AMERICAN MIDSTREAM PARTNERS, LP, 10-Q filed on 8/10/2017
Quarterly Report
Document and Entity Information
6 Months Ended
Jun. 30, 2017
Aug. 3, 2017
Document Information [Line Items]
 
 
Entity Registrant Name
American Midstream Partners, LP 
 
Entity Central Index Key
0001513965 
 
Document Type
10-Q 
 
Document Period End Date
Jun. 30, 2017 
 
Amendment Flag
false 
 
Document Fiscal Year Focus
2017 
 
Document Fiscal Period Focus
Q2 
 
Current Fiscal Year End Date
--12-31 
 
Entity Filer Category
Accelerated Filer 
 
Entity Common Stock, Shares Outstanding (in shares)
 
51,759,787 
Series A [Member]
 
 
Document Information [Line Items]
 
 
Entity Common Stock, Shares Outstanding (in shares)
 
10,400,213 
Series C [Member]
 
 
Document Information [Line Items]
 
 
Entity Common Stock, Shares Outstanding (in shares)
 
8,792,205 
Series D [Member]
 
 
Document Information [Line Items]
 
 
Entity Common Stock, Shares Outstanding (in shares)
 
2,333,333 
Condensed Consolidated Balance Sheets (Unaudited) (USD $)
In Thousands, unless otherwise specified
Jun. 30, 2017
Dec. 31, 2016
Current assets
 
 
Cash and cash equivalents
$ 5,903 
$ 5,666 
Restricted cash
18,965 
Accounts receivable, net of allowance for doubtful accounts of $1,872 and $1,871, respectively
22,905 
27,769 
Unbilled revenue
51,123 
55,646 
Inventory
8,105 
6,776 
Other current assets
39,655 
27,667 
Total current assets
146,656 
123,524 
Risk management assets-long term
7,704 
10,664 
Property, plant and equipment, net
1,166,421 
1,145,003 
Goodwill
217,498 
217,498 
Restricted cash-long term
5,038 
323,564 
Intangible assets, net
212,990 
225,283 
Investment in unconsolidated affiliates
286,548 
291,988 
Other assets, net
9,087 
11,797 
Total assets
2,051,942 
2,349,321 
Current liabilities
 
 
Accounts payable
34,156 
45,278 
Accrued gas purchases
14,211 
7,891 
Accrued expenses and other current liabilities
87,026 
81,284 
Current portion of long-term debt
1,757 
5,485 
Total current liabilities
137,150 
139,938 
Asset retirement obligations
45,302 
44,363 
Other long-term liabilities
2,225 
2,030 
Revolving credit facility
678,042 
888,250 
Deferred tax liability
9,455 
8,205 
Total liabilities
1,220,077 
1,430,074 
Commitments and contingencies
   
   
Convertible preferred units (Note 13)
338,195 
334,090 
Equity and partners’ capital
 
 
General Partner interests (953 thousand and 680 thousand units issued and outstanding as of June 30, 2017 and December 31, 2016, respectively)
(26,664)
(47,645)
Limited Partner interests (51,760 thousand and 51,351 thousand units issued and outstanding as of June 30, 2017 and December 31, 2016, respectively)
502,311 
616,087 
Accumulated other comprehensive income (loss)
(40)
Total partners’ capital
475,649 
568,402 
Noncontrolling interests
18,021 
16,755 
Total equity and partners’ capital
493,670 
585,157 
Total liabilities, equity and partners’ capital
2,051,942 
2,349,321 
Senior Notes [Member] |
3.77% Senior Notes [Member]
 
 
Current liabilities
 
 
Senior notes
55,294 
55,979 
Senior Notes [Member] |
8.50% Senior Notes [Member]
 
 
Current liabilities
 
 
Senior notes
$ 292,609 
$ 291,309 
Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) (USD $)
In Thousands, except Share data, unless otherwise specified
Jun. 30, 2017
Dec. 31, 2016
Allowance for doubtful accounts receivable
$ 1,872 
$ 1,871 
General partner interest units, outstanding (in shares)
953,000 
680,000 
Preferred, units, outstanding (in shares)
51,745,000 
51,351,000 
Partnership Interest [Member]
 
 
General partner interest, units issued (in shares)
953,000 
680,000 
General partner interest units, outstanding (in shares)
953,000 
680,000 
Preferred, units, issued (in shares)
51,760,000 
51,351,000 
Preferred, units, outstanding (in shares)
51,760,000 
51,351,000 
Condensed Consolidated Statements of Operations (Unaudited) (USD $)
In Thousands, except Per Share data, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2017
Jun. 30, 2016
Jun. 30, 2017
Jun. 30, 2016
Revenue:
 
 
 
 
Commodity sales
$ 153,728 
$ 148,592 
$ 312,229 
$ 256,162 
Services
39,698 
38,611 
81,086 
74,655 
Gains (losses) on commodity derivatives, net
207 
(1,367)
(50)
(1,605)
Total revenue
193,633 
185,836 
393,265 
329,212 
Operating expenses:
 
 
 
 
Costs of sales
128,816 
115,080 
261,601 
189,018 
Direct operating expenses
31,884 
31,967 
61,972 
62,542 
Corporate expenses
30,084 
22,281 
62,928 
43,382 
Depreciation, amortization and accretion
30,170 
26,398 
59,521 
51,439 
(Gain) loss on sale of assets, net
52 
478 
(176)
1,600 
Total operating expenses
221,006 
196,204 
445,846 
347,981 
Operating loss
(27,373)
(10,368)
(52,581)
(18,769)
Other income (expense), net
 
 
 
 
Interest expense
(17,152)
(10,610)
(35,118)
(18,912)
Other income
72 
496 
86 
527 
Earnings in unconsolidated affiliates
17,552 
11,702 
32,954 
19,045 
Loss from continuing operations before taxes
(26,901)
(8,780)
(54,659)
(18,109)
Income tax expense
(801)
(701)
(1,924)
(1,436)
Loss from continuing operations
(27,702)
(9,481)
(56,583)
(19,545)
Loss from discontinued operations, net of tax
(539)
Net loss
(27,702)
(9,481)
(56,583)
(20,084)
Less: Net income attributable to noncontrolling interests
1,462 
954 
2,765 
951 
Net loss attributable to the Partnership
(29,164)
(10,435)
(59,348)
(21,035)
Distribution declared per common unit (in usd per share)
$ 0.4125 1
$ 0.4125 1
$ 0.825 1
$ 0.885 1
Limited Partners’ net loss per common unit, basic and diluted:
 
 
 
 
Loss from continuing operations (in usd per share)
$ (0.72)
$ (0.33)
$ (1.46)
$ (0.65)
Loss from discontinued operations (in usd per share)
$ 0.00 
$ 0.00 
$ 0.00 
$ (0.01)
Net loss (in usd per share)
$ (0.72)
$ (0.33)
$ (1.46)
$ (0.66)
Weighted average number of common units outstanding:
 
 
 
 
Weighted average number of common units outstanding: basic and diluted (shares)
51,870 
51,090 
51,870 
51,090 
General Partner [Member]
 
 
 
 
Other income (expense), net
 
 
 
 
Net loss
 
 
(795)
(204)
General Partner’s interest in net loss
(375)
(107)
(795)
(204)
Limited Partner [Member]
 
 
 
 
Other income (expense), net
 
 
 
 
Net loss
 
 
(58,553)
(20,831)
Limited Partners’ interest in net loss
$ (28,789)
$ (10,328)
$ (58,553)
$ (20,831)
Condensed Consolidated Statements of Comprehensive Loss (Unaudited) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2017
Jun. 30, 2016
Jun. 30, 2017
Jun. 30, 2016
Statement of Comprehensive Income [Abstract]
 
 
 
 
Net loss
$ (27,702)
$ (9,481)
$ (56,583)
$ (20,084)
Unrealized gain related to postretirement benefit plan
24 
21 
 
 
Comprehensive loss
(27,678)
(9,460)
(56,541)
(20,049)
Less: Comprehensive income attributable to noncontrolling interests
1,462 
954 
2,765 
951 
Comprehensive loss attributable to the Partnership
$ (29,140)
$ (10,414)
$ (59,306)
$ (21,000)
Condensed Consolidated Statements of Changes in Partners' Capital (Unaudited) (USD $)
In Thousands, unless otherwise specified
Total
Parent [Member]
Accumulated Other Comprehensive Income (Loss) [Member]
Noncontrolling Interest [Member]
Series B [Member]
General Partner [Member]
Limited Partner [Member]
Partners' Capital at Dec. 31, 2015
 
$ 739,930 
$ 40 
$ 12,111 
$ 33,593 
$ (47,091)
$ 753,388 
Increase (Decrease) in Partners' Capital [Roll Forward]
 
 
 
 
 
 
 
Net income (loss)
(20,084)
(21,035)
 
951 
 
(204)
(20,831)
Issuance of common units, net of offering costs
 
2,986 
 
 
 
 
2,986 
Cancellation of escrow units
(6,817)
(6,817)
 
 
 
 
(6,817)
Conversion of Series B units
 
 
 
(33,593)
 
33,593 
Contributions
4,000 
5,791 
 
 
 
1,791 
4,000 
Distributions
 
(65,301)
 
 
 
(2,351)
(62,950)
Issuance of warrant
 
4,481 
 
 
 
4,481 
General Partner’s contribution for acquisition
 
990 
 
 
 
990 
 
Contributions from noncontrolling interest owners
 
 
 
1,980 
 
 
 
LTIP vesting
 
 
 
 
(2,107)
2,107 
Tax netting repurchase
309 
(309)
 
 
 
 
(309)
Equity compensation expense
 
2,480 
 
 
 
1,538 
942 
Post-retirement benefit plan
 
35 
35 
 
 
 
 
Addition of Mesquite NCI
 
 
475 
 
 
 
Partners' Capital at Jun. 30, 2016
 
663,231 
75 
15,517 
(42,953)
706,109 
Partners' Capital at Mar. 31, 2016
 
 
 
 
 
 
 
Increase (Decrease) in Partners' Capital [Roll Forward]
 
 
 
 
 
 
 
Net income (loss)
(9,481)
 
 
 
 
 
 
Equity compensation expense
 
800 
 
 
 
 
 
Post-retirement benefit plan
21 
 
 
 
 
 
 
Partners' Capital at Jun. 30, 2016
 
663,231 
 
 
 
 
 
Partners' Capital at Dec. 31, 2016
568,402 
568,402 
(40)
16,755 
(47,645)
616,087 
Increase (Decrease) in Partners' Capital [Roll Forward]
 
 
 
 
 
 
 
Net income (loss)
(56,583)
(59,348)
 
2,765 
 
(795)
(58,553)
Cancellation of escrow units
 
 
 
 
 
 
Contributions
4,000 
27,130 
 
 
23,130 
4,000 
Distributions
 
(64,168)
 
 
 
(594)
(63,574)
Contributions from noncontrolling interest owners
 
 
 
296 
 
 
 
Distributions to noncontrolling interests owners
 
 
 
(1,795)
 
 
 
LTIP vesting
 
 
 
 
 
(4,633)
4,633 
Tax netting repurchase
1,642 
(1,642)
 
 
 
 
(1,642)
Equity compensation expense
 
5,233 
 
 
3,873 
1,360 
Post-retirement benefit plan
 
42 
42 
 
 
 
 
Partners' Capital at Jun. 30, 2017
475,649 
475,649 
18,021 
(26,664)
502,311 
Partners' Capital at Mar. 31, 2017
 
 
 
 
 
 
 
Increase (Decrease) in Partners' Capital [Roll Forward]
 
 
 
 
 
 
 
Net income (loss)
(27,702)
 
 
 
 
 
 
Equity compensation expense
 
1,200 
 
 
 
 
 
Post-retirement benefit plan
24 
 
 
 
 
 
 
Partners' Capital at Jun. 30, 2017
$ 475,649 
$ 475,649 
 
 
$ 0 
 
 
Condensed Consolidated Statements of Cash Flows (Unaudited) (USD $)
In Thousands, unless otherwise specified
6 Months Ended
Jun. 30, 2017
Jun. 30, 2016
Cash flows from operating activities
 
 
Net loss
$ (56,583)
$ (20,084)
Adjustments to reconcile net loss to net cash provided by operating activities:
 
 
Depreciation, amortization and accretion
 
51,650 
Amortization of deferred financing costs
2,456 
1,512 
Amortization of weather derivative premium
475 
451 
Unrealized loss on derivatives contracts, net
3,020 
4,870 
Non-cash compensation expense
5,233 
3,051 
(Gain) loss on sale of assets, net
(176)
1,486 
Corporate overhead support
4,000 
4,000 
Other non cash items
1,906 
(709)
Earnings in unconsolidated affiliates
(32,954)
(19,045)
Distributions from unconsolidated affiliates
32,954 
19,045 
Deferred tax expense
1,250 
835 
Bad debt expense
515 
(61)
Changes in operating assets and liabilities, net of effects of assets acquired and liabilities assumed:
 
 
Accounts receivable
4,238 
(1,223)
Inventory
(1,738)
(5,668)
Unbilled revenue
4,523 
6,686 
Risk management assets and liabilities
(1,157)
(1,030)
Other current assets
(6,394)
8,149 
Other assets, net
147 
896 
Restricted cash
(3,135)
Accounts payable
(12,069)
(8,446)
Accrued gas purchases
6,320 
2,285 
Accrued expenses and other current liabilities
13,216 
1,749 
Asset retirement obligations
(45)
(10)
Other liabilities
(247)
(673)
Net cash provided by operating activities
25,276 
49,716 
Cash flows from investing activities
 
 
Acquisitions, net of cash acquired and settlements (Note 3)
(32,000)
(3,073)
Additions to property, plant and equipment
(44,039)
(54,658)
Proceeds from disposals of property, plant and equipment
121 
11,434 
Insurance proceeds from involuntary conversion of property, plant and equipment
150 
Investments in unconsolidated affiliates
(11,444)
Distributions from unconsolidated affiliates, return of capital
5,440 
16,673 
Restricted cash
302,643 
Net cash provided by (used in) investing activities
232,315 
(141,976)
Cash flows from financing activities
 
 
Proceeds from issuance of common units to public, net of offering costs
2,986 
Contributions
23,130 
1,791 
Distributions
(60,494)
(53,983)
Contribution from noncontrolling interest owners
296 
1,980 
Distributions to noncontrolling interests owners
(1,795)
LTIP tax netting unit repurchase
(1,642)
(309)
Payment of financing costs
(2,116)
(1,475)
Payments on 3.77% Senior Notes
(1,078)
Payments on other debt
(3,447)
(1,810)
Payments on credit agreement
(383,908)
(101,900)
Borrowings on credit agreement
173,700 
245,200 
Other
(166)
Net cash provided by (used in) financing activities
(257,354)
92,314 
Net increase in cash and cash equivalents
237 
54 
Cash and cash equivalents
 
 
Beginning of period
5,666 
1,987 
End of period
5,903 
2,041 
Emerald Transaction [Member]
 
 
Cash flows from investing activities
 
 
Investments in unconsolidated affiliates
$ 0 
$ (100,908)
Organization, Basis of Presentation and Summary of Significant Accounting Policies
Organization, Basis of Presentation and Summary of Significant Accounting Policies
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 77% owned by High Point Infrastructure Partners, LLC (“HPIP”) and 23% 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.

JPE Acquisition

On March 8, 2017, we completed the acquisition of JP Energy Partners LP (“JPE”), an entity controlled by ArcLight affiliates, in a unit-for-unit merger (“JPE Acquisition”). In connection with the transaction, we issued approximately 20.2 million common units to holders of the JPE common and subordinated units, including 9.8 million common units to ArcLight affiliates. In connection with the completion of the JPE Acquisition, we entered into a supplemental indenture pursuant to which the JPE Entities jointly and severally, fully and unconditionally, guarantee the 8.50% Senior Notes (as defined below).

As both we and JPE were controlled by ArcLight affiliates, the acquisition represented a transaction among entities under common control. Although we are the legal acquirer, JPE was considered the acquirer for accounting purposes as ArcLight obtained control of JPE prior to obtaining control of us on April 15, 2013. As a result, we adjusted our historical financial statements to reflect ArcLight’s acquisition cost basis of their investment in us back to April 15, 2013. In addition, the accompanying financial statements and related notes have been retrospectively adjusted to include the historical results of JPE prior to the effective date of the JPE Acquisition. The accompanying financial statements and related notes present the combined financial position, results of operations, cash flows and equity of JPE at historical cost.

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 six reportable segments, (1) gas gathering and processing services, (2) liquid pipelines and services, (3) natural gas transportation services, (4) offshore pipelines and services, (5) terminalling services and (6) propane marketing services, we engage in the business of gathering, treating, processing, and transporting natural gas; gathering, transporting, storing, treating and fractionating NGLs; gathering, storing and transporting crude oil and condensates; storing specialty chemical products; and distributing and selling propane and refined products. See Note 21 - Subsequent Events
regarding the announced sale of substantially all of our propane marketing services segment in July 2017.

Most of our cash flow is generated from fee-based and fixed-margin arrangements for gathering, processing, transporting and treating natural gas and crude oil, firm capacity reservation charges, interruptible transportation charges, guaranteed firm storage contracts, throughput fees and other optional charges associated with ancillary services.

Our primary assets are strategically located in some of the most prolific onshore and offshore producing regions and key demand markets in the United States. Our gathering and processing assets are primarily located in (i) the Permian Basin of West Texas, (ii) the Cotton Valley/Haynesville Shale of East Texas, (iii) the Eagle Ford Shale of South Texas, (iv) the Bakken Shale of North Dakota, and (v) offshore in the Gulf of Mexico. Our natural gas transportation, offshore pipelines and terminal assets are in key demand markets in Oklahoma, Alabama, Arkansas, Louisiana, Mississippi and Tennessee and in the Port of New Orleans in Louisiana and the Port of Brunswick in Georgia. Our propane marketing services include commercial and retail operations across 46 of the lower 48 states.

Basis of presentation

The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2016, except that the consolidated financial statements have been retrospectively adjusted to reflect the consolidation of JPE, as discussed above. The results of operations for the three and six months ended June 30, 2017 are not necessarily indicative of results expected for the full year. In the opinion of our management, such financial information reflects all adjustments necessary for a fair statement of the financial position and the results of operations for such interim periods in accordance with GAAP. All such adjustments are of a normal recurring nature. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC.

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 June 2011 (the date Arclight affiliates obtained control of JPE) or the date the ArcLight affiliate obtained control of the assets acquired.

Summary of Significant Accounting Policies

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, asset retirement obligations, contracted arrangements and management restrictions. Such amounts are included in Restricted cash in our condensed 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, historical collection experience and the age of accounts receivable. As of June 30, 2017 and December 31, 2016, the balance of allowance for doubtful accounts was $1.9 million.

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 condensed 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. The unconsolidated affiliates were determined to be variable interest entities due to disproportionate economic interests and decision making rights. In each case, we lack the power to direct the activities that most significantly impact the unconsolidated affiliate’s economic performance. As we do not hold a controlling financial interest in these affiliates, we account for our related investments using the equity method. Additionally, our maximum exposure to loss related to each entity is limited to our equity investment as presented on the condensed consolidated balance sheets as of the balance sheet date. In each case, we are not obligated to absorb losses greater than our proportional ownership percentages. Our right to receive residual returns is not limited to any amount less than the ownership percentages.

Revenue recognition

We recognize revenue from the sale of commodities (e.g., natural gas, crude oil, NGLs, refined products 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.

Revenue-related taxes collected from customers and remitted to taxing authorities, principally sales taxes, are presented on a net basis within the condensed consolidated statements of operations.
New Accounting Pronouncements (Notes)
New Accounting Pronouncements
New Accounting Pronouncements

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. From March 2016 to May 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; 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 and 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 the new accounting guidance for revenue recognition will have on our consolidated financial statements and related disclosures. We also have engaged a third-party consulting firm to assist us with all the three phases of adoption of the new guidance (Impact Assessment, Convert and Implement). We will adopt the new standard on its effective date January 1, 2018 using the modified retrospective method of adoption.

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. We are still in the process of evaluating the impact of ASU 2016-02 on our consolidated financial statements as we will be required to reflect our various lease obligations and associated asset use rights on our consolidated balance sheets. The adoption may also impact our debt covenant compliance and may require us to modify or replace certain of our existing information systems. We will adopt the guidance on its effective date January 1, 2019.

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. The retrospective transition method of adoption is required unless it is impracticable. Early adoption is permitted, but only if all aspects are adopted in the same period. We are still evaluating the impact of this update on our consolidated statements of cash flows and the related disclosures. We will adopt the standard upon its effective date January 1, 2018.

In November 2016, the FASB issued ASU No. 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. We have evaluated the impact of this update and believe it will have a material impact on our consolidated statement of cash flows and related disclosures, upon our effective date of adoption January 1, 2018.

In January 2017, the FASB issued ASU No. 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business” The guidance provides criteria for use in determining when to conclude an integrated “set of assets and activities (as defined in the original guidance) being acquired or disposed in a transaction is not a business. Where the criteria are not met, more stringent screening has been provided to define a set as a business without an output, as more narrowly defined within the guidance. ASU No. 2017-01 is effective for annual periods beginning after December 15, 2017, including interim periods within those periods. The amendments should be applied prospectively on or after the effective date. Early adoption is permitted. We are still in the process of evaluating the guidance and can not determine the impact of this guidance on our consolidated financial statements and related disclosures. We will adopt ASU 2017-01 on its effective date of January 1, 2018.
In January 2017, the FASB issued ASU No. 2017-04, Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment, in which the guidance on testing for goodwill was updated by the elimination of Step 2 in the determination on whether goodwill should be considered impaired. The annual and/or interim assessments are still required to be completed. Further, the guidance eliminates the requirement to assess reporting units with zero or negative carrying values, however, the carrying values for all reporting units must be disclosed. ASU No. 2017-04 is effective for annual or any interim goodwill impairment tests beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. We are currently evaluating the impact of this update on our consolidated financial statements and related disclosures and will adopt the guidance on its effective date January 1, 2020 using the required prospective method

In May 2017, the FASB issued ASU No. 2017-09, Compensation - Stock Compensation (Topic 718): Scope of Modification Accounting, to provide guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting. Pursuant to this ASU, an entity should account for the effects of a modification unless all the following are met: (1) the fair value (or calculated value or intrinsic value, if such an alternative measurement method is used) of the modified award is the same as the fair value (or calculated value or intrinsic value, if such an alternative measurement method is used) of the original award immediately before the original award is modified (if the modification does not affect any of the inputs to the valuation technique that the entity uses to value the award, the entity is not required to estimate the value immediately before and after the modification); (2) the vesting conditions of the modified award are the same as the vesting conditions of the original award immediately before the original award is modified; and (3) the classification of the modified award as an equity instrument or a liability instrument is the same as the classification of the original award immediately before the original award is modified. ASU No. 2017-09 is effective for annual periods beginning after December 15, 2017, including interim periods within those periods. Early adoption is permitted, including adoption in any interim period. This update should be applied prospectively to an award modified on or after the adoption date. The Partnership is currently evaluating the impact of this update on our consolidated financial statements and related disclosures and will adopt the guidance on our effective date January 1, 2018.
Acquisitions
Acquisitions
Acquisitions

JP Energy Partners LP

On March 8, 2017, we completed the acquisition of JPE, a legal 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. We issued a total of 20.2 million of common units to complete the acquisition, including 9.8 million common units to ArcLight affiliates.

As both we and JPE were controlled by ArcLight affiliates, the acquisition represented a transaction among entities under common control. Although we were the legal acquirer, JPE was considered the acquirer for accounting purposes as ArcLight obtained control of JPE prior to obtaining control of us on April 15, 2013. As a result, we adjusted our historical financial statements to reflect ArcLight’s acquisition cost basis of us back to April 15, 2013. In addition, the accompanying financial statements and related notes have been retrospectively adjusted to include the historical results of JPE prior to the effective date of the JPE acquisition. The accompanying financial statements and related notes present the combined financial position, results of operations, cash flows and equity of JPE at historical cost.

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.

