AMERICAN MIDSTREAM PARTNERS, LP, 10-K filed on 3/28/2017
Annual Report
Document and Entity Information (USD $)
12 Months Ended
Dec. 31, 2016
Mar. 20, 2017
Jun. 30, 2016
Entity Registrant Name
American Midstream Partners, LP 
 
 
Entity Central Index Key
0001513965 
 
 
Document Type
10-K 
 
 
Document Period End Date
Dec. 31, 2016 
 
 
Amendment Flag
false 
 
 
Document Fiscal Year Focus
2016 
 
 
Document Fiscal Period Focus
FY 
 
 
Current Fiscal Year End Date
--12-31 
 
 
Entity Well-known Seasoned Issuer
No 
 
 
Entity Voluntary Filers
No 
 
 
Entity Current Reporting Status
Yes 
 
 
Entity Filer Category
Accelerated Filer 
 
 
Entity Public Float
 
 
$ 321,334,978 
Entity Common Stock, Shares Outstanding (in shares)
 
51,585,690 
 
Series A
 
 
 
Entity Common Stock, Shares Outstanding (in shares)
 
10,266,642 
 
Series C
 
 
 
Entity Common Stock, Shares Outstanding (in shares)
 
8,792,205 
 
Series D
 
 
 
Entity Common Stock, Shares Outstanding (in shares)
 
2,333,333 
 
Consolidated Balance Sheets (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2016
Dec. 31, 2015
Current assets
 
 
Cash and cash equivalents
$ 2,939 
$ 0 
Accounts receivable, net of allowance for doubtful accounts of $630 in 2016
9,523 
3,181 
Unbilled revenue
19,799 
15,559 
Other current assets
16,470 
10,459 
Total current assets
48,731 
29,199 
Property, plant and equipment, net
755,457 
655,310 
Restricted cash
323,564 
5,037 
Investment in unconsolidated affiliates
291,987 
63,704 
Intangible assets, net
107,898 
112,849 
Goodwill
16,262 
16,262 
Risk management assets
10,401 
0 
Other assets, net
9,195 
9,519 
Total assets
1,563,495 
891,880 
Current liabilities
 
 
Accounts payable
3,555 
6,389 
Accrued gas purchases
7,891 
7,281 
Accrued expenses and other current liabilities
61,578 
23,313 
Current portion of debt
4,458 
2,338 
Total current liabilities
77,482 
39,321 
Noncurrent asset retirement obligation
44,363 
28,549 
Other liabilities
1,488 
1,001 
Revolving credit agreement
1,058,538 
525,100 
Deferred tax liabilities
7,858 
5,826 
Total liabilities
1,189,729 
599,797 
Commitments and contingencies (see Note 18)
   
   
Convertible preferred units
334,090 
169,712 
Equity and partners' capital
 
 
General Partner Interest (680 thousand and 536 thousand units issued and outstanding as of December 31, 2016 and December 31, 2015, respectively)
(105,223)
(104,853)
Accumulated other comprehensive income
(40)
40 
Total partners' capital
29,879 
117,257 
Noncontrolling interests
9,797 
5,114 
Total equity and partners' capital
39,676 
122,371 
Total liabilities, equity and partners' capital
1,563,495 
891,880 
Limited Partner Common Units
 
 
Equity and partners' capital
 
 
Limited Partners' Capital Account
135,142 
188,477 
Limited Partner Series B Convertible Units
 
 
Equity and partners' capital
 
 
Limited Partners' Capital Account
0 
33,593 
3.77% Senior Notes, due 2031
 
 
Current liabilities
 
 
Senior Notes
55,979 
0 
8.50% Senior Notes, due 2021
 
 
Current liabilities
 
 
Senior Notes
291,309 
0 
Credit Agreement
 
 
Current liabilities
 
 
Revolving credit agreement
$ 711,250 
$ 525,100 
Consolidated Balance Sheets (Parenthetical) (USD $)
In Thousands, except Share data, unless otherwise specified
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2015
Limited Partner Series B Convertible Units
Allowance for doubtful accounts
$ 630 
 
 
General partners' interest units issued (in shares)
680,000 
536,000 
 
General partners' interest units outstanding (in shares)
680,000 
536,000 
 
Limited partners, units issued (in shares)
31,237,000 
30,427,000 
1,350,000 
Limited partners, units outstanding (in shares)
31,237,000 
30,427,000 
1,350,000 
Consolidated Statements of Operations (USD $)
In Thousands, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Revenues:
 
 
 
Sales of natural gas, NGLs and condensate
$ 160,950 
$ 179,818 
$ 255,025 
Services
72,572 
55,216 
52,284 
Gains (losses) on commodity derivatives, net
(840)
1,324 
1,091 
Total revenue
232,682 
236,358 
308,400 
Operating expenses:
 
 
 
Purchases of natural gas, NGLs and condensate
92,556 
105,883 
197,952 
Direct operating expenses
61,861 
60,737 
45,919 
Corporate expenses
54,223 
29,818 
24,422 
Depreciation, amortization and accretion expense
46,022 
38,014 
28,832 
Loss on sale of assets, net
591 
3,011 
122 
Loss on impairment of property, plant and equipment
697 
0 
99,892 
Loss on impairment of goodwill
0 
118,600 
0 
Total operating expenses
255,950 
356,055 
397,139 
Operating loss
(23,268)
(119,697)
(88,739)
Other income (expense):
 
 
 
Interest expense
(15,499)
(14,745)
(7,577)
Other expense
0 
0 
(670)
Earnings in unconsolidated affiliates
40,158 
8,201 
348 
Income (loss) from continuing operations before income taxes
1,391 
(126,241)
(96,638)
Income tax expense
(2,057)
(1,134)
(557)
Loss from continuing operations
(666)
(127,375)
(97,195)
Loss from discontinued operations, net of tax
0 
(80)
(611)
Net loss
(666)
(127,455)
(97,806)
Net income attributable to noncontrolling interests
2,804 
25 
214 
Net loss attributable to the Partnership
(3,470)
(127,480)
(98,020)
Distribution declared per common unit (in dollars per share)
$ 1.71 
$ 1.89 
$ 1.85 
Basic and diluted:
 
 
 
Loss from continuing operations (in dollars per share)
$ (1.11)
$ (6.00)
$ (8.54)
Loss from discontinued operations (in dollars per share)
$ 0.00 
$ 0.00 
$ (0.04)
Net loss (in dollars per share)
$ (1.11)
$ (6.00)
$ (8.58)
Weighted average number of common units outstanding:
 
 
 
Basic and diluted (in shares)
31,043 
24,983 
13,472 
General Partner
 
 
 
Other income (expense):
 
 
 
Net loss
(48)
(1,645)
(1,279)
Weighted average number of common units outstanding:
 
 
 
Net Income (Loss) Allocated to General Partners
(48)
 
 
Limited Partner
 
 
 
Other income (expense):
 
 
 
Net loss
(3,422)
(125,835)
(96,741)
Limited Partners' interest in net loss
$ (3,422)
$ (125,835)
$ (96,741)
Consolidated Statements of Comprehensive Income (Loss) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Statement of Comprehensive Income [Abstract]
 
 
 
Net loss
$ (666)
$ (127,455)
$ (97,806)
Unrealized gains (losses) relating to postretirement benefit plan
(80)
38 
(102)
Comprehensive income loss
(746)
(127,417)
(97,908)
Net income attributable to noncontrolling interests
2,804 
25 
214 
Comprehensive loss attributable to Partnership
$ (3,550)
$ (127,442)
$ (98,122)
Consolidated Statements of Changes in Partners' Capital and Noncontrolling Interests (USD $)
In Thousands, unless otherwise specified
Total
Accumulated Other Comprehensive Income
Total Partners Capital
Noncontrolling Interest
Blackwater
Total Partners Capital
Blackwater
Noncontrolling Interest
Series B
Series B
Total Partners Capital
Delta House
Total Partners Capital
BP
Total Partners Capital
General Partner
General Partner
Delta House
General Partner
BP
Limited Partner
Limited Partner
Blackwater
Beginning Balance at Dec. 31, 2013
 
$ 104 
$ 73,839 
$ 4,628 
 
 
 
 
 
 
$ 2,696 
 
 
$ 71,039 
 
Increase (Decrease) in Partners' Capital [Roll Forward]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net income (loss)
(97,806)
 
(98,020)
214 
 
 
 
 
 
 
(1,279)
 
 
(96,741)
 
Issuance of units
 
 
351,551 
 
 
 
32,220 
32,220 
 
 
 
 
 
351,551 
 
Unitholder contributions
 
 
5,678 
 
 
 
 
 
 
 
5,678 
 
 
 
 
Unitholder distributions
 
 
(42,063)
 
 
 
 
 
 
 
(2,913)
 
 
(39,150)
 
Issuance and exercise of warrants
 
 
0 
 
 
 
 
 
 
 
(7,164)
 
 
7,164 
 
Contributions from noncontrolling interest owners
 
 
 
 
21 
219 
 
 
 
 
 
 
 
 
21 
Distributions to noncontrolling interest owners
 
 
0 
(344)
 
 
 
 
 
 
 
 
 
 
 
LTIP vesting
 
 
243 
 
 
 
 
 
 
 
(824)
 
 
1,067 
 
Tax netting repurchases
256 
 
(256)
 
 
 
 
 
 
 
 
 
 
(256)
 
Equity compensation expense
 
 
1,356 
 
 
 
 
 
 
 
1,356 
 
 
 
 
Other comprehensive income (loss)
(102)
(102)
(102)
 
 
 
 
 
 
 
 
 
 
 
 
Ending Balance at Dec. 31, 2014
 
2 
324,467 
4,717 
 
 
32,220 
 
 
 
(2,450)
 
 
294,695 
 
Increase (Decrease) in Partners' Capital [Roll Forward]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net income (loss)
(127,455)
 
(127,480)
25 
 
 
 
 
 
 
(1,645)
 
 
(125,835)
 
Issuance of units
 
 
82,421 
 
 
 
1,373 
1,373 
 
 
 
 
 
82,421 
 
Unitholder contributions
 
 
1,996 
 
 
 
 
 
 
 
1,996 
 
 
 
 
Unitholder distributions
 
 
(71,737)
 
 
 
 
 
 
 
(7,023)
 
 
(64,714)
 
Contributions from noncontrolling interest owners
 
 
0 
739 
 
 
 
 
 
 
 
 
 
 
 
Unitholder distributions for Delta House
 
 
 
 
 
 
 
 
(96,297)
 
 
(96,297)
 
 
 
Distributions to noncontrolling interest owners
 
 
(20)
(367)
 
 
 
 
 
 
 
 
 
(20)
 
LTIP vesting
 
 
196 
 
 
 
 
 
 
 
(2,490)
 
 
2,686 
 
Tax netting repurchases
756 
 
(756)
 
 
 
 
 
 
 
 
 
 
(756)
 
Equity compensation expense
 
 
3,056 
 
 
 
 
 
 
 
3,056 
 
 
 
 
Other comprehensive income (loss)
38 
38 
38 
 
 
 
 
 
 
 
 
 
 
 
 
Ending Balance at Dec. 31, 2015
117,257 
40 
117,257 
5,114 
 
 
33,593 
 
 
 
(104,853)
 
 
188,477 
 
Increase (Decrease) in Partners' Capital [Roll Forward]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net income (loss)
(666)
 
(3,470)
2,804 
 
 
 
 
 
 
(48)
 
 
(3,422)
 
Unitholder contributions
 
 
1,998 
 
 
 
 
 
 
 
1,998 
 
 
 
 
Unitholder distributions
 
 
(90,638)
 
 
 
 
 
 
 
(7,938)
 
 
(82,700)
 
Cancellation of escrow units
 
 
(6,817)
 
 
 
 
 
 
 
 
 
 
(6,817)
 
Conversion of Series B Units
 
 
 
 
 
 
(33,593)
 
 
 
 
 
 
33,593 
 
Issuance and exercise of warrants
 
 
4,481 
 
 
 
 
 
 
 
4,481 
 
 
 
 
Issuance of common units, net of offering costs
 
 
2,871 
 
 
 
 
 
 
 
 
 
 
2,871 
 
Contributions from noncontrolling interest owners
 
 
0 
3,366 
 
 
 
 
 
 
 
 
 
 
 
Unitholder distributions for Delta House
 
 
 
 
 
 
 
 
 
 
(96,300)
 
 
 
 
Unitholder contribution for Emerald transactions
 
 
 
 
 
 
 
 
 
990 
 
 
990 
 
 
Distributions to noncontrolling interest owners
 
 
0 
(1,487)
 
 
 
 
 
 
 
 
 
 
 
LTIP vesting
 
 
0 
 
 
 
 
 
 
 
(3,487)
 
 
3,487 
 
Tax netting repurchases
347 
 
(347)
 
 
 
 
 
 
 
 
 
 
(347)
 
Equity compensation expense
 
 
3,634 
 
 
 
 
 
 
 
3,634 
 
 
 
 
Other comprehensive income (loss)
(80)
(80)
(80)
 
 
 
 
 
 
 
 
 
 
 
 
Ending Balance at Dec. 31, 2016
$ 29,879 
$ (40)
$ 29,879 
$ 9,797 
 
 
$ 0 
 
 
 
$ (105,223)
 
 
$ 135,142 
 
Consolidated Statements of Cash Flows (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Cash flows from operating activities
 
 
 
Net loss
$ (666)
$ (127,455)
$ (97,806)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
Depreciation, amortization and accretion expense
46,022 
38,014 
28,832 
Amortization of deferred financing costs
2,267 
1,482 
2,212 
Amortization of weather derivative premium
966 
912 
1,035 
Unrealized (gain) loss on derivative contracts, net
(10,221)
71 
(595)
Non-cash compensation expense
3,634 
3,863 
1,626 
Postretirement benefit plan benefit
(17)
(14)
(45)
Loss on sale of assets, net
591 
3,161 
207 
Loss on impairment of property, plant and equipment
697 
0 
99,892 
Loss on impairment of noncurrent assets held for sale
0 
0 
673 
Loss on impairment of goodwill
0 
118,600 
0 
Earnings in unconsolidated affiliates
(40,158)
(8,201)
(348)
Distributions from unconsolidated affiliates
40,158 
8,201 
348 
Deferred tax expense
2,057 
953 
213 
Allowance for bad debts
630 
0 
0 
Changes in operating assets and liabilities, net of effects of assets acquired and liabilities assumed:
 
 
 
Accounts receivable
(6,972)
1,743 
13,067 
Unbilled revenue
(4,240)
9,060 
2,272 
Risk management assets and liabilities
(1,030)
(875)
(809)
Other current assets
(2,817)
(962)
(7,533)
Other assets, net
841 
(522)
6,049 
Accounts payable
(827)
(1,921)
(12,026)
Accrued gas purchases
610 
(7,045)
(5,540)
Accrued expenses and other current liabilities
14,212 
1,135 
(9,149)
Asset retirement obligations
(858)
(90)
(1,030)
Other liabilities
483 
835 
(67)
Net cash provided by operating activities
45,362 
40,937 
21,478 
Cash flows from investing activities
 
 
 
Cost of acquisitions, net of cash acquired and settlements
(2,676)
7,383 
(362,316)
Acquisition of investments in unconsolidated affiliates
(150,179)
(65,701)
(12,000)
Additions to property, plant and equipment
(123,078)
(137,029)
(96,998)
Proceeds from disposal of property, plant and equipment
133 
4,813 
6,323 
Distributions from unconsolidated affiliates, return of capital
42,886 
12,367 
1,632 
Restricted cash
(318,527)
6,475 
(8,511)
Net cash used in investing activities
(551,441)
(171,692)
(471,870)
Cash flows from financing activities
 
 
 
Proceeds from issuance of common units, net of offering costs
2,825 
82,488 
204,255 
Unitholder contributions
1,998 
1,905 
5,588 
Unitholder distributions
(64,075)
(53,386)
(28,009)
Contributions from noncontrolling interest owners
3,366 
584 
0 
LTIP tax netting unit repurchases
(347)
(756)
(256)
Payment of financing costs
(5,140)
(2,238)
(3,841)
Proceeds from debt
351,100 
341,300 
493,085 
Payments on Credit Agreement
(164,950)
(189,150)
(250,870)
Payments on other debt
(2,685)
(3,557)
(2,589)
Borrowings on other debt
0 
4,709 
3,449 
Net cash provided by financing activities
509,018 
130,256 
450,490 
Net increase (decrease) in cash and cash equivalents
2,939 
(499)
98 
Cash and cash equivalents
 
 
 
Beginning of period
0 
499 
401 
End of period
2,939 
0 
499 
Blackwater
 
 
 
Cash flows from financing activities
 
 
 
Unitholder distributions for common control transactions
0 
(96,297)
0 
Noncontrolling Interest
 
 
 
Cash flows from operating activities
 
 
 
Net loss
2,804 
25 
214 
Cash flows from financing activities
 
 
 
Distributions to noncontrolling interest owners
(1,487)
(114)
(322)
Series A Preferred Stock
 
 
 
Cash flows from financing activities
 
 
 
Issuance of units
34,413 
44,768 
0 
Limited Partner Series B Convertible Units
 
 
 
Cash flows from financing activities
 
 
 
Issuance of units
0 
0 
30,000 
3.77% Senior Notes, due 2031
 
 
 
Cash flows from financing activities
 
 
 
Proceeds from debt
60,000 
0 
0 
8.50% Senior Notes, due 2021
 
 
 
Cash flows from financing activities
 
 
 
Proceeds from debt
$ 294,000 
$ 0 
$ 0 
Consolidated Statements of Cash Flows (Parenthical) (Senior Notes)
Dec. 31, 2016
3.77% Senior Notes, due 2031
Sep. 30, 2016
3.77% Senior Notes, due 2031
Dec. 31, 2016
8.50% Senior Notes, due 2021
Dec. 28, 2016
8.50% Senior Notes, due 2021
Debt instrument, interest rate, stated percentage
3.77% 
3.77% 
8.50% 
8.50% 
Organization and Basis of Presentation
Organization and Basis of Presentation
Organization, Basis of Presentation and Summary of Significant Accounting Policies

General

American Midstream Partners, LP (the “Partnership”, “we”, “us”, or “our”) is a growth-oriented Delaware limited partnership that was formed on August 20, 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 95% owned by High Point Infrastructure Partners, LLC (“HPIP”) and 5% owned by Magnolia Infrastructure Holdings, LLC, 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.

Nature of business

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 three reportable segments, (i) gathering and processing, (ii) transmission and (iii) terminals, 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.

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 located in key demand markets in Alabama, Louisiana, Mississippi and Tennessee and in the Port of New Orleans in Louisiana and the Port of Brunswick in Georgia.

We own or have ownership interests in more than 3,800 miles of onshore and offshore natural gas, crude oil, NGL and saltwater pipelines across 15 gathering systems, six interstate pipelines and eight intrastate pipelines; eight natural gas processing plants; four fractionation facilities; an offshore semisubmersible floating production system with nameplate processing capacity of 80 MMBbl/d of crude oil and 200 MMcf/d of natural gas; and three marine terminal sites with approximately 2.4 MMBbls of above-ground aggregate storage capacity for petroleum products, distillates, chemicals and agricultural products. A portion of our cash flow is derived from our investments in unconsolidated affiliates.

Basis of presentation

We have prepared the accompanying consolidated financial statements in accordance with accounting principles generally accepted in the United States of America ("GAAP").

The results of operations for acquisitions accounted for as business combinations have been included in the consolidated financial statements since their respective acquisition dates. See Note 2 - Acquisitions for further information.

Revisions and out of period adjustments

Revenues - Historically, we presented revenue from the sales of natural gas, NGLs and condensate and from the provision of midstream services on an aggregate basis in our consolidated statements of operations. Beginning in 2016, we have broken those amounts into separate line items in our consolidated statements of operations. Our financial statements for prior years have been revised to conform to the new presentation.

Collaborative arrangements - As part of the Costar Midstream, L.L.C. acquisition in October 2014, we acquired a 50% interest in a project to process unstablized condensate and off-spec NGLs. We accounted for this project, which commenced operations during the second quarter of 2016, as an investment in an unconsolidated affiliate under the equity method. During the fourth quarter of 2016, we determined that this accounting method was incorrect and that the project should have been accounted for as a collaborative arrangement. We corrected the cumulative impact of this error with an out of period adjustment in the fourth quarter of 2016, resulting in an increase in services revenue of $1.2 million, offset by an increase in depreciation, amortization and accretion expense of $1.0 million and a reduction in earnings in unconsolidated affiliates of $0.5 million. On a net basis, the correction resulted in a $0.3 million decrease in net income for the fourth quarter of 2016; there was no impact on our results for the year ended December 31, 2016. We also revised our consolidated balance sheet as of December 31, 2015 to correct the related classification errors. Such revision resulted in increases in property, plant and equipment of $7.3 million and intangible assets of $11.9 million, offset by a decrease in investment in unconsolidated affiliates of $18.6 million, and an increase in non-controlling interests of $0.6 million. Finally, we revised our consolidated statement of cash flows for the year ended December 31, 2015 to increase additions to property plant and equipment by $6.5 million, reduce investments in unconsolidated affiliates by $5.9 million and increase non-controlling interests by $0.6 million.

Earnings in unconsolidated affiliates - During the fourth quarter of 2016, we were notified by one of our unconsolidated affiliates that it had identified an error in the financial information it had previously reported to us. Specifically, the affiliate advised that its depreciation expense in prior periods was understated and as a result, its net income for those periods was overstated. As we account for our investment in this affiliate on the equity method, our related earnings were overstated by our pro rata share of this error. We corrected the cumulative impact of this error with an out of period adjustment of $1.4 million to reduce earnings for unconsolidated affiliates in the fourth quarter of 2016. Of this amount, $0.4 million related to 2015 while the remaining $1.0 million related to the first nine months of 2016.

We evaluated the impact of the errors referred to above and concluded that they were not material, individually or in the aggregate, to the financial statements of any previous annual or interim period and that correction of the errors in the fourth quarter of 2016 was not material to the 2016 financial statements.

Transactions between entities under common control
 
We may enter into transactions with ArcLight affiliates whereby we receive midstream assets or other businesses in exchange for cash or Partnership equity. We account for the net assets acquired at the affiliate's historical cost basis as the transactions are between entities under common control. 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 affiliate obtained control of the assets acquired.

Consolidation policy

The accompanying consolidated financial statements include accounts of American Midstream Partners, LP, and its controlled subsidiaries. All significant inter-company accounts and transactions have been eliminated in the preparation of the accompanying consolidated financial statements.

Use of estimates

When preparing consolidated financial statements in conformity with GAAP, management must make estimates and assumptions based on information available at the time. These estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosures of contingent assets and liabilities as of the date of the financial statements. Estimates and assumptions are based on information available at the time such estimates and assumptions are made. Adjustments made with respect to the use of these estimates and assumptions often relate to information not previously available. Uncertainties with respect to such estimates and assumptions are inherent in the preparation of financial statements. Estimates and assumptions are used in, among other things, i) estimating unbilled revenues, product purchases and operating and general and administrative costs, ii) developing fair value assumptions, including estimates of future cash flows and discount rates, iii) analyzing long-lived assets, goodwill and intangible assets for possible impairment, iv) estimating the useful lives of assets and v) determining amounts to accrue for contingencies, guarantees and indemnifications. Actual results, therefore, could differ materially from estimated amounts.

Cash, cash equivalents and restricted cash

We consider all highly liquid investments with an original maturity of three months or less at the date of purchase to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value because of the short term to maturity of these investments.

From time to time we are required to maintain cash in separate accounts the use of which is restricted by the terms of our debt agreements or asset retirement obligations. Such amounts are included in Restricted cash in our consolidated balance sheets.

Allowance for doubtful accounts
We establish provisions for losses on accounts receivable when we determine that we will not collect all or part of an outstanding balance. Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. As of December 31, 2016, the Partnership recorded allowances for doubtful accounts of $0.6 million.

Derivative financial instruments

Our net income (loss) and cash flows are subject to volatility stemming from changes in interest rates on our variable rate debt, commodity prices and fractionation margins (the relative difference between the price we receive from NGL sales and the corresponding cost of natural gas purchases). In an effort to manage the risks to unitholders, we use a variety of derivative financial instruments including swaps, collars and interest rate caps to create offsetting positions to specific commodity or interest rate exposures. In accordance with the authoritative accounting guidance, we record all derivative financial instruments in our consolidated balance sheets at fair value as current and long-term assets or liabilities on a net basis by counterparty. We record changes in the fair value of our commodity derivatives in Gains (losses) on commodity derivatives, net while changes in the fair value of our interest rate swaps are included in Interest expense in our consolidated statements of operations.

Our hedging program provides a control structure and governance for our hedging activities specific to identified risks and time periods, which are subject to the approval and monitoring by the Board of Directors of our General Partner. We employ derivative financial instruments in connection with an underlying asset, liability or anticipated transaction, and we do not use derivative financial instruments for speculative or trading purposes.

The price assumptions we use to value our derivative financial instruments can affect net income (loss) for each period. We use published market price information where available, or quotations from over-the-counter, market makers to find executable bids and offers. The valuations also reflect the potential impact of conditions, including credit risk of our counterparties. The amounts reported in our consolidated financial statements change quarterly as these valuations are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control.

Fair value measurements

We apply the authoritative accounting provisions for measuring the fair value of our derivative financial instruments and disclosures associated with our outstanding indebtedness. We define fair value as an exit price representing the expected amount we would receive when selling an asset or pay to transfer a liability in an orderly transaction with market participants at the measurement date.

We use various assumptions and methods in estimating the fair values of our financial instruments. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximated their fair value due to the short-term maturity of these instruments.

We employ a hierarchy which prioritizes the inputs we use to measure recurring fair value into three distinct categories based upon whether such inputs are observable in active markets or unobservable. We classify assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our methodology for categorizing assets and liabilities that are measured at fair value pursuant to this hierarchy gives the highest priority to unadjusted quoted prices in active markets and the lowest level to unobservable inputs as outlined below:

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Level 1 – Inputs represent unadjusted quoted prices in active markets for identical assets or liabilities;
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Level 2 – Inputs include quoted prices for similar assets and liabilities in active markets that are either directly or indirectly observable; and
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Level 3 – Inputs are unobservable and considered significant to fair value measurement.

We utilize a mid-market pricing convention, or the "market approach," for valuation for assigning fair value to our derivative assets and liabilities. Our credit exposure for over-the-counter derivatives is directly with our counterparty and continues until the maturity or termination of the contracts. As appropriate, valuations are adjusted for various factors such as credit and liquidity considerations.

Property, plant and equipment

We capitalize expenditures related to property, plant and equipment that have a useful life greater than one year. We also capitalize expenditures that improve or extend the useful life of an asset. Maintenance and repair costs, including any planned major maintenance activities, are expensed as incurred.

We record property, plant, and equipment at cost and recognize depreciation expense on a straight-line basis over the related estimated useful lives of the assets which range from 3 to 40 years. Our determination of the useful lives of property, plant and equipment requires us to make various assumptions, including the supply of and demand for hydrocarbons in the markets served by our assets, normal wear and tear of the facilities, and the extent and frequency of maintenance programs. We record depreciation using the group method of depreciation, which is commonly used by pipelines, utilities and similar assets.

We classify long-lived assets to be disposed of through sales that meet specific criteria as held for sale. We cease depreciating those assets effective on the date the asset is classified as held for sale. We record those assets at the lower of their carrying value or the estimated fair value less the cost to sell. Until the assets are disposed of, our estimate of fair value is re-determined when related events or circumstances change.

Impairment of long lived Assets

We evaluate the recoverability of our property, plant and equipment and intangible assets with definite lives when events or circumstances indicate we may not recover the carrying amount of the assets. We continually monitor our operations, the market, and business environment to identify indicators that could suggest an asset or asset group may not be recoverable. We evaluate the asset or asset group for recoverability by estimating the undiscounted future cash flows expected to be derived from their use and disposition. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost, contract renewals, and other factors. An asset or asset group is considered impaired when the estimated undiscounted cash flows are less than the carrying amount. In that event, an impairment loss is recognized to the extent that the carrying amount of the asset or asset group exceeds its fair value as determined by quoted market prices in active markets or present value techniques. The determination of fair values using present value techniques requires us to make projections and assumptions regarding future cash flows and weighted average cost of capital. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of the recoverability of our property, plant and equipment and the recognition of an impairment loss in our consolidated statements of operations.

Goodwill and intangible assets

We record goodwill for the excess of the cost of an acquisition over the fair value of the net assets of the acquired business. Goodwill is reviewed for impairment at least annually or more frequently if an event or change in circumstance indicates that an impairment may have occurred. We first assess qualitative factors to evaluate whether it is more likely than not that an impairment has occurred and it is therefore necessary to perform the two-step goodwill impairment test. If the two-step goodwill impairment test indicates that the goodwill is impaired, an impairment loss is recorded.

We record the estimated fair value of acquired customer contracts, relationships and dedicated acreage agreements as intangible assets. These intangible assets have definite lives and are subject to amortization on a straight-line basis over their economic lives, currently ranging between 10 years and 30 years. We assess intangible assets for impairment together with related underlying long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.

Investment in unconsolidated affiliates

We hold membership interests in entities that own and operate natural gas pipeline systems and NGL and crude oil pipelines in and around Louisiana, Alabama, Mississippi and the Gulf of Mexico. While we have significant influence over these entities, we do not control them and therefore, they are accounted for using the equity method and are reported in Investment in unconsolidated affiliates in the consolidated balance sheets. We evaluate the recoverability of these investments on a regular basis and recognize impairment write downs if we determine a loss in value represents an other than temporary decline.

Deferred financing costs

Costs incurred in connection with our Credit Agreement are deferred and charged to interest expense over the term of the related credit arrangement. Such amounts are included in Other assets, net in our consolidated balance sheet. Costs incurred in connection with our 8.50% Senior Notes and 3.77% Senior Notes are also deferred and charged to interest expense over the respective term of the agreements; however, these amounts are reflected as a reduction of the related obligation. Gains or losses on debt repurchases or extinguishment include any associated unamortized deferred financing costs.

Asset retirement obligations

Asset retirement obligations ("ARO") are legal obligations associated with the retirement of tangible long-lived assets that result from the asset's acquisition, construction, development and operation. An ARO is initially measured at its estimated fair value. Upon initial recognition, we also record an increase to the carrying amount of the related long-lived asset. We depreciate the asset using the straight-line method over the period during which it is expected to provide benefits. After initial recognition, we revise the ARO to reflect the passage of time and for changes in the estimated amount or timing of cash flows.

We have legal obligations requiring us to decommission our offshore pipeline systems at retirement. In certain rate jurisdictions, we are permitted to include annual charges for removal costs in the regulated cost of service rates we charge our customers. Additionally, legal obligations exist for certain of our offshore right-of-way agreements due to requirements or landowner options to compel us to remove the pipe at final abandonment. Sufficient data exists with certain onshore pipeline systems to reasonably estimate the cost of abandoning or retiring a pipeline system. However, in some cases, there is insufficient information to reasonably determine the timing and/or method of settlement for purposes of estimating the fair value of the asset retirement obligation. In these cases, the asset retirement obligation cost is considered indeterminate because there is no data or information that can be derived from past practice, industry practice, management's experience, or the asset's estimated economic life. The useful lives of most pipeline systems are primarily derived from available supply resources and ultimate consumption of those resources by end users. Variables can affect the remaining lives of the assets which preclude us from making a reasonable estimate of the asset retirement obligation. Indeterminate asset retirement obligation costs will be recognized in the period in which sufficient information exists to reasonably estimate potential settlement dates and methods.

Commitments, contingencies and environmental liabilities

We expense or capitalize, as appropriate, expenditures for ongoing compliance with environmental regulations that relate to past or current operations. We expense amounts we incur from the remediation of existing environmental contamination caused by past operations that do not benefit future periods by preventing or eliminating future contamination. We record liabilities for environmental matters when assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of environmental liabilities are based on currently available facts, existing technology and presently enacted laws and regulation taking into consideration the likely effects of inflation and other factors. These amounts also take into account our prior experience in remediating contaminated sites, other companies' clean-up experience and data released by government organizations. Our estimates are subject to revision in future periods based on actual cost or new information. We evaluate recoveries from insurance coverage separately from the liability and, when recovery is probable, we record an asset separately from the associated liability in our consolidated financial statements.

We recognize liabilities for other commitments and contingencies when, after fully analyzing the available information, we determine it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. When a range of probable loss can be estimated, we accrue the most likely amount or if no amount is more likely than another, we accrue the minimum of the range of probable loss. We expense legal costs associated with loss contingencies as such costs are incurred.

Noncontrolling interests

Noncontrolling interests represent the minority interest holders' proportionate share of the equity in certain of our consolidated subsidiaries and are adjusted for the minority interest holders' proportionate share of the subsidiaries' earnings or losses each period.

Revenue recognition

We recognize revenue from the sale of commodities (e.g., natural gas, crude oil, NGLs or condensate) as well as from the provision of gathering, processing, transportation or storage services when all of the following criteria are met: i) persuasive evidence of an exchange arrangement exists, ii) delivery has occurred or services have been rendered, iii) the price is fixed or determinable, and iv) collectability is reasonably assured. We recognize revenue from the sale of commodities and the related cost of product sold on a gross basis for those transactions where we act as the principal and take title to commodities that are purchased for resale.

Purchases of natural gas, NGLs and condensate

Purchases of natural gas, NGLs and condensate represent the cost of commodities purchased for resale or obtained in connection with certain of our customer revenue arrangements. These costs do not include an allocation of depreciation expense or direct operating costs.

Corporate expenses

Corporate expenses include compensation costs for executives and administrative personnel, professional service fees, rent expense and other general and administrative expenses and are recognized as incurred.

