and Processing Services
 
Liquid Pipelines and Services
 
Natural Gas Transportation Services
 
Offshore Pipelines and Services
 
Terminalling Services
 
Total
Revenue
$
35,676

 
$
119,773

 
$
16,063

 
$
16,859

 
$
17,398

 
$
205,769

Gain (loss) on commodity derivatives, net
2

 
58

 
—

 
—

 
—

 
60

Total revenue
35,678

 
119,831

 
16,063

 
16,859

 
17,398

 
205,829

Earnings in unconsolidated affiliates
—

 
2,222

 
—

 
10,451

 
—

 
12,673

Operating expenses:
 
 
 
 
 
 
 
 
 
 
 
Cost of Sales
23,056

 
114,805

 
5,288

 
1,994

 
5,023

 
150,166

Direct operating expenses
6,680

 
2,976

 
1,673

 
7,795

 
4,322

 
23,446

Corporate expenses
 
 
 
 
 
 
 
 
 
 
22,692

Depreciation, amortization and accretion expense
 
 
 
 
 
 
 
 
 
 
21,997

Gain on sale of assets, net
 
 
 
 
 
 
 
 
 
 
(95
)
Total operating expenses
 
 
 
 
 
 
 
 
 
 
218,206

Interest expense
 
 
 
 
 
 
 
 
 
 
13,876

Other income
 
 
 
 
 
 
 
 
 
 
(22
)
Loss from continuing operations before income taxes
 
 
 
 
 
 
 
 
 
 
(13,558
)
Income tax expense
 
 
 
 
 
 
 
 
 
 
(280
)
Loss from continuing operations
 
 
 
 
 
 
 
 
 
 
(13,838
)
Income from discontinued operations, including gain on disposition
 
 
 
 
 
 
 
 
 
 
—

Net loss
 
 
 
 
 
 
 
 
 
 
(13,838
)
Less: Net income attributable to non-controlling interests
 
 
 
 
 
 
 
 
 
 
45

Net loss attributable to the Partnership
 
 
 
 
 
 
 
 
 
 
$
(13,883
)
 
 
 
 
 
 
 
 
 
 
 
 
Segment gross margin
$
12,653

 
$
7,271

 
$
10,688

 
$
25,316

 
$
8,053

 



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


 
Three months ended March 31, 2017
 
Gas Gathering and Processing Services
 
Liquid Pipelines and Services
 
Natural Gas Transportation Services
 
Offshore Pipelines and Services
 
Terminalling Services
 
Total
Revenue
$
34,407

 
$
83,411

 
$
12,438

 
$
14,831

 
$
18,626

 
$
163,713

Gain (loss) on commodity derivatives, net
(7
)
 
372

 
—

 
—

 
—

—

365

Total revenue
34,400

 
83,783

 
12,438

 
14,831

 
18,626

 
164,078

Earnings in unconsolidated affiliates
—

 
1,088

 
—

 
14,314

 
—

 
15,402

 
 
 
 
 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
 
 
 
 
Cost of Sales
23,187

 
78,285

 
6,260

 
3,343

 
4,393

 
115,468

Direct operating expenses
8,065

 
2,453

 
1,235

 
2,579

 
3,073

 
17,405

Corporate expenses
 
 
 
 
 
 
 
 
 
 
30,113

     Depreciation, amortization and accretion expense
 
 
 
 
 
 
 
 
 
 
25,570

Gain on sale of assets, net
 
 
 
 
 
 
 
 
 
 
(21
)
Total operating expenses
 
 
 
 
 
 
 
 
 
 
188,535

Interest expense
 
 
 
 
 
 
 
 
 
 
17,956

Other expense
 
 
 
 
 
 
 
 
 
 
37

Loss from continuing operations before income taxes
 
 
 
 
 
 
 
 
 
 
(27,048
)
Income tax expense
 
 
 
 
 
 
 
 
 
 
(1,123
)
Loss from continuing operations
 
 
 
 
 
 
 
 
 
 
(28,171
)
Loss from discontinued operations
 
 
 
 
 
 
 
 
 
 
(710
)
Net loss
 
 
 
 
 
 
 
 
 
 
(28,881
)
Less: Net income attributable to non-controlling interests
 
 
 
 
 
 
 
 
 
 
1,303

Net loss attributable to the Partnership
 
 
 
 
 
 
 
 
 
 
$
(30,184
)
 
 
 
 
 
 
 
 
 
 
 
 
Segment gross margin
$
11,251

 
$
6,634

 
$
6,119

 
$
25,802

 
$
11,160

 



A reconciliation of total assets and investment in equity method investees as of March 31, 2018 and December 31, 2017 by segment to the amounts included in the condensed consolidated balance sheets follows:

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


 
March 31,
 
December 31,
 
2018
 
2017
Segment assets:
 
 
 
Gas Gathering and Processing Services
$
400,757

 
$
404,872

Liquid Pipelines and Services
379,592

 
359,646

Offshore Pipelines and Services
537,548

 
553,213

Natural Gas Transportation Services
267,782

 
268,991

Terminalling Services 
291,662

 
293,085

Other (1)
55,921

 
43,659

Total Assets
$
1,933,262

 
$
1,923,466

 
 
 
 
Investment in equity method investees:
 
 
 
Liquid Pipelines and Services
$
66,421

 
$
64,399

Offshore Pipelines and Services
272,850

 
284,035

Total Investment in equity method investees
$
339,271

 
$
348,434

_____________________________________
(1) Other assets consist 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 periods ended March 31, 2018 and 2017 by segment:     
 
Three months ended March 31,
 
2018
 
2017(1)
Capital expenditures (1)
 
 
 
Gas Gathering and Processing Services
$
6,654

 
$
4,383

Liquid Pipelines and Services
6,414

 
370

Offshore Pipelines and Services
6,350

 
220

Natural Gas Transportation Services
1,338

 
10,228

Terminalling Services 
3,705

 
1,811

Corporate and other
1,485

 
2,089

Total Capital expenditures
$
25,946

 
$
19,101

_________________________
(1) Capital expenditures for the period ended March 31, 2017 excludes expenditures made for the Propane Business of approximately $1.1 million.




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



(22) Subsequent Events

Distribution

On April 26, 2018, we announced that the Board of Directors of our General Partner declared a quarterly cash distribution of $0.4125 per common unit and preferred unit, Series A and Series C, for the quarter ended March 31, 2018, or $1.65 per common unit on an annualized basis. The distribution was paid on May 15, 2018, to unitholders of record as of the close of business on May 7, 2018.



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




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. 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", "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 obtain financing required to complete the SXE Merger (as defined herein) or to obtain financing on terms other than those currently anticipated;
•
our ability to complete the SXE Transactions (as defined herein) in a timely manner or at all, and to successfully integrate the operations of SXE;
•
dispositions of assets owned by us or SXE prior to or following the completion of the SXE Merger, which assets may have been material to us or SXE;
•
the outcome of any legal proceedings related to the SXE Merger;
•
greater than expected operating costs, customer loss and business disruption following the SXE Merger, including difficulties in maintaining relationships with employees;
•
diversion of management time on SXE Transactions-related issues;
•
our ability to timely and successfully identify, consummate and integrate our current and future acquisitions (including the SXE Transactions) and complete strategic dispositions, including the realization of all anticipated benefits of any such transaction, which otherwise could negatively impact our future financial performance;
•
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 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 our 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;

43


•
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 and interest rate 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 or internal growth projects;
•
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 that was 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.

Our primary assets are strategically located in some of the most prolific onshore and offshore producing regions and key demand markets in the United States. Our gathering and processing assets are primarily located in (i) the Permian Basin of West Texas, (ii) the Cotton Valley/Haynesville Shale of East Texas, (iii) the Eagle Ford Shale of South Texas, (iv) the Bakken Shale of North Dakota, and (v) offshore in the Gulf of Mexico. Our liquid pipelines, natural gas transportation and offshore pipelines and terminal assets are located in prolific producing regions and key demand markets in Alabama, Louisiana, Mississippi, North Dakota, Texas, Tennessee and in the Port of New Orleans in Louisiana and the Port of Brunswick in Georgia. Additionally, we operate a fleet of NGL gathering and transportation trucks in the Eagle Ford shale and the Permian Basin. See Recent Developments below for more information about our recent acquisitions and dispositions.

We own or have ownership interests in more than 5,100 miles of onshore and offshore natural gas, crude oil, NGL and saltwater pipelines across 17 gathering systems, seven interstate pipelines and nine intrastate pipelines; eight natural gas processing plants; four fractionation facilities; an offshore semisubmersible floating production system with nameplate processing capacity of 90 MBbl/d of crude oil and 220 MMcf/d of natural gas; six marine terminal sites with approximately 6.7 MMBbls of above-ground aggregate storage capacity for petroleum products, distillates, chemicals and agricultural products; and 90 transportation trucks and a total trailer fleet of 130, of which 35 are LPG trailers and 95 are crude oil trailers.