Acquisition of Viosca Knoll

On June 2, 2017 (“acquisition date”), we acquired 100% of the Viosca Knoll System (“Viosca Knoll”) from Genesis Energy, L.P. for total consideration of approximately $32 million in cash. The Viosca Knoll System serves producing fields located in the Main Pass, Mississippi Canyon and Viosca Knoll areas of the Gulf of Mexico and connects to several major delivery pipelines including the Partnership’s High Point and Destin pipelines. Viosca Knoll will provide greater East-West Gulf connectivity, through the connection of the High Point Gas Transmission system and the Destin Pipeline, both controlled by us. The Viosca Knoll acquisition was funded with the Partnership’s revolving credit facility and Viosca Knoll was added to our Offshore pipeline and services segment.

In accordance with ASC Topic 805 - Business Combinations, we accounted for Viosca Knoll acquisition as an acquisition of a business, with the Partnership as the acquirer. ASC 805 requires, among other things, that the consideration transferred be measured at the current market price as of the acquisition date and the asset acquired and liabilities assumed be measured at their fair value as of the acquisition date. The total consideration transferred of $32 million cash was allocated 100% to Viosca Knoll’s assets as shown below.

The following table presents our aggregated preliminary allocation of the purchase price based on estimated fair values of assets acquired as of June 30, 2017 (in thousands):

 
Purchase Price Allocation
Property, plant and equipment:
 
Pipelines
$
12,266

Equipment
16,484

Total property, plant and equipment
28,750

Intangible assets
3,250

Total cash consideration
$
32,000



The purchase price allocation is subject to the measurement period that ends at the earlier of twelve months from the acquisition date or when information becomes available.

Pro Forma Financial Information

The following table presents selected unaudited pro forma information for the Partnership assuming the acquisition of Viosca Knoll had occurred as of January 1, 2016. This pro forma information does not purport to represent what the Partnership’s actual results would have been if the acquisition had occurred as of the date indicated or what such results would be for any future periods.


The unaudited pro forma financial information consists of the following (in thousands):

 
 
 
 
 
Six Months Ended
 
June 30, 2017
 
June 30, 2016
Revenue
$
396,254

 
$
333,837

Income (loss) from continuing operations
$
(56,407
)
 
$
(17,962
)
Inventory (Notes)
Inventory
Inventory

Inventory consists of the following (in thousands):
 
 
June 30, 2017
 
December 31, 2016
Crude oil
 
$
2,741

 
$
1,216

NGLs
 
3,207

 
3,482

Refined products
 
413

 
291

Materials, supplies and equipment
 
1,744

 
1,787

   Total inventory
 
$
8,105

 
$
6,776

Other Current Assets
Other Current Assets
Other Current Assets

Other current assets consist of the following (in thousands):
 
June 30, 2017
 
December 31, 2016
Prepaid insurance
$
5,109

 
$
9,702

Insurance receivables
6,162

 
2,895

Due from related parties
20,853

 
4,805

Other receivables
2,363

 
2,998

Risk management assets
1,772

 
964

Other assets
3,396

 
6,303

   Total other current assets
$
39,655


$
27,667

Risk Management Activities
Risk Management Activities
Risk Management Activities

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

Commodity Derivatives

Our normal business activities expose us to risks associated with changes in the market price of crude oil and natural gas, among other commodities. Management believes it is prudent to limit our exposure to these risks, which include our (i) propane purchases, (ii) pre-existing or anticipated physical crude oil and refined product sales, and (iii) certain crude oil held in inventory. To meet this objective, we use a combination of fixed price swap and forward contracts. Our forward contracts that qualify for the Normal Purchase Normal Sale (“NPNS”) exception under GAAP are recognized when the underlying physical transaction is delivered. While these contracts are considered derivative financial instruments under ASC 815, Derivatives and Hedging, they are not recorded at fair value, but on an accrual basis of accounting. If it is determined that a transaction designated as NPNS no longer meets the scope exception, the fair value of the related contract is recorded on the balance sheet (as an asset or liability) and the difference between the fair value and the contract amount is immediately recognized through earnings.We measure our commodity derivatives at fair value using the income approach which discounts the future net cash settlements expected under the derivative contracts to a present value. These valuations utilize indirectly observable (“Level 2”) inputs, including contractual terms and commodity prices observable at commonly quoted intervals.

The following table summarizes the net notional volumes of our outstanding commodity-related derivatives, excluding those contracts that qualified for the NPNS exception as of June 30, 2017 and December 31, 2016, none of which were designated as hedges for accounting purposes.

 
 
June 30, 2017
 
December 31, 2016
Commodity Swaps
 
Volume
 
Maturity
 
Volume
 
Maturity
Propane Fixed Price (gallons)
 
10,892,201

 
July 1, 2017 - December 31, 2019
 
4,364,880

 
January 31, 2017 - November 30, 2018
Crude Oil Fixed Price (barrels)
 
68,000

 
July 1, 2017 -
July 31, 2017
 
 
Crude Oil Basis (barrels)
 
 
 
180,000

 
January 25, 2017-
March 25, 2017


Interest Rate Swaps

To manage the impact of the interest rate risk associated with our Credit Agreement, as defined in Note 12 - Debt Obligations, we enter into interest rate swaps from time to time, effectively converting a portion of the cash flows related to our long-term variable rate debt into fixed rate cash flows.


Our outstanding interest rate swap contracts’ fair value consist of the following (in thousands):
Notional Amount
Term
As of June 30, 2017
 
As of December 31, 2016
$100,000
July 1, 2017 through December 29, 2017
$
119

 
$

$100,000
December 29, 2017 through January 29, 2019
208

 

$200,000
July 1, 2017 through September 3, 2019
1,711

 
1,912

$100,000
January 1, 2018 through December 31, 2021
2,385

 
3,090

$150,000
January 1, 2018 through December 31, 2022
3,944

 
5,219

 
 
$
8,367

 
$
10,221



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

Weather Derivative

In the second quarter of 2017, we entered into a yearly weather derivative to mitigate the impact of potential unfavorable weather on our operations under which we could receive payments totaling up to $30.0 million in the event that a hurricane of certain strength passes through the areas identified in the derivative agreement. The weather 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 $1.1 million and $1.0 million in premiums during the six months ended June 30, 2017 and 2016, respectively. Premiums are amortized to Direct operating expenses on a straight-line basis over the 1 year term of the contract. Unamortized amounts associated with the weather derivatives were approximately $1.1 million and $0.4 million as of June 30, 2017 and December 31, 2016, respectively, and are included in Other current assets on the condensed consolidated balance sheets.

The following table summarizes the fair values of our derivative contracts (before netting adjustments) included in the condensed consolidated balance sheets (in thousands):
 
 
 
Asset Derivatives
 
Liability Derivatives
Type
Balance Sheet Classification
 
June 30,
2017
 
December 31, 2016
 
June 30,
2017
 
December 31, 2016
Commodity swaps
Other current assets
 
$
234

 
$
607

 
$

 
$

Commodity swaps
Accrued expenses and other current liabilities
 

 

 
(404
)
 
(1
)
Commodity swaps
Risk management assets - long term
 

 
37

 

 

Commodity swaps
Other liabilities
 

 

 
(196
)
 
(1
)
 
 
 
 
 
 
 
 
 
 
Interest rate swaps
Other current assets
 
663

 

 

 

Interest rate swaps
Accrued expenses and other current liabilities
 

 

 

 
(252
)
Interest rate swaps
Risk management assets- long term
 
7,704

 
10,628

 

 

 
 
 
 
 
 
 
 
 
 
Weather derivatives
Other current assets
 
$
1,110

 
$
429

 
$

 
$






The following tables present the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset in the condensed consolidated balance sheets that are subject to enforceable master netting arrangements (in thousands):
 
 
Gross Risk Management Position
 
Netting Adjustments
 
Net Risk Management Position
Balance Sheet Classification
 
June 30,
2017
 
December 31, 2016
 
June 30,
2017
 
December 31, 2016
 
June 30,
2017
 
December 31, 2016
Other current assets
 
$
2,006

 
$
1,036

 
$
(234
)
 
$
(72
)
 
$
1,772

 
$
964

Risk management assets- long term
 
7,704

 
10,665

 

 
(1
)
 
7,704

 
10,664

Total assets
 
$
9,710

 
$
11,701

 
$
(234
)
 
$
(73
)
 
$
9,476

 
$
11,628

 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued expenses and other liabilities
 
$
(404
)
 
$
(253
)
 
$
234

 
$
72

 
$
(170
)
 
$
(181
)
Other liabilities
 
(196
)
 
(1
)
 

 
1

 
(196
)
 

Total liabilities
 
$
(600
)
 
$
(254
)
 
$
234

 
$
73

 
$
(366
)
 
$
(181
)


For each of the three and six months ended June 30, 2017 and 2016 the realized and unrealized gains (losses) associated with our commodity, interest rate and weather derivative instruments were recorded in our unaudited condensed consolidated statements of operations as follows (in thousands):
 
Three months ended June 30,
 
Six months ended June 30,
Statement of Operations Classification
Realized
 
Unrealized
 
Realized
 
Unrealized
2017
 
 
 
 
 
 
 
Gains (losses) on commodity derivatives, net
$
260

 
$
(53
)
 
$
960

 
$
(1,010
)
Interest expense

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

 
(475
)
 

Total
$
42

 
$
(1,746
)
 
$
415

 
$
(3,020
)
2016
 
 
 
 
 
 
 
Losses on commodity derivatives, net
$
(388
)
 
$
(979
)
 
$
(776
)
 
$
(829
)
Interest expense
(32
)
 
(2,510
)
 
(32
)
 
(4,041
)
Direct operating expenses
(231
)
 

 
(451
)
 

Total
$
(651
)
 
$
(3,489
)
 
$
(1,259
)
 
$
(4,870
)
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)
 
June 30,
2017
 
December 31,
2016
Land
Infinite
 
$
23,098

 
$
23,520

Construction in progress
N/A
 
46,657

 
131,448

Buildings and improvements
4 to 40
 
24,280

 
24,225

Transportation equipment
5 to 15
 
45,090

 
44,060

Processing and treating plants (1)
8 to 40
 
141,109

 
120,977

Pipelines, compressors and right-of-way (1)
3 to 40
 
909,963

 
804,815

Storage
3 to 40
 
210,291

 
210,579

Equipment
3 to 31
 
124,607

 
102,409

Total property, plant and equipment
 
 
1,525,095

 
1,462,033

Accumulated depreciation (1)
 
 
(358,674
)
 
(317,030
)
Property, plant and equipment, net
 
 
$
1,166,421

 
$
1,145,003


_____________________________________(1) The Partnership has revised the December 31, 2016 amounts above from those amounts previously reported in its Form 10-Q for the quarter ended March 31, 2017 to primarily decrease the amount for Processing and treating plants by approximately $16 million and to increase the amount for Pipelines, compressors and rights-of-way by approximately $49.9 million, with the offsetting change to Accumulated depreciation of approximately $33.9 million.  

At June 30, 2017 and December 31, 2016, gross property, plant and equipment included $253.5 million and $291.1 million, respectively, related to our FERC regulated interstate and intrastate assets.

Depreciation expense totaled $21.3 million and $20.8 million for the three months ended June 30, 2017 and 2016, respectively, and $42.9 million and $40.5 million for the six months ended June 30, 2017 and 2016, respectively.

Capitalized interest was $0.5 million for each of the three months ended June 30, 2017 and 2016, and $1.5 million and $1.0 million for the six months ended June 30, 2017 and 2016, respectively.
Goodwill and Intangible Assets, Net
Goodwill and Intangible Assets, Net
Goodwill and Intangible Assets, Net

Goodwill as of June 30, 2017 and December 31, 2016 consisted of the following (in thousands):
 
June 30, 2017
 
December 31, 2016
Liquid Pipelines and Services (1)
$
113,669

 
$
113,669

Terminalling Services (1)
88,466

 
88,466

Propane Marketing Services
15,363

 
15,363

Total
$
217,498

 
$
217,498

_____________________________________
(1) The Partnership has revised the December 31, 2016 amounts by segment above from those amounts previously reported in its Form 10-Q for the quarter ended March 31, 2017 to increase the Terminalling Services segment by approximately $11 million with the offset being to decrease the Liquid Pipelines and Services segment by the same amount.  
 
Intangible assets, net, consists of customer relationships, dedicated acreage agreements, collaborative arrangements, noncompete agreements and trade names. These intangible assets have definite lives and are subject to amortization on a straight-line basis over their economic lives, currently ranging from approximately 5 years to 44 years. Intangible assets, net, consist of the following (in thousands):
 
June 30, 2017
 
Gross carrying amount
 
Accumulated amortization
 
Net carrying amount
Customer relationships
$
133,503

 
$
(35,834
)
 
$
97,669

Customer contracts
98,844

 
(43,142
)
 
55,702

Dedicated acreage
53,350

 
(5,328
)
 
48,022

Collaborative arrangements
11,884

 
(990
)
 
10,894

Noncompete agreements
3,423

 
(3,250
)
 
173

Other
751

 
(221
)
 
530

Total
$
301,755

 
$
(88,765
)
 
$
212,990

 
 
 
 
 
 
 
December 31, 2016
 
Gross carrying amount
 
Accumulated amortization
 
Net carrying amount
Customer relationships
$
133,503

 
$
(31,471
)
 
$
102,032

Customer contracts
95,594

 
(33,414
)
 
62,180

Dedicated acreage
53,350

 
(4,439
)
 
48,911

Collaborative arrangements
11,884

 
(601
)
 
11,283

Noncompete agreements
3,423

 
(3,086
)
 
337

Other
751

 
(211
)
 
540

Total
$
298,505

 
$
(73,222
)
 
$
225,283



Amortization expense related to our intangible assets totaled $8.3 million and $5.2 million for the three months ended June 30, 2017 and 2016, respectively, and $15.5 million and $10.3 million for the six months ended June 30, 2017 and 2016, respectively.
Investment in unconsolidated affiliates
Investment in unconsolidated affiliates
Investment in unconsolidated affiliates

The following table presents the activity in our equity method investments in unconsolidated affiliates (in thousands):
 
Delta House (1)
 
Emerald Transactions (2)
 
 
 
 
 
FPS
 
OGL
 
Destin
 
Tri-States
 
Okeanos
 
Wilprise
 
MPOG (3)
 
Total
Ownership % at December 31, 2016 and June 30, 2017
20.1
%
 
20.1
%
 
49.7
%
 
16.7
%
 
66.7
%
 
25.3
%
 
66.7
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balances at December 31, 2016
$
64,483

 
$
25,450

 
$
110,882

 
$
55,022

 
$
27,059

 
$
4,944

 
$
4,148

 
$
291,988

  Earnings in unconsolidated affiliates
15,529

 
6,571

 
5,116

 
2,161

 
3,692

 
408

 
(523
)
 
32,954

  Distributions
(8,753
)
 
(7,137
)
 
(12,119
)
 
(2,626
)
 
(6,667
)
 
(392
)
 
(700
)
 
(38,394
)
Balances at June 30, 2017
$
71,259

 
$
24,884

 
$
103,879

 
$
54,557


$
24,084


$
4,960


$
2,925


$
286,548

 
___________________________________________________ 
(1) Represents direct and indirect ownership interests in Class A Units.
(2) Represents our Emerald equity method investments which were acquired in the second quarter of 2016.
(3) Main Pass Oil Gathering.

The following tables present the summarized combined financial information for our equity investments (amounts represent 100% of investee financial information) (in thousands):
Balance Sheets:
June 30, 2017
 
December 31, 2016
Current assets
$
105,211

 
$
120,167

Non-current assets
1,337,201

 
1,369,492

Current liabilities
121,966

 
133,085

Non-current liabilities
$
489,080

 
$
541,312


 
Three months ended June 30,
 
Six months ended June 30,
Statements of Operations:
2017
 
2016
 
2017
 
2016
Revenue
$
105,373

 
$
89,541

 
$
203,366

 
$
184,757

Gross profit
96,442

 
83,045

 
185,075

 
169,668

Net income
$
76,414

 
$
67,937

 
$
145,532

 
$
136,387

Accrued Expenses and Other Current Liabilities
Accrued Expenses and Other Current Liabilities
Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities consists of the following (in thousands):
 
 
June 30, 2017
 
December 31, 2016
Due to related parties
 
$
15,694

 
$
4,072

Accrued interest
 
8,470

 
5,743

Legal accrual
 
8,192

 

Capital expenditures
 
7,240

 
14,499

Convertible preferred unit distributions
 
6,735

 
7,103

Current portion of asset retirement obligation
 
6,495

 
6,499

Additional Blackwater acquisition consideration
 
5,000

 
5,000

Employee compensation
 
4,967

 
10,804

Taxes payable
 
3,902

 
1,688

Royalties payable
 
3,536

 
3,926

Customer deposits
 
3,092

 
3,080

Gas imbalances payable
 
1,580

 
1,098

Transaction costs
 
1,179

 
3,000

Deferred financing costs
 

 
2,743

Recoverable gas costs
 
238

 
1,126

Other
 
10,706

 
10,903

   Total accrued expenses and other current liabilities
 
$
87,026


$
81,284

Asset Retirement Obligations
Asset Retirement Obligations
Asset Retirement Obligations

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

Certain assets related to our Offshore Pipelines and Services segment have regulatory obligations to perform remediation, and in some instances, dismantlement and removal activities when the assets are abandoned. These AROs include varying levels of activity including disconnecting inactive assets from active assets, cleaning and purging assets, and in some cases, completely removing the assets and returning the land to its original state. These assets have been in existence for many years and with regular maintenance will continue to be in service for many years to come. It is not possible to predict when demand for these transmission services will cease, however, we do not believe that such demand will cease for the foreseeable future. The majority of the current portion of our AROs is related to the retirement of the Midla pipeline discussed in Note 17 - Commitments and Contingencies.

The following table presents activity in our asset retirement obligations for the six months ended June 30, 2017 (in thousands):
Non-current balance
$
44,363

Current balance
6,499

Balances at December 31, 2016
$
50,862

Expenditures
(49
)
Accretion expense
984

Balances at June 30, 2017
$
51,797

Less: current portion
6,495

Noncurrent asset retirement obligation
$
45,302



We are required to establish security against potential obligations relating to the abandonment of certain transmission assets that may be imposed on the previous owner by applicable regulatory authorities. We have deposited $5.0 million with a third party to secure our performance on these potential obligations. These deposits are included in Restricted cash-long term in our condensed consolidated balance sheets as of June 30, 2017 and December 31, 2016.
Debt Obligations
Debt Obligations
Debt Obligations

Our outstanding debt consists of the following (in thousands):
 
June 30, 2017
 
December 31, 2016
Revolving credit facility
$
678,042

 
$
888,250

8.5% Senior unsecured notes, due 2021
300,000

 
300,000

3.77% Senior secured notes, due 2031 (non-recourse)
58,922

 
60,000

Other debt (2)
685

 
3,809

Total debt obligations
1,037,649

 
1,252,059

Unamortized debt issuance costs (1)
(9,776
)
 
(11,036
)
Total debt
1,027,873

 
1,241,023

Less: Current portion, including unamortized debt issuance costs
(1,556
)
 
(5,485
)
Long term debt
$
1,026,317

 
$
1,235,538

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

(2) Other debt includes capital lease and miscellaneous long-term obligations, which are reported in Current portion of debt and Other liabilities line items on our condensed consolidated balance sheets.

Revolving Credit Facility

On March 8, 2017, we entered into the Second Amended and Restated Credit Agreement with Bank of America N.A., as Administrative Agent, Collateral Agent and L/C Issuer, Wells Fargo Bank, National Association, as Syndication Agent, and other lenders (the “Credit Agreement”) which increased our borrowing capacity from $750.0 million to $900.0 million and provided for an accordion feature that will permit, subject to customary conditions, the borrowing capacity under the facility to be increased to a maximum of $1.1 billion. 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. The Credit Agreement matures on September 5, 2019.

The Credit Agreement contains certain financial covenants that are applicable as of the end of any fiscal quarter, including a consolidated total leverage ratio which requires our indebtedness not to exceed 5.00 times adjusted consolidated EBITDA (except for the fiscal quarters ended March 31, 2017, and the subsequent two quarters, at which time the covenant is increased to 5.50 times adjusted consolidated EBITDA), a consolidated secured leverage ratio which requires our secured indebtedness not to exceed 3.50 times adjusted consolidated EBITDA, and a minimum interest coverage ratio that requires our adjusted consolidated EBITDA to exceed consolidated interest charges by not less than 2.50 times. In addition to the financial covenants described above, the 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).

As of June 30, 2017, we had approximately $678.0 million of borrowings and $32.3 million of letters of credit outstanding under the Credit Agreement resulting in $189.6 million of available borrowing capacity.

As of June 30, 2017, our consolidated total leverage ratio was 4.79 and our interest coverage ratio was 5.04, which were both in compliance with the related requirements of our 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 our Credit Agreement approximates the related fair value, as interest charges vary with market rates conditions.

JPE Revolver

JPE had a $275.0 million revolving loan, which included a sub-limit of up to $100.0 million for letters of credit with Bank of America, N.A. (the “JPE Revolver”). The JPE Revolver was scheduled to mature on February 12, 2019, but on March 8, 2017, in connection with the closing of the JPE acquisition, the $199.5 million outstanding balance of the JPE Revolver was paid off in full and terminated.

For the six months ended June 30, 2017 and 2016, the weighted average interest rate on borrowings under our Credit Agreement and the JPE Revolver was approximately 4.67% and 4.15%, respectively.

8.50% Senior Unsecured Notes

On December 28, 2016, we and American Midstream Finance Corporation, our wholly-owned subsidiary (the “Issuers”), completed the issuance and sale of $300 million in aggregate principal amount of senior notes due 2021 (the “8.50% Senior Notes”). The 8.50% Senior Notes are jointly and severally guaranteed by certain of our existing direct and indirect wholly owned subsidiaries that guarantee our Credit Agreement. 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 Acquisition and was included in Restricted cash-long term on our consolidated balance sheet as of December 31, 2016. We 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 Acquisition and the satisfaction of other related conditions the restricted cash was released from escrow on March 8, 2017 and used to repay and terminate the JPE Revolver and reduce borrowings under the Credit Agreement.

The 8.50% Senior Notes will mature on December 15, 2021 with interest payable in cash semi-annually in arrears on June 15 and December 15, commencing June 15, 2017.

As of June 30, 2017, the fair value of the 8.50% Senior Notes was $303.3 million. This estimate was based on similar private placement transactions along with changes in market interest rates which represent a Level 2 measurement.

3.77% Senior Secured 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 (the “Note Purchase Agreement”) with certain institutional investors (the “Purchasers”) whereby Midla Financing issued $60.0 million in aggregate principal amount of 3.77% Senior Notes (non-recourse) due June 30, 2031.

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. Many of these provisions apply not only to Midla Financing and the Note Guarantors, but also to American Midstream Midla Financing Holdings, LLC (“Midla Holdings”), a wholly owned subsidiary of the Partnership and the sole member of Midla Financing. Among other things, 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 Note Purchase Agreement) are restricted from making distributions (a) until June 30, 2017, (b) unless the debt service coverage ratio is not less than, and is not projected for the following 12 calendar months to be less than, 1.20:1.00, and (c) unless certain other requirements are met.

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

Net proceeds from the 3.77% Senior Notes are restricted and are to be used (1) to fund project costs incurred in connection with (a) the construction of the Midla-Natchez Line (b) the retirement of Midla’s existing 1920’s vintage pipeline (c) the move of our Baton Rouge operations to the MLGT system (d) the reconfiguration of the DeSiard compression system and all related ancillary facilities, (2) to pay transaction fees and expenses in connection with the issuance of the 3.77% Senior Notes, and (3) for other general corporate purposes of Midla Financing.

As of June 30, 2017, the fair value of the 3.77% Senior Notes was $55.5 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 (Notes)
Convertible Preferred Units
Convertible Preferred Units

Our convertible preferred units consist of the following (in thousands):
 
Series A
 
Series C
 
Series D
 
Total
 
Units
$
 
Units
$
 
Units
$
 
$
December 31, 2016
10,107

$
181,386

 
8,792

$
118,229

 
2,333

$
34,475

 
$
334,090

Paid in kind unit distributions
293

4,105

 


 


 
4,105

June 30, 2017
10,400

$
185,491

 
8,792

$
118,229

 
2,333

$
34,475

 
$
338,195



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, we, 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 $0.4125 per unit or the declared distribution to common unitholders. The Series A-1 Units may be converted into common units, subject to customary anti-dilutive adjustments, at the option of the unitholders on or any time after January 1, 2014. As of June 30, 2017, the conversion price is $15.69 and the conversion ratio is 1 to 1.1054.