Operational balancing agreements and natural gas imbalances

To facilitate deliveries of natural gas and provide for operational flexibility, we have operational balancing agreements in place with other interconnecting pipelines. These agreements ensure that the volume of natural gas a shipper schedules for transportation between two interconnecting pipelines equals the volume actually delivered. If natural gas moves between pipelines in volumes that are more or less than the volumes the shipper previously scheduled, a natural gas imbalance is created. The imbalances are settled through periodic cash payments or repaid in-kind through future receipt or delivery of natural gas. Natural gas imbalances are recorded in Other current assets or Accrued expenses and other current liabilities on our consolidated balance sheets at cost which approximates fair value.

Equity-based compensation

We award equity-based compensation to management, non-management employees and directors under our Long-Term Incentive Plan ("LTIP"), which provides for the issuance of options, unit appreciation rights, restricted units, phantom units, other unit-based awards, unit awards or replacement awards, as well as tandem Distribution Equivalent Rights ("DERs"). Compensation expense is measured by the fair value of the award at the date of grant as determined by management. Compensation expense is recognized in Corporate expenses and Direct operating expenses over the requisite service period of each award.

Income taxes

The Partnership is not a taxable entity for U.S. federal income tax purposes or for the majority of states that impose an income tax. Taxes on our net income are generally borne by our unitholders through the allocation of taxable income. American Midstream Blackwater, LLC, a subsidiary of the Partnership, owns a subsidiary that has operations which are subject to both federal and state income taxes. We account for income taxes of that subsidiary using an asset and liability approach for financial accounting and reporting of income taxes. If it is more than likely that a deferred tax asset will not be realized, a valuation allowance is recognized.

Margin tax expense results from the enactment of laws by the State of Texas that apply to entities organized as partnerships and is included in Income tax expense in our consolidated statements of operations. The Texas margin tax is computed on the portion of our taxable margin which is apportioned to Texas.

Net income (loss) for financial statement purposes may differ significantly from taxable income (loss) allocable to unitholders as a result of differences between the financial reporting and income tax bases of our assets and liabilities and the taxable income allocation requirement under our Partnership Agreement. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner's tax attributes in us is not available.

Accumulated other comprehensive income (loss)

Accumulated other comprehensive income (loss) is comprised solely of adjustments related to the Partnership's postretirement benefit plan.

Limited partners' net income (loss) per unit

We compute earnings per unit using the two-class method. The two-class method requires that securities that meet the definition of a participating security be considered for inclusion in the computation of basic earnings per unit. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of the Partnership Agreement, regardless of whether the General Partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the General Partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period.

The two-class method does not impact our overall net income or other financial results; however, in periods in which aggregate net income exceeds our aggregate distributions for such period, it will have the impact of reducing net income per limited partner unit. This result occurs as a larger portion of our aggregate earnings, as if distributed, is allocated to the incentive distribution rights of the General Partner, even though we make distributions on the basis of available cash and not earnings. In periods in which our aggregate net income does not exceed our aggregate distributions for such period, the two-class method does not have any impact on our calculation of earnings per limited partner unit.

New Accounting Pronouncements

Recently Adopted Accounting Standards

In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-03, Simplifying the Presentation of Debt Issuance Costs. This update requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. ASU 2015-03 is effective for fiscal years beginning after December 15, 2015, including interim periods therein, and is applied retrospectively. Early adoption is permitted for financial statements that have not been previously issued. ASU 2015-15, Presentation and Subsequent Measurement of Debt Issue Costs Associated with Line of Credit Arrangements, was subsequently issued to address the absence of authoritative guidance for debt issuance costs related to line-of-credit arrangements and states that the Securities and Exchange Commission ("SEC") staff will not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement.
The Partnership adopted the requirements of ASU No. 2015-03 effective January 1, 2016 and classifies the debt issuance costs applicable to its 8.50% Senior Notes and 3.77% Senior Notes as a reduction of the related debt obligation. Additionally, the Partnership continues to classify the debt issuance costs relating to its Credit Agreement within Other assets, net as allowed by ASU No. 2015-15.
 
In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805). This update requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. ASU 2015-16 is effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. Early adoption is permitted for financial statements that have not been issued. The Partnership adopted the updated guidance effective January 1, 2016 without impact to its financial statements.

Accounting Standards Issued Not Yet Adopted

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), which amends the existing accounting guidance for revenue recognition. The update requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU No. 2015-14 was subsequently issued and deferred the effective date to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that period. In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal Versus Agent Considerations, as further clarification on principal versus agent considerations. In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing as further clarification on identifying performance obligations and the licensing implementation guidance. In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients, as clarifying guidance on specific narrow scope improvements and practical expedients. We are in the process of reviewing our various customer arrangements in order to determine the impact that these updates will have on our consolidated financial statements and related disclosures. We have engaged a third-party consultant to assist with our review, which we currently expect to complete in the third quarter of 2017.

In February 2016, the FASB issued ASU No. 2016-02 (Topic 842) "Leases" which supersedes the lease recognition requirements in Accounting Standards Codification Topic 840, "Leases". Under ASU No. 2016-02 lessees are required to recognize assets and liabilities on the balance sheet for most leases and 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. Based upon our evaluation to date, we anticipate that the adoption of ASU 2016-02 will have a material effect 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 have not yet determined the timing or manner in which we will implement the updated guidance.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 320): Classification of Cash Receipts and Cash Payments, which addresses eight specific cash flow issues with the objective of reducing the existing diversity of presentation and classification in the statement of cash flows. ASU No. 2016-15 is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal periods. Early adoption is permitted, but only if all aspects are adopted in the same period. The Partnership is currently evaluating the impact this update will have on its consolidated statements of cash flows and related disclosures.

In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash, which aims to improve the disclosure of the change during the period in total cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. Amounts generally described as restricted cash or restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts on the statement of cash flows. The update is effective beginning first quarter of 2018. Early adoption is permitted, but it must occur in the first interim period. Any adjustments required in early adoption of this update should be reflected as of the beginning of the fiscal year that includes the interim period and should be applied using a retrospective transition method to each period. The Partnership is evaluating the impact that this update will have on our consolidated statement of cash flows and related disclosures.
Acquisitions and Divestitures
Acquisitions and Divestitures
Acquisitions and Divestitures

JP Energy Partners

On March 8, 2017, the Partnership completed the acquisition of JPE, an entity controlled by ArcLight affiliates, in a unit-for-unit merger. In connection with the transaction, each JPE common or subordinated unit held by investors not affiliated with ArcLight was converted into the right to receive 0.5775 of a Partnership common unit, and each JPE common or subordinated unit held by ArcLight affiliates was converted into the right to receive 0.5225 of a Partnership common unit. The Partnership issued a total of 20.2 million of its common units to complete the acquisition, including 9.8 million common units to ArcLight affiliates.

As both the Partnership and JPE were controlled by ArcLight affiliates, the acquisition represents a transaction among entities under common control and will be accounted for as a common control transaction. Although the Partnership is the legal acquirer, JPE is considered to be the acquirer for accounting purposes as ArcLight obtained control of JPE prior to obtaining control of the Partnership on April 15, 2013. As a result, JPE will record the acquisition of the Partnership at ArcLight’s historical cost basis. The Partnership will file recast historical cost financial statements for the combined entity in May 2017.

JPE owns, operates and develops a diversified portfolio of midstream energy assets with three business segments (i) crude oil pipelines and storage, (ii) refined products terminals and storage and (iii) NGL distribution and sales, which together provide midstream infrastructure solutions for the growing supply of crude oil, refined products and NGLs, in the United States.

Delta House Investment

On September 18, 2015, the Partnership acquired a 26.3% interest in Pinto Offshore Holdings, LLC ("Pinto"), an entity that owns 49% of the Class A Units of Delta House FPS LLC and of Delta House Oil and Gas Lateral LLC (collectively referred to herein as "Delta House"), a floating production system platform with associated crude oil and gas export pipelines, located in the Mississippi Canyon region of the deepwater Gulf of Mexico ("Delta House").

We acquired our 26.3% non-operated interest in Pinto in exchange for $162.0 million in cash, funded by the proceeds of a public offering of 7.5 million of the Partnership's common units and with borrowings under the Partnership’s Amended and Restated Credit Agreement (the "Credit Agreement"). As a result, we own a minority interest in Pinto, which represents an indirect interest in 12.9% of Delta House's Class A Units. Pursuant to the Pinto LLC Agreement, we have no management control or authority over the day-to-day operations. Our interest in Pinto is accounted for as an equity method investment in the consolidated financial statements.

Because our interest in Delta House was previously owned by an ArcLight affiliate, we accounted for our investment at the affiliate's historical cost basis of $65.7 million and was recorded in Investments in unconsolidated affiliates in our consolidated balance sheets and as an investing activity within the related consolidated statement of cash flows. The amount by which the total consideration exceeded affiliate's historical cost basis was $96.3 million and is recorded as a distribution within the consolidated statements of changes in partners’ capital and noncontrolling interests and a financing activity in the consolidated statement of cash flows.

On April 25, 2016, the Partnership increased its investment in Delta House through the purchase of 100% of the outstanding membership interests in D-Day Offshore Holdings, LLC (“D-Day”), an Arclight affiliate which owned 1.0% of Delta House Class A Units in exchange for approximately $9.9 million in cash funded with borrowings under the Partnership’s Credit Agreement.

Because the additional investment in Delta House was previously owned by an ArcLight affiliate, we recorded our investment in D-Day at the affiliate’s historical cost basis of $9.9 million in Investments in unconsolidated affiliates on our consolidated balance sheet and as an investing activity within our condensed consolidated statements of cash flows.

On October 31, 2016, D-Day acquired an additional 6.2% direct interest in Delta House Class A Units from unrelated parties for approximately $48.8 million which was funded with $34.5 million in net proceeds from the issuance of 2,333,333 Series D convertible preferred units (“Series D Preferred Units") to an ArcLight affiliate, plus $14.3 million in cash funded with borrowings under our Credit Agreement.

Our investments in D-Day and Pinto result in the Partnership holding a 20.1% non-operated direct and indirect interests in the Class A units of Delta House as of December 31, 2016. The Partnership’s interest in Delta House consists of a 20.1% interest in Class A Units of Delta House FPS, which are currently entitled to receive 100% of the distributions from Delta House FPS until a certain payout threshold is met. Once the payout threshold is met, approximately 7% of distributions from Delta House FPS will be paid to the Class B membership interests in Delta House FPS.

Emerald Transactions

On April 25, 2016 and April 27, 2016, American Midstream Emerald, LLC (“Emerald”), a wholly-owned subsidiary of the Partnership, entered into two purchase and sale agreements with Emerald Midstream, LLC, an ArcLight affiliate, for the purchase of membership interests in certain midstream entities.

On April 25, 2016, Emerald entered into the first purchase and sale agreement for the purchase of membership interests in entities that own and operate natural gas pipeline systems and NGL pipelines in and around Louisiana, Alabama, Mississippi, and the Gulf of Mexico (the “Pipeline Purchase Agreement”). Pursuant to the Pipeline Purchase Agreement, Emerald acquired (i) 49.7% of the issued and outstanding membership interests of in Destin Pipeline Company, L.L.C. (“Destin”), (ii) 16.7% of the issued and outstanding membership interests of Tri-States NGL Pipeline, L.L.C. ("Tri-States"), and (iii) 25.3% of the issued and outstanding membership interests of Wilprise Pipeline Company, L.L.C. (“Wilprise”), in exchange for approximately $183.6 million (the “Pipeline Transaction”).

The Destin pipeline is a FERC-regulated, 255-mile natural gas transportation system with total capacity of 1.2 Bcf/d. The system originates offshore in the Gulf of Mexico and includes connections with four producing platforms and six producer-operated laterals, including Delta House. The 120-mile offshore portion of the Destin system terminates at the Pascagoula processing plant, which is owned by Enterprise Products Partners, LP, and is the single source of raw natural gas to the plant. The onshore portion of Destin is the sole delivery point for merchant-quality gas from the Pascagoula processing plant and extends 135 miles north in Mississippi. Destin currently serves as the primary transfer of gas flows from the Barnett and Haynesville shale plays to Florida markets through interconnections with major interstate pipelines. Contracted volumes on the Destin pipeline are based on life-of-field dedications, dedicated volumes over a given period, or interruptible volumes as capacity permits. We became the operator of the Destin pipeline on November 1, 2016. The Tri-States pipeline is a FERC-regulated, 161-mile NGL pipeline and sole form of transport to Louisiana-based fractionators for NGLs produced at the Pascagoula plant served by Destin and other facilities. The Wilprise pipeline is a FERC-regulated, approximately 30-mile NGL pipeline that originates at the Kenner Junction and terminates in Sorrento, Louisiana, where volumes flow via pipeline to a Baton Rouge fractionator.

On April 27, 2016, Emerald entered into a second purchase and sale agreement for the purchase of 66.7% of the issued and outstanding membership interests of Okeanos Gas Gathering Company, LLC ("Okeanos"), in exchange for a cash purchase price of approximately $27.4 million (such Purchase and Sale Agreement, the “Okeanos Purchase Agreement,” and such transaction, the “Okeanos Transaction,” and together with the Pipeline Transaction, the “Emerald Transactions”). The Okeanos pipeline is a 100-mile natural gas gathering system located in the Gulf of Mexico with a total capacity of 1.0 Bcf/d. The Okeanos pipeline connects two platforms and one lateral, terminating at the Destin Main Pass 260 platform in the Mississippi Canyon region of the Gulf of Mexico. Contracted volumes on the Okeanos pipeline are based on life-of-field dedication. We became the operator of the Okeanos pipeline on November 1, 2016.

The Partnership funded the aggregate purchase price for the Emerald Transactions with the issuance of 8,571,429 Series C convertible preferred units (the “Series C Units”) representing limited partnership interests in the Partnership and a warrant (the “ Series C Warrant”) to purchase up to 800,000 common units representing limited partnership interests in the Partnership (“common units”) at an exercise price of $7.25 per common unit amounting to a combined value of approximately $120.0 million, plus additional borrowings of $91.0 million under our Credit Agreement. ArcLight affiliates hold and participate in distributions on our Series C Units with such distributions being made in paid-in-kind Series C Units, cash or a combination thereof at the election of the Board of Directors of our General Partner.

Because our interests in the entities underlying the Emerald Transactions were previously owned by an ArcLight affiliate, we accounted for our investments at the affiliate’s historical cost basis of $212.0 million, and recorded them in Investment in unconsolidated affiliates in our consolidated balance sheet, and as an investing activity of $100.9 million within the consolidated statement of cash flows. The amount by which the affiliate's historical basis exceeded total consideration paid was $1.0 million and is recorded as a contribution from our General Partner in the consolidated statement of changes in partners’ capital and noncontrolling interests.

Gulf of Mexico Pipeline

On April 15, 2016, American Panther LLC, ("American Panther"), a 60%-owned subsidiary of the Partnership, acquired approximately 200 miles of crude oil, natural gas, and salt water onshore and offshore Gulf of Mexico pipelines (“Gulf of Mexico Pipeline”) from Chevron Pipeline Company and Chevron Midstream Pipeline, LLC for approximately $2.7 million in cash and the assumption of certain asset retirement obligations. The Partnership controls American Panther and therefore consolidates it for financial reporting purposes.

The American Panther acquisition was accounted for using the acquisition method of accounting and as a result, the purchase price was allocated to the assets acquired and liabilities assumed based on their respective estimated fair values as of the acquisition date. The purchase price allocation included $16.6 million in pipelines, $0.4 million in land, $14.3 million in asset retirement obligations, and $1.8 million in noncontrolling interests.

American Panther contributed revenue of $13.2 million and operating income of $7.4 million to the Partnership for the year ended December 31, 2016. Such amounts are included in the Partnership’s Gathering and Processing segment. During the year ended December 31, 2016, the Partnership incurred $0.3 million of transaction costs related to the American Panther acquisition which are included in Corporate expenses in our consolidated statements of operations for the periods.
Unaudited pro forma financial information depicting what the Partnership's revenue, net income and per unit amounts would have been had the American Panther acquisition occurred on January 1, 2016, is not available because Chevron Pipeline Company and Chevron Midstream Pipeline, LLC did not historically operate the acquired assets as a standalone business.

Costar Acquisition

On October 14, 2014, the Partnership acquired 100% of the membership interests of Costar Midstream, L.L.C. ("Costar") from Energy Spectrum Partners VI LP and Costar Midstream Energy, LLC, in exchange for cash and common units with an aggregate value of $405.3 million. Costar is an onshore gathering and processing company with its primary gathering, processing, fractionation, and off-spec condensate treating and stabilization assets in East Texas and the Permian basin, with a significant crude oil gathering system project in the Bakken oil play.

The Costar acquisition was accounted for using the acquisition method of accounting and as a result, the purchase price was allocated to the assets acquired and liabilities assumed based on their respective fair values as of the acquisition date. The excess of the aggregate purchase price of the fair values of the assets acquired, liabilities assumed and the noncontrolling interest was classified as goodwill, which was attributable to future prospective customer agreements expected to be obtained as a result of the acquisition. The operating systems acquired have been included in the Partnership’s Gathering and Processing segment from the acquisition date.

During 2015, the Partnership reached agreements with the Costar sellers regarding certain matters which resulted in a return of $7.4 million of cash to the Partnership and related reductions in the goodwill initially recorded. Additionally, in February 2016, the Partnership reached a settlement of certain indemnification claims with the Costar sellers whereby 1,034,483 common units held in escrow with a fair value of $6.8 million were returned to the Partnership, while the Partnership agreed to pay the Costar sellers an additional $0.3 million. The net impact of this settlement was recorded as a reduction in property, plant and equipment in the first quarter of 2016. The Partnership recognized a $95.0 million impairment of the remaining Costar goodwill in fourth quarter of 2015.

Lavaca Acquisition

On January 31, 2014, the Partnership acquired approximately 120 miles of high- and low-pressure pipelines and associated facilities located in the Eagle Ford shale in Gonzales and Lavaca Counties, Texas from Penn Virginia Corporation (NYSE: PVA) ("PVA") for $104.4 million in cash. The Lavaca acquisition was financed with proceeds from the Partnership's January 2014 equity offering and from the issuance of Series B Units to our General Partner.

The Lavaca acquisition was accounted for using the acquisition method of accounting and, as a result, the purchase price was allocated to the assets acquired upon their respective fair values as of the acquisition date. The excess of the purchase price over the fair value of the assets acquired was classified as goodwill, which was attributable to future prospective customer agreements expected to be obtained as a result of the acquisition. The operating systems acquired have been included in the Partnership’s Gathering and Processing segment from the acquisition date. The Partnership recognized a $23.6 million impairment of the remaining Lavaca goodwill in the fourth quarter of 2015.
Discontinued Operations
Discontinued Operations
Discontinued Operations

On December 17, 2013, the Partnership acquired Blackwater Midstream Holdings LLC ("Blackwater") from an ArcLight affiliate. As part of the Blackwater acquisition, we acquired certain long-lived terminal assets which were immediately classified as held for sale. Due to deteriorating market conditions, the Partnership recognized an impairment charge on these assets of $0.7 million in 2014. These assets were sold during the third quarter of 2015 at a nominal loss.

We classified these assets as discontinued operations within our consolidated statements of operations, but elected not to separately present the related operating, investing and financing cash flows in our consolidated statements of cash flows as the related activity was immaterial for all periods presented.

The following table presents the revenue, expense and (loss) gain from discontinued operations associated with the assets classified as held for sale for the years ended December 31, 2015 and 2014 (in thousands, except per unit amounts):

 
Years Ended December 31,
 
2015
 
2014
Revenue
$
74

 
$
474

Expense
(196
)
 
(658
)
Impairment
—

 
(673
)
Loss on sale of assets
(150
)
 
(87
)
Income tax benefit
192

 
333

Loss from discontinued operations, net of tax
$
(80
)
 
$
(611
)
Limited partners' net income (loss) per unit from discontinued operations (basic and diluted)
$
—

 
$
(0.04
)
Concentration of Credit Risk and Trade Accounts Receivable
Concentration of Credit Risk and Trade Accounts Receivable
Concentration of Credit Risk and Trade Accounts Receivable

Our primary assets, which are strategically located in Alabama, Georgia, Louisiana, Mississippi, North Dakota, Tennessee, Texas and the Gulf of Mexico, provide critical infrastructure that links customers of natural gas, crude oil, NGLs, condensate and specialty chemicals to numerous intermediate and end-use markets.  As a result of recent acquisitions and geographic diversification, we have reduced the concentration our of trade receivable balances. Our customers' historical financial and operating information is analyzed prior to extending credit. We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees. We record allowances for potentially uncollectible accounts receivable when necessary. For the year ended December 31, 2016, we recorded an allowance of $0.6 million.

Significant customers are defined as those who represent 10% of more of our consolidated revenue during the year. In 2016, we had one such customer who accounted for 10% of our consolidated revenue. In 2015, we had one such customer who accounted for 10% of our consolidated revenue. In 2014, we had three such customers who accounted for 22%, 12% and 10%, respectively, of our consolidated revenue.
Other Current Assets
Other Current Assets
Other Current Assets

Other current assets consists of the following (in thousands):
 
December 31,
 
2016
 
2015
Prepaid insurance
$
4,308

 
$
3,948

Other receivables
2,376

 
1,573

Due from related parties
4,206

 
64

Risk management assets
429

 
365

Other prepaids
2,967

 
2,866

Miscellaneous
2,184

 
1,643

 
$
16,470

 
$
10,459

Risk Management Activities
Risk Management Activities
Risk Management Activities

Commodity Derivatives

To limit the effect of commodity price changes and maintain our cash flow and the economics of our development plans, we enter into commodity derivative contracts from time to time. The terms of the contracts depend on various factors, including management's view of future commodity prices, economics on purchased assets and future financial commitments. This hedging program is designed to mitigate the effect of commodity price declines while allowing us to participate in some commodity price increases. Management regularly monitors the commodity markets and financial commitments to determine if, when, and at what level commodity hedging is appropriate in accordance with policies that are established by the board of directors of our General Partner.

We enter into commodity contracts with multiple counterparties, and in some cases, may be required to post collateral with our counterparties in connection with our derivative positions. The counterparties are not required to post collateral with us in connection with their derivative positions. Netting agreements are in place that permit us to offset our commodity derivative asset and liability positions with our counterparties.

As of December 31, 2016 and 2015, we did not have any outstanding commodity derivative contracts.

Interest Rate Swaps

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

As of December 31, 2016, our outstanding interest rate swap contracts consist of the following (in thousands):

Notional Amount
Term
Fair Value
$200,000
January 3, 2017 thru September 3, 2019
$1,912
$100,000
January 1, 2018 thru December 31, 2021
$3,090
$150,000
January 1, 2018 thru December 31, 2022
$5,219
 
 
$10,221


The fair value of our interest rate swaps was estimated using a valuation methodology based upon forward interest rate 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 quarters of 2016 and 2015, we entered into weather derivatives to mitigate the impact of potential unfavorable weather to our operations under which we could receive payments totaling up to $30.0 million in the event that a hurricane or hurricanes of certain strength pass through the area as identified in the related agreement. The weather derivatives, which are accounted for using the intrinsic value method, were entered into with a single counterparty and we were not required to post collateral.

We paid premiums of $1.0 million and $0.9 million in 2016 and 2015, respectively, which are amortized to Direct operating expenses on a straight-line basis over the 1 year term of the contract. Unamortized amounts associated with weather derivatives were approximately $0.4 million at December 31, 2016 and 2015, and are included in Other current assets on the consolidated balance sheets.

Our interest rate swaps and weather derivatives were recorded in our consolidated balance sheets, under the following captions (in thousands):
 
 
Gross Risk Management Position
 
Netting Adjustment
 
Net Risk Management Position
Balance Sheet Classification
 
December 31, 2016
 
December 31, 2015
 
December 31, 2016
 
December 31, 2015
 
December 31, 2016
 
December 31, 2015
Other current assets
 
$
487

 
$
365

 
$
(58
)
 
$
—

 
$
429

 
$
365

Risk management assets
 
10,401

 
—

 
—

 
—

 
10,401

 
—

Total assets
 
$
10,888

 
$
365

 
$
(58
)
 
$
—

 
$
10,830

 
$
365

 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued expenses and other liabilities
 
$
(238
)
 
$
—

 
$
58

 
$
—

 
$
(180
)
 
$
—

Total liabilities
 
$
(238
)
 
$
—

 
$
58

 
$
—

 
$
(180
)
 
$
—


For the years ended December 31, 2016, 2015 and 2014, the realized and unrealized gains (losses) associated with our commodity, interest rate and weather derivative instruments were recorded in our consolidated statements of operations, under the captions as follows (in thousands):
 
 
Realized
 
Unrealized
2016
 

Gains (losses) on commodity derivatives, net
 
$
(840
)
 
$
—

Interest expense
 
—

 
10,221

Direct operating expenses
 
(966
)
 
—

Total
 
$
(1,806
)
 
$
10,221

2015
 
 
 
 
Gains (losses) on commodity derivatives, net
 
$
1,610

 
$
(286
)
Interest expense
 
(240
)
 
215

Direct operating expenses
 
(913
)
 
—

Total
 
$
457

 
$
(71
)
2014
 
 
 
 
Gains (losses) on commodity derivatives, net
 
$
735

 
$
356

Interest expense
 
(433
)
 
239

Direct operating expenses
 
(1,035
)
 
—

Total
 
$
(733
)
 
$
595

Property, Plant and Equipment, Net
Property, Plant and Equipment, Net
Property, Plant and Equipment, Net

Property, plant and equipment, net. consists of the following (in thousands):
 
 
Useful Life
(in years)
 
December 31,
2016
 
December 31,
2015
Land
N/A
 
$
15,112

 
$
10,319

Construction in progress
N/A
 
122,884

 
45,383

Buildings and improvements
4 to 40
 
12,413

 
10,871

Processing and treating plants
8 to 40
 
134,434

 
115,568

Pipelines and compressors
3 to 40
 
554,965

 
538,402

Storage
20 to 40
 
58,786

 
58,220

Equipment
5 to 20
 
39,470

 
22,510

Total property, plant and equipment
 
 
938,064

 
801,273

Less accumulated depreciation
 
 
(182,607
)
 
(145,963
)
Property, plant and equipment, net
 
 
$
755,457

 
$
655,310



At December 31, 2016 and 2015, gross property, plant and equipment included $231.1 million and $160.4 million, respectively, related to our FERC regulated interstate and intrastate assets.

Depreciation expense totaled $38.3 million, $31.9 million and $23.9 million for the years ended December 31, 2016, 2015 and 2014, respectively. Capitalized interest was $2.7 million, $1.9 million and $0.8 million for the years ended December 31, 2016, 2015 and 2014, respectively.

During the fourth quarter of 2014, management noted the declining commodity markets and related impact on producers and shippers to whom we provide gathering and processing services. The decline in the market price of crude oil led to a corresponding decrease in natural gas and crude oil production impacting the volume of natural gas and NGLs we gather and process on certain assets. As a result, an asset impairment charge of $99.9 million was recorded to reduce the carrying value of the impacted assets to their estimated fair value. The related fair value measurements were based on significant inputs not observable in the market and thus represented Level 3 measurements as defined by ASC 820. Primarily using the income approach, the fair value estimates were based on i) present value of estimated EBITDA, ii) an assumed discount rate of 9.5%, and iii) the expected remaining useful life of the asset or asset group.
Goodwill and Intangible Assets, Net
Goodwill and Intangible Assets, Net
Goodwill and Intangible Assets, Net

Management performs an annual goodwill assessment at the reporting unit level. We first assess qualitative factors to evaluate whether it is more likely than not that an impairment has occurred and if it is then necessary to perform the two-step goodwill impairment test. The two-step goodwill impairment test involves fair value measurements that are based on significant inputs not observable in the market and thus represent Level 3 measurements as defined by ASC 820. In the two-step assessment, management primarily uses a discounted cash flow analysis, supplemented by a market approach analysis. Key assumptions in the discounted cash flow analysis include an appropriate discount rate, estimated volumes, storage utilization, terminal year multiples, operating costs and maintenance capital expenditures. In estimating cash flows, management incorporates current market information, as well as historical and other factors into the forecasted commodity prices and contracted rates used.

In 2015, management utilized the approach described above in performing the first step of its annual goodwill impairment test. As a result of our step one analysis, we determined that the estimated fair value of certain reporting units within our Gathering and Processing reportable segment were less than their respective carrying amounts, primarily due to changes in assumptions related to commodity prices, timing of estimated drilling by producers, and discount rates. These assumptions were adversely impacted by the continuing decline in market conditions within the energy sector.

The second step of the goodwill impairment test involved allocating the estimated fair value of each reporting unit among the assets and liabilities of the reporting unit in a hypothetical purchase price allocation. The results of the hypothetical purchase price allocation indicated there was no fair value attributable to goodwill of the reporting units within our Gathering and Processing reportable segment. As a result, we recognized a goodwill impairment charge of $118.6 million during the fourth quarter which
consisted of $95.0 million and $23.6 million related to the Costar and Lavaca acquisitions, respectively.

At December 31, 2016 and 2015, our goodwill relates to the Blackwater reporting unit within our Terminals segment. During the fourth quarter of 2016, we assessed qualitative factors to evaluate whether it was more likely than not that a related goodwill impairment had occurred. Based on that assessment, which considered the amount by which the fair value of the Blackwater reporting unit exceeded its related carrying value at the time of the last annual impairment test coupled with the continued performance of that reporting unit, we concluded that the goodwill was not impaired and that completion of the two-step impairment test was not necessary.

Intangible assets, net, consists of customer relationships, dedicated acreage agreements, and collaborative arrangements identified as part of the Costar, Lavaca and Blackwater acquisitions. These intangible assets have definite lives and are subject to amortization on a straight-line basis over their economic lives, currently ranging from approximately 10 years to 30 years. Intangible assets, net, consist of the following (in thousands):
 
December 31,
 
2016
 
2015
Gross carrying amount:
 
 
 
Customer relationships
$
53,400

 
$
53,400

Dedicated acreage
53,350

 
53,350

Collaborative arrangements
11,884

 
11,884

 
$
118,634

 
$
118,634

Accumulated amortization:
 
 
 
Customer relationships
$
(5,696
)
 
$
(3,124
)
Dedicated acreage
(4,439
)
 
(2,661
)
Collaborative arrangements
(601
)
 
—

 
$
(10,736
)
 
$
(5,785
)
Net carrying amount:
 
 
 
Customer relationships
$
47,704

 
$
50,276

Dedicated acreage
48,911

 
50,689

Collaborative arrangements
11,283

 
11,884

 
$
107,898

 
$
112,849



For the years ended December 31, 2016, 2015 and 2014, amortization expense on our intangible assets totaled $4.6 million, $5.3 million and $4.1 million, respectively. Estimated amortization expense for each of the next five fiscal years (2017 – 2021) is approximately $4.6 million per year and $85.0 million thereafter.
Investment in Unconsolidated Affiliates
Investment in Unconsolidated Affiliates
Investment in Unconsolidated Affiliates

The following table presents activity in the Partnership's investments in unconsolidated affiliates (in thousands):
 
 
Delta House (1)
 
Emerald Transactions
 
 
 
 
 
 
FPS
 
OGL
 
Destin
 
Tri-States
 
Okeanos
 
Wilprise
 
MPOG
 
Total
Ownership % at December 31, 2016
20.1
%
 
20.1
%
 
49.7
%
 
16.7
%
 
66.7
%
 
25.3
%
 
66.7
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance at December 31, 2013
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
Investment
—

 
—

 
—

 
—

 
—

 
—

 
12,000

 
12,000

 
Earnings in unconsolidated affiliates
—

 
—

 
—

 
—

 
—

 
—

 
348

 
348

 
Contributions
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
Distributions
—

 
—

 
—

 
—

 
—

 
—

 
(1,980
)
 
(1,980
)
Balance at December 31, 2014
—

 
—

 
—

 
—

 
—

 
—

 
10,368

 
10,368

 
Investment
40,559

 
25,144

 
—

 
—

 
—

 
—

 
—

 
65,703

 
Earnings in unconsolidated affiliates
5,457

 
2,013

 
—

 
—

 
—

 
—

 
731

 
8,201

 
Contributions
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
Distributions
(12,551
)
 
(4,097
)
 
—

 
—

 
—

 
—

 
(3,920
)
 
(20,568
)
Balance at December 31, 2015
33,465

 
23,060

 
—

 
—

 
—

 
—

 
7,179

 
63,704

 
Investment
55,461

 
3,255

 
122,830

 
56,681

 
27,451

 
5,064

 
—

 
270,742

 
Earnings in unconsolidated affiliates
21,022

 
9,260

 
3,946

 
1,633

 
3,642

 
437

 
218

 
40,158

 
Contributions
—

 
—

 
—

 
—

 
—

 
—

 
430

 
430

 
Distributions
(45,465
)
 
(10,125
)
 
(15,894
)
 
(3,292
)
 
(4,034
)
 
(557
)
 
(3,679
)
 
(83,046
)
Balance at December 31, 2016
$
64,483

 
$
25,450

 
$
110,882

 
$
55,022

 
$
27,059

 
$
4,944

 
$
4,148

 
$
291,988



(1) Represents direct and indirect ownership interests in Class A Units.

We have included the audited financial statements for each of the unconsolidated affiliates listed above, except Wilprise, as exhibits to this Form 10-K. As of December 31, 2016, Wilprise had current assets of $1.6 million, non-current assets (primarily property, plant and equipment) of $12.0 million, liabilities of $0.3 million, and members' equity of $13.3 million. Additionally, for the year ended December 31, 2016, Wilprise had revenues of $5.1 million, operating expenses of $1.9 million, and net income of $3.2 million.