A portion of our cash flow is derived from our investments in unconsolidated affiliates, including a 66.67% operated interest in Destin, a natural gas pipeline; a 66.7% operated interest in Okeanos, a natural gas pipeline; a 35.7% non-operated interest in the Class A units and common units of Delta House, a floating production system platform and related pipeline infrastructure; a 25.3% non-operated interest in Wilprise, an NGL pipeline; a 16.7% non-operated interest in Tri-States, an NGL pipeline; and prior to our acquisition of Panther Operating Company, LLC (“POC”), a 66.7% interest in Main Pass Oil Gathering
(MPOG”), a crude oil gathering and processing system. Subsequent to the acquisition of POC, Panther Pipeline, LLC and Panther Offshore Gathering Systems, LLC (collectively, “Panther”) on August 8, 2017, we wholly owned and consolidated MPOG.


Recent Developments

Pending Southcross Energy Partners, L.P. Merger

As disclosed in our Annual Report, on October 31, 2017, we, our General Partner, our wholly owned subsidiary, Cherokee Merger Sub LLC (“Merger Sub”), Southcross Energy Partners, L.P. (“SXE”), and Southcross Energy Partners GP, LLC (“SXE GP”), entered into an Agreement and Plan of Merger (the “SXE Merger Agreement”). Upon the terms and subject to the conditions set forth in the SXE Merger Agreement, SXE will merge with Merger Sub (the “SXE Merger”), with SXE continuing its existence under Delaware law as the surviving entity in the SXE Merger and wholly owned subsidiary of us. In connection with the SXE Merger, Southcross Holdings LP (“Holdings LP”) agreed to contribute to us its equity interests in its new wholly owned subsidiary, which will hold substantially all the current subsidiaries (Southcross Holdings Intermediary LLC, Southcross Holdings Guarantor GP LLC and Southcross Holdings Guarantor LP) and business of Holdings LP (together with the SXE Merger, the “SXE Transactions”).

As disclosed in the registration statement on Form S-4, as initially filed with the SEC on January 11, 2018, the SXE Merger involves a total aggregate consideration of $817.9 million, including an estimated total assumed debt of $644.6 million.

Other Developments

In the fourth quarter of 2017, we were notified by the operator of Delta House FPS that certain third party-owned upstream infrastructure would require remedial work, resulting in a temporary delay of production volumes flowing into Delta House. This remediation is scheduled to be completed later in the second quarter of 2018, at which time full production is anticipated to resume flowing into Delta House. This has resulted in a reduction in cash distributions from Delta House, including those attributable to our 35.7% interest, during the curtailment period. On March 11, 2018, we and Magnolia Infrastructure Holdings, LLC ("Magnolia"), an affiliate of ArcLight, entered into a Capital Contribution Agreement to provide additional capital and corporate 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 agreement, Magnolia has agreed to provide support to us 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. Subsequent to the balance sheet date of March 31, 2018, we have received $9.4 million for such support. See further detail in Note 19 - Related Party Transactions.

On February 16, 2018, we announced the sale of our two refined products terminals (the "Refined Products Business") located in Caddo Mills, Texas ("Caddo Mills") and North Little Rock, Arkansas, to DKGP Energy Terminals LLC, a joint venture between Delek Logistics Partners, LP and Green Plains Partners LP, for approximately $138.5 million in cash, subject to working capital adjustments. Closing of the sale of the Refined Products Business is subject to customary closing conditions, including clearance under the Hart-Scott-Rodino Act. On May 11, 2018, we received notification that the Federal Trade Commission had requested additional information and documentary materials with respect to the planned sale.  We and the counterparties to this planned transaction are reviewing this request and will be working to coordinate an appropriate response.

Financial Highlights

Financial highlights for the three months ended March 31, 2018, include the following:

•
Net loss attributable to the Partnership amounted to $13.9 million, or a decreased loss of $16.3 million, as compared to a $30.2 million loss for the same period in 2017;

•
Earnings in unconsolidated affiliates were $12.7 million, a decrease of $3.1 million as compared to the same period in 2017, primarily due to reduced earnings related to our investment in Delta House as a result of shut-ins and other disruptions affecting production, offset by increased earnings due to the Cayenne pipeline becoming operational in January 2018;

•
Segment gross margin amounted to $64.0 million, or an increase of $2.6 million as compared to the same period in 2017, 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 Terminalling Services and Offshore Pipelines and Services segments;

44



•
Adjusted EBITDA was $52.4 million, or an increase of 12.2% as compared to the same period in 2017, primarily due to a decrease in net loss of $18.3 million; and

•
We distributed $21.7 million to our common unitholders, or $0.4125 per common unit.
 
Operational highlights for the three months ended March 31, 2018, include the following:

•
Contracted capacity for our Terminalling Services segment averaged 4,574,767 Bbls, representing a 13.7% increase compared to the same period in 2017;

•
Average condensate production totaled 62.3 Mgal/d, representing an 18.6 Mgal/d decrease compared to the same period in 2017 primarily due to lower system volumes resulting from a plant outage at Chatom which began in late October 2017 and continued through mid-January 2018;

•
Average gross NGL production totaled 262.0 Mgal/d, representing a 35.0 Mgal/d decrease compared to the same period in 2017 due to the Chatom plant outage mentioned above as well as lower NGL volumes at the Longview plant due to favorable pricing at other facilities and icy road conditions in January;

•
Throughput volumes attributable to the Natural Gas Transportation Services segment totaled 839.0 MMcf/d, representing a 449.0 MMcf/d increase compared to the same period in 2017 primarily due to additional firm transportation contracts on MLGT, higher volumes due to colder weather and the addition of volumes due to the acquisition of TransUnion which occurred in the fourth quarter of 2017;

•
Throughput volumes attributable to the Offshore Pipelines and Services segment totaled 274.0 MMcf/d, representing a 130 MMcf/d decrease compared to the same period in 2017, primarily due to a Venice plant disruption in the first quarter of 2017, which caused more volumes to be directed to our High Point Gas Transmission system in 2017;

•
Throughput volumes attributable to the Liquid Pipelines and Services segment totaled 34,310 Bbl/d, representing a 1,230 Bbl/d increase compared to the same period in 2017; and

•
The percentage of gross margin generated from fee based, fixed margin, firm and interruptible transportation contracts and firm storage contracts was 89.1% representing a decrease of 2.5% as compared to the same period in 2017.


Our Operations

We manage our business and analyze and report our results of operations through five reportable segments.

•
Gas Gathering and Processing Services. Our Gas Gathering and Processing Services segment provides “wellhead-to-market” services to producers of natural gas and NGLs, 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.

•
Liquid Pipelines and Services. Our Liquid Pipelines and Services segment provides transportation, purchase and sales of crude oil from various receipt points including lease automatic customer transfer facilities and deliveries to various markets.

•
Natural Gas Transportation Services. Our Natural Gas Transportation Services segment transports and delivers natural gas from producing wells, receipt points or pipeline interconnects for shippers and other customers, which include local distribution companies (“LDCs”), utilities and industrial, commercial and power generation customers.

•
Offshore Pipelines and Services. Our Offshore Pipelines and Services segment gathers and transports natural gas and crude oil from various receipt points to other pipeline interconnects, onshore facilities and other delivery points.

•
Terminalling Services. Our Terminalling Services segment provides above-ground leasable storage operations at our marine terminals that support various commercial customers, including commodity brokers, refiners and chemical

45


manufacturers to store a range of products and also includes crude oil storage in Cushing, Oklahoma and refined products terminals in Texas and Arkansas.

Cash distributions received from our unconsolidated affiliates amounted to $12.7 million and $15.4 million for the three months ended March 31, 2018 and 2017, respectively. Cash distributions derived from our unconsolidated affiliates are primarily generated from fee-based gathering and processing arrangements.

How We Evaluate Our Operations

Our management uses a variety of financial and operational metrics to analyze our performance. We view these metrics as important factors in evaluating our profitability and review these measurements on at least a monthly basis 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, and Adjusted EBITDA on a company-wide basis.

Throughput Volumes

In our Gas Gathering and Processing Services segment, we must continually obtain new supplies of natural gas, NGLs and condensate to maintain or increase throughput volumes on our systems. Our ability to maintain or increase existing volumes of natural gas, NGLs and condensate is impacted by (i) the level of work-overs or recompletions of existing connected wells and successful drilling activity of our significant producers in areas currently dedicated to or near our gathering systems, (ii) our ability to compete for volumes from successful new wells in the areas in which we operate, (iii) our ability to obtain natural gas, NGLs and condensate that has been released from other commitments and (iv) the volume of natural gas, NGLs and condensate that we purchase from connected systems. We actively monitor producer activity in the areas served by our gathering and processing systems to maintain current throughput volumes and pursue new supply opportunities.

