AMERICAN MIDSTREAM PARTNERS, LP, 10-K filed on 3/10/2015
Annual Report
Document and Entity Information (USD $)
12 Months Ended
Dec. 31, 2014
Jun. 30, 2014
Mar. 6, 2015
Limited Partner Common Units
Mar. 6, 2015
Series A
Mar. 6, 2015
Series B
Entity Registrant Name
American Midstream Partners, LP 
 
 
 
 
Entity Central Index Key
0001513965 
 
 
 
 
Document Type
10-K 
 
 
 
 
Document Period End Date
Dec. 31, 2014 
 
 
 
 
Amendment Flag
false 
 
 
 
 
Document Fiscal Year Focus
2014 
 
 
 
 
Document Fiscal Period Focus
FY 
 
 
 
 
Current Fiscal Year End Date
--12-31 
 
 
 
 
Entity Well-known Seasoned Issuer
No 
 
 
 
 
Entity Voluntary Filers
No 
 
 
 
 
Entity Current Reporting Status
Yes 
 
 
 
 
Entity Filer Category
Accelerated Filer 
 
 
 
 
Entity Public Float
 
$ 294,650,782 
 
 
 
Entity Common Stock, Shares Outstanding
 
 
22,753,974 
5,909,349 
1,277,772 
Consolidated Balance Sheets (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Current assets
 
 
Cash and cash equivalents
$ 499 
$ 393 
Accounts receivable
4,924 
6,822 
Unbilled revenue
24,619 
23,001 
Risk management assets
688 
473 
Other current assets
15,502 
7,497 
Current deferred tax asset
3,086 
0 
Current assets held for sale
52 
272 
Total current assets
49,370 
38,458 
Property, plant and equipment, net
582,182 
312,701 
Goodwill
142,236 
16,447 
Intangible assets, net
106,306 
3,682 
Investment in unconsolidated affiliates
22,252 
0 
Other assets, net
13,117 
9,064 
Noncurrent assets held for sale, net
1,181 
1,723 
Total assets
916,644 
382,075 
Current liabilities
 
 
Accounts payable
20,326 
3,261 
Accrued gas purchases
14,326 
17,386 
Accrued expenses and other current liabilities
25,788 
15,058 
Current portion of long-term debt
2,908 
2,048 
Risk management liabilities
215 
423 
Current liabilities held for sale
12 
114 
Total current liabilities
63,575 
38,290 
Risk management liabilities
0 
101 
Asset retirement cost
34,645 
34,636 
Other liabilities
126 
191 
Long-term debt
372,950 
130,735 
Deferred Tax Liabilities
8,199 
4,749 
Liabilities of Disposal Group, Including Discontinued Operation, Noncurrent
0 
95 
Total liabilities
479,495 
208,797 
Commitments and contingencies (see Note 19)
   
   
Series A convertible preferred units (5,745 thousand and 5,279 thousand units issued and outstanding as of December 31, 2014 and 2013, respectively)
107,965 
94,811 
Equity and partners' capital
 
 
General Partner Interests (392 thousand and 185 thousand units issued and outstanding as of December 31, 2014 and 2013, respectively)
(2,450)
2,696 
Accumulated other comprehensive income
2 
104 
Total partners’ capital
324,467 
73,839 
Noncontrolling interests
4,717 
4,628 
Total equity and partners' capital
329,184 
78,467 
Total liabilities, equity and partners' capital
916,644 
382,075 
Limited Partner Common Units [Member]
 
 
Equity and partners' capital
 
 
Limited Partners' Capital Account
294,695 
71,039 
Limited Partner Series B Convertible Units [Member]
 
 
Equity and partners' capital
 
 
Limited Partners' Capital Account
$ 32,220 
$ 0 
Consolidated Balance Sheets (Parenthetical)
Dec. 31, 2014
Series A
Dec. 31, 2013
Series A
Dec. 31, 2014
Series B
Dec. 31, 2013
Series B
Preferred units issued
5,745,000 
5,279,000 
1,255,000 
0 
Preferred units outstanding
5,745,000 
5,279,000 
1,255,000 
0 
Consolidated Statements of Operations (USD $)
In Thousands, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Document Fiscal Year Focus
2014 
 
 
Revenue
$ 307,309 
$ 294,051 
$ 204,868 
Gain (loss) on commodity derivatives, net
1,091 
28 
3,400 
Total revenue
308,400 
294,079 
208,268 
Operating expenses:
 
 
 
Purchases of natural gas, NGLs and condensate
197,952 
215,053 
154,472 
Direct operating expenses
45,702 
32,236 
17,183 
Selling, general and administrative expenses
23,103 
19,079 
14,309 
Equity compensation expense
1,536 
2,094 
1,783 
Depreciation, amortization and accretion expense
28,832 
30,002 
21,287 
Total operating expenses
297,125 
298,464 
209,034 
Gain (loss) on involuntary conversion of property, plant and equipment
0 
343 
(1,021)
Gain (loss) on sale of assets, net
(122)
0 
123 
Loss on impairment of property, plant and equipment
(99,892)
(18,155)
0 
Operating income (loss)
(88,739)
(22,197)
(1,664)
Other income (expenses):
 
 
 
Interest expense
(7,577)
(9,291)
(4,570)
Other expense
(670)
0 
0 
Earnings in unconsolidated affiliates
348 
0 
0 
Net income (loss) before income tax benefit
(96,638)
(31,488)
(6,234)
Income Tax Expense (Benefit), Continuing Operations
557 
(495)
0 
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest
(97,195)
(30,993)
(6,234)
Discontinued operations
 
 
 
Gain (loss) from operations of disposal groups, net of tax
(611)
(2,413)
(18)
Net income (loss)
(97,806)
(33,406)
(6,252)
Less: Comprehensive income (loss) attributable to noncontrolling interests
214 
633 
256 
Net income (loss) attributable to the Partnership
(98,020)
(34,039)
(6,508)
Distribution declared per common unit (a)
$ 1.85 
$ 1.75 
$ 1.73 
Basic and diluted:
 
 
 
Income (Loss) from Continuing Operations, Per Outstanding Limited Partnership Unit, Basic
$ (8.54)
$ (7.15)
$ (0.70)
Limited partners' net income (loss) from discontinued operations per unit (basic and diluted)
$ (0.04)
$ (0.27)
$ 0.00 
Limited partners’ net income (loss) per unit (basic and diluted)
$ (8.58)
$ (7.42)
$ (0.70)
Weighted Average Number of Shares Outstanding, Diluted [Abstract]
 
 
 
Basic and diluted
13,472 
7,525 
9,113 
Total Partners Capital
 
 
 
Discontinued operations
 
 
 
Net income (loss) attributable to the Partnership
(98,020)
(34,039)
(6,508)
General Partner Interest
 
 
 
Discontinued operations
 
 
 
General Partner's Interest in net income (loss)
(1,279)
(1,405)
(129)
Limited Partner [Member]
 
 
 
Discontinued operations
 
 
 
Limited Partners' Interest in net income (loss)
(96,741)
(32,634)
(6,379)
Terminals [Member]
 
 
 
Revenue
 
9,831 
 
Gain (loss) on commodity derivatives, net
0 
0 
 
Total revenue
15,504 
 
 
Operating expenses:
 
 
 
Purchases of natural gas, NGLs and condensate
0 
0 
 
Direct operating expenses
$ 6,342 
$ 4,403 
 
Consolidated Statements of Comprehensive Income (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Statement of Comprehensive Income [Abstract]
 
 
 
Net income (loss)
$ (97,806)
$ (33,406)
$ (6,252)
Other Comprehensive Income (Loss), Net of Tax
(102)
(247)
(64)
Comprehensive income (loss)
(97,908)
(33,653)
(6,316)
Less: Comprehensive income (loss) attributable to noncontrolling interests
214 
633 
256 
Comprehensive income (loss) attributable to Partnership
$ (98,122)
$ (34,286)
$ (6,572)
Consolidated Statements of Changes in Partners' Capital and Noncontrolling Interest (USD $)
In Thousands
Total
General Partner Interest
Limited Partner Interest
Series B
Accumulated Other Comprehensive Income
Total Partners Capital
Noncontrolling Interest
Blackwater [Member]
Blackwater [Member]
General Partner Interest
Blackwater [Member]
Total Partners Capital
Series B
Series B
Series B
Accumulated Other Comprehensive Income
Series B
Total Partners Capital
Series B
Noncontrolling Interest
Beginning Balance at Dec. 31, 2011
 
$ 1,091 
$ 99,890 
 
$ 415 
$ 101,396 
 
 
 
 
 
 
 
 
 
Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests
0 
 
 
 
 
 
7,407 
 
 
 
 
 
 
 
 
General Partner's Interest in net income (loss)
 
(129)
 
 
 
 
 
 
 
 
 
 
 
 
 
Limited Partners' Interest in net income (loss)
 
 
(6,379)
 
 
 
 
 
 
 
 
 
 
 
 
Net income (loss)
(6,508)
 
 
 
 
(6,508)
 
 
 
 
 
 
 
 
 
Net Income (loss) attributable to noncontrolling interests
256 
 
 
 
 
 
256 
 
 
 
 
 
 
 
 
Issuance of common units, net of offering costs
0 
 
 
 
 
 
 
 
 
 
0 
 
 
 
 
Unit holder contributions
 
13 
 
 
 
13 
 
 
 
 
 
 
 
 
 
Unitholder distributions
(16,070)
(322)
(15,748)
 
 
(16,070)
 
0 
 
 
0 
 
 
 
 
Fair value of Series A Units in excess of net assets received
0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net distributions to noncontrolling interest owners
 
 
 
 
 
 
(225)
 
 
 
 
 
 
 
 
LTIP vesting
 
(1,888)
1,888 
 
 
 
 
 
 
 
 
 
 
 
 
Tax netting repurchase
385 
 
385 
 
 
385 
 
 
 
 
 
 
 
 
 
Unit based compensation
 
1,783 
 
 
 
1,783 
 
 
 
 
 
 
 
 
 
Other comprehensive income (loss)
(64)
 
 
 
(64)
(64)
 
 
 
 
 
 
 
 
 
Ending Balance at Dec. 31, 2012
 
548 
79,266 
 
351 
80,165 
7,438 
 
 
 
 
 
 
 
 
Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests
752 
(37)
(1,993)
 
 
(2,030)
(2,782)
 
 
 
 
 
 
 
 
General Partner's Interest in net income (loss)
 
(1,405)
 
 
 
 
 
 
 
 
 
 
 
 
 
Limited Partners' Interest in net income (loss)
 
 
(32,634)
 
 
 
 
 
 
 
 
 
 
 
 
Net income (loss)
(34,039)
 
 
 
 
(34,039)
 
 
 
 
 
 
 
 
 
Net Income (loss) attributable to noncontrolling interests
633 
 
 
 
 
 
633 
 
 
 
 
 
 
 
 
Issuance of common units, net of offering costs
54,853 
 
54,853 
 
 
54,853 
 
 
 
 
0 
 
 
 
 
Unit holder contributions
 
12,500 
0 
 
0 
12,500 
 
 
22,696 
22,696 
 
 
 
 
 
Unitholder distributions
(16,120)
(623)
(21,628)
 
 
(22,251)
 
(27,650)
(30,702)
 
0 
 
 
 
 
Fair value of Series A Units in excess of net assets received
(15,612)
(312)
(15,300)
 
 
(15,612)
 
 
 
 
 
 
 
 
 
Net distributions to noncontrolling interest owners
 
0 
0 
 
0 
0 
(661)
 
 
 
 
 
 
 
 
LTIP vesting
 
(2,067)
2,067 
 
 
 
 
 
 
 
 
 
 
 
 
Tax netting repurchase
630 
 
630 
 
 
630 
 
 
 
 
 
 
 
 
 
Unit based compensation
 
2,024 
 
 
 
2,024 
 
 
 
 
 
 
 
 
 
Other comprehensive income (loss)
(247)
 
 
 
(247)
(247)
 
 
 
 
 
 
 
 
 
Ending Balance at Dec. 31, 2013
73,839 
2,696 
71,039 
 
104 
73,839 
4,628 
 
 
 
 
 
 
 
 
Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests
8 
0 
(21)
0 
0 
(21)
189 
 
 
 
 
 
 
 
 
General Partner's Interest in net income (loss)
 
(1,279)
 
 
 
 
 
 
 
 
 
 
 
 
 
Limited Partners' Interest in net income (loss)
 
 
(96,741)
 
 
 
 
 
 
 
 
 
 
 
 
Net income (loss)
(98,020)
 
 
 
 
(98,020)
 
 
 
 
 
 
 
 
 
Net Income (loss) attributable to noncontrolling interests
214 
 
 
 
 
 
214 
 
 
 
 
 
 
 
 
Issuance of common units, net of offering costs
204,255 
0 
351,551 
0 
0 
 
0 
 
 
 
(30,000)
 
 
 
 
Issuance of Series B Units
 
 
0 
 
 
 
 
 
 
 
 
32,220 
0 
32,220 
0 
Unit holder contributions
 
5,678 
0 
0 
 
5,678 
0 
 
 
 