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 we issued, in separate private placements, newly-designated Series A-2 Units (the “Series A-2 Units”) representing limited partnership interests in the Partnership. As a result, the Partnership issued a total of 2,571,430 Series A-2 Units for approximately $45.0 million in aggregate proceeds during the year ended December 31, 2015. The Series A-2 Units will participate in distributions of the Partnership along with common units in a manner identical to the existing Series A-1 Units (together with the Series A-2 Units, the "Series A Units"), with such distributions being made in cash or with paid-in-kind Series A Units at the election of the Board of Directors of our General Partner.

On July 27, 2015, we amended our Partnership Agreement to grant us the right (the “Call Right”) to require the holders of the Series A-2 Units to sell, assign and transfer all or a portion of the then outstanding Series A-2 Units to us for a purchase price of $17.50 per Series A-2 Unit (subject to appropriate adjustment for any equity distribution, subdivision or combination of equity interests in the Partnership). We may exercise the Call Right at any time, in connection with our or our 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 June 30, 2017, the conversion price is $15.69 and the conversion ratio is 1 to 1.1054.

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 and A-2 Units have been classified as mezzanine equity in the condensed consolidated balance sheets.

Third Amendment to Partnership Agreement

On March 8, 2017, the Partnership executed Amendment No. 3 to our Fifth Amended and Restated Partnership Agreement (as amended, the “Partnership Agreement”), which amends the distribution payment terms of the Partnership’s outstanding Series A Preferred Units to provide for the payment of a number of Series A payment-in-kind (“PIK”) preferred units for the quarter (the “Series A Preferred Quarterly Distribution”) in which the JPE Acquisition is consummated (which is the quarter ended March 31, 2017) and each quarter thereafter equal to the quotient of (i) the greater of (a) $0.4125 and (b) the "Series A Distribution Amount," as such term is defined in the Partnership Agreement, divided by (ii) the Series A Adjusted Issue Price, as such term is defined in the Partnership Agreement. However, in our General Partner’s discretion, which determination shall be made prior to the record date for the relevant quarter, the Series A Preferred Quarterly Distribution may be paid as a combination (x) an amount in cash up to the greater of (1) $0.4125 and (2) the Series A Distribution Amount, and (y) a number of Series A Preferred Units equal to the quotient of (a) the remainder of (i) the greater of (I) $0.4125 and (II) the Series A Distribution Amount less (ii) the amount of cash paid pursuant to clause (x), divided by (b) the Series A Adjusted Issue Price. This calculation results in a reduced Series A Preferred Quarterly Distribution, which was previously calculated under the Partnership Agreement using $0.50 in place of $0.4125 in the preceding calculations.

Series C Convertible Preferred Units

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

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

In the event that we issue, sell or grant any common units or convertible securities at an indicative per common unit price that is less than $14.00 per common unit (subject to customary anti-dilution adjustments), then the conversion price will be adjusted according to a formula to provide for an increase in the number of common units into which Series C Units are convertible. As of June 30, 2017, the conversion price is $13.79 and the conversion ratio is 1 to 1.0035.

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

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

As conversion is at the option of the holder and redemption is contingent upon a future event which is outside the control of the Partnership, the Series C Units have been classified as mezzanine equity in the condensed consolidated balance sheets.

Series D Convertible Preferred Units

On October 31, 2016, we issued 2,333,333 shares of our 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 during the third quarter 2016. The related agreement provides that if any of the Series D Units remain outstanding on June 30, 2017 (the “ Series D Determination Date”), we 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. On July 14, 2017, the Partnership entered into an amendment to the related agreement and Amendment No. 5 to the Partnership Agreement, pursuant to which the Series D Warrant Determination Date was extended to August 31, 2017.

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 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 June 30, 2017, the conversion price is $14.83 and the conversion ratio is 1 to 1.0035.
Partners Capital
Partners’ Capital and Convertible Preferred Units
Partners’ Capital

Our capital accounts are comprised of approximately 1.3% notional General Partner interests and 98.7% limited partner interests as of June 30, 2017. Our limited partners have limited rights of ownership as provided for under our Partnership Agreement and the right to participate in our distributions. Our General Partner manages our operations and participates in our distributions, including certain incentive distributions pursuant to the incentive distribution rights that are non-voting limited partner interests held by our General Partner. Pursuant to our Partnership Agreement, our General Partner participates in losses and distributions based on its interest. The General Partner’s participation in the allocation of losses and distributions is not limited and therefore, such participation can result in a deficit to its capital account. As such, allocation of losses and distributions, including distributions for previous transactions between entities under common control, has resulted in a deficit to the General Partner’s capital account included in our condensed consolidated balance sheets.

Outstanding Units

The following table presents unit activity (in thousands):
 
 
General
Partner Interest
 
Limited Partner Interest
Balances at December 31, 2016
 
680

 
51,351

LTIP vesting
 

 
373

Issuance of GP units
 
273

 

Issuance of common units
 

 
21

Balances at June 30, 2017
 
953

 
51,745



General Partner Units

In order to maintain the ownership percentage, we received proceeds of $3.9 million from our General Partner as consideration for the issuance of 272,811 additional notional General Partner units for the six months ended June 30, 2017. For the six months ended June 30, 2016, we received proceeds of $1.8 million for the issuance of 128,272 additional notional General Partner units.
Distributions

We made the following distributions (in thousands):

 
 
Three months ended June 30,
 
Six months ended June 30,
 
 
2017
 
2016
 
2017
 
2016
Series A Units
 
 
 
 
 
 
 
 
Cash Paid
 
$
2,117

 
$

 
$
4,644

 
$

Accrued
 
4,069

 
4,602

 
4,069

 
4,602

Paid-in-kind units
 
2,181

 
4,471

 
4,914

 
8,851

 
 
 
 
 
 
 
 
 
Series C Units
 
 
 
 
 
 
 
 
Cash Paid
 
3,627

 

 
7,254

 

Accrued
 
3,627

 
2,249

 
3,627

 
2,249

Paid-in-kind units
 

 

 

 

 
 
 
 
 
 
 
 
 
Series D Units
 
 
 
 
 
 
 
 
Cash Paid
 
963

 

 
1,925

 

Accrued
 
963

 

 
963

 

 
 
 
 
 
 
 
 
 
Limited Partner Units
 
 
 
 
 
 
 
 
Cash Paid
 
21,390

 
24,782

 
46,303

 
51,782

 
 
 
 
 
 
 
 
 
General Partner Units
 
 
 
 
 
 
 
 
Cash Paid
 
201

 
173

 
368

 
2,201

 
 
 
 
 
 
 
 
 
Summary
 
 
 
 
 
 
 
 
Cash Paid
 
28,298

 
24,955

 
60,494

 
53,983

Accrued
 
8,659

 
6,851

 
8,659

 
6,851

Paid-in-kind units
 
2,181

 
4,471

 
4,914

 
8,851



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 measurement as defined by ASC 820. Under the income approach, the fair value estimates for all periods presented were based on i) present value of estimated future contracted distributions, ii) option values ranging from $0.02 per unit to $3.39 per unit using a Black-Scholes model, iii) assumed discount rates ranging from 5.98% to 10.0% and iv) assumed growth rates of 1.0%.
Net Loss per Limited Partner Unit
Net Loss per Limited Partner Unit
Net Loss per Limited Partner Unit

Net 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 loss per common unit. Basic and diluted limited partners' net loss per common unit is calculated by dividing limited partners' interest in net loss by the weighted average number of outstanding limited partner units during the period.


As discussed in Note 1, the JPE Acquisition was a combination between entities under common control. As a result, prior periods were retrospectively adjusted to furnish comparative information. Accordingly, the prior period earnings combining both entities were allocated among our General Partners and common unitholders assuming JPE units were converted into our common units in the comparative historical periods.

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

 
Three months ended June 30,
 
Six months ended June 30,
 
2017
 
2016
 
2017
 
2016
Net loss from continuing operations
$
(27,702
)
 
$
(9,481
)
 
$
(56,583
)
 
$
(19,545
)
Less: Net income attributable to noncontrolling interests
1,462

 
954

 
2,765

 
951

Net loss from continuing operations attributable to the Partnership
(29,164
)
 
(10,435
)
 
(59,348
)
 
(20,496
)
Less:
 
 
 
 
 
 
 
Distributions on Series A Units
4,069

 
4,602

 
8,367

 
9,073

Distributions on Series C Units
3,627

 
2,249

 
7,254

 
2,249

Distributions on Series D Units
963

 

 
1,925

 

General partner's distribution
277

 
173

 
476

 
2,201

General partner's share in undistributed loss
(784
)
 
(400
)
 
(1,541
)
 
(818
)
Net loss from continuing operations attributable to Limited Partners
(37,316
)
 
(17,059
)
 
(75,829
)
 
(33,201
)
Net loss from discontinued operations attributable to Limited Partners

 

 

 
(539
)
Net loss attributable to Limited Partners
$
(37,316
)
 
$
(17,059
)
 
$
(75,829
)
 
$
(33,740
)
 
 
 
 
 
 
 
 
Weighted average number of common units used in computation of Limited Partners' net loss per common unit - basic and diluted
51,870

 
51,090

 
51,870

 
51,090

 
 
 
 
 
 
 
 
Limited Partners' net loss from continuing operations per unit
$
(0.72
)
 
$
(0.33
)
 
$
(1.46
)
 
$
(0.65
)
Limited Partners' net loss from discontinued operations per unit

 

 

 
(0.01
)
Limited Partners' net loss per common unit (1)
$
(0.72
)
 
$
(0.33
)
 
$
(1.46
)
 
$
(0.66
)
_____________________________________
(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 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”). On March 9, 2017, an additional 312,716 common units were registered to be issued in relation to the converted JPE phantom units.

All such equity-based awards issued under the LTIP consist of phantom units, distribution equivalent rights (“DERs”) 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 in cash upon the vesting of phantom units, our General Partner has not historically settled these awards in cash. Under the LTIP, phantom units typically vest over 3-4 years 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 based on the extent to which our Series A 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 six months ended June 30, 2017:

 
 
Units
 
Weighted-Average Grant Date Fair Value Per Unit
Outstanding units at December 31, 2016
 
1,558,835

 
$
6.98

Granted
 
2,000

 
11.20

Forfeited
 
(7,643
)
 
21.46

Vested
 
(479,130
)
 
10.32

Outstanding units at June 30, 2017
 
1,074,062

 
$
5.39



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 expenses related to these awards were $1.2 million and $0.8 million for the three months ended June 30, 2017 and 2016, respectively, and were $5.2 million and $2.5 million for the six months ended June 30, 2017 and 2016, respectively, and are included in Corporate expenses and Direct operating expenses in our unaudited condensed consolidated statements of operations and Equity compensation expense in our unaudited condensed consolidated statements of changes in partners’ capital and noncontrolling interests.

The total fair value of units at the time of vesting was $7.9 million and $0.9 million for the six months ended June 30, 2017 and 2016, respectively.
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 certainty, our management believes that the resolution of any of our pending proceedings will not have a material adverse effect on our financial condition, results of operations or cash flows.

Environmental matters

We are subject to federal and state laws and regulations relating to the protection of the environment. Environmental risk is inherent to 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, 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 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, we 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, and services commenced on March 31, 2017. Under the Midla Agreement, Midla executed long-term agreements seeking to recover its investment in the Midla-Natchez Line.

Acquisition related costs

As part of the JPE Acquisition, management of JPE communicated to its employees a severance plan. The plan includes termination benefits in the form of severance and accelerated vesting of phantom units for employees who render service through their respective termination date. We have estimated the fair value of the obligation to be approximately $0.9 million, which has been recorded as of June 30, 2017.
Related Party Transactions
Related Party Transactions
Related Party Transactions

In December 2013, we acquired Blackwater Midstream Holdings, LLC (“Blackwater”) from an affiliate of ArcLight. The acquisition agreement included a provision whereby an ArcLight affiliate would be entitled to an additional $5.0 million of merger consideration based on Blackwater meeting certain operating targets. During the third quarter of 2016, we 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 expense and other current liabilities in the accompanying condensed consolidated balance sheets as of June 30, 2017.

Employees of our General Partner are assigned to work for us 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.

In connection with the JPE Acquisition closing during the first quarter of 2017, our General Partner agreed to provide quarterly financial support up to a maximum of $25 million. The financial support will continue for eight (8) consecutive quarters following the closing of the acquisition, or if earlier, until $25 million in support has been provided. We have utilized $15.1 million of the financial support mentioned above.

During the second quarter of 2017, the Partnership received $9.6 million from the General Partner as reimbursement of post-closing transition costs. Separate from the financial support described above, our General Partner also agreed to absorb $9.6 million corporate overhead expenses, which were incurred by us in the first quarter of 2017, and subsequently paid the amount in the second quarter of 2017. These two cash amounts, and the $3.8 million received related to the General Partner’s ownership percentage, totaled $23.1 million which was presented as part of the contribution line item on our condensed consolidated statements of cash flows.

Republic Midstream, LLC (“Republic”), is an entity owned by ArcLight in which we charge a monthly fee of approximately $0.1 million. The monthly fee reduced the Corporate expenses in the condensed consolidated statements of operations by $0.3 million and $0.7 million for each of the three and six months ended June 30, 2017 and June 30, 2016, respectively. As of June 30, 2017, we had a receivable balance due from Republic of $1.4 million, which is included in the account Receivables from related parties which is part of Other current assets in the condensed consolidated balance sheets.

As of June 30, 2017 and December 31, 2016, we had $2.3 million of payables balance, which is net of $15.6 million of account payables and $13.3 million of account receivables, and $3.9 million of account payables, 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, we 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 us. In addition, the affiliates reimburse us for certain transition related expenses. For the six months ended June 30, 2017, we recognized $1.2 million of management fee income. As of June 30, 2017 and December 31, 2016, we had an outstanding account receivables balance of $5.8 million and $2.2 million, respectively, which is recorded in Receivables from related parties and is part of Other current assets in the condensed consolidated balance sheets.

American Panther, LLC ("American Panther") is a 60%-owned subsidiary of ours which is consolidated for financial reporting purposes. Panther, a provider of midstream activities and services to the oil & gas industry in Texas, Louisiana and the Gulf Coast, is the 40% non-controlling interest owner of American Panther. Pursuant to a related party agreement which began in the second quarter of 2016, an affiliate of Panther, or Panther Offshore Gathering Systems, LLC, provides management 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 unaudited condensed consolidated statements of operations. During the six months ended June 30, 2017, such management services totaled $0.5 million of Direct operating expenses and $0.3 million of Corporate expenses in the unaudited condensed consolidated statements of operations.

We enter 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 three months ended June 30, 2017, and 2016, we recognized revenue of $1.8 million and $0.7 million, respectively, while purchases from this company totaled $1.2 million, and $0.8 million, respectively. During the six months ended June 30, 2017, and 2016, we recognized revenue of $2.5 million and $1.6 million, respectively, while purchases from this company totaled $2.6 million and $1.8 million, respectively.

JP Energy Development (“JP Development”), an affiliate owned by Arclight, had a pipeline transportation business that provided crude oil pipeline transportation services to JPE’s discontinued Mid-Continent Business. As a result of utilizing JP Development’s pipeline transportation services, JPE incurred pipeline tariff fees of $0.4 million for the six months ended June 30, 2016, which have been included in net loss from discontinued operations in the condensed consolidated statements of operations. We combined the cash flows from the Mid-Continent Business with the cash flows from continuing operations for all periods presented in the condensed consolidated statements of cash flows. As of December 31, 2015, we had a net receivable from JP Development of $7.9 million, primarily as the result of the prepayments made in 2014 for the crude oil pipeline transportation services to be provided by JP Development. We recovered these amounts in full on February 1, 2016.

On February 1, 2016, JPE sold certain trucking and marketing assets in the Mid-Continent area to JP Development in connection with JP Development’s sale of its GSPP pipeline assets to a third party.

During the year ended December 31, 2016, JPE’s general partner agreed to absorb corporate overhead expenses incurred by us and not pass such expense through to us. We record non-cash contributions for these expenses in the quarters subsequent to when they were incurred, which was $0 million and $4 million for the three and six months ended June 30, 2017, respectively, and $1.5 million and $4.0 million for the three and six months ended June 30, 2016, respectively. JPE’s general partner agreed to absorb $3.5 million and $5.0 million of such corporate overhead expenses in the three and six months ended June 30, 2016.
Supplemental Cash Flow Information (Notes)
Supplemental Cash Flow Information
Supplemental Cash Flow Information

Supplemental cash flows and non-cash transactions consist of the following (in thousands):
 
Six months ended June 30,
 
2017
 
2016
Supplemental non-cash information
 
 
 
Investing
 
 
 
Increase (decrease) in accrued property, plant and equipment purchases
$
(7,259
)
 
$
4,856

Financing
 
 
 
Contributions from an affiliate holding limited partner interests
4,000

 
4,000

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

 
120,000

Accrued distributions on convertible preferred units
8,659

 
6,851

Paid-in-kind distributions on convertible preferred units
4,914

 
8,851

Cancellation of escrow units

 
6,817

Accrued distribution from unconsolidated affiliates

 
4,360

Reportable Segments
Reportable Segments
Reportable Segments

During the first quarter of 2017, as a result of the acquisition of JPE described in Note 1, we realigned the composition of our reportable segments. Accordingly, we have restated the items of segment information for the three and six months ended June 30, 2016 to reflect this new segment adjustment.

Our operations are located in the United States and are organized into six reportable segments: 1) Gas Gathering and Processing Services, 2) Liquid Pipelines and Services, 3) Natural Gas Transportation Services, 4) Offshore Pipelines and Services, 5) Terminalling Services, and 6) Propane Marketing Services.

Gas Gathering and Processing Services. Our Gas Gathering and Processing Services segment provides “wellhead-to-market” services to producers of natural gas and natural gas liquids, which include transporting raw natural gas from various receipt points through gathering systems, treating the raw natural gas, processing raw natural gas to separate the NGLs from the natural gas, fractionating NGLs, and selling or delivering pipeline-quality natural gas and NGLs to various markets and pipeline systems.

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

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

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

Terminalling Services. Our Terminalling Services segment provides above-ground leasable storage operations at our marine terminals that support various commercial customers, including commodity brokers, refiners and chemical manufacturers to store a range of products and also includes crude oil storage in Cushing, Oklahoma and refined products terminals in Texas and Arkansas.

Propane Marketing Services. Our Propane Marketing Services segment gathers, transports and sells natural gas liquids (NGLs). This is accomplished through cylinder tank exchange, sales through retail, commercial and wholesale distribution and through a fleet of trucks operating in the Eagle Ford and Permian basin areas.


These segments are monitored separately by our chief operating decision maker (“CODM”) for performance and are consistent with our internal financial reporting. The CODM periodically reviews segment gross margin information for each segment to make business decisions. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations.

We define total segment gross margin as the sum of the segment gross margins for our Gas Gathering and Processing Services,
Liquid Pipelines and Services, Natural Gas Transportation Services, Offshore Pipelines and Services, Terminalling Services and
Propane Marketing Services segments.

We define segment gross margin in our Gas Gathering and Processing Services segment as total revenue plus unconsolidated affiliate earnings less unrealized gains or plus unrealized losses on commodity derivatives, construction and operating management agreement income and the cost of natural gas, crude oil and NGLs and condensate purchased.

We define segment gross margin in our Liquid Pipelines and Services segment as total revenue plus unconsolidated affiliate earnings less unrealized gains or plus unrealized losses on commodity derivatives and the cost of crude oil purchased in connection with fixed-margin arrangements. Substantially all of our gross margin in this segment is fee-based or fixed-margin, with little to no direct commodity price risk.

We define segment gross margin in our Natural Gas Transportation Services segment as total revenue plus unconsolidated affiliate earnings less the cost of natural gas purchased in connection with fixed-margin arrangements. Substantially all of our gross margin in this segment is fee-based or fixed-margin, with little to no direct commodity price risk.

We define segment gross margin in our Offshore Pipelines and Services segment as total revenue plus unconsolidated affiliate earnings less the cost of natural gas purchased in connection with fixed-margin arrangements. Substantially all of our gross margin in this segment is fee-based or fixed-margin, with little to no direct commodity price risk.

We define segment gross margin in our Terminalling Services segment as total revenue less direct operating expense which includes direct labor, general materials and supplies and direct overhead.

We define segment gross margin in our Propane Marketing Services segment as total revenue less purchases of natural gas, NGLs and condensate excluding non-cash charges such as non-cash unrealized gains or plus unrealized losses on commodity derivatives.

A reconciliation from Segment Gross Margin to Net Income attributable to the Partnership for the periods presented is below (in thousands):

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

2017
 
2016
 
2017
 
2016
Reconciliation of Segment Gross Margin to Net loss attributable to the Partnership:
 
 
 
 
 
 
 
Gas Gathering and Processing Services segment gross margin
$
12,651

 
$
13,337

 
$
23,902

 
$
24,957

Liquid Pipelines and Services segment gross margin
6,683

 
9,432

 
13,152

 
15,284

Natural Gas Transportation Services segment gross margin
5,631

 
3,843

 
11,750

 
9,406

Offshore Pipelines and Services segment gross margin
25,623

 
20,558

 
51,426

 
33,819

Terminalling Services segment gross margin (1)
10,760

 
11,586

 
21,920

 
21,030

Propane Marketing Services segment gross margin
17,952

 
22,316

 
37,254

 
50,621

Total Segment Gross Margin
79,300

 
81,072

 
159,404

 
155,117

Less:
 
 
 
 
 
 
 
Other direct operating expenses (1)
28,886

 
29,579

 
55,902

 
57,545

Plus:
 
 
 
 
 
 
 
Gain (loss) on commodity derivatives, net
207

 
(1,367
)
 
(50
)
 
(1,605
)
Less:
 
 
 
 
 
 
 
Corporate expenses
30,084

 
22,281

 
62,928

 
43,382

Depreciation, amortization and accretion expense
30,170

 
26,398

 
59,521

 
51,439

(Gain) loss on sale of assets, net
52

 
478

 
(176
)
 
1,600

Interest expense
17,152

 
10,610

 
35,118

 
18,912

Other income
(72
)
 
(496
)
 
(86
)
 
(527
)
Other (income) expense, net
136

 
(365
)
 
806

 
(730
)
Income tax expense
801

 
701

 
1,924

 
1,436

Loss from discontinued operations, net of tax

 

 

 
539

Net income attributable to noncontrolling interest
1,462

 
954

 
2,765

 
951

Net loss attributable to the Partnership
$
(29,164
)
 
$
(10,435
)
 
$
(59,348
)
 
$
(21,035
)
_____________________________________
(1)
Other direct operating expenses include Gas Gathering and Processing Services segment direct operating expenses of $8.0 million and $8.9 million, respectively, Liquid Pipelines and Services segment direct operating expenses of $1.8 million and $2.2 million, respectively, Natural Gas Transportation Services segment direct operating expenses of $1.9 million and $2.0 million, respectively, Offshore Pipelines and Services segment direct operating expenses of $3.5 million and $2.8 million, respectively, and Propane Marketing Services segment direct operating expenses of $13.6 million and $13.6 million, respectively, for the three months ended June 30, 2017 and 2016. Direct operating expenses related to our Terminalling Services segment of $3.0 million and $2.4 million for the three months ended June 30, 2017 and 2016, respectively, are included within the calculation of Terminalling Services segment gross margin.
Other direct operating expenses include Gas Gathering and Processing Services segment direct operating expenses of $16.1 million and $17.5 million, respectively, Liquid Pipelines and Services segment direct operating expenses of $3.9 million and $4.7 million, respectively, Natural Gas Transportation Services segment direct operating expenses of $3.2 million and $3.2 million, respectively, Offshore Pipelines and Services segment direct operating expenses of $6.1 million and $5.1 million, respectively, and Propane Marketing Services segment direct operating expenses of $26.7 million and $27.1 million, respectively, for the six months ended June 30, 2017 and 2016. Direct operating expenses related to our Terminalling Services segment of $6.1 million and $5.0 million for the six months ended June 30, 2017 and 2016, respectively, are included within the calculation of Terminalling Services segment gross margin.