In our Liquid Pipelines and Services segment, the amount of revenue we generate from our crude oil pipelines business depends primarily on throughput volumes. We generate a portion of our crude oil pipeline revenues through long-term contracts containing acreage dedications or minimum volume commitments. Throughput volumes on our pipeline system are affected primarily by the supply of crude oil in the market served by our assets. The revenue generated from our crude oil supply and logistics business depends on the volume of crude oil we purchase from producers, aggregators and traders and then sell to producers, traders and refiners as well as the volumes of crude oil that we gather and transport. The volume of our crude oil supply and logistics activities and the volumes transported by our crude oil gathering and transportation trucks are affected by the supply of crude oil in the markets served directly or indirectly by our assets. Accordingly, we actively monitor producer activity in the areas served by our crude oil supply and logistics business and other producing areas in the United States to compete for volumes from crude oil producers. Revenues in this business are also impacted by changes in the market price of commodities that we pass through to our customers.

In our Natural Gas Transportation Services and Offshore Pipelines and Services segments, the majority of our segment gross margin is generated by firm capacity reservation charges and interruptible transportation services from throughput volumes on our interstate and intrastate pipelines. Substantially all of the segment gross margin is generated under contracts with shippers, including producers, industrial companies, LDCs and marketers, for firm and interruptible natural gas transportation on our pipelines. We routinely monitor natural gas market activities in the areas served by our transmission systems to maintain current throughput volumes and pursue new shipper opportunities.

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. The amount of revenue we generate from our refined products terminals depends primarily on the volume of refined products that we handle. These volumes are affected primarily by the supply of and demand for refined products in the markets served directly or indirectly by our refined products terminals. Our refined products have butane blending capabilities. The volume of crude oil stored at our crude oil storage facility in Cushing, Oklahoma has no impact on the revenue generated by our crude oil storage business because we receive a fixed monthly fee per barrel of shell capacity that is not contingent on the usage of our storage tanks.

Storage Utilization

Storage utilization is a metric that we use to evaluate the performance of our Terminalling Services segment. We define storage utilization as the percentage of the contracted capacity in barrels compared to the design capacity of the tank.


46


Segment Gross Margin, Total Segment Gross Margin and Operating Margin

Segment gross margin, total segment gross margin and operating margin are supplemental non-GAAP financial measures that we use to evaluate our performance. We define total segment gross margin as the sum of the segment gross margins for each of our segments. The GAAP measure most directly comparable to total segment gross margin is net loss attributable to the Partnership. For a reconciliation of total segment gross margin to net loss, see Note about Non-GAAP Financial Measures below.

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. Segment 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 operating margin is net loss attributable to the Partnership. For a reconciliation of operating margin to net loss, see Note about Non-GAAP Financial Measures below.

Substantially all of our gross margin in the Liquid Pipelines and Services, Natural Gas Transportation Services, and Offshore Pipelines and Services segments is fee-based or fixed-margin, with little to no direct commodity price risk.

Total segment gross margin is useful for understanding our operating performance because it measures the operating results of our segments before depreciation and amortization and certain expenses that are generally not controllable by our business segment development managers, such as certain operating costs, general and administrative expenses, interest expense and income taxes. Operating margin is useful for similar reasons except that it also includes all direct operating expenses in order to assist management’s assessment of the performance of our operating managers.

Direct Operating Expenses

Our management seeks to maximize the profitability of our operations in part by minimizing direct operating expenses without sacrificing safety or the environment. Direct labor costs, insurance costs, ad valorem and property taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities, lost and unaccounted for gas, and contract services comprise the most significant portion of our operating expenses. These expenses are relatively stable and largely independent of throughput volumes through our systems but may fluctuate depending on the activities performed during a specific period.

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, interest expense, debt issuance cost, unrealized 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 our General Partner's contribution, less earnings in unconsolidated affiliates, gains (losses) that are unusual such as gain on revaluation of equity interest, and the gain on sale of the Propane Business, other, net and gain on sale of assets, net.

The GAAP measure most directly comparable to our performance measure Adjusted EBITDA is net loss attributable to the Partnership. For a reconciliation of net loss to Adjusted EBITDA, see Note about Non-GAAP Financial Measures below.

Note about Non-GAAP Financial Measures

Total segment gross margin, operating margin and Adjusted EBITDA 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.

47



You should not consider total segment gross margin, operating margin, or Adjusted EBITDA 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 and Adjusted EBITDA may be defined differently by other companies in our industry. Our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

The following tables reconcile the non-GAAP financial measures of total segment gross margin, operating margin and Adjusted EBITDA used by management to net loss attributable to the Partnership, their most directly comparable GAAP measure, for the three months ended March 31, 2018 and 2017 (in thousands):

Three months ended March 31,

2018
 
2017
Reconciliation of Total Segment Gross Margin to Net loss attributable to the Partnership:
 
 
 
Gas Gathering and Processing Services segment gross margin
$
12,653

 
$
11,251

Liquid Pipelines and Services segment gross margin
7,271

 
6,634

Natural Gas Transportation Services segment gross margin
10,688

 
6,119

Offshore Pipelines and Services segment gross margin
25,316

 
25,802

Terminalling Services segment gross margin (1)
8,053

 
11,160

Total segment gross margin
63,981

 
60,966

Less:
 
 
 
Direct operating expenses (2)
19,124

 
14,332

Plus:
 
 
 
Unrealized gain on commodity derivatives, net
60

 
365

Less:
 
 
 
Corporate expenses
22,692

 
30,113

Depreciation, amortization and accretion expense
21,997

 
25,570

Gain on sale of assets, net
(95
)
 
(21
)
Interest expense
13,876

 
17,956

Other (income) expense
(22
)
 
37

Other, net
27

 
392

Income tax expense
280

 
1,123

Loss from discontinued operations, net of tax
—

 
710

Net income attributable to noncontrolling interests
45

 
1,303

Net loss attributable to the Partnership
$
(13,883
)
 
$
(30,184
)
_______________________
(1) Direct operating expenses related to our Terminalling Services segment of $4.3 million and $3.1 million for the three months ended March 31, 2018 and 2017, respectively, are included within the calculation of Terminalling Services segment gross margin.
(2) Direct operating expenses include Gas Gathering and Processing Services segment direct operating expenses of $6.7 million and $8.1 million for the three months ended March 31, 2018 and 2017, respectively, Liquid Pipelines and Services segment direct operating expenses of $3.0 million and $2.5 million for the three months ended March 31, 2018 and 2017, respectively, Natural Gas Transportation Services segment direct operating expenses of $1.7 million and $1.2 million for the three months ended March 31, 2018 and 2017, respectively, Offshore Pipelines and Services segment direct operating expenses of $7.8 million and $2.6 million for the three months ended March 31, 2018 and 2017, respectively.


48



Three months ended March 31,

2018
 
2017
Reconciliation of Net loss attributable to the Partnership to Adjusted EBITDA:
 
 
 
Net loss attributable to the Partnership
$
(13,883
)
 
$
(30,184
)
Add:
 
 
 
Depreciation, amortization and accretion expense
21,997

 
25,290

Interest expense
17,731

 
14,925

Debt issuance costs paid
1,085

 
1,402

Unrealized losses (gains) on derivatives, net
(5,112
)
 
372

Non-cash equity compensation expense
1,014

 
4,038

Transaction expenses
8,877

 
8,614

Income tax expense
280

 
1,123

Discontinued operations
—

 
4,489

Distributions from unconsolidated affiliates
23,853

 
22,494

General Partner contribution for cost reimbursement
9,417

 
9,614

Deduct:
 
 
 
Earnings in unconsolidated affiliates
12,673


15,402

Other income
90


28

OPEB plan net periodic benefit
(15
)
 
—

Gain on sale of assets, net
95


21

Adjusted EBITDA
$
52,416

 
$
46,726


General Trends and Outlook

During 2018, our business objectives will continue to focus on maintaining stable cash flows from our existing assets and executing on 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 anticipate maintenance capital expenditures between $14.0 million and $19.0 million, and approved expenditures for expansion capital between $100.0 million and $120.0 million, for the year ending December 31, 2018. Forecast growth capital expenditures primarily include East Texas NGL Value Chain consolidation, the build-out of the Lavaca system, expansion of the Harvey terminal and other organic growth projects.

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. We also expect the SXE Transactions to be accretive to our Adjusted EBITDA upon consummation.

We expect our business to continue to be affected by the key trends and outlook discussed below. 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.