 
 
 
 
 
Unitholder distributions
(28,009)
(2,913)
(39,150)
 
 
(42,063)
 
0 
 
 
(2,220)
 
 
 
 
Fair value of Series A Units in excess of net assets received
0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Issuance and exercise of warrants
 
7,164 
7,164 
 
 
 
 
 
 
 
 
 
 
 
 
Net distributions to noncontrolling interest owners
 
0 
0 
0 
0 
0 
(314)
 
 
 
 
 
 
 
 
LTIP vesting
 
(824)
1,067 
 
 
243 
 
 
 
 
 
 
 
 
 
Tax netting repurchase
256 
 
256 
0 
 
256 
 
 
 
 
 
 
 
 
 
Unit based compensation
 
1,356 
0 
0 
0 
1,356 
0 
 
 
 
 
 
 
 
 
Other comprehensive income (loss)
(102)
 
 
 
(102)
(102)
 
 
 
 
 
 
 
 
 
Ending Balance at Dec. 31, 2014
$ 324,467 
$ (2,450)
$ 294,695 
$ 32,220 
$ 2 
$ 324,467 
$ 4,717 
 
 
 
 
 
 
 
 
Consolidated Statements of Cash Flows (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2014
Blackwater [Member]
Dec. 31, 2013
Blackwater [Member]
Dec. 31, 2012
Blackwater [Member]
Dec. 31, 2014
ArcLight [Member]
Dec. 31, 2013
ArcLight [Member]
Dec. 31, 2012
ArcLight [Member]
Cash flows from operating activities
 
 
 
 
 
 
 
 
 
Net income (loss)
$ (97,806)
$ (33,406)
$ (6,252)
 
 
 
 
 
 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
 
 
 
 
 
 
Depreciation, amortization and accretion expense
28,832 
29,999 
21,414 
 
 
 
 
 
 
Amortization of deferred financing costs
2,212 
1,334 
716 
 
 
 
 
 
 
Amortization of weather derivative premium
1,035 
662 
0 
 
 
 
 
 
 
Unrealized (gain) loss on derivative contracts, net
(595)
1,505 
(992)
 
 
 
 
 
 
Non-cash compensation
1,626 
2,094 
1,783 
 
 
 
 
 
 
Postretirement expense (benefit)
(45)
(73)
(88)
 
 
 
 
 
 
(Gain) loss on involuntary conversion of property, plant and equipment
0 
(343)
1,021 
 
 
 
 
 
 
(Gain) loss on sale of assets, net
207 
75 
(128)
 
 
 
 
 
 
Loss on impairment of property, plant and equipment
99,892 
18,155 
0 
 
 
 
 
 
 
Loss on impairment of noncurrent assets held for sale
673 
2,400 
0 
 
 
 
 
 
 
Deferred tax expense (benefit)
213 
(847)
0 
 
 
 
 
 
 
Changes in operating assets and liabilities, net of effects of assets acquired and liabilities assumed:
 
 
 
 
 
 
 
 
 
Accounts receivable
13,067 
(790)
(740)
 
 
 
 
 
 
Unbilled revenue
2,272 
(226)
2,768 
 
 
 
 
 
 
Risk management assets and liabilities
(809)
(1,147)
(156)
 
 
 
 
 
 
Other current assets
(7,533)
(1,614)
984 
 
 
 
 
 
 
Other assets, net
6,049 
(823)
(57)
 
 
 
 
 
 
Accounts payable
(12,026)
(845)
1,197 
 
 
 
 
 
 
Accrued gas purchases
(5,540)
462 
(1,711)
 
 
 
 
 
 
Accrued expenses and other current liabilities
(9,149)
769 
(943)
 
 
 
 
 
 
Asset retirement obligations
(1,030)
0 
0 
 
 
 
 
 
 
Other liabilities
(67)
(118)
(468)
 
 
 
 
 
 
Net cash provided by operating activities
21,478 
17,223 
18,348 
 
 
 
 
 
 
Net cash provided by operating activities
 
 
 
 
 
 
 
 
 
Cost of acquisitions, net of cash acquired
(362,316)
0 
(51,377)
 
 
 
 
 
 
Additions to property, plant and equipment
(96,998)
(27,196)
(11,705)
 
 
 
 
 
 
Proceeds from disposal of property, plant and equipment
6,323 
500 
128 
 
 
 
 
 
 
Insurance proceeds from involuntary conversion of property, plant and equipment
0 
482 
527 
 
 
 
 
 
 
Investment in unconsolidated affiliate
(12,000)
0 
0 
 
 
 
 
 
 
Proceeds from equity method investment, return of capital
1,632 
0 
0 
 
 
 
 
 
 
Restricted cash
(8,511)
(2,000)
0 
 
 
 
 
 
 
Net cash used in investing activities
(471,870)
(28,214)
(62,427)
 
 
 
 
 
 
Cash flows from financing activities
 
 
 
 
 
 
 
 
 
Proceeds from issuance of common units to public, net of offering costs
204,255 
54,853 
0 
 
 
 
 
 
 
Unitholder contributions
5,588 
13,075 
13 
 
 
 
 
 
 
Unitholder distributions
(28,009)
(16,120)
(16,070)
0 
(27,650)
0 
 
 
 
Issuance of Series A Units
0 
14,393 
0 
 
 
 
 
 
 
Acquisition of noncontrolling interests
(8)
(752)
0 
 
 
 
 
 
 
LTIP tax netting unit repurchase
(256)
(630)
(385)
 
 
 
 
 
 
Deferred financing costs
(3,841)
(2,113)
(1,564)
 
 
 
 
 
 
Payments on other debt
(2,589)
(2,640)
0 
 
 
 
 
 
 
Borrowings on other debt
3,449 
3,795 
0 
 
 
 
 
 
 
Payments on loan to affiliate
0 
(20,000)
0 
 
 
 
 
 
 
Payments on bank loans
0 
(34,730)
0 
 
 
 
 
 
 
Borrowings on bank loans
0 
27,546 
0 
 
 
 
 
 
 
Payments on long-term debt
(250,870)
(131,571)
(59,230)
 
 
 
 
 
 
Borrowings on long-term debt
493,085 
134,021 
121,245 
 
 
 
 
 
 
Net cash provided by financing activities
450,490 
10,816 
43,784 
 
 
 
 
 
 
Net increase (decrease) in cash and cash equivalents
98 
(175)
(295)
 
 
 
 
 
 
Cash and cash equivalents
 
 
 
 
 
 
 
 
 
Beginning of period
401 
576 
871 
 
 
 
 
 
 
End of period
499 
401 
576 
 
 
 
 
 
 
Supplemental cash flow information
 
 
 
 
 
 
 
 
 
Interest payments, net
6,726 
6,416 
3,185 
 
 
 
 
 
 
Supplemental non-cash information
 
 
 
 
 
 
 
 
 
(Decrease) increase in accrued property, plant and equipment
31,390 
(5,181)
6,968 
 
 
 
 
 
 
Receivable for reimbursable construction in progress projects
0 
0 
141 
 
 
 
 
 
 
Noncash or Part Noncash Acquisition, Net Nonmonetary Assets Acquired (Liabilities Assumed)
 
 
 
0 
22,121 
0 
0 
59,995 
0 
Fair value of Series A Units in excess of net assets received
0 
15,612 
0 
 
 
 
 
 
 
Accrued and in-kind unitholder distribution for Series A Units
13,154 
4,811 
0 
 
 
 
 
 
 
In-kind unitholder distribution for Series B Units
2,220 
0 
0 
 
 
 
 
 
 
Common unit issuance related to Acquisition
 
 
 
 
$ 3,100 
 
 
 
 
Organization and Basis of Presentation
Organization and Basis of Presentation
Organization and Basis of Presentation

General

American Midstream Partners, LP (the "Partnership"), was formed on August 20, 2009 as a Delaware limited partnership for the purpose of operating, developing and acquiring a diversified portfolio of midstream energy assets. The Partnership's general partner, American Midstream GP, LLC (the "General Partner"), is 95% owned by High Point Infrastructure Partners, LLC ("HPIP") and 5% owned by AIM Midstream Holdings, LLC. We hold our assets in a series of wholly owned limited liability companies, a limited partnership and a corporation. Our capital accounts consist of notional general partner units and limited partner interests.

Nature of business

We are engaged in the business of gathering, treating, processing, and transporting natural gas, fractionating NGLs and storing specialty chemical products through our ownership and operation of twelve gathering systems, five processing facilities, three fractionation facilities, four marine terminal sites, three interstate pipelines and five intrastate pipelines. We also own a 66.7% non-operating interest in Main Pass Oil Gathering, LP ("MPOG"), a crude oil gathering and processing system, as well as a 50% undivided, non-operating interest in the Burns Point Plant, a natural gas processing plant. Our primary assets, which are strategically located in Alabama, Georgia, Louisiana, Maryland, Mississippi, North Dakota, Tennessee and Texas, provide critical infrastructure that links producer of natural gas, NGLs, condensate and specialty chemicals to numerous intermediate and end-use markets. We currently operate more than 3,000 miles of pipelines that gather and transport over 1 Bcf/d of natural gas and operate approximately 1.7 million barrels of storage capacity across four marine terminal sites.

Basis of presentation

The accompanying financial statements and related notes present our consolidated financial position as of December 31, 2014 and 2013, and results of operations, comprehensive income, changes in partners' capital and noncontrolling interest, and cash flows for the years ended December 31, 2014, 2013 and 2012.

We have prepared the consolidated financial statements in accordance with accounting principles generally accepted in the United States of America ("GAAP"). We have made reclassifications to amounts reported in prior period consolidated financial statements to conform with current year presentation. These reclassifications did not have an impact on net income for the period previously reported.

The financial results for the years ended December 31, 2013 and 2012 have been reclassified to present an asset group previously presented as held for sale as held and used.

The results of operations for acquisitions accounted for as business combinations have been included in the consolidated financial statements since their respective acquisition dates. See Note 3 "Acquisitions" for further information.

Transactions Between Entities Under Common Control
 
We may enter into transactions with our General Partner and affiliates whereby we receive a contribution of midstream assets or subsidiaries in exchange for consideration from the Partnership. We account for the net assets received using the historical book value of the asset or subsidiary being contributed or transferred as these are transactions between entities under common control. Our historical financial statements may be revised to include the results attributable to the assets contributed from our General Partner as if we owned such assets for all periods presented by the Partnership since either the change in control of our General Partner, effective April 15, 2013 or later.

Consolidation policy

The accompanying consolidated financial statements include accounts of American Midstream Partners, LP, and its controlled subsidiaries. All significant inter-company accounts and transactions have been eliminated in the preparation of the accompanying consolidated financial statements. We hold a 50% undivided interest in the Burns Point gas processing facility in which we are responsible for our proportionate share of the costs and expenses of the facility. Our consolidated financial statements reflect our proportionate share of the revenues, expenses, assets and liabilities of this undivided interest. In July 2012, the Partnership acquired an 87.4% undivided interest in the Chatom Processing and Fractionation facility (the "Chatom System"). In the fourth quarter of 2013, the Partnership acquired an additional 4.8% undivided interest in the Chatom System. Our consolidated financial statements reflect the accounts of the Chatom System since acquisition. The interests in the Chatom System held by non-affiliated working interest owners are reflected as noncontrolling interests in the Partnership's consolidated financial statements.

The Partnership accounts for its 66.7% non-operated interest in MPOG as an equity method investments under ASC 323, as the Partnership exercises significant influence but does not control nor is the primary beneficiary of MPOG.

Use of estimates

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

Cash and cash equivalents

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.

Allowance for doubtful accounts

We establish provisions for losses on accounts receivable when we determine that we will not collect all or part of an outstanding balance. Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. As of December 31, 2014 and 2013, the Partnership recorded no allowances for losses on accounts receivable.

Inventory

Inventory includes natural gas liquids ("NGLs") product inventory. The Partnership records all product inventories at the lower of cost or market with a cost basis determined on a weighted average basis. Product inventories are included within Other current assets on the consolidated balance sheets.

Operational balancing agreements and natural gas imbalances

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

Derivative financial instruments

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

•
Commodity-based derivatives: "Total revenue"
•
Corporate interest rate derivatives: "Interest expense"

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

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

Fair value measurements

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

We use various assumptions and methods in estimating the fair values of our financial instruments. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximated their fair value due to the short-term maturity of these instruments. The carrying amount of our various credit facilities approximate fair value, because the interest rates on these facilities are variable.

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

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

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

Property, plant and equipment

We capitalize expenditures related to property, plant and equipment that have a useful life greater than one year for assets purchased or constructed; existing assets that are replaced, improved, or the useful lives of which have been extended; and all land, regardless of cost. Maintenance and repair costs, including any planned major maintenance activities, are expensed as incurred.

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

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


Impairment of long lived Assets

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

Goodwill and intangible assets

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

We record the estimated fair value of acquired customer contracts, relationships and dedicated acreage agreements as intangible assets. These intangible assets have definite lives and are subject to amortization on a straight-line basis over their economic lives, currently ranging between 5 months and thirty years. We assess intangible assets for impairment together with related underlying long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.