Our investments in the unconsolidated affiliates underlying the Emerald Transactions were acquired in late April 2016. The following table presents information for each of these affiliates for the portion of 2016 that we held the related investments:

 
Emerald Transactions
 
Destin
 
Tri-States
 
Okeanos
 
Wilprise
Revenues
34,360

 
25,557

 
10,453

 
3,306

Net income
8,272

 
15,983

 
1,911

 
2,028

Partnership ownership %
49.7
%
 
16.7
%
 
66.7
%
 
25.3
%
Partnership share of investee net income
4,109

 
2,664

 
1,274

 
513

Basis difference amortization
(163
)
 
(1,031
)
 
2,368

 
(76
)
Earnings in unconsolidated affiliates
3,946

 
1,633

 
3,642

 
437



The unconsolidated affiliates were determined to be variable interest entities due to disproportionate economic interests and decision making rights. In each case, the Partnership lacks the power to direct the activities that most significantly impact the unconsolidated affiliate's economic performance. As the Partnership does not hold a controlling financial interest in these affiliates, the Partnership accounts for its related investments using the equity method. Additionally, the Partnership’s maximum exposure to loss related to each entity is limited to its equity investment as presented on the consolidated balance sheet, as it is not obligated to absorb losses greater than its proportional ownership percentages indicated above. The Partnership’s right to receive residual returns is not limited to any amount less than the ownership percentages indicated above.
Accrued Expenses and Other Current Liabilities
Accounts Expenses and Other Current Liabilities
Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities consists of the following (in thousands):

 
 
December 31,
 
 
2016
 
2015
Capital expenditures
 
$
13,319

 
$
3,984

Convertible preferred unit distributions
 
7,103

 
—

Current portion of asset retirement obligations
 
6,499

 
6,822

Accrued interest
 
5,743

 
1,411

Additional Blackwater acquisition consideration
 
5,000

 
—

Employee compensation
 
4,226

 
3,114

Due to related parties
 
3,895

 
3,894

Transaction costs
 
3,000

 
—

Deferred financing costs
 
2,743

 
—

Gas imbalances payable
 
1,098

 
413

Other
 
8,952

 
3,675

 
 
$
61,578

 
$
23,313

Asset Retirement Obligations
Asset Retirement Obligations
Asset Retirement Obligations

The following table presents activity in the Partnership's asset retirement obligations (in thousands):
 
Years Ended December 31,
 
2016
 
2015
Beginning balance
$
35,371

 
$
34,645

Liabilities assumed (1)
14,542

 
—

Revision in estimate
230

 
—

Expenditures
(858
)
 
(91
)
Accretion expense
1,577

 
817

Ending balance
50,862

 
35,371

Less: current portion
6,499

 
6,822

Noncurrent asset retirement obligation
$
44,363

 
$
28,549


______________________________________________________________________________________________________
(1) $14.3 million of the liability is a result of the Gulf of Mexico Pipeline acquisition.

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 in our consolidated balance sheets as of December 31, 2016 and 2015.
Debt Obligations
Debt Obligations
Debt Obligations

Our outstanding debt consists of the following as of December 31, 2016 (in thousands):
 

 
8.5% Senior
 
3.77% Senior
 
 
 
 
 
Credit
 
Notes due
 
Notes due
 
Other
 
 
 
 Agreement (1)
 
2021
 
2031
 
Debt
 
Total
Balance
$
711,250

 
$
300,000

 
$
60,000

 
$
2,782

 
$
1,074,032

Less unamortized deferred financing costs and discount
—

 
(8,691
)
 
(2,345
)
 
—

 
(11,036
)
  Subtotal
711,250

 
291,309

 
57,655

 
2,782

 
1,062,996

Less current portion
—

 
—

 
(1,676
)
 
(2,782
)
 
(4,458
)
  Non-current portion
$
711,250

 
$
291,309

 
$
55,979

 
$
—

 
$
1,058,538



Our outstanding debt consists of the following as of December 31, 2015 (in thousands):
 
Credit
 
Other
 
 
 
 Agreement (1)
 
Debt
 
Total
Balance
$
525,100

 
$
2,338

 
$
527,438

Less current portion
—

 
(2,338
)
 
(2,338
)
  Non-current portion
$
525,100

 
$
—

 
$
525,100


______________________
(1) Unamortized deferred financing costs related to the Credit Agreement are included in Other assets, net.

Credit Agreement

Effective as of April 25, 2016, the Partnership entered into the Second Amendment to the Amended and Restated Credit Agreement (as amended, the "Credit Agreement"), which provides for maximum borrowings up to $750.0 million, with the ability to further increase the borrowing capacity to $900.0 million subject to lender approval. We can elect to have loans under our Credit Agreement bear interest either at a Eurodollar-based rate, plus a margin ranging from 2.00% to 3.25% depending on our total leverage ratio then in effect, or 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," or (iii) the Eurodollar Rate plus 1.00% 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 of 0.50% per annum on the undrawn portion of the revolving loan under the Credit Agreement.

Our obligations under the Credit Agreement are secured by a lien on substantially all of our assets. Advances made under the Credit Agreement are guaranteed on a senior unsecured basis by certain of our subsidiaries (the “Guarantors”). These guarantees 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.

On September 30, 2016, in connection with the 3.77% Senior Note Purchase Agreement, the Partnership entered into the Limited Waiver and Third Amendment to the Credit Agreement, which among other things, (i) allows Midla Holdings (as defined below), for so long as the 3.77% Senior Notes are outstanding, to be excluded from guaranteeing the obligations under the Credit Agreement and being subject to certain convents thereunder, (ii) releases the lien granted under the original credit agreement on D-Day’s equity interests in Delta House FPS, LLC, and (iii) deems the equity interests in Delta House FPS, LLC to be excluded property under the Credit Agreement. All other terms under the Credit Agreement remain the same.

On November 18, 2016, the Partnership entered into the Fourth Amendment to the Amended and Restated Credit Agreement. The Fourth Amendment (i) modifies certain investment covenants to reflect the recently completed incremental acquisition of additional interests in Delta House Class A Units (ii) permits JPE’s existing credit facility (the “JPE Credit Facility”) to remain in place during the time period between (a) the consummation of the JPE Merger and (b) the payoff of the JPE Credit Facility, (iii) permits the joining of JPE and its subsidiaries as guarantors under the Credit Agreement, and (iv) permits the integration of JPE and its subsidiaries into the Partnership’s ownership structure.

The Credit Agreement contains certain financial covenants, including a consolidated total leverage ratio which requires our indebtedness not to exceed 4.75 times adjusted consolidated EBITDA for the prior twelve month period adjusted in accordance with the Credit Agreement (except for the current and subsequent two quarters after the consummation of a permitted acquisition, at which time the covenant is increased to 5.25 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. The financial covenants in our Credit Agreement may limit the amount available to us for borrowing to less than $750.0 million. In addition to the financial covenants described above, the Credit Agreement also contains customary representations and warranties (including those relating to organization and authorization, compliance with laws, absence of defaults, material agreements and litigation) and customary events of default (including those relating to monetary defaults, covenant defaults, cross defaults and bankruptcy events).

For the years ended December 31, 2016, 2015 and 2014, the weighted average interest rate on borrowings under our Credit Agreement was approximately 4.29%, 3.67%, and 3.80%, respectively.

As of December 31, 2016, our consolidated total leverage ratio was 4.07 and our interest coverage ratio was 7.43, which were both in compliance with the related requirements of our Credit Agreement. At December 31, 2016 and 2015, letters of credit outstanding under the Credit Agreement were $7.4 million and $1.8 million, respectively. As of December 31, 2016, we had approximately $711.3 million of borrowings and $7.4 million of letters of credit outstanding under the Credit Agreement resulting in $31.3 million of available borrowing capacity.

As of December 31, 2016, we were in compliance with the covenants included in the Credit Agreement. 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 carrying value of amounts outstanding under the Partnership’s Credit Agreement approximates the related fair value, as interest charges vary with market rates conditions. On March 8, 2017, the Partnership entered into the Second Amended and Restated Credit Agreement, which increased our borrowing capacity from $750.0 million to $900.0 million and provided for an accordion feature that will permit, subject to the customary conditions, the borrowing capacity under the facility to be increased to a maximum of $1.1 billion. Please see Note 23.

8.50% Senior 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 8.50% Senior Notes. The 8.50% Senior Notes are jointly and severally guaranteed by the Partnership’s existing direct and indirect wholly owned subsidiaries (other than the Co-Issuer) and certain of the Partnership’s future subsidiaries (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. This amount was deposited into escrow pending completion of the JPE Merger and is included in Restricted cash on our consolidated balance sheet as of December 31, 2016. 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.

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 and terminate JPE's revolving credit facility and reduce borrowings under the Partnership’s Credit Agreement.
 
The 8.50% Senior Notes will mature on December 15, 2021 with interest payable in arrears on June 15 and December 15, commencing June 15, 2017.

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.

Prior to December 15, 2018, the Issuers may redeem all or part of the 8.50% Senior Notes, at a redemption price equal to the sum of:

•
the principal amount thereof, plus

•
the make whole premium (as defined in the Indenture) at the redemption date, plus

•
accrued and unpaid interest, to the redemption date.

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 December 31, 2016 approximates the related fair value as of that date as the Senior Notes were issued on December 28, 2016.

3.77% Senior Notes

On September 30, 2016, Midla Financing, LLC ("Midla Financing"), American Midstream (Midla), LLC (“Midla”), and Mid Louisiana Gas Transmission LLC ("MLGT" and together with Midla, the "Note Guarantors") entered into a Note Purchase and Guaranty Agreement with certain institutional investors (the “Purchasers”) whereby Midla Financing issued $60.0 million in aggregate principal amount of 3.77% Senior Notes 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 after deducting related 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 general corporate purposes of Midla Financing. As of December 31, 2016, Restricted cash includes $24.5 million from the issuance of the 3.77% Senior Notes.

The Note Purchase Agreement includes customary 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, and Midla Financing and the Note Guarantors (including any entities that become guarantors under the terms of the 3.77% Senior Note Purchase Agreement) are restricted from making distributions until June 30, 2017, unless the debt service coverage ratio is not less than, and is not projected to be for the following 12 calendar months less than, 1.20:1.00, and unless certain other requirements are met.

In connection with the 3.77% Senior Note Purchase Agreement, the Note Guarantors guaranteed the payment in full of all Midla Financing’s related obligations. Also, Midla Financing and the Note Guarantors granted a security interest in substantially all of their tangible and intangible personal assets, 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.

As of December 31, 2016, the fair value of the 3.77% Senior Notes was $54.6 million.This estimate was based on similar private placement transactions along with changes in market interest rates which represent a Level 2 measurement.
Convertible Preferred Units
Convertible Preferred Units
Convertible Preferred Units

Our convertible preferred units consist of the following (in thousands):

 
Series A
 
Series C
 
Series D
 
Units
$
 
Units
$
 
Units
$
December 31, 2013
5,279

$
94,811

 
—

$
—

 
—

$
—

Issuance of units
—

—

 
—

—

 
—

—

Paid in kind unit distributions
466

13,154

 
—

—

 
—

—

December 31, 2014
5,745

107,965

 
—

—

 
—

—

Issuance of units
2,571

44,769

 
—

—

 
—

—

Paid in kind unit distributions
894

16,978

 
—

—

 
—

—

December 31, 2015
9,210

169,712

 
—

—

 
—

—

Issuance of units
—

—

 
8,571

115,457

 
2,333

34,475

Paid in kind unit distributions
897

11,674

 
221

2,772

 
—

—

December 31, 2016
10,107

$
181,386

 
8,792

$
118,229

 
2,333

$
34,475



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, although quarterly distribution on our Series D Units will only be paid in cash. 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 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 and $15.0 million in cash to us in exchange for 5,142,857 of our Series A-1 Units.
The Series A-1 Units receive distributions prior to distributions to our common unitholders. The distributions on the Series A-1 Units are equal to the greater of $0.50 per unit or the declared distribution to common unitholders. The Series A-1 Units may be converted into common units on a one-to-one basis, subject to customary anti-dilutive adjustments, at the option of the unitholders on or any time after January 1, 2014. As of December 31, 2016, the conversion price is $15.87.

Upon any liquidation and winding up of the Partnership or the sale of substantially all of its assets, the holders of Series A-1 Units will generally be entitled to receive, in preference to the holders of any of the Partnership's other equity securities, but in parity with all convertible preferred units, an amount equal to the sum of $15.87 multiplied by the number of Series A-1 Units owned by such holders, plus all accrued but unpaid distributions on such Series A Units.

Prior to the consummation of any recapitalization, reorganization, consolidation, merger, spin-off or other business combination in which the holders of common units are to receive securities, cash or other assets (a "Partnership Event"), we are obligated to make an irrevocable written offer, subject to consummation of the Partnership Event, to each holder of Series A Units to redeem all (but not less than all) of such holder's Series A-1 Units for a per unit price payable in cash as described in the Partnership Agreement.

Upon receipt of such a redemption offer from us, each holder of Series A-1 Units may elect to receive such cash amount or a preferred security issued by the person surviving or resulting from such Partnership Event and containing provisions substantially equivalent to the provisions set forth in the Partnership Agreement with respect to the Series A-1 Units without material abridgement.

Except as provided in the Partnership Agreement, the Series A-1 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, with each Series A-1 Unit entitled to one vote for each common unit into which such Series A-1 Unit is convertible.

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 Units have been classified as mezzanine equity in the consolidated balance sheets.

Under the Partnership Agreement, distributions on Series A-1 Units were made with paid-in-kind Series A-1 Units, cash or a combination thereof, at the discretion of the Board of Directors, through the distribution for the quarter ended March 31, 2016. The Partnership was previously required to pay distributions on the Series A-1 Units with a combination of paid-in-kind units and cash.

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 ("Magnolia") an affiliate of HPIP pursuant to which the Partnership 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 affiliate’s 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 December 31, 2016, the conversion price is $15.87.

Series C Convertible Preferred Units

On April 25, 2016, the Partnership issued 8,571,429 of its Series C Units to an ArcLight affiliate in connection with the Emerald Transactions described in Note 2.

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 Securities Act pursuant to Rule 4(a)(2) under the Securities Act.

In the event that the Partnership issues, sells or grants 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 December 31, 2016, the conversion price is $13.95.

Prior to consummating any recapitalization, reorganization, consolidation, merger, spin-off or other business combination in which the holders of common units are to receive securities, cash or other assets, we are obligated to make an irrevocable written offer, subject to consummating the Partnership Event, to the holders of Series C Units to redeem all (but not less than all) of the Series C Units for a price per Series C Unit payable in cash as described in the Partnership Agreement.

Upon receipt of a redemption offer, each holder of Series C Preferred Units may elect to receive the cash amount or a preferred security issued by the person surviving or resulting from the Partnership Event and containing provisions substantially equivalent to the provisions set forth in the Fifth Amended and Restated Partnership Agreement with respect to the Series C Preferred Units without material abridgement.

Upon any liquidation and winding up of the Partnership or the sale of substantially all of the assets of the Partnership, the holders of Series C Units generally will be entitled to receive, in preference to the holders of any of the Partnership's other equity securities but in parity with all convertible preferred units, an amount equal to the sum of the $14.00 multiplied by the number of Series C Units owned by such holders, plus all accrued but unpaid distributions.

At any time prior to April 25, 2017, the Partnership has the right (the “Series C Call Right”) to require the holders of the Series C Units to sell, assign and transfer all or a portion of the then outstanding Series C Units for a purchase price of $14.00 per Series C Unit (subject to customary anti-dilution adjustments), plus all accrued but unpaid distributions on each Series C Unit.

The Partnership may not exercise the Series C Call Right if the holder has elected to convert it into common units on or prior to the date the Partnership has provided notice of its intent to exercise its Series C Call Right, and may not exercise the Series C Call Right if doing so would violate applicable law or result in a default under any financing agreement or obligation of the Partnership or its affiliates.

In connection with the issuance of the Series C Units, the Partnership 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.

On April 25, 2017, the number of common units that may be purchased pursuant to the exercise of the Series C Warrant will be adjusted by an amount, rounded to the nearest whole common unit, equal to the product obtained by the following calculation: (i) 400,000 multiplied by (ii) (A) the Series C Issue Price multiplied by the number of Series C Units then outstanding less $45.0 million divided by (B) the Series C Issue Price multiplied by the number of Series C Units issued, less $45.0 million.

Any Series C Units issued in-kind as a distribution to holders of Series C Units (“Series C PIK Units”) will increase the number of common units that can be purchased upon exercise of the Series C Warrant by an amount, rounded to the nearest whole common unit, equal to the product obtained by the following calculation: (i) the total number of common units into which each Series C Warrant may be exercised immediately prior to the most recent issuance of the Series C PIK Units multiplied by (ii) (A) the total number of outstanding Series C Units immediately after the most recent issuance of Series C PIK Units divided by (B) the total number of outstanding Series C Units immediately prior to the most recent issuance of Series C PIK Units.

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.

Series D Convertible Preferred Units

On October 31, 2016, Partnership issued 2,333,333 shares of its newly-designated Series D Units to an ArcLight affiliate at a price of $15.00 per unit, less a 1.5% closing fee, in connection with the Delta House transaction described in Note 2. The related agreement provides that if any of the Series D Units remain outstanding on June 30, 2017, the Partnership will issue the holder of the Series D Units a warrant (the “Series D Warrant”) to purchase 700,000 common units representing limited partnership interests with an exercise price of $22.00 per common unit. The fair value of the conditional Series D Warrant at the time of issuance was immaterial.

The Series D Units are entitled to quarterly distributions payable in arrears equal to the greater of $0.4125 and the cash distribution that the Series D Units would have received if they had been converted to common units immediately prior to the beginning of the the quarter. The Series D 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 D Units. The Series D Units are convertible in whole or in part into common units at the election of the holder of the Series D Unit at any time after June 30, 2017. As of the date of issuance, the conversion rate for each Series D Unit was one -to-one (the “Conversion Rate”). As of December 31, 2016, the conversion price is $14.98.

In the event that the Partnership issues, sells or grants any common units or securities convertible into common units at an indicative per common unit price that is less than $15.00 per unit (subject to customary anti-dilution adjustments), then the Conversion Rate will be adjusted according to a formula to provide for an increase in the number of common units into which Series D Units are convertible.

Prior to the consummation of any recapitalization, reorganization, consolidation, merger, spin-off or other business combination in which the holders of Common Units are to receive securities, cash or other assets (a “Partnership Event”), the Partnership is obligated to make an irrevocable written offer, subject to consummation of the Partnership Event, to the holders of Series D Units to redeem all (but not less than all) of the Series D Units for a price per Series D Unit payable in cash as described in the Partnership Agreement.

Upon receipt of a redemption offer, each holder of Series D Units may elect to receive the cash amount or a preferred security issued by the person surviving or resulting from the Partnership Event.

Upon any liquidation and winding up of the Partnership or the sale of substantially all of the assets of the Partnership, the holders of Series D Units generally will be entitled to receive, in preference to the holders of any of the Partnership's other equity securities but in parity with all convertible preferred units, an amount equal to the sum of the $15.00 multiplied by the number of Series D Units owned by such holders, plus all accrued but unpaid distributions.

At any time prior to June 30, 2017, the Partnership has the right (the “Series D Call Right”) to redeem the Series D Units for the product of (i) the sum of $15.00 and all accrued and accumulated but unpaid distributions for each Series D Unit (including a proportionate amount of the distribution on each Series D Unit that has accrued for the quarter in which the redemption occurs); and (ii) 1.03.
Partners' Capital
Partners' Capital
Partners' Capital

Outstanding Units

The following table presents unit activity (in thousands):

 
 
General
Partner Interest
 
Limited Partner Interest
 
Series B Convertible Units
Balances at December 31, 2013
 
185

 
7,414

 
—

Initial issuance of Series B Units
 
—

 
—

 
1,168

Issuance of Series B Units
 
—

 
—

 
87

LTIP vesting
 
—

 
41

 
—

Issuance of GP units
 
207

 
—

 
—

Exercise of warrants
 
—

 
300

 
—

Issuance of common units
 
—

 
14,915

 
—

Balances at December 31, 2014
 
392

 
22,670

 
1,255

Issuance of Series B Units
 
—

 
—

 
95

LTIP vesting
 
—

 
105

 
—

Exercise of unit options
 
—

 
152

 
—

Issuance of GP units
 
144

 
—

 
—

Issuance of common units
 
—

 
7,500

 
—

Balances at December 31, 2015
 
536

 
30,427

 
1,350

Conversion of Series B Units
 
—

 
1,350

 
(1,350
)
Return of escrow units
 
—

 
(1,034
)
 
—

LTIP vesting
 
—

 
246

 
—

Issuance of GP units
 
144

 
—

 
—

Issuance of common units
 
—

 
248

 
—

Balances at December 31, 2016
 
680

 
31,237

 
—



Our capital accounts are comprised of approximately 1.3% notional General Partner interest and 98.7% limited partner interests as of December 31, 2016. 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 are not limited and therefore, such participation can result in a deficit to its respective capital account. As such, allocation of losses and distributions for previous transactions between entities under common control have resulted in a deficit to the General Partner's capital account included in our consolidated balance sheets.

Series B Convertible Preferred Units

Effective January 31, 2014, the Partnership issued 1,168,225 Series B Units to its General Partner in exchange for approximately $30.0 million to fund a portion of the Lavaca acquisition described in Note 2. The Series B Units participated in distributions of the Board of Directors of our General Partner along with common units, with such distributions being made in cash distributions or with paid-in-kind Series B Units at the election of the Partnership. The Series B Units were issued in a private placement in reliance upon an exemption from the registration requirements of the Securities Act of 1933 pursuant to Section 4(a)(2) thereof and the safe harbor provided by Rule 506 of Regulation D promulgated thereunder. On February 1, 2016, all outstanding Series B Units were converted on a one-for-one basis into common units.

The Board of Directors of our General Partner elected to pay the Series B distributions using paid-in-kind Series B Units. For the years ended December 31, 2015 and 2014, the Partnership issued 94,923 and 86,461, respectively, of paid-in-kind Series B Units with a fair value of $1.4 million and $2.2 million, respectively.

Equity Offerings

In October 2015, the Partnership and certain of its affiliates entered into an agreement with a group of investment banks under which it may issue up to $100 million of its common units in at the market (“ATM”) offerings. During 2016, the Partnership issued 248,561 common units under this program resulting in net proceeds of $2.9 million after deducting related offering costs of $0.3 million. The net proceeds were used to repay amounts outstanding under the Credit Agreement. At December 31, 2016, $96.8 million remained available under the ATM program.

In September 2015, the Partnership sold 7,500,000 of its common units in a public offering at a price to the public of $11.31 per common unit. The net proceeds of approximately $81.0 million were used to fund a portion of the Delta House investment described in Note 2. In October 2016, the Partnership issued an additional 151,937 common units at a price of $11.31 per unit pursuant to the partial exercise of the underwriters' overallotment option, resulting in net proceeds of approximately $1.7 million.

In October 2014, the Partnership acquired Costar from Energy Spectrum Partners VI LP and Costar Midstream Energy, LLC which was funded, in part, with 6,892,931 of common units issued directly to Energy Spectrum and Costar Midstream Energy LLC. In February 2016, the Partnership reached a settlement of certain indemnification claims with the Costar sellers whereby approximately 1,034,483 common units held in escrow were returned to the Partnership.

In July 2014, the Partnership entered into a common unit purchase agreement with certain institutional investors, which was subsequently amended on August 15, 2014, to provide for the sale of 4,622,352 common units representing limited partner interests in the Partnership in a private placement at a price of $25.8075 per common unit (reflecting an adjustment for the Partnership's second quarter distribution of $0.4625 per unit), for cash consideration of $119.3 million.

In January 2014, the Partnership sold 3,400,000 of its common units in a public offering at a price of $26.75 per common unit. The Partnership used the net proceeds of $86.9 million to fund a portion of the Lavaca Acquisition described in Note 2.

General Partner Units

In order to maintain its ownership percentage, we received proceeds of $2.0 million from our General Partner as consideration for the issuance of 143,900 additional notional general partner units for the year ended December 31, 2016 and proceeds of $1.9 million for the issuance of 143,517 additional notional general partner units for the year ended December 31, 2015.
Distributions

We made the following distributions (in thousands):
 
 
Years Ended December 31,
 
 
2016
 
2015
 
2014
Series A Units
 
 
 
 
 
 
Cash:
 
 
 
 
 
 
Paid
 
$
4,935

 
$
—

 
$
2,658

Accrued
 
2,514

 
—

 
—

Paid-in-kind units
 
11,674

 
16,978

 
13,154

Total
 
19,123

 
16,978

 
15,812

 
 
 
 
 
 
 
Series B Units
 
 
 
 
 
 
Paid-in-kind units
 
—

 
1,373

 
2,220

Total
 
—

 
1,373

 
2,220

 
 
 
 
 
 
 
Series C Units
 
 
 
 
 
 
Cash:
 
 
 
 
 
 
Paid
 
3,089

 
—

 
—

Accrued
 
3,626

 
—

 
—

Paid-in-kind units
 
2,772

 
—

 
—

Total
 
9,487

 
—

 
—

 
 
 
 
 
 
 
Series D Units
 
 
 
 
 
 
Cash:
 

 

 

Paid
 
—

 
—

 
—

Accrued
 
963

 
—

 
—

Paid-in-kind units
 
—

 
—

 
—

Total
 
963

 
—

 
—

 
 
 
 
 
 
 
Limited Partner Units
 
 
 
 
 
 
Cash:
 
 
 
 
 
 
Paid
 
53,500

 
46,597

 
22,656

Accrued
 
—

 
—

 
—

Total
 
53,500

 
46,597

 
22,656

 
 
 
 
 
 
 
General Partner Units
 
 
 
 
 
 
Cash:
 
 
 
 
 
 
Paid
 
2,551

 
6,789

 
2,695

Accrued
 
—

 
—

 
—

Additional Blackwater acquisition consideration
 
5,000

 
—

 
—

Total
 
7,551

 
6,789

 
2,695

 
 
 
 
 
 
 
Summary
 
 
 
 
 
 
Cash
 
 
 
 
 
 
Paid
 
64,075

 
53,386

 
28,009

Accrued
 
7,103

 
—

 
—

Paid-in-kind units
 
14,446

 
18,351

 
15,374

Additional Blackwater acquisition consideration
 
5,000

 
—

 
—

Total
 
$
90,624

 
$
71,737

 
$
43,383


On January 26, 2017, 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 was paid on February 13, 2017, to unitholders of record as of the close of business on February 6, 2017. Accrued cash distributions on our preferred convertible units were also paid in February 2017.

The fair value of the paid-in-kind 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 measurements as defined by ASC 820. Under the income approach, the fair value estimates for all years presented were based on i) present value of estimated future contracted distributions, ii) option values ranging from $0.02 per unit to $9.68 per unit using a Black-Scholes model, iii) assumed discount rates ranging from 5.57% to 10.0% and iv) assumed growth rates of 1.0%.
Net Income (Loss) per Limited Partner Unit
Net Income (Loss) per Limited Partner Unit
Net Income (Loss) per Limited Partner Unit

Net income (loss) is allocated to the General Partner and the limited partners in accordance with their respective ownership percentages, after giving effect to distributions on our convertible preferred units and General Partner units, including incentive distribution rights. Unvested unit-based compensation awards that contain non-forfeitable rights to distributions (whether paid or unpaid) are classified as participating securities and are included in our computation of basic and diluted net limited partners' net income (loss) per common unit. Basic and diluted limited partners' net income (loss) per common unit is calculated by dividing limited partners' interest in net income (loss) by the weighted average number of outstanding limited partner units during the period.

The calculation of basic and diluted limited partners' net income (loss) per common unit is summarized below (in thousands, except per unit amounts):

 
Years Ended December 31,
 
2016
 
2015
 
2014
Net income (loss) from continuing operations
$
(666
)
 
$
(127,375
)
 
$
(97,195
)
Less: Net income attributable to noncontrolling interests
2,804

 
25

 
214

Net (income) loss from continuing operations attributable to the Partnership
(3,470
)
 
(127,400
)
 
(97,409
)
Less:
 
 
 
 
 
Distributions on Series A Units
19,138

 
16,978

 
14,492

Distributions on Series C Units
9,487

 
—

 
—

Distributions on Series D Units
963

 
—

 
—

Distributions on Series B Units
—

 
1,373

 
2,220

General partner's distributions
2,550

 
6,790

 
2,694

General partner's share in undistributed loss
(1,140
)
 
(2,569
)
 
(1,820
)
Net loss from continuing operations attributable to Limited Partners
(34,468
)
 
(149,972
)
 
(114,995
)
Net loss from discontinued operations attributable to Limited Partners
—

 
(80
)
 
(603
)
Net loss attributable to Limited Partners
$
(34,468
)
 
$
(150,052
)
 
$
(115,598
)
 
 
 
 
 
 
Weighted average number of common units used in computation of Limited Partners' net loss per common unit - basic and diluted
31,043

 
24,983

 
13,472

 
 
 
 
 
 
Limited Partners' net loss from continuing operations per unit (basic and diluted)
$
(1.11
)
 
$
(6.00
)
 
$
(8.54
)
Limited Partners' net loss from discontinued operations per unit (basic and diluted)
—

 
—

 
(0.04
)
Limited Partners' net loss per common unit - basic and diluted (1)
$
(1.11
)
 
$
(6.00
)
 
$
(8.58
)
 
_______________________
(1) Potential common unit equivalents are antidilutive for all periods and, as a result, have been excluded from the determination of diluted limited partners' net income (loss) per common unit.
Long-Term Incentive Plan
Long-Term Incentive Plan
Long-Term Incentive Plan

Our General Partner manages our operations and activities and employs the personnel who provide support to our operations. On November 19, 2015, the Board of Directors of our General Partner approved the Third Amended and Restated Long-Term Incentive Plan to, among other things, increase the number of common units authorized for issuance by 6,000,000 common units. On February 11, 2016, the unitholders approved the Third Amended and Restated Long-Term Incentive Plan (as amended and as currently in effect as of the date hereof, the "LTIP"). At December 31, 2016, 2015 and 2014, there were 5,017,528, 15,484 and 688,976 common units, respectively, available for future grant under the LTIP.

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

Phantom Unit Awards. Ownership in the phantom unit awards is subject to forfeiture until the vesting date. The LTIP is administered by the Compensation Committee of the Board of Directors of our General Partner, which at its discretion, may elect to settle such vested phantom units with a number of common units equivalent to the fair market value at the date of vesting in lieu of cash. Although our General Partner has the option to settle vested phantom units in cash, our General Partner has not historically settled these awards in cash. 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.

In December 2015, the Board of Directors of our General Partner approved a grant of 200,000 phantom units under the LTIP which contain DERs to the extent the Partnership’s Series A Preferred Unitholders receive distributions in cash. These units will vest on the three year anniversary of the date of grant, subject to acceleration in certain circumstances.

The following table summarizes activity in our phantom unit-based awards for the years ended December 31, 2016, 2015 and 2014:
 
 
Units
 
Weighted-Average Grant Date Fair Value Per Unit
 
Aggregate Intrinsic Value (1) (In thousands)
Outstanding shares at December 2013
 
75,529

 
$
17.62

 
$
2,045

Granted
 
188,946

 
20.80

 
 
Forfeited
 
(12,009
)
 
(18.28
)
 
 
Vested
 
(51,334
)
 
(20.89
)
 
 
Outstanding shares at December 2014
 
201,132

 
$
19.85

 
$
3,964

Granted
 
546,329

 
12.25

 
 
Forfeited
 
(31,298
)
 
(15.62
)
 
 
Vested
 
(146,404
)
 
(18.47
)
 
 
Outstanding shares at December 2015
 
569,759

 
$
13.15

 
$
4,609

Granted
 
1,374,226

 
2.14

 
 
Forfeited
 
(411,794
)
 
(2.60
)
 
 
Vested
 
(286,348
)
 
(12.18
)
 
 
Outstanding shares at December 2016
 
1,245,843

 
$
4.72

 
$
22,674



(1) The intrinsic value of phantom units was calculated by multiplying the closing market price of our underlying stock on December 31, 2016, 2015 and 2014 by the number of phantom units.

The fair value of our phantom units, which are subject to equity classification, is based on the fair value of our common units at the grant date. Compensation expense related to these awards for the years ended December 31, 2016, 2015, and 2014 was $3.6 million, $3.8 million and $1.5 million, respectively, and is included in Corporate expenses and Direct operating expenses in our consolidated statements of operations and the equity compensation expense in our consolidated statements of changes in partners' capital and noncontrolling interests.

The total fair value of units at the time of vesting was $2.4 million, $2.6 million, and $1.4 million for the years ended December 31, 2016, 2015, and 2014, respectively.

Equity compensation expense related to unvested phantom awards not yet recognized at December 31, 2016 was $4.2 million and the weighted average period over which this expense is expected to be recognized as of December 31, 2016 is approximately 2.2 years.

Performance and Service Condition Awards. In November 2015, the Board of Directors of our General Partner modified awards that introduced certain performance and service conditions that were probable of being achieved, amounting to $2.0 million payable to certain employees. During the third quarter of 2016, we settled $1.0 million of the obligation in cash while in the fourth quarter of 2016, forfeitures reduced the total payable amount from $2.0 million to $1.5 million. These awards are accounted for as liability classified awards. Compensation expense related to these awards for the years ended December 31, 2016 and 2015 was $0.9 million and $0.5 million, respectively, and is included in Direct operating expenses in our consolidated statements of operations. Compensation expense related to unvested awards not yet recognized at December 31, 2016 was $0.1 million.

Option to Purchase Common Units. In December 2015, the Board of Directors of our General Partner approved the grant of an option to purchase 200,000 common units at an exercise price per unit equal to $7.50. The grant will vest on January 1, 2019, subject to acceleration in certain circumstances, and will expire on March 15th of the calendar year following the calendar year in which it vests.

In August 2016, the Board of Directors of our General Partner approved the grant of an option to purchase 30,000 common units at an exercise price per unit equal to $12.00. The grant will vest on July 31, 2019, subject to continued employment, and will expire on July 31st of the calendar year following the calendar year in which it vests.

In September 2016, the Board of Directors of our General Partner approved the grant of an option to purchase 45,000 common units of the Partnership at an exercise price per unit equal to $13.88. The options will vest at a rate of 25% per year. The options will expire on September 30th of the calendar year following the calendar year in which it vests.