In the fourth quarter of 2017, we were notified by the operator of Delta House FPS that certain third party-owned upstream infrastructure would require remedial work, resulting in a temporary curtailment of production flow at Delta House. This remediation is scheduled to be completed later in the second quarter of 2018, at which time full production is anticipated to resume flowing into Delta House.
Gas Gathering and Processing Services Segment. Except for our fee-based contracts, which may be impacted by throughput volumes, the profitability of our Gas Gathering and Processing Services segment is dependent upon commodity prices, natural gas supply, and demand for natural gas, NGLs and condensate.


49


Liquid Pipelines and Services Segment. The profitability of our Liquid Pipelines and Services segment is dependent upon the price of crude oil. Throughput volumes could decline should crude oil prices remain low resulting in decreased production in our areas of operation.

Natural Gas Transportation Services and Offshore Pipelines and Services Segments. The profitability of our Natural Gas Transportation Services and Offshore Pipelines and Services segments are dependent upon the demand to transport natural gas pursuant under our firm and interruptible transportation contracts. Throughput volumes could decline should natural gas prices and drilling levels decline.

Terminalling Services Segment. The profitability of our Terminalling Services segment is dependent upon the demand from our customers to store their products, which is generally not tied to the crude oil and natural gas commodity markets. Currently, we have not experienced deterioration of terminal gross margin in connection with the volatility of the natural gas, crude oil, NGL or condensate markets. Further, the terms of our firm storage contracts are multiple years, with renewal options.

Average daily prices for New York Mercantile Exchange (“NYMEX”) West Texas Intermediate crude oil ranged from a high of $68.64 per barrel to a low of $59.19 per barrel from January 1, 2018 through April 30, 2018. Average daily prices for NYMEX Henry Hub natural gas ranged from a high of $6.24 per MMBtu to a low of $2.49 per MMBtu from January 1, 2018 through April 30, 2018. We are unable to predict future potential movements in the market price for natural gas, crude oil and NGLs and thus, cannot predict the ultimate impact of prices on our operations. If commodity prices decline, this could lead to reduced profitability and may impact our liquidity, compliance with financial covenants in our revolving credit facility, and our ability to maintain our current distribution levels. Our long-term view is that as economic conditions improve and regulatory burden is reduced, as it has been the case under the current presidential administration, commodity prices should reach levels that will support continued natural gas and crude oil production in the United States. Reduced profitability, if any, may result in future potential non-cash impairments of long-lived assets, goodwill, or intangible assets.

On April 26, 2018 the Board of Directors of our General Partner declared a quarterly cash distribution of $0.4125 per common unit or $1.65 per common unit on an annualized basis. The distribution is expected to be paid on May 15, 2018, to unitholders of record as of the close of business on May 7, 2018. The amount of our cash distributions on our units principally depends upon the amount of cash we generate from our operations, which could be adversely impacted by market conditions and factors outside of our control. The Partnership Agreement allows us to reduce or eliminate quarterly distributions, if required to maintain ongoing operations.

Capital Markets. Volatility in the capital markets may impact our operations in multiple ways, including limiting our producers' ability to finance their drilling and workover programs and limiting our ability to fund drop downs, organic growth projects and acquisitions.

We expect our business to continue to be affected by the key trends discussed in our Annual Report, under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations — General Trends and Outlook.”

Results of Operations — Consolidated

Net loss attributable to the Partnership decreased by $16.3 million to $13.9 million, as compared to $30.2 million for the same period in 2017, primarily reflecting increased total revenues from both commodity sales and services and reduced interest expense, net of capitalized interest. Partially offsetting these decreases to the net loss were higher operating expenses, mainly due to cost of sales increases associated with higher revenues.
Segment gross margin increased by $3.0 million to $64.0 million for the three months ended March 31, 2018 compared to $61.0 million for the three months ended March 31, 2017. The increase of $3.0 million for the three months ended March 31, 2018 was primarily due to higher segment gross margin in our Natural Gas Transportation Services, Gas Gathering and Processing Services, Liquid Pipelines and Services and Offshore Pipelines and Services segments offset by decreases in our Terminalling Services segment.

For the three months ended March 31, 2018, Adjusted EBITDA increased by $5.7 million to $52.4 million, or 12.2%, compared to the same period in 2017. The increase was primarily due to the increase in segment gross margin of $3.0 million described in the preceding paragraph as well as increases in distributions from equity method investees of $1.4 million.

We distributed $21.7 million to holders of our common units, or $0.4125 per common unit, during the three months ended March 31, 2018, which is comparable to the same period of last year.


50


The results of operations by segment are discussed in further detail following this overview (in thousands):
 
Three months ended March 31,
 
2018
 
2017
Statement of Operations Data:
 
 
 
Revenue:
 
 
 
Commodity sales
$
158,863

 
$
123,521

Services
46,906

 
40,192

Gain on commodity derivatives, net
60

 
365

Total revenue
205,829

 
164,078

Operating expenses:
 
 
 
Costs of sales
150,166

 
115,468

Direct operating expenses
23,446

 
17,405

Corporate expenses
22,692

 
30,113

Depreciation, amortization and accretion
21,997

 
25,570

Total operating expenses
218,301

 
188,556

Gain on sale of assets, net
(95
)
 
(21
)
Operating loss
(12,377
)
 
(24,457
)
Other income (expense), net
 
 
 
     Interest expense, net of capitalized interest
(13,876
)
 
(17,956
)
Other income (expense)
22

 
(37
)
Earnings in unconsolidated affiliates
12,673

 
15,402

Loss from continuing operations before income taxes
(13,558
)
 
(27,048
)
Income tax expense
(280
)
 
(1,123
)
Loss from continuing operations
(13,838
)
 
(28,171
)
Loss from discontinued operations
—

 
(710
)
Net loss
(13,838
)
 
(28,881
)
Less: Net income attributable to noncontrolling interests
45

 
1,303

Net loss attributable to the Partnership
$
(13,883
)
 
$
(30,184
)
Other Financial Data:
 
 
 
Total segment gross margin (1)
$
63,981

 
$
60,966

Adjusted EBITDA (1)
$
52,416

 
$
46,726

______________________
(1)
For definitions of total segment gross margin and Adjusted EBITDA and reconciliations to their most directly comparable financial measure calculated and presented in accordance with GAAP, and a discussion of how we use total segment gross margin and Adjusted EBITDA to evaluate our operating performance, see the information in this Item under the caption “How We Evaluate Our Operations.”
 
Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017

Total Revenue. Our total revenue for the three months ended March 31, 2018 was $205.8 million compared to $164.1 million for the three months ended March 31, 2017. This increase of $41.8 million was primarily due to the following:

•
an increase in our Liquid Pipelines and Services segment revenue of $36.4 million primarily due to increased sales to Shell and BP America of $23.0 million related to our Crude Oil Supply and Logistics business (“COSL”) and increased marketing activity that started in March 2017 for $13.9 million;

•
an increase in our Gas Gathering and Processing Services segment revenue of $1.3 million mostly due to new contracts at our Longview plant and better operational results at Mesquite and Yellow Rose partially offset by lower volumes at Chatom/Bazor Ridge/Glade Crossing, as well as the impact of Topic 606, which resulted in a $4.0 million reduction

51


in revenue as a result of deeming certain Percentage of Proceeds (“POP”) contracts to be appropriately recorded on a net basis as opposed to a gross basis; and

•
an increase in our Natural Gas Transportation Services segment revenue of $3.7 million primarily due to $1.6 million from Trans-Union, which was acquired in the fourth quarter of 2017, and new marketing transactions of $1.1 million.

Cost of Sales. Our purchases of natural gas, NGLs, condensate and crude for the three months ended March 31, 2018 were $150.2 million compared to $115.5 million for the three months ended March 31, 2017. The increase of $34.7 million was mostly due to our Liquid Pipelines and Services segment of $36.5 million due to a new Hunt Oil line for $15.8 million, increased purchases of $5.8 million with PT Petroleum and $14.9 million from our crude marketing contracts. Partially offsetting these increases was a decrease on our Natural Gas Transportation Services segment due to imbalances on our Trans-Union, MLGT, Midla and Magnolia systems. Additionally, our Gas Gathering and Processing segment increased $3.9 million mostly from higher NGL sales from a new marketing contract and higher sales of NGLs, natural gas and condensate at the Longview plant ; however, these increases were offset by $4.0 million as a result of our Topic 606 determination that certain POP contracts are appropriately recorded on a net basis rather than gross. This Topic 606 impact fully offsets that noted in the Revenue section above, resulting in no impact to segment gross margin.