Deferred financing costs

Costs incurred in connection with the issuance of long-term debt are deferred and charged to interest expense over the term of the related debt. Gains or losses on debt repurchase and debt extinguishment include any associated unamortized deferred financing costs.

Asset retirement obligations ("AROs")

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

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

Commitments, contingencies and environmental liabilities

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

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

Noncontrolling interests

Noncontrolling interests represent the noncontrolling interest holders' proportionate share of the equity of the respective systems. Noncontrolling interest is adjusted for the noncontrolling interest holders' proportionate share of the earnings or losses. Management reports noncontrolling interest in the Chatom system in the financial statements pursuant to paragraph ASC 810-10-65-1. The 7.8% noncontrolling interest is held by non-affiliated working interest owners.

Revenue recognition and the estimation of revenues and cost of purchases

We recognize revenue 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 record revenue and cost of product sold on a gross basis for those transactions where we act as the principal and take title to natural gas, NGLs or condensates that are purchased for resale. When our customers pay us a fee for providing a service such as gathering, treating, transportation or storage, we record those fees separately in revenues. We have the following arrangements:

Fee-based

Under these arrangements, we generally are paid a fixed fee for gathering and transporting natural gas. Fee-based revenues are recorded when services have been provided, and collectability of the revenue is reasonably assured.

Percent-of-proceeds, or POP

Under these arrangements, we generally gather raw natural gas from producers at the wellhead or other supply points, transport it through our gathering system, process it and sell the residue natural gas and NGLs at market prices. Where we provide processing services at the processing plants that we own, or obtain processing service for our own account under our own elective processing arrangements we typically retain and sell a percentage of the residue natural gas and resulting NGLs. We recognize percent-of-proceeds contract revenue when the natural gas, NGLs or condensate is sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, and collectability of the revenue is reasonably assured.

Fixed-margin

Under these arrangements, we purchase natural gas from producers or suppliers at receipt points on our systems at an index price less a fixed transportation fee and simultaneously sell an identical volume of natural gas at delivery points on our systems at the same, undiscounted index price. We recognize revenue from fixed-margin contracts when the natural gas is sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, and collectability of the revenue is reasonably assured.

Firm transportation

Under arrangements to provide firm transportation service, we are obligated to transport natural gas nominated by the shipper up to the maximum daily quantity specified in the contract. In exchange for that obligation on our part, the shipper pays a specified reservation charge, whether or not they utilize the capacity. In most cases, the shipper also pays a variable-use charge with respect to quantities actually transported by us. Firm transportation revenue is recorded when products are delivered, services have been provided, and collectability of the revenue is reasonably assured.

Interruptible transportation

Under arrangements to provide interruptible transportation service, we are only obligated to transport natural gas nominated by the shipper to the extent we have available capacity. For this service, the shipper pays no reservation charge but pays a variable-use charge for quantities actually shipped. Interruptible transportation revenue is recorded when products are delivered, services have been provided, and collectability of revenue is reasonably assured.

Interest in the Burns Point Plant

We account for our interest in the Burns Point Plant using the proportionate consolidation method. Under this method, we include in our consolidated statement of operations our value of plant revenues taken in-kind and plant expenses reimbursed to the operator.

Terminal revenue and services

Revenues for our terminals include storage tank lease fees, whereby a customer agrees to pay for a certain amount of tank storage over a certain period of time; and throughput fees, whereby a customer pays a fee based on volumes moving through the terminal. At our terminals, we also offer and provide packaging, blending, handling, filtering and certain other ancillary services. Revenue from firm storage contracts is recognized ratably, which is typically monthly, over the term of the lease. Occasionally, customers pay for tank lease fees in advance. Fees received in advance are deferred until the period earned. Revenue from throughput fees and ancillary fees are recognized as services are provided to the customer and collectability is reasonably assured.

Equity-based compensation

We award equity-based compensation to management, non-management employees and directors in the form of phantom units, which are deemed to be equity awards. Compensation expense on phantom units is measured by the fair value of the award at the date of grant as determined by management. Compensation expense is recognized in Equity compensation expense over the requisite service period of each award.

Income taxes

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

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

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

Accumulated other comprehensive income (loss)

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

Limited partners' net income (loss) per unit

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

The two-class method does not impact our overall net income or other financial results; however, in periods in which aggregate net income exceeds our aggregate distributions for such period, it will have the impact of reducing net income per limited partner unit. This result occurs as a larger portion of our aggregate earnings, as if distributed, is allocated to the incentive distribution rights of the General Partner, even though we make distributions on the basis of available cash and not earnings. In periods in which our aggregate net income does not exceed our aggregate distributions for such period, the two-class method does not have any impact on our calculation of earnings per limited partner unit. We have no dilutive securities, therefore basic and diluted net income per unit are the same.
Acquisitions
Acquisitions
Acquisitions

Costar Acquisition

On October 14, 2014, the Partnership acquired 100% of the membership interests of Costar Midstream, L.L.C. ("Costar") from Energy Spectrum Partners VI LP and Costar Midstream Energy, LLC, in exchange for $265.4 million in cash and 6.9 million of the Partnership's limited partner common units ("Costar Acquisition"). Costar Midstream is an onshore gathering and processing company with its primary gathering, processing, fractionation, and off-spec condensate treating and stabilization assets in East Texas and the Permian basin, with a significant crude oil gathering system project underway in the Bakken oil play.

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

The following table summarizes the fair value of consideration transferred to acquire Costar and the preliminary allocation of that amount to the assets acquired, liabilities assumed and the noncontrolling interest based upon their respective fair values as of the acquisition date. Such allocation will be finalized once the Partnership negotiates a final settlement of working capital amounts with the sellers with any resulting adjustment being recorded to goodwill.
Fair value of consideration transferred (in thousands):
 
Cash
$
265,383

Limited partner common units
147,296

Total fair value of consideration
$
412,679


Fair Value of assets acquired, liabilities assumed and noncontrolling interest (in thousands):
 
Working capital
$
8,152

Property, plant and equipment:
 
Processing plants
$
48,357

Pipelines
128,799

Land
1,244

Buildings
682

Equipment
9,827

Construction in progress
16,146

Total property, plant and equipment
205,055

Investment in unconsolidated affiliate
11,884

Intangible assets:
 
Customer relationships
53,400

Dedicated acreage
32,000

Goodwill
102,407

Noncontrolling interest
(219
)
 
$
412,679



The fair value of the limited partner common units of $147.3 million differs from the amount determined using the market price of such units on the date of the acquisition as a result of restrictions which require the sellers to hold the units for specified periods of time. The fair value of limited partner units issued in the transaction was determined using an option pricing model and the following key assumptions: i) the closing unit market price on the day of the acquisition, ii) the contractual holding periods, iii) historical unit price volatility for the Partnership and its peers, and iv) a risk-free rate of return.

The fair value of property, plant and equipment was determined using both the cost and market approaches which required significant Level 3 inputs. Key assumptions included i) estimated replacement costs for individual assets or asset groups, ii) estimated remaining useful lives for the acquired assets, and iii) recent market transactions for similar assets. The fair value of intangible assets was determined using the income approach which also required significant Level 3 inputs. Key assumptions included i) estimated throughput volumes, ii) forward market prices for natural gas and NGLS as of the acquisition date, iii) estimated future operating and development cash flows, and iv) discount rates ranging from 11.0% to 16.0%.

The intangible assets acquired relate to existing customer relationships which Costar had at the time of the acquisition, as well as agreements with two producers under which Costar agreed to construct and operate gathering and processing facilities in exchange for the producers’ agreements to dedicate certain acreage and related production to those facilities. Working capital includes $11.2 million of accounts receivable, all of which were subsequently collected.

Costar contributed revenue of $19.9 million and operating income of $0.3 million for the period October 14, 2014 through December 31, 2014, attributable to the Partnership's Gathering and Processing segment. Additionally, the Partnership incurred $0.5 million of transaction costs related to the acquisition which are included in Selling, general and administrative expenses in the consolidated statement of operations for the year ended December 31, 2014. The following unaudited pro forma summary presents consolidated financial information for the Partnership as if the Costar acquisition had occurred on January 1, 2013 (in thousands):
 
Year Ended December 31,
 
2014
 
2013
Revenue
$
435,133

 
$
448,748

Net loss
(101,237
)
 
(30,672
)
Limited partners' net loss per unit
(6.15
)
 
(3.82
)


These pro forma amounts have been calculated after applying the Partnership’s accounting policies to Costar’s historical results and making adjustments to reflect additional interest expense that would have been incurred and additional depreciation and amortization expense that would have been recognized had the acquisition occurred as of January 1, 2013. The unaudited pro forma adjustments are based on available information and certain assumptions we believe are reasonable.

Lavaca Acquisition

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

The Lavaca Acquisition was accounted for using the acquisitions method of accounting and, as a result, the purchase price was allocated to the assets acquired upon their respective fair values as of the acquisition date. The excess of the purchase price over the fair value of the assets acquired was classified as goodwill.

The following table summarizes the preliminary allocation of the purchase price to the assets acquired based upon their respective fair values as of the acquisition date. Such allocation will be finalized once the Partnership negotiates a final settlement of property, plant and equipment expenditures with the sellers, with any resulting adjustment being recorded to goodwill (in thousands):
Property, plant and equipment:
 
Land
$
2

Pipelines
58,737

Equipment
753

Total property, plant and equipment
59,492

Intangible assets
21,350

Goodwill
23,567

Total cash consideration
$
104,409



During the fourth quarter of 2014, errors were identified in the spreadsheets used to determine the preliminary purchase price allocation for the Lavaca Acquisition, which resulted in a $23.6 million overstatement of the previously reported amount allocated to intangible assets with an offsetting understatement of goodwill. These errors also resulted in a $0.5 million overstatement of amortization expense for the first nine months of 2014. The preliminary purchase price allocation as summarized above has been revised to correct these errors. Additionally, an adjustment was recorded during the fourth quarter of 2014 to correct the overstatement of amortization expense which occurred during the first nine months of the year.

The fair value of property, plant and equipment was determined using the cost approach which required significant Level 3 inputs. Key assumptions included i) estimated replacement costs for individual assets or asset groups and ii) estimated remaining useful lives for the acquired assets. The fair value of intangible assets was determined using the income approach which also required significant Level 3 inputs. Key assumptions included i) estimated throughput volumes, ii) future operating and development cash flows, and iii) a discount rate of 10.5%.

The intangible assets acquired relate to a 25-year gas gathering agreement under which PVA will dedicate certain acreage and related production to the acquired facilities.

Lavaca contributed revenue of $16.8 million and net income of $7.6 million for the period from January 31, 2014 through December 31, 2014, attributable to the Partnership's Gathering and Processing segment. The Partnership incurred $0.1 million of transaction costs related to the acquisition, which are included in Selling, general and administrative expenses in the consolidated statement of operations for the year ended December 31, 2014.

Pro forma financial results are not presented as it is impractical to obtain the necessary information. The seller did not operate the acquired assets as a standalone business and, therefore, historical financial information that is consistent with the operations under the current agreement is not available.

Other Acquisitions

Investment in Unconsolidated Affiliate

On August 11, 2014, the Partnership acquired a 66.7% non-operated interest in MPOG, an offshore oil gathering system, for a net purchase price of $12.0 million, which was financed with borrowings from the Partnership's credit facility. Although the Partnership owns a majority interest in MPOG, the ownership structure requires unanimous approval of all owners on decisions impacting the operation of the assets and any changes in ownership structure. Therefore, the Partnership's voting rights are not proportional to its obligation to absorb losses or receive returns. The Partnership accounts for its 66.7% interest using the equity method. The Partnership recorded $0.3 million in earnings from unconsolidated affiliate, and received cash distributions of $2.0 million for the year ended December 31, 2014. The excess of the cash distributions received over the earnings recorded from MPOG is classified as a return of capital within the investing section of our consolidated statement of cash flows.

Williams Pipeline Acquisition

In the first quarter of 2014, the Partnership acquired natural gas pipeline facilities that are contiguous to and connect with our High Point System in offshore Louisiana from Transcontinental Gas Pipe Line Company, LLC ("Transco"), a subsidiary of Williams Partners, LP for $6.5 million  in cash (the "Williams Pipeline Acquisition"). The acquisition was subject to FERC approval of the seller's application to abandon by sale to us the pipeline facilities and to permit the facilities to serve a gathering function, exempt from FERC's jurisdiction. The FERC granted approval of the application during the first quarter of 2014, and the purchase and sale agreement closed on March 14, 2014. The purchase price was allocated to pipelines using the income approach which required certain Level 3 inputs.

Blackwater Terminals Acquisition

On December 17, 2013, the Partnership acquired Blackwater Midstream Holdings LLC ("Blackwater"), a Delaware limited liability company and other related subsidiaries from an affiliate of HPIP. Blackwater operated 1.3 million barrels of storage capacity across four marine terminal sites located in Westwego, Louisiana; Brunswick, Georgia; Harvey, Louisiana; and Salisbury, Maryland.