The following tables set forth our segment information for the three and six months ended June 30, 2017 and 2016 (in thousands):
 
Three months ended June 30, 2017
 
Gas Gathering and Processing Services
 
Liquid Pipelines and Services
 
Natural Gas Transportation Services
 
Offshore Pipelines and Services
 
Terminalling Services
 
Propane Marketing Services
 
Total
Revenue
$
39,307

 
$
82,303

 
$
11,397

 
$
12,139

 
$
15,831

 
$
32,449

 
$
193,426

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

 

 

 

 
8

 
207

Total revenue
39,209

 
82,600

 
11,397

 
12,139

 
15,831

 
32,457

 
193,633

Earnings in unconsolidated affiliates

 
1,482

 

 
16,070

 

 

 
17,552

Operating expenses:
 
 
 
 
 
 
 
 
 
 
 
 
 
Cost of Sales
26,582

 
77,332

 
5,678

 
2,586

 
2,073

 
14,565

 
128,816

Direct operating expenses
8,045

 
1,833

 
1,928

 
3,490

 
2,998

 
13,590

 
31,884

Corporate expenses
 
 
 
 
 
 
 
 
 
 
 
 
30,084

Depreciation, amortization and accretion expense
 
 
 
 
 
 
 
 
 
 
 
 
30,170

Loss on sale of assets, net
 
 
 
 
 
 
 
 
 
 
 
 
52

Total operating expenses
 
 
 
 
 
 
 
 
 
 
 
 
221,006

Interest expense
 
 
 
 
 
 
 
 
 
 
 
 
17,152

Other income
 
 
 
 
 
 
 
 
 
 
 
 
(72
)
Loss from continuing operations before taxes
 
 
 
 
 
 
 
 
 
 
 
 
(26,901
)
Income tax expense
 
 
 
 
 
 
 
 
 
 
 
 
801

Net loss
 
 
 
 
 
 
 
 
 
 
 
 
(27,702
)
Less: Net income attributable to non-controlling interests
 
 
 
 
 
 
 
 
 
 
 
 
1,462

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

 
$
6,683

 
$
5,631

 
$
25,623

 
$
10,760

 
$
17,952

 


 
Three months ended June 30, 2016
 
Gas Gathering and Processing Services
 
Liquid Pipelines and Services
 
Natural Gas Transportation Services
 
Offshore Pipelines and Services
 
Terminalling Services
 
Propane Marketing Services
 
Total
Revenue
$
30,710

 
$
85,415

 
$
7,877

 
$
10,645

 
$
17,815

 
$
34,741

 
$
187,203

Gain (loss) on commodity derivatives, net
(763
)
 
(716
)
 

 
(2
)
 
(260
)

374

 
(1,367
)
Total revenue
29,947

 
84,699

 
7,877

 
10,643

 
17,555

 
35,115

 
185,836

Earnings in unconsolidated affiliates

 
1,009

 

 
10,693

 

 

 
11,702




 


 


 


 


 


 


Operating expenses:
 
 
 
 
 
 
 
 
 
 
 
 
 
Cost of Sales
17,162

 
76,992

 
4,026

 
778

 
3,542

 
12,580

 
115,080

Direct operating expenses
8,945

 
2,235

 
1,963

 
2,802

 
2,388

 
13,634

 
31,967

Corporate expenses
 
 
 
 
 
 
 
 
 
 
 
 
22,281

Depreciation, amortization and accretion expense
 
 
 
 
 
 
 
 
 
 
 
 
26,398

Loss on sale of assets, net
 
 
 
 
 
 
 
 
 
 
 
 
478

Total operating expenses
 
 
 
 
 
 
 
 
 
 
 
 
196,204

Interest expense
 
 
 
 
 
 
 
 
 
 
 
 
10,610

Other income
 
 
 
 
 
 
 
 
 
 
 
 
(496
)
Loss from continuing operations before taxes
 
 
 
 
 
 
 
 
 
 
 
 
(8,780
)
Income tax expense
 
 
 
 
 
 
 
 
 
 
 
 
701

Loss from continuing operation
 
 
 
 
 
 
 
 
 
 
 
 
(9,481
)
Loss from discontinued operations, net of tax
 
 
 
 
 
 
 
 
 
 
 
 
$

Net loss
 
 
 
 
 
 
 
 
 
 
 
 
(9,481
)
Less: Net income attributable to non-controlling interests
 
 
 
 
 
 
 
 
 
 
 
 
$
954

Net loss attributable to the Partnership
 
 
 
 
 
 
 
 
 
 
 
 
$
(10,435
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Segment gross margin
$
13,337

 
$
9,432

 
$
3,843

 
$
20,558

 
$
11,586

 
$
22,316

 




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

 
$
164,342

 
$
23,835

 
$
26,970

 
$
34,457

 
$
69,997

 
$
393,315

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

 

 

 

 
(614
)
 
(50
)
Total revenue
73,609

 
165,011

 
23,835

 
26,970

 
34,457

 
69,383

 
393,265

Earnings in unconsolidated affiliates

 
2,569

 

 
30,385

 

 

 
32,954

Operating expenses:
 
 
 
 
 
 
 
 
 
 
 
 
 
Cost of Sales
49,769

 
154,409

 
11,938

 
5,929

 
6,466

 
33,090

 
261,601

Direct operating expenses
16,110

 
3,906

 
3,163

 
6,070

 
6,071

 
26,652

 
61,972

Corporate expenses
 
 
 
 
 
 
 
 
 
 
 
 
62,928

Depreciation, amortization and accretion expense
 
 
 
 
 
 
 
 
 
 
 
 
59,521

Gain on sale of assets, net
 
 
 
 
 
 
 
 
 
 
 
 
(176
)
Total operating expenses
 
 
 
 
 
 
 
 
 
 
 
 
445,846

Interest expense
 
 
 
 
 
 
 
 
 
 
 
 
35,118

Other income
 
 
 
 
 
 
 
 
 
 
 
 
(86
)
Loss from continuing operations before taxes
 
 
 
 
 
 
 
 
 
 
 
 
(54,659
)
Income tax expense
 
 
 
 
 
 
 
 
 
 
 
 
1,924

Net loss
 
 
 
 
 
 
 
 
 
 
 
 
(56,583
)
Less: Net income attributable to non-controlling interests
 
 
 
 
 
 
 
 
 
 
 
 
2,765

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

 
$
13,152

 
$
11,750

 
$
51,426

 
$
21,920

 
$
37,254

 

 
Six months ended June 30, 2016
 
Gas Gathering and Processing Services
 
Liquid Pipelines and Services
 
Natural Gas Transportation Services
 
Offshore Pipelines and Services
 
Terminalling Services
 
Propane Marketing Services
 
Total
Revenue
$
54,004

 
$
129,930

 
$
17,672

 
$
17,645

 
$
32,210

 
$
79,356

 
$
330,817

Gain (loss) on commodity derivatives, net
(866
)
 
(948
)
 

 
(2
)
 
(436
)
 
647

 
(1,605
)
Total revenue
53,138

 
128,982

 
17,672

 
17,643

 
31,774

 
80,003

 
329,212

Earnings in unconsolidated affiliates
 
 
1,009

 
 
 
18,036

 
 
 
 
 
19,045




 


 


 


 


 


 


Operating expenses:
 
 
 
 
 
 
 
 
 
 
 
 
 
Cost of Sales
28,868

 
115,645

 
8,250

 
1,860

 
5,747

 
28,648

 
189,018

Direct operating expenses
17,492

 
4,701

 
3,190

 
5,055

 
4,997

 
27,107

 
62,542

Corporate expenses
 
 
 
 
 
 
 
 
 
 
 
 
43,382

Depreciation, amortization and accretion expense
 
 
 
 
 
 
 
 
 
 
 
 
51,439

Loss on sale of assets, net
 
 
 
 
 
 
 
 
 
 
 
 
1,600

Total operating expenses
 
 
 
 
 
 
 
 
 
 
 
 
347,981

Interest expense
 
 
 
 
 
 
 
 
 
 
 
 
18,912

Other income
 
 
 
 
 
 
 
 
 
 
 
 
(527
)
Loss from continuing operations before taxes
 
 
 
 
 
 
 
 
 
 
 
 
(18,109
)
Income tax expense
 
 
 
 
 
 
 
 
 
 
 
 
1,436

Loss from continuing operation
 
 
 
 
 
 
 
 
 
 
 
 
(19,545
)
Loss from discontinued operations, net of tax
 
 
 
 
 
 
 
 
 
 
 
 
(539
)
Net loss
 
 
 
 
 
 
 
 
 
 
 
 
(20,084
)
Less: Net income attributable to non-controlling interests
 
 
 
 
 
 
 
 
 
 
 
 
$
951

Net loss attributable to the Partnership
 
 
 
 
 
 
 
 
 
 
 
 
$
(21,035
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Segment gross margin
$
24,957

 
$
15,284

 
$
9,406

 
$
33,819

 
$
21,030

 
$
50,621

 

















A reconciliation of Total assets by segment to the amounts included in the condensed consolidated balance sheets follows:
 
June 30,
 
December 31,
 
2017
 
2016
Segment assets:
 
 
 
Gas Gathering and Processing Services
$
524,905

 
$
530,889

Liquid Pipelines and Services
433,618

 
422,636

Offshore Pipelines and Services (2)
369,137

 
400,193

Natural Gas Transportation Services
227,466

 
221,604

Terminalling Services (2)
281,016

 
299,534

Propane Marketing Services
130,731

 
140,864

Other (1)
85,069

 
333,601

Total Assets
$
2,051,942

 
$
2,349,321

_____________________________________
(1) Other assets not allocable to segments consist of corporate leasehold improvements and other miscellaneous assets.
(2) The Partnership has revised the December 31, 2016 amounts by segment above from those amounts previously reported in its Form 10-Q for the quarter ended March 31, 2017 to increase the Offshore Pipelines and Services segment by approximately $14 million and to decrease the amounts of Other and the Offshore Pipelines and Services segment by approximately $13 million and $1 million, respectively.
Subsequent Events
Subsequent Events
Subsequent Events

Amendment No. 5 to the Partnership Agreement

On July 14, 2017, we entered into Amendment No. 5 to the Partnership Agreement, pursuant to which the Series D Warrant Determination Date was extended to August 31, 2017.

Sale of Propane Marketing Services Business

On July 21, 2017, American Midstream Merger LP (“AMID Merger Sub”), a wholly-owned subsidiary of the Partnership, entered into a Membership Interest Purchase Agreement (“Purchase Agreement”) with SHV Energy N.V. (“SHV Energy”) pursuant to which we agreed to sell 100% of our Propane Marketing Services business, including Pinnacle Propane’s 40 service locations, Pinnacle Propane Express’ cylinder exchange business and related logistic assets, and the Alliant Gas utility system to SHV Energy, for $170 million in cash, plus balance sheet cash at closing, less the repayment of all indebtedness and transaction costs, and subject to working capital adjustments.

The transaction is expected to close in the third quarter of 2017, subject to satisfaction or waiver of certain conditions, including: (i) subject to specified materiality standards, the accuracy of the representations and warranties of each party; (ii) compliance by each party in all material respects with its covenants; (iii) expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the “HSR Act”); (iv) there being no law or injunction prohibiting the consummation of the Transaction; and (v) the receipt of consent of third parties under specified contracts or the entry into substitute contractual arrangements with respect to such contracts. The Partnership has agreed to indemnify SHV Energy for certain liabilities, including certain pre-closing tax matters, specified litigation matters and certain employment-related liabilities. Certain termination rights for both AMID Merger Sub and SHV Energy including, but not limited to, the right to terminate the Purchase Agreement in the event that (i) the transaction has not been consummated on or before October 21, 2017 or (ii) under certain conditions, if there has been a breach of certain representations and warranties or a failure to perform any covenant by the other party.

Distribution

On July 25, 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 quarter ended June 30, 2017, or $1.65 per common unit on an annualized basis. The distribution is expected to be paid on August 14, 2017, to unitholders of record as of the close of business on August 7, 2017.

Acquisitions

On August 8, 2017, we announced two strategic transactions which will help to increase operating efficiency in our core areas as well as extending our participation in the value chain of our core commodities.

Acquisition of Panther
We acquired 100% of the assets of Panther Asset Management LLC (“Panther”), who is our joint venture partner in both Ampan and MPOG for a total consideration of approximately $52 million, consisting of $39 million cash from borrowings under the Partnership’s revolving credit facility and common units representing limited partner interests. The underlying assets acquired are highly complementary with our core Gulf of Mexico assets as a substantial portion of Panther’s cash flows are generated by our joint ventures. Through the purchase, we will now acquire Panther’s 33.3% equity interests in MPOG, as well as Panther’s 40% equity interest in AmPan. As such, we will now own 100% of MPOG and AmPan. This transaction allows us to both consolidate several joint ventures and moves us into an operator position for oil pipelines in the Gulf of Mexico.

Joint Venture with Targa Midstream Services, LLC
We entered into a joint venture agreement with Targa  Midstream Services, LLC (“Targa”) creating Cayenne Pipeline, LLC (“Cayenne”). Cayenne will transport Y-grade NGLs from the Targa-operated Venice Energy Services Company, LLC gas processing plant (“Venice”) to Enterprise Products’ pipeline at Toca, Louisiana, for delivery to Enterprise Products’ Norco Fractionator. As part of the Cayenne joint venture, we are contributing an underutilized natural gas pipeline that will convert into high value, natural gas liquids service. The project is supported by a 15-year dedication for all NGL production from Targa’s 750 MMcf/d Venice plant with inlet from six offshore pipelines in the Gulf of Mexico, including the prolific deep-water Mississippi Canyon area. The pipeline will have initial capacity of over 40,000 barrels per day with the ability to throughput more than 50,000 barrels per day. We and Targa will each have 50% economic interests and 50% voting rights, respectively, with Targa serving as the operator of the venture. The costs of conversion and associated construction will be shared equally by us and Targa.

The pipeline is expected to be operational by the end of the 4th quarter of 2017.
Organization, Basis of Presentation and Summary of Significant Accounting Policies (Policies)
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 six reportable segments, (1) gas gathering and processing services, (2) liquid pipelines and services, (3) natural gas transportation services, (4) offshore pipelines and services, (5) terminalling services and (6) propane marketing services, we engage in the business of gathering, treating, processing, and transporting natural gas; gathering, transporting, storing, treating and fractionating NGLs; gathering, storing and transporting crude oil and condensates; storing specialty chemical products; and distributing and selling propane and refined products. See Note 21 - Subsequent Events
regarding the announced sale of substantially all of our propane marketing services segment in July 2017.

Most of our cash flow is generated from fee-based and fixed-margin arrangements for gathering, processing, transporting and treating natural gas and crude oil, firm capacity reservation charges, interruptible transportation charges, guaranteed firm storage contracts, throughput fees and other optional charges associated with ancillary services.

Our primary assets are strategically located in some of the most prolific onshore and offshore producing regions and key demand markets in the United States. Our gathering and processing assets are primarily located in (i) the Permian Basin of West Texas, (ii) the Cotton Valley/Haynesville Shale of East Texas, (iii) the Eagle Ford Shale of South Texas, (iv) the Bakken Shale of North Dakota, and (v) offshore in the Gulf of Mexico. Our natural gas transportation, offshore pipelines and terminal assets are in key demand markets in Oklahoma, Alabama, Arkansas, Louisiana, Mississippi and Tennessee and in the Port of New Orleans in Louisiana and the Port of Brunswick in Georgia. Our propane marketing services include commercial and retail operations across 46 of the lower 48 states.

Basis of presentation

The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2016, except that the consolidated financial statements have been retrospectively adjusted to reflect the consolidation of JPE, as discussed above. The results of operations for the three and six months ended June 30, 2017 are not necessarily indicative of results expected for the full year. In the opinion of our management, such financial information reflects all adjustments necessary for a fair statement of the financial position and the results of operations for such interim periods in accordance with GAAP. All such adjustments are of a normal recurring nature. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC.
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 June 2011 (the date Arclight affiliates obtained control of JPE) or the date the ArcLight affiliate obtained control of the assets acquired.

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, asset retirement obligations, contracted arrangements and management restrictions. Such amounts are included in Restricted cash in our condensed 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, historical collection experience and the age of accounts receivable.
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 condensed 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. The unconsolidated affiliates were determined to be variable interest entities due to disproportionate economic interests and decision making rights. In each case, we lack the power to direct the activities that most significantly impact the unconsolidated affiliate’s economic performance. As we do not hold a controlling financial interest in these affiliates, we account for our related investments using the equity method. Additionally, our maximum exposure to loss related to each entity is limited to our equity investment as presented on the condensed consolidated balance sheets as of the balance sheet date. In each case, we are not obligated to absorb losses greater than our proportional ownership percentages. Our right to receive residual returns is not limited to any amount less than the ownership percentages.

Revenue recognition

We recognize revenue from the sale of commodities (e.g., natural gas, crude oil, NGLs, refined products 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.

Revenue-related taxes collected from customers and remitted to taxing authorities, principally sales taxes, are presented on a net basis within the condensed consolidated statements of operations.
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. From March 2016 to May 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; 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 and 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 the new accounting guidance for revenue recognition will have on our consolidated financial statements and related disclosures. We also have engaged a third-party consulting firm to assist us with all the three phases of adoption of the new guidance (Impact Assessment, Convert and Implement). We will adopt the new standard on its effective date January 1, 2018 using the modified retrospective method of adoption.

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. We are still in the process of evaluating the impact of ASU 2016-02 on our consolidated financial statements as we will be required to reflect our various lease obligations and associated asset use rights on our consolidated balance sheets. The adoption may also impact our debt covenant compliance and may require us to modify or replace certain of our existing information systems. We will adopt the guidance on its effective date January 1, 2019.

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. The retrospective transition method of adoption is required unless it is impracticable. Early adoption is permitted, but only if all aspects are adopted in the same period. We are still evaluating the impact of this update on our consolidated statements of cash flows and the related disclosures. We will adopt the standard upon its effective date January 1, 2018.

In November 2016, the FASB issued ASU No. 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. We have evaluated the impact of this update and believe it will have a material impact on our consolidated statement of cash flows and related disclosures, upon our effective date of adoption January 1, 2018.

In January 2017, the FASB issued ASU No. 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business” The guidance provides criteria for use in determining when to conclude an integrated “set of assets and activities (as defined in the original guidance) being acquired or disposed in a transaction is not a business. Where the criteria are not met, more stringent screening has been provided to define a set as a business without an output, as more narrowly defined within the guidance. ASU No. 2017-01 is effective for annual periods beginning after December 15, 2017, including interim periods within those periods. The amendments should be applied prospectively on or after the effective date. Early adoption is permitted. We are still in the process of evaluating the guidance and can not determine the impact of this guidance on our consolidated financial statements and related disclosures. We will adopt ASU 2017-01 on its effective date of January 1, 2018.
In January 2017, the FASB issued ASU No. 2017-04, Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment, in which the guidance on testing for goodwill was updated by the elimination of Step 2 in the determination on whether goodwill should be considered impaired. The annual and/or interim assessments are still required to be completed. Further, the guidance eliminates the requirement to assess reporting units with zero or negative carrying values, however, the carrying values for all reporting units must be disclosed. ASU No. 2017-04 is effective for annual or any interim goodwill impairment tests beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. We are currently evaluating the impact of this update on our consolidated financial statements and related disclosures and will adopt the guidance on its effective date January 1, 2020 using the required prospective method

In May 2017, the FASB issued ASU No. 2017-09, Compensation - Stock Compensation (Topic 718): Scope of Modification Accounting, to provide guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting. Pursuant to this ASU, an entity should account for the effects of a modification unless all the following are met: (1) the fair value (or calculated value or intrinsic value, if such an alternative measurement method is used) of the modified award is the same as the fair value (or calculated value or intrinsic value, if such an alternative measurement method is used) of the original award immediately before the original award is modified (if the modification does not affect any of the inputs to the valuation technique that the entity uses to value the award, the entity is not required to estimate the value immediately before and after the modification); (2) the vesting conditions of the modified award are the same as the vesting conditions of the original award immediately before the original award is modified; and (3) the classification of the modified award as an equity instrument or a liability instrument is the same as the classification of the original award immediately before the original award is modified. ASU No. 2017-09 is effective for annual periods beginning after December 15, 2017, including interim periods within those periods. Early adoption is permitted, including adoption in any interim period. This update should be applied prospectively to an award modified on or after the adoption date. The Partnership is currently evaluating the impact of this update on our consolidated financial statements and related disclosures and will adopt the guidance on our effective date January 1, 2018.
Acquisitions Acquisitions (Tables)
In accordance with ASC Topic 805 - Business Combinations, we accounted for Viosca Knoll acquisition as an acquisition of a business, with the Partnership as the acquirer. ASC 805 requires, among other things, that the consideration transferred be measured at the current market price as of the acquisition date and the asset acquired and liabilities assumed be measured at their fair value as of the acquisition date. The total consideration transferred of $32 million cash was allocated 100% to Viosca Knoll’s assets as shown below.

The following table presents our aggregated preliminary allocation of the purchase price based on estimated fair values of assets acquired as of June 30, 2017 (in thousands):

 
Purchase Price Allocation
Property, plant and equipment:
 
Pipelines
$
12,266

Equipment
16,484

Total property, plant and equipment
28,750

Intangible assets
3,250

Total cash consideration
$
32,000

The unaudited pro forma financial information consists of the following (in thousands):

 
 
 
 
 
Six Months Ended
 
June 30, 2017
 
June 30, 2016
Revenue
$
396,254

 
$
333,837

Income (loss) from continuing operations
$
(56,407
)
 
$
(17,962
)
Inventory (Tables)
Schedule of Inventory
Inventory consists of the following (in thousands):
 
 
June 30, 2017
 
December 31, 2016
Crude oil
 
$
2,741

 
$
1,216

NGLs
 
3,207

 
3,482

Refined products
 
413

 
291

Materials, supplies and equipment
 
1,744

 
1,787

   Total inventory
 
$
8,105

 
$
6,776

Other Current Assets (Tables)
Schedule of Other Current Assets
Other current assets consist of the following (in thousands):
 
June 30, 2017
 
December 31, 2016
Prepaid insurance
$
5,109

 
$
9,702

Insurance receivables
6,162

 
2,895

Due from related parties
20,853

 
4,805

Other receivables
2,363

 
2,998

Risk management assets
1,772

 
964

Other assets
3,396

 
6,303

   Total other current assets
$
39,655


$
27,667

Risk Management Activities (Tables)
Our outstanding interest rate swap contracts’ fair value consist of the following (in thousands):
Notional Amount
Term
As of June 30, 2017
 
As of December 31, 2016
$100,000
July 1, 2017 through December 29, 2017
$
119

 
$

$100,000
December 29, 2017 through January 29, 2019
208

 

$200,000
July 1, 2017 through September 3, 2019
1,711

 
1,912

$100,000
January 1, 2018 through December 31, 2021
2,385

 
3,090

$150,000
January 1, 2018 through December 31, 2022
3,944

 
5,219

 
 
$
8,367

 
$
10,221

The following table summarizes the net notional volumes of our outstanding commodity-related derivatives, excluding those contracts that qualified for the NPNS exception as of June 30, 2017 and December 31, 2016, none of which were designated as hedges for accounting purposes.