Total Segment Gross Margin. Total segment gross margin for the three months ended March 31, 2018 was $64.0 million compared to $61.0 million for the three months ended March 31, 2017. The increase of $3.0 million for the three months ended March 31, 2018 was primarily due to our Natural Gas Transportation Services segment of $4.6 million mostly due to the Trans-Union acquisition and increased marketing activities, a small increase of $1.4 million in our Gas Gathering and Processing Services segment mostly due to new contracts at our Longview plant and better operational results at Mesquite and Yellow Rose, and a small increase of $0.7 million in our Liquid Pipelines and Services segment mostly due to the Cayenne Pipeline system becoming operational in the first quarter of 2018. The increases were partially offset by a decrease of $3.1 million in our Terminalling Services segment mostly due to reduced storage and utilization at Cushing.

Direct Operating Expenses. Direct operating expenses for the three months ended March 31, 2018 were $23.4 million compared to $17.4 million for the three months ended March 31, 2017. This increase of $5.6 million was primarily due to an increase of $3.1 million and $1.2 million related to the acquisitions in the third quarter of 2017 for Panther and the Viosca Knoll Gathering System, respectively and $0.6 million due to an increase in utilities and repairs and maintenance costs. The remaining variance of $0.7 million is due to line pack imbalances.
 
Corporate Expenses. Corporate expenses for the three months ended March 31, 2018 were $22.7 million compared to $30.1 million for the three months ended March 31, 2017. This decrease of $7.4 million was primarily due to reductions of $3.1 million in corporate salaries and wages, $2.6 million in contractors and consulting costs, $1.0 million in office rent expense and $0.7 million in higher capitalized labor allocated to projects.
Depreciation, Amortization and Accretion Expense. Depreciation, amortization and accretion expense for the three months ended March 31, 2018 was $22.0 million compared to $25.6 million for the three months ended March 31, 2017. This decrease of $3.6 million was primarily due to $3.1 million in accelerated amortization of AMID Crude Oil Storage intangible in the first quarter of 2017, and $1.2 million in decreased depreciation and amortization as a result of impairments in 2017. This was partially offset by a $1.9 million increase due to the Panther and Trans-Union acquisitions in the second half of 2017.

Interest Expense. Interest expense for the three months ended March 31, 2018 was $13.9 million compared to $18.0 million for the three months ended March 31, 2017. The decrease of $4.1 million was primarily due to the favorable position of our interest rate swaps in the amount of $6.8 million partially offset by higher interest charges of $2.7 million on the 8.50% Senior Notes, as a result of the $125.0 million bond offering in the fourth quarter of 2017. The outstanding balance on our revolving credit facility was $712.6 million as of March 31, 2018.
 
Earnings in Unconsolidated Affiliates. Earnings in unconsolidated affiliates for the three months ended March 31, 2018 was $12.7 million compared to $15.4 million for the three months ended March 31, 2017. This decrease of $2.7 million was primarily due to reduced earnings of $4.7 million related to our investment in Delta House as a result of shut-ins and other disruptions affecting production partially offset by $1.1 million due to the Cayenne pipeline becoming operational in January 2018.

Loss from discontinued operations. Loss from discontinued operations for the three months ended March 31, 2017 was associated with our Propane Business which was discontinued in September 2017. The prior period’s results have been recast for comparative purposes.

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 March 31,
 
2018
 
2017
Segment Financial and Operating Data:
 
 
 
Gas Gathering and Processing Services segment
 
 
 
Financial data:
 
 
 
Commodity sales
$
28,888

 
$
28,773

Services
6,788

 
5,634

Revenue from operations
35,676

 
34,407

Gain (loss) on commodity derivatives, net
2

 
(7
)
Segment revenue
35,678

 
34,400

Cost of sales
23,056

 
23,187

Direct operating expenses
6,680

 
8,065

Other financial data:
 
 
 
Segment gross margin (1)
$
12,653

 
$
11,251

Operating data:
 
 
 
Average throughput (MMcf/d)
160.5

 
207.6

Average plant inlet volume (MMcf/d) (2)
41.8

 
103.3

Average gross NGL production (Mgal/d) (2)
262.0

 
297.0

Average gross condensate production (Mgal/d) (2)
62.3

 
80.9

 _______________________
(1) For the definition of segment gross margin and a discussion of how we use segment gross margin to evaluate our operating performance, see the information in this Item under the caption “How We Evaluate Our Operations.”
(2) Excludes volumes and gross production under our elective processing arrangements.


Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017

Commodity sales. Commodity sales revenue for the three months ended March 31, 2018 was $28.9 million compared to $28.8 million for the three months ended March 31, 2017. The increase of $0.1 million resulted from a combination of the following:

•
increased sales of NGLs, natural gas and condensate at the Longview Plant for $2.1 million due to a new contract which began in March 2017 and accounted for $1.1 million as well as a change in reporting of gross residue gas revenue in 2018 which accounted for $1.0 million;
•
increased sales of NGLs from new marketing contracts that started in the late fourth quarter of 2017 for $2.0 million;
•
increased activity of NGLs at Mesquite resulting from a fully operational stabilizer for $1.4 million;
•
increased sales of Permian NGLs for processing at Yellow Rose for $1.4 million, a 21% daily volume increase;
•
offset by reduced NGL, natural gas and condensate revenues at Chatom/Bazor Ridge/Glade Crossing for $1.5 million due to lower system volumes resulting from a plant outage at Chatom which began in late October 2017 and continued through mid-January 2018, with a return to fully operational status in March 2018; and
•
lower throughput and plant inlet volumes mostly due to our Burns Point plant that was down but had minimal revenue impact.
•
The increases noted above were essentially offset by a $5.2 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.

52



Services. Segment services revenue for the period ended March 31, 2018 was $6.8 million compared to $5.6 million for the three months ended March 31, 2017. Services revenue increased by $1.2 million primarily due to increased throughput at Lavaca from new wells of $0.4 million, partially offset by a Longview XTO contract that was changed from a service contract to a product purchase in March of 2017 of $0.4 million. While these two items offset each other, as a result of Topic 606 implementation, we have determined that certain POP contracts are appropriately recorded on a net basis, resulting in a $1.2 million increase in Services revunue.

Cost of Sales. Purchases of natural gas, NGLs and condensate for the three months ended March 31, 2018 were $23.1 million compared to $23.2 million for the three months ended March 31, 2017. The increase of $0.1 million was primarily due to increased NGL sales from new marketing contracts of $2.5 million, increased sales of NGLs, natural gas and condensate sales at the Longview Plant of $1.9 million and increased sales of NGLs at Yellow Rose of $0.3 million, partially offset by decreased Chatom/Bazor Ridge/Glade Crossing NGL, natural gas and condensate sales of $0.6 million as discussed above. These increases were offset by a decrease in Cost of Sales of $4.0 million due to Topic 606 implementation as discussed above.

Segment Gross Margin. Segment gross margin for the three months ended March 31, 2018 was $12.7 million compared to $11.3 million for the three months ended March 31, 2017, for the reasons discussed above.

Direct Operating Expenses. Direct operating expenses for the three months ended March 31, 2018 was $6.7 million compared to $8.1 million for the three months ended March 31, 2017. The $1.4 million decrease was mainly due to a $0.5 million decrease in outside services and contractors, $0.3 million in regulatory and environmental fees, $0.3 million in lower compressor and equipment rentals, $0.2 million reduction in salaries and wages due to a bonus true-up, and $0.1 million in increased vehicle expenses.

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 March 31,
 
2018
 
2017
Segment Financial and Operating Data:
 
 
 
Liquid Pipelines and Services segment
 
 
 
Financial data:
 
 
 
Commodity sales
$
115,782

 
$
78,945

Services
3,991

 
4,465

Revenue from operations
119,773

 
83,410

Gain on commodity derivatives, net
58

 
372

Earnings in unconsolidated affiliates
2,222

 
1,088

Segment revenue
122,053

 
84,870

Cost of sales
114,805

 
78,285

Direct operating expenses
2,976

 
2,453

Other financial data:
 
 
 
Segment gross margin (1)
$
7,271

 
$
6,634

Operating data (2)
:
 
 
 
Average throughput Pipeline (Bbls/d)
34,310

 
33,080

Average throughput Truck (Bbls/d)
2,738

 
1,558

_______________________
(1) For the definition of segment gross margin and a discussion of how we use segment gross margin to evaluate our operating performance, see the information in this Item under the caption “How We Evaluate Our Operations.”
(2) These volumes exclude volumes from our equity investments.


53


Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017

Commodity Sales. Segment revenue from crude oil for the three months ended March 31, 2018 was $115.8 million compared to $78.9 million for the three months ended March 31, 2017. The increase of $36.9 million was primarily due to a $23.0 million increase on COSL as a result of increased bulk sales to Shell and BP America coupled with a favorable average price increase of $11.77/Bbl in the first quarter of 2018 compared to the first quarter of 2017, along with $13.9 million of increases resulting from marketing activity that began in March 2017.
    