The Partnership distributed consideration of $63.9 million, of which $27.7 million was accounted for as a cash distribution to the General Partner. The consideration also included 125,500 limited partner units which were accounted for as a non-cash distribution to the General Partner at a fair value of $3.1 million. The fair value of the units issued was determined using level one inputs based upon the Partnership's closing unit price on December 17, 2013.

The remaining consideration was utilized to settle all of the Blackwater's outstanding debt at December 17, 2013.

The acquisition of Blackwater represents a transaction between entities under common control and a change in reporting entity. Transfers of net assets or exchanges of shares between entities under common control are accounted for as if the transfer occurred at the beginning of the period or date of common control. Therefore, net assets received were recorded at their historical book value of $22.7 million as of the date common control was established, which is April 15, 2013.

For the period from April 15, 2013 to December 31, 2013, our Terminals segment contributed $9.8 million of revenue and $0.8 million of net loss attributable to the Partnership's Terminals segment, which are included in the consolidated statement of operations.

High Point System

Effective April 15, 2013, our General Partner contributed the High Point System, consisting of 100% of the limited liability company interests in High Point Gas Transmission, LLC, and High Point Gas Gathering, LLC. The High Point System consists of approximately 700 miles of natural gas and liquids pipeline assets located in southeast Louisiana, in the Plaquemines and St. Bernard parishes, and the shallow water and deep shelf Gulf of Mexico, including the Mississippi Canyon, Viosca Knoll, West Delta, Main Pass, South Pass and Breton Sound zones. Natural gas is collected at more than 75 receipt points that connect hundreds of wells with an emphasis on oil and liquids-rich reservoirs.

The High Point System, along with $15.0 million in cash, was contributed to us by HPIP in exchange for 5,142,857 Series A Units. Of the cash consideration paid by HPIP, approximately $2.5 million was used to pay certain transaction expenses of HPIP, and the remaining approximately $12.5 million was used to repay borrowings outstanding under the Partnership's former credit facility. The contribution of the High Point System occurred concurrently with HPIP's acquisition of 90% of our General Partner and all of our subordinated units, which resulted in HPIP gaining control of our General Partner and a majority of our outstanding limited partner interests.

The fair value of the Series A Units on April 15, 2013, was $17.50 per unit, or a total of $90.0 million, and was issued by the Partnership in exchange for net cash of approximately $12.5 million and net assets of $61.9 million contributed to the Partnership by our General Partner. The contribution of net assets of the High Point System was accounted for as a transaction between entities under common control whereby the High Point System was recorded at historical book value. As such, the value of the Series A Units in excess of the net assets contributed by our General Partner amounted to $15.6 million and was allocated pro-rata to our General Partner and existing limited partners' interest based on their ownership interests.

The fair value measurement was based on significant inputs not observable in the market and thus represents a Level 3 measurement as defined by ASC 820. Primarily using the income approach, the fair value estimate was based on i) present value of estimated future contracted distributions, ii) an assumed discount rate of 18.0%, and iii) an assumed distribution growth rate of 1.0% in 2014 and thereafter.

The fair value of the additional Series A Units in an amount equal to the cash portion of the distribution was $19.67 per unit, or a total distribution of $13.2 million for the year ended December 31, 2014. Primarily using the market and income approach, the fair value estimate was based on i) present value of estimated future contracted distributions, ii) an option value of $3.32 per unit using a Black-Scholes model, iii) an assumed discount rate of 10.0%, and iv) an assumed distribution growth rate of 1.0% in 2014 and thereafter.

The contribution was treated as a transaction between entities under common control, under which the net assets received are recorded at their historical book value as of date of transfer. The following table presents the carrying value of the identified assets received and liabilities assumed at the acquisition date (in thousands):
Cash and cash equivalents
$
1,935

Accounts receivable
3,629

Unbilled revenue
1,446

Other current assets
2,049

Property, plant and equipment, net
82,615

Other assets
1,000

Accounts payable
(11
)
Accrued expenses and other current liabilities
(4,077
)
Current portion of long-term debt
(893
)
Asset retirement obligation liability
(25,763
)
Total identifiable net assets
$
61,930



Subsequent to the contribution, for the year ended December 31, 2013, the High Point System contributed $30.4 million of revenue and $7.2 million of net income attributable to the Partnership's Transmission segment, which are included in the consolidated statement of operations.

Chatom Gathering, Processing and Fractionation Plant

Effective July 1, 2012, we acquired an 87.4% undivided interest in the Chatom system from affiliates of Quantum Resources Management, LLC. The acquisition fair value consideration of $51.4 million includes a credit associated with the cash flow the Chatom system generated between January 1, 2012, and the effective date of July 1, 2012. The consideration paid by the Partnership consisted of cash, which was funded under borrowings under our revolving credit facility.

The Chatom system is located in Washington County, Alabama, approximately 15 miles from our Bazor Ridge processing plant in Wayne County, Mississippi, and consists of a 25 MMcf/d cryogenic processing plant, a 1,900 Bbl/d fractionation unit, a 160 long-ton per day sulfur recovery unit, and a 24 mile gas gathering system. We believe the fractionating services provide flexibility to the Partnership's product and service offerings.

The following table presents the fair value of consideration transferred to acquire the Chatom system and the amounts of identified assets acquired and liabilities assumed at the acquisition date, as well as the fair value of the 12.6% noncontrolling interest in the Chatom system at the acquisition date (in thousands):
Cash consideration:
$
51,377

Recognized amounts of identifiable assets acquired and liabilities assumed:
 
Unbilled revenue
$
4,535

Property, plant and equipment
58,279

Asset retirement cost
452

Accounts payable
(399
)
Accrued gas purchases
(3,631
)
Asset retirement obligations
(452
)
Noncontrolling interest
(7,407
)
Total identifiable net assets:
$
51,377



The fair value of the property, plant and equipment and noncontrolling interests were estimated by applying a combination of the market and income approaches. These fair value measurements are based on significant inputs not observable in the market and thus represent a Level 3 measurement as defined by ASC 820. Primarily using the income approach, the fair value estimates are based on i) an assumed cost of capital of 9.25%, ii) an assumed terminal value based on the present value of estimated EBITDA, iii) an inflationary cost increase of 2.5%, iv) forward market prices as of July 2012 for natural gas and crude oil, v) a Federal tax rate of 35% and a state tax rate of 6.5%, and vi) an increase in processed and fractionated volumes in 2013, declining thereafter. Working capital was estimated using net realizable value. Accrued revenue was deemed to be fully collectible at July 1, 2012.

During the fourth quarter of 2013 we offered to purchase the noncontrolling interest in Chatom from all holders of the noncontrolling interest. As of December 31, 2013, 38% of the noncontrolling interest was purchased by us (a 4.8% overall interest), increasing our total ownership to 92.2% and reducing the noncontrolling interest to 7.8%.

Subsequent to the initial 87.4% acquisition, our undivided interest in the Chatom system contributed $25.4 million of revenue and $1.8 million of net income attributable to the Partnership, which are included in the consolidated statement of operations for the year ended December 31, 2012.

Madison Divestiture

On March 31, 2014, the Partnership completed the sale of certain gathering and processing assets in Madison County, Texas. We received $6.1 million in cash proceeds related to the sale. The Partnership recognized a $3.0 million impairment charge related to these assets for the year ended December 31, 2013, which wrote down the assets to a carrying value of $6.1 million as of December 31, 2013.
Recent Accounting Pronouncements (Notes)
Significant Accounting Policies [Text Block]
Recent Accounting Pronouncements

In April 2014, the FASB issued ASU No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. This guidance amends the requirements for reporting discontinued operations and requires expanded disclosures for individually significant components of an entity that either have been disposed of or are classified as held for sale, but do not qualify for discontinued operations reporting. Only those disposals of components of an entity that represent a strategic shift that has (or will have) a major effect on an entity's operations and financial results will be reported as discontinued operations in the financial statements. ASU 2014-08 is effective for annual periods, and interim periods within those years, beginning on or after December 15, 2014 and is applied prospectively. Early adoption is permitted, but only for disposals or classifications as held for sale that have not been reported in financial statements previously issued or available for issuance. The update was early adopted by the Partnership as of April 1, 2014 and did not have a material impact on its consolidated financial statements.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), which amends the existing accounting standards for revenue recognition. The standard 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. The guidance in ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods therein. Early adoption is not permitted. The Partnership is currently evaluating the method of adoption and impact this standard will have on its financial statements and related disclosures.

In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements-Going Concern (Topic 205-40): Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern. This guidance provides additional information to guide management's evaluation of whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity's ability to continue as a going concern within one year after the date that the financial statements are issued. The update is effective for annual periods beginning on or after December 15, 2016. The Partnership has evaluated the impact of this standard on its financial statements and determined it will not have a material impact.
Discontinued Operations (Notes)
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]
Discontinued Operations

During 2013, the board of directors of our General Partner approved a plan to sell certain non-strategic gathering and processing assets which meet specific criteria, qualifying them as held for sale. During the year ended December 31, 2013, certain gathering and processing assets were written down by $1.8 million to the estimated fair value less cost to sell. These fair value measurements are based on significant inputs not observable in the market and thus represent a Level 3 measurement as defined by ASC 820. Primarily using the income approach, the fair value estimates were based on i) present value of estimated EBITDA, ii) an assumed discount rate of 10%, and iii) a decline in throughput volumes of 2.5% in 2013 and thereafter.

During the second quarter of 2014, the Partnership’s management resolved not to sell a portion of the assets that had previously been reclassified to discontinued operations and assets held for sale in the second quarter of 2013. In accordance with ASC 360, the Partnership reclassified the assets as held and used at the carrying value of the assets before they were classified as held for sale, adjusted for depreciation expense that would have been recorded. The Partnership has reclassified the amounts recorded in discontinued operations related to the assets for all prior periods presented, as well as reclassified the assets to held and used on the comparative December 31, 2013 balance sheet.

The Partnership continues to classify the terminal in Salisbury, Maryland as held for sale as we are continuing negotiations for the sale of those assets, contingent upon the purchaser’s completion of funding requirements. The Partnership recognized an additional impairment on these assets of $0.7 million ($0.4 million, net of tax) for the year ended December 31, 2014, due to deteriorating market conditions. The impairment was the result of an analysis of the carrying value of the assets relative to their estimated fair value using a market based approach less costs to sell.

The net book value of the assets and liabilities attributable to the terminal assets are presented separately on the consolidated balance sheet and comprise $0.1 million of Current assets held for sale, $1.2 million of Noncurrent assets held for sale, net, and less than $0.1 million of Current liabilities held for sale as of December 31, 2014.

As a result of the planned divestiture of these non-strategic midstream assets, we have classified these disposal groups as discontinued operations within our consolidated statement of operations. Accordingly, we reclassified and excluded the disposal groups' results of operations from our results of continuing operations and reported the disposal groups' results of operations as Gain (loss) from operations of disposal groups, net of tax in our accompanying consolidated statement of operations for all periods presented. We did not, however, elect to present separately the operating, investing and financing cash flows related to the disposal groups in our accompanying consolidated statement of cash flows as this activity was immaterial for all periods presented. The following table presents the revenue, expense and (loss) gain from operations of disposal groups associated with the assets classified as held for sale for the years ended December 31, 2014, 2013, and 2012 (in thousands, except per unit amounts):

 
Year Ended December 31,
 
2014
 
2013
 
2012
Revenue
$
474

 
$
2,084

 
$
2,318

Expense
(658
)
 
(2,361
)
 
(2,336
)
Impairment
(673
)
 
(2,400
)
 
—

Loss on sale of assets
(87
)
 
(75
)
 
—

Income tax benefit
333

 
339

 
—

Gain (loss) from operations of disposal groups, net of tax
$
(611
)
 
$
(2,413
)
 
$
(18
)
Limited partners' net income (loss) per unit from discontinued operations (basic and diluted)
$
(0.04
)
 
$
(0.27
)
 
$
—

Concentration of Credit Risk and Trade Accounts Receivable
Concentration Risk Disclosure [Text Block]
Concentration of Credit Risk and Trade Accounts Receivable

Our primary market areas are located in the United States along the Gulf Coast and in the Southeast. We have a concentration of trade receivable balances due from companies engaged in the production, trading, distribution and marketing of natural gas and NGL products. These concentrations of customers may affect our overall credit risk in that the customers may be similarly affected by changes in economic, regulatory or other factors. Our customers' historical financial and operating information is analyzed prior to extending credit. We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees. We maintain allowances for potentially uncollectible accounts receivable; however, for the years ended December 31, 2014, 2013 and 2012, no allowances on or significant write-offs of accounts receivable were recorded.