 
 
June 30, 2017
 
December 31, 2016
Commodity Swaps
 
Volume
 
Maturity
 
Volume
 
Maturity
Propane Fixed Price (gallons)
 
10,892,201

 
July 1, 2017 - December 31, 2019
 
4,364,880

 
January 31, 2017 - November 30, 2018
Crude Oil Fixed Price (barrels)
 
68,000

 
July 1, 2017 -
July 31, 2017
 
 
Crude Oil Basis (barrels)
 
 
 
180,000

 
January 25, 2017-
March 25, 2017
The following table summarizes the fair values of our derivative contracts (before netting adjustments) included in the condensed consolidated balance sheets (in thousands):
 
 
 
Asset Derivatives
 
Liability Derivatives
Type
Balance Sheet Classification
 
June 30,
2017
 
December 31, 2016
 
June 30,
2017
 
December 31, 2016
Commodity swaps
Other current assets
 
$
234

 
$
607

 
$

 
$

Commodity swaps
Accrued expenses and other current liabilities
 

 

 
(404
)
 
(1
)
Commodity swaps
Risk management assets - long term
 

 
37

 

 

Commodity swaps
Other liabilities
 

 

 
(196
)
 
(1
)
 
 
 
 
 
 
 
 
 
 
Interest rate swaps
Other current assets
 
663

 

 

 

Interest rate swaps
Accrued expenses and other current liabilities
 

 

 

 
(252
)
Interest rate swaps
Risk management assets- long term
 
7,704

 
10,628

 

 

 
 
 
 
 
 
 
 
 
 
Weather derivatives
Other current assets
 
$
1,110

 
$
429

 
$

 
$






The following tables present the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset in the condensed consolidated balance sheets that are subject to enforceable master netting arrangements (in thousands):
 
 
Gross Risk Management Position
 
Netting Adjustments
 
Net Risk Management Position
Balance Sheet Classification
 
June 30,
2017
 
December 31, 2016
 
June 30,
2017
 
December 31, 2016
 
June 30,
2017
 
December 31, 2016
Other current assets
 
$
2,006

 
$
1,036

 
$
(234
)
 
$
(72
)
 
$
1,772

 
$
964

Risk management assets- long term
 
7,704

 
10,665

 

 
(1
)
 
7,704

 
10,664

Total assets
 
$
9,710

 
$
11,701

 
$
(234
)
 
$
(73
)
 
$
9,476

 
$
11,628

 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued expenses and other liabilities
 
$
(404
)
 
$
(253
)
 
$
234

 
$
72

 
$
(170
)
 
$
(181
)
Other liabilities
 
(196
)
 
(1
)
 

 
1

 
(196
)
 

Total liabilities
 
$
(600
)
 
$
(254
)
 
$
234

 
$
73

 
$
(366
)
 
$
(181
)
For each of the three and six months ended June 30, 2017 and 2016 the realized and unrealized gains (losses) associated with our commodity, interest rate and weather derivative instruments were recorded in our unaudited condensed consolidated statements of operations as follows (in thousands):
 
Three months ended June 30,
 
Six months ended June 30,
Statement of Operations Classification
Realized
 
Unrealized
 
Realized
 
Unrealized
2017
 
 
 
 
 
 
 
Gains (losses) on commodity derivatives, net
$
260

 
$
(53
)
 
$
960

 
$
(1,010
)
Interest expense

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

 
(475
)
 

Total
$
42

 
$
(1,746
)
 
$
415

 
$
(3,020
)
2016
 
 
 
 
 
 
 
Losses on commodity derivatives, net
$
(388
)
 
$
(979
)
 
$
(776
)
 
$
(829
)
Interest expense
(32
)
 
(2,510
)
 
(32
)
 
(4,041
)
Direct operating expenses
(231
)
 

 
(451
)
 

Total
$
(651
)
 
$
(3,489
)
 
$
(1,259
)
 
$
(4,870
)
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)
 
June 30,
2017
 
December 31,
2016
Land
Infinite
 
$
23,098

 
$
23,520

Construction in progress
N/A
 
46,657

 
131,448

Buildings and improvements
4 to 40
 
24,280

 
24,225

Transportation equipment
5 to 15
 
45,090

 
44,060

Processing and treating plants (1)
8 to 40
 
141,109

 
120,977

Pipelines, compressors and right-of-way (1)
3 to 40
 
909,963

 
804,815

Storage
3 to 40
 
210,291

 
210,579

Equipment
3 to 31
 
124,607

 
102,409

Total property, plant and equipment
 
 
1,525,095

 
1,462,033

Accumulated depreciation (1)
 
 
(358,674
)
 
(317,030
)
Property, plant and equipment, net
 
 
$
1,166,421

 
$
1,145,003


_____________________________________(1) The Partnership has revised the December 31, 2016 amounts above from those amounts previously reported in its Form 10-Q for the quarter ended March 31, 2017 to primarily decrease the amount for Processing and treating plants by approximately $16 million and to increase the amount for Pipelines, compressors and rights-of-way by approximately $49.9 million, with the offsetting change to Accumulated depreciation of approximately $33.9 million
Goodwill and Intangible Assets, Net (Tables)
Goodwill as of June 30, 2017 and December 31, 2016 consisted of the following (in thousands):
 
June 30, 2017
 
December 31, 2016
Liquid Pipelines and Services (1)
$
113,669

 
$
113,669

Terminalling Services (1)
88,466

 
88,466

Propane Marketing Services
15,363

 
15,363

Total
$
217,498

 
$
217,498

_____________________________________
(1) The Partnership has revised the December 31, 2016 amounts by segment above from those amounts previously reported in its Form 10-Q for the quarter ended March 31, 2017 to increase the Terminalling Services segment by approximately $11 million with the offset being to decrease the Liquid Pipelines and Services segment by the same amount.  
Intangible assets, net, consist of the following (in thousands):
 
June 30, 2017
 
Gross carrying amount
 
Accumulated amortization
 
Net carrying amount
Customer relationships
$
133,503

 
$
(35,834
)
 
$
97,669

Customer contracts
98,844

 
(43,142
)
 
55,702

Dedicated acreage
53,350

 
(5,328
)
 
48,022

Collaborative arrangements
11,884

 
(990
)
 
10,894

Noncompete agreements
3,423

 
(3,250
)
 
173

Other
751

 
(221
)
 
530

Total
$
301,755

 
$
(88,765
)
 
$
212,990

 
 
 
 
 
 
 
December 31, 2016
 
Gross carrying amount
 
Accumulated amortization
 
Net carrying amount
Customer relationships
$
133,503

 
$
(31,471
)
 
$
102,032

Customer contracts
95,594

 
(33,414
)
 
62,180

Dedicated acreage
53,350

 
(4,439
)
 
48,911

Collaborative arrangements
11,884

 
(601
)
 
11,283

Noncompete agreements
3,423

 
(3,086
)
 
337

Other
751

 
(211
)
 
540

Total
$
298,505

 
$
(73,222
)
 
$
225,283

Investment in unconsolidated affiliates (Tables)
The following table presents the activity in our equity method investments in unconsolidated affiliates (in thousands):
 
Delta House (1)
 
Emerald Transactions (2)
 
 
 
 
 
FPS
 
OGL
 
Destin
 
Tri-States
 
Okeanos
 
Wilprise
 
MPOG (3)
 
Total
Ownership % at December 31, 2016 and June 30, 2017
20.1
%
 
20.1
%
 
49.7
%
 
16.7
%
 
66.7
%
 
25.3
%
 
66.7
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balances at December 31, 2016
$
64,483

 
$
25,450

 
$
110,882

 
$
55,022

 
$
27,059

 
$
4,944

 
$
4,148

 
$
291,988

  Earnings in unconsolidated affiliates
15,529

 
6,571

 
5,116

 
2,161

 
3,692

 
408

 
(523
)
 
32,954

  Distributions
(8,753
)
 
(7,137
)
 
(12,119
)
 
(2,626
)
 
(6,667
)
 
(392
)
 
(700
)
 
(38,394
)
Balances at June 30, 2017
$
71,259

 
$
24,884

 
$
103,879

 
$
54,557


$
24,084


$
4,960


$
2,925


$
286,548

 
___________________________________________________ 
(1) Represents direct and indirect ownership interests in Class A Units.
(2) Represents our Emerald equity method investments which were acquired in the second quarter of 2016.
(3) Main Pass Oil Gathering.

The following tables present the summarized combined financial information for our equity investments (amounts represent 100% of investee financial information) (in thousands):
Balance Sheets:
June 30, 2017
 
December 31, 2016
Current assets
$
105,211

 
$
120,167

Non-current assets
1,337,201

 
1,369,492

Current liabilities
121,966

 
133,085

Non-current liabilities
$
489,080

 
$
541,312


 
Three months ended June 30,
 
Six months ended June 30,
Statements of Operations:
2017
 
2016
 
2017
 
2016
Revenue
$
105,373

 
$
89,541

 
$
203,366

 
$
184,757

Gross profit
96,442

 
83,045

 
185,075

 
169,668

Net income
$
76,414

 
$
67,937

 
$
145,532

 
$
136,387

Accrued Expenses and Other Current Liabilities (Tables)
Schedule of Accrued Liabilities
Accrued expenses and other current liabilities consists of the following (in thousands):
 
 
June 30, 2017
 
December 31, 2016
Due to related parties
 
$
15,694

 
$
4,072

Accrued interest
 
8,470

 
5,743

Legal accrual
 
8,192

 

Capital expenditures
 
7,240

 
14,499

Convertible preferred unit distributions
 
6,735

 
7,103

Current portion of asset retirement obligation
 
6,495

 
6,499

Additional Blackwater acquisition consideration
 
5,000

 
5,000

Employee compensation
 
4,967

 
10,804

Taxes payable
 
3,902

 
1,688

Royalties payable
 
3,536

 
3,926

Customer deposits
 
3,092

 
3,080

Gas imbalances payable
 
1,580

 
1,098

Transaction costs
 
1,179

 
3,000

Deferred financing costs
 

 
2,743

Recoverable gas costs
 
238

 
1,126

Other
 
10,706

 
10,903

   Total accrued expenses and other current liabilities
 
$
87,026


$
81,284

Asset Retirement Obligations (Tables)
Schedule of Change in Asset Retirement Obligation
The following table presents activity in our asset retirement obligations for the six months ended June 30, 2017 (in thousands):
Non-current balance
$
44,363

Current balance
6,499

Balances at December 31, 2016
$
50,862

Expenditures
(49
)
Accretion expense
984

Balances at June 30, 2017
$
51,797

Less: current portion
6,495

Noncurrent asset retirement obligation
$
45,302

Debt Obligations (Tables)
Outstanding borrowings under the credit facility
Our outstanding debt consists of the following (in thousands):
 
June 30, 2017
 
December 31, 2016
Revolving credit facility
$
678,042

 
$
888,250

8.5% Senior unsecured notes, due 2021
300,000

 
300,000

3.77% Senior secured notes, due 2031 (non-recourse)
58,922

 
60,000

Other debt (2)
685

 
3,809

Total debt obligations
1,037,649

 
1,252,059

Unamortized debt issuance costs (1)
(9,776
)
 
(11,036
)
Total debt
1,027,873

 
1,241,023

Less: Current portion, including unamortized debt issuance costs
(1,556
)
 
(5,485
)
Long term debt
$
1,026,317

 
$
1,235,538

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

(2) Other debt includes capital lease and miscellaneous long-term obligations, which are reported in Current portion of debt and Other liabilities line items on our condensed consolidated balance sheets.

Convertible Preferred Units (Tables)
Schedule of Preferred Units
Our convertible preferred units consist of the following (in thousands):
 
Series A
 
Series C
 
Series D
 
Total
 
Units
$
 
Units
$
 
Units
$
 
$
December 31, 2016
10,107

$
181,386

 
8,792

$
118,229

 
2,333

$
34,475

 
$
334,090

Paid in kind unit distributions
293

4,105

 


 


 
4,105

June 30, 2017
10,400

$
185,491

 
8,792

$
118,229

 
2,333

$
34,475

 
$
338,195

Partners Capital (Tables)
Schedule of Units Outstanding and Distributions
We made the following distributions (in thousands):

 
 
Three months ended June 30,
 
Six months ended June 30,
 
 
2017
 
2016
 
2017
 
2016
Series A Units
 
 
 
 
 
 
 
 
Cash Paid
 
$
2,117

 
$

 
$
4,644

 
$

Accrued
 
4,069

 
4,602

 
4,069

 
4,602

Paid-in-kind units
 
2,181

 
4,471

 
4,914

 
8,851

 
 
 
 
 
 
 
 
 
Series C Units
 
 
 
 
 
 
 
 
Cash Paid
 
3,627

 

 
7,254

 

Accrued
 
3,627

 
2,249

 
3,627

 
2,249

Paid-in-kind units
 

 

 

 

 
 
 
 
 
 
 
 
 
Series D Units
 
 
 
 
 
 
 
 
Cash Paid
 
963

 

 
1,925

 

Accrued
 
963

 

 
963

 

 
 
 
 
 
 
 
 
 
Limited Partner Units
 
 
 
 
 
 
 
 
Cash Paid
 
21,390

 
24,782

 
46,303

 
51,782

 
 
 
 
 
 
 
 
 
General Partner Units
 
 
 
 
 
 
 
 
Cash Paid
 
201

 
173

 
368

 
2,201

 
 
 
 
 
 
 
 
 
Summary
 
 
 
 
 
 
 
 
Cash Paid
 
28,298

 
24,955

 
60,494

 
53,983

Accrued
 
8,659

 
6,851

 
8,659

 
6,851

Paid-in-kind units
 
2,181

 
4,471

 
4,914

 
8,851



The following table presents unit activity (in thousands):
 
 
General
Partner Interest
 
Limited Partner Interest
Balances at December 31, 2016
 
680

 
51,351

LTIP vesting
 

 
373

Issuance of GP units
 
273

 

Issuance of common units
 

 
21

Balances at June 30, 2017
 
953

 
51,745

Net Loss per Limited Partner Unit (Tables)
Schedule of Calculation for Net Loss Per Limited Partner Unit
The calculation of basic and diluted limited partners' net loss per common unit is summarized below (in thousands, except per unit amounts):

 
Three months ended June 30,
 
Six months ended June 30,
 
2017
 
2016
 
2017
 
2016
Net loss from continuing operations
$
(27,702
)
 
$
(9,481
)
 
$
(56,583
)
 
$
(19,545
)
Less: Net income attributable to noncontrolling interests
1,462

 
954

 
2,765

 
951

Net loss from continuing operations attributable to the Partnership
(29,164
)
 
(10,435
)
 
(59,348
)
 
(20,496
)
Less:
 
 
 
 
 
 
 
Distributions on Series A Units
4,069

 
4,602

 
8,367

 
9,073

Distributions on Series C Units
3,627

 
2,249

 
7,254

 
2,249

Distributions on Series D Units
963

 

 
1,925

 

General partner's distribution
277

 
173

 
476

 
2,201

General partner's share in undistributed loss
(784
)
 
(400
)
 
(1,541
)
 
(818
)
Net loss from continuing operations attributable to Limited Partners
(37,316
)
 
(17,059
)
 
(75,829
)
 
(33,201
)
Net loss from discontinued operations attributable to Limited Partners

 

 

 
(539
)
Net loss attributable to Limited Partners
$
(37,316
)
 
$
(17,059
)
 
$
(75,829
)
 
$
(33,740
)
 
 
 
 
 
 
 
 
Weighted average number of common units used in computation of Limited Partners' net loss per common unit - basic and diluted
51,870

 
51,090

 
51,870

 
51,090

 
 
 
 
 
 
 
 
Limited Partners' net loss from continuing operations per unit
$
(0.72
)
 
$
(0.33
)
 
$
(1.46
)
 
$
(0.65
)
Limited Partners' net loss from discontinued operations per unit

 

 

 
(0.01
)
Limited Partners' net loss per common unit (1)
$
(0.72
)
 
$
(0.33
)
 
$
(1.46
)
 
$
(0.66
)
_____________________________________
(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 loss per common unit.
Long-Term Incentive Plan (Tables)
Table summarizes our unit-based awards
The following table summarizes activity in our phantom unit-based awards for the six months ended June 30, 2017:

 
 
Units
 
Weighted-Average Grant Date Fair Value Per Unit
Outstanding units at December 31, 2016
 
1,558,835

 
$
6.98

Granted
 
2,000

 
11.20

Forfeited
 
(7,643
)
 
21.46

Vested
 
(479,130
)
 
10.32

Outstanding units at June 30, 2017
 
1,074,062

 
$
5.39

Supplemental Cash Flow Information (Tables)
Schedule of Supplemental Cash Flow Information
Supplemental cash flows and non-cash transactions consist of the following (in thousands):
 
Six months ended June 30,
 
2017
 
2016
Supplemental non-cash information
 
 
 
Investing
 
 
 
Increase (decrease) in accrued property, plant and equipment purchases
$
(7,259
)
 
$
4,856

Financing
 
 
 
Contributions from an affiliate holding limited partner interests
4,000

 
4,000

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

 
120,000

Accrued distributions on convertible preferred units
8,659

 
6,851

Paid-in-kind distributions on convertible preferred units
4,914

 
8,851

Cancellation of escrow units

 
6,817

Accrued distribution from unconsolidated affiliates

 
4,360

Reportable Segments (Tables)
Segment information
A reconciliation from Segment Gross Margin to Net Income attributable to the Partnership for the periods presented is below (in thousands):

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

2017
 
2016
 
2017
 
2016
Reconciliation of Segment Gross Margin to Net loss attributable to the Partnership:
 
 
 
 
 
 
 
Gas Gathering and Processing Services segment gross margin
$
12,651

 
$
13,337

 
$
23,902

 
$
24,957

Liquid Pipelines and Services segment gross margin
6,683

 
9,432

 
13,152

 
15,284

Natural Gas Transportation Services segment gross margin
5,631

 
3,843

 
11,750

 
9,406

Offshore Pipelines and Services segment gross margin
25,623

 
20,558

 
51,426

 
33,819

Terminalling Services segment gross margin (1)
10,760

 
11,586

 
21,920

 
21,030

Propane Marketing Services segment gross margin
17,952

 
22,316

 
37,254

 
50,621

Total Segment Gross Margin
79,300

 
81,072

 
159,404

 
155,117

Less:
 
 
 
 
 
 
 
Other direct operating expenses (1)
28,886

 
29,579

 
55,902

 
57,545

Plus:
 
 
 
 
 
 
 
Gain (loss) on commodity derivatives, net
207

 
(1,367
)
 
(50
)
 
(1,605
)
Less:
 
 
 
 
 
 
 
Corporate expenses
30,084

 
22,281

 
62,928

 
43,382

Depreciation, amortization and accretion expense
30,170

 
26,398

 
59,521

 
51,439

(Gain) loss on sale of assets, net
52

 
478

 
(176
)
 
1,600

Interest expense
17,152

 
10,610

 
35,118

 
18,912

Other income
(72
)
 
(496
)
 
(86
)
 
(527
)
Other (income) expense, net
136

 
(365
)
 
806

 
(730
)
Income tax expense
801

 
701

 
1,924

 
1,436

Loss from discontinued operations, net of tax

 

 

 
539

Net income attributable to noncontrolling interest
1,462

 
954

 
2,765

 
951

Net loss attributable to the Partnership
$
(29,164
)
 
$
(10,435
)
 
$
(59,348
)
 
$
(21,035
)
_____________________________________
(1)
Other direct operating expenses include Gas Gathering and Processing Services segment direct operating expenses of $8.0 million and $8.9 million, respectively, Liquid Pipelines and Services segment direct operating expenses of $1.8 million and $2.2 million, respectively, Natural Gas Transportation Services segment direct operating expenses of $1.9 million and $2.0 million, respectively, Offshore Pipelines and Services segment direct operating expenses of $3.5 million and $2.8 million, respectively, and Propane Marketing Services segment direct operating expenses of $13.6 million and $13.6 million, respectively, for the three months ended June 30, 2017 and 2016. Direct operating expenses related to our Terminalling Services segment of $3.0 million and $2.4 million for the three months ended June 30, 2017 and 2016, respectively, are included within the calculation of Terminalling Services segment gross margin.
Other direct operating expenses include Gas Gathering and Processing Services segment direct operating expenses of $16.1 million and $17.5 million, respectively, Liquid Pipelines and Services segment direct operating expenses of $3.9 million and $4.7 million, respectively, Natural Gas Transportation Services segment direct operating expenses of $3.2 million and $3.2 million, respectively, Offshore Pipelines and Services segment direct operating expenses of $6.1 million and $5.1 million, respectively, and Propane Marketing Services segment direct operating expenses of $26.7 million and $27.1 million, respectively, for the six months ended June 30, 2017 and 2016. Direct operating expenses related to our Terminalling Services segment of $6.1 million and $5.0 million for the six months ended June 30, 2017 and 2016, respectively, are included within the calculation of Terminalling Services segment gross margin.


The following tables set forth our segment information for the three and six months ended June 30, 2017 and 2016 (in thousands):
 
Three months ended June 30, 2017
 
Gas Gathering and Processing Services
 
Liquid Pipelines and Services
 
Natural Gas Transportation Services
 
Offshore Pipelines and Services
 
Terminalling Services
 
Propane Marketing Services
 
Total
Revenue
$
39,307

 
$
82,303

 
$
11,397

 
$
12,139

 
$
15,831

 
$
32,449

 
$
193,426

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

 

 

 

 
8

 
207

Total revenue
39,209

 
82,600

 
11,397

 
12,139

 
15,831

 
32,457

 
193,633

Earnings in unconsolidated affiliates

 
1,482

 

 
16,070

 

 

 
17,552

Operating expenses:
 
 
 
 
 
 
 
 
 
 
 
 
 
Cost of Sales
26,582

 
77,332

 
5,678

 
2,586

 
2,073

 
14,565

 
128,816

Direct operating expenses
8,045

 
1,833

 
1,928

 
3,490

 
2,998

 
13,590

 
31,884

Corporate expenses
 
 
 
 
 
 
 
 
 
 
 
 
30,084

Depreciation, amortization and accretion expense
 
 
 
 
 
 
 
 
 
 
 
 
30,170

Loss on sale of assets, net
 
 
 
 
 
 
 
 
 
 
 
 
52

Total operating expenses
 
 
 
 
 
 
 
 
 
 
 
 
221,006

Interest expense
 
 
 
 
 
 
 
 
 
 
 
 
17,152

Other income
 
 
 
 
 
 
 
 
 
 
 
 
(72
)
Loss from continuing operations before taxes
 
 
 
 
 
 
 
 
 
 
 
 
(26,901
)
Income tax expense
 
 
 
 
 
 
 
 
 
 
 
 
801

Net loss
 
 
 
 
 
 
 
 
 
 
 
 
(27,702
)
Less: Net income attributable to non-controlling interests
 
 
 
 
 
 
 
 
 
 
 
 
1,462

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

 
$
6,683

 
$
5,631

 
$
25,623

 
$
10,760

 
$
17,952

 


 
Three months ended June 30, 2016
 
Gas Gathering and Processing Services
 
Liquid Pipelines and Services
 
Natural Gas Transportation Services
 
Offshore Pipelines and Services
 
Terminalling Services
 
Propane Marketing Services
 
Total
Revenue
$
30,710

 
$
85,415

 
$
7,877

 
$
10,645

 
$
17,815

 
$
34,741

 
$
187,203

Gain (loss) on commodity derivatives, net
(763
)
 
(716
)
 

 
(2
)
 
(260
)

374

 
(1,367
)
Total revenue
29,947

 
84,699

 
7,877

 
10,643

 
17,555

 
35,115

 
185,836

Earnings in unconsolidated affiliates

 
1,009

 

 
10,693

 

 

 
11,702




 


 


 


 


 


 


Operating expenses:
 
 
 
 
 
 
 
 
 
 
 
 
 
Cost of Sales
17,162

 
76,992

 
4,026

 
778

 
3,542

 
12,580

 
115,080

Direct operating expenses
8,945

 
2,235

 
1,963

 
2,802

 
2,388

 
13,634

 
31,967

Corporate expenses
 
 
 
 
 
 
 
 
 
 
 
 
22,281

Depreciation, amortization and accretion expense
 
 
 
 
 
 
 
 
 
 
 
 
26,398

Loss on sale of assets, net
 
 
 
 
 
 
 
 
 
 
 
 
478

Total operating expenses
 
 
 
 
 
 
 
 
 
 
 
 
196,204

Interest expense
 
 
 
 
 
 
 
 
 
 
 
 
10,610

Other income
 
 
 
 
 
 
 
 
 
 
 
 
(496
)
Loss from continuing operations before taxes
 
 
 
 
 
 
 
 
 
 
 
 
(8,780
)
Income tax expense
 
 
 
 
 
 
 
 
 
 
 
 
701

Loss from continuing operation
 
 
 
 
 
 
 
 
 
 
 
 
(9,481
)
Loss from discontinued operations, net of tax
 
 
 
 
 
 
 
 
 
 
 
 
$

Net loss
 
 
 
 
 
 
 
 
 
 
 
 
(9,481
)
Less: Net income attributable to non-controlling interests
 
 
 
 
 
 
 
 
 
 
 
 
$
954

Net loss attributable to the Partnership
 
 
 
 
 
 
 
 
 
 
 
 
$
(10,435
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Segment gross margin
$
13,337