Services revenue. Segment services revenue for the three months ended March 31, 2018 was $4.0 million compared to $4.5 million for the three months ended March 31, 2017. The decrease of $0.5 million was due to zero third party dispatch fees due to increased intercompany hauling.

Earnings in Unconsolidated Affiliates. Earnings in unconsolidated affiliates for the three months ended March 31, 2018 was $2.2 million compared to $1.1 million for the three months ended March 31, 2017. The increase of $1.1 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 three months ended March 31, 2018 was $114.8 million compared to $78.3 million for the three months ended March 31, 2017. The increase of $36.5 million was primarily due to our new connection to our Hunt Oil line that began in December 2017, resulting in purchases of $15.8 million on our Silver Dollar Pipeline system, $5.8 million of new activity with PT Petroleum on COSL in the first quarter of 2018, and $14.9 million of sour crude marketing transactions that began in March 2017.

Segment Gross Margin. Segment gross margin for the three months ended March 31, 2018, was $7.3 million compared to $6.6 million for the three months ended March 31, 2017. The increase of $0.7 million was due to the reasons discussed above.

Direct Operating Expenses. Direct operating expenses were $3.0 million for the three months ended March 31, 2018, an increase from $2.5 million for the three months ended March 31, 2017, mainly due to $0.3 million in excess salaries and wages related to bonus true-up, $0.1 million in information technology costs, and $0.1 million in utilities costs.

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 March 31,
 
2018
 
2017
Segment Financial and Operating Data:
 
 
 
Natural Gas Transportation Services segment
 
 
 
Financial data:
 
 
 
Commodity sales
$
6,641

 
$
6,868

Services
9,422

 
5,570

Segment revenue
16,063

 
12,438

Cost of sales
5,288

 
6,260

Direct operating expenses
1,673

 
1,235

Other financial data:
 
 
 
Segment gross margin (1)
$
10,688

 
$
6,119

Operating data:
 
 
 
Average throughput (MMcf/d)
839.0

 
390.0

 _______________________
(1) For the definition of segment gross margin and a discussion of how we use segment gross margin to evaluate our operating performance, see the information in this Item under the caption “How We Evaluate Our Operations.”


54


Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017

Commodity Sales. Segment sales of natural gas, NGLs and condensate for the three months ended March 31, 2018 were $6.6 million compared to $6.9 million for the three months ended March 31, 2017. The small decrease of $0.3 million was primarily due to a rate reduction on our Magnolia system.

Services revenue. Segment services revenue for the three months ended March 31, 2018 was $9.4 million compared to $5.6 million for the three months ended March 31, 2017. The increase of $3.8 million was primarily due to our acquisition of Trans-Union in the fourth quarter of 2017 for $1.6 million and new marketing transactions of $1.1 million and adjustments on Midla as a result of ASC606 revenue recognition changes of $0.8 million.

Cost of Sales. Purchases of natural gas, NGLs and condensate for the three months ended March 31, 2018 were $5.3 million as compared to $6.3 million for the three months ended March 31, 2017. The decrease of $1.0 million was primarily due to imbalances on a number of our systems.

Segment Gross Margin. Segment gross margin for the three months ended March 31, 2018, was $10.7 million compared to $6.1 million for the three months ended March 31, 2017. The increase of $4.6 million was primarily due to reasons discussed above.

Direct Operating Expenses. Direct operating expenses for the three months ended March 31, 2018 were $1.7 million compared to $1.2 million for the three months ended March 31, 2017. The increase of $0.5 million was primarily due to $0.1 million in bad debt expense, $0.1 million in regulatory and environmental costs, $0.1 million in repair and maintenance, and $0.2 million in higher property taxes.

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 March 31,
 
2018
 
2017
Segment Financial and Operating Data:
 
 
 
Offshore Pipelines and Services segment
 
 
 
Financial data:
 
 
 
Commodity sales
$
2,548

 
$
3,763

Services
14,311

 
11,068

Revenue from operations
16,859

 
14,831

Earnings in unconsolidated affiliates
10,451

 
14,314

Segment revenue
27,310

 
29,145

Cost of sales
1,994

 
3,343

Direct operating expenses
7,795

 
2,579

Other financial data:
 
 
 
Segment gross margin (1)
$
25,316

 
$
25,802

Operating data (2):
 
 
 
Average throughput (MMcf/d)
274.0

 
404.0

_______________________
(1) For the definition of segment gross margin and a discussion of how we use segment gross margin to evaluate our operating performance, see the information in this Item under the caption “How We Evaluate Our Operations.”
(2) These volumes exclude Equity Investment volumes.

Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017

Commodity Sales. Segment sales of natural gas, NGLs and condensate for the three months ended March 31, 2018 was $2.5 million compared to $3.8 million for the three months ended March 31, 2017. The decrease of $1.2 million was primarily

55


due to lower pricing on a new well contract at Mud Lake on our Gloria system of $2.1 million partially offset by $0.9 million as a result of the acquisition of Panther in the third quarter of 2017.

Services revenue. Segment services revenue for the three months ended March 31, 2018 was $14.3 million compared to $11.1 million for the three months ended March 31, 2017. The increase of $3.2 million was primarily due to the results of the acquisition of MPOG (MPOG was formerly owned at 66.7%) and POC in the third quarter of 2017 for $4.5 million, partially offset by the Venice plant disruption that occurred in February 2017, that rerouted volumes into our High Point Gas Transmission, L.L.C. (“HPGT”) system at maximum rates yielding an additional $1.2 million in the first quarter of 2017.

Earnings in unconsolidated affiliates. Earnings for the three months ended March 31, 2018 were $10.5 million compared to $14.3 million for the three months ended March 31, 2017. The decrease of $3.8 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 the second quarter of 2018, at which time full production is anticipated to resume flowing into Delta House.

Cost of Sales. Purchases of natural gas, NGLs and condensate for the three months ended March 31, 2018 were $2.0 million compared to $3.4 million for the three months ended March 31, 2017. The decrease of $1.4 million was primarily due to the reductions from decreased production at Mud Lake on our Gloria system of $2.0 million and imbalance activity on High Point Gas Gathering, L.L.C. (“HPGG”) of $0.4 million, offset by $1.1 million due to the Panther acquisition in the third quarter of 2017.

Segment Gross Margin. Segment gross margin for the three months ended March 31, 2018 was $25.3 million compared to $25.8 million for the three months ended March 31, 2017. The decrease of $0.5 million was primarily due to the increased earnings from the acquisitions noted in Services Revenue above, partially offset by decreased earnings in unconsolidated affiliates.

Direct Operating Expenses. Direct operating expenses were $7.8 million for three months ended March 31, 2018 and $2.6 million for the three ended March 31, 2017. The increase of $5.2 million was mainly due to $3.1 million and $1.2 million related to the acquisitions in the third quarter of 2017 for Panther and the Viosca Knoll Gathering System, respectively, $0.7 million due to line pack imbalances, and $0.2 million in outside services.

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 March 31,
 
2018
 
2017
Segment Financial and Operating Data:
 
 
 
Terminalling Services segment
 
 
 
Financial data:
 
 
 
Commodity sales
$
5,004

 
$
5,172

Services
12,394

 
13,454

Segment revenue
17,398

 
18,626

Cost of sales
5,023

 
4,393

Direct operating expenses
4,322

 
3,073

Other financial data:
 
 
 
Segment gross margin (1)
$
8,053

 
$
11,160

Operating data:
 
 
 
Contracted capacity (Bbls)
4,574,767
 
5,299,667
Design capacity (Bbls) (2)
5,400,800
 
5,400,800
Storage utilization (3)
84.7
%
 
98.1
%
Terminalling and Storage throughput (Bbls/d)
56,768

 
56,279

_______________________
(1) For the definition of segment gross margin and a discussion of how we use segment gross margin to evaluate our operating performance, see the information in this Item under the caption “How We Evaluate Our Operations.”
(2) Excludes terminals in our Refined Products Business.

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(3) Excludes storage utilization associated with our discontinued operations.


Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017

Commodity Sales. Segment commodity sales for the three months ended March 31, 2018 was $5.0 million compared to $5.2 million for the three months ended March 31, 2017. The decrease of $0.2 million related to our refined products and was driven by lower butane blending at Caddo Mills.

Services Revenue. Segment services revenue for the three months ended March 31, 2018 was $12.4 million compared to $13.5 million for the three months ended March 31, 2017. The decrease of $1.1 million was primarily driven by a $2.2 million reduction in storage and utilization at our Cushing terminal from a new contract with lower storage and rate terms offset by a $0.7 million change in revenue recognition (as a result of ASC606) of butane blending at our North Little Rock terminal and a $0.3 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 March 31, 2018 were $5.0 million compared to $4.4 million for the three months ended March 31, 2017. The increase of $0.6 million was primarily due to a change resulting from ASC606 revenue recognition which also changed butane blending services costs for $0.7 million and $0.2 million at our North Little Rock and Caddo Mills terminals, respectively, offset by lower butane blending volume sales primarily at Caddo Mills.