The following table summarizes the percentage of revenue earned from those customers that exceed 10% of the Partnership's consolidated revenue in the consolidated statement of operations for the each of the years presented below:

 
Year Ended December 31,
 
2014
 
2013
 
2012
Customer A
22
%
 
28
%
 
30
%
Customer B
—
%
 
13
%
 
—
%
Customer C
12
%
 
12
%
 
13
%
Customer D
10
%
 
10
%
 
14
%
Other
56
%
 
37
%
 
43
%
Total
100
%
 
100
%
 
100
%
Other Current Assets
Other Current Assets
Other Current Assets

Other current assets consists of the following (in thousands):
 
December 31,
 
2014
 
2013
Prepaid insurance
$
4,162

 
$
3,166

Restricted cash
6,475

 
—

Other current assets
4,865

 
4,331

 
$
15,502

 
$
7,497



Restricted cash of $6.5 million is a cash-backed letter of credit related to Costar Midstream operations that the Partnership was contractually obligated to maintain after the Costar Acquisition. The Partnership was released of this obligation in January 2015.
Derivatives
Derivatives
Derivatives

Commodity Derivatives

To minimize the effect of commodity prices changes and maintain our cash flow and the economics of our development plans, we enter into commodity hedge contracts from time to time. The terms of the contracts depend on various factors, including management's view of future commodity prices, economics on purchased assets and future financial commitments. This hedging program is designed to mitigate the effect of commodity price declines while allowing us to participate in some commodity price upside. Management regularly monitors the commodity markets and financial commitments to determine if, when, and at what level commodity hedging is appropriate in accordance with policies that are established by the board of directors of our General Partner. Currently, the commodity derivatives are in the form of swaps and collars. As of December 31, 2014, the aggregate notional volume of our commodity derivatives was 0.5 million gallons.

We enter into commodity contracts with multiple counterparties, and in some cases, may be required to post collateral with our counterparties in connection with our derivative positions. As of December 31, 2014, we have not posted collateral with our counterparties. The counterparties are not required to post collateral with us in connection with their derivative positions. Netting agreements are in place that permit us to offset our commodity derivative asset and liability positions with our counterparties .

We did not designate any of our commodity derivatives as hedges for accounting purposes. As a result, our commodity derivatives are accounted for at fair value in our consolidated balance sheets with changes in fair value recognized currently in earnings.

Interest Rate Swap

We entered into an interest rate swap to manage the impact of the interest rate risk associated with our credit facility, effectively converting a portion of the cash flows related to our long-term variable rate debt into fixed rate cash flows. As of December 31, 2014, the notional amount of our interest rate swap was $100.0 million. The interest rate swap was entered into with a single counterparty and we were not required to post collateral. The interest rate swap will expire August 1, 2015.

Weather Derivative

In the second quarter of 2014 and 2013, we entered into weather derivatives to mitigate the impact of potential unfavorable weather to our operations under which we could receive payments totaling up to $10.0 million in the event that a hurricane or hurricanes of certain strength pass through the area as identified in the derivative agreement. The weather derivatives are accounted for using the intrinsic value method, under which the fair value of the contract was zero and any amounts received are recognized as gains during the period received. The weather derivatives were entered into with a single counterparty and we were not required to post collateral.

We paid premiums of $1.0 million and $1.1 million in 2014 and 2013, respectively, which are recorded as current Risk management assets on the consolidated balance sheet and are amortized to Direct operating expenses on a straight-line basis over the term of the contract of 1 year. Unamortized amounts associated with weather derivatives were approximately $0.4 million and $0.5 million as of December 31, 2014 and 2013, respectively.

As of December 31, 2014 and 2013, the value associated with our commodity derivatives, interest rate swap and weather derivative were recorded in our consolidated balance sheets, under the captions as follows (in thousands):
 
 
Gross Risk Management Assets
 
Gross Risk Management Liabilities
 
Net Risk Management Assets (Liabilities)
Balance Sheet Classification
 
December 31, 2014
 
December 31, 2013
 
December 31, 2014
 
December 31, 2013
 
December 31, 2014
 
December 31, 2013
Current
 
$
688

 
$
473

 
$
—

 
$
—

 
$
688

 
$
473

Noncurrent
 
—

 
—

 
—

 
—

 
—

 
—

Total assets
 
$
688

 
$
473

 
$
—

 
$
—

 
$
688

 
$
473

 
 
 
 
 
 
 
 
 
 
 
 
 
Current
 
$
—

 
$
27

 
$
(215
)
 
$
(450
)
 
$
(215
)
 
$
(423
)
Noncurrent
 
—

 
—

 
—

 
(101
)
 
—

 
(101
)
Total liabilities
 
$
—

 
$
27

 
$
(215
)
 
$
(551
)
 
$
(215
)
 
$
(524
)

For the years ended December 31, 2014, 2013 and 2012, the realized and unrealized gains (losses) associated with our commodity, interest rate and weather derivative instruments were recorded in our consolidated statements of operations, under the captions as follows (in thousands):
 
 
Realized
 
Unrealized
2014
 

Gain (loss) on commodity derivatives, net
 
$
735

 
$
356

Interest expense
 
(433
)
 
239

Direct operating expenses
 
(1,035
)
 
—

Total
 
$
(733
)
 
$
595

2013
 
 
 
 
Gain (loss) on commodity derivatives, net
 
$
1,069

 
$
(1,041
)
Interest expense
 
(207
)
 
(454
)
Direct operating expenses
 
(662
)
 
—

Total
 
$
200

 
$
(1,495
)
2012
 
 
 
 
Gain (loss) on commodity derivatives, net
 
$
2,408

 
$
992

Total
 
$
2,408

 
$
992

Fair Value Measurement
Fair Value Measurement
Fair Value Measurement

We believe the carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximate fair value because of the short-term maturity of these instruments.

The recorded value of the amounts outstanding under the credit facility approximates its fair value, as interest rates are variable, based on prevailing market rates and the short-term nature of borrowings and repayments under the credit facility.

The fair value of all derivatives instruments is estimated using a market valuation methodology based upon forward commodity price curves, 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 are obtained from independent pricing services, and we have made no adjustments to the obtained prices.

We have consistently applied these valuation techniques in all periods presented and believe we have obtained the most accurate information available for the types of derivatives contracts held. We will recognize transfers between levels at the end of the reporting period for which the transfer has occurred. There were no such transfers for the years ended December 31, 2014 and 2013.

Fair Value of Financial Instruments

The following table sets forth by level within the fair value hierarchy, our commodity derivative instruments and interest rate swap, included as part of Risk management assets and Risk management liabilities within the consolidated balance sheet, that were measured at fair value on a recurring basis as of December 31, 2014 and 2013 (in thousands):

 
Carrying
Amount
 
Estimated Fair Value of the Asset (Liability)
 
Level 1
 
Level 2
 
Level 3
 
Total
Commodity derivative instruments, net
 
 
 
 
 
 
 
 
 
December 31, 2014
$
286

 
$
—

 
$
286

 
$
—

 
$
286

December 31, 2013
(70
)
 
—

 
(70
)
 
—

 
(70
)
Interest rate swap
 
 
 
 
 
 
 
 
 
December 31, 2014
$
(215
)
 
$
—

 
$
(215
)
 
$
—

 
$
(215
)
December 31, 2013
(454
)
 
—

 
(454
)
 
—

 
(454
)

The unamortized portion of the premium paid to enter the weather derivative described in Note 7 "Derivatives," is included within Risk management assets on the consolidated balance sheet but is not included in the above table as it is recorded at amortized cost, not fair value.
Property, Plant and Equipment, Net
Property, Plant and Equipment, Net
Property, Plant and Equipment, Net

Property, plant and equipment, net, as of December 31, 2014 and 2013, were as follows (in thousands):
 
 
Useful Life
(in years)
 
December 31,
2014
 
December 31,
2013
Land
N/A
 
$
5,282

 
$
6,015

Construction in progress
N/A
 
77,551

 
6,443

Base gas
N/A
 
1,108

 
1,108

Buildings and improvements
4 to 40
 
6,905

 
5,109

Processing and treating plants
8 to 40
 
80,141

 
97,106

Pipelines
5 to 40
 
452,180

 
239,865

Compressors
4 to 20
 
24,227

 
11,955

Dock
20 to 40
 
8,072

 
7,942

Tanks, truck rack and piping
20 to 40
 
30,079

 
22,432

Equipment
8 to 20
 
8,952

 
6,294

Computer software
5
 
3,520

 
3,531

Total property, plant and equipment
 
 
698,017

 
407,800

Accumulated depreciation
 
 
(115,835
)
 
(95,099
)
Property, plant and equipment, net
 
 
$
582,182

 
$
312,701



Of the gross property, plant and equipment balances at December 31, 2014 and 2013, $101.9 million and $100.5 million, respectively, were related to AlaTenn, Midla and High Point Gas Transmission, our FERC regulated interstate and intrastate assets.

Capitalized interest was $0.8 million and $0.2 million for the years ended December 31, 2014 and 2013, respectively.

Depreciation expense was $23.9 million and $25.9 million for the years ended December 31, 2014 and 2013, respectively.

Asset Impairments

2014 Impairments

During the fourth quarter of 2014, management noted the declining commodity markets and related impact on producers and shippers to whom we provide gathering and processing services. The decline in the market price of crude oil has led to a corresponding decrease in oil and natural gas production and is impacting the volume of natural and NGLs we gather and process on certain assets. As a result, an asset impairment charge of $99.9 million was recorded in the three months ended December 31, 2014. These fair value measurements are based on significant inputs not observable in the market and thus represent a Level 3 measurement as defined by ASC 820. Primarily using the income approach, the fair value estimates are based on i) present value of estimated EBITDA, ii) an assumed discount rate of 9.5%, and iii) the expected remaining useful life of the asset or asset group.

The Partnership continues to classify the terminal in Salisbury, Maryland as held for sale as we are continuing negotiations for the sale of those assets, contingent upon the purchaser’s completion of funding requirements. The Partnership recognized an additional impairment on these assets of $0.7 million ($0.4 million, net of tax) for the year ended December 31, 2014, due to deteriorating market conditions. The impairment was the result of an analysis of the carrying value of the assets relative to their estimated fair value using a market based approach less costs to sell.

2013 Impairments

During 2013, management determined to change its commercial approach towards certain non-strategic gathering and processing assets. As a result, an asset impairment charge of $15.2 million was recorded in the three months ended June 30, 2013. These fair value measurements are based on significant inputs not observable in the market and thus represent a Level 3 measurement as defined by ASC 820. Primarily using the income approach, the fair value estimates are based on i) present value of estimated EBITDA, ii) an assumed discount rate of 10%, and iii) a decline in throughput volumes of 2.5% in 2013 and thereafter.

During 2013, the board of directors of our General Partner approved a plan to sell certain non-strategic gathering and processing assets which meet specific criteria, qualifying them as held for sale. As a result, certain gathering and processing assets were written down by $1.8 million to the estimated fair value less cost to sell. As part of the Blackwater Acquisition, we acquired long-lived terminal assets classified as held for sale. As of December 31, 2013, certain long-lived terminal assets were written down by $0.6 million to the estimated fair value less cost to sell. See Note 4 "Discontinued Operations."

During the first quarter of 2014, the board of directors of our General Partner gave approval to the management team to pursue the sale of certain gathering and processing assets for an amount less than the carrying value of the assets. As a result, these gathering and processing assets were written down by $3.0 million in the fourth quarter of 2013.

Insurance proceeds

Involuntary conversions result from the loss of an asset because of some unforeseen event (e.g., destruction due to hurricanes). Some of these events are insurable, thus resulting in a property damage insurance recovery. Amounts we receive from insurance carriers are net of any deductibles related to the covered event. During the year ended December 31, 2013, we collected $1.1 million of nonrefundable cash proceeds from our insurance carrier. During the first quarter of 2013, $0.5 million of nonrefundable cash proceeds were recognized as an offset to property, plant and equipment write-downs of $0.1 million and presented as $0.4 million under the caption Gain (loss) on involuntary conversion of property, plant and equipment. During the second quarter of 2013, $0.6 million of nonrefundable cash proceeds were associated with business interruption insurance and recorded to Revenue in the consolidated statement of operations.
Goodwill and Intangible assets (Notes)
Goodwill and Intangible Assets Disclosure [Text Block]
Goodwill and Intangible Assets, Net

The carrying value of goodwill as of December 31, 2014 and 2013, was $142.2 million and $16.4 million, respectively. Goodwill as of December 31, 2014 consisted of $125.9 million and $16.3 million related to our Gathering and Processing and Terminal Segments, respectively. Goodwill as of December 31, 2013 related entirely to the Terminals Segment.

The goodwill associated with our Gathering and Processing segment relates to the Costar and Lavaca Acquisitions and primarily represent strategic developmental locations to grow the business within the segment. The goodwill associated with our Terminal Segment was contributed to the Partnership as part of the Blackwater Acquisition. Goodwill was recorded as a result of the excess of the investment by an affiliate of HPIP in Blackwater over the fair market value of the identifiable net assets and customer contracts acquired.