 
$
9,432

 
$
3,843

 
$
20,558

 
$
11,586

 
$
22,316

 




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

 
$
164,342

 
$
23,835

 
$
26,970

 
$
34,457

 
$
69,997

 
$
393,315

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

 

 

 

 
(614
)
 
(50
)
Total revenue
73,609

 
165,011

 
23,835

 
26,970

 
34,457

 
69,383

 
393,265

Earnings in unconsolidated affiliates

 
2,569

 

 
30,385

 

 

 
32,954

Operating expenses:
 
 
 
 
 
 
 
 
 
 
 
 
 
Cost of Sales
49,769

 
154,409

 
11,938

 
5,929

 
6,466

 
33,090

 
261,601

Direct operating expenses
16,110

 
3,906

 
3,163

 
6,070

 
6,071

 
26,652

 
61,972

Corporate expenses
 
 
 
 
 
 
 
 
 
 
 
 
62,928

Depreciation, amortization and accretion expense
 
 
 
 
 
 
 
 
 
 
 
 
59,521

Gain on sale of assets, net
 
 
 
 
 
 
 
 
 
 
 
 
(176
)
Total operating expenses
 
 
 
 
 
 
 
 
 
 
 
 
445,846

Interest expense
 
 
 
 
 
 
 
 
 
 
 
 
35,118

Other income
 
 
 
 
 
 
 
 
 
 
 
 
(86
)
Loss from continuing operations before taxes
 
 
 
 
 
 
 
 
 
 
 
 
(54,659
)
Income tax expense
 
 
 
 
 
 
 
 
 
 
 
 
1,924

Net loss
 
 
 
 
 
 
 
 
 
 
 
 
(56,583
)
Less: Net income attributable to non-controlling interests
 
 
 
 
 
 
 
 
 
 
 
 
2,765

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

 
$
13,152

 
$
11,750

 
$
51,426

 
$
21,920

 
$
37,254

 

 
Six months ended June 30, 2016
 
Gas Gathering and Processing Services
 
Liquid Pipelines and Services
 
Natural Gas Transportation Services
 
Offshore Pipelines and Services
 
Terminalling Services
 
Propane Marketing Services
 
Total
Revenue
$
54,004

 
$
129,930

 
$
17,672

 
$
17,645

 
$
32,210

 
$
79,356

 
$
330,817

Gain (loss) on commodity derivatives, net
(866
)
 
(948
)
 

 
(2
)
 
(436
)
 
647

 
(1,605
)
Total revenue
53,138

 
128,982

 
17,672

 
17,643

 
31,774

 
80,003

 
329,212

Earnings in unconsolidated affiliates
 
 
1,009

 
 
 
18,036

 
 
 
 
 
19,045




 


 


 


 


 


 


Operating expenses:
 
 
 
 
 
 
 
 
 
 
 
 
 
Cost of Sales
28,868

 
115,645

 
8,250

 
1,860

 
5,747

 
28,648

 
189,018

Direct operating expenses
17,492

 
4,701

 
3,190

 
5,055

 
4,997

 
27,107

 
62,542

Corporate expenses
 
 
 
 
 
 
 
 
 
 
 
 
43,382

Depreciation, amortization and accretion expense
 
 
 
 
 
 
 
 
 
 
 
 
51,439

Loss on sale of assets, net
 
 
 
 
 
 
 
 
 
 
 
 
1,600

Total operating expenses
 
 
 
 
 
 
 
 
 
 
 
 
347,981

Interest expense
 
 
 
 
 
 
 
 
 
 
 
 
18,912

Other income
 
 
 
 
 
 
 
 
 
 
 
 
(527
)
Loss from continuing operations before taxes
 
 
 
 
 
 
 
 
 
 
 
 
(18,109
)
Income tax expense
 
 
 
 
 
 
 
 
 
 
 
 
1,436

Loss from continuing operation
 
 
 
 
 
 
 
 
 
 
 
 
(19,545
)
Loss from discontinued operations, net of tax
 
 
 
 
 
 
 
 
 
 
 
 
(539
)
Net loss
 
 
 
 
 
 
 
 
 
 
 
 
(20,084
)
Less: Net income attributable to non-controlling interests
 
 
 
 
 
 
 
 
 
 
 
 
$
951

Net loss attributable to the Partnership
 
 
 
 
 
 
 
 
 
 
 
 
$
(21,035
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Segment gross margin
$
24,957

 
$
15,284

 
$
9,406

 
$
33,819

 
$
21,030

 
$
50,621

 

















A reconciliation of Total assets by segment to the amounts included in the condensed consolidated balance sheets follows:
 
June 30,
 
December 31,
 
2017
 
2016
Segment assets:
 
 
 
Gas Gathering and Processing Services
$
524,905

 
$
530,889

Liquid Pipelines and Services
433,618

 
422,636

Offshore Pipelines and Services (2)
369,137

 
400,193

Natural Gas Transportation Services
227,466

 
221,604

Terminalling Services (2)
281,016

 
299,534

Propane Marketing Services
130,731

 
140,864

Other (1)
85,069

 
333,601

Total Assets
$
2,051,942

 
$
2,349,321

_____________________________________
(1) Other assets not allocable to segments consist of corporate leasehold improvements and other miscellaneous assets.
(2) The Partnership has revised the December 31, 2016 amounts by segment above from those amounts previously reported in its Form 10-Q for the quarter ended March 31, 2017 to increase the Offshore Pipelines and Services segment by approximately $14 million and to decrease the amounts of Other and the Offshore Pipelines and Services segment by approximately $13 million and $1 million, respectively.

Organization, Basis of Presentation and Summary of Significant Accounting Policies (Details) (USD $)
Share data in Thousands, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2017
Jun. 30, 2016
Jun. 30, 2017
segments
Jun. 30, 2016
Dec. 31, 2016
Jun. 30, 2017
Senior Notes [Member]
8.50% Senior Notes [Member]
Mar. 8, 2017
Senior Notes [Member]
8.50% Senior Notes [Member]
Dec. 28, 2016
Senior Notes [Member]
8.50% Senior Notes [Member]
Jun. 30, 2017
Senior Notes [Member]
Senior Notes, Due 2021 [Member]
Mar. 8, 2017
General Partner [Member]
Mar. 8, 2017
Affiliated Entity [Member]
General Partner [Member]
Mar. 8, 2017
JPE Energy Partners [Member]
Mar. 8, 2017
JPE Energy Partners [Member]
Affiliated Entity [Member]
Debt Instrument [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
General partners' capital account, percentage
 
 
77.00% 
 
 
 
 
 
 
 
 
 
 
Limited partners' capital account, percentage
 
 
23.00% 
 
 
 
 
 
 
 
 
 
 
General Partners' Capital Account, Units Issued
 
 
 
 
 
 
 
 
 
20,200 
9,800 
20,200 
9,800 
Debt instrument, interest rate, stated percentage
 
 
 
 
 
8.50% 
8.50% 
8.50% 
8.50% 
 
 
 
 
Number of Reportable Segments
 
 
 
 
 
 
 
 
 
 
 
 
Allowance for doubtful accounts receivable
$ 1,872,000 
 
$ 1,872,000 
 
$ 1,871,000 
 
 
 
 
 
 
 
 
Income tax expense
801,000 
701,000 
1,924,000 
1,436,000 
 
 
 
 
 
 
 
 
 
Debt instrument, face amount
 
 
 
 
 
 
 
300,000,000 
 
 
 
 
 
Repayments of lines of credit
 
 
$ 383,908,000 
$ 101,900,000 
 
 
 
 
 
 
 
 
 
Acquisitions (Narrative) (Details) (USD $)
In Millions, except Share data in Thousands, unless otherwise specified
0 Months Ended 0 Months Ended
Mar. 8, 2017
JPE Energy Partners [Member]
business_segment
Mar. 8, 2017
General Partner [Member]
Mar. 8, 2017
General Partner [Member]
Affiliated Entity [Member]
Mar. 8, 2017
Affiliated Holders [Member]
Mar. 8, 2017
Public Unit Consideration [Member]
Jun. 2, 2017
Viosca Knoll [Member]
Jun. 2, 2017
Viosca Knoll [Member]
Business Acquisition [Line Items]
 
 
 
 
 
 
 
Merger agreement, conversion ratio
 
 
 
0.5775 
0.5225 
 
 
General Partners' Capital Account, Units Issued
 
20,200 
9,800 
 
 
 
 
Number of operating segments
 
 
 
 
 
 
Voting interests acquired (percent)
 
 
 
 
 
 
100.00% 
Total consideration upon acquisition
 
 
 
 
 
$ 32 
 
Viosca Knoll Transaction (Details) (Viosca Knoll [Member], USD $)
In Thousands, unless otherwise specified
Jun. 30, 2017
Business Acquisition [Line Items]
 
Total property, plant and equipment
$ 28,750 
Intangible assets
3,250 
Total cash consideration
32,000 
Pipelines [Member]
 
Business Acquisition [Line Items]
 
Total property, plant and equipment
12,266 
Equipment [Member]
 
Business Acquisition [Line Items]
 
Total property, plant and equipment
$ 16,484 
Viosca Knoll Proforma Information (Details) (USD $)
In Thousands, unless otherwise specified
6 Months Ended
Jun. 30, 2017
Jun. 30, 2016
Business Acquisition [Line Items]
 
 
Revenue
$ 396,254 
$ 333,837 
Income (loss) from continuing operations
(56,407)
 
Viosca Knoll [Member]
 
 
Business Acquisition [Line Items]
 
 
Income (loss) from continuing operations
 
$ (17,962)
Inventory (Details) (USD $)
In Thousands, unless otherwise specified
Jun. 30, 2017
Dec. 31, 2016
Inventory Disclosure [Abstract]
 
 
Crude oil
$ 2,741 
$ 1,216 
NGLs
3,207 
3,482 
Refined products
413 
291 
Materials, supplies and equipment
1,744 
1,787 
Total inventory
$ 8,105 
$ 6,776 
Other Current Assets (Details) (USD $)
In Thousands, unless otherwise specified
Jun. 30, 2017
Dec. 31, 2016
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
 
 
Prepaid insurance
$ 5,109 
$ 9,702 
Insurance receivables
6,162 
2,895 
Due from related parties
20,853 
4,805 
Other receivables
2,363 
2,998 
Risk management assets
1,772 
964 
Other assets
3,396 
6,303 
Total other current assets
$ 39,655 
$ 27,667 
Risk Management Activities (Interest Rate Swaps) (Details) (Interest Rate Swap [Member], USD $)
Jun. 30, 2017
Dec. 31, 2016
Derivative [Line Items]
 
 
As of June 30, 2017
$ 8,367,000 
$ 10,221,000 
July 1, 2017 through December 29, 2017
 
 
Derivative [Line Items]
 
 
Notional Amount
100,000,000 
 
As of June 30, 2017
119,000 
December 29, 2017 through January 29, 2019
 
 
Derivative [Line Items]
 
 
Notional Amount
100,000,000 
 
As of June 30, 2017
208,000 
July 1, 2017 through September 3, 2019
 
 
Derivative [Line Items]
 
 
Notional Amount
200,000,000 
 
As of June 30, 2017
1,711,000 
1,912,000 
January 1, 2018 through December 31, 2021
 
 
Derivative [Line Items]
 
 
Notional Amount
100,000,000 
 
As of June 30, 2017
2,385,000 
3,090,000 
January 1, 2018 through December 31, 2022
 
 
Derivative [Line Items]
 
 
Notional Amount
150,000,000 
 
As of June 30, 2017
$ 3,944,000 
$ 5,219,000 
Risk Management Activities (Narrative) (Details) (Weather Contract [Member], USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2016
Jun. 30, 2017
Jun. 30, 2016
Dec. 31, 2016
Weather Contract [Member]
 
 
 
 
Derivative [Line Items]
 
 
 
 
Potential proceeds from derivative contract
$ 30.0 
 
 
 
Payment for weather derivative premium
 
1.1 
1.0 
 
Derivative term of contract
 
1 year 0 months 0 days 
 
 
Debt instrument, unamortized premium
 
$ 1.1 
 
$ 0.4 
Risk Management Activities (Fair Value of Commodity Derivatives) (Details) (USD $)
In Thousands, unless otherwise specified
Jun. 30, 2017
Dec. 31, 2016
Derivative Asset [Abstract]
 
 
Gross Risk Management Position
$ 9,710 
$ 11,701 
Netting Adjustments
(234)
(73)
Net Risk Management Position
9,476 
11,628 
Derivative Liability [Abstract]
 
 
Gross Risk Management Position
(600)
(254)
Netting Adjustments
234 
73 
Net Risk Management Position
(366)
(181)
Other Current Assets [Member] |
Commodity derivatives [Member]
 
 
Derivative Asset [Abstract]
 
 
Gross Risk Management Position
234 
607 
Derivative Liability [Abstract]
 
 
Netting Adjustments
Other Current Assets [Member] |
Interest Rate Swap [Member]
 
 
Derivative Asset [Abstract]
 
 
Gross Risk Management Position
663 
Derivative Liability [Abstract]
 
 
Netting Adjustments
Other Current Assets [Member] |
Weather Derivative [Member]
 
 
Derivative Asset [Abstract]
 
 
Gross Risk Management Position
1,110 
429 
Derivative Liability [Abstract]
 
 
Netting Adjustments
Accrued Expenses and Other Liabilities [Member] |
Commodity derivatives [Member]
 
 
Derivative Asset [Abstract]
 
 
Gross Risk Management Position
Derivative Liability [Abstract]
 
 
Netting Adjustments
(404)
(1)
Accrued Expenses and Other Liabilities [Member] |
Interest Rate Swap [Member]
 
 
Derivative Asset [Abstract]
 
 
Gross Risk Management Position
Derivative Liability [Abstract]
 
 
Netting Adjustments
(252)
Risk Management Assets [Member]
 
 
Derivative Asset [Abstract]
 
 
Gross Risk Management Position
2,006 
1,036 
Netting Adjustments
(234)
(72)
Net Risk Management Position
1,772 
964 
Risk Management Assets - Long Term [Member]
 
 
Derivative Asset [Abstract]
 
 
Gross Risk Management Position
7,704 
10,665 
Netting Adjustments
(1)
Net Risk Management Position
7,704 
10,664 
Risk Management Assets - Long Term [Member] |
Commodity derivatives [Member]
 
 
Derivative Asset [Abstract]
 
 
Gross Risk Management Position
37 
Derivative Liability [Abstract]
 
 
Netting Adjustments
Risk Management Assets - Long Term [Member] |
Interest Rate Swap [Member]
 
 
Derivative Asset [Abstract]
 
 
Gross Risk Management Position
7,704 
10,628 
Derivative Liability [Abstract]
 
 
Netting Adjustments
Other Liabilities [Member] |
Commodity derivatives [Member]
 
 
Derivative Asset [Abstract]
 
 
Gross Risk Management Position
Derivative Liability [Abstract]
 
 
Netting Adjustments
(196)
(1)
Risk Management Liabilities [Member]
 
 
Derivative Liability [Abstract]
 
 
Gross Risk Management Position
(404)
(253)
Netting Adjustments
234 
72 
Net Risk Management Position
(170)
(181)
Risk Management Liabilities - Long Term [Member]
 
 
Derivative Liability [Abstract]
 
 
Gross Risk Management Position
(196)
(1)
Netting Adjustments
Net Risk Management Position
$ (196)
$ 0 
Risk Management Activities (Realized and Unrealized Gains (Losses)) (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2017
Jun. 30, 2016
Jun. 30, 2017
Jun. 30, 2016
Derivatives, Fair Value [Line Items]
 
 
 
 
Gains (losses) on commodity derivatives, net
$ 207 
$ (1,367)
$ (50)
$ (1,605)
Commodity derivatives [Member]
 
 
 
 
Derivatives, Fair Value [Line Items]
 
 
 
 
Gains (losses) on commodity derivatives, net
42 
(651)
415 
(1,259)
Unrealized gain (loss) on derivatives
(1,746)
(3,489)
(3,020)
(4,870)
Commodity derivatives [Member] |
Gain (Loss) on Derivative Instruments [Member]
 
 
 
 
Derivatives, Fair Value [Line Items]
 
 
 
 
Gains (losses) on commodity derivatives, net
260 
(388)
960 
(776)
Unrealized gain (loss) on derivatives
(53)
(979)
(1,010)
(829)
Commodity derivatives [Member] |
Interest Expense [Member]
 
 
 
 
Derivatives, Fair Value [Line Items]
 
 
 
 
Gains (losses) on commodity derivatives, net
(32)
(70)
(32)
Unrealized gain (loss) on derivatives
(1,693)
(2,510)
(2,010)
(4,041)
Commodity derivatives [Member] |
Direct operating expenses [Member]
 
 
 
 
Derivatives, Fair Value [Line Items]
 
 
 
 
Gains (losses) on commodity derivatives, net
(218)
(231)
(475)
(451)
Unrealized gain (loss) on derivatives
$ 0 
$ 0 
$ 0 
$ 0 
Property, Plant and Equipment, Net (Details) (USD $)
In Thousands, unless otherwise specified
6 Months Ended
Jun. 30, 2017
Dec. 31, 2016
Jun. 30, 2017
Land [Member]
Dec. 31, 2016
Land [Member]
Jun. 30, 2017
Construction in progress [Member]
Dec. 31, 2016
Construction in progress [Member]
Jun. 30, 2017
Buildings and improvements [Member]
Dec. 31, 2016
Buildings and improvements [Member]
Jun. 30, 2017
Transportation equipment [Member]
Dec. 31, 2016
Transportation equipment [Member]
Jun. 30, 2017
Processing and treating plants [Member]
Dec. 31, 2016
Processing and treating plants [Member]
Jun. 30, 2017
Pipelines and compressors [Member]
Dec. 31, 2016
Pipelines and compressors [Member]
Jun. 30, 2017
Storage [Member]
Dec. 31, 2016
Storage [Member]
Jun. 30, 2017
Equipment [Member]
Dec. 31, 2016
Equipment [Member]
Jun. 30, 2017
Minimum [Member]
Buildings and improvements [Member]
Jun. 30, 2017
Minimum [Member]
Transportation equipment [Member]
Jun. 30, 2017
Minimum [Member]
Processing and treating plants [Member]
Jun. 30, 2017
Minimum [Member]
Pipelines and compressors [Member]
Jun. 30, 2017
Minimum [Member]
Storage [Member]
Jun. 30, 2017
Minimum [Member]
Equipment [Member]
Jun. 30, 2017
Maximum [Member]
Buildings and improvements [Member]
Jun. 30, 2017
Maximum [Member]
Transportation equipment [Member]
Jun. 30, 2017
Maximum [Member]
Processing and treating plants [Member]
Jun. 30, 2017
Maximum [Member]
Pipelines and compressors [Member]
Jun. 30, 2017
Maximum [Member]
Storage [Member]
Jun. 30, 2017
Maximum [Member]
Equipment [Member]
Property, Plant and Equipment, Net [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Property plant and equipment in useful life
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4 years 
5 years 
8 years 
3 years 
20 years 
5 years 
40 years 
15 years 
40 years 
40 years 
40 years 
20 years 
Property plant and equipment gross
$ 1,525,095 
$ 1,462,033 
$ 23,098 
$ 23,520 
$ 46,657 
$ 131,448 
$ 24,280 
$ 24,225 
$ 45,090 
$ 44,060 
$ 141,109 
$ 120,977 
$ 909,963 
$ 804,815 
$ 210,291 
$ 210,579 
$ 124,607 
$ 102,409 
 
 
 
 
 
 
 
 
 
 
 
 
Accumulated depreciation
(358,674)
(317,030)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Property, plant and equipment, net
$ 1,166,421 
$ 1,145,003 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Property, Plant and Equipment (Narrative) (Details) (USD $)
3 Months Ended 6 Months Ended
Jun. 30, 2017
Jun. 30, 2016
Jun. 30, 2017
Jun. 30, 2016
Dec. 31, 2016
Property, Plant and Equipment [Line Items]
 
 
 
 
 
Property plant and equipment gross
$ 1,525,095,000 
 
$ 1,525,095,000 
 
$ 1,462,033,000 
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment
358,674,000 
 
358,674,000 
 
317,030,000 
Depreciation
21,300,000 
20,800,000 
42,900,000 
40,500,000 
 
Interest costs capitalized
500,000 
500,000 
1,500,000 
1,000,000 
 
FERC Regulated Assets [Member]
 
 
 
 
 
Property, Plant and Equipment [Line Items]
 
 
 
 
 
Property plant and equipment gross
253,500,000 
 
253,500,000 
 
291,100,000 
Scenario, Adjustment [Member]
 
 
 
 
 
Property, Plant and Equipment [Line Items]
 
 
 
 
 
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment
 
 
 
 
(33,900,000)
Processing And Treating Plants [Member]
 
 
 
 
 
Property, Plant and Equipment [Line Items]
 
 
 
 
 
Property plant and equipment gross
141,109,000 
 
141,109,000 
 
120,977,000 
Processing And Treating Plants [Member] |
Scenario, Adjustment [Member]
 
 
 
 
 
Property, Plant and Equipment [Line Items]
 
 
 
 
 
Property plant and equipment gross
 
 
 
 
(16,000,000)
Pipelines [Member]
 
 
 
 
 
Property, Plant and Equipment [Line Items]
 
 
 
 
 
Property plant and equipment gross
909,963,000 
 
909,963,000 
 
804,815,000 
Pipelines [Member] |
Scenario, Adjustment [Member]
 
 
 
 
 
Property, Plant and Equipment [Line Items]
 
 
 
 
 
Property plant and equipment gross
 
 
 
 
$ 49,900,000 
Goodwill and Intangible Assets, Net (Schedule of Goodwill) (Details) (USD $)
In Thousands, unless otherwise specified
Jun. 30, 2017
Dec. 31, 2016
Goodwill [Line Items]
 
 
Goodwill
$ 217,498 
$ 217,498 
Liquid Pipelines and Services [Member]
 
 
Goodwill [Line Items]
 
 
Goodwill
113,669 
113,669 
Terminalling Services [Member]
 
 
Goodwill [Line Items]
 
 
Goodwill
88,466 
88,466 
Propane Marketing Services [Member]
 
 
Goodwill [Line Items]
 
 
Goodwill
15,363 
15,363 
Scenario, Adjustment [Member] |
Liquid Pipelines and Services [Member]
 
 
Goodwill [Line Items]
 
 
Goodwill
 
(11,000)
Scenario, Adjustment [Member] |
Terminalling Services [Member]
 
 
Goodwill [Line Items]
 
 
Goodwill
 
$ 11,000 
Goodwill and Intangible Assets, Net Goodwill and Intangible Assets, Net (Narrative) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2017
Jun. 30, 2016
Jun. 30, 2017
Jun. 30, 2016
Finite-Lived Intangible Assets [Line Items]
 
 
 
 
Amortization of intangible assets
$ 8.3 
$ 5.2 
$ 15.5 
$ 10.3 
Minimum [Member]
 
 
 
 
Finite-Lived Intangible Assets [Line Items]
 
 
 
 
Finite-Lived intangible asset, useful life
 
 
5 years 0 months 0 days 
 
Maximum [Member]
 
 
 
 
Finite-Lived Intangible Assets [Line Items]
 
 
 
 
Finite-Lived intangible asset, useful life
 
 
44 years 
 
Goodwill and Intangible Assets, Net Schedule of Intangible Assets (Details) (USD $)
In Thousands, unless otherwise specified
Jun. 30, 2017
Dec. 31, 2016
Finite-Lived Intangible Assets [Line Items]
 
 
Customer relationships
$ 301,755 
$ 298,505 
Finite-Lived Intangible Assets, Accumulated Amortization
(88,765)
(73,222)
Finite-Lived Intangible Assets, Net
212,990 
225,283 
Customer Relationships [Member]
 
 
Finite-Lived Intangible Assets [Line Items]
 
 
Customer relationships
133,503 
133,503 
Finite-Lived Intangible Assets, Accumulated Amortization
(35,834)
(31,471)
Finite-Lived Intangible Assets, Net
97,669 
102,032 
Customer Contracts [Member]
 
 
Finite-Lived Intangible Assets [Line Items]
 