The Black-Scholes pricing model was used to determine the fair value of our options grants using the following assumptions:
 
Years Ended December 31,
 
2016
 
2015
Weighted average common unit price volatility
61.1
%
 
47.0
%
Expected distribution yield
12.6
%
 
26.3
%
Weighted average expected term (in years)
4.10

 
3.5

Weighted average risk-free rate
1.1
%
 
1.3
%


The weighted average unit price volatility was based upon the historical volatility of our common units. The expected distribution yield was based on an annualized distribution divided by the closing unit price on the date of grant. The risk-free rate was based on the U.S. Treasury yield curve in effect on the date of grant.

Compensation expense related to these awards was not material for the years ended December 31, 2016 and 2015. Compensation cost related to unvested awards not yet recognized at December 31, 2016 was $0.2 million.

The following table summarizes our option activity for the years ended December 31, 2016 and 2015:
 
 
Units
 
Weighted-Average Exercise Price
 
Weighted-Average Grant Date Fair Value per Unit
 
Aggregate Intrinsic Value (1) (In thousands)
 
Weighted Average Remaining Contractual Life (Years)
Outstanding at December 31, 2014
 
—

 
$
—

 
$
—

 
$
—

 
—

Granted
 
200,000

 
7.50

 
0.33

 
—

 
—

Vested
 
—

 
—

 
 
 
—

 
—

Forfeited
 
—

 
—

 
 
 
—

 
—

Outstanding at December 31, 2015
 
200,000

 
$
7.50

 
$
0.33

 
$
118

 
4.2

Granted
 
75,000

 
13.13

 
2.65

 
—

 
—

Vested
 
—

 
—

 
 
 
—

 
—

Forfeited
 
—

 
—

 
 
 
—

 
—

Outstanding at December 31, 2016
 
275,000

 
$
9.03

 
$
0.96

 
$
2,522

 
5.0


(1) The intrinsic value of the stock option is the amount by which the current market value of the underlying stock exceeds the exercise price of the option.
Income Taxes
Income Taxes
 Income Taxes

With the exception of certain subsidiaries in our Terminals Segment, the Partnership is not subject to U.S. federal or state income taxes as such income taxes are generally borne by our unitholders through the allocation of our taxable income (loss) to them. The State of Texas does impose a franchise tax that is assessed on the portion of our taxable margin which is apportioned to Texas.

Income tax (expense) benefit for the years ended December 31, 2016, 2015 and 2014 is as follows:
 
Years Ended December 31,
 
2016
 
2015
 
2014
Current income tax expense
$
—

 
$
—

 
$
(10
)
Deferred income tax expense
(2,057
)
 
(1,134
)
 
(547
)
 
 
 
 
 
 
Effective income tax rate
147.9
%
 
0.9
%
 
0.6
%


A reconciliation of our expected income tax (expense) benefit calculated at the U.S. federal statutory rate of 34% to our actual tax (expense) for the years ended December 31, 2016, 2015 and 2014 is as follows:

 
Years Ended December 31,
 
2016
 
2015
 
2014
Net income (loss) before income tax expense
$
1,391

 
$
(126,241
)
 
$
(96,638
)
US Federal statutory tax rate
34
%
 
34
%
 
34
%
Federal income tax (expense) benefit at statutory rate
(473
)
 
42,922

 
32,857

Reconciling items:
 
 
 
 
 
    Partnership loss not subject to income tax
(1,300
)
 
(43,812
)
 
(33,216
)
    State and local tax expense
(279
)
 
(103
)
 
(159
)
    Other
(5
)
 
(141
)
 
(39
)
Income tax expense
$
(2,057
)
 
$
(1,134
)
 
$
(557
)

The Partnership’s deferred tax assets and liabilities as of December 31, 2016 and 2015 are summarized below:
 
December 31,
 
2016
 
2015
Deferred tax assets:
 
 
 
    Net operating loss carryforwards
$
6,300

 
$
7,570

    Other
577

 
493

    Total deferred tax assets
6,877

 
8,063

Deferred tax liabilities:
 
 
 
    Property, plant and equipment
(14,735
)
 
(13,889
)
Deferred income tax liability, net
$
(7,858
)
 
$
(5,826
)


As of December 31, 2016, certain subsidiaries in our Terminals Segment had net operating loss carryforwards for federal income tax purposes of approximately $16.1 million which begin to expire in 2028.

We recognize the tax benefits from uncertain tax positions if it is more likely than not that the position will be sustained on examination by the taxing authorities. As of December 31, 2016, we have not recognized tax benefits relating to uncertain tax positions.

The preparation of our income tax returns requires the use of management's estimates and interpretations which may be subjected to review by the respective taxing authorities and may result in an assessment of additional taxes, penalties and interest. Tax years subsequent to 2010 remain subject to examination by federal and state taxing authorities.
Commitments and Contingencies
Commitments and Contingencies
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 certainly, our management believes that the resolution of any of our pending proceeds 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.

Regulatory matters

On October 8, 2014, American Midstream (Midla), LLC ("Midla") reached an agreement in principle with its customers regarding the interstate pipeline that traverses Louisiana and Mississippi in order to provide continued service to its customers while addressing safety concerns with the existing pipeline.

On April 16, 2015, FERC approved the stipulation and agreement (the “Midla Agreement”) relating to the October 8, 2014 regulatory matter and allowing Midla to retire the existing 1920’s pipeline and replace it with the Midla-Natchez Line to serve existing residential, commercial, and industrial customers. Under the Midla Agreement, customers not served by the new Midla-Natchez Line will be connected to other interstate or intrastate pipelines, other gas distribution systems, or offered conversion to propane service. On June 29, 2015, the Partnership filed with FERC for authorization to construct the Midla-Natchez pipeline, which was approved on December 17, 2015. Construction commenced in the second quarter of 2016 with service expected to begin in the first six months of 2017. Under the Midla Agreement, Midla plans to execute long-term agreements seeking to recover its investment in the Midla-Natchez Line.

Exit and disposal costs

On March 9, 2016, management committed to a corporate headquarters relocation plan and communicated that plan to the impacted employees. The plan included relocation assistance or one-time termination benefits for employees who rendered service until their respective termination dates. Charges associated with these termination benefits, which totaled $9.1 million were recognized ratably over the requisite service period and are presented in Corporate expenses in our consolidated statement of operations. At December 31, 2016, payments under the plan had been completed.

Commitments and contractual obligations

The Partnership had the following non-cancelable contractual commitments as of December 31, 2016 (in thousands):
 
 
Credit Agreement
 
3.77% Senior Notes
 
8.50% Senior Notes
 
Asset Retirement Obligation
 
     Other (1)
 
Total
2017
 
$
—

 
$
1,677

 
$
—

 
$
6,499

 
$
4,144

 
$
12,320

2018
 
—

 
806

 
—

 
—

 
2,411

 
3,217

2019
 
711,250

 
2,233

 
—

 
—

 
2,547

 
716,030

2020
 
—

 
2,299

 
—

 
—

 
2,081

 
4,380

2021
 
—

 
4,430

 
300,000

 
—

 
1,892

 
306,322

Thereafter
 
—

 
48,555

 
—

 
44,363

 
13,435

 
106,353

 
 
$
711,250

 
$
60,000

 
$
300,000

 
$
50,862

 
$
26,510

 
$
1,148,622


(1) Minimum payments have not been reduced by minimum sublease rentals of $0.2 million.

For the years ended December 31, 2016, 2015 and 2014, total rental expenses were $13.4 million, $12.0 million, and $5.8 million, respectively.
Related-Party Transactions
Related-Party Transactions
Related-Party Transactions

As described in Note 3, in December 2013 the Partnership acquired Blackwater Midstream Holdings, LLC (“Blackwater”) from affiliates of ArcLight. The acquisition agreement included a provision whereby an ArcLight affiliate would be entitled to an additional $5.0 million of merger consideration based on Blackwater meeting certain operating targets. During the third quarter of 2016, the Partnership determined that it was probable the operating targets would be met in early 2017 and recorded a $5.0 million accrued distribution to the ArcLight affiliate which is included in Accrued expenses and other current liabilities in the accompanying consolidated balance sheet at December 31, 2016.

Employees of our General Partner are assigned to work for the Partnership or other affiliates of our General Partner. Where directly attributable, all compensation and related expenses for these employees are charged directly by our General Partner to American Midstream, LLC, which, in turn, charges the appropriate subsidiary or affiliate. Our General Partner does not record any profit or margin on the expenses charged to us. During the years ended December 31, 2016, 2015, and 2014, related expenses of $41.6 million, $28.7 million, and $22.6 million respectively,which were charged to the Partnership by our General Partner.

During the second quarter of 2014, the Partnership and an affiliate of its General Partner entered into a Management Service Fee arrangement under which the affiliate pays a monthly fee to reimburse the Partnership for administrative expenses incurred on the affiliate’s behalf. For the years ended December 31, 2016, 2015, and 2014, the Partnership recognized related management fee income of $0.8 million, $1.4 million and $0.9 million respectively, under this agreement and recorded such amounts as a reduction of Corporate expenses in the consolidated statements of operations.

As of December 31, 2016, and 2015, the Partnership had $3.9 million and $3.8 million, respectively, due to our General Partner, which has been recorded in Accrued expenses and other current liabilities and relates primarily to compensation. This payable is generally settled on a quarterly basis related to the foregoing transactions.

On November 1, 2016, the Partnership became operator of the Destin and Okeanos pipelines and entered into an operating and administrative management agreements under which the affiliates pay a monthly fee for general and administrative services provided by the Partnership. In addition, the affiliates reimburses the Partnership for certain transition related expenses. For the year ended December 31, 2016, the Partnership recognized $0.4 million of management fee income and $1.0 million as reimbursement of transition related expenses.

American Panther, LLC ("American Panther") is a 60%-owned subsidiary of the Partnership which is consolidated for financial reporting purposes. Pursuant to a related agreement which began in the second quarter of 2016, an affiliate of the non-controlling interest holder provides services to American Panther in exchange for related fees, which in 2016 totaled $0.8 million of Direct operating expenses and $0.4 million of Corporate expenses in the consolidated statement of operations.  

The Partnership enters into purchases and sales of natural gas and crude oil with a company whose chief financial officer is the brother of one of our executive officers. During the years ended December 31, 2016, 2015, and 2014, the Partnership recognized revenue of $3.6 million, $6.2 million and $10.1 million, respectively, while purchases from the company totaled $4.3 million, $5.9 million, and $3.7 million, respectively.
Supplemental Cash Flow Information
Supplemental Cash Flow Information
Supplemental Cash Flow Information

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

 
Years Ended December 31,
 
2016
 
2015
 
2014
Supplemental cash flow information
 
 
 
 
 
Interest payments, net of capitalized interest
$
16,922

 
$
12,013

 
$
6,726

Supplemental non-cash information
 
 
 
 
 
Increase (decrease) in accrued property, plant and equipment purchases
$
7,353

 
$
(25,637
)
 
$
31,390

Issuance of Series C Units and Warrant in connection with the Emerald Transactions
120,000

 
—

 
—

Accrued cash distributions on convertible preferred units
7,103

 
—

 
—

Paid-in-kind distributions on convertible preferred units
14,446

 
16,978

 
13,154

Paid-in-kind distributions on Series B Units
—

 
1,373

 
2,220

Cancellation of escrow units
6,817

 
—

 
—

Additional Blackwater acquisition consideration
5,000

 
—

 
—

Common unit issuance related to Costar Acquisition
—

 
—

 
147,296

Reporting Segments
Reporting Segments
Reportable Segments

Our operations are located in the United States and are organized into the following reportable segments:

Gathering and Processing

Our Gathering and Processing segment provides "wellhead-to-market" services to producers of natural gas and crude oil, which include transporting raw natural gas and crude oil 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.

In 2016, the Gathering and Processing segment had one customer who accounted for 11% of its segment revenue. In 2015, the segment had two customers who each accounted for 12% its segment revenue. In 2014, the segment had two customers who accounted for 33% and 12%, respectively, of its segment revenue.

Transmission

Our Transmission segment transports and delivers natural gas from producing wells, receipt points or pipeline interconnects for shippers and other customers, including local distribution companies ("LDCs"), utilities and industrial, commercial and power generation customers.

In 2016, the Transmission segment had two customers who accounted for 14% and 13%, respectively, of its segment revenue. In 2015, the segment had two customers who accounted for 19% and 16%, respectively, of its segment revenue. In 2014, the segment had two customers who accounted for 43% and 16%, respectively, of its segment revenue.


Terminals

Our Terminals segment provides above-ground storage services at our marine terminals that support various commercial customers, including commodity brokers, refiners and chemical manufacturers to store a range of products, including petroleum products, distillates, chemicals and agricultural products.

In 2016, the Terminals segment had three customers who accounted for 23%, 17%, and 12%, respectively, of its segment revenue. In 2015, the segment had four customers who accounted for 21%, 13%, 13%, and 13%, respectively, of its segment revenue. In 2014, the segment had four customers who accounted for 20%, 19%, 15%, and 11%, respectively, of its segment revenue.

These segments are monitored separately by management for performance and are consistent with the Partnership's internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. Gross margin is a performance measure utilized by management to monitor the results of each segment.
 
The following tables set forth our segment financial information for the periods indicated (in thousands):

 
December 31, 2016
 
Gathering
and
Processing
 
Transmission
 
Terminals
 
Total
Sales of natural gas, NGLs and condensate revenue
$
153,174

 
$
7,775

 
$
1

 
$
160,950

Services revenue
10,531

 
39,196

 
22,845

 
72,572

Loss on commodity derivatives, net
(836
)
 
(4
)
 
—

 
(840
)
Total revenue
162,869

 
46,967

 
22,846

 
232,682

Operating expenses:
 
 
 
 
 
 
 
Purchases of natural gas, NGL's and condensate
87,026

 
5,530

 
—

 
92,556

Direct operating expenses
41,345

 
11,920

 
8,596

 
61,861

Corporate expenses
 
 
 
 
 
 
54,223

Depreciation, amortization and accretion expense
 
 
 
 
 
 
46,022

Loss on sale of assets, net
 
 
 
 
 
 
591

Loss on impairment of property, plant and equipment
 
 
 
 
 
 
697

Interest expense
 
 
 
 
 
 
15,499

Earnings in unconsolidated affiliates
 
 
 
 
 
 
(40,158
)
Income tax expense
 
 
 
 
 
 
2,057

Net income
 
 
 
 
 
 
(666
)
Less: Net income attributable to noncontrolling interests
 
 
 
 
 
 
2,804

Net loss attributable to the Partnership
 
 
 
 
 
 
$
(3,470
)
 
 
 
 
 
 
 
 
Segment gross margin (1)
$
74,582

 
$
41,233

 
$
14,250

 
 
_________________________
(1) Segment gross margin for our Gathering and Processing segment consists of total revenue less construction and operating management agreement income of $1.3 million and purchases of natural gas, NGLs and condensate.

Segment gross margin for our Transmission segment consists of total revenue less construction and operating management agreement income of less than $0.2 million and purchases of natural gas, NGLs and condensate.

Segment gross margin for our Terminals segment consists of total revenue less direct operating expenses.

 
Year Ended December 31, 2015
 
Gathering
and
Processing
 
Transmission
 
Terminals
 
Total
Sales of natural gas, NGLs and condensate revenue
$
170,197

 
$
9,600

 
$
21

 
$
179,818

Services revenue
3,400

 
34,082

 
17,734

 
55,216

Gain on commodity derivatives, net
1,324

 
—

 
—

 
1,324

Total revenue
174,921

 
43,682

 
17,755

 
236,358

Operating expenses:
 
 
 
 
 
 
 
Purchases of natural gas, NGL's and condensate
97,580

 
8,303

 
—

 
105,883

Direct operating expenses
39,249

 
13,768

 
7,720

 
60,737

Corporate expenses
 
 
 
 
 
 
29,818

Depreciation, amortization and accretion expense
 
 
 
 
 
 
38,014

Loss on sale of assets, net
 
 
 
 
 
 
3,011

Loss on impairment of goodwill
 
 
 
 
 
 
118,592

Interest expense
 
 
 
 
 
 
14,745

Earnings in unconsolidated affiliates
 
 
 
 
 
 
(8,201
)
Income tax expense
 
 
 
 
 
 
1,134

Loss from discontinued operations, net of tax
 
 
 
 
 
 
80

Net Loss
 
 
 
 
 
 
(127,455
)
Less: Net income attributable to noncontrolling interests
 
 
 
 
 
 
25

Net loss attributable to the Partnership
 
 
 
 
 
 
$
(127,480
)
 
 
 
 
 
 
 
 
Segment gross margin (1)
$
76,865

 
$
35,301

 
$
10,035

 
 
____________________
(1) Segment gross margin for our Gathering and Processing segment consists of total revenue less unrealized gain on commodity derivatives of $0.3 million, construction and operating management agreement income of $0.8 million and purchases of natural gas, NGLs and condensate.

Segment gross margin for our Transmission segment consists of total revenue less construction and operating management agreement income of less than $0.1 million and purchases of natural gas, NGLs and condensate.

Segment gross margin for our Terminals segment consists of total revenue less direct operating expenses.



 
Year Ended December 31, 2014
 
Gathering
and
Processing
 
Transmission
 
Terminals (b)
 
Total
Sales of natural gas, NGLs and condensate revenue
$
202,035

 
$
52,881

 
$
109

 
$
255,025

Services revenue
1,581

 
35,308

 
15,395

 
52,284

Gain on commodity derivatives, net
1,091

 
—

 
—

 
1,091

Total revenue
204,707

 
88,189

 
15,504

 
308,400

Operating expenses:
 
 
 
 
 
 
 
Purchases of natural gas, NGL's and condensate
152,690

 
45,262

 
—

 
197,952

Direct operating expenses
23,806

 
15,619

 
6,494

 
45,919

Corporate expenses
 
 
 
 
 
 
24,422

Depreciation, amortization and accretion expense
 
 
 
 
 
 
28,832

Loss on impairment of property, plant and equipment
 
 
 
 
 
 
99,892

Loss on sale of assets, net
 
 
 
 
 
 
122

Other expense
 
 
 
 
 
 
670

Interest expense
 
 
 
 
 
 
7,577

Earnings in unconsolidated affiliates
 
 
 
 
 
 
(348
)
Income tax expense
 
 
 
 
 
 
557

Loss from discontinued operations, net of tax
 
 
 
 
 
 
611

Net Loss
 
 
 
 
 
 
(97,806
)
Less: Net income attributable to noncontrolling interests
 
 
 
 
 
 
214

Net loss attributable to the Partnership
 
 
 
 
 
 
$
(98,020
)
 
 
 
 
 
 
 
 
Segment gross margin (1)
$
50,817

 
$
42,828

 
$
9,010

 
 
____________________
(1) Segment gross margin for our Gathering and Processing segment consists of total revenue less unrealized gain on commodity derivatives of $0.4 million, construction and operating management agreement income of $0.8 million, and purchases of natural gas, NGLs and condensate.

Segment gross margin for our Transmission segment consists of total revenue less construction and operating management agreement income of less than $0.1 million and purchases of natural gas, NGLs and condensate.

Segment gross margin for our Terminals segment consists of total revenue less direct operating expenses.

A reconciliation of total assets by segment to the amounts included in the consolidated balance sheets is as follows:

 
December 31,
 
2016
 
2015
Segment assets:
 
 
 
Gathering and Processing
$
537,658

 
$
573,408

Transmission
142,404

 
133,870

Terminals
45,226

 
84,449

Other (1)
838,207

 
100,153

Total assets
$
1,563,495

 
$
891,880

_______________________
(1) Other assets not allocable to segments consist of investment in unconsolidated affiliates, restricted cash and other assets.
Quarterly Financial Data (Unaudited)
Quarterly Financial Data (Unaudited)
Quarterly Financial Data (Unaudited)

Summarized unaudited quarterly financial data for 2016 and 2015 are as follows (in thousands, except per unit amounts):
 
 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter (2)
 
 
 
 
 
 
 
 
Total revenues
$
46,020

 
$
55,382

 
$
63,818

 
$
67,462

Gross margin (1)(3)
27,291

 
31,809

 
34,312

 
36,653

Operating loss
(5,116
)
 
(6,191
)
 
(2,717
)
 
(9,244
)
Net income (loss)
(3,964
)
 
(3,591
)
 
2,679

 
4,210

Net income (loss) attributable to the Partnership
(3,951
)
 
(4,583
)
 
1,483

 
3,581

General Partner's Interest in net income (loss)
(52
)
 
(61
)
 
19

 
46

Limited Partners' Interest in net income (loss)
$
(3,899
)
 
$
(4,522
)
 
$
1,464

 
$
3,535

 
 
 
 
 
 
 
 
Limited Partners' income (loss) per unit:
 
 
 
 
 
 
 
Loss from continuing operations
$
(0.33
)
 
$
(0.36
)
 
$
(0.22
)
 
$
(0.20
)
Net income (loss)
$
(0.33
)
 
$
(0.36
)
 
$
(0.22
)
 
$
(0.20
)
Year Ended December 31, 2015
 
 
 
 
 
 
 
Total revenues
$
64,609

 
$
67,509

 
$
55,641

 
$
48,599

Gross margin (1) (3)
33,776

 
31,917

 
28,854

 
27,654

Operating income (loss)
3,434

 
1,867

 
(1,523
)
 
(123,475
)
Net income (loss) from continuing operations
835

 
(2,002
)
 
(4,574
)
 
(121,634
)
Income (loss) from discontinued operations, net of tax
5

 
(31
)
 
(53
)
 
(1
)
Net income (loss) attributable to noncontrolling interest
14

 
32

 
34

 
(55
)
Net income (loss) attributable to the Partnership
826

 
(2,065
)
 
(4,661
)
 
(121,580
)
General Partner's Interest in net income (loss)
10

 
(25
)
 
(60
)
 
(1,570
)
Limited Partners' Interest in net income (loss)
$
816

 
$
(2,040
)
 
$
(4,601
)
 
$
(120,010
)
 
 
 
 
 
 
 
 
Limited Partners' income (loss) per unit:
 
 
 
 
 
 
 
Loss from continuing operations
$
(0.19
)
 
$
(0.35
)
 
$
(0.48
)
 
$
(4.16
)
Net loss
$
(0.19
)
 
$
(0.35
)
 
$
(0.48
)
 
$
(4.16
)
 
(1)
For a definition of gross margin and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP and a discussion of how we use gross margin to evaluate our operating performance, please read Item 7. "Management's Discussion and Analysis, How We Evaluate Our Operations."
(2)
In the fourth quarter of 2015, we recognized a goodwill impairment charge of $118.6 million.
(3)
Amounts are different than previously reported due to reclassifying a portion of equity compensation expense into Direct operating expense for the Terminals segment.
Subsequent Event (Notes)
Subsequent Event
Subsequent Event

Distribution

On January 26, 2017, we announced that the Board of Directors of our General Partner declared a quarterly cash distribution of $0.4125 per common unit for the fourth quarter ended December 31, 2016, or $1.65 per common unit on an annualized basis. The cash distribution was paid on February 13, 2017, to unitholders of record as of the close of business on February 6, 2017.

Dakota Access Connection Agreement

On March 1, 2017, the Partnership announced it has entered a connection agreement with Dakota Access Pipeline (“DAPL”), the 1,172-mile pipeline that extends from the Partnership’s Bakken formation production area in North Dakota to Patoka, Illinois. The new DAPL interconnect will tie into the Partnership’s Bakken crude oil gathering system which consists of interstate pipelines with capacity to transport up to approximately 40,000 barrels per day of crude oil.

JP Energy Partners

On March 8, 2017, the Partnership completed the acquisition of JPE, an entity controlled by ArcLight affiliates, in a unit-for-unit merger. In connection with the transaction, each JPE common or subordinated unit held by investors not affiliated with ArcLight was converted into the right to receive 0.5775 of a Partnership common unit, and each JPE common or subordinated unit held by ArcLight affiliates was converted into the right to receive 0.5225 of a Partnership common unit. The Partnership issued a total of 20.2 million of its common units to complete the acquisition, including 9.8 million common units to ArcLight affiliates. In connection with the completion of the JPE Merger, the Partnership entered into a supplemental indenture pursuant to which the JPE Entities jointly and severally, fully and unconditionally, guarantee the 8.50% Senior Notes.

As both the Partnership and JPE were controlled by ArcLight affiliates, the acquisition represents a transaction among entities under common control and will be accounted for as a common control transaction. Although the Partnership is the legal acquirer, JPE is considered to be the acquirer for accounting purposes as ArcLight obtained control of JPE prior to obtaining control of the Partnership on April 15, 2013. As a result, JPE will record the acquisition of the Partnership at ArcLight’s historical cost basis. The Partnership will file recast historical cost financial statements for the combined entity in May 2017.

Upon the closing of the JPE Merger and the satisfaction of other related conditions the restricted cash proceeds from the 8.50% Senior Notes was released from escrow on March 8, 2017. The Partnership used the net proceeds to repay and terminate JPE's revolving credit facility and to reduce borrowings under the Partnership’s Credit Agreement.

JPE owns, operates and develops a diversified portfolio of midstream energy assets with three business segments (i) crude oil pipelines and storage, (ii) refined products terminals and storage and (iii) NGL distribution and sales, which together provide midstream infrastructure solutions for the growing supply of crude oil, refined products and NGLs, in the United States.

Second Amended and Restated Credit Agreement

On March 8, 2017 the Partnership entered into the Second Amended and Restated Credit Agreement, which increased our borrowing capacity from $750 million to $900.0 million and provided for an accordion feature that will permit, subject to the customary conditions, the borrowing capacity under the Credit Agreement to be increased to a maximum of $1.1 billion.
Organization and Basis of Presentation (Policies)
Nature of business 
Nature of business

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 three reportable segments, (i) gathering and processing, (ii) transmission and (iii) terminals, 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.

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 located in key demand markets in Alabama, Louisiana, Mississippi and Tennessee and in the Port of New Orleans in Louisiana and the Port of Brunswick in Georgia.

We own or have ownership interests in more than 3,800 miles of onshore and offshore natural gas, crude oil, NGL and saltwater pipelines across 15 gathering systems, six interstate pipelines and eight intrastate pipelines; eight natural gas processing plants; four fractionation facilities; an offshore semisubmersible floating production system with nameplate processing capacity of 80 MMBbl/d of crude oil and 200 MMcf/d of natural gas; and three marine terminal sites with approximately 2.4 MMBbls of above-ground aggregate storage capacity for petroleum products, distillates, chemicals and agricultural products. A portion of our cash flow is derived from our investments in unconsolidated affiliates.

Basis of presentation 
Basis of presentation

We have prepared the accompanying consolidated financial statements in accordance with accounting principles generally accepted in the United States of America ("GAAP").

The results of operations for acquisitions accounted for as business combinations have been included in the consolidated financial statements since their respective acquisition dates. See Note 2 - Acquisitions for further information.

Transactions between entities under common control 
Transactions between entities under common control
 
We may enter into transactions with ArcLight affiliates whereby we receive midstream assets or other businesses in exchange for cash or Partnership equity. We account for the net assets acquired at the affiliate's historical cost basis as the transactions are between entities under common control. 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 affiliate obtained control of the assets acquired.
Consolidation policy 
Consolidation policy

The accompanying consolidated financial statements include accounts of American Midstream Partners, LP, and its controlled subsidiaries. All significant inter-company accounts and transactions have been eliminated in the preparation of the accompanying consolidated financial statements.
Use of estimates 
Use of estimates

When preparing consolidated financial statements in conformity with GAAP, management must make estimates and assumptions based on information available at the time. These estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosures of contingent assets and liabilities as of the date of the financial statements. Estimates and assumptions are based on information available at the time such estimates and assumptions are made. Adjustments made with respect to the use of these estimates and assumptions often relate to information not previously available. Uncertainties with respect to such estimates and assumptions are inherent in the preparation of financial statements. Estimates and assumptions are used in, among other things, i) estimating unbilled revenues, product purchases and operating and general and administrative costs, ii) developing fair value assumptions, including estimates of future cash flows and discount rates, iii) analyzing long-lived assets, goodwill and intangible assets for possible impairment, iv) estimating the useful lives of assets and v) determining amounts to accrue for contingencies, guarantees and indemnifications. Actual results, therefore, could differ materially from estimated amounts.
Cash and cash equivalents 
Cash, cash equivalents and restricted cash

We consider all highly liquid investments with an original maturity of three months or less at the date of purchase to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value because of the short term to maturity of these investments.

From time to time we are required to maintain cash in separate accounts the use of which is restricted by the terms of our debt agreements or asset retirement obligations. Such amounts are included in Restricted cash in our consolidated balance sheets.

Allowance for doubtful accounts 
Allowance for doubtful accounts
We establish provisions for losses on accounts receivable when we determine that we will not collect all or part of an outstanding balance. Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method.
Derivative financial instruments 
Derivative financial instruments

Our net income (loss) and cash flows are subject to volatility stemming from changes in interest rates on our variable rate debt, commodity prices and fractionation margins (the relative difference between the price we receive from NGL sales and the corresponding cost of natural gas purchases). In an effort to manage the risks to unitholders, we use a variety of derivative financial instruments including swaps, collars and interest rate caps to create offsetting positions to specific commodity or interest rate exposures. In accordance with the authoritative accounting guidance, we record all derivative financial instruments in our consolidated balance sheets at fair value as current and long-term assets or liabilities on a net basis by counterparty. We record changes in the fair value of our commodity derivatives in Gains (losses) on commodity derivatives, net while changes in the fair value of our interest rate swaps are included in Interest expense in our consolidated statements of operations.

Our hedging program provides a control structure and governance for our hedging activities specific to identified risks and time periods, which are subject to the approval and monitoring by the Board of Directors of our General Partner. We employ derivative financial instruments in connection with an underlying asset, liability or anticipated transaction, and we do not use derivative financial instruments for speculative or trading purposes.

The price assumptions we use to value our derivative financial instruments can affect net income (loss) for each period. We use published market price information where available, or quotations from over-the-counter, market makers to find executable bids and offers. The valuations also reflect the potential impact of conditions, including credit risk of our counterparties. The amounts reported in our consolidated financial statements change quarterly as these valuations are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control.
Fair value measurements 
Fair value measurements

We apply the authoritative accounting provisions for measuring the fair value of our derivative financial instruments and disclosures associated with our outstanding indebtedness. We define fair value as an exit price representing the expected amount we would receive when selling an asset or pay to transfer a liability in an orderly transaction with market participants at the measurement date.

We use various assumptions and methods in estimating the fair values of our financial instruments. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximated their fair value due to the short-term maturity of these instruments.

We employ a hierarchy which prioritizes the inputs we use to measure recurring fair value into three distinct categories based upon whether such inputs are observable in active markets or unobservable. We classify assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our methodology for categorizing assets and liabilities that are measured at fair value pursuant to this hierarchy gives the highest priority to unadjusted quoted prices in active markets and the lowest level to unobservable inputs as outlined below:

•
Level 1 – Inputs represent unadjusted quoted prices in active markets for identical assets or liabilities;
•
Level 2 – Inputs include quoted prices for similar assets and liabilities in active markets that are either directly or indirectly observable; and
•
Level 3 – Inputs are unobservable and considered significant to fair value measurement.

We utilize a mid-market pricing convention, or the "market approach," for valuation for assigning fair value to our derivative assets and liabilities. Our credit exposure for over-the-counter derivatives is directly with our counterparty and continues until the maturity or termination of the contracts. As appropriate, valuations are adjusted for various factors such as credit and liquidity considerations.
Property, plant and equipment 
Property, plant and equipment

We capitalize expenditures related to property, plant and equipment that have a useful life greater than one year. We also capitalize expenditures that improve or extend the useful life of an asset. Maintenance and repair costs, including any planned major maintenance activities, are expensed as incurred.

We record property, plant, and equipment at cost and recognize depreciation expense on a straight-line basis over the related estimated useful lives of the assets which range from 3 to 40 years. Our determination of the useful lives of property, plant and equipment requires us to make various assumptions, including the supply of and demand for hydrocarbons in the markets served by our assets, normal wear and tear of the facilities, and the extent and frequency of maintenance programs. We record depreciation using the group method of depreciation, which is commonly used by pipelines, utilities and similar assets.

We classify long-lived assets to be disposed of through sales that meet specific criteria as held for sale. We cease depreciating those assets effective on the date the asset is classified as held for sale. We record those assets at the lower of their carrying value or the estimated fair value less the cost to sell. Until the assets are disposed of, our estimate of fair value is re-determined when related events or circumstances change.
Impairment of long lived Assets 
Impairment of long lived Assets

We evaluate the recoverability of our property, plant and equipment and intangible assets with definite lives when events or circumstances indicate we may not recover the carrying amount of the assets. We continually monitor our operations, the market, and business environment to identify indicators that could suggest an asset or asset group may not be recoverable. We evaluate the asset or asset group for recoverability by estimating the undiscounted future cash flows expected to be derived from their use and disposition. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost, contract renewals, and other factors. An asset or asset group is considered impaired when the estimated undiscounted cash flows are less than the carrying amount. In that event, an impairment loss is recognized to the extent that the carrying amount of the asset or asset group exceeds its fair value as determined by quoted market prices in active markets or present value techniques. The determination of fair values using present value techniques requires us to make projections and assumptions regarding future cash flows and weighted average cost of capital. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of the recoverability of our property, plant and equipment and the recognition of an impairment loss in our consolidated statements of operations.
Goodwill and intangible assets 
Goodwill and intangible assets

We record goodwill for the excess of the cost of an acquisition over the fair value of the net assets of the acquired business. Goodwill is reviewed for impairment at least annually or more frequently if an event or change in circumstance indicates that an impairment may have occurred. We first assess qualitative factors to evaluate whether it is more likely than not that an impairment has occurred and it is therefore necessary to perform the two-step goodwill impairment test. If the two-step goodwill impairment test indicates that the goodwill is impaired, an impairment loss is recorded.