Segment Gross Margin. Segment gross margin for the three months ended March 31, 2018 was $8.1 million compared to $11.2 million for the three months ended March 31, 2017. The $3.1 million decrease was mostly driven by the decrease in Cushing storage and higher operating costs at Harvey.

Direct Operating Expenses. Segment direct operating expenses for the three months ended March 31, 2018 was $4.3 million compared to $3.1 million for the three months ended March 31, 2017. This increase of $1.2 million was mainly due to an increase in direct operating expenses at the Harvey and Caddo Mills facilities, which comprised of $0.7 million in outside services and contractors, $0.2 million in repairs and maintenance, and $0.2 million in utilities.

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 principal sources of liquidity include cash from operating activities, borrowings under our Credit Agreement (as defined herein), or other indebtedness, or through private and public offerings of debt and equity securities. We also have received cash and liquidity support from our affiliates sponsor, ArcLight. We believe that the sources of liquidity described will be sufficient to meet our short-term working capital requirements, medium-term maintenance capital expenditure requirements, and quarterly cash distributions for at least the next four quarters. 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.

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 of our Annual Report, under the caption Quantitative and Qualitative Disclosures about Market Risk.

The counterparties to certain of our commodity swap contracts are investment-grade rated financial institutions. Under these contracts, we may be required to provide collateral to the counterparties in the event that our potential payment exposure exceeds a predetermined collateral threshold. Collateral thresholds are set by us and each counterparty, as applicable, in the master contract that governs our financial transactions based on our and the counterparty’s assessment of creditworthiness. The assessment of our position with respect to the collateral thresholds is determined on a counterparty by counterparty basis, and is impacted by

57


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. As of March 31, 2018, we have not been required to post collateral with our counterparties.

AMID Revolving Credit Agreement

On March 8, 2017, we entered into the Second Amended and Restated Credit Agreement, with Bank of America N.A., as Administrative Agent, Collateral Agent and L/C Issuer, Wells Fargo Bank, National Association, as Syndication Agent, and other lenders (the “Credit Agreement” or “revolving credit facility”), which increased our borrowing capacity thereunder from $750.0 million to $900.0 million and provided for an accordion feature that will permit, subject to customary conditions, the borrowing capacity under the facility to be increased to a maximum of $1.1 billion.

For the three months ended March 31, 2018 and 2017, the weighted average interest rate on borrowings under our Credit Agreement was approximately 4.96% and 4.44%, respectively. At March 31, 2018 and December 31, 2017, letters of credit outstanding under the Credit Agreement were $31.0 million and $26.6 million, respectively. As of March 31, 2018, we had approximately $712.6 million of borrowings, $31.0 million of letters of credit outstanding under the Credit Agreement and approximately $78.5 million of available borrowing capacity which can be increased up to $156.5 million, conditional upon compliance with future covenants.

As of March 31, 2018, we were in compliance with the covenants included in the Credit Agreement. As of March 31, 2018, our consolidated total leverage ratio was 5.19, our consolidated secured leverage ratio was 3.30 and our interest coverage ratio was 3.43. Our ability to maintain compliance with the leverage and interest coverage ratios included in the Credit Agreement may be subject to, among other things, the timing and success of initiatives we are pursuing, which may include expansion capital projects, acquisitions, or drop down transactions, as well as the associated financing for such initiatives. If required, ArcLight, which controls the General Partner of the Partnership, has confirmed its intent to provide financial support for the Partnership to maintain compliance with the covenants contained in the Credit Agreement through April 10, 2019. See Note 14 - Debt Obligations, in Part II, Item 8 of our Annual Report, for further discussion of the Credit Agreement. Also, see Note 13 - Debt Obligations in Part I, Item 1 of this Quarterly Report for further discussion of the Credit Agreement.

8.50% Senior Unsecured Notes

On December 28, 2016, the Partnership and American Midstream Finance Corporation, our wholly-owned subsidiary (the “Co-Issuer” and together with the Partnership, the “Issuers”), completed the issuance and sale of the $300 million aggregate principal amount of their 8.50% Senior Notes due 2021 (the "8.50% Senior Notes"). The 8.50% Senior Notes rank equal in right of payment with all existing and future senior indebtedness of the Issuers, and senior in right of payment to any future subordinated indebtedness of the Issuers. The 8.50% Senior Notes were issued at par and provided approximately $291.3 million in proceeds, after deducting the initial purchasers' discount of $6.0 million and $2.7 million of direct issuance costs.

The 8.50% Senior Notes were offered and sold to qualified institutional buyers in the United States pursuant to Rule 144A under the Securities Act, and to persons, other than U.S. persons, outside the United States pursuant to Regulation S under the Securities Act. Upon the closing of the JPE Merger and the satisfaction of other conditions related thereto, the proceeds were used to repay and terminate the JPE’s revolving credit facility and reduce borrowings under our Credit Agreement.

On December 19, 2017, the Issuers completed the issuance and sale of an additional $125 million in aggregate principal amount of 8.50% Senior Notes (the “Additional Issuance”), net of issuance cost of approximately $3.0 million. The Additional Issuance was offered and sold to qualified institutional buyers in the United States pursuant to Rule 144A under the Securities Act, and to persons, other than U.S. persons, outside the United States pursuant to Regulation S under the Securities Act. None of the 8.50% Senior Notes, including the Additional Issuance, have been registered under the Securities Act.

The 8.50% Senior Notes will mature on December 15, 2021 and interest on the Additional Issuance will accrue from December 15, 2017. Interest on the 8.50% Senior Notes is payable in cash semiannually in arrears on each June 15 and December 15, with interest payable on the Additional Issuance commencing June 15, 2018. Interest will be payable to holders of record on the June 1 and December 1 immediately preceding the related interest payment date, and will be computed on the basis of a 360-day year consisting of twelve 30-day months. Pursuant to the registration rights agreements entered into in connection with the issuances of the 8.50% Senior Notes, additional interest on the 8.50% Senior Notes accrues at 0.25% per annum for the first 90-day period following December 23, 2017 and by an additional 0.25% per annum with respect to each subsequent 90-day period,

58


up to a maximum additional rate of 1.00% per annum over 8.50%, until we complete an exchange offer for the 8.50% Senior Notes. See Note 14 - Debt Obligations in Part II, Item 8 of our Annual Report, for further discussion of the 8.50% Senior Notes.
Also, see Note 13 - Debt Obligations in Part I, Item 1 of this Quarterly Report for further discussion of the 8.50% Senior Notes.


3.77% Senior Secured Notes

On September 30, 2016, Midla Financing, LLC (“Midla Financing”) American Midstream (Midla) LLC (“Midla”), and MLGT (together with Midla, the “Note Guarantors”) entered into the 3.77% Senior Note Purchase and Guaranty Agreement (the “Note Purchase Agreement”) with the purchasers party thereto (the “Purchasers”). Pursuant to the Note Purchase Agreement, Midla Financing issued and sold $60.0 million in aggregate principal amount of 3.77% Senior Notes (non-recourse) due June 30, 2031 (the “3.77% Senior Notes”) to the Purchasers, which bear interest at an annual rate of 3.77% to be paid quarterly. The average quarterly principal payment is approximately $1.1 million. Principal on the 3.77% Senior Notes will be paid on the last business day of each fiscal quarter end which began June 30, 2017. The 3.77% Senior Notes are payable in full on June 30, 2031. The 3.77% Senior Notes were issued at par and provided net proceeds of approximately $57.7 million after deducting related issuance costs of $2.3 million. The 3.77% Senior Notes are non-recourse to the Partnership.

In connection with the Note Purchase Agreement, the Note Guarantors guaranteed the payment in full of all Midla Financing’s obligations under the Note Purchase Agreement. Also, Midla Financing and the Note Guarantors granted a security interest in substantially all of their tangible and intangible personal property, including the membership interests in each Note Guarantor held by Midla Financing, and Financing Holdings pledged the membership interests in Midla Financing to the Collateral Agent.

Net proceeds from the 3.77% Senior Notes are restricted and have been be used (i) to fund project costs incurred in connection with (a) the construction of the Midla-Natchez Line (b) the retirement of Midla’s existing 1920’s vintage pipeline (c) the move of our Baton Rouge operations to the MLGT system, and (d) the reconfiguration of the DeSiard compression system and all related ancillary facilities, (ii) to pay transaction fees and expenses in connection with the issuance of the 3.77% Senior Notes, and (iii) for other general corporate purposes of Midla Financing. See Note 14 - Debt Obligations, in Part II, Item 8 of our Annual Report, for further discussion of the 3.77% Senior Notes. Also, see Note 13 - Debt Obligations in Part I, Item 1 of this Quarterly Report for further discussion of the 3.77% Senior Notes.