 
Customer relationships
98,844 
95,594 
Finite-Lived Intangible Assets, Accumulated Amortization
(43,142)
(33,414)
Finite-Lived Intangible Assets, Net
55,702 
62,180 
Dedicated Acreage [Member]
 
 
Finite-Lived Intangible Assets [Line Items]
 
 
Customer relationships
53,350 
53,350 
Finite-Lived Intangible Assets, Accumulated Amortization
(5,328)
(4,439)
Finite-Lived Intangible Assets, Net
48,022 
48,911 
Collaborative Arrangement [Member]
 
 
Finite-Lived Intangible Assets [Line Items]
 
 
Customer relationships
11,884 
11,884 
Finite-Lived Intangible Assets, Accumulated Amortization
(990)
(601)
Finite-Lived Intangible Assets, Net
10,894 
11,283 
Noncompete Agreements [Member]
 
 
Finite-Lived Intangible Assets [Line Items]
 
 
Customer relationships
3,423 
3,423 
Finite-Lived Intangible Assets, Accumulated Amortization
(3,250)
(3,086)
Finite-Lived Intangible Assets, Net
173 
337 
Other Intangible Assets [Member]
 
 
Finite-Lived Intangible Assets [Line Items]
 
 
Customer relationships
751 
751 
Finite-Lived Intangible Assets, Accumulated Amortization
(221)
(211)
Finite-Lived Intangible Assets, Net
$ 530 
$ 540 
Investment in unconsolidated affiliates Partnership's Equity Investments (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2017
Jun. 30, 2016
Jun. 30, 2017
Jun. 30, 2016
Investments in and Advances to Affiliates, at Fair Value [Roll Forward]
 
 
 
 
Balances
 
 
$ 291,988 
 
Earnings in unconsolidated affiliates
17,552 
11,702 
32,954 
19,045 
Distributions
 
 
(38,394)
 
Balances
286,548 
 
286,548 
 
FPS [Member]
 
 
 
 
Schedule of Equity Method Investments [Line Items]
 
 
 
 
Ownership percentage
20.10% 
 
20.10% 
 
Investments in and Advances to Affiliates, at Fair Value [Roll Forward]
 
 
 
 
Balances
 
 
64,483 
 
Earnings in unconsolidated affiliates
 
 
15,529 
 
Distributions
 
 
(8,753)
 
Balances
71,259 
 
71,259 
 
OGL [Member]
 
 
 
 
Schedule of Equity Method Investments [Line Items]
 
 
 
 
Ownership percentage
20.10% 
 
20.10% 
 
Investments in and Advances to Affiliates, at Fair Value [Roll Forward]
 
 
 
 
Balances
 
 
25,450 
 
Earnings in unconsolidated affiliates
 
 
6,571 
 
Distributions
 
 
(7,137)
 
Balances
24,884 
 
24,884 
 
Destin [Member]
 
 
 
 
Schedule of Equity Method Investments [Line Items]
 
 
 
 
Ownership percentage
49.70% 
 
49.70% 
 
Investments in and Advances to Affiliates, at Fair Value [Roll Forward]
 
 
 
 
Balances
 
 
110,882 
 
Earnings in unconsolidated affiliates
 
 
5,116 
 
Distributions
 
 
(12,119)
 
Balances
103,879 
 
103,879 
 
Tri-State [Member]
 
 
 
 
Schedule of Equity Method Investments [Line Items]
 
 
 
 
Ownership percentage
16.70% 
 
16.70% 
 
Investments in and Advances to Affiliates, at Fair Value [Roll Forward]
 
 
 
 
Balances
 
 
55,022 
 
Earnings in unconsolidated affiliates
 
 
2,161 
 
Distributions
 
 
(2,626)
 
Balances
54,557 
 
54,557 
 
Okeanos [Member]
 
 
 
 
Schedule of Equity Method Investments [Line Items]
 
 
 
 
Ownership percentage
66.70% 
 
66.70% 
 
Investments in and Advances to Affiliates, at Fair Value [Roll Forward]
 
 
 
 
Balances
 
 
27,059 
 
Earnings in unconsolidated affiliates
 
 
3,692 
 
Distributions
 
 
(6,667)
 
Balances
24,084 
 
24,084 
 
Wilprise [Member]
 
 
 
 
Schedule of Equity Method Investments [Line Items]
 
 
 
 
Ownership percentage
25.30% 
 
25.30% 
 
Investments in and Advances to Affiliates, at Fair Value [Roll Forward]
 
 
 
 
Balances
 
 
4,944 
 
Earnings in unconsolidated affiliates
 
 
408 
 
Distributions
 
 
(392)
 
Balances
4,960 
 
4,960 
 
MPOG [Member]
 
 
 
 
Schedule of Equity Method Investments [Line Items]
 
 
 
 
Ownership percentage
66.70% 
 
66.70% 
 
Investments in and Advances to Affiliates, at Fair Value [Roll Forward]
 
 
 
 
Balances
 
 
4,148 
 
Earnings in unconsolidated affiliates
 
 
(523)
 
Distributions
 
 
(700)
 
Balances
$ 2,925 
 
$ 2,925 
 
Investment in unconsolidated affiliates Financial Information for the Partnership's Equity Investments - Balance Sheets (Details) (USD $)
In Thousands, unless otherwise specified
Jun. 30, 2017
Dec. 31, 2016
Equity Method Investments and Joint Ventures [Abstract]
 
 
Current assets
$ 105,211 
$ 120,167 
Non-current assets
1,337,201 
1,369,492 
Current liabilities
121,966 
133,085 
Non-current liabilities
$ 489,080 
$ 541,312 
Investment in unconsolidated affiliates Financial Information for the Partnership's Equity Investments - Statement of Operations (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2017
Jun. 30, 2016
Jun. 30, 2017
Jun. 30, 2016
Equity Method Investments and Joint Ventures [Abstract]
 
 
 
 
Revenue
$ 105,373 
$ 89,541 
$ 203,366 
$ 184,757 
Gross profit
96,442 
83,045 
185,075 
169,668 
Net income
$ 76,414 
$ 67,937 
$ 145,532 
$ 136,387 
Accrued Expenses and Other Current Liabilities (Details) (USD $)
In Thousands, unless otherwise specified
Jun. 30, 2017
Dec. 31, 2016
Other Liabilities Disclosure [Abstract]
 
 
Due to related parties
$ 15,694 
$ 4,072 
Accrued interest
8,470 
5,743 
Legal accrual
8,192 
Capital expenditures
7,240 
14,499 
Convertible preferred unit distributions
6,735 
7,103 
Current portion of asset retirement obligation
6,495 
6,499 
Additional Blackwater acquisition consideration
5,000 
5,000 
Employee compensation
4,967 
10,804 
Taxes payable
3,902 
1,688 
Royalties payable
3,536 
3,926 
Customer deposits
3,092 
3,080 
Gas imbalances payable
1,580 
1,098 
Transaction costs
1,179 
3,000 
Deferred financing costs
2,743 
Recoverable gas costs
238 
1,126 
Other
10,706 
10,903 
Total accrued expenses and other current liabilities
$ 87,026 
$ 81,284 
Asset Retirement Obligations (Details) (USD $)
6 Months Ended
Jun. 30, 2017
Dec. 31, 2016
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
 
 
Non-current balance
$ 45,302,000 
$ 44,363,000 
Current portion of asset retirement obligation
6,495,000 
6,499,000 
Balances at December 31, 2016
50,862,000 
 
Expenditures
(49,000)
 
Accretion expense
984,000 
 
Balances at June 30, 2017
51,797,000 
 
Less: current portion
6,495,000 
6,499,000 
Noncurrent asset retirement obligation
45,302,000 
44,363,000 
Restricted cash and cash equivalents
$ 5,000,000 
$ 5,000,000 
Debt Obligations (Details) (USD $)
In Thousands, unless otherwise specified
Jun. 30, 2017
Dec. 31, 2016
Debt Instrument [Line Items]
 
 
Revolving credit facility
$ 678,042 
$ 888,250 
Long-term
1,037,649 
1,252,059 
Unamortized debt issuance costs
(9,776)
(11,036)
Total debt obligations
1,027,873 
1,241,023 
Less: current portion
(1,556)
(5,485)
Long-term debt
1,026,317 
1,235,538 
Senior Notes [Member] |
8.50% Senior Notes [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term
300,000 
300,000 
Senior Notes [Member] |
3.77% Senior Notes [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term
58,922 
60,000 
Other Debt Obligations [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term
685 
3,809 
Revolving Credit Facility [Member]
 
 
Debt Instrument [Line Items]
 
 
Revolving credit facility
$ 678,042 
$ 888,250 
Debt Obligations (Narrative) (Details) (USD $)
6 Months Ended 0 Months Ended 0 Months Ended 0 Months Ended 6 Months Ended 6 Months Ended 6 Months Ended 0 Months Ended
Jun. 30, 2017
Jun. 30, 2016
Dec. 31, 2016
Dec. 28, 2016
8.50% Senior Notes [Member]
Senior Notes [Member]
Jun. 30, 2017
8.50% Senior Notes [Member]
Senior Notes [Member]
Mar. 8, 2017
8.50% Senior Notes [Member]
Senior Notes [Member]
Dec. 28, 2016
8.50% Senior Notes [Member]
Senior Notes [Member]
Dec. 28, 2016
Senior Notes, Due 2021 [Member]
Senior Notes [Member]
Jun. 30, 2017
Senior Notes, Due 2021 [Member]
Senior Notes [Member]
Jun. 30, 2017
3.77% Senior Notes [Member]
Senior Notes [Member]
Sep. 30, 2016
3.77% Senior Notes [Member]
Senior Notes [Member]
Mar. 8, 2017
Revolving Credit Facility [Member]
Jun. 30, 2017
Revolving Credit Facility [Member]
Mar. 8, 2017
Revolving Credit Facility [Member]
Dec. 31, 2016
Revolving Credit Facility [Member]
Jun. 30, 2016
Revolving Credit Facility [Member]
Apr. 25, 2016
Revolving Credit Facility [Member]
Jun. 30, 2017
Revolving Credit Facility [Member]
Base Rate [Member]
Maximum [Member]
Jun. 30, 2017
Revolving Credit Facility [Member]
Base Rate [Member]
Minimum [Member]
Jun. 30, 2017
Revolving Credit Facility [Member]
Federal Funds [Member]
Jun. 30, 2017
Revolving Credit Facility [Member]
Eurodollar [Member]
Jun. 30, 2017
Revolving Credit Facility [Member]
Eurodollar [Member]
Maximum [Member]
Jun. 30, 2017
Revolving Credit Facility [Member]
Eurodollar [Member]
Minimum [Member]
Jun. 30, 2017
JPE [Member]
Revolving Credit Facility [Member]
Mar. 8, 2017
JPE [Member]
Letter of Credit [Member]
Jun. 30, 2017
JPE [Member]
Letter of Credit [Member]
Debt Instrument [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Line of credit facility, current borrowing capacity
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 900,000,000 
 
 
$ 750,000,000 
 
 
 
 
 
 
 
 
 
Line of Credit Facility, Maximum Borrowing Capacity
 
 
 
 
 
 
 
 
 
 
 
 
 
1,100,000,000 
 
 
 
 
 
 
 
 
 
275,000,000.0 
 
100,000,000.0 
Debt Iinstrument, basis spread on variable rate
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3.25% 
2.00% 
 
 
2.25% 
1.00% 
 
 
 
Debt instrument, interest rate, stated percentage
 
 
 
 
8.50% 
8.50% 
8.50% 
 
8.50% 
3.77% 
3.77% 
 
 
 
 
 
 
 
 
0.50% 
1.00% 
 
 
 
 
 
Proceeds from Issuance of Long-term Debt and Capital Securities, Net
 
 
 
294,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proceeds from 8.50% Senior Notes
 
 
 
 
 
 
 
291,300,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Issuance Costs, Gross
 
 
 
 
 
 
6,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Additional Debt Issuance Costs
 
 
 
 
 
 
2,700,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Fair Value Disclosure
 
 
 
 
 
 
 
 
303,300,000 
55,500,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Line of credit facility, unused capacity, commitment fee percentage
 
 
 
 
 
 
 
 
 
 
 
 
0.50% 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Covenants, Adjusted Consolidated EBITDA
 
 
 
 
 
 
 
 
 
 
 
5.00 
5.50 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument Covenant, Consolidated Secured Leverage Ratio
 
 
 
 
 
 
 
 
 
 
 
 
3.50 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt instrument, interest coverage ratio
 
 
 
 
 
 
 
 
 
 
1.20 
 
5.04 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt, weighted average interest rate
 
 
 
 
 
 
 
 
 
 
 
 
4.67% 
 
 
4.15% 
 
 
 
 
 
 
 
 
 
 
Letters of credit outstanding, amount
 
 
 
 
 
 
 
 
 
 
 
 
32,300,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revolving credit facility
678,042,000 
 
888,250,000 
 
 
 
 
 
 
 
 
 
678,042,000 
 
888,250,000 
 
 
 
 
 
 
 
 
 
 
 
Line of Credit Facility, Remaining Borrowing Capacity
 
 
 
 
 
 
 
 
 
 
 
 
189,600,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Consolidated Total Leverage Ratio
 
 
 
 
 
 
 
 
 
 
 
 
4.79 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument Covenant Consolidated Interest Coverage Ratio
 
 
 
 
 
 
 
 
 
 
 
 
2.50 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt instrument, face amount
 
 
 
 
 
 
300,000,000 
 
 
 
60,000,000.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Repayments of lines of credit
383,908,000 
101,900,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
199,500,000 
 
Other
$ 0 
$ (166,000)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Convertible Preferred Units (Schedule of Convertible Preferred Units) (Details) (USD $)
In Thousands, except Share data, unless otherwise specified
6 Months Ended 6 Months Ended 6 Months Ended 6 Months Ended
Jun. 30, 2017
Dec. 31, 2016
Jun. 30, 2017
Unit Distribution [Member]
Jun. 30, 2017
Series A [Member]
Dec. 31, 2016
Series A [Member]
Apr. 15, 2013
Series A [Member]
Jun. 30, 2017
Series A [Member]
Unit Distribution [Member]
Jun. 30, 2017
Series C [Member]
Dec. 31, 2016
Series C [Member]
Jun. 30, 2017
Series C [Member]
Unit Distribution [Member]
Jun. 30, 2017
Series D [Member]
Dec. 31, 2016
Series D [Member]
Jun. 30, 2017
Series D [Member]
Unit Distribution [Member]
Increase (Decrease) in Partners' Capital [Roll Forward]
 
 
 
 
 
 
 
 
 
 
 
 
 
Convertible preferred units, Beginning Balance, Units
 
 
 
10,400,000 
10,107,000 
5,142,857 
 
8,792,000 
8,792,000 
 
2,333,000 
2,333,000 
 
Paid in kind unit distributions, Units
 
 
 
 
 
 
293,000 
 
 
 
 
Convertible preferred units, Ending Balance, Units
 
 
 
10,400,000 
10,107,000 
5,142,857 
 
8,792,000 
8,792,000 
 
2,333,000 
2,333,000 
 
Convertible preferred units, Beginning Balance, Amount,
$ 338,195 
$ 334,090 
 
$ 185,491 
$ 181,386 
 
 
$ 118,229 
$ 118,229 
 
$ 34,475 
$ 34,475 
 
Paid in kind unit distributions, Amount
 
 
4,105 
 
 
 
4,105 
 
 
 
 
Convertible preferred units, Ending Balance, Amount,
$ 338,195 
$ 334,090 
 
$ 185,491 
$ 181,386 
 
 
$ 118,229 
$ 118,229 
 
$ 34,475 
$ 34,475 
 
Convertible Preferred Units (Details) (USD $)
0 Months Ended 3 Months Ended 6 Months Ended 0 Months Ended 0 Months Ended 6 Months Ended 12 Months Ended 6 Months Ended 0 Months Ended 6 Months Ended 6 Months Ended 12 Months Ended 0 Months Ended
Apr. 25, 2017
Jun. 30, 2017
Jun. 30, 2016
Jun. 30, 2017
Jun. 30, 2016
Apr. 15, 2013
Series A [Member]
Jun. 30, 2017
Series A [Member]
Dec. 31, 2016
Series A [Member]
Jul. 27, 2015
Series A-2 [Member]
Jun. 30, 2017
Series A-2 [Member]
Dec. 31, 2015
Series A-2 [Member]
Jul. 27, 2015
Series A-2 [Member]
Jun. 30, 2017
Series A [Member]
Apr. 15, 2013
Series A [Member]
Apr. 25, 2016
Series C [Member]
Jun. 30, 2017
Series C [Member]
Dec. 31, 2016
Series C [Member]
Apr. 25, 2016
Series C [Member]
Jun. 30, 2017
Series C [Member]
Apr. 25, 2016
Series C [Member]
Jun. 30, 2017
Series D [Member]
Dec. 31, 2016
Series D [Member]
Oct. 31, 2016
Series D [Member]
Jun. 30, 2017
Series D [Member]
Apr. 15, 2013
High Point Infrastructure Partners, LLC [Member]
Series A [Member]
Dec. 31, 2015
Magnolia Infrastructure Partners, LLC [Member]
Issuance of Preferred Units [Member]
Series A-2 [Member]
Apr. 25, 2016
ArcLight [Member]
Issuance of Preferred Units [Member]
Series C [Member]
Apr. 25, 2017
Scenario, Previously Reported [Member]
Preferred Units [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Partners' Capital Account, Units, Sale of Units, Percentage
 
 
 
 
 
90.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Consideration for Issuance of Preferred Units
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 15,000,000 
 
 
 
Partners' Capital Account, Units
 
 
 
 
 
5,142,857 
10,400,000 
10,107,000 
 
 
 
 
 
 
 
8,792,000 
8,792,000 
 
8,792,000 
 
2,333,000 
2,333,000 
 
2,333,000 
 
 
 
 
Distribution declared per common unit (in usd per share)
$ 0.4125 
$ 0.4125 1
$ 0.4125 1
$ 0.825 1
$ 0.885 1
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 0.50 
Partners' Capital Account, Units, Sold in Private Placement
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2,571,430 
8,571,429 
 
Proceeds from Issuance of Convertible Preferred Units
 
 
 
 
 
 
 
 
 
 
45,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Investment options, exercise price (in usd per share)
 
 
 
 
 
 
 
 
$ 17.50 
$ 15.69 
 
 
$ 15.69 
 
$ 14.00 
 
 
 
$ 13.79 
 
 
 
 
 
 
 
 
 
Convertible Preferred Stock, Shares Issued upon Conversion
 
 
 
 
 
 
 
 
 
1.1054 
 
 
1.1054 
 
 
1.0035 
 
1.0035 
1.0035 
 
1.0035 
 
 
 
 
Class of warrant, number of securities called by warrants (in shares)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
800,000 
 
800,000 
 
 
700,000 
 
 
 
 
 
Class of warrant, exercise price of warrants (in usd per share)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 7.25 
 
 
 
 
$ 22.00 
$ 14.83 
 
 
 
 
Call right defined acquisition value
 
 
 
 
 
 
 
 
 
 
 
100,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Warrant, exercisable period
 
 
 
 
 
 
 
 
 
 
 
 
 
 
7 years 
7 years 
 
 
7 years 
 
 
 
 
 
 
 
 
 
Fair value of warrant unit (in usd per share)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 4.41 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value Assumptions, Expected Dividend Rate
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
18.00% 
 
 
18.00% 
 
 
 
 
 
 
 
 
 
Fair value assumptions, expected volatility Rate
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
42.00% 
 
 
42.00% 
 
 
 
 
 
 
 
 
 
Issuance of warrant
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 4,500,000 
 
 
 
 
 
 
 
 
 
 
 
 
Units issued (in shares)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2,333,333 
 
 
 
 
 
Shares issued, price per share (in usd per share)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 15.00 
 
 
 
 
 
Limited Partners' Capital Account, Units Issued, Closing Fee, Percent
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1.50% 
 
 
 
 
 
Partners' Capital Account, Distribution Per Unit of Limited Partner Interest
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 0.4125 
 
 
 
 
 
 
$ 0.4125 
 
 
 
 
 
 
 
Partners Capital (Narrative) (Details) (USD $)
6 Months Ended
Jun. 30, 2017
Jun. 30, 2016
Class of Stock [Line Items]
 
 
General partner interest
1.30% 
 
Limited partner interests
98.70% 
 
Proceeds from General Partner
$ 4,000,000 
$ 4,000,000 
Additional notional General Partner units (shares)
272,811 
128,272 
Fair value inputs,assumed growth rate (percent)
1.00% 
 
General Partner [Member]
 
 
Class of Stock [Line Items]
 
 
Proceeds from Issuance of Common Limited Partners Units
3,900,000 
 
Proceeds from General Partner
$ 23,130,000 
$ 1,791,000 
Minimum [Member]
 
 
Class of Stock [Line Items]
 
 
Fair value input, option value (dollars per unit)
$ 0.02 
 
Fair value inputs, discount rate (percent)
5.98% 
 
Maximum [Member]
 
 
Class of Stock [Line Items]
 
 
Fair value input, option value (dollars per unit)
$ 3.39 
 
Fair value inputs, discount rate (percent)
10.00% 
 
Partners’ Capital Outstanding Units (Details)
In Thousands, unless otherwise specified
6 Months Ended
Jun. 30, 2017
Dec. 31, 2016
Jun. 30, 2017
General Partner [Member]
Long Term Incentive Plan [Member]
Jun. 30, 2017
General Partner [Member]
General Partner Units [Member]
Jun. 30, 2017
General Partner [Member]
Common Units [Member]
Jun. 30, 2017
Limited Partner [Member]
Long Term Incentive Plan [Member]
Jun. 30, 2017
Limited Partner [Member]
General Partner Units [Member]
Jun. 30, 2017
Limited Partner [Member]
Common Units [Member]
Increase (Decrease) in Partners' Capital [Roll Forward]
 
 
 
 
 
 
 
 
Balances at December 31, 2016
953 
680 
 
 
 
 
 
 
Balances at December 31, 2016
51,745 
51,351 
 
 
 
 
 
 
Partners' Capital Account Increase
 
 
273 
373 
21 
Balances at June 30, 2017
953 
680 
 
 
 
 
 
 
Balances at June 30, 2017
51,745 
51,351 
 
 
 
 
 
 
Partners’ Capital Distributions (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2017
Jun. 30, 2016
Jun. 30, 2017
Jun. 30, 2016
Limited Partner [Member]
 
 
 
 
Class of Stock [Line Items]
 
 
 
 
General partner's distribution
 
 
$ 63,574 
$ 62,950 
General Partner [Member]
 
 
 
 
Class of Stock [Line Items]
 
 
 
 
General partner's distribution
 
 
594 
2,351 
Paid In-kind Unit [Member]
 
 
 
 
Class of Stock [Line Items]
 
 
 
 
General partner's distribution
2,181 
4,471 
4,914 
8,851 
Paid In-kind Unit [Member] |
Series A [Member] |
Preferred Partner [Member]
 
 
 
 
Class of Stock [Line Items]
 
 
 
 
General partner's distribution
2,181 
4,471 
4,914 
8,851 
Paid In-kind Unit [Member] |
Series C [Member] |
Preferred Partner [Member]
 
 
 
 
Class of Stock [Line Items]
 
 
 
 
General partner's distribution
Paid [Member] |
Paid / Accrued [Member]
 
 
 
 
Class of Stock [Line Items]
 
 
 
 
General partner's distribution
28,298 
24,955 
60,494 
53,983 
Paid [Member] |
Paid / Accrued [Member] |
Limited Partner [Member]
 
 
 
 
Class of Stock [Line Items]
 
 
 
 
General partner's distribution
21,390 
24,782 
46,303 
51,782 
Paid [Member] |
Paid / Accrued [Member] |
General Partner [Member]
 
 
 
 
Class of Stock [Line Items]
 
 
 
 
General partner's distribution
201 
173 
368 
2,201 
Paid [Member] |
Paid / Accrued [Member] |
Series A [Member] |
Preferred Partner [Member]
 
 
 
 
Class of Stock [Line Items]
 
 
 
 
General partner's distribution
2,117 
4,644 
Paid [Member] |
Paid / Accrued [Member] |
Series C [Member] |
Preferred Partner [Member]
 
 
 
 
Class of Stock [Line Items]
 
 
 