We record the estimated fair value of acquired customer contracts, relationships and dedicated acreage agreements as intangible assets. These intangible assets have definite lives and are subject to amortization on a straight-line basis over their economic lives, currently ranging between 10 years and 30 years. We assess intangible assets for impairment together with related underlying long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.
Investment in unconsolidated affiliates 
Investment in unconsolidated affiliates

We hold membership interests in entities that own and operate natural gas pipeline systems and NGL and crude oil pipelines in and around Louisiana, Alabama, Mississippi and the Gulf of Mexico. While we have significant influence over these entities, we do not control them and therefore, they are accounted for using the equity method and are reported in Investment in unconsolidated affiliates in the consolidated balance sheets. We evaluate the recoverability of these investments on a regular basis and recognize impairment write downs if we determine a loss in value represents an other than temporary decline.
Deferred financing costs 
Deferred financing costs

Costs incurred in connection with our Credit Agreement are deferred and charged to interest expense over the term of the related credit arrangement. Such amounts are included in Other assets, net in our consolidated balance sheet. Costs incurred in connection with our 8.50% Senior Notes and 3.77% Senior Notes are also deferred and charged to interest expense over the respective term of the agreements; however, these amounts are reflected as a reduction of the related obligation. Gains or losses on debt repurchases or extinguishment include any associated unamortized deferred financing costs.
Asset retirement obligations 
Asset retirement obligations

Asset retirement obligations ("ARO") are legal obligations associated with the retirement of tangible long-lived assets that result from the asset's acquisition, construction, development and operation. An ARO is initially measured at its estimated fair value. Upon initial recognition, we also record an increase to the carrying amount of the related long-lived asset. We depreciate the asset using the straight-line method over the period during which it is expected to provide benefits. After initial recognition, we revise the ARO to reflect the passage of time and for changes in the estimated amount or timing of cash flows.

We have legal obligations requiring us to decommission our offshore pipeline systems at retirement. In certain rate jurisdictions, we are permitted to include annual charges for removal costs in the regulated cost of service rates we charge our customers. Additionally, legal obligations exist for certain of our offshore right-of-way agreements due to requirements or landowner options to compel us to remove the pipe at final abandonment. Sufficient data exists with certain onshore pipeline systems to reasonably estimate the cost of abandoning or retiring a pipeline system. However, in some cases, there is insufficient information to reasonably determine the timing and/or method of settlement for purposes of estimating the fair value of the asset retirement obligation. In these cases, the asset retirement obligation cost is considered indeterminate because there is no data or information that can be derived from past practice, industry practice, management's experience, or the asset's estimated economic life. The useful lives of most pipeline systems are primarily derived from available supply resources and ultimate consumption of those resources by end users. Variables can affect the remaining lives of the assets which preclude us from making a reasonable estimate of the asset retirement obligation. Indeterminate asset retirement obligation costs will be recognized in the period in which sufficient information exists to reasonably estimate potential settlement dates and methods.
Commitments, contingencies and environmental liabilities 
Commitments, contingencies and environmental liabilities

We expense or capitalize, as appropriate, expenditures for ongoing compliance with environmental regulations that relate to past or current operations. We expense amounts we incur from the remediation of existing environmental contamination caused by past operations that do not benefit future periods by preventing or eliminating future contamination. We record liabilities for environmental matters when assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of environmental liabilities are based on currently available facts, existing technology and presently enacted laws and regulation taking into consideration the likely effects of inflation and other factors. These amounts also take into account our prior experience in remediating contaminated sites, other companies' clean-up experience and data released by government organizations. Our estimates are subject to revision in future periods based on actual cost or new information. We evaluate recoveries from insurance coverage separately from the liability and, when recovery is probable, we record an asset separately from the associated liability in our consolidated financial statements.

We recognize liabilities for other commitments and contingencies when, after fully analyzing the available information, we determine it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. When a range of probable loss can be estimated, we accrue the most likely amount or if no amount is more likely than another, we accrue the minimum of the range of probable loss. We expense legal costs associated with loss contingencies as such costs are incurred.
Noncontrolling interests 
Noncontrolling interests

Noncontrolling interests represent the minority interest holders' proportionate share of the equity in certain of our consolidated subsidiaries and are adjusted for the minority interest holders' proportionate share of the subsidiaries' earnings or losses each period.
Revenue recognition 
Revenue recognition

We recognize revenue from the sale of commodities (e.g., natural gas, crude oil, NGLs or condensate) as well as from the provision of gathering, processing, transportation or storage services when all of the following criteria are met: i) persuasive evidence of an exchange arrangement exists, ii) delivery has occurred or services have been rendered, iii) the price is fixed or determinable, and iv) collectability is reasonably assured. We recognize revenue from the sale of commodities and the related cost of product sold on a gross basis for those transactions where we act as the principal and take title to commodities that are purchased for resale.

Purchases of natural gas, NGLs and condensate

Purchases of natural gas, NGLs and condensate represent the cost of commodities purchased for resale or obtained in connection with certain of our customer revenue arrangements. These costs do not include an allocation of depreciation expense or direct operating costs.

Corporate expenses 
Corporate expenses

Corporate expenses include compensation costs for executives and administrative personnel, professional service fees, rent expense and other general and administrative expenses and are recognized as incurred.
Operational balancing agreements and natural gas imbalances 
Operational balancing agreements and natural gas imbalances

To facilitate deliveries of natural gas and provide for operational flexibility, we have operational balancing agreements in place with other interconnecting pipelines. These agreements ensure that the volume of natural gas a shipper schedules for transportation between two interconnecting pipelines equals the volume actually delivered. If natural gas moves between pipelines in volumes that are more or less than the volumes the shipper previously scheduled, a natural gas imbalance is created. The imbalances are settled through periodic cash payments or repaid in-kind through future receipt or delivery of natural gas. Natural gas imbalances are recorded in Other current assets or Accrued expenses and other current liabilities on our consolidated balance sheets at cost which approximates fair value.
Equity-based compensation 
Equity-based compensation

We award equity-based compensation to management, non-management employees and directors under our Long-Term Incentive Plan ("LTIP"), which provides for the issuance of options, unit appreciation rights, restricted units, phantom units, other unit-based awards, unit awards or replacement awards, as well as tandem Distribution Equivalent Rights ("DERs"). Compensation expense is measured by the fair value of the award at the date of grant as determined by management. Compensation expense is recognized in Corporate expenses and Direct operating expenses over the requisite service period of each award.
Income taxes 
Income taxes

The Partnership is not a taxable entity for U.S. federal income tax purposes or for the majority of states that impose an income tax. Taxes on our net income are generally borne by our unitholders through the allocation of taxable income. American Midstream Blackwater, LLC, a subsidiary of the Partnership, owns a subsidiary that has operations which are subject to both federal and state income taxes. We account for income taxes of that subsidiary using an asset and liability approach for financial accounting and reporting of income taxes. If it is more than likely that a deferred tax asset will not be realized, a valuation allowance is recognized.

Margin tax expense results from the enactment of laws by the State of Texas that apply to entities organized as partnerships and is included in Income tax expense in our consolidated statements of operations. The Texas margin tax is computed on the portion of our taxable margin which is apportioned to Texas.

Net income (loss) for financial statement purposes may differ significantly from taxable income (loss) allocable to unitholders as a result of differences between the financial reporting and income tax bases of our assets and liabilities and the taxable income allocation requirement under our Partnership Agreement. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner's tax attributes in us is not available.
Accumulated other comprehensive income (loss) 
Accumulated other comprehensive income (loss)

Accumulated other comprehensive income (loss) is comprised solely of adjustments related to the Partnership's postretirement benefit plan.

Limited partners' net income (loss) per unit 
Limited partners' net income (loss) per unit

We compute earnings per unit using the two-class method. The two-class method requires that securities that meet the definition of a participating security be considered for inclusion in the computation of basic earnings per unit. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of the Partnership Agreement, regardless of whether the General Partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the General Partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period.

The two-class method does not impact our overall net income or other financial results; however, in periods in which aggregate net income exceeds our aggregate distributions for such period, it will have the impact of reducing net income per limited partner unit. This result occurs as a larger portion of our aggregate earnings, as if distributed, is allocated to the incentive distribution rights of the General Partner, even though we make distributions on the basis of available cash and not earnings. In periods in which our aggregate net income does not exceed our aggregate distributions for such period, the two-class method does not have any impact on our calculation of earnings per limited partner unit.
New accounting pronouncements 
New Accounting Pronouncements

Recently Adopted Accounting Standards

In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-03, Simplifying the Presentation of Debt Issuance Costs. This update requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. ASU 2015-03 is effective for fiscal years beginning after December 15, 2015, including interim periods therein, and is applied retrospectively. Early adoption is permitted for financial statements that have not been previously issued. ASU 2015-15, Presentation and Subsequent Measurement of Debt Issue Costs Associated with Line of Credit Arrangements, was subsequently issued to address the absence of authoritative guidance for debt issuance costs related to line-of-credit arrangements and states that the Securities and Exchange Commission ("SEC") staff will not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement.
The Partnership adopted the requirements of ASU No. 2015-03 effective January 1, 2016 and classifies the debt issuance costs applicable to its 8.50% Senior Notes and 3.77% Senior Notes as a reduction of the related debt obligation. Additionally, the Partnership continues to classify the debt issuance costs relating to its Credit Agreement within Other assets, net as allowed by ASU No. 2015-15.
 
In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805). This update requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. ASU 2015-16 is effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. Early adoption is permitted for financial statements that have not been issued. The Partnership adopted the updated guidance effective January 1, 2016 without impact to its financial statements.

Accounting Standards Issued Not Yet Adopted

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), which amends the existing accounting guidance for revenue recognition. The update requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU No. 2015-14 was subsequently issued and deferred the effective date to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that period. In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal Versus Agent Considerations, as further clarification on principal versus agent considerations. In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing as further clarification on identifying performance obligations and the licensing implementation guidance. In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients, as clarifying guidance on specific narrow scope improvements and practical expedients. We are in the process of reviewing our various customer arrangements in order to determine the impact that these updates will have on our consolidated financial statements and related disclosures. We have engaged a third-party consultant to assist with our review, which we currently expect to complete in the third quarter of 2017.

In February 2016, the FASB issued ASU No. 2016-02 (Topic 842) "Leases" which supersedes the lease recognition requirements in Accounting Standards Codification Topic 840, "Leases". Under ASU No. 2016-02 lessees are required to recognize assets and liabilities on the balance sheet for most leases and 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. Based upon our evaluation to date, we anticipate that the adoption of ASU 2016-02 will have a material effect 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 have not yet determined the timing or manner in which we will implement the updated guidance.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 320): Classification of Cash Receipts and Cash Payments, which addresses eight specific cash flow issues with the objective of reducing the existing diversity of presentation and classification in the statement of cash flows. ASU No. 2016-15 is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal periods. Early adoption is permitted, but only if all aspects are adopted in the same period. The Partnership is currently evaluating the impact this update will have on its consolidated statements of cash flows and related disclosures.

In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash, which aims to improve the disclosure of the change during the period in total cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. Amounts generally described as restricted cash or restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts on the statement of cash flows. The update is effective beginning first quarter of 2018. Early adoption is permitted, but it must occur in the first interim period. Any adjustments required in early adoption of this update should be reflected as of the beginning of the fiscal year that includes the interim period and should be applied using a retrospective transition method to each period. The Partnership is evaluating the impact that this update will have on our consolidated statement of cash flows and related disclosures.
Discontinued Operations (Tables)
Schedule of disposal groups
The following table presents the revenue, expense and (loss) gain from discontinued operations associated with the assets classified as held for sale for the years ended December 31, 2015 and 2014 (in thousands, except per unit amounts):

 
Years Ended December 31,
 
2015
 
2014
Revenue
$
74

 
$
474

Expense
(196
)
 
(658
)
Impairment
—

 
(673
)
Loss on sale of assets
(150
)
 
(87
)
Income tax benefit
192

 
333

Loss from discontinued operations, net of tax
$
(80
)
 
$
(611
)
Limited partners' net income (loss) per unit from discontinued operations (basic and diluted)
$
—

 
$
(0.04
)
Detail of Certain Asset Accounts (Tables)
Schedule of other current assets
Other current assets consists of the following (in thousands):
 
December 31,
 
2016
 
2015
Prepaid insurance
$
4,308

 
$
3,948

Other receivables
2,376

 
1,573

Due from related parties
4,206

 
64

Risk management assets
429

 
365

Other prepaids
2,967

 
2,866

Miscellaneous
2,184

 
1,643

 
$
16,470

 
$
10,459



Risk Management Activities (Tables)
Derivatives and fair value 
As of December 31, 2016, our outstanding interest rate swap contracts consist of the following (in thousands):

Notional Amount
Term
Fair Value
$200,000
January 3, 2017 thru September 3, 2019
$1,912
$100,000
January 1, 2018 thru December 31, 2021
$3,090
$150,000
January 1, 2018 thru December 31, 2022
$5,219
 
 
$10,221
Fair value associated with commodity derivative instruments 
Our interest rate swaps and weather derivatives were recorded in our consolidated balance sheets, under the following captions (in thousands):
 
 
Gross Risk Management Position
 
Netting Adjustment
 
Net Risk Management Position
Balance Sheet Classification
 
December 31, 2016
 
December 31, 2015
 
December 31, 2016
 
December 31, 2015
 
December 31, 2016
 
December 31, 2015
Other current assets
 
$
487

 
$
365

 
$
(58
)
 
$
—

 
$
429

 
$
365

Risk management assets
 
10,401

 
—

 
—

 
—

 
10,401

 
—

Total assets
 
$
10,888

 
$
365

 
$
(58
)
 
$
—

 
$
10,830

 
$
365

 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued expenses and other liabilities
 
$
(238
)
 
$
—

 
$
58

 
$
—

 
$
(180
)
 
$
—

Total liabilities
 
$
(238
)
 
$
—

 
$
58

 
$
—

 
$
(180
)
 
$
—


Realized and unrealized gains (losses) with commodity and interest rate derivative instruments 
For the years ended December 31, 2016, 2015 and 2014, the realized and unrealized gains (losses) associated with our commodity, interest rate and weather derivative instruments were recorded in our consolidated statements of operations, under the captions as follows (in thousands):
 
 
Realized
 
Unrealized
2016
 

Gains (losses) on commodity derivatives, net
 
$
(840
)
 
$
—

Interest expense
 
—

 
10,221

Direct operating expenses
 
(966
)
 
—

Total
 
$
(1,806
)
 
$
10,221

2015
 
 
 
 
Gains (losses) on commodity derivatives, net
 
$
1,610

 
$
(286
)
Interest expense
 
(240
)
 
215

Direct operating expenses
 
(913
)
 
—

Total
 
$
457

 
$
(71
)
2014
 
 
 
 
Gains (losses) on commodity derivatives, net
 
$
735

 
$
356

Interest expense
 
(433
)
 
239

Direct operating expenses
 
(1,035
)
 
—

Total
 
$
(733
)
 
$
595

Property, Plant and Equipment, Net (Tables)
Property, plant, and equipment, net
Property, plant and equipment, net. consists of the following (in thousands):
 
 
Useful Life
(in years)
 
December 31,
2016
 
December 31,
2015
Land
N/A
 
$
15,112

 
$
10,319

Construction in progress
N/A
 
122,884

 
45,383

Buildings and improvements
4 to 40
 
12,413

 
10,871

Processing and treating plants
8 to 40
 
134,434

 
115,568

Pipelines and compressors
3 to 40
 
554,965

 
538,402

Storage
20 to 40
 
58,786

 
58,220

Equipment
5 to 20
 
39,470

 
22,510

Total property, plant and equipment
 
 
938,064

 
801,273

Less accumulated depreciation
 
 
(182,607
)
 
(145,963
)
Property, plant and equipment, net
 
 
$
755,457

 
$
655,310

Goodwill and Intangible Assets, Net (Tables)
Schedule of finite-jived intangible assets
Intangible assets, net, consist of the following (in thousands):
 
December 31,
 
2016
 
2015
Gross carrying amount:
 
 
 
Customer relationships
$
53,400

 
$
53,400

Dedicated acreage
53,350

 
53,350

Collaborative arrangements
11,884

 
11,884

 
$
118,634

 
$
118,634

Accumulated amortization:
 
 
 
Customer relationships
$
(5,696
)
 
$
(3,124
)
Dedicated acreage
(4,439
)
 
(2,661
)
Collaborative arrangements
(601
)
 
—

 
$
(10,736
)
 
$
(5,785
)
Net carrying amount:
 
 
 
Customer relationships
$
47,704

 
$
50,276

Dedicated acreage
48,911

 
50,689

Collaborative arrangements
11,283

 
11,884

 
$
107,898

 
$
112,849

Investment in Unconsolidated Affiliates (Tables)
Investments in and Advances to Affiliates 
The following table presents activity in the Partnership's investments in unconsolidated affiliates (in thousands):
 
 
Delta House (1)
 
Emerald Transactions
 
 
 
 
 
 
FPS
 
OGL
 
Destin
 
Tri-States
 
Okeanos
 
Wilprise
 
MPOG
 
Total
Ownership % at December 31, 2016
20.1
%
 
20.1
%
 
49.7
%
 
16.7
%
 
66.7
%
 
25.3
%
 
66.7
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance at December 31, 2013
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
Investment
—

 
—

 
—

 
—

 
—

 
—

 
12,000

 
12,000

 
Earnings in unconsolidated affiliates
—

 
—

 
—

 
—

 
—

 
—

 
348

 
348

 
Contributions
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
Distributions
—

 
—

 
—

 
—

 
—

 
—

 
(1,980
)
 
(1,980
)
Balance at December 31, 2014
—

 
—

 
—

 
—

 
—

 
—

 
10,368

 
10,368

 
Investment
40,559

 
25,144

 
—

 
—

 
—

 
—

 
—

 
65,703

 
Earnings in unconsolidated affiliates
5,457

 
2,013

 
—

 
—

 
—

 
—

 
731

 
8,201

 
Contributions
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
Distributions
(12,551
)
 
(4,097
)
 
—

 
—

 
—

 
—

 
(3,920
)
 
(20,568
)
Balance at December 31, 2015
33,465

 
23,060

 
—

 
—

 
—

 
—

 
7,179

 
63,704

 
Investment
55,461

 
3,255

 
122,830

 
56,681

 
27,451

 
5,064

 
—

 
270,742

 
Earnings in unconsolidated affiliates
21,022

 
9,260

 
3,946

 
1,633

 
3,642

 
437

 
218

 
40,158

 
Contributions
—

 
—

 
—

 
—

 
—

 
—

 
430

 
430

 
Distributions
(45,465
)
 
(10,125
)
 
(15,894
)
 
(3,292
)
 
(4,034
)
 
(557
)
 
(3,679
)
 
(83,046
)
Balance at December 31, 2016
$
64,483

 
$
25,450

 
$
110,882

 
$
55,022

 
$
27,059

 
$
4,944

 
$
4,148

 
$
291,988



(1) Represents direct and indirect ownership interests in Class A Units.
Schedule of Investments 
Our investments in the unconsolidated affiliates underlying the Emerald Transactions were acquired in late April 2016. The following table presents information for each of these affiliates for the portion of 2016 that we held the related investments:

 
Emerald Transactions
 
Destin
 
Tri-States
 
Okeanos
 
Wilprise
Revenues
34,360

 
25,557

 
10,453

 
3,306

Net income
8,272

 
15,983

 
1,911

 
2,028

Partnership ownership %
49.7
%
 
16.7
%
 
66.7
%
 
25.3
%
Partnership share of investee net income
4,109

 
2,664

 
1,274

 
513

Basis difference amortization
(163
)
 
(1,031
)
 
2,368

 
(76
)
Earnings in unconsolidated affiliates
3,946

 
1,633

 
3,642

 
437

Accrued Expenses and Other Current Liabilities (Tables)
Schedule of accrued expenses and other current liabilities
Accrued expenses and other current liabilities consists of the following (in thousands):

 
 
December 31,
 
 
2016
 
2015
Capital expenditures
 
$
13,319

 
$
3,984

Convertible preferred unit distributions
 
7,103

 
—

Current portion of asset retirement obligations
 
6,499

 
6,822

Accrued interest
 
5,743

 
1,411

Additional Blackwater acquisition consideration
 
5,000

 
—

Employee compensation
 
4,226

 
3,114

Due to related parties
 
3,895

 
3,894

Transaction costs
 
3,000

 
—

Deferred financing costs
 
2,743

 
—

Gas imbalances payable
 
1,098

 
413

Other
 
8,952

 
3,675

 
 
$
61,578

 
$
23,313

Asset Retirement Obligations (Tables)
Schedule of reconciliation of the beginning and ending aggregate carrying amount of ARO liabilities
The following table presents activity in the Partnership's asset retirement obligations (in thousands):
 
Years Ended December 31,
 
2016
 
2015
Beginning balance
$
35,371

 
$
34,645

Liabilities assumed (1)
14,542

 
—

Revision in estimate
230

 
—

Expenditures
(858
)
 
(91
)
Accretion expense
1,577

 
817

Ending balance
50,862

 
35,371

Less: current portion
6,499

 
6,822

Noncurrent asset retirement obligation
$
44,363

 
$
28,549


______________________________________________________________________________________________________
(1) $14.3 million of the liability is a result of the Gulf of Mexico Pipeline acquisition.
Debt Obligations (Tables)
Outstanding borrowings 
Our outstanding debt consists of the following as of December 31, 2016 (in thousands):
 

 
8.5% Senior
 
3.77% Senior
 
 
 
 
 
Credit
 
Notes due
 
Notes due
 
Other
 
 
 
 Agreement (1)
 
2021
 
2031
 
Debt
 
Total
Balance
$
711,250

 
$
300,000

 
$
60,000

 
$
2,782

 
$
1,074,032

Less unamortized deferred financing costs and discount
—

 
(8,691
)
 
(2,345
)
 
—

 
(11,036
)
  Subtotal
711,250

 
291,309

 
57,655

 
2,782

 
1,062,996

Less current portion
—

 
—

 
(1,676
)
 
(2,782
)
 
(4,458
)
  Non-current portion
$
711,250

 
$
291,309

 
$
55,979

 
$
—

 
$
1,058,538



Our outstanding debt consists of the following as of December 31, 2015 (in thousands):
 
Credit
 
Other
 
 
 
 Agreement (1)
 
Debt
 
Total
Balance
$
525,100

 
$
2,338

 
$
527,438

Less current portion
—

 
(2,338
)
 
(2,338
)
  Non-current portion
$
525,100

 
$
—

 
$
525,100


______________________
(1) Unamortized deferred financing costs related to the Credit Agreement are included in Other assets, net.
Debt instrument redemption 
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%
Convertible Preferred Units (Tables)
Schedule of preferred units
Our convertible preferred units consist of the following (in thousands):

 
Series A
 
Series C
 
Series D
 
Units
$
 
Units
$
 
Units
$
December 31, 2013
5,279

$
94,811

 
—

$
—

 
—

$
—

Issuance of units
—

—

 
—

—

 
—

—

Paid in kind unit distributions
466

13,154

 
—

—

 
—

—

December 31, 2014
5,745

107,965

 
—

—

 
—

—

Issuance of units
2,571

44,769

 
—

—

 
—

—

Paid in kind unit distributions
894

16,978

 
—

—

 
—

—

December 31, 2015
9,210

169,712

 
—

—

 
—

—

Issuance of units
—

—

 
8,571

115,457

 
2,333

34,475

Paid in kind unit distributions
897

11,674

 
221

2,772

 
—

—

December 31, 2016
10,107

$
181,386

 
8,792

$
118,229

 
2,333

$
34,475

Partners' Capital (Tables)
Schedule for number of units outstanding 
The following table presents unit activity (in thousands):

 
 
General
Partner Interest
 
Limited Partner Interest
 
Series B Convertible Units
Balances at December 31, 2013
 
185

 
7,414

 
—

Initial issuance of Series B Units
 
—

 
—

 
1,168

Issuance of Series B Units
 
—

 
—

 
87

LTIP vesting
 
—

 
41

 
—

Issuance of GP units
 
207

 
—

 
—

Exercise of warrants
 
—

 
300

 
—

Issuance of common units
 
—

 
14,915

 
—

Balances at December 31, 2014
 
392

 
22,670

 
1,255

Issuance of Series B Units
 
—

 
—

 
95

LTIP vesting
 
—

 
105

 
—

Exercise of unit options
 
—

 
152

 
—

Issuance of GP units
 
144

 
—

 
—

Issuance of common units
 
—

 
7,500

 
—

Balances at December 31, 2015
 
536

 
30,427

 
1,350

Conversion of Series B Units
 
—

 
1,350

 
(1,350
)
Return of escrow units
 
—

 
(1,034
)
 
—

LTIP vesting
 
—

 
246

 
—

Issuance of GP units
 
144

 
—

 
—

Issuance of common units
 
—

 
248

 
—

Balances at December 31, 2016
 
680

 
31,237

 
—

Distributions Made to Limited Partner, by Distribution 
We made the following distributions (in thousands):
 
 
Years Ended December 31,
 
 
2016
 
2015
 
2014
Series A Units
 
 
 
 
 
 
Cash:
 
 
 
 
 
 
Paid
 
$
4,935

 
$
—

 
$
2,658

Accrued
 
2,514

 
—

 
—

Paid-in-kind units
 
11,674

 
16,978

 
13,154

Total
 
19,123

 
16,978

 
15,812

 
 
 
 
 
 
 
Series B Units
 
 
 
 
 
 
Paid-in-kind units
 
—

 
1,373

 
2,220

Total
 
—

 
1,373

 
2,220

 
 
 
 
 
 
 
Series C Units
 
 
 
 
 
 
Cash:
 
 
 
 
 
 
Paid
 
3,089

 
—

 
—

Accrued
 
3,626

 
—

 
—

Paid-in-kind units
 
2,772

 
—

 
—

Total
 
9,487

 
—

 
—

 
 
 
 
 
 
 
Series D Units
 
 
 
 
 
 
Cash:
 

 

 

Paid
 
—

 
—

 
—

Accrued
 
963

 
—

 
—

Paid-in-kind units
 
—

 
—

 
—

Total
 
963

 
—

 
—

 
 
 
 
 
 
 
Limited Partner Units
 
 
 
 
 
 
Cash:
 
 
 
 
 
 
Paid
 
53,500

 
46,597

 
22,656

Accrued
 
—

 
—

 
—

Total
 
53,500

 
46,597

 
22,656

 
 
 
 
 
 
 
General Partner Units
 
 
 
 
 
 
Cash:
 
 
 
 
 
 
Paid
 
2,551

 
6,789

 
2,695

Accrued
 
—

 
—

 
—

Additional Blackwater acquisition consideration
 
5,000

 
—

 
—

Total
 
7,551

 
6,789

 
2,695

 
 
 
 
 
 
 
Summary
 
 
 
 
 
 
Cash
 
 
 
 
 
 
Paid
 
64,075

 
53,386

 
28,009

Accrued
 
7,103

 
—

 
—

Paid-in-kind units
 
14,446

 
18,351

 
15,374

Additional Blackwater acquisition consideration
 
5,000

 
—

 
—

Total
 
$
90,624

 
$
71,737

 
$
43,383


Net Income (Loss) per Limited Partner Unit (Tables)
Schedule of earnings per share

The calculation of basic and diluted limited partners' net income (loss) per common unit is summarized below (in thousands, except per unit amounts):

 
Years Ended December 31,
 
2016
 
2015
 
2014
Net income (loss) from continuing operations
$
(666
)
 
$
(127,375
)
 
$
(97,195
)
Less: Net income attributable to noncontrolling interests
2,804

 
25

 
214

Net (income) loss from continuing operations attributable to the Partnership
(3,470
)
 
(127,400
)
 
(97,409
)
Less:
 
 
 
 
 
Distributions on Series A Units
19,138

 
16,978

 
14,492

Distributions on Series C Units
9,487

 
—

 
—

Distributions on Series D Units
963

 
—

 
—

Distributions on Series B Units
—

 
1,373

 
2,220

General partner's distributions
2,550

 
6,790

 
2,694

General partner's share in undistributed loss
(1,140
)
 
(2,569
)
 
(1,820
)
Net loss from continuing operations attributable to Limited Partners
(34,468
)
 
(149,972
)
 
(114,995
)
Net loss from discontinued operations attributable to Limited Partners
—

 
(80
)
 
(603
)
Net loss attributable to Limited Partners
$
(34,468
)
 
$
(150,052
)
 
$
(115,598
)
 
 
 
 
 
 
Weighted average number of common units used in computation of Limited Partners' net loss per common unit - basic and diluted
31,043

 
24,983

 
13,472

 
 
 
 
 
 
Limited Partners' net loss from continuing operations per unit (basic and diluted)
$
(1.11
)
 
$
(6.00
)
 
$
(8.54
)
Limited Partners' net loss from discontinued operations per unit (basic and diluted)
—

 
—

 
(0.04
)
Limited Partners' net loss per common unit - basic and diluted (1)
$
(1.11
)
 
$
(6.00
)
 
$
(8.58
)
 
_______________________
(1) Potential common unit equivalents are antidilutive for all periods and, as a result, have been excluded from the determination of diluted limited partners' net income (loss) per common unit.
Long-Term Incentive Plan (Tables)
Schedule of restricted stock and restricted stock units activity 
The following table summarizes activity in our phantom unit-based awards for the years ended December 31, 2016, 2015 and 2014:
 
 
Units
 
Weighted-Average Grant Date Fair Value Per Unit
 
Aggregate Intrinsic Value (1) (In thousands)
Outstanding shares at December 2013
 
75,529

 
$
17.62

 
$
2,045

Granted
 
188,946

 
20.80

 
 
Forfeited
 
(12,009
)
 
(18.28
)
 
 
Vested
 
(51,334
)
 
(20.89
)
 
 
Outstanding shares at December 2014
 
201,132

 
$
19.85

 
$
3,964

Granted
 
546,329

 
12.25

 
 
Forfeited
 
(31,298
)
 
(15.62
)
 
 
Vested
 
(146,404
)
 
(18.47
)
 
 
Outstanding shares at December 2015
 
569,759

 
$
13.15

 
$
4,609

Granted
 
1,374,226

 
2.14

 
 
Forfeited
 
(411,794
)
 
(2.60
)
 
 
Vested
 
(286,348
)
 
(12.18
)
 
 
Outstanding shares at December 2016
 
1,245,843

 
$
4.72

 
$
22,674



(1) The intrinsic value of phantom units was calculated by multiplying the closing market price of our underlying stock on December 31, 2016, 2015 and 2014 by the number of phantom units.
Schedule of stock options, valuation assumptions 
The Black-Scholes pricing model was used to determine the fair value of our options grants using the following assumptions:
 
Years Ended December 31,
 
2016
 
2015
Weighted average common unit price volatility
61.1
%
 
47.0
%
Expected distribution yield
12.6
%
 
26.3
%
Weighted average expected term (in years)
4.10

 
3.5

Weighted average risk-free rate
1.1
%
 
1.3
%
Options, grants in period, weighted average grant date fair value 
The following table summarizes our option activity for the years ended December 31, 2016 and 2015:
 
 
Units
 
Weighted-Average Exercise Price
 
Weighted-Average Grant Date Fair Value per Unit
 
Aggregate Intrinsic Value (1) (In thousands)
 
Weighted Average Remaining Contractual Life (Years)
Outstanding at December 31, 2014
 
—

 
$
—

 
$
—

 
$
—

 
—

Granted
 
200,000

 
7.50

 
0.33

 
—

 
—

Vested
 
—

 
—

 
 
 
—

 
—

Forfeited
 
—

 
—

 
 
 
—

 
—

Outstanding at December 31, 2015
 
200,000

 
$
7.50

 
$
0.33

 
$
118

 
4.2

Granted
 
75,000

 
13.13

 
2.65

 
—

 
—

Vested
 
—

 
—

 
 
 
—

 
—

Forfeited
 
—

 
—

 
 
 
—

 
—

Outstanding at December 31, 2016
 
275,000

 
$
9.03

 
$
0.96

 
$
2,522

 
5.0


(1) The intrinsic value of the stock option is the amount by which the current market value of the underlying stock exceeds the exercise price of the option.
Income Taxes (Tables)
Schedule of components of income tax (expense) benefit 

Income tax (expense) benefit for the years ended December 31, 2016, 2015 and 2014 is as follows:
 
Years Ended December 31,
 
2016
 
2015
 
2014
Current income tax expense
$
—

 
$
—

 
$
(10
)
Deferred income tax expense
(2,057
)
 
(1,134
)
 
(547
)
 
 
 
 
 
 
Effective income tax rate
147.9
%
 
0.9
%
 
0.6
%
Schedule of effective income tax rate reconciliation 
A reconciliation of our expected income tax (expense) benefit calculated at the U.S. federal statutory rate of 34% to our actual tax (expense) for the years ended December 31, 2016, 2015 and 2014 is as follows:

 
Years Ended December 31,
 
2016
 
2015
 
2014
Net income (loss) before income tax expense
$
1,391

 
$
(126,241
)
 
$
(96,638
)
US Federal statutory tax rate
34
%
 
34
%
 
34
%
Federal income tax (expense) benefit at statutory rate
(473
)
 
42,922

 
32,857

Reconciling items:
 
 
 
 
 
    Partnership loss not subject to income tax
(1,300
)
 
(43,812
)
 
(33,216
)
    State and local tax expense
(279
)
 
(103
)
 
(159
)
    Other
(5
)
 
(141
)
 
(39
)
Income tax expense
$
(2,057
)
 
$
(1,134
)
 
$
(557
)

Schedule of deferred tax assets and liabilities 
The Partnership’s deferred tax assets and liabilities as of December 31, 2016 and 2015 are summarized below:
 
December 31,
 
2016
 
2015
Deferred tax assets:
 
 
 
    Net operating loss carryforwards
$
6,300

 
$
7,570

    Other
577

 
493

    Total deferred tax assets
6,877

 
8,063

Deferred tax liabilities:
 
 
 
    Property, plant and equipment
(14,735
)
 
(13,889
)
Deferred income tax liability, net
$
(7,858
)
 
$
(5,826
)
Commitments and Contingencies (Tables)
Future non-cancelable commitments related to certain contractual obligations

The Partnership had the following non-cancelable contractual commitments as of December 31, 2016 (in thousands):
 
 
Credit Agreement
 
3.77% Senior Notes
 
8.50% Senior Notes
 
Asset Retirement Obligation
 
     Other (1)
 
Total
2017
 
$
—

 
$
1,677

 
$
—

 
$
6,499

 
$
4,144

 
$
12,320

2018
 
—

 
806

 
—

 
—

 
2,411

 
3,217

2019
 
711,250

 
2,233

 
—

 
—

 
2,547

 
716,030

2020
 
—

 
2,299

 
—

 
—

 
2,081

 
4,380

2021
 
—

 
4,430

 
300,000

 
—

 
1,892

 
306,322

Thereafter
 
—

 
48,555

 
—

 
44,363

 
13,435

 
106,353

 
 
$
711,250

 
$
60,000

 
$
300,000

 
$
50,862

 
$
26,510

 
$
1,148,622


(1) Minimum payments have not been reduced by minimum sublease rentals of $0.2 million.