Intangible assets, net, consists of customer contracts, relationships and dedicated acreage agreements identified as part of the Costar Acquisition, Lavaca Acquisition and Blackwater Acquisition. These intangible assets have definite lives and are subject to amortization on a straight-line basis over their economic lives, currently ranging from 5 months to thirty years. Intangible assets, net, consist of the following (in thousands):

 
December 31,
 
2014
 
2013
Gross carrying amount:
 
 
 
    Customer contracts
$
12,101

 
$
12,101

    Customer relationships
53,400

 
—

    Dedicated acreage
53,350

 
—

 
$
118,851

 
$
12,101

Accumulated amortization:
 
 
 
    Customer contracts
$
(11,110
)
 
$
(8,419
)
    Customer relationships
(553
)
 
—

    Dedicated acreage
(882
)
 
—

 
$
(12,545
)
 
$
(8,419
)
Net carrying amount:
 
 
 
    Customer contracts
$
991

 
$
3,682

    Customer relationships
52,847

 
—

    Dedicated acreage
52,468

 
—

 
$
106,306

 
$
3,682



For the years ended December 31, 2014 and 2013, amortization expense on our intangible assets totaled $4.1 million and $3.7 million, respectively. Estimated amortization expense for each of the next five fiscal years (2015 – 2019) is approximately $5.3 million, $4.3 million, $4.3 million, $4.3 million and $4.3 million, respectively.
Accrued Expenses and Other Current Liabilities
Accounts Expenses and Other Current Liabilities
Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities were as follows (in thousands):

 
 
December 31,
 
 
2014
 
2013
Accrued capital expenditures
 
$
17,134

 
$
2,562

Accrued expenses
 
7,036

 
5,412

Gas imbalances payable
 
1,069

 
4,305

Other
 
549

 
2,779

 
 
$
25,788

 
$
15,058

Asset Retirement Obligation
Asset Retirement Obligation
Asset Retirement Obligations

The following table is a reconciliation of the asset retirement obligations (in thousands):
 
Year Ended December 31,
 
2014
 
2013
Beginning asset retirement obligation
$
34,636

 
$
8,319

Liabilities assumed
248

 
25,763

Expenditures
(1,030
)
 
—

Accretion expense
791

 
554

Ending asset retirement obligation
$
34,645

 
$
34,636



We are required to establish security against any potential secondary obligations relating to the abandonment of the certain transmission assets that may be imposed on the previous owner by applicable regulatory authorities. As such, we have a restricted cash account that is established, held and maintained by a third party that amounted to $5.0 million and $3.0 million as of December 31, 2014 and 2013, respectively, and is presented in Other assets, net in our consolidated balance sheets.
Debt Obligations
Debt Obligations

Our outstanding borrowings under the credit facility were (in thousands):
 
 
December 31,
 
 
2014
 
2013
Revolving credit facility
 
$
372,950

 
$
130,735

Other debt
 
2,908

 
2,048

Total debt
 
375,858

 
132,783

Less: current portion
 
2,908

 
2,048

Long-term debt
 
$
372,950

 
$
130,735



On September 5, 2014, the Partnership entered into an amended and restated credit agreement (the "Credit Agreement"), which provides for a maximum borrowing equal to $500.0 million, with the ability to further increase the borrowing capacity subject to lender approval. We can elect to have loans under our credit facility 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 (a) the Federal Funds Rate plus 0.50%, (b) 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 (c) 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 maximum commitment fee of 0.50% per annum on the undrawn portion of the revolving loan.

Our obligations under the credit facility are secured by a first mortgage in favor of the lenders in our real property. Advances made under the Credit Agreement are guaranteed on a senior unsecured basis by certain of our subsidiaries (the "Guarantors"). These guarantees are full and unconditional and joint and several among the Guarantors. The terms of the new credit facility include covenants that restrict our ability to make cash distributions and acquisitions in some circumstances. The remaining principal balance of loans and any accrued and unpaid interest will be due and payable in full on the maturity date, September 5, 2019.

The Credit Agreement contains certain financial covenants, including the requirement that our indebtedness not exceed 4.75 times adjusted consolidated EBITDA (except for the current and subsequent two quarters after the consummation of a permitted acquisition, at which time the covenant is increased to 5.25 times adjusted Consolidated EBITDA) and a minimum interest coverage ratio test (not less than 2.50). The Credit Agreement also contains customary representations and warranties (including those relating to organization and authorization, compliance with laws, absence of defaults, material agreements and litigation) and customary events of default (including those relating to monetary defaults, covenant defaults, cross defaults and bankruptcy events).

For the years ended December 31, 2014, 2013 and 2012, the weighted average interest rate on borrowings under our credit facilities was approximately 3.80%, 4.53%, and 4.09%, respectively.

As of December 31, 2014 our consolidated total leverage was 4.44 and our interest coverage ratio was 13.44, which was in compliance with the consolidated total leverage ratio and interest coverage ratio tests in accordance with the financial covenants required in our Credit Agreement. At December 31, 2014 and 2013, letters of credit outstanding under the credit facility were $1.6 million and $4.8 million, respectively. As of December 31, 2014, we had approximately $373.0 million of outstanding borrowings under our $500.0 million credit facility.

Other debt

Other debt represents insurance premium financing in the original amount of $3.3 million bearing interest at 3.95% per annum, which is repayable in equal monthly installments of approximately $0.4 million through the third quarter of 2015.

In connection with our credit facility, we have incurred $10.4 million in cumulative debt issuance costs through December 31, 2014, which are being amortized on a straight-line basis over the term of the credit facility. In connection with the amendment and restatement of our Credit Agreement, discussed above, the Partnership recognized $0.7 million in extinguishment costs during the quarter ended September 30, 2014, which is included in Other expense in our consolidated statement of operations.
Partners' Capital
Partners' Capital
Partners' Capital

Our capital accounts are comprised of approximately 1.3% general partner interest and 98.7% limited partner interests as of December 31, 2014. 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 rights ("IDRs") that are non-voting limited partner interests held by our General Partner.

Series B Units

Effective January 31, 2014, the Partnership created and issued to its General Partner 1,168,225 Series B Units in exchange for cash. The Series B Units participate in distributions of the Partnership along with common units, with such distributions being made in cash distributions or with paid-in-kind Series B Units at the election of the Partnership. The Series B Units are entitled to vote along with common unitholders and such units will automatically convert to common units two years after the issuance date. Proceeds from the issuance of the Series B Units were used to partially fund the Lavaca Acquisition.

During 2014, the Partnership elected to pay the Series B distributions using paid-in-kind Series B Units. The number of paid-in-kind Series B Units is determined by the quotient of: i) the number of Series B Units outstanding at the record date multiplied by the distribution amount declared to common unit holders ("Series B Unit Distribution Amount"), and ii) the Series B Unit Distribution Amount divided by the original issue price of the Series B Units. The Partnership records the paid-in-kind Series B Units at fair value at the time of issuance. The fair value measurement uses our unit price as a significant input in the determination of the fair value and thus represents a Level 2 measurement as defined by ASC 820. For the year ended December 31, 2014, the Partnership issued 86,461 of paid-in-kind Series B Units with a fair value of $2.2 million.

Series A Convertible Preferred Units

On April 15, 2013, the Partnership, our General Partner and AIM Midstream Holdings entered into agreements with HPIP, pursuant to which HPIP i) acquired 90% of our General Partner and all of our subordinated units from AIM Midstream Holdings and ii) contributed certain midstream assets and $15.0 million in cash to us in exchange for 5,142,857 Series A Units issued by the Partnership. Of the cash consideration paid by HPIP, approximately $2.5 million was used to pay certain transaction expenses of HPIP, and the remaining approximately $12.5 million was used to repay borrowings outstanding under the Partnership's former credit facility. As a result of these transactions, which were also consummated on April 15, 2013, HPIP acquired both control of our General Partner and a majority of our outstanding limited partnership interests. On April 15, 2013, our General Partner entered into the Third Amended & Restated Agreement of Limited Partnership (the "Amended Partnership Agreement") of the Partnership providing for the creation and designation of the rights, preferences, terms and conditions of the Series A Units.

The Series A Units receive distributions prior to distributions to Partnership common unitholders. Through October 1, 2014, the distributions to the Series A Unitholders were equal to $0.25 in cash per unit and additional Series A Units in an amount equal to the cash portion of the distribution. Subsequent to that date, the distribution to each Series A Unit is the greater of the distribution to be made on a per unit basis to common unitholders or approximately $0.4125 per unit. The Series A Units may be converted into common units on a one-to-one basis, subject to customary anti-dilutive adjustments, at the option of the unitholders on or any time after January 1, 2014.

Upon any liquidation and winding up of the Partnership or the sale of substantially all of the assets of the Partnership, the holders of Series A Units generally will be entitled to receive, in preference to the holders of any of the Partnership's other securities, an amount equal to the sum of $17.50 multiplied by the number of Series A Units owned by such holders, plus all accrued but unpaid distributions on such Series A Units.

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

•
the sum of $17.50 and all accrued and accumulated but unpaid distributions for each Series A Unit; or
•
an amount equal to the product of:
i) the number of common units into which each Series A Unit is convertible; and
ii) the sum of:
(A) the cash consideration per common unit to be paid to the holders of common units pursuant to the Partnership Event, plus
(B) the fair market value per common unit of the securities or other assets to be distributed to the holders of the common units pursuant to the Partnership Event.

Upon receipt of such a redemption offer from us, each holder of Series A Units may elect to receive such cash amount or a preferred security issued by the person surviving or resulting from such Partnership Event and containing provisions substantially equivalent to the provisions set forth in the Amended Partnership Agreement with respect to the Series A Units without material abridgement.
Except as provided in the Amended Partnership Agreement, the Series A Units have voting rights that are identical to the voting rights of the common units and will vote with the common units as a single class, with each Series A Unit entitled to one vote for each common unit into which such Series A Unit is convertible.

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

The Partnership executed an amendment (the "Amendment") to the Partnership agreement related to its outstanding Series A convertible preferred units ("Series A Units") which became effective July 24, 2014. As a result of the Amendment, distributions on Series A Units will be made with paid-in-kind Series A Units, cash or a combination thereof, at the discretion of the Board of Directors, which began with the distribution for the three months ended June 30, 2014 and will continue through the distribution for the quarter ended March 31, 2015. Prior to the Amendment, the Partnership was required to pay distributions on the Series A Units with a combination of paid-in-kind units and cash. At December 31, 2014, we have accrued $3.2 million for the paid-in-kind Series A Units.

Equity Restructuring

Effective August 9, 2013, we executed an equity restructuring agreement ("Equity Restructuring") with our General Partner and HPIP. As part of the Equity Restructuring, the Partnership's 4,526,066 subordinated units and previous incentive distribution rights (the "former IDRs," all of which were owned by our General Partner, which is controlled by HPIP) were combined into and restructured as a new class of incentive distribution rights (the "new IDRs"). Upon the issuance of the new IDRs, the subordinated units and former IDRs were canceled. The new IDRs were allocated 85.02% to HPIP and 14.98% to our General Partner. The new IDRs entitle the holders of our incentive distribution rights to receive 48% of any quarterly cash distributions from available cash after the Partnership's common unitholders have received the full minimum quarterly distribution ($0.4125 per unit) for each quarter plus any arrearages from prior quarters. On February 5, 2014, further amendments were made as a result of a settlement such that:
 
•
HPIP and AIM Midstream Holdings amended the LLC Amendment to, among other things, amend the Sharing Percentages (as defined therein) such that HPIP's sharing percentage thereafter is 95% and AIM Midstream Holdings's Sharing Percentage is 5%;

•
HPIP transferred all of the 85.02% of our outstanding new IDRs held by HPIP to our General Partner such that our General Partner owns 100% of the outstanding new IDRs; and

•
we issued to AIM Midstream Holdings a warrant to purchase up to 300,000 common units of the Partnership at an exercise price of $0.01 per common unit (the "Warrant"), which Warrant, among other terms, i) is exercisable at any time on or after February 8, 2014 until the tenth anniversary of February 5, 2014, ii) contains cashless exercise provisions and iii) contains customary anti-dilution and other protections. The Warrant was exercised on February 21, 2014.

Equity Offerings

On October 14, 2014, the Partnership acquired Costar Midstream from Energy Spectrum Partners VI LP and Costar Midstream Energy, LLC which was funded, in part, with 6.9 million of limited partner common units issued directly to Energy Spectrum and Costar Midstream Energy LLC, which are subject to customary lock-up provisions.

On July 14, 2014, the Partnership entered into a common unit purchase agreement with certain institutional investors, which was subsequently amended on August 15, 2014, to provide for the sale of 4,622,352 common units representing limited partner interests in the Partnership in a private placement at a price of $25.8075 per common unit (reflecting an adjustment for the Partnership's second quarter distribution of $0.4625 per unit), for cash consideration of $119.3 million.

On January 29, 2014, the Partnership and certain of its affiliates entered into an underwriting agreement (the "Underwriting Agreement") with Barclays Capital Inc. and UBS Securities LLC (the "Underwriters"), providing for the issuance and sale by the Partnership, and the purchase by the Underwriter, of 3,400,000 common units representing limited partner interests in the Partnership at a price to the public of $26.75 per common unit. The Partnership used the net proceeds of $86.9 million to fund a portion of the Lavaca Acquisition.