 
General partner's distribution
3,627 
7,254 
Paid [Member] |
Paid / Accrued [Member] |
Series D [Member] |
Preferred Partner [Member]
 
 
 
 
Class of Stock [Line Items]
 
 
 
 
General partner's distribution
963 
1,925 
Accrued [Member] |
General Partner [Member]
 
 
 
 
Class of Stock [Line Items]
 
 
 
 
General partner's distribution
277 
173 
476 
2,201 
Accrued [Member] |
Paid / Accrued [Member]
 
 
 
 
Class of Stock [Line Items]
 
 
 
 
General partner's distribution
8,659 
6,851 
8,659 
6,851 
Accrued [Member] |
Paid / Accrued [Member] |
Series A [Member] |
Preferred Partner [Member]
 
 
 
 
Class of Stock [Line Items]
 
 
 
 
General partner's distribution
4,069 
4,602 
4,069 
4,602 
Accrued [Member] |
Paid / Accrued [Member] |
Series C [Member] |
Preferred Partner [Member]
 
 
 
 
Class of Stock [Line Items]
 
 
 
 
General partner's distribution
3,627 
2,249 
3,627 
2,249 
Accrued [Member] |
Paid / Accrued [Member] |
Series D [Member] |
Preferred Partner [Member]
 
 
 
 
Class of Stock [Line Items]
 
 
 
 
General partner's distribution
$ 963 
$ 0 
$ 963 
$ 0 
Net Loss per Limited Partner Unit Net Loss per Limited Partner Unit (Details) (USD $)
In Thousands, except Per Share data, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2017
Jun. 30, 2016
Jun. 30, 2017
Jun. 30, 2016
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
 
 
 
 
Net loss
$ (27,702)
$ (9,481)
$ (56,583)
$ (19,545)
Less: Net income attributable to noncontrolling interests
1,462 
954 
2,765 
951 
Net income (loss) from continuing operations attributable to the Partnership
(29,164)
(10,435)
(59,348)
(20,496)
Distributions
4,069 
4,602 
8,367 
9,073 
General partner’s share in undistributed loss
(784)
(400)
(1,541)
(818)
Net loss from continuing operations available to Limited Partners
(37,316)
(17,059)
(75,829)
(33,201)
Net loss from discontinued operations available to Limited Partners
(539)
Net loss available to Limited Partners
(37,316)
(17,059)
(75,829)
(33,740)
Weighted average number of common units outstanding: basic and diluted (shares)
51,870 
51,090 
51,870 
51,090 
Limited Partners' net loss from continuing operations per unit (in usd per unit)
$ (0.72)
$ (0.33)
$ (1.46)
$ (0.65)
Limited Partners' net loss from discontinued operations per unit (in usd per unit)
$ 0.00 
$ 0.00 
$ 0.00 
$ (0.01)
Limited Partners' net loss per common unit (in usd per share)
$ (0.72)
$ (0.33)
$ (1.46)
$ (0.66)
Series C [Member]
 
 
 
 
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
 
 
 
 
Distributions
3,627 
2,249 
7,254 
2,249 
Series D [Member]
 
 
 
 
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
 
 
 
 
Distributions
963 
1,925 
General Partner [Member]
 
 
 
 
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
 
 
 
 
General partner's distribution
 
 
594 
2,351 
General Partner [Member] |
Accrued [Member]
 
 
 
 
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
 
 
 
 
General partner's distribution
$ 277 
$ 173 
$ 476 
$ 2,201 
Long Term Incentive Plan (Narrative) (Details) (USD $)
3 Months Ended 6 Months Ended 0 Months Ended 6 Months Ended 1 Months Ended 6 Months Ended
Jun. 30, 2017
Parent [Member]
Jun. 30, 2016
Parent [Member]
Jun. 30, 2017
Parent [Member]
Jun. 30, 2016
Parent [Member]
Mar. 9, 2017
Long Term Incentive Plan [Member]
Nov. 19, 2015
Long Term Incentive Plan [Member]
Jun. 30, 2017
Long Term Incentive Plan [Member]
Jun. 30, 2016
Long Term Incentive Plan [Member]
Dec. 31, 2015
Long Term Incentive Plan [Member]
Phantom Share Units (PSUs) [Member]
Jun. 30, 2017
Long Term Incentive Plan [Member]
Minimum [Member]
Phantom Share Units (PSUs) [Member]
Jun. 30, 2017
Long Term Incentive Plan [Member]
Maximum [Member]
Phantom Share Units (PSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Additional number of common units authorized for issuance (shares)
 
 
 
 
312,716 
6,000,000 
 
 
 
 
 
Award vesting period
 
 
 
 
 
 
 
 
3 years 
3 years 
4 years 
Granted (in shares)
 
 
 
 
 
 
 
 
200,000 
 
 
Partners' Capital Account, Unit-based Compensation
$ 1,200,000 
$ 800,000 
$ 5,233,000 
$ 2,480,000 
 
 
 
 
 
 
 
Equity instruments other than options, vested in period, fair value
 
 
 
 
 
 
$ 7,900,000 
$ 900,000 
 
 
 
Long-Term Incentive Plan - Phantom Units (Details) (Phantom Share Units (PSUs) [Member], USD $)
6 Months Ended
Jun. 30, 2017
Phantom Share Units (PSUs) [Member]
 
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]
 
Outstanding at end beginning of period (in shares)
1,558,834.89 
Granted (in shares)
2,000 
Forfeited (in shares)
(7,643)
Vested (in shares)
(479,130)
Outstanding at end of period (in shares)
1,074,062 
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Weighted Average [Roll Forward]
 
Outstanding at beginning of period (in usd per share)
$ 6.98 
Granted (in usd per share)
$ 11.20 
Forfeited (in usd per share)
$ 21.46 
Vested (in usd per share)
$ 10.32 
Outstanding at end of period (in usd per share)
$ 5.39 
Commitments and Contingencies (Details) (USD $)
In Millions, unless otherwise specified
Jun. 30, 2017
Other Commitments [Line Items]
 
Obligation fair value
$ 0.9 
Related Party Transactions (Narrative) (Details) (USD $)
3 Months Ended 6 Months Ended 3 Months Ended 6 Months Ended 42 Months Ended 3 Months Ended 6 Months Ended 6 Months Ended 12 Months Ended 3 Months Ended 6 Months Ended
Jun. 30, 2017
Jun. 30, 2016
Jun. 30, 2017
Jun. 30, 2016
Dec. 31, 2016
Jun. 30, 2017
Blackwater [Member]
Dec. 31, 2013
Blackwater [Member]
Jun. 30, 2017
General Partner [Member]
quarter
Jun. 30, 2016
General Partner [Member]
Jun. 30, 2017
General Partner [Member]
quarter
Jun. 30, 2016
General Partner [Member]
Jun. 30, 2017
General Partner [Member]
quarter
Jun. 30, 2017
Republic Midstream, LLC (“Republic”) [Member]
Jun. 30, 2016
Republic Midstream, LLC (“Republic”) [Member]
Jun. 30, 2017
Republic Midstream, LLC (“Republic”) [Member]
Jun. 30, 2017
Affiliated Entity [Member]
Dec. 31, 2015
J P Energy Development L P [Member]
Jun. 30, 2017
Other Current Liabilities [Member]
General Partner [Member]
Dec. 31, 2016
Other Current Liabilities [Member]
General Partner [Member]
Jun. 30, 2017
Other Current Assets [Member]
Dec. 31, 2016
Other Current Assets [Member]
Jun. 30, 2017
American Panther [Member]
Affiliated Entity [Member]
Jun. 30, 2017
American Panther [Member]
Affiliated Entity [Member]
Dec. 31, 2016
American Panther [Member]
Affiliated Entity [Member]
Jun. 30, 2017
Panther Asset Management LLC (Panther) [Member]
American Panther [Member]
Affiliated Entity [Member]
Jun. 30, 2017
CIMA Energy Ltd [Member]
Vice President [Member]
Jun. 30, 2016
CIMA Energy Ltd [Member]
Vice President [Member]
Jun. 30, 2017
CIMA Energy Ltd [Member]
Vice President [Member]
Jun. 30, 2016
CIMA Energy Ltd [Member]
Vice President [Member]
Jun. 30, 2016
Crude Oil Pipelines And Storage Segment [Member]
Mid Continent Business [Member]
J P Energy Development L P [Member]
Related Party Transaction [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Additional consideration
 
 
 
 
 
 
$ 5,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Additional Blackwater acquisition consideration
 
 
 
 
 
5,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Maximum financial support
 
 
 
 
 
 
 
25,000,000 
 
25,000,000 
 
25,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Term of maximum financial support (Number of Quarters)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Financial support utilized
 
 
 
 
 
 
 
 
 
 
 
15,100,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Reimbursements received from general partner
 
 
 
 
 
 
 
9,600,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Corporate overhead expenses to be absorbed
 
 
 
 
 
 
 
 
 
9,600,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Contributions
 
 
23,130,000 
1,791,000 
 
 
 
 
 
3,800,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Monthly fee
 
 
 
 
 
 
 
 
 
 
 
 
 
 
100,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenue from related parties
 
 
 
 
 
 
 
 
 
 
 
 
300,000 
300,000 
700,000 
 
 
 
 
 
 
 
 
 
 
1,800,000 
700,000 
2,500,000 
1,600,000 
 
Receivable balance from affiliate
 
 
 
 
 
 
 
 
 
 
 
 
1,400,000 
 
1,400,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Related party transaction, due to related party
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2,300,000 
3,900,000 
 
 
 
 
 
 
 
 
 
 
 
Due from related parties
20,853,000 
 
20,853,000 
 
4,805,000 
 
 
 
 
 
 
 
 
 
 
 
 
15,600,000 
 
5,800,000 
2,200,000 
 
 
 
 
 
 
 
 
 
Due to related parties
15,694,000 
 
15,694,000 
 
4,072,000 
 
 
 
 
 
 
 
 
 
 
 
 
13,300,000 
 
 
 
 
 
 
 
 
 
 
 
 
Management fees revenue
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,200,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ownership interest in subsidiary (percent)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
60.00% 
 
 
 
 
 
 
 
 
Noncontrolling interest ownership interest (percent)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
40.00% 
 
 
 
 
 
Direct operating expenses
31,884,000 
31,967,000 
61,972,000 
62,542,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
500,000 
800,000 
 
 
 
 
 
 
Direct operating expenses
30,084,000 
22,281,000 
62,928,000 
43,382,000 
 
 
 
1,500,000 
4,000,000 
4,000,000 
 
 
 
 
 
 
 
 
 
 
 
300,000 
400,000 
 
 
 
 
 
 
Purchases from related party
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,200,000 
800,000 
2,600,000 
1,800,000 
 
Pipeline tariff fees
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
400,000 
Net receivable from JP Development
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
7,900,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
Corporate overhead expenses to be absorbed by general partner
 
 
 
 
 
 
 
 
$ 3,500,000 
 
$ 5,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Supplemental Cash Flow Information (Details) (USD $)
In Thousands, unless otherwise specified
6 Months Ended
Jun. 30, 2017
Jun. 30, 2016
Supplemental Cash Flow Elements [Abstract]
 
 
Increase (decrease) in accrued property, plant and equipment purchases
$ (7,259)
$ 4,856 
Contributions
4,000 
4,000 
Issuance of Series C Units and Warrant in connection with the Emerald Transactions
120,000 
Accrued distributions on convertible preferred units
8,659 
6,851 
Paid-in-kind distributions on convertible preferred units
4,914 
8,851 
Cancellation of escrow units
6,817 
Accrued Cash Dividends Paid to Parent Company by Unconsolidated Affiliates
$ 0 
$ 4,360 
Reportable Segments - Reconciliation of Gross Profit (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2017
Jun. 30, 2016
Jun. 30, 2017
Jun. 30, 2016
Segment Reporting Information [Line Items]
 
 
 
 
Segment gross margin
$ 79,300 
$ 81,072 
$ 159,404 
$ 155,117 
Direct operating expenses
31,884 
31,967 
61,972 
62,542 
Operating Income (Loss)
(27,373)
(10,368)
(52,581)
(18,769)
Derivative, Gain (Loss) on Derivative, Net
207 
(1,367)
(50)
(1,605)
Corporate expenses
30,084 
22,281 
62,928 
43,382 
Depreciation, amortization and accretion
30,170 
26,398 
59,521 
51,439 
Gain (Loss) on Disposition of Property Plant Equipment, Excluding Oil and Gas Property and Timber Property
(52)
(478)
176 
(1,600)
Interest expense
17,152 
10,610 
35,118 
18,912 
Other income
72 
496 
86 
527 
Other Nonoperating Income (Expense)
136 
(365)
806 
(730)
Income tax expense
801 
701 
1,924 
1,436 
Loss from discontinued operations, net of tax
(539)
Less: Net income attributable to noncontrolling interests
1,462 
954 
2,765 
951 
Net Income (Loss) Attributable to Parent
(29,164)
(10,435)
(59,348)
(21,035)
Gathering and Processing reporting segment [Member]
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
Segment gross margin
12,651 
13,337 
23,902 
24,957 
Direct operating expenses
8,045 
8,945 
16,110 
17,492 
Derivative, Gain (Loss) on Derivative, Net
(98)
(763)
(105)
(866)
Liquid Pipelines and Services [Member]
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
Segment gross margin
6,683 
9,432 
13,152 
15,284 
Direct operating expenses
1,833 
2,235 
3,906 
4,701 
Derivative, Gain (Loss) on Derivative, Net
297 
(716)
669 
(948)
Natural Gas Transportation Services [Member]
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
Segment gross margin
5,631 
3,843 
11,750 
9,406 
Direct operating expenses
1,928 
1,963 
3,163 
3,190 
Derivative, Gain (Loss) on Derivative, Net
Offshore Pipelines and Services [Member]
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
Segment gross margin
25,623 
20,558 
51,426 
33,819 
Direct operating expenses
3,490 
2,802 
6,070 
5,055 
Derivative, Gain (Loss) on Derivative, Net
(2)
(2)
Terminalling Services [Member]
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
Segment gross margin
10,760 
11,586 
21,920 
21,030 
Direct operating expenses
2,998 
2,388 
6,071 
4,997 
Derivative, Gain (Loss) on Derivative, Net
(260)
(436)
Propane Marketing Services [Member]
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
Segment gross margin
17,952 
22,316 
37,254 
50,621 
Direct operating expenses
13,590 
13,634 
26,652 
27,107 
Derivative, Gain (Loss) on Derivative, Net
374 
(614)
647 
All Operating Segments, Excluding Terminalling Segment [Member]
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
Direct operating expenses
$ 28,886 
$ 29,579 
$ 55,902 
$ 57,545 
Reportable Segments (Narrative) (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2017
Jun. 30, 2016
Jun. 30, 2017
Jun. 30, 2016
Segment Reporting Information [Line Items]
 
 
 
 
Direct operating expenses
$ 31,884 
$ 31,967 
$ 61,972 
$ 62,542 
Gathering and Processing reporting segment [Member]
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
Direct operating expenses
8,045 
8,945 
16,110 
17,492 
Liquid Pipelines and Services [Member]
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
Direct operating expenses
1,833 
2,235 
3,906 
4,701 
Natural Gas Transportation Services [Member]
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
Direct operating expenses
1,928 
1,963 
3,163 
3,190 
Offshore Pipelines and Services [Member]
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
Direct operating expenses
3,490 
2,802 
6,070 
5,055 
Propane Marketing Services [Member]
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
Direct operating expenses
13,590 
13,634 
26,652 
27,107 
Terminalling Services [Member]
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
Direct operating expenses
$ 2,998 
$ 2,388 
$ 6,071 
$ 4,997 
Reportable Segments (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2017
Jun. 30, 2016
Jun. 30, 2017
Jun. 30, 2016
Segment information
 
 
 
 
Revenue
$ 193,426 
$ 187,203 
$ 393,315 
$ 330,817 
Gains (losses) on commodity derivatives, net
207 
(1,367)
(50)
(1,605)
Total revenue
193,633 
185,836 
393,265 
329,212 
Earnings in unconsolidated affiliates
17,552 
11,702 
32,954 
19,045 
Cost of Sales
128,816 
115,080 
261,601 
189,018 
Direct operating expenses
31,884 
31,967 
61,972 
62,542 
Corporate expenses
30,084 
22,281 
62,928 
43,382 
Depreciation, amortization and accretion
30,170 
26,398 
59,521 
51,439 
(Gain) loss on sale of assets, net
52 
478 
(176)
1,600 
Total operating expenses
221,006 
196,204 
445,846 
347,981 
Interest expense
17,152 
10,610 
35,118 
18,912 
Other income
(72)
(496)
(86)
(527)
Loss from continuing operations before taxes
(26,901)
(8,780)
(54,659)
(18,109)
Income tax expense
801 
701 
1,924 
1,436 
Loss from continuing operation
(27,702)
(9,481)
(56,583)
(19,545)
Loss from discontinued operations, net of tax
(539)
Net loss
(27,702)
(9,481)
(56,583)
(20,084)
Less: Net income attributable to noncontrolling interests
1,462 
954 
2,765 
951 
Net loss attributable to the Partnership
(29,164)
(10,435)
(59,348)
(21,035)
Segment gross margin
79,300 
81,072 
159,404 
155,117 
Gathering and Processing reporting segment [Member]
 
 
 
 
Segment information
 
 
 
 
Revenue
39,307 
30,710 
73,714 
54,004 
Gains (losses) on commodity derivatives, net
(98)
(763)
(105)
(866)
Total revenue
39,209 
29,947 
73,609 
53,138 
Earnings in unconsolidated affiliates
 
Cost of Sales
26,582 
17,162 
49,769 
28,868 
Direct operating expenses
8,045 
8,945 
16,110 
17,492 
Segment gross margin
12,651 
13,337 
23,902 
24,957 
Liquid Pipelines and Services [Member]
 
 
 
 
Segment information
 
 
 
 
Revenue
82,303 
85,415 
164,342 
129,930 
Gains (losses) on commodity derivatives, net
297 
(716)
669 
(948)
Total revenue
82,600 
84,699 
165,011 
128,982 
Earnings in unconsolidated affiliates
1,482 
1,009 
2,569 
1,009 
Cost of Sales
77,332 
76,992 
154,409 
115,645 
Direct operating expenses
1,833 
2,235 
3,906 
4,701 
Segment gross margin
6,683 
9,432 
13,152 
15,284 
Natural Gas Transportation Services [Member]
 
 
 
 
Segment information
 
 
 
 
Revenue
11,397 
7,877 
23,835 
17,672 
Gains (losses) on commodity derivatives, net
Total revenue
11,397 
7,877 
23,835 
17,672 
Earnings in unconsolidated affiliates
 
Cost of Sales
5,678 
4,026 
11,938 
8,250 
Direct operating expenses
1,928 
1,963 
3,163 
3,190 
Segment gross margin
5,631 
3,843 
11,750 
9,406 
Offshore Pipelines and Services [Member]
 
 
 
 
Segment information
 
 
 
 
Revenue
12,139 
10,645 
26,970 
17,645 
Gains (losses) on commodity derivatives, net
(2)
(2)
Total revenue
12,139 
10,643 
26,970 
17,643 
Earnings in unconsolidated affiliates
16,070 
10,693 
30,385 
18,036 
Cost of Sales
2,586 
778 
5,929 
1,860 
Direct operating expenses
3,490 
2,802 
6,070 
5,055 
Segment gross margin
25,623 
20,558 
51,426 
33,819 
Terminalling Services [Member]
 
 
 
 
Segment information
 
 
 
 
Revenue
15,831 
17,815 
34,457 
32,210 
Gains (losses) on commodity derivatives, net
(260)
(436)
Total revenue
15,831 
17,555 
34,457 
31,774 
Earnings in unconsolidated affiliates
 
Cost of Sales
2,073 
3,542 
6,466 
5,747 
Direct operating expenses
2,998 
2,388 
6,071 
4,997 
Segment gross margin
10,760 
11,586 
21,920 
21,030 
Propane Marketing Services [Member]
 
 
 
 
Segment information
 
 
 
 
Revenue
32,449 
34,741 
69,997 
79,356 
Gains (losses) on commodity derivatives, net
374 
(614)
647 
Total revenue
32,457 
35,115 
69,383 
80,003 
Earnings in unconsolidated affiliates
 
Cost of Sales
14,565 
12,580 
33,090 
28,648 
Direct operating expenses
13,590 
13,634 
26,652 
27,107 
Segment gross margin
$ 17,952 
$ 22,316 
$ 37,254 
$ 50,621 
Reportable Segments Reportable Segments - Assets (Details) (USD $)
In Thousands, unless otherwise specified
Jun. 30, 2017
Dec. 31, 2016
Segment Reporting Information [Line Items]
 
 
Assets
$ 2,051,942 
$ 2,349,321 
Gathering and Processing reporting segment [Member]
 
 
Segment Reporting Information [Line Items]
 
 
Assets
524,905 
530,889 
Liquid Pipelines and Services [Member]
 
 
Segment Reporting Information [Line Items]
 
 
Assets
433,618 
422,636 
Offshore Pipelines and Services [Member]
 
 
Segment Reporting Information [Line Items]
 
 
Assets
369,137 
400,193 
Natural Gas Transportation Services [Member]
 
 
Segment Reporting Information [Line Items]
 
 
Assets
227,466 
221,604 
Terminalling Services [Member]
 
 
Segment Reporting Information [Line Items]
 
 
Assets
281,016 
299,534 
Propane Marketing Services [Member]
 
 
Segment Reporting Information [Line Items]
 
 
Assets
130,731 
140,864 
Other Segments [Member]
 
 
Segment Reporting Information [Line Items]
 
 
Assets
85,069 
333,601 
Scenario, Adjustment [Member] |
Offshore Pipelines and Services [Member]
 
 
Segment Reporting Information [Line Items]
 
 
Assets
 
14,000 
Scenario, Adjustment [Member] |
Terminalling Services [Member]
 
 
Segment Reporting Information [Line Items]
 
 
Assets
 
(1,000)
Scenario, Adjustment [Member] |
Other Segments [Member]
 
 
Segment Reporting Information [Line Items]
 
 
Assets
 
$ (13,000)
Subsequent Events (Details) (USD $)
0 Months Ended 3 Months Ended 6 Months Ended 0 Months Ended 0 Months Ended
Apr. 25, 2017
Jun. 30, 2017
Jun. 30, 2016
Jun. 30, 2017
Jun. 30, 2016
Dec. 31, 2016
Jul. 25, 2017
Subsequent Event [Member]
Jul. 21, 2017
Subsequent Event [Member]
Propane Marketing Services [Member]
location
Aug. 8, 2017
AmPan [Member]
Subsequent Event [Member]
Aug. 8, 2017
Panther Asset Management LLC (Panther) [Member]
Subsequent Event [Member]
Aug. 8, 2017
Panther Asset Management LLC (Panther) [Member]
Subsequent Event [Member]
Aug. 8, 2017
MPOG [Member]
Subsequent Event [Member]
Aug. 7, 2017
Panther Asset Management LLC (Panther) [Member]
AmPan [Member]
Subsequent Event [Member]
Aug. 7, 2017
Panther Asset Management LLC (Panther) [Member]
MPOG [Member]
Subsequent Event [Member]
Subsequent Event [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of assets to be divested (percent)
 
 
 
 
 
 
 
100.00% 
 
 
 
 
 
 
Number of service locations to be divested
 
 
 
 
 
 
 
40 
 
 
 
 
 
 
Cash consideration for the planned divestitures
 
 
 
 
 
 
 
$ 170,000,000 
 
 
 
 
 
 
Distribution declared per common unit (in usd per share)
$ 0.4125 
$ 0.4125 1
$ 0.4125 1
$ 0.825 1
$ 0.885 1
 
$ 0.4125 
 
 
 
 
 
 
 
Distribution made to limited partner, distributions declared, per unit, annualized basis (in usd per share)
 
 
 
 
 
 
$ 1.65 
 
 
 
 
 
 
 
Ownership interest acquired (percent)
 
 
 
 
 
 
 
 
100.00% 
 
100.00% 
100.00% 
40.00% 
33.30% 
Consideration transferred to acquire interest in joint venture
 
286,548,000 
 
286,548,000 
 
291,988,000 
 
 
 
 
52,000,000 
 
 
 
Cash payment to acquire interest in joint venture
 
 
 
 
 
 
 
 
 
$ 39,000,000