Supplemental Cash Flow Information (Tables)
Schedule of cash flow, supplemental disclosures
Supplemental cash flows and non-cash transactions consists of the following (in thousands):

 
Years Ended December 31,
 
2016
 
2015
 
2014
Supplemental cash flow information
 
 
 
 
 
Interest payments, net of capitalized interest
$
16,922

 
$
12,013

 
$
6,726

Supplemental non-cash information
 
 
 
 
 
Increase (decrease) in accrued property, plant and equipment purchases
$
7,353

 
$
(25,637
)
 
$
31,390

Issuance of Series C Units and Warrant in connection with the Emerald Transactions
120,000

 
—

 
—

Accrued cash distributions on convertible preferred units
7,103

 
—

 
—

Paid-in-kind distributions on convertible preferred units
14,446

 
16,978

 
13,154

Paid-in-kind distributions on Series B Units
—

 
1,373

 
2,220

Cancellation of escrow units
6,817

 
—

 
—

Additional Blackwater acquisition consideration
5,000

 
—

 
—

Common unit issuance related to Costar Acquisition
—

 
—

 
147,296

Reporting Segments (Tables)
Segment information for the periods 
The following tables set forth our segment financial information for the periods indicated (in thousands):

 
December 31, 2016
 
Gathering
and
Processing
 
Transmission
 
Terminals
 
Total
Sales of natural gas, NGLs and condensate revenue
$
153,174

 
$
7,775

 
$
1

 
$
160,950

Services revenue
10,531

 
39,196

 
22,845

 
72,572

Loss on commodity derivatives, net
(836
)
 
(4
)
 
—

 
(840
)
Total revenue
162,869

 
46,967

 
22,846

 
232,682

Operating expenses:
 
 
 
 
 
 
 
Purchases of natural gas, NGL's and condensate
87,026

 
5,530

 
—

 
92,556

Direct operating expenses
41,345

 
11,920

 
8,596

 
61,861

Corporate expenses
 
 
 
 
 
 
54,223

Depreciation, amortization and accretion expense
 
 
 
 
 
 
46,022

Loss on sale of assets, net
 
 
 
 
 
 
591

Loss on impairment of property, plant and equipment
 
 
 
 
 
 
697

Interest expense
 
 
 
 
 
 
15,499

Earnings in unconsolidated affiliates
 
 
 
 
 
 
(40,158
)
Income tax expense
 
 
 
 
 
 
2,057

Net income
 
 
 
 
 
 
(666
)
Less: Net income attributable to noncontrolling interests
 
 
 
 
 
 
2,804

Net loss attributable to the Partnership
 
 
 
 
 
 
$
(3,470
)
 
 
 
 
 
 
 
 
Segment gross margin (1)
$
74,582

 
$
41,233

 
$
14,250

 
 
_________________________
(1) Segment gross margin for our Gathering and Processing segment consists of total revenue less construction and operating management agreement income of $1.3 million and purchases of natural gas, NGLs and condensate.

Segment gross margin for our Transmission segment consists of total revenue less construction and operating management agreement income of less than $0.2 million and purchases of natural gas, NGLs and condensate.

Segment gross margin for our Terminals segment consists of total revenue less direct operating expenses.

 
Year Ended December 31, 2015
 
Gathering
and
Processing
 
Transmission
 
Terminals
 
Total
Sales of natural gas, NGLs and condensate revenue
$
170,197

 
$
9,600

 
$
21

 
$
179,818

Services revenue
3,400

 
34,082

 
17,734

 
55,216

Gain on commodity derivatives, net
1,324

 
—

 
—

 
1,324

Total revenue
174,921

 
43,682

 
17,755

 
236,358

Operating expenses:
 
 
 
 
 
 
 
Purchases of natural gas, NGL's and condensate
97,580

 
8,303

 
—

 
105,883

Direct operating expenses
39,249

 
13,768

 
7,720

 
60,737

Corporate expenses
 
 
 
 
 
 
29,818

Depreciation, amortization and accretion expense
 
 
 
 
 
 
38,014

Loss on sale of assets, net
 
 
 
 
 
 
3,011

Loss on impairment of goodwill
 
 
 
 
 
 
118,592

Interest expense
 
 
 
 
 
 
14,745

Earnings in unconsolidated affiliates
 
 
 
 
 
 
(8,201
)
Income tax expense
 
 
 
 
 
 
1,134

Loss from discontinued operations, net of tax
 
 
 
 
 
 
80

Net Loss
 
 
 
 
 
 
(127,455
)
Less: Net income attributable to noncontrolling interests
 
 
 
 
 
 
25

Net loss attributable to the Partnership
 
 
 
 
 
 
$
(127,480
)
 
 
 
 
 
 
 
 
Segment gross margin (1)
$
76,865

 
$
35,301

 
$
10,035

 
 
____________________
(1) Segment gross margin for our Gathering and Processing segment consists of total revenue less unrealized gain on commodity derivatives of $0.3 million, construction and operating management agreement income of $0.8 million and purchases of natural gas, NGLs and condensate.

Segment gross margin for our Transmission segment consists of total revenue less construction and operating management agreement income of less than $0.1 million and purchases of natural gas, NGLs and condensate.

Segment gross margin for our Terminals segment consists of total revenue less direct operating expenses.



 
Year Ended December 31, 2014
 
Gathering
and
Processing
 
Transmission
 
Terminals (b)
 
Total
Sales of natural gas, NGLs and condensate revenue
$
202,035

 
$
52,881

 
$
109

 
$
255,025

Services revenue
1,581

 
35,308

 
15,395

 
52,284

Gain on commodity derivatives, net
1,091

 
—

 
—

 
1,091

Total revenue
204,707

 
88,189

 
15,504

 
308,400

Operating expenses:
 
 
 
 
 
 
 
Purchases of natural gas, NGL's and condensate
152,690

 
45,262

 
—

 
197,952

Direct operating expenses
23,806

 
15,619

 
6,494

 
45,919

Corporate expenses
 
 
 
 
 
 
24,422

Depreciation, amortization and accretion expense
 
 
 
 
 
 
28,832

Loss on impairment of property, plant and equipment
 
 
 
 
 
 
99,892

Loss on sale of assets, net
 
 
 
 
 
 
122

Other expense
 
 
 
 
 
 
670

Interest expense
 
 
 
 
 
 
7,577

Earnings in unconsolidated affiliates
 
 
 
 
 
 
(348
)
Income tax expense
 
 
 
 
 
 
557

Loss from discontinued operations, net of tax
 
 
 
 
 
 
611

Net Loss
 
 
 
 
 
 
(97,806
)
Less: Net income attributable to noncontrolling interests
 
 
 
 
 
 
214

Net loss attributable to the Partnership
 
 
 
 
 
 
$
(98,020
)
 
 
 
 
 
 
 
 
Segment gross margin (1)
$
50,817

 
$
42,828

 
$
9,010

 
 
____________________
(1) Segment gross margin for our Gathering and Processing segment consists of total revenue less unrealized gain on commodity derivatives of $0.4 million, construction and operating management agreement income of $0.8 million, and purchases of natural gas, NGLs and condensate.
Reconciliation of assets from segment to consolidated 
A reconciliation of total assets by segment to the amounts included in the consolidated balance sheets is as follows:

 
December 31,
 
2016
 
2015
Segment assets:
 
 
 
Gathering and Processing
$
537,658

 
$
573,408

Transmission
142,404

 
133,870

Terminals
45,226

 
84,449

Other (1)
838,207

 
100,153

Total assets
$
1,563,495

 
$
891,880

_______________________
(1) Other assets not allocable to segments consist of investment in unconsolidated affiliates, restricted cash and other assets.
Quarterly Financial Data (Unaudited) (Tables)
Schedule of quarterly financial information
Summarized unaudited quarterly financial data for 2016 and 2015 are as follows (in thousands, except per unit amounts):
 
 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter (2)
 
 
 
 
 
 
 
 
Total revenues
$
46,020

 
$
55,382

 
$
63,818

 
$
67,462

Gross margin (1)(3)
27,291

 
31,809

 
34,312

 
36,653

Operating loss
(5,116
)
 
(6,191
)
 
(2,717
)
 
(9,244
)
Net income (loss)
(3,964
)
 
(3,591
)
 
2,679

 
4,210

Net income (loss) attributable to the Partnership
(3,951
)
 
(4,583
)
 
1,483

 
3,581

General Partner's Interest in net income (loss)
(52
)
 
(61
)
 
19

 
46

Limited Partners' Interest in net income (loss)
$
(3,899
)
 
$
(4,522
)
 
$
1,464

 
$
3,535

 
 
 
 
 
 
 
 
Limited Partners' income (loss) per unit:
 
 
 
 
 
 
 
Loss from continuing operations
$
(0.33
)
 
$
(0.36
)
 
$
(0.22
)
 
$
(0.20
)
Net income (loss)
$
(0.33
)
 
$
(0.36
)
 
$
(0.22
)
 
$
(0.20
)
Year Ended December 31, 2015
 
 
 
 
 
 
 
Total revenues
$
64,609

 
$
67,509

 
$
55,641

 
$
48,599

Gross margin (1) (3)
33,776

 
31,917

 
28,854

 
27,654

Operating income (loss)
3,434

 
1,867

 
(1,523
)
 
(123,475
)
Net income (loss) from continuing operations
835

 
(2,002
)
 
(4,574
)
 
(121,634
)
Income (loss) from discontinued operations, net of tax
5

 
(31
)
 
(53
)
 
(1
)
Net income (loss) attributable to noncontrolling interest
14

 
32

 
34

 
(55
)
Net income (loss) attributable to the Partnership
826

 
(2,065
)
 
(4,661
)
 
(121,580
)
General Partner's Interest in net income (loss)
10

 
(25
)
 
(60
)
 
(1,570
)
Limited Partners' Interest in net income (loss)
$
816

 
$
(2,040
)
 
$
(4,601
)
 
$
(120,010
)
 
 
 
 
 
 
 
 
Limited Partners' income (loss) per unit:
 
 
 
 
 
 
 
Loss from continuing operations
$
(0.19
)
 
$
(0.35
)
 
$
(0.48
)
 
$
(4.16
)
Net loss
$
(0.19
)
 
$
(0.35
)
 
$
(0.48
)
 
$
(4.16
)
 
(1)
For a definition of gross margin and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP and a discussion of how we use gross margin to evaluate our operating performance, please read Item 7. "Management's Discussion and Analysis, How We Evaluate Our Operations."
(2)
In the fourth quarter of 2015, we recognized a goodwill impairment charge of $118.6 million.
(3)
Amounts are different than previously reported due to reclassifying a portion of equity compensation expense into Direct operating expense for the Terminals segment.
Organization and Basis of Presentation (Details) (USD $)
0 Months Ended 12 Months Ended 3 Months Ended 12 Months Ended 3 Months Ended 9 Months Ended 12 Months Ended
Aug. 20, 2009
Dec. 31, 2016
segments
mi
facility
pipeline
gathering_system
bbl
terminal
plant
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2016
Minimum
Dec. 31, 2016
Maximum
Dec. 31, 2016
8.50% Senior Notes, due 2021
Senior Notes
Dec. 28, 2016
8.50% Senior Notes, due 2021
Senior Notes
Dec. 31, 2016
3.77% Senior Notes, due 2031
Senior Notes
Sep. 30, 2016
3.77% Senior Notes, due 2031
Senior Notes
Dec. 31, 2016
Out of Period Adjustment
Dec. 31, 2015
Out of Period Adjustment
Oct. 14, 2014
Costar Midstream, L.L.C.
Oct. 31, 2014
Collaborative Arrangement
Costar Midstream, L.L.C.
Dec. 31, 2016
Investments in Majority-owned Subsidiaries
Out of Period Adjustment
Sep. 30, 2016
Restatement Adjustment
Investments in Majority-owned Subsidiaries
Out of Period Adjustment
Dec. 31, 2015
Restatement Adjustment
Investments in Majority-owned Subsidiaries
Out of Period Adjustment
Collaborative Arrangements and Non-collaborative Arrangement Transactions [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
General partners' capital account, percentage
95.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Limited partners' capital account, percentage
5.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of reportable segments
 
3 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gathering pipeline (miles)
 
3,800 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of gathering systems
 
15 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of interstate pipelines
 
6 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of intrastate pipelines
 
8 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of processing facilities
 
8 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of fractionation facilities
 
4 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Volume of crude oil, operating
 
80,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Volume of natural gas, operating
 
200 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of marine terminal sites
 
3 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Million barrels of storage capacity
 
2,400,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Acquired interest (percent)
 
 
 
 
 
 
 
 
 
 
 
 
100.00% 
50.00% 
 
 
 
Services
 
$ 72,572,000 
$ 55,216,000 
$ 52,284,000 
 
 
 
 
 
 
$ 1,200,000 
 
 
 
 
 
 
Depreciation, amortization and accretion expense
 
46,022,000 
38,014,000 
28,832,000 
 
 
 
 
 
 
1,000,000 
 
 
 
 
 
 
Earnings in unconsolidated affiliates
 
(40,158,000)
(8,201,000)
(348,000)
 
 
 
 
 
 
500,000 
 
 
 
1,400,000 
(1,000,000)
(400,000)
Net loss
 
(666,000)
(127,455,000)
(97,806,000)
 
 
 
 
 
 
300,000 
7,300,000 
 
 
 
 
 
Intangible assets, net
 
107,898,000 
112,849,000 
 
 
 
 
 
 
 
 
11,900,000 
 
 
 
 
 
Investment in unconsolidated affiliates
 
(291,987,000)
(63,704,000)
 
 
 
 
 
 
 
 
18,600,000 
 
 
 
 
 
Noncontrolling interests
 
9,797,000 
5,114,000 
 
 
 
 
 
 
 
 
600,000 
 
 
 
 
 
Additions to property, plant and equipment
 
123,078,000 
137,029,000 
96,998,000 
 
 
 
 
 
 
 
6,500,000 
 
 
 
 
 
Acquisition of investments in unconsolidated affiliates
 
(150,179,000)
(65,701,000)
(12,000,000)
 
 
 
 
 
 
 
5,900,000 
 
 
 
 
 
Contributions from noncontrolling interest owners
 
3,366,000 
584,000 
0 
 
 
 
 
 
 
 
600,000 
 
 
 
 
 
Allowance for doubtful accounts receivable
 
$ 600,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Useful Life (in years)
 
 
 
 
3 years 
40 years 
 
 
 
 
 
 
 
 
 
 
 
Useful life
 
 
 
 
10 years 0 months 0 days 
30 years 
 
 
 
 
 
 
 
 
 
 
 
Debt instrument, interest rate, stated percentage
 
 
 
 
 
 
8.50% 
8.50% 
3.77% 
3.77% 
 
 
 
 
 
 
 
Acquisitions and Divestitures JP Energy Partners Merger (Details)
0 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Mar. 8, 2017
Subsequent Event
Affiliated Holders
Mar. 8, 2017
Subsequent Event
Public Unit Consideration
Mar. 8, 2017
JPE Energy Partners
Subsequent Event
business_segment
Dec. 31, 2016
General Partner
Dec. 31, 2015
General Partner
Mar. 8, 2017
General Partner
Subsequent Event
Mar. 7, 2017
Affiliated Entity
General Partner
Subsequent Event
Business Acquisition [Line Items]
 
 
 
 
 
 
 
 
 
Merger agreement, conversion ratio
 
 
0.5775 
0.5225 
 
 
 
 
 
General partners' interest units issued (in shares)
680,000 
536,000 
 
 
 
143,900 
143,517 
20,200,000 
0 
Number of businesses segments acquired
 
 
 
 
3 
 
 
 
 
Acquisitions and Divestitures Delta House Investment (Details) (USD $)
0 Months Ended 12 Months Ended 12 Months Ended 0 Months Ended 12 Months Ended 0 Months Ended 12 Months Ended
Oct. 31, 2016
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Oct. 8, 2015
Sep. 18, 2015
Sep. 15, 2015
Aug. 15, 2014
Jan. 29, 2014
Sep. 18, 2015
Pinto Offshore Holdings LLC
Dec. 31, 2016
FPS
Dec. 31, 2015
FPS
Dec. 31, 2014
FPS
Sep. 18, 2015
FPS
Oct. 31, 2016
Delta House
Apr. 25, 2016
Delta House
Sep. 18, 2015
Delta House
Dec. 31, 2016
Delta House
Oct. 31, 2016
Delta House
Apr. 25, 2016
D-Day Offshore Holdings
Sep. 18, 2015
Pinto Offshore Holdings LLC
Delta House
Apr. 25, 2016
Arclight Affiliate
D-Day Offshore Holdings
Oct. 31, 2016
Series D Preferred Stock
Oct. 31, 2016
Series D Preferred Stock
Dec. 31, 2016
General Partner
Dec. 31, 2015
General Partner
Dec. 31, 2016
Class A Units
Dec. 31, 2016
Class B Units
Business Acquisition [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage ownership
 
 
 
 
 
 
 
 
 
26.30% 
20.10% 
 
 
49.00% 
 
 
 
20.10% 
 
100.00% 
12.90% 
1.00% 
 
 
 
 
 
 
Payments to acquire equity method investments
 
$ 150,179,000 
$ 65,701,000 
$ 12,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
$ 162,000,000 
 
 
 
 
 
 
 
 
 
 
 
Limited partners, units issued (in shares)
 
31,237,000 
30,427,000 
 
151,937 
7,500,000 
7,500,000 
4,622,352 
3,400,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Investment
 
270,742,000 
65,703,000 
12,000,000 
 
 
 
 
 
 
55,461,000 
40,559,000 
0 
 
48,800,000 
9,900,000 
 
65,700,000 
 
 
 
 
 
 
 
 
 
 
Partners capital account distributions, delta house
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(96,300,000)
 
 
 
Acquired interest (percent)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
6.20% 
 
 
 
 
 
 
 
 
 
Issuance of units
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
34,500,000 
 
 
 
 
 
General partners' interest units issued (in shares)
 
680,000 
536,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2,333,333 
143,900 
143,517 
 
 
Proceeds from lines of credit
$ 14,300,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Equity method investment, distribution percentage
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
100.00% 
7.00% 
Acquisitions and Divestitures Emerald Transactions (Details) (USD $)
0 Months Ended 12 Months Ended 0 Months Ended 12 Months Ended 0 Months Ended 12 Months Ended 0 Months Ended 12 Months Ended 0 Months Ended 12 Months Ended 0 Months Ended 0 Months Ended
Apr. 27, 2016
Dec. 31, 2016
mi
Dec. 31, 2015
Dec. 31, 2014
Apr. 27, 2016
platform
agreement
lateral
Apr. 25, 2016
lateral
platform
Apr. 25, 2016
Destin
mi
Dec. 31, 2016
Destin
Dec. 31, 2015
Destin
Dec. 31, 2014
Destin
Apr. 25, 2016
Destin
Apr. 25, 2016
Tri-States
mi
Dec. 31, 2016
Tri-States
Dec. 31, 2015
Tri-States
Dec. 31, 2014
Tri-States
Apr. 25, 2016
Tri-States
Apr. 25, 2016
Wilprise
mi
Dec. 31, 2016
Wilprise
Dec. 31, 2015
Wilprise
Dec. 31, 2014
Wilprise
Apr. 25, 2016
Wilprise
Apr. 27, 2016
Okeanos
mi
Dec. 31, 2016
Okeanos
Dec. 31, 2015
Okeanos
Dec. 31, 2014
Okeanos
Apr. 27, 2016
Okeanos
Apr. 27, 2016
BP
Apr. 25, 2016
BP
Apr. 25, 2016
Series C Preferred Stock
Apr. 27, 2016
BP
Apr. 27, 2016
Limited Partner
Business Acquisition [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of agreements
 
 
 
 
2 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ownership % at December 31, 2016
 
 
 
 
 
 
 
49.70% 
 
 
49.70% 
 
16.70% 
 
 
16.70% 
 
25.30% 
 
 
25.30% 
 
66.70% 
 
 
66.70% 
 
 
 
 
 
Payments to acquire equity method investments
 
$ 150,179,000 
$ 65,701,000 
$ 12,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 27,400,000 
$ 183,600,000 
 
$ 100,900,000 
 
Length of pipeline
 
3,800 
 
 
 
 
255 
 
 
 
 
161 
 
 
 
 
30 
 
 
 
 
100 
 
 
 
 
 
 
 
 
 
Volume of natural gas, operating amount
 
 
 
 
 
 
1,200 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of platforms
 
 
 
 
2 
4 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of laterals
 
 
 
 
1 
6 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Length of offshore pipeline
 
 
 
 
 
 
120 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Length of onshore pipeline
 
 
 
 
 
 
135 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Volume of natural gas, operating amount, production
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,000 
 
 
 
 
 
 
 
 
 
Temporary equity, shares issued (in shares)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
8,571,429 
 
 
Number of securities called by warrants (in shares)
 
 
 
 
 
800,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exercise price of warrants (in dollars per share)
 
 
 
 
 
$ 7.25 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Issuance of Series C Units and Warrant in connection with the Emerald Transactions
 
120,000,000 
0 
0 
 
120,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Borrowings to acquire equity method investments
91,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Investment
 
270,742,000 
65,703,000 
12,000,000 
 
 
 
122,830,000 
0 
0 
 
 
56,681,000 
0 
0 
 
 
5,064,000 
0 
0 
 
 
27,451,000 
0 
0 
 
212,000,000 
 
 
 
 
Partners capital account contributions, emerald
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 1,000,000 
Acquisitions and Divestitures Gulf of Mexico Pipeline Narrative (Details) (USD $)
3 Months Ended 12 Months Ended 0 Months Ended 12 Months Ended
Dec. 31, 2016
Sep. 30, 2016
Jun. 30, 2016
Mar. 31, 2016
Sep. 30, 2015
Jun. 30, 2015
Mar. 31, 2015
Dec. 31, 2014
Dec. 31, 2016
mi
Dec. 31, 2015
Dec. 31, 2014
Apr. 15, 2016
American Panther
mi
Dec. 31, 2016
American Panther
Apr. 15, 2016
American Panther
Business Acquisition [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Noncontrolling interest, ownership percentage by parent
 
 
 
 
 
 
 
 
 
 
 
 
 
60.00% 
Length of pipeline
 
 
 
 
 
 
 
 
3,800 
 
 
200 
 
 
Cash
 
 
 
 
 
 
 
 
 
 
 
$ 2,700,000 
 
 
Pipelines
 
 
 
 
 
 
 
 
 
 
 
 
 
16,600,000 
Land
 
 
 
 
 
 
 
 
 
 
 
 
 
400,000 
ARO
 
 
 
 
 
 
 
 
 
 
 
14,300,000 
 
 
Noncontrolling interest
 
 
 
 
 
 
 
 
 
 
 
 
 
1,800,000 
Total revenue
67,462,000 
63,818,000 
55,382,000 
46,020,000 
55,641,000 
67,509,000 
64,609,000 
48,599,000 
232,682,000 
236,358,000 
308,400,000 
 
13,200,000 
 
Operating loss
(9,244,000)
(2,717,000)
(6,191,000)
(5,116,000)
(1,523,000)
1,867,000 
3,434,000 
(123,475,000)
(23,268,000)
(119,697,000)
(88,739,000)
 
7,400,000 
 
Transaction costs
 
 
 
 
 
 
 
 
 
 
 
 
$ 300,000 
 
Acquisitions and Divestitures Costar Acquisition Narrative (Details) (USD $)
3 Months Ended 12 Months Ended 0 Months Ended 3 Months Ended 1 Months Ended
Dec. 31, 2015
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Oct. 14, 2014
Costar Midstream, L.L.C.
Dec. 31, 2015
Costar Midstream, L.L.C.
Oct. 14, 2014
Costar Midstream, L.L.C.
Feb. 29, 2016
Interest rate swap
Business Acquisition [Line Items]
 
 
 
 
 
 
 
 
Acquired interest (percent)
 
 
 
 
 
 
100.00% 
 
Consideration transferred
 
 
 
 
$ 405,300,000 
 
 
 
Acquisition working capital adjustment
 
 
7,400,000 
 
 
 
 
6,800,000 
Escrowed units returned to partnership (in shares)
 
 
 
 
 
 
 
1,034,483 
Payments for previous acquisition
 
 
 
 
 
 
 
300,000 
Loss on impairment of goodwill
$ 118,600,000 
$ 0 
$ 118,600,000 
$ 0 
 
$ 95,000,000 
 
 
Acquisitions and Divestitures Lavaca Acquisition Narrative (Details) (USD $)
3 Months Ended 12 Months Ended 0 Months Ended 3 Months Ended
Dec. 31, 2015
Dec. 31, 2016
mi
Dec. 31, 2015
Dec. 31, 2014
Jan. 31, 2014
Lavaca
mi
Dec. 31, 2015
Lavaca
Business Acquisition [Line Items]
 
 
 
 
 
 
Length of pipeline
 
3,800 
 
 
120 
 
Cash
 
 
 
 
$ 104,400,000 
 
Loss on impairment of goodwill
$ 118,600,000 
$ 0 
$ 118,600,000 
$ 0 
 
$ 23,600,000 
Discontinued Operations (Details) (USD $)
In Thousands, except Per Share data, unless otherwise specified
3 Months Ended 12 Months Ended
Sep. 30, 2015
Jun. 30, 2015
Mar. 31, 2015
Dec. 31, 2014
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Discontinued Operations and Disposal Groups [Abstract]
 
 
 
 
 
 
 
Loss on impairment of noncurrent assets held for sale
 
 
 
 
$ 0 
$ 0 
$ 673 
Revenue
 
 
 
 
 
74 
474 
Expense
 
 
 
 
 
(196)
(658)
Impairment
 
 
 
 
 
0 
(673)
Loss on sale of assets
 
 
 
 
 
(150)
(87)
Income tax benefit
 
 
 
 
 
192 
333 
Loss from discontinued operations, net of tax
$ (53)
$ (31)
$ 5 
$ (1)
$ 0 
$ (80)
$ (611)
Limited Partners' net income (loss) from discontinued operations per unit (basic and diluted) (in dollars per share)
 
 
 
 
$ 0.00 
$ 0.00 
$ (0.04)
Concentration of Credit Risk and Trade Accounts Receivable (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Revenue, Major Customer
 
 
 
Allowance for doubtful accounts receivable
$ 0.6 
 
 
Sales Revenue, Net |
Customer Concentration Risk |
Customer A
 
 
 
Revenue, Major Customer
 
 
 
Entity-wide revenue by major customer, percentage
10.00% 
10.00% 
22.00% 
Sales Revenue, Net |
Customer Concentration Risk |
Customer B
 
 
 
Revenue, Major Customer
 
 
 
Entity-wide revenue by major customer, percentage
 
 
12.00% 
Sales Revenue, Net |
Customer Concentration Risk |
Customer C
 
 
 
Revenue, Major Customer
 
 
 
Entity-wide revenue by major customer, percentage
 
 
10.00% 
Detail of Certain Asset Accounts (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2016
Dec. 31, 2015
Other current assets
 
 
Prepaid insurance
$ 4,308 
$ 3,948 
Other receivables
2,376 
1,573 
Due from related parties
4,206 
64 
Risk management assets
429 
365 
Other prepaids
2,967 
2,866 
Miscellaneous
2,184 
1,643 
Total Other current assets
$ 16,470 
$ 10,459 
Risk Management Activities (Interest Rate Swap) (Details) (Interest rate swap, USD $)
In Thousands, unless otherwise specified
Dec. 31, 2016
Derivative [Line Items]
 
Fair Value
$ 10,221 
January 3, 2017 thru September 3, 2019
 
Derivative [Line Items]
 
Notional Amount
200,000 
Fair Value
1,912 
January 1, 2018 thru December 31, 2021
 
Derivative [Line Items]
 
Notional Amount
100,000 
Fair Value
3,090 
January 1, 2018 thru December 31, 2022
 
Derivative [Line Items]
 
Notional Amount
150,000 
Fair Value
$ 5,219 
Risk Management Activities (Details Textual) (USD $)
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Derivative [Line Items]
 
 
 
Amortization of weather derivative premium
$ 966,000 
$ 912,000 
$ 1,035,000 
Weather Contract
 
 
 
Derivative [Line Items]
 
 
 
Derivative instruments not designated as hedging instruments, potential cash proceeds from Contract
30,000,000 
 
 
Payments of derivative issuance costs
1,000,000 
900,000 
 
Term of Contract
1 year 0 months 0 days 
 
 
Amortization of weather derivative premium
$ 400,000 
$ 400,000 
 
Risk Management Activities (Fair Value of Commodity Derivatives) (Details) (Commodity derivative instruments, net, USD $)
In Thousands, unless otherwise specified
Dec. 31, 2016
Dec. 31, 2015
Derivative [Line Items]
 
 
Derivative asset, gross derivative asset
$ 10,888 
$ 365 
Derivative asset, gross derivative liabilities
(58)
0 
Derivative asset, fair value, net
10,830 
365 
Derivative liability, gross derivative assets
(238)
0 
Derivative liability, gross derivative liabilities
58 
0 
Derivative liability, fair value, net
(180)
0 
Other current assets
 
 
Derivative [Line Items]
 
 
Derivative asset, gross derivative asset
487 
365 
Derivative asset, gross derivative liabilities
(58)
0 
Derivative asset, fair value, net
429 
365 
Risk management assets
 
 
Derivative [Line Items]
 
 
Derivative asset, gross derivative asset
10,401 
0 
Derivative asset, gross derivative liabilities
0 
0 
Derivative asset, fair value, net
10,401 
0 
Accrued expenses and other liabilities
 
 
Derivative [Line Items]
 
 
Derivative liability, gross derivative assets
(238)
0 
Derivative liability, gross derivative liabilities
58 
0 
Derivative liability, fair value, net
$ (180)
$ 0 
Risk Management Activities (Realized and Unrealized Gains (Losses)) (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Derivatives, Fair Value [Line Items]
 
 
 
Loss on commodity derivatives, net
$ (840)
$ 1,324 
$ 1,091 
Commodity derivative instruments, net
 
 
 
Derivatives, Fair Value [Line Items]
 
 
 
Loss on commodity derivatives, net
(1,806)
457 
(733)
Gain (loss) on derivatives, unrealized
10,221 
(71)
595 
Commodity derivative instruments, net |
Gains (losses) on commodity derivatives, net
 
 
 
Derivatives, Fair Value [Line Items]
 
 
 
Loss on commodity derivatives, net
(840)
1,610 
735 
Gain (loss) on derivatives, unrealized
0 
(300)
356 
Commodity derivative instruments, net |
Interest expense
 
 
 
Derivatives, Fair Value [Line Items]
 
 
 
Loss on commodity derivatives, net
0 
(240)
(433)
Gain (loss) on derivatives, unrealized
10,221 
215 
239 
Commodity derivative instruments, net |
Direct operating expenses
 
 
 
Derivatives, Fair Value [Line Items]
 
 
 
Loss on commodity derivatives, net
(966)
(913)
(1,035)
Gain (loss) on derivatives, unrealized
$ 0 
$ 0 
$ 0 
Fair Value Measurement (Details Textual) (3.77% Senior Notes, due 2031, Senior Notes)
Dec. 31, 2016
Sep. 30, 2016
3.77% Senior Notes, due 2031 |
Senior Notes
 
 
Debt Instrument [Line Items]
 
 
Debt instrument, interest rate, stated percentage
3.77% 
3.77% 
Property, Plant and Equipment, Net (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2016
Land
Dec. 31, 2015
Land
Dec. 31, 2016
Construction in progress
Dec. 31, 2015
Construction in progress
Dec. 31, 2016
Buildings and improvements
Dec. 31, 2015
Buildings and improvements
Dec. 31, 2016
Processing and treating plants
Dec. 31, 2015
Processing and treating plants
Dec. 31, 2016
Pipelines and compressors
Dec. 31, 2015
Pipelines and compressors
Dec. 31, 2016
Storage
Dec. 31, 2015
Storage
Dec. 31, 2016
Equipment
Dec. 31, 2015
Equipment
Dec. 31, 2016
Minimum
Dec. 31, 2016
Minimum
Buildings and improvements
Dec. 31, 2016
Minimum
Processing and treating plants
Dec. 31, 2016
Minimum
Pipelines and compressors
Dec. 31, 2016
Minimum
Storage
Dec. 31, 2016
Minimum
Equipment
Dec. 31, 2016
Maximum
Dec. 31, 2016
Maximum
Buildings and improvements
Dec. 31, 2016
Maximum
Processing and treating plants
Dec. 31, 2016
Maximum
Pipelines and compressors
Dec. 31, 2016
Maximum
Storage
Dec. 31, 2016
Maximum
Equipment
Property, Plant and Equipment, Net [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Useful Life (in years)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3 years 
4 years 
8 years 
3 years 
20 years 
5 years 
40 years 
40 years 
40 years 
40 years 
40 years 
20 years 
Property plant and equipment gross
$ 938,064 
$ 801,273 
$ 15,112 
$ 10,319 
$ 122,884 
$ 45,383 
$ 12,413 
$ 10,871 
$ 134,434 
$ 115,568 
$ 554,965 
$ 538,402 
$ 58,786 
$ 58,220 
$ 39,470 
$ 22,510 
 
 
 
 
 
 
 
 
 
 
 
 
Less accumulated depreciation
(182,607)
(145,963)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Property, plant and equipment, net
$ 755,457 
$ 655,310 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Property, Plant and Equipment, Net (Asset Impairments and Insurance Proceeds) (Details) (USD $)
3 Months Ended 12 Months Ended
Dec. 31, 2014
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Property, Plant and Equipment [Line Items]
 
 
 
 
Property plant and equipment gross
 
$ 938,064,000 
$ 801,273,000 
 
Depreciation
 
38,300,000 
31,900,000 
23,900,000 
Interest costs capitalized
 
2,700,000 
1,900,000 
800,000 
Loss on impairment of property, plant and equipment
99,900,000 
697,000 
0 
99,892,000 
Discount rate
9.50% 
 
 
 
Ala Tenn System
 
 
 
 
Property, Plant and Equipment [Line Items]
 
 
 
 
Property plant and equipment gross
 
$ 231,100,000 
$ 160,400,000 
 
Goodwill and Intangible Assets, Net (Details) (USD $)
3 Months Ended 12 Months Ended
Dec. 31, 2015
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Goodwill [Line Items]
 
 
 
 
Loss on impairment of goodwill
$ 118,600,000 
$ 0 
$ 118,600,000 
$ 0 
Amortization of intangible assets
 
4,600,000 
5,300,000 
4,100,000 
2017
 
4,600,000 
 
 
2018
 
4,600,000 
 
 
2019
 
4,600,000 
 
 
2020
 
4,600,000 
 
 
2021
 
4,600,000 
 
 
Thereafter
 
85,000,000 
 
 
Minimum
 
 
 
 
Goodwill [Line Items]
 
 
 
 
Useful life
 
10 years 0 months 0 days 
 
 
Maximum
 
 
 
 
Goodwill [Line Items]
 
 
 
 
Useful life
 
30 years 
 
 
Costar Midstream, L.L.C.
 