On December 11, 2013, the Partnership and certain of its affiliates entered into an underwriting agreement (the "Underwriting Agreement") with Barclays Capital Inc. (the "Underwriter"), providing for the issuance and sale by the Partnership, and the purchase by the Underwriter, of 2,568,712 common units representing limited partner interests in the Partnership at a price to the public of $22.47 per common unit. The Partnership used the net proceeds of $54.9 million to fund a portion of the purchase price for the Blackwater Acquisition.

General Partner Units

In connection with the equity offerings discussed above, we received proceeds of $5.7 million from our General Partner as consideration for 206,810 additional notional general partner units.

Outstanding Units

The numbers of units outstanding were as follows (in thousands):
 
December 31,
 
2014
 
2013
 
2012
Series A convertible preferred units
5,745

 
5,279

 
—

Series B convertible units
1,255

 
—

 
—

Limited Partner common units
22,670

 
7,414

 
4,639

Limited Partner subordinated units
—

 
—

 
4,526

General Partner units
392

 
185

 
185



Distributions

We made cash distributions as follows (in thousands):
 
Year Ended December 31,
 
2014
 
2013
 
2012
Series A convertible preferred units
2,658

 
2,375

 
—

Limited Partner common units
22,656

 
8,207

 
7,919

Limited Partner subordinated units
—

 
5,073

 
7,830

General Partner units
333

 
284

 
321

General Partners' incentive distribution rights
2,362

 
181

 
—

 
$
28,009

 
$
16,120

 
$
16,070


At December 31, 2014, we have accrued $3.2 million for the paid-in-kind Series A Units. The distributions will be made in the first quarter of 2015. During the year ended December 31, 2014, we issued 555 thousand Series A PIK Units and 86 thousand Series B PIK Units.
Earnings per Unit
Net Income Loss Per Limited and General Partner Unit [Text Block]
Net Income (Loss) per Limited Partner Unit

Net income (loss) is allocated to the General Partner and the limited partners in accordance with their respective ownership percentages, after giving effect to distributions on Series A preferred convertible units, declared distributions on the Series B Units, limited partner and to the General Partner units, including IDRs. Unvested unit-based payment 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 income per limited partner unit. Basic and diluted net income (loss) per limited partner unit is calculated by dividing limited partners' interest in net income (loss) by the weighted average number of outstanding limited partner units during the period. We determined basic and diluted net income (loss) per limited partner unit as follows, (in thousands, except per unit amounts):

 
Year Ended December 31,
 
2014
 
2013
 
2012
Net income (loss) from continuing operations
$
(97,195
)
 
$
(30,993
)
 
$
(6,234
)
Net income (loss) attributable to noncontrolling interests
214

 
633

 
256

Net income (loss) from continuing operations attributable to the Partnership
(97,409
)
 
(31,626
)
 
(6,490
)
Less:
 
 
 
 
 
Distributions on Series A preferred units
14,492

 
24,117

 
—

Declared distributions on Series B Units
2,220

 
—

 
—

General partner's distributions
2,694

 
464

 
322

General partner's share in undistributed loss
(1,820
)
 
(1,708
)
 
(458
)
Blackwater net loss from continuing operations
—

 
(716
)
 
—

Net income (loss) from continuing operations available to limited Partners
(114,995
)
 
(53,783
)
 
(6,354
)
Net income (loss) from discontinued operations available to Limited Partners
(603
)
 
(2,051
)
 
(18
)
Net income (loss) available to Limited Partners
$
(115,598
)
 
$
(55,834
)
 
$
(6,372
)
 
 
 
 
 
 
Weighted average number of units used in computation of Limited Partners' net income (loss) per unit (basic and diluted)
13,472

 
7,525

 
9,113

 
 
 
 
 
 
Limited Partners' net income (loss) from continuing operations per unit (basic and diluted)
$
(8.54
)
 
$
(7.15
)
 
$
(0.70
)
Limited Partners' net income (loss) from discontinued operations per unit (basic and diluted)
(0.04
)
 
(0.27
)
 
—

Limited Partners' net income (loss) per unit (basic and diluted)
$
(8.58
)
 
$
(7.42
)
 
$
(0.70
)
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 2, 2009, the board of directors of our General Partner adopted a long-term incentive plan for its employees, consultants and directors who perform services for it or its affiliates. On May 25, 2010, the board of directors of our General Partner adopted an amended and restated long-term incentive plan. On July 11, 2012, the board of directors of our General Partner adopted a second amended and restated long-term incentive plan ("LTIP") that effectively increased available awards by 871,750 units. At December 31, 2014, 2013 and 2012, there were 688,976, 855,089 and 920,193 units, respectively, available for future grant under the LTIP.

Ownership in the awards is subject to forfeiture until the vesting date. The LTIP is administered by the board of directors of our General Partner. The board of directors of our General Partner, at its discretion, may elect to settle such vested phantom units with a number of 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. Although other types of awards are contemplated under the LTIP, the only currently outstanding awards are phantom units without distribution equivalent rights ("DERs").

Generally, grants issued under the LTIP vest in increments of 25% on each grant anniversary date and do not contain any vesting requirements other than continued employment.

The following table summarizes our unit-based awards for each of the periods indicated, in units:

 
 
Year Ended December 31, 2014
 
 
Shares
 
Weighted-Average Exercise Price
Outstanding at beginning of period
 
75,529

 
17.62

Granted
 
188,946

 
20.80

Forfeited
 
(12,009
)
 
18.28

Vested
 
(51,334
)
 
20.89

Outstanding at end of period
 
201,132

 
19.73



The fair value of our phantom units, which are subject to equity classification, is based on the fair value of our units at the grant date. Compensation costs related to these awards for the years ended December 31, 2014, 2013, and 2012 was $1.5 million, $2.1 million and $1.8 million, respectively, and are classified as Equity compensation expense in the consolidated statement of operations and the equity based compensation in partners' capital on the consolidated balance sheet.

The total fair value of vesting units at the time of vesting was $1.4 million, $2.2 million, and $1.9 million for the years ended December 31, 2014, 2013, and 2012, respectively.

The total compensation cost related to unvested awards not yet recognized at December 31, 2014, 2013, and 2012 was $3.1 million, $0.9 million, and $1.4 million, respectively, and the weighted average period over which this cost is expected to be recognized as of December 31, 2014, is approximately 3 years.
Post-Employment Benefits
Post-Employment Benefits
Postretirement Benefits

We sponsor a contributory postretirement plan that provides medical, dental and life insurance benefits for qualifying U.S. retired employees (referred to as the "OPEB Plan").

The tables below detail the changes in the benefit obligation, the fair value of the plan assets and the funded status of the OPEB Plan using the accrual method (in thousands):

 
 
Year Ended December 31,
 
 
2014
 
2013
Change in benefit obligation
 
 
 
 
Benefit obligation, beginning of period
 
$
532

 
$
472

Service cost
 
2

 
5

Interest cost
 
24

 
15

Actuarial (gain) loss
 
122

 
(29
)
Plan amendments
 
—

 
126

Benefits paid
 
(25
)
 
(57
)
Benefit obligation, end of period
 
$
655

 
$
532

Change in plan assets
 
 
 
 
Fair value of plan assets, beginning of period
 
$
1,528

 
$
1,552

Actual return on plan assets
 
104

 
(53
)
Employer's contributions
 
90

 
90

Benefits paid
 
(38
)
 
(61
)
Fair value of plan assets, end of period
 
$
1,684

 
$
1,528

Funded status
 
 
 
 
Funded status
 
$
1,029

 
$
996



The funded status of the OPEB plan is included in Other assets in the consolidated balance sheets.

The amounts included in accumulated other comprehensive income (loss) at December 31, 2014, 2013 and 2012 that have not been recognized as components of net periodic benefit expenses are $0.0 million, $(0.1) million, and $(0.1) million, respectively, which relate to net (gains) losses.
 
Components of Net Periodic Benefit Cost and Other amounts Recognized in Other Comprehensive Income (in thousands):
 
 
Year Ended December 31,
 
 
2014
 
2013
 
2012
Net Periodic Benefit Cost
 
 
 
 
 
 
Service cost
 
$
2

 
$
5

 
$
4

Interest cost
 
24

 
15

 
18

Expected return on plan assets
 
(70
)
 
(70
)
 
(67
)
Amortization of prior service cost
 
4

 
—

 
—

Amortization of net (gain) loss
 
(5
)
 
(23
)
 
(43
)
Net periodic benefit cost
 
$
(45
)
 
$
(73
)
 
$
(88
)
Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income
 
 
 
 
 
 
Net (gain) loss
 
$
102

 
$
247

 
$
64

Total recognized in other comprehensive income
 
102

 
247

 
64

Total recognized in net periodic benefit cost and other comprehensive income
 
$
57

 
$
174

 
$
(24
)


The estimated net gain that will be amortized from accumulated other comprehensive income (loss) into net periodic benefit cost over the next fiscal year is less than $0.1 million.

Economic assumptions

The assumptions made in measurement of the projected benefit obligations or assets of the OPEB Plan were as follows:

 
 
Year Ended December 31,
 
 
2014
 
2013
 
Discount rate
 
3.73
%
 
4.57
%
 
Expected return on plan assets
 
2.50
%
 
4.50
%
 
Health care trend rate
 
3.00
%
 
4.50
%
 


A one percent change in the assumed health care trend rate would result in a change of less than $0.1 million in the postretirement benefit obligations.

The above table reflects the expected long-term rates of return on assets of the OPEB Plan on a weighted-average basis. The overall expected rates of return are based on the asset allocation targets with estimates for returns on equity and debt securities based on long-term expectations. We believe this rate approximates the return we will achieve over the long-term on the assets of our plans. Historically, we have used a discount rate that corresponds to one or more high quality corporate bond indices as an estimate of our expected long-term rate of return on plan assets for our OPEB Plan assets. For 2014, 2013 and 2012 we selected the discount rate using the Citigroup Pension Discount Curve, or CPDC. The CPDC spot rates represent the equivalent yield on high-quality, zero-coupon bonds for specific maturities. These rates are used to develop a single, equivalent discount rate based on the OPEB Plan's expected future cash flows.

Expected future benefit payments

The following table presents the benefits expected to be paid in each of the next five fiscal years, and in the aggregate for the five years thereafter by the OPEB Plan (in thousands):
For the year ending
 
2015
$
33.0

2016
32.0

2017
32.0

2018
32.0

2019
31.0

Five years thereafter
194.0



The expected future benefit payments are based upon the same assumptions used to measure the projected benefit obligations of the OPEB Plan, including benefits associated with future employee service.

Future contributions to the Plans

We expect to make contributions of $0.1 million to the OPEB Plan for the year ending December 31, 2015.
 
Plan assets

The weighted average asset allocation of our OPEB Plan at the measurement date by asset category, which are all classified as Level 1 investments, are as follows:
 
 
December 31,
 
 
2014
 
2013
 
2012
Fixed income (a)
 
70.0
%
 
70.1
%
 
72.2
%
Other (b)
 
30.0
%
 
29.9
%
 
27.8
%
Total
 
100.0
%
 
100.0
%
 
100.0
%
 
(a)
United States government securities, municipal corporate bonds and notes and asset backed securities
(b)
Cash and securities with maturities of one year or less
Income Tax (Notes)
Income Tax Disclosure [Text Block]
 Income Taxes

The Partnership is not a taxable entity for U.S. federal income tax purposes or for the majority of states that impose an income tax. Taxes on our net income generally are borne by our unitholders through the allocation of taxable income. The State of Texas imposes a margin tax that is assessed at 0.95%, 0.975% and 1% of taxable margin apportioned to Texas for each of the three years in the period ended December 31, 2014, respectively. Effective December 17, 2013, we acquired Blackwater Midstream Holdings, LLC, an entity that owns a taxable C Corporation consolidated return group.

For its taxable operations, the Partnership follows the provisions of ASC 740 "Accounting For Income Taxes," which provides for recognition of deferred tax assets and liabilities for deductible temporary timing differences, net operating loss, statutory depletion and tax credit carryforwards, net of a valuation allowance for any deferred tax asset which more likely than not, will not be realized in the Partnership's tax return. An analysis of the Partnership's deferred taxes is as follows (in thousands):
 
December 31, 2014
 
December 31, 2013
Deferred tax assets:
 
 
 
    Net operating loss carryforwards
$
4,173

 
$
5,455

    Other
213

 
182

    Total deferred tax assets
4,386

 
5,637

Deferred tax liabilities:
 
 
 
    Property, plant and equipment
9,112

 
9,022

    Intangible assets
387

 
1,364

    Total deferred tax liabilities
9,499

 
10,386

Deferred income tax liability, net
$
(5,113
)
 
$
(4,749
)


These amounts reflect the classification and presentation that is reported for each tax jurisdiction in which we operate.

Net deferred income tax assets and liabilities consist of (in thousands):
 
December 31, 2014
 
December 31, 2013
Current deferred tax asset
$
3,086

 
$
—

Deferred tax liability, net
(8,199
)
 
(4,749
)
 
$
(5,113
)
 
$
(4,749
)


As of December 31, 2014, we had approximately $10.7 million of operating loss carryforwards which begin to expire in 2028. Some of our net operating losses may be limited by section 382 of the Internal Revenue Code due to the change in control that occurred in December 2013 and another change in control that occurred in October 2012.