3.97% Trans-Union Secured Senior Notes

On May 10, 2016, Trans-Union Interstate Pipeline, LP ("Trans-Union") entered into an agreement with certain institutional investors in the insurance business represented by Babson Capital Management LLC whereby Trans-Union issued $35.0 million in an aggregate principal amount of 3.97% Senior Secured Notes ("Trans-Union Senior Notes") due December 31, 2032. Principal and interest on the Trans-Union Senior Notes is payable in installments on the last business day of each quarter beginning June 30, 2016 with the remaining balance payable in full on December 31, 2032. The average quarterly principal payment is approximately $0.5 million. The Trans-Union Senior Notes were originally issued at par and provided net proceeds of approximately $34.6 million after deducting related issuance cost of approximately $0.4 million. The Partnership assumed the Trans-Union Senior Notes following the Trans-Union acquisition on November 3, 2017. As of March 31, 2018, the fair value of the 3.97% Senior Notes was approximately $28.7 million. This estimate was based on similar private placement transactions along with changes in market interest rates which represent a Level 2 measurement.

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.  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 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. 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.

Working Capital


59


Working capital is the amount by which current assets exceed current liabilities and is a measure of our ability to pay our liabilities as they become due. 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 because 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 because 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 $109.1 million and $16.2 million as of March 31, 2018 and December 31, 2017, respectively.


Cash Flows

The following table reflects cash flows for the applicable periods (in thousands):
 
Three months ended March 31,
 
2018
 
2017
Net cash provided by (used in):
 
 
 
Operating activities
$
14,847

 
$
8,847

Investing activities
(15,744
)
 
(12,928
)
Financing activities
(1,774
)
 
(280,899
)
Net decrease in cash, cash equivalents and restricted cash
$
(2,671
)
 
$
(284,980
)

Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017

Operating Activities. During the three months ended March 31, 2018, we had $14.8 million of cash provided by operating activities, an increase of $6.0 million as compared to $8.8 million of cash provided by operating activities in the same period in 2017. The increase in cash flows from operating activities resulted primarily from a reduction in net loss of $15.1 million to $13.8 million year over year, offset by the net increase in operating assets and liabilities of approximately $9.0 million, mainly driven by an increase in working capital.

Investing Activities. During the three months ended March 31, 2018, net cash used in investing activities was $15.7 million, an increase of $2.8 million as compared to net cash used in investing activities of $12.9 million in the same period of 2017. The increase of cash flows used in investing activities resulted primarily from a $6.0 million increase in additions to property, plant and equipment for the three months ended March 31, 2017 as compared to the same period in 2017.

Financing Activities. During the three months ended March 31, 2018, net cash used in financing activities was $1.8 million, a decrease of $279.1 million as compared to net cash used in financing activities of $280.9 million in the same period in 2017. During the three months ended March 31, 2018, we had net borrowings under our Credit Agreement of approximately $15 million whereas during the three months ended March 31, 2017, the net pay down on our Credit Agreement was $243.4 million.

Distribution to our unitholders

In the three months ended March 31, 2018, we paid a total of approximately $21.7 million of distributions to our unitholders associated with the fourth quarter of 2017. This was made possible primarily by $14.8 million of cash generated from operating activities, plus approximately $6.7 million of distributions received relating to our unconsolidated affiliates return of capital and $9.4 million pursuant to our sponsor’s agreement to provide distribution support to offset the shortfall at Delta House.

On April 26, 2018, the Board of Directors of our General Partner declared a quarterly cash distribution of $0.4125 per common unit or $1.65 per common unit on an annualized basis. The distribution is expected to be paid on May 15, 2018, to unitholders of record as of the close of business on May 7, 2018. The amount of our cash distributions on our units principally depends upon the amount of cash we generate from our operations, which could be adversely impacted by market conditions and factors outside of our control, and our General Partner’s determination as to the most appropriate use of our cash from operations in accordance with our partnership agreement. We may reduce, suspend or eliminate quarterly distributions on our common units.

Capital Requirements

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The energy business is capital intensive, requiring significant investment for the maintenance of existing assets and the acquisition and development of new systems and facilities. We categorize our capital expenditures as either:

•
maintenance capital expenditures, which are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets) made to maintain our operating income or operating capacity; or

•
expansion capital expenditures, incurred for acquisitions of capital assets or capital improvements that we expect will increase our operating income or operating capacity over the long term.

Historically, our maintenance capital expenditures have not included all capital expenditures required to maintain volumes on our systems. It is customary in the regions in which we operate for producers to bear the cost of well connections, but we cannot be assured that this will be the case in the future. Although we classified our capital expenditures as expansion and maintenance, we believe those classifications approximate, but do not necessarily correspond to, the definitions of estimated maintenance capital expenditures and expansion capital expenditures under our Partnership Agreement.

For the three months ended March 31, 2018, capital expenditures totaled $25.9 million, including expansion capital expenditures of $19.7 million, maintenance capital expenditures of $4.5 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 $1.7 million.


Critical Accounting Estimates

There were no changes to our critical accounting estimates from those disclosed in our Annual Report.

Off-Balance Sheet Arrangements

As of March 31, 2018, there were no off-balance sheet arrangements.


Recent Accounting Pronouncements

For information regarding new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements, refer to Note 2 - New Accounting Pronouncements and Note 3 - Revenue Recognition in Part I, Item 1 of this Quarterly Report, which is incorporated herein by reference.


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. A discussion of our market risk exposure in financial instruments is presented below.

Commodity Price Risk

We have entered into contracts to hedge a portion of our NGL and crude oil exposure in 2018. As of March 31, 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.

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 March 31, 2018, we had exposure to changes in interest rates on our indebtedness associated with our Credit Agreement. We do not hold or purchase financial instruments or derivative financial instruments for trading purposes.

As of March 31, 2018, we had a combined notional principal amount of $550.0 million of variable to fixed interest rate swap agreements. As of March 31, 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 March 31, 2018, a hypothetical increase or decrease in interest rates by 1.0% would have changed our interest expense by $1.6 million for the three months ended March 31, 2018.

Item 4. Controls and Procedures

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 March 31, 2018. We are formulating our remediation plan and 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 is still in the process of implementing and testing these processes and procedures, and additional time is required to complete implementation and to assess and ensure the sustainability of these procedures. Management believes these actions will be effective in remediating the material weaknesses described above and will continue to devote significant time and attention to these remediation efforts. However, the material weaknesses cannot be considered re-mediated until the applicable re-mediated 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 March 31, 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. 1350 are furnished with this Quarterly Report as Exhibits 32.1 and 32.2.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

On December 18, 2015, Vintage Assets, Inc., et al. (“Vintage”), filed a lawsuit in the Judicial District Court in Plaquemines Parish, Louisiana alleging that defendants Southern Natural Gas Company, L.L.C. (“SNG”) and Tennessee Gas Pipeline Company, L.L.C. (i) failed to maintain the canals in which their pipelines were laid, (ii) failed to maintain the associated banks causing erosion, ecological damage, and unspecified monetary damages, and (iii) trespassed on Plaintiffs’ property. The case was removed to the United States District Court for the Eastern District of Louisiana on January 27, 2016. Our subsidiaries HPGT and HPGG are successors in interest to SNG with regard to certain of the property interests at issue in this proceeding. On October 24, 2016, HPGT and HPGG were added to the lawsuit as co-defendants. Plaintiffs subsequently demanded either restoration of their property or, alternatively, $44.0 million in damages (the Plaintiffs’ alleged estimated cost of restoration). A bench trial was held in September 2017, and a judgment rendered on May 4, 2018, held that HPGT and HPGG were obligated to restore approximately 2.4 acres of defendants land, maintain the width of canals and pay $1,104.00 in monetary damages. The Partnership estimates the cost of restoring the land will be less than $1 million. The purchase and sale agreements pursuant to which HPGG and HPGT acquired their property interests contain provisions pursuant to which the sellers agreed to indemnify HPGT or HPGG, as applicable, from all liabilities, including attorney’s fees, attributable to the period prior to such acquisition.

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.


Item 1A. Risk Factors


61


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. 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.


Item 6. Exhibits

62


Exhibit
Number
Exhibit
3.1

3.2
3.3
3.4
3.5
3.6
3.7
3.8
3.9
3.10
3.11
3.12
3.13
3.14
*10.1
10.2

*31.1
*31.2
**32.1
**32.2

63


**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.

64


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: May 15, 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)



65