 
 
 
Goodwill [Line Items]
 
 
 
 
Loss on impairment of goodwill
95,000,000 
 
 
 
Lavaca
 
 
 
 
Goodwill [Line Items]
 
 
 
 
Loss on impairment of goodwill
$ 23,600,000 
 
 
 
Goodwill and Intangible Assets, Net Schedule of intangible assets (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2016
Dec. 31, 2015
Finite-Lived Intangible Assets [Line Items]
 
 
Gross carrying amount
$ 118,634 
$ 118,634 
Accumulated amortization
(10,736)
(5,785)
Net carrying amount
107,898 
112,849 
Customer relationships
 
 
Finite-Lived Intangible Assets [Line Items]
 
 
Gross carrying amount
53,400 
53,400 
Accumulated amortization
(5,696)
(3,124)
Net carrying amount
47,704 
50,276 
Dedicated acreage
 
 
Finite-Lived Intangible Assets [Line Items]
 
 
Gross carrying amount
53,350 
53,350 
Accumulated amortization
(4,439)
(2,661)
Net carrying amount
48,911 
50,689 
Collaborative arrangements
 
 
Finite-Lived Intangible Assets [Line Items]
 
 
Gross carrying amount
11,884 
11,884 
Accumulated amortization
(601)
0 
Net carrying amount
$ 11,283 
$ 11,884 
Investment in Unconsolidated Affiliates (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended 12 Months Ended 9 Months Ended 12 Months Ended 9 Months Ended 12 Months Ended 9 Months Ended 12 Months Ended 9 Months Ended 12 Months Ended 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2016
FPS
Dec. 31, 2015
FPS
Dec. 31, 2014
FPS
Sep. 18, 2015
FPS
Dec. 31, 2016
OGL
Dec. 31, 2015
OGL
Dec. 31, 2014
OGL
Dec. 31, 2016
Destin
Dec. 31, 2016
Destin
Dec. 31, 2015
Destin
Dec. 31, 2014
Destin
Apr. 25, 2016
Destin
Dec. 31, 2016
Tri-States
Dec. 31, 2016
Tri-States
Dec. 31, 2015
Tri-States
Dec. 31, 2014
Tri-States
Apr. 25, 2016
Tri-States
Dec. 31, 2016
Okeanos
Dec. 31, 2016
Okeanos
Dec. 31, 2015
Okeanos
Dec. 31, 2014
Okeanos
Apr. 27, 2016
Okeanos
Dec. 31, 2016
Wilprise
Dec. 31, 2016
Wilprise
Dec. 31, 2015
Wilprise
Dec. 31, 2014
Wilprise
Apr. 25, 2016
Wilprise
Dec. 31, 2016
MPOG
Dec. 31, 2015
MPOG
Dec. 31, 2014
MPOG
Schedule of Equity Method Investments [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ownership % at December 31, 2016
 
 
 
20.10% 
 
 
49.00% 
20.10% 
 
 
49.70% 
49.70% 
 
 
49.70% 
16.70% 
16.70% 
 
 
16.70% 
66.70% 
66.70% 
 
 
66.70% 
25.30% 
25.30% 
 
 
25.30% 
66.70% 
 
 
Investments in and Advances to Affiliates, at Fair Value [Roll Forward]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Equity method investments
$ 63,704 
$ 10,368 
$ 0 
$ 33,465 
$ 0 
$ 0 
 
$ 23,060 
$ 0 
$ 0 
 
$ 0 
$ 0 
$ 0 
 
 
$ 0 
$ 0 
$ 0 
 
 
$ 0 
$ 0 
$ 0 
 
 
$ 0 
$ 0 
$ 0 
 
$ 7,179 
$ 10,368 
$ 0 
Investment
270,742 
65,703 
12,000 
55,461 
40,559 
0 
 
3,255 
25,144 
0 
 
122,830 
0 
0 
 
 
56,681 
0 
0 
 
 
27,451 
0 
0 
 
 
5,064 
0 
0 
 
0 
0 
12,000 
Earnings in unconsolidated affiliates
40,158 
8,201 
348 
21,022 
5,457 
0 
 
9,260 
2,013 
0 
3,946 
3,946 
0 
0 
 
1,633 
1,633 
0 
0 
 
3,642 
3,642 
0 
0 
 
437 
437 
0 
0 
 
218 
731 
348 
Contributions
430 
0 
0 
0 
0 
0 
 
0 
0 
0 
 
0 
0 
0 
 
 
0 
0 
0 
 
 
0 
0 
0 
 
 
0 
0 
0 
 
430 
0 
0 
Distributions
(83,046)
(20,568)
(1,980)
(45,465)
(12,551)
0 
 
(10,125)
(4,097)
0 
 
(15,894)
0 
0 
 
 
(3,292)
0 
0 
 
 
(4,034)
0 
0 
 
 
(557)
0 
0 
 
(3,679)
(3,920)
(1,980)
Equity method investments
$ 291,988 
$ 63,704 
$ 10,368 
$ 64,483 
$ 33,465 
$ 0 
 
$ 25,450 
$ 23,060 
$ 0 
$ 110,882 
$ 110,882 
$ 0 
$ 0 
 
$ 55,022 
$ 55,022 
$ 0 
$ 0 
 
$ 27,059 
$ 27,059 
$ 0 
$ 0 
 
$ 4,944 
$ 4,944 
$ 0 
$ 0 
 
$ 4,148 
$ 7,179 
$ 10,368 
Investment in Unconsolidated Affiliates Narrative (Details) (USD $)
9 Months Ended 12 Months Ended
Dec. 31, 2016
Dec. 31, 2016
Schedule of Investments [Line Items]
 
 
Non-current assets
$ 12,000,000 
$ 12,000,000 
Wilprise
 
 
Schedule of Investments [Line Items]
 
 
Current assets
1,600,000 
1,600,000 
Liabilities
300,000 
300,000 
Members equity
13,300,000 
13,300,000 
Revenues
3,306,000 
5,100,000 
Operating expense
 
1,900,000 
Net income
$ 2,028,000 
$ 3,200,000 
Investment in Unconsolidated Affiliates Emerald transactions (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended 9 Months Ended 12 Months Ended 9 Months Ended 12 Months Ended 9 Months Ended 12 Months Ended 9 Months Ended 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2016
Destin
Dec. 31, 2016
Destin
Dec. 31, 2015
Destin
Dec. 31, 2014
Destin
Apr. 25, 2016
Destin
Dec. 31, 2016
Tri-States
Dec. 31, 2016
Tri-States
Dec. 31, 2015
Tri-States
Dec. 31, 2014
Tri-States
Apr. 25, 2016
Tri-States
Dec. 31, 2016
Okeanos
Dec. 31, 2016
Okeanos
Dec. 31, 2015
Okeanos
Dec. 31, 2014
Okeanos
Apr. 27, 2016
Okeanos
Dec. 31, 2016
Wilprise
Dec. 31, 2016
Wilprise
Dec. 31, 2015
Wilprise
Dec. 31, 2014
Wilprise
Apr. 25, 2016
Wilprise
Schedule of Equity Method Investments [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
 
 
$ 34,360 
 
 
 
 
$ 25,557 
 
 
 
 
$ 10,453 
 
 
 
 
$ 3,306 
$ 5,100 
 
 
 
Net income
 
 
 
8,272 
 
 
 
 
15,983 
 
 
 
 
1,911 
 
 
 
 
2,028 
3,200 
 
 
 
Ownership % at December 31, 2016
 
 
 
49.70% 
49.70% 
 
 
49.70% 
16.70% 
16.70% 
 
 
16.70% 
66.70% 
66.70% 
 
 
66.70% 
25.30% 
25.30% 
 
 
25.30% 
Partnership share of investee net income
 
 
 
4,109 
 
 
 
 
2,664 
 
 
 
 
1,274 
 
 
 
 
513 
 
 
 
 
Basis difference amortization
 
 
 
(163)
(163)
 
 
 
(1,031)
(1,031)
 
 
 
2,368 
2,368 
 
 
 
(76)
(76)
 
 
 
Earnings in unconsolidated affiliates
$ 40,158 
$ 8,201 
$ 348 
$ 3,946 
$ 3,946 
$ 0 
$ 0 
 
$ 1,633 
$ 1,633 
$ 0 
$ 0 
 
$ 3,642 
$ 3,642 
$ 0 
$ 0 
 
$ 437 
$ 437 
$ 0 
$ 0 
 
Accrued Expenses and Other Current Liabilities (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2016
Dec. 31, 2015
Payables and Accruals [Abstract]
 
 
Capital expenditures
$ 13,319 
$ 3,984 
Convertible preferred unit distributions
7,103 
0 
Current portion of asset retirement obligations
6,499 
6,822 
Accrued interest
5,743 
1,411 
Additional Blackwater acquisition consideration
5,000 
0 
Employee compensation
4,226 
3,114 
Due to related parties
3,895 
3,894 
Transaction costs
3,000 
0 
Deferred financing costs
2,743 
0 
Gas imbalances payable
1,098 
413 
Other
8,952 
3,675 
Accrued expenses and other current liabilities
$ 61,578 
$ 23,313 
Asset Retirement Obligations (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
 
 
Balance at beginning of period
$ 35,371 
$ 34,645 
Liabilities assumed
14,542 
0 
Revision in estimate
230 
0 
Expenditures
(858)
(91)
Accretion expense
1,577 
817 
Balance at end of period
50,862 
35,371 
Less: current portion
6,499 
6,822 
Noncurrent asset retirement obligation
44,363 
28,549 
Restricted cash
323,564 
5,037 
Assets Retirement Obligation
 
 
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
 
 
Restricted cash
5,000 
 
American Panther
 
 
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
 
 
Liabilities assumed
$ 14,300 
 
Debt Obligations (Outstanding Borrowings) (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2016
Credit Agreement
Dec. 31, 2015
Credit Agreement
Dec. 31, 2016
Senior Notes
8.50% Senior Notes, due 2021
Dec. 28, 2016
Senior Notes
8.50% Senior Notes, due 2021
Dec. 31, 2016
Senior Notes
3.77% Senior Notes, due 2031
Sep. 30, 2016
Senior Notes
3.77% Senior Notes, due 2031
Dec. 31, 2016
Other Debt
Dec. 31, 2015
Other Debt
Debt Instrument [Line Items]
 
 
 
 
 
 
 
 
 
 
Balance
$ 1,074,032 
$ 527,438 
$ 711,250 
$ 525,100 
$ 300,000 
 
$ 60,000 
 
$ 2,782 
$ 2,338 
Less unamortized deferred financing costs and discount
(11,036)
 
0 
 
(8,691)
 
(2,345)
 
0 
 
Subtotal
1,062,996 
 
711,250 
 
291,309 
 
57,655 
 
2,782 
 
Less current portion
(4,458)
(2,338)
0 
0 
0 
 
(1,676)
 
(2,782)
(2,338)
Non-current portion
$ 1,058,538 
$ 525,100 
$ 711,250 
$ 525,100 
$ 291,309 
 
$ 55,979 
 
$ 0 
$ 0 
Debt instrument, interest rate, stated percentage
 
 
 
 
8.50% 
8.50% 
3.77% 
3.77% 
 
 
Debt Obligations Credit Agreement (Details) (USD $)
0 Months Ended 12 Months Ended 0 Months Ended
Apr. 25, 2016
Dec. 31, 2016
Apr. 25, 2016
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2016
Minimum
Dec. 31, 2016
Maximum
Apr. 25, 2016
Federal Funds
Apr. 25, 2016
Eurodollar
Dec. 31, 2016
Senior Notes
3.77% Senior Notes, due 2031
Sep. 30, 2016
Senior Notes
3.77% Senior Notes, due 2031
Apr. 25, 2016
Fiscal Quarter Ending December 31, 2014
Fourth Amendment
Base Rate
Minimum
Apr. 25, 2016
Fiscal Quarter Ending December 31, 2014
Fourth Amendment
Base Rate
Maximum
Apr. 25, 2016
Fiscal Quarter Ending December 31, 2014
Fourth Amendment
Eurodollar
Minimum
Apr. 25, 2016
Fiscal Quarter Ending December 31, 2014
Fourth Amendment
Eurodollar
Maximum
Mar. 8, 2017
Subsequent Event
Mar. 7, 2017
Subsequent Event
Debt Instrument [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Line of credit facility, current borrowing capacity
 
 
$ 750,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Line of credit facility, maximum borrowing capacity upon increase
 
 
900,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
1,100,000,000 
 
Basis spread on variable rate
 
 
 
 
 
 
 
 
 
 
 
2.00% 
3.25% 
1.00% 
2.25% 
 
 
Debt instrument, interest rate, stated percentage
 
 
 
 
 
 
 
0.50% 
1.00% 
3.77% 
3.77% 
 
 
 
 
 
 
Unused capacity, commitment fee percentage
0.50% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ratio of indebtedness to net capital
 
4.07 
 
 
 
 
4.75 
 
 
 
 
 
 
 
 
 
 
Ratio of indebtedness to net capital, after allowed acquisition
 
 
 
 
 
 
5.25 
 
 
 
 
 
 
 
 
 
 
Interest coverage ratio
 
7.43 
 
 
 
2.5 
 
 
 
1.20 
 
 
 
 
 
 
 
Debt, weighted average interest rate
 
4.29% 
 
3.67% 
3.80% 
 
 
 
 
 
 
 
 
 
 
 
 
Letters of credit outstanding amount
 
7,400,000 
 
1,800,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revolving credit facility
 
711,300,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Line of credit facility, remaining borrowing capacity
 
31,300,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Line of credit facility, maximum borrowing capacity
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 900,000,000 
$ 750,000,000 
Debt Obligations 8.50% Senior Notes (Details) (USD $)
In Millions, unless otherwise specified
0 Months Ended 0 Months Ended 24 Months Ended
Dec. 28, 2016
Dec. 28, 2016
Dec. 28, 2016
Senior Notes
8.50% Senior Notes, due 2021
Dec. 31, 2016
Senior Notes
8.50% Senior Notes, due 2021
Dec. 28, 2016
Senior Notes
8.50% Senior Notes, due 2021
Dec. 14, 2018
Scenario, Forecast
Senior Notes
8.50% Senior Notes, due 2021
Dec. 14, 2018
Scenario, Forecast
Senior Notes
8.50% Senior Notes, due 2021
Maximum
Dec. 14, 2018
Scenario, Forecast
Senior Notes
8.50% Senior Notes, due 2021
Minimum
Debt Instrument [Line Items]
 
 
 
 
 
 
 
 
Debt instrument, interest rate, stated percentage
 
 
 
8.50% 
8.50% 
 
 
 
Proceeds from issuance of long-term debt
$ 294.0 
 
 
 
 
 
 
 
Debt issuance costs
 
(6.0)
 
 
 
 
 
 
Proceeds from issuance of senior long-term debt
 
 
291.3 
 
 
 
 
 
Additional debt issuance costs
 
$ (2.7)
 
 
 
 
 
 
Debt instrument, redemption price, percentage of principal amount redeemed
 
 
 
 
 
 
35.00% 
 
Debt instrument, redemption price, percentage
 
 
108.50% 
 
 
 
 
 
Debt instrument, redemption price, aggregate principal amount outstanding
 
 
 
 
 
 
 
65.00% 
Debt instrument, redemption price, equity offer period
 
 
 
 
 
180 days 
 
 
Debt Obligations Debt Instrument, Redemption Price (Details) (Senior Notes, 8.50% Senior Notes, due 2021)
0 Months Ended
Dec. 28, 2016
Debt Instrument [Line Items]
 
Debt instrument, redemption price, percentage
108.50% 
2018
 
Debt Instrument [Line Items]
 
Debt instrument, redemption price, percentage
104.25% 
2019
 
Debt Instrument [Line Items]
 
Debt instrument, redemption price, percentage
102.125% 
2020 and thereafter
 
Debt Instrument [Line Items]
 
Debt instrument, redemption price, percentage
100.00% 
Debt Obligations 3.77% Senior Notes (Details) (USD $)
0 Months Ended
Dec. 31, 2016
Dec. 28, 2016
Sep. 30, 2016
Senior Notes
3.77% Senior Notes, due 2031
Dec. 31, 2016
Senior Notes
3.77% Senior Notes, due 2031
Sep. 30, 2016
Senior Notes
3.77% Senior Notes, due 2031
Debt Instrument [Line Items]
 
 
 
 
 
Debt instrument
 
 
 
 
$ 60,000,000.0 
Debt instrument, interest rate, stated percentage
 
 
 
3.77% 
3.77% 
Repayments, average quarterly principal payment
 
 
1,100,000 
 
 
Proceeds from debt
 
 
57,700,000 
 
 
Debt issuance costs
 
6,000,000 
 
 
2,300,000 
Restricted cash and investments
24,500,000 
 
 
 
 
Interest coverage ratio
7.43 
 
 
1.20 
 
Debt instrument, fair value
 
 
 
$ 54,600,000 
 
Partners' Capital (Units Outstanding) (Details) (USD $)
In Thousands, except Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Apr. 15, 2013
Increase (Decrease) in Partners' Capital [Roll Forward]
 
 
 
 
Partners' capital account, beginning balance
$ 169,712 
 
 
 
Paid in kind unit distributions
90,624 
71,737 
43,383 
 
Partners' capital account, ending balance
334,090 
169,712 
 
 
Series A
 
 
 
 
Increase (Decrease) in Partners' Capital [Roll Forward]
 
 
 
 
Partners' capital account, beginning balance (in shares)
9,210,000 
5,745,000 
5,279,000 
5,142,857 
Partners' capital account, beginning balance
169,712 
107,965 
94,811 
 
Issuance of units (in shares)
0 
2,571,000 
0 
 
Issuance of units
0 
44,769 
0 
 
Paid in kind unit distributions
19,123 
16,978 
15,812 
 
Partners' capital account, ending balance (in shares)
10,107,000 
9,210,000 
5,745,000 
5,142,857 
Partners' capital account, ending balance
181,386 
169,712 
107,965 
 
Series C
 
 
 
 
Increase (Decrease) in Partners' Capital [Roll Forward]
 
 
 
 
Partners' capital account, beginning balance (in shares)
0 
0 
0 
 
Partners' capital account, beginning balance
0 
0 
0 
 
Issuance of units (in shares)
8,571,000 
0 
0 
 
Issuance of units
115,457 
0 
0 
 
Paid in kind unit distributions
9,487 
0 
0 
 
Partners' capital account, ending balance (in shares)
8,792,000 
0 
0 
 
Partners' capital account, ending balance
118,229 
0 
0 
 
Series D
 
 
 
 
Increase (Decrease) in Partners' Capital [Roll Forward]
 
 
 
 
Partners' capital account, beginning balance (in shares)
0 
0 
0 
 
Partners' capital account, beginning balance
0 
0 
0 
 
Issuance of units (in shares)
2,333,000 
0 
0 
 
Issuance of units
34,475 
0 
0 
 
Paid in kind unit distributions
963 
0 
0 
 
Partners' capital account, ending balance (in shares)
2,333,000 
0 
0 
 
Partners' capital account, ending balance
34,475 
0 
0 
 
Paid-in-kind units
 
 
 
 
Increase (Decrease) in Partners' Capital [Roll Forward]
 
 
 
 
Paid in kind unit distributions
14,446 
18,351 
15,374 
 
Paid-in-kind units |
Series A
 
 
 
 
Increase (Decrease) in Partners' Capital [Roll Forward]
 
 
 
 
Paid in kind unit distributions (in shares)
897,000 
894,000 
466,000 
 
Paid in kind unit distributions
11,674 
16,978 
13,154 
 
Paid-in-kind units |
Series C
 
 
 
 
Increase (Decrease) in Partners' Capital [Roll Forward]
 
 
 
 
Paid in kind unit distributions (in shares)
221,000 
0 
0 
 
Paid in kind unit distributions
2,772 
0 
0 
 
Paid-in-kind units |
Series D
 
 
 
 
Increase (Decrease) in Partners' Capital [Roll Forward]
 
 
 
 
Paid in kind unit distributions (in shares)
0 
0 
0 
 
Paid in kind unit distributions
$ 0 
$ 0 
$ 0 
 
Partners' Capital Outstanding Units (Details)
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
General Partner
 
 
 
Increase (Decrease) in Partners' Capital [Roll Forward]
 
 
 
Partners' capital account, beginning balance (in shares)
536,000 
392,000 
185,000 
Issuance of units (in shares)
144,000 
144,000 
207,000 
Partners' capital account, ending balance (in shares)
680,000 
536,000 
392,000 
Limited Partner
 
 
 
Increase (Decrease) in Partners' Capital [Roll Forward]
 
 
 
Partners' capital account, beginning balance (in shares)
30,427,000 
22,670,000 
7,414,000 
Issuance of units (in shares)
248,000 
7,500,000 
14,915,000 
Conversion, Exerise of units, warrants (in shares)
1,350,000 
152,000 
300,000 
Return of escrow units (in shares)
(1,034,000)
 
 
Partners' capital account, ending balance (in shares)
31,237,000 
30,427,000 
22,670,000 
Limited Partner |
Long Term Incentive Plan
 
 
 
Increase (Decrease) in Partners' Capital [Roll Forward]
 
 
 
Issuance of units (in shares)
246,000 
105,000 
41,000 
Series B
 
 
 
Increase (Decrease) in Partners' Capital [Roll Forward]
 
 
 
Partners' capital account, beginning balance (in shares)
1,350,000 
1,255,000 
0 
Issuance of units (in shares)
 
95,000 
87,000 
Conversion, Exerise of units, warrants (in shares)
(1,350,000)
 
 
Partners' capital account, ending balance (in shares)
0 
1,350,000 
1,255,000 
Okeanos
 
 
 
Increase (Decrease) in Partners' Capital [Roll Forward]
 
 
 
Issuance of units (in shares)
1,168,000 
 
 
Convertible Preferred Units Series A-1 Convertible Preferred Units (Details) (USD $)
In Thousands, except Share data, unless otherwise specified
0 Months Ended 12 Months Ended
Dec. 31, 2016
Apr. 25, 2016
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2016
Series A
Apr. 15, 2013
Series A
Dec. 31, 2016
Series A
Dec. 31, 2015
Series A
Dec. 31, 2014
Series A
Dec. 31, 2013
Series A
Apr. 15, 2013
Series A
High Point
Class of Stock [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Partnership cancellation of subordinated units (percent)
 
 
 
 
 
90.00% 
 
 
 
 
 
Issuance of Series C Units and Warrant in connection with the Emerald Transactions
$ 120,000 
$ 120,000 
$ 0 
$ 0 
 
 
 
 
 
 
$ 15,000 
Partners' capital account (in shares)
 
 
 
 
 
5,142,857 
10,107,000 
9,210,000 
5,745,000 
5,279,000 
 
Partners' capital account (in dollars per share)
 
 
 
 
 
$ 0.50 
 
 
 
 
 
Shares issued upon conversion (in shares)
 
 
 
 
 
1 
 
 
 
 
 
Investment options, exercise price (in dollars per share)
 
 
 
 
$ 15.87 
 
$ 15.87 
 
 
 
 
Partners' Capital Textual (Details)
12 Months Ended
Dec. 31, 2016
Equity [Abstract]
 
General partner interest
1.30% 
Limited partner interest
98.70% 
Convertible Preferred Units Series A-2 Convertible Preferred Units (Details) (Series A-2, USD $)
0 Months Ended 12 Months Ended
Dec. 31, 2016
Dec. 31, 2016
Dec. 31, 2015
Jul. 27, 2015
Class of Stock [Line Items]
 
 
 
 
Issuance of units
 
 
$ 45,000,000 
 
Investment options, exercise price (in dollars per share)
$ 15.87 
$ 17.50 
 
 
Call right defined acquisition, value
 
 
 
$ 100,000,000 
Magnolia Infrastructure Partners, LLC |
Issuance of Preferred Units
 
 
 
 
Class of Stock [Line Items]
 
 
 
 
Partners' capital account, units, sold in private placement (in shares)
 
 
2,571,430 
 
Partners' Capital Series B Units (Details) (USD $)
12 Months Ended 0 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Oct. 8, 2015
Sep. 18, 2015
Sep. 15, 2015
Aug. 15, 2014
Jan. 29, 2014
Dec. 31, 2015
Series B
Dec. 31, 2014
Series B
Jan. 31, 2014
Series B
Jan. 31, 2014
Series B
Feb. 1, 2016
Series B
Dec. 31, 2015
Dividend Paid
Series B
Dec. 31, 2014
Dividend Paid
Series B
Class of Stock [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Limited partners, units issued (in shares)
31,237,000 
30,427,000 
151,937 
7,500,000 
7,500,000 
4,622,352 
3,400,000 
 
 
1,168,225 
 
 
94,923 
86,461 
Issuance of units
 
 
 
 
 
 
 
 
 
 
$ 30,000,000 
 
 
 
Shares issued upon conversion (in shares)
 
 
 
 
 
 
 
 
 
 
 
1 
 
 
Fair value, paid in kind distributions
 
 
 
 
 
 
 
$ 1,400,000 
$ 2,200,000 
 
 
 
 
 
Convertible Preferred Units Series C (Details) (USD $)
0 Months Ended 12 Months Ended 0 Months Ended
Apr. 25, 2016
Dec. 31, 2016
Series C
Apr. 25, 2016
Series C
Dec. 31, 2016
Series C
Dec. 31, 2015
Series C
Dec. 31, 2014
Series C
Apr. 25, 2016
Series C
Apr. 25, 2017
Scenario, Forecast
Series C
Apr. 25, 2016
Issuance of Preferred Units
ArcLight
Series C
Class of Stock [Line Items]
 
 
 
 
 
 
 
 
 
Issuance of units (in shares)
 
 
 
8,571,000 
0 
0 
 
 
8,571,429 
Investment options, exercise price (in dollars per share)
 
$ 13.95 
$ 14.00 
 
 
 
 
 
 
Number of securities called by warrants (in shares)
800,000 
 
 
 
 
 
800,000 
 
 
Exercise price of warrants (in dollars per share)
$ 7.25 
 
 
 
 
 
$ 7.25 
 
 
Warrant, exercisable period
 
 
7 years 
7 years 
 
 
 
 
 
Number of units in warrant calculation (in shares)
 
 
 
 
 
 
 
400,000 
 
Stipulated deduction in warrant calculation
 
 
 
 
 
 
 
$ 45,000,000 
 
Fair value of warrant unit (in dollars per share)
 
 
 
$ 4.41 
 
 
 
 
 
Expected dividend rate
 
 
 
18.00% 
 
 
 
 
 
Expected volatility rate
 
 
 
42.00% 
 
 
 
 
 
Issuance and exercise of warrants
 
 
 
$ 4,500,000 
 
 
 
 
 
Partners' Capital Equity Offerings (Details) (USD $)
0 Months Ended 12 Months Ended 12 Months Ended 0 Months Ended
Oct. 8, 2015
Sep. 15, 2015
Aug. 15, 2014
Jan. 29, 2014
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Oct. 8, 2015
Sep. 18, 2015
Sep. 15, 2015
Aug. 15, 2014
Jan. 29, 2014
Dec. 31, 2016
Costar Midstream, L.L.C.
Dec. 31, 2015
Costar Midstream, L.L.C.
Dec. 31, 2014
Costar Midstream, L.L.C.
Dec. 31, 2016
Limited Partner
Dec. 31, 2015
Limited Partner
Dec. 31, 2014
Limited Partner
Oct. 14, 2014
Limited Partner
Costar Midstream, L.L.C.
Feb. 29, 2016
Interest rate swap
Class of Stock [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Aggregate offering price
 
 
 
 
$ 100,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Partners' capital account, units, sold in public offering (in shares)
 
 
 
 
248,561 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proceeds from issuance IPO
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2,900,000 
 
 
 
 
Limited partners' offering costs
 
 
 
 
300,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Authorized amount remaining
 
 
 
 
96,800,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Limited partners, units issued (in shares)
 
 
 
 
31,237,000 
30,427,000 
 
151,937 
7,500,000 
7,500,000 
4,622,352 
3,400,000 
 
 
 
 
 
 
 
 
Sale of stock (in dollars per share)
 
 
 
 
 
 
 
$ 11.31 
 
$ 11.31 
$ 25.8074999481 
$ 26.75 
 
 
 
 
 
 
 
 
Issuance of common units, net of offering costs
1,700,000 
81,000,000 
119,300,000 
86,900,000 
 
 
 
 
 
 
 
 
 
 
 
 
82,421,000 
351,551,000 
 
 
Common unit issuance related to Costar Acquisition
 
 
 
 
 
 
 
 
 
 
 
 
$ 0 
$ 0 
$ 147,296,000 
 
 
 
$ 6,892,931 
 
Escrowed units returned to partnership (in shares)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,034,483 
Distribution declared per common unit (in dollars per share)
 
 
$ 0.4625 
 
$ 1.71 
$ 1.89 
$ 1.85 
 
 
 
 
 
 
 
 
 
 
 
 
 
Convertible Preferred Units Series D (Details) (USD $)
Dec. 31, 2016
Apr. 25, 2016
Dec. 31, 2015
Oct. 8, 2015
Sep. 18, 2015
Sep. 15, 2015
Aug. 15, 2014
Jan. 29, 2014
Dec. 31, 2016
Series D
Oct. 31, 2016
Series D
Class of Stock [Line Items]
 
 
 
 
 
 
 
 
 
 
Limited partners, units issued (in shares)
31,237,000 
 
30,427,000 
151,937 
7,500,000 
7,500,000 
4,622,352 
3,400,000 
 
2,333,333 
Shares issued (in dollars per share)
 
 
 
 
 
 
 
 
 
$ 15.00 
Units issued, closing fee
 
 
 
 
 
 
 
 
 
1.50% 
Number of securities called by warrants (in shares)
 
800,000 
 
 
 
 
 
 
 
700,000 
Exercise price of warrants (in dollars per share)
 
$ 7.25 
 
 
 
 
 
 
$ 14.98 
$ 22.00 
Partners' capital account (in dollars per share)
 
 
 
 
 
 
 
 
$ 0.4125 
 
Shares issued upon conversion (in shares)
 
 
 
 
 
 
 
 
1 
 
Series D call right, ratio multiplier
 
 
 
 
 
 
 
 
 
1.03 
Partners' Capital General Partner Units (Details) (USD $)
In Millions, except Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Class of Stock [Line Items]
 
 
General partners' capital account, period distribution amount
$ 2.0 
$ 1.9 
General partners' interest units issued (in shares)
680,000 
536,000 
General Partner
 
 
Class of Stock [Line Items]
 
 
General partners' interest units issued (in shares)
143,900 
143,517 
Partners' Capital Distributions (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Class of Stock [Line Items]
 
 
 
Paid in kind unit distributions
$ 90,624 
$ 71,737 
$ 43,383 
Series A
 
 
 
Class of Stock [Line Items]
 
 
 
Paid in kind unit distributions
19,123 
16,978 
15,812 
Series B
 
 
 
Class of Stock [Line Items]
 
 
 
Paid in kind unit distributions
0 
1,373 
2,220 
Series C
 
 
 
Class of Stock [Line Items]
 
 
 
Paid in kind unit distributions
9,487 
0 
0 
Series D
 
 
 
Class of Stock [Line Items]
 
 
 
Paid in kind unit distributions
963 
0 
0 
Limited Partner
 
 
 
Class of Stock [Line Items]
 
 
 
Paid in kind unit distributions
53,500 
46,597 
22,656 
General Partner
 
 
 
Class of Stock [Line Items]
 
 
 
Paid in kind unit distributions
7,551 
6,789 
2,695 
Paid
 
 
 
Class of Stock [Line Items]
 
 
 
Paid in kind unit distributions
64,075 
53,386 
28,009 
Paid |
Series A
 
 
 
Class of Stock [Line Items]
 
 
 
Paid in kind unit distributions
4,935 
0 
2,658 
Paid |
Series C
 
 
 
Class of Stock [Line Items]
 
 
 
Paid in kind unit distributions
3,089 
0 
0 
Paid |
Series D
 
 
 
Class of Stock [Line Items]
 
 
 
Paid in kind unit distributions
0 
0 
0 
Paid |
Limited Partner
 
 
 
Class of Stock [Line Items]
 
 
 
Paid in kind unit distributions
53,500 
46,597 
22,656 
Paid |
General Partner
 
 
 
Class of Stock [Line Items]
 
 
 
Paid in kind unit distributions
2,551 
6,789 
2,695 
Accrued
 
 
 
Class of Stock [Line Items]
 
 
 
Paid in kind unit distributions
7,103 
0 
0 
Accrued |
Series A
 
 
 
Class of Stock [Line Items]
 
 
 
Paid in kind unit distributions
2,514 
0 
0 
Accrued |
Series C
 
 
 
Class of Stock [Line Items]
 
 
 
Paid in kind unit distributions
3,626 
0 
0 
Accrued |
Series D
 
 
 
Class of Stock [Line Items]
 
 
 
Paid in kind unit distributions
963 
0 
0 
Accrued |
Limited Partner
 
 
 
Class of Stock [Line Items]
 
 
 
Paid in kind unit distributions
0 
0 
0 
Paid-in-kind units
 
 
 
Class of Stock [Line Items]
 
 
 
Paid in kind unit distributions
14,446 
18,351 
15,374 
Paid-in-kind units |
Series A
 
 
 
Class of Stock [Line Items]
 
 
 
Paid in kind unit distributions
11,674 
16,978 
13,154 
Paid-in-kind units |
Series B
 
 
 
Class of Stock [Line Items]
 
 
 
Paid in kind unit distributions
0 
1,373 
2,220 
Paid-in-kind units |
Series C
 
 
 
Class of Stock [Line Items]
 
 
 
Paid in kind unit distributions
2,772 
0 
0 
Paid-in-kind units |
Series D
 
 
 
Class of Stock [Line Items]
 
 
 
Paid in kind unit distributions
0 
0 
0 
Accrued |
General Partner
 
 
 
Class of Stock [Line Items]
 
 
 
Paid in kind unit distributions
0 
0 
0 
Additional Blackwater acquisition consideration
 
 
 
Class of Stock [Line Items]
 
 
 
Paid in kind unit distributions
5,000 
0 
0 
Additional Blackwater acquisition consideration |
General Partner
 
 
 
Class of Stock [Line Items]
 
 
 
Paid in kind unit distributions
$ 5,000 
$ 0 
$ 0 
Partners' Capital Distributions Textual (Details)
0 Months Ended 3 Months Ended 12 Months Ended 0 Months Ended 12 Months Ended
Aug. 15, 2014
Dec. 31, 2014
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Jan. 26, 2017
Subsequent Event
Dec. 31, 2016
Minimum
Dec. 31, 2016
Maximum
Class of Stock [Line Items]
 
 
 
 
 
 
 
 
Distribution declared per common unit (in dollars per share)
$ 0.4625 
 
$ 1.71 
$ 1.89 
$ 1.85 
$ 0.4125 
 
 
Distribution made to limited partner (in dollars per share)
 
 
 
 
 
$ 1.65 
 
 
Fair value input, option value (in dollars per share)
 
 
 
 
 
 
$ 0.02 
$ 9.68 
Discount rate
 
9.50% 
 
 
 
 
5.57% 
10.00% 
Fair Value input, distribution growth rate
 
 
1.00% 
 
 
 
 
 
Net Income (Loss) per Limited Partner Unit (Details) (USD $)
In Thousands, except Per Share data, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2016
Sep. 30, 2016
Jun. 30, 2016
Mar. 31, 2016
Sep. 30, 2015
Jun. 30, 2015
Mar. 31, 2015
Dec. 31, 2014
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Net income (loss) from continuing operations
$ 4,210 
$ 2,679 
$ (3,591)
$ (3,964)
$ (4,574)
$ (2,002)
$ 835 
$ (121,634)
$ (666)
$ (127,375)
$ (97,195)
Less: Net income attributable to noncontrolling interests
 
 
 
 
34 
32 
14 
(55)
2,804 
25 
214 
Net (income) loss from continuing operations attributable to the Partnership
 
 
 
 
 
 
 
 
(3,470)
(127,400)
(97,409)
Distributions on Units
 
 
 
 
 
 
 
 
19,138 
16,978 
14,492 
Distributions
 
 
 
 
 
 
 
 
90,624 
71,737 
43,383 
General partner's share in undistributed loss
 
 
 
 
 
 
 
 
(1,140)
(2,569)
(1,820)
Net loss from continuing operations attributable to Limited Partners
 
 
 
 
 
 
 
 
(34,468)
(149,972)
(114,995)
Net loss from discontinued operations attributable to Limited Partners
 
 
 
 
 
 
 
 
0 
(80)
(603)
Net loss attributable to Limited Partners
 
 
 
 
 
 
 
 
(34,468)
(150,052)
(115,598)
Weighted average number of common units used in computation of Limited Partners' net loss per common unit - basic and diluted (in shares)
 
 
 
 
 
 
 
 
31,043 
24,983 
13,472 
Limited Partners' net loss from continuing operations per unit (basic and diluted) (in dollars per share)
$ (0.20)
$ (0.22)
$ (0.36)
$ (0.33)
$ (0.48)
$ (0.35)
$ (0.19)
$ (4.16)
$ (1.11)
$ (6.00)
$ (8.54)
Limited Partners' net income (loss) from discontinued operations per unit (basic and diluted) (in dollars per share)
 
 
 
 
 
 
 
 
$ 0.00 
$ 0.00 
$ (0.04)
Limited partners’ net income (loss) per unit (basic and diluted) (in dollars per share)
$ (0.20)
$ (0.22)
$ (0.36)
$ (0.33)
$ (0.48)
$ (0.35)
$ (0.19)
$ (4.16)
$ (1.11)
$ (6.00)
$ (8.58)
Series C Preferred Stock
 
 
 
 
 
 
 
 
 
 
 
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Distributions on Units
 
 
 
 
 
 
 
 
9,487 
0 
0 
Series D Preferred Stock
 
 
 
 
 
 
 
 
 
 
 
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Distributions on Units
 
 
 
 
 
 
 
 
963 
0 
0 
Series B
 
 
 
 
 
 
 
 
 
 
 
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Distributions
 
 
 
 
 
 
 
 
0 
1,373 
2,220 
General Partner
 
 
 
 
 
 
 
 
 
 
 
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Distributions
 
 
 
 
 
 
 
 
7,551 
6,789 
2,695 
General Partner |
Dividend Declared
 
 
 
 
 
 
 
 
 
 
 
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Distributions
 
 
 
 
 
 
 
 
$ 2,550 
$ 6,790 
$ 2,694 
Long Term Incentive Plan (Textual) (Details) (USD $)
1 Months Ended 12 Months Ended 12 Months Ended 3 Months Ended 1 Months Ended
Aug. 31, 2016
Dec. 31, 2015
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Feb. 11, 2016
Dec. 31, 2013
Dec. 31, 2016
Performance Shares
Dec. 31, 2015
Performance Shares
Sep. 30, 2016
Operating Expense
Performance Shares
Nov. 30, 2015
Operating Expense
Performance Shares
Sep. 30, 2016
September 2016
Subsequent Event [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
Long-term incentive plan, increase in available awards (in shares)
 
 
 
 
 
6,000,000 
 
 
 
 
 
 
Long term incentive plan available for future grant (in shares)
 
15,484 
5,017,528 
15,484 
688,976 
 
 
 
 
 
 
 
Grants issued under long term incentive plan
 
 
25.00% 
 
 
 
 
 
 
 
 
 
Granted (in shares)
30,000 
200,000 
75,000,000 
200,000,000 
 
 
 
 
 
 
 
45,000 
Award vesting period
 
3 years 
 
 
 
 
 
 
 
 
 
 
Equity compensation expense
 
 
$ 3,600,000 
$ 3,800,000 
$ 1,500,000 
 
 
$ 900,000 
$ 500,000 
$ 1,000,000 
 
 
Total fair value of vested units
 
 
2,400,000 
2,600,000 
1,400,000 
 
 
 
 
 
 
 
Compensation cost not yet recognized
 
 
4,200,000 
 
 
 
 
100,000 
 
 
 
 
Weighted average period cost recognized
 
 
2 years 2 months 12 days 
 
 
 
 
 
 
 
 
 
Aggregate intrinsic value, nonvested
 
4,609,000 
22,674,000 
4,609,000 
3,964,000 
 
2,045,000 
1,500,000 
 
 
2,000,000 
 
Granted (in dollars per share)
 
$ 7.50 
$ 13.13 
$ 7.50 
 
 
 
 
 
 
 
 
Options, outstanding, weighted average exercise price (in dollars per share)
$ 12.00 
$ 7.50 
$ 9.03 
$ 7.50 
$ 0.00 
 
 
 
 
 
 
$ 13.88 
Award vesting rights
 
 
 
 
 
 
 
 
 
 
 
25.00% 
Compensation not yet recognized, stock options
 
 
$ 200,000 
 
 
 
 
 
 
 
 
 
Long-Term Incentive Plan (Unit-based Awards) (Details) (USD $)
In Thousands, except Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
 
 
 
 
Outstanding shares (in shares)
569,759 
201,132 
75,529 
 
Granted (in shares)
1,374,226 
546,329 
188,946 
 
Forfeited (in shares)
(411,794)
(31,298)
(12,009)
 
Vested (in shares)
(286,348)
(146,404)
(51,334)
 
Outstanding shares (in shares)
1,245,843 
569,759 
201,132 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Intrinsic Value, Amount Per Share [Abstract]
 
 
 
 
Outstanding shares (in dollars per share)
$ 13.15 
$ 19.85 
$ 17.62 
 
Granted (in dollars per share)
$ 2.14 
$ 12.25 
$ 20.80 
 
Forfeited (in dollars per share)
$ (2.60)
$ (15.62)
$ (18.28)
 
Vested (in dollars per share)
$ (12.18)
$ (18.47)
$ (20.89)
 
Outstanding shares (in dollars per share)
$ 4.72 
$ 13.15 
$ 19.85 
 
Aggregate intrinsic value, nonvested
$ 22,674 
$ 4,609 
$ 3,964 
$ 2,045 
Long-Term Incentive Plan Assumptions (Details)
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
 
 
Weighted average common unit price volatility
61.10% 
47.00% 
Expected distribution yield
12.60% 
26.30% 
Weighted average expected term (in years)
4 years 1 month 6 days 
3 years 6 months 
Weighted average risk-free rate
1.10% 
1.30% 
Long-Term Incentive Plan Option Grant Awards (Details) (USD $)
In Thousands, except Share data, unless otherwise specified
0 Months Ended 1 Months Ended 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Aug. 31, 2016
Dec. 31, 2015
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Number of Shares [Roll Forward]
 
 
 
 
 
 
 
Outstanding beginning balance (in shares)
275,000,000 
200,000,000 
 
 
200,000,000 
0 
 
Granted (in shares)
 
 
30,000 
200,000 
75,000,000 
200,000,000 
 
Vested (in shares)
 
 
 
 
0 
0 
 
Forfeited (in shares)
 
 
 
 
0 
0 
 
Outstanding ending balance (in shares)
 
 
 
200,000,000 
275,000,000 
200,000,000 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Abstract]
 
 
 
 
 
 
 
Outstanding beginning balance (in dollars per share)
$ 9.03 
$ 7.50 
 
 
$ 7.50 
$ 0.00 
 
Granted (in dollars per share)
 
 
 
$ 7.50 
$ 13.13 
$ 7.50 
 
Vested (in dollars per share)
 
 
 
 
$ 0.00 
$ 0.00 
 
Forfeited (in dollars per share)
 
 
 
 
$ 0.00 
$ 0.00 
 
Outstanding ending balance (in dollars per share)
 
 
$ 12.00 
$ 7.50 
$ 9.03 
$ 7.50 
 
Weighted-Average Grant Date Fair Value per Unit (in dollars per share)
 
 
 
$ 0.33 
$ 0.96 
$ 0.33 
$ 0.00 
Weighted-Average Grant Date Fair Value per Unit (in dollars per share)
 
 
 
 
$ 2.65 
$ 0.33 
 
Aggregate Intrinsic Value
 
 
 
$ 118 
$ 2,522 
$ 118 
$ 0 
Weighted Average Remaining Contractual Life
4 years 11 months 23 days 
4 years 2 months 12 days 
 
 
 
 
 
Income Taxes Income Tax (Expense) Benefit (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Income Tax Disclosure [Abstract]
 
 
 
Current income tax expense
$ 0 
$ 0 
$ (10)
Deferred income tax expense
$ (2,057)
$ (1,134)
$ (547)
Effective income tax rate
147.90% 
0.90% 
0.60% 
Income Taxes Narrative (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Income Tax Disclosure [Abstract]
 
 
 
US Federal statutory tax rate
34.00% 
34.00% 
34.00% 
Operating Loss Carryforwards
$ 16.1 
 
 
Income Taxes Income Tax Expense (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Income Tax Disclosure [Abstract]
 
 
 
Net income (loss) before income tax expense
$ 1,391 
$ (126,241)
$ (96,638)
US Federal statutory tax rate
34.00% 
34.00% 
34.00% 
Federal income tax (expense) benefit at statutory rate
(473)
42,922 
32,857 
Partnership loss not subject to income tax
(1,300)
(43,812)
(33,216)
State and local tax (benefit) expense
(279)
(103)
(159)
Other
(5)
(141)
(39)
Income tax expense
$ (2,057)
$ (1,134)
$ (557)
Income Taxes Deferred Tax Assets and Liabilities (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2016
Dec. 31, 2015
Deferred tax assets:
 
 
Net operating loss carryforwards
$ 6,300 
$ 7,570 
Other
577 
493 
Total deferred tax assets
6,877 
8,063 
Deferred tax liabilities:
 
 
Property, plant and equipment
(14,735)
(13,889)
Deferred income tax liability, net
$ (7,858)
$ (5,826)
Commitments and Contingencies (Details Textual) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
 
 
 
Business exit costs
$ 9.1 
 
 
Operating leases
$ 13.4 
$ 12.0 
$ 5.8 
Commitments and Contingencies (Contractual Obligations) (Details) (USD $)
Dec. 31, 2016
Future Non Cancelable Commitment [Line Items]
 
2017
$ 12,320,000 
2018
3,217,000 
2019
716,030,000 
2020
4,380,000 
2021
306,322,000 
Thereafter
106,353,000 
Total
1,148,622,000 
Asset Retirement Obligation
 
Future Non Cancelable Commitment [Line Items]
 
2017
6,499,000 
2018
0 
2019
0 
2020
0 
2021
0 
Thereafter
44,363,000 
Total
50,862,000 
Other (1)
 
Future Non Cancelable Commitment [Line Items]
 
2017
4,144,000 
2018
2,411,000 
2019
2,547,000 
2020
2,081,000 
2021
1,892,000 
Thereafter
13,435,000 
Total
26,510,000 
Sublease rentals
200,000 
Credit Agreement
 
Future Non Cancelable Commitment [Line Items]
 
2017
0 
2018
0 
2019
711,250,000 
2020
0 
2021
0 
Thereafter
0 
Total
711,250,000 
Senior Notes |
8.50% Senior Notes, due 2021
 
Future Non Cancelable Commitment [Line Items]
 
2017
0 
2018
0 
2019
0 
2020
0 
2021
300,000,000 
Thereafter
0 
Total
300,000,000 
Senior Notes |
3.77% Senior Notes, due 2031
 
Future Non Cancelable Commitment [Line Items]
 
2017
1,677,000 
2018
806,000 
2019
2,233,000 
2020
2,299,000 
2021
4,430,000 
Thereafter
48,555,000 
Total
$ 60,000,000 
Related- Party Transactions (Details Textual) (USD $)
12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Sep. 30, 2016
Blackwater
Dec. 31, 2013
Blackwater
Dec. 31, 2016
American Midstream, LLC
Dec. 31, 2015
American Midstream, LLC
Dec. 31, 2014
American Midstream, LLC
Dec. 31, 2016
Affiliated Entity
Dec. 31, 2016
Other Current Liabilities
General Partner
Dec. 31, 2015
Other Current Liabilities
General Partner
Dec. 31, 2016
American Panther
Affiliated Entity
Apr. 15, 2016
American Panther
Dec. 31, 2016
American Panther
Affiliated Entity
Dec. 31, 2016
CIMA Energy Ltd
Vice President
Dec. 31, 2015
CIMA Energy Ltd
Vice President
Dec. 31, 2014
CIMA Energy Ltd
Vice President
Related Party Transaction [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Range of outcomes
 
 
 
 
$ 5,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued expenses
 
 
 
5,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
Administrative and operational service expenses
 
 
 
 
 
41,600,000 
28,700,000 
22,600,000 
 
 
 
 
 
 
 
 
 
Management fees revenue
800,000 
1,400,000 
900,000 
 
 
 
 
 
400,000 
 
 
 
 
 
 
 
 
Related party transaction, due from related party
 
 
 
 
 
 
 
 
 
3,900,000 
3,800,000 
 
 
 
 
 
 
Transaction expenses
 
 
 
 
 
 
 
 
1,000,000 
 
 
 
 
 
 
 
 
Noncontrolling interest, ownership percentage by parent
 
 
 
 
 
 
 
 
 
 
 
 
60.00% 
60.00% 
 
 
 
Direct operating expenses
61,861,000 
60,737,000 
45,919,000 
 
 
 
 
 
 
 
 
800,000 
 
 
 
 
 
Corporate expenses
54,223,000 
29,818,000 
24,422,000 
 
 
 
 
 
 
 
 
400,000 
 
 
 
 
 
Revenue from related parties
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3,600,000 
6,200,000 
10,100,000 
Related party transaction, purchases from related party
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 4,300,000 
$ 5,900,000 
$ 3,700,000 
Supplemental Cash Flow Information (Details) (USD $)
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Apr. 25, 2016
Class of Stock [Line Items]
 
 
 
 
Interest payments, net of capitalized interest
$ 16,922,000 
$ 12,013,000 
$ 6,726,000 
 
Increase (decrease) in accrued property, plant and equipment purchases
7,353,000 
(25,637,000)
31,390,000 
 
Issuance of Series C Units and Warrant in connection with the Emerald Transactions
120,000,000 
0 
0 
120,000,000 
Accrued distributions
7,103,000 
0 
0 
 
Series C Preferred Stock
 
 
 
 
Class of Stock [Line Items]
 
 
 
 
Accrued distributions
14,446,000 
16,978,000 
13,154,000 
 
Limited Partner Series B Convertible Units
 
 
 
 
Class of Stock [Line Items]
 
 
 
 
Dividends, paid-in-kind
0 
1,373,000 
2,220,000 
 
Costar Midstream, L.L.C.
 
 
 
 
Class of Stock [Line Items]
 
 
 
 
Accrued distributions
5,000,000 
0 
0 
 
Cancellation of escrow units
6,817,000 
0 
0 
 
Common unit issuance related to Costar Acquisition
$ 0 
$ 0 
$ 147,296,000 
 
Reporting Segments Narrative (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Gathering And Processing
 
 
 
Revenue, Major Customer
 
 
 
COMA income
$ 1.3 
$ 0.8 
$ 0.8 
Transmission
 
 
 
Revenue, Major Customer
 
 
 
COMA income
$ 0.2 
$ 0.1 
$ 0.1 
Sales Revenue, Segment |
Customer Concentration Risk |
Customer A |
Gathering And Processing
 
 
 
Revenue, Major Customer
 
 
 
Entity-wide revenue by major customer, percentage
11.00% 
12.00% 
33.00% 
Sales Revenue, Segment |
Customer Concentration Risk |
Customer A |
Transmission
 
 
 
Revenue, Major Customer
 
 
 
Entity-wide revenue by major customer, percentage
13.00% 
19.00% 
43.00% 
Sales Revenue, Segment |
Customer Concentration Risk |
Customer A |
Terminals
 
 
 
Revenue, Major Customer
 
 
 
Entity-wide revenue by major customer, percentage
23.00% 
21.00% 
20.00% 
Sales Revenue, Segment |
Customer Concentration Risk |
Customer B |
Gathering And Processing
 
 
 
Revenue, Major Customer
 
 
 
Entity-wide revenue by major customer, percentage
 
12.00% 
12.00% 
Sales Revenue, Segment |
Customer Concentration Risk |
Customer B |
Transmission
 
 
 
Revenue, Major Customer
 
 
 
Entity-wide revenue by major customer, percentage
14.00% 
16.00% 
16.00% 
Sales Revenue, Segment |
Customer Concentration Risk |
Customer B |
Terminals
 
 
 
Revenue, Major Customer
 
 
 
Entity-wide revenue by major customer, percentage
17.00% 
13.00% 
19.00% 
Sales Revenue, Segment |
Customer Concentration Risk |
Customer C |
Terminals
 
 
 
Revenue, Major Customer
 
 
 
Entity-wide revenue by major customer, percentage
12.00% 
13.00% 
15.00% 
Sales Revenue, Segment |
Customer Concentration Risk |
Customer D |
Terminals
 
 
 
Revenue, Major Customer
 
 
 
Entity-wide revenue by major customer, percentage
 
13.00% 
11.00% 
Reporting Segments (Details) (USD $)
3 Months Ended 12 Months Ended
Dec. 31, 2016
Sep. 30, 2016
Jun. 30, 2016
Mar. 31, 2016
Dec. 31, 2015
Sep. 30, 2015
Jun. 30, 2015
Mar. 31, 2015
Dec. 31, 2014
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Segment information
 
 
 
 
 
 
 
 
 
 
 
 
Sales of natural gas, NGLs and condensate revenue
 
 
 
 
 
 
 
 
 
$ 160,950,000 
$ 179,818,000 
$ 255,025,000 
Services
 
 
 
 
 
 
 
 
 
72,572,000 
55,216,000 
52,284,000 
Loss on commodity derivatives, net
 
 
 
 
 
 
 
 
 
(840,000)
1,324,000 
1,091,000 
Total revenue
67,462,000 
63,818,000 
55,382,000 
46,020,000 
 
55,641,000 
67,509,000 
64,609,000 
48,599,000 
232,682,000 
236,358,000 
308,400,000 
Purchases of natural gas, NGLs and condensate
 
 
 
 
 
 
 
 
 
92,556,000 
105,883,000 
197,952,000 
Direct operating expenses
 
 
 
 
 
 
 
 
 
61,861,000 
60,737,000 
45,919,000 
Corporate expenses
 
 
 
 
 
 
 
 
 
54,223,000 
29,818,000 
24,422,000 
Depreciation, amortization and accretion expense
 
 
 
 
 
 
 
 
 
46,022,000 
38,014,000 
28,832,000 
Loss on sale of assets, net
 
 
 
 
 
 
 
 
 
(591,000)
(3,011,000)
(122,000)
Loss on impairment of property, plant and equipment
 
 
 
 
 
 
 
 
99,900,000 
697,000 
0 
99,892,000 
Loss on impairment of goodwill
 
 
 
 
(118,600,000)
 
 
 
 
0 
(118,600,000)
0 
Other expense
 
 
 
 
 
 
 
 
 
 
 
670,000 
Interest expense
 
 
 
 
 
 
 
 
 
15,499,000 
14,745,000 
7,577,000 
Earnings in unconsolidated affiliates
 
 
 
 
 
 
 
 
 
(40,158,000)
(8,201,000)
(348,000)
Income tax (expense) benefit
 
 
 
 
 
 
 
 
 
2,057,000 
1,134,000 
557,000 
Loss from discontinued operations, net of tax
 
 
 
 
 
53,000 
31,000 
(5,000)
1,000 
0 
80,000 
611,000 
Net income (loss)
 
 
 
 
 
 
 
 
 
(666,000)
(127,455,000)
(97,806,000)
Net income attributable to noncontrolling interests
 
 
 
 
 
34,000 
32,000 
14,000 
(55,000)
2,804,000 
25,000 
214,000 
Net loss attributable to the Partnership
3,581,000 
1,483,000 
(4,583,000)
(3,951,000)
 
(4,661,000)
(2,065,000)
826,000 
(121,580,000)
(3,470,000)
(127,480,000)
(98,020,000)
Gross margin
36,653,000 
34,312,000 
31,809,000 
27,291,000 
 
28,854,000 
31,917,000 
33,776,000 
27,654,000 
 
 
 
Gathering And Processing
 
 
 
 
 
 
 
 
 
 
 
 
Segment information
 
 
 
 
 
 
 
 
 
 
 
 
Sales of natural gas, NGLs and condensate revenue
 
 
 
 
 
 
 
 
 
153,174,000 
170,197,000 
202,035,000 
Services
 
 
 
 
 
 
 
 
 
10,531,000 
3,400,000 
1,581,000 
Loss on commodity derivatives, net
 
 
 
 
 
 
 
 
 
(836,000)
1,324,000 
1,091,000 
Total revenue
 
 
 
 
 
 
 
 
 
162,869,000 
174,921,000 
204,707,000 
Purchases of natural gas, NGLs and condensate
 
 
 
 
 
 
 
 
 
87,026,000 
97,580,000 
152,690,000 
Direct operating expenses
 
 
 
 
 
 
 
 
 
41,345,000 
39,249,000 
23,806,000 
Gross margin
 
 
 
 
 
 
 
 
 
74,582,000 
76,865,000 
50,817,000 
COMA income
 
 
 
 
 
 
 
 
 
1,300,000 
800,000 
800,000 
Transmission
 
 
 
 
 
 
 
 
 
 
 
 
Segment information
 
 
 
 
 
 
 
 
 
 
 
 
Sales of natural gas, NGLs and condensate revenue
 
 
 
 
 
 
 
 
 
7,775,000 
9,600,000 
52,881,000 
Services
 
 
 
 
 
 
 
 
 
39,196,000 
34,082,000 
35,308,000 
Loss on commodity derivatives, net
 
 
 
 
 
 
 
 
 
(4,000)
0 
0 
Total revenue
 
 
 
 
 
 
 
 
 
46,967,000 
43,682,000 
88,189,000 
Purchases of natural gas, NGLs and condensate
 
 
 
 
 
 
 
 
 
5,530,000 
8,303,000 
45,262,000 
Direct operating expenses
 
 
 
 
 
 
 
 
 
11,920,000 
13,768,000 
15,619,000 
Gross margin
 
 
 
 
 
 
 
 
 
41,233,000 
35,301,000 
42,828,000 
COMA income
 
 
 
 
 
 
 
 
 
200,000 
100,000 
100,000 
Terminals
 
 
 
 
 
 
 
 
 
 
 
 
Segment information
 
 
 
 
 
 
 
 
 
 
 
 
Sales of natural gas, NGLs and condensate revenue
 
 
 
 
 
 
 
 
 
1,000 
21,000 
109,000 
Services
 
 
 
 
 
 
 
 
 
22,845,000 
17,734,000 
15,395,000 
Loss on commodity derivatives, net
 
 
 
 
 
 
 
 
 
0 
0 
0 
Total revenue
 
 
 
 
 
 
 
 
 
22,846,000 
17,755,000 
15,504,000 
Purchases of natural gas, NGLs and condensate
 
 
 
 
 
 
 
 
 
0 
0 
0 
Direct operating expenses
 
 
 
 
 
 
 
 
 
8,596,000 
7,720,000 
6,494,000 
Gross margin
 
 
 
 
 
 
 
 
 
14,250,000 
10,035,000 
9,010,000 
Commodity derivative instruments, net
 
 
 
 
 
 
 
 
 
 
 
 
Segment information
 
 
 
 
 
 
 
 
 
 
 
 
Loss on commodity derivatives, net
 
 
 
 
 
 
 
 
 
(1,806,000)
457,000 
(733,000)
Gain (loss) on derivatives, unrealized
 
 
 
 
 
 
 
 
 
10,221,000 
(71,000)
595,000 
Gains (losses) on commodity derivatives, net |
Commodity derivative instruments, net
 
 
 
 
 
 
 
 
 
 
 
 
Segment information
 
 
 
 
 
 
 
 
 
 
 
 
Loss on commodity derivatives, net
 
 
 
 
 
 
 
 
 
(840,000)
1,610,000 
735,000 
Gain (loss) on derivatives, unrealized
 
 
 
 
 
 
 
 
 
$ 0 
$ (300,000)
$ 356,000 
Reporting Segments Assets (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2016
Dec. 31, 2015
Segment Reporting Information [Line Items]
 
 
Total assets
$ 1,563,495 
$ 891,880 
Gathering And Processing
 
 
Segment Reporting Information [Line Items]
 
 
Total assets
537,658 
573,408 
Transmission
 
 
Segment Reporting Information [Line Items]
 
 
Total assets
142,404 
133,870 
Terminals
 
 
Segment Reporting Information [Line Items]
 
 
Total assets
45,226 
84,449 
Other
 
 
Segment Reporting Information [Line Items]
 
 
Total assets
$ 838,207 
$ 100,153 
Quarterly Financial Data (Unaudited) (Details) (USD $)
In Thousands, except Per Share data, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2016
Sep. 30, 2016
Jun. 30, 2016
Mar. 31, 2016
Dec. 31, 2015
Sep. 30, 2015
Jun. 30, 2015
Mar. 31, 2015
Dec. 31, 2014
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
Total revenue
$ 67,462 
$ 63,818 
$ 55,382 
$ 46,020 
 
$ 55,641 
$ 67,509 
$ 64,609 
$ 48,599 
$ 232,682 
$ 236,358 
$ 308,400 
Gross margin
36,653 
34,312 
31,809 
27,291 
 
28,854 
31,917 
33,776 
27,654 
 
 
 
Operating loss
(9,244)
(2,717)
(6,191)
(5,116)
 
(1,523)
1,867 
3,434 
(123,475)
(23,268)
(119,697)
(88,739)
Net income (loss)
4,210 
2,679 
(3,591)
(3,964)
 
(4,574)
(2,002)
835 
(121,634)
(666)
(127,375)
(97,195)
Loss from discontinued operations, net of tax
 
 
 
 
 
(53)
(31)
5 
(1)
0 
(80)
(611)
Net income attributable to noncontrolling interests
 
 
 
 
 
34 
32 
14 
(55)
2,804 
25 
214 
Net income (loss) attributable to the Partnership
3,581 
1,483 
(4,583)
(3,951)
 
(4,661)
(2,065)
826 
(121,580)
(3,470)
(127,480)
(98,020)
General Partner's Interest in net income (loss)
46 
19 
(61)
(52)
 
(60)
(25)
10 
(1,570)
 
 
 
Limited Partners' Interest in net income (loss)
3,535 
1,464 
(4,522)
(3,899)
 
(4,601)
(2,040)
816 
(120,010)
 
 
 
Loss from continuing operations (in dollars per share)
$ (0.20)
$ (0.22)
$ (0.36)
$ (0.33)
 
$ (0.48)
$ (0.35)
$ (0.19)
$ (4.16)
$ (1.11)
$ (6.00)
$ (8.54)
Limited partners’ net income (loss) per unit (basic and diluted) (in dollars per share)
$ (0.20)
$ (0.22)
$ (0.36)
$ (0.33)
 
$ (0.48)
$ (0.35)
$ (0.19)
$ (4.16)
$ (1.11)
$ (6.00)
$ (8.58)
Loss on impairment of goodwill
 
 
 
 
$ 118,600 
 
 
 
 
$ 0 
$ 118,600 
$ 0 
Subsequent Event (Details) (USD $)
0 Months Ended 12 Months Ended 0 Months Ended 0 Months Ended 0 Months Ended
Aug. 15, 2014
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Apr. 25, 2016
Jan. 26, 2017
Subsequent Event
Mar. 8, 2017
Subsequent Event
Mar. 7, 2017
Subsequent Event
Mar. 8, 2017
Affiliated Holders
Subsequent Event
Mar. 8, 2017
Public Unit Consideration
Subsequent Event
Dec. 31, 2016
General Partner
Dec. 31, 2015
General Partner
Mar. 8, 2017
General Partner
Subsequent Event
Mar. 7, 2017
Affiliated Entity
General Partner
Subsequent Event
Dec. 31, 2016
8.50% Senior Notes, due 2021
Senior Notes
Dec. 28, 2016
8.50% Senior Notes, due 2021
Senior Notes
Mar. 8, 2017
JPE Energy Partners
Subsequent Event
business_segment
Subsequent Event [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distribution declared per common unit (in dollars per share)
$ 0.4625 
$ 1.71 
$ 1.89 
$ 1.85 
 
$ 0.4125 
 
 
 
 
 
 
 
 
 
 
 
Distribution made to limited partner (in dollars per share)
 
 
 
 
 
$ 1.65 
 
 
 
 
 
 
 
 
 
 
 
Merger agreement, conversion ratio
 
 
 
 
 
 
 
 
0.5775 
0.5225 
 
 
 
 
 
 
 
Number of businesses segments acquired
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3 
Line of credit facility, maximum borrowing capacity
 
 
 
 
 
 
$ 900,000,000 
$ 750,000,000 
 
 
 
 
 
 
 
 
 
General partners' interest units issued (in shares)
 
680,000 
536,000 
 
 
 
 
 
 
 
143,900 
143,517 
20,200,000 
0 
 
 
 
Debt instrument, interest rate, stated percentage
 
 
 
 
 
 
 
 
 
 
 
 
 
 
8.50% 
8.50% 
 
Line of credit facility, maximum borrowing capacity upon increase
 
 
 
 
$ 900,000,000 
 
$ 1,100,000,000