The preparation of our income tax returns requires the use of management's estimates and interpretations which may be subjected to review by the respective taxing authorities and may result in an assessment of additional taxes, penalties and interest. We will account for interest and penalties relating to uncertain tax provisions in the current period statement of operations, as necessary. Tax years 2009 through 2013 remain subject to examination by various federal and state tax jurisdictions, as applicable. During the third quarter of 2014, the Internal Revenue Service commenced an audit of the Partnership's 2012 U.S. federal partnership tax return which remains open to examination.

We must recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based not only on the technical merits of the tax position based on tax law, but also on the past administrative practices and precedents of the taxing authority. As of December 31, 2014, we have not recognized tax benefits from uncertain tax positions.

The provision for income taxes is attributable to the activities of the taxable C-Corporation consolidated return group and taxable margin apportioned to Texas. The details of the provision for taxes on income for the year ended December 31, 2014, are as follows (in thousands):

 
Year Ended December 31,
 
2014
 
2013
Net loss before income tax benefit (expense)
$
(96,638
)
 
$
(31,488
)
US Federal statutory tax rate
34
%
 
34
%
Federal income tax benefit at statutory rate
32,857

 
10,706

Reconciling items:
 
 
 
    Partnership loss not subject to income tax
(33,216
)
 
(10,296
)
    Income not subject to corporate-level tax
—

 
222

    State and local tax benefit (expense)
(159
)
 
71

Adjustments related to prior years
(37
)
 
(175
)
    Other
(2
)
 
(33
)
Income tax benefit (expense)
$
(557
)
 
$
495



The income tax provision related to continuing operations consist of the following (in thousands):
 
Year Ended December 31,
 
2014
 
2013
Current income tax benefit (expense)
$
(10
)
 
$
—

Deferred income tax benefit (expense)
(547
)
 
495

 
 
 
 
Effective income tax rate
0.6
%
 
1.6
%


Our effective tax rate differs from the statutory rates, primarily due to being structured as a master limited partnership, which is a pass-through entity for federal income tax purposes, while being treated as a taxable entity in certain states.
Commitments and Contingencies
Commitments and Contingencies
Commitments and Contingencies

Legal proceedings

Equity restructuring

On September 5, 2013, HPIP, our General Partner and the Partnership were named as defendants in an action filed by AIM challenging the Equity Restructuring. AIM Midstream Holdings, LLC v. High Point Infrastructure Partners, LLC, American Midstream GP, LLC and American Midstream Partners, LP (Civil Action No. 8803-VCP) was filed in the Court of Chancery of the State of Delaware. Among claims against the other parties to the litigation, the action asserts a claim of tortious interference with contract against the Partnership and sought either rescission of the Partnership's equity restructuring agreement executed on August 9, 2013 or, in the alternative, monetary damages.

On February 5, 2014, we, HPIP and our General Partner entered into a settlement (the "Settlement") with AIM Midstream Holdings regarding the action filed in Delaware Chancery Court by AIM Midstream Holdings. Under the Settlement, among other things:

•
HPIP and AIM Midstream Holdings amended the LLC Amendment to, among other things, amend the Sharing Percentages (as defined therein) such that HPIP's sharing percentage thereafter is 95% and AIM Midstream Holdings's Sharing Percentage is 5%;
•
HPIP transferred all of the 85.02% of our outstanding new IDRs held by HPIP to our General Partner such that our General Partner owns 100% of the outstanding new IDRs; and
•
We issued to AIM Midstream Holdings a warrant to purchase up to 300,000 common units of the Partnership at an exercise price of $0.01 per common unit, which Warrant, among other terms, i) was exercisable at any time on or after February 8, 2014 until the tenth anniversary of February 5, 2014, ii) contained cashless exercise provisions and iii) contains customary anti-dilution and other protections. The Warrant was exercised on February 21, 2014.

Gloria System Matter

We were named in a lawsuit in the District Court of Jefferson Parish, Louisiana related to right of way maintenance and damages on our Louisiana Intrastate (Gloria) pipeline system related to a servitude agreement entered into by a predecessor in 1956. The landowner had sued us claiming that we have failed to maintain the pipeline right-of-way, allegedly causing erosion of the pipeline canal, erosion of levees, and deterioration of the adjacent marshland. The landowner sought damages for the cost to narrow the pipeline canal, rebuild the pipeline levees, and restore the damaged marsh.

Following negotiations, we entered into an agreement with the landowner during the fourth quarter of 2014 for the procurement of additional pipeline right-of-way and permits in order to rebuild sections of the levees and dams which will provide additional protection to portions of our Gloria System. We expect to incur up to $1.0 million of capital expenditures over the next twelve months in connection with this rebuilding.

Environmental matters

We are subject to federal and state laws and regulations relating to the protection of the environment. Environmental risk is inherent to natural gas pipeline, NGL and crude pipelines and operations, as well as terminal 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, the Partnership reached an agreement in principle with customers regarding its Midla interstate pipeline that traverses Louisiana and Mississippi. The parties involved reached the agreement in principle in order to provide continued service to Midla's customers while addressing safety concerns with the existing pipeline.

Midla and the parties agreed that Midla may retire the existing 1920s vintage pipeline and replace the existing natural gas service with a new pipeline from Winnsboro, Louisiana to Natchez, Mississippi (the "Natchez Line") to serve existing residential, commercial, and industrial customers. Customers not served by the new Natchez Line will be connected to other interstate or intrastate pipelines, other gas distribution systems, or offered conversion to propane service. The agreement is subject to final agreements and ongoing proceedings at the FERC.

Under the agreement in principle and subject to FERC approval, Midla will execute long-term agreements to recover its investment in the new Natchez Line.

Commitments and contractual obligations

Future non-cancelable commitments related to certain contractual obligations as of December 31, 2014, are presented below (in thousands):
 
 
Operating leases and service contracts
 
Asset Retirement Obligation
 
Total
2015
 
$
3,428

 
$
—

 
$
3,428

2016
 
2,204

 
6,884

 
9,088

2017
 
1,421

 
—

 
1,421

2018
 
1,306

 
—

 
1,306

2019
 
1,525

 
—

 
1,525

Thereafter
 
2,945

 
27,761

 
30,706

 
 
$
12,829

 
$
34,645

 
$
47,474



For the years ended December 31, 2014, 2013 and 2012, total expenses related to operating leases, land site leases and right-of-way agreements were $5.8 million, $1.1 million, and $0.9 million, respectively.
Related-Party Transactions
Related-Party Transactions
Related-Party Transactions

Employees of our General Partner are assigned to work for us. Where directly attributable, the costs of all compensation, benefits expenses and employer expenses for these employees are charged directly by our General Partner to American Midstream, LLC, which, in turn, charges the appropriate subsidiary. Our General Partner does not record any profit or margin for the administrative and operational services charged to us. During the years ended December 31, 2014, 2013, and 2012, administrative and operational services expenses of $23.5 million, $14.2 million and $12.5 million, respectively, were charged to us by our General Partner. For the year ended December 31, 2014, 2013 and 2012, our General Partner incurred approximately $1.2 million, $1.8 million and $0.4 million of costs associated with certain business development activities, respectively. If the business development activities result in a project that will be pursued and funded by the Partnership, we will reimburse our General Partner for the business development costs related to that project.

During the second quarter of 2014, the Partnership and an affiliate of its General Partner entered into a Management Service Fee arrangement under which the affiliate pays a monthly fee to reimburse the Partnership for administrative expenses incurred on the affiliate's behalf. For the year ended December 31, 2014, the Partnership recognized $0.9 million in management fee income that has been recorded as a reduction to Selling, general and administrative expenses.

The High Point System, along with $15.0 million in cash, was contributed to us by HPIP in exchange for 5,142,857 Series A Units. Of the cash consideration paid by HPIP, approximately $2.5 million was used to pay certain transaction expenses of HPIP, and the remaining approximately $12.5 million was used to repay borrowings outstanding under the Partnership's former credit facility.

In January 2014, in connection with the acquisition of the Lavaca System, the Partnership issued 1,168,225 Series B Units to our General Partner. The net proceeds related to the issuance was $30.0 million.

In connection with the Blackwater Acquisition, our General Partner contributed the net assets of Blackwater which were recorded at their historical book value of $22.7 million for consideration of $63.9 million, of which $27.7 million was accounted for as a cash distribution to the General Partner. The consideration also included 125,500 limited partner units which were accounted for as a non-cash distribution to the General Partner at a fair value of $3.1 million. See Note 3 "Acquisitions" for more information.

On October 9, 2012, Blackwater entered into a Convertible Promissory Note (the "BWHD Note") with ArcLight Energy Partners Fund V, L.P. ("AL Fund V"), in the amount of $20.0 million. AL Fund V is a related party to the Partnership. The BWHD Note was paid off during the fourth quarter of 2013 as part of the Blackwater Acquisition.
Reporting Segments
Reporting Segments
Reporting Segments

Our operations are located in the United States and are organized into three reporting segments: i) Gathering and Processing, ii) Transmission and iii) Terminals.

Gathering and Processing

Our Gathering and Processing segment provides "wellhead-to-market" services to producers of natural gas and oil, which include transporting raw natural gas from the wellhead through gathering systems, treating the raw natural gas, processing raw natural gas to separate the NGLs and selling or delivering pipeline quality natural gas and NGLs to various markets and pipeline systems.

Transmission

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

Terminals

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

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

 
Year Ended December 31, 2014
 
Gathering
and
Processing
 
Transmission
 
Terminals
 
Total
Revenue
$
203,616

 
$
88,189

 
$
15,504

 
$
307,309

Gain (loss) on commodity derivatives, net
1,091

 
—

 
—

 
1,091

Total revenue
204,707

 
88,189

 
15,504

 
308,400

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

 
45,262

 
—

 
197,952

Direct operating expenses
23,783

 
15,577

 
6,342

 
45,702

Selling, general and administrative expenses
 
 
 
 
 
 
23,103

Equity compensation expense
 
 
 
 
 
 
1,536

Depreciation, amortization and accretion expense
 
 
 
 
 
 
28,832

Total operating expenses
 
 
 
 
 
 
297,125

Gain (loss) on sale of assets, net
 
 
 
 
 
 
(122
)
Loss on impairment of property, plant and equipment
 
 
 
 
 
 
(99,892
)
Other expense
 
 
 
 
 
 
(670
)
Interest expense
 
 
 
 
 
 
(7,577
)
Earnings in unconsolidated affiliates
 
 
 
 
 
 
348

Income tax benefit (expense)
 
 
 
 
 
 
(557
)
Income (loss) from operations of disposal groups, net of tax
 
 
 
 
 
 
(611
)
Net income (loss)
 
 
 
 
 
 
(97,806
)
Less: Net income (loss) attributable to noncontrolling interests
 
 
 
 
 
 
214

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

 
$
42,828

 
$
9,162

 
$
102,807


 
Year Ended December 31, 2013
 
Gathering
and
Processing
 
Transmission
 
Terminals (a)
 
Total
Revenue
$
205,179

 
$
79,041

 
$
9,831

 
$
294,051

Gain (loss) on commodity derivatives, net
28

 
—

 
—

 
28

Total revenue
205,207

 
79,041

 
9,831

 
294,079

Operating expenses:
 
 
 
 
 
 
 
Purchases of natural gas, NGL's and condensate
168,574

 
46,479

 
—

 
215,053

Direct operating expenses
14,574

 
13,259

 
4,403

 
32,236

Selling, general and administrative expenses
 
 
 
 
 
 
19,079

Equity compensation expense
 
 
 
 
 
 
2,094

Depreciation, amortization and accretion expense
 
 
 
 
 
 
30,002

Total operating expenses
 
 
 
 
 
 
298,464

Gain (loss) on involuntary conversion of property, plant and equipment
 
 
 
 
 
 
343

Loss on impairment of property, plant and equipment
 
 
 
 
 
 
(18,155
)
Interest expense
 
 
 
 
 
 
(9,291
)
Income tax benefit (expense)
 
 
 
 
 
 
495

Income (loss) from operation of disposal groups, net of tax
 
 
 
 
 
 
(2,413
)
Net income (loss)
 
 
 
 
 
 
(33,406
)
Less: Net income (loss) attributable to noncontrolling interests
 
 
 
 
 
 
633

Net income (loss) attributable to the Partnership
 
 
 
 
 
 
$
(34,039
)
 
 
 
 
 
 
 
 
Segment gross margin (b)
$
36,985

 
$
32,408

 
$
5,428

 
$
74,821


 
Year Ended December 31, 2012
 
Gathering
and
Processing
 
Transmission
 
Total
Revenue
$
152,339

 
$
52,529

 
$
204,868

Gain (loss) on commodity derivatives, net
3,400

 
—

 
3,400

Total revenue
155,739

 
52,529

 
208,268

Operating expenses:
 
 
 
 
 
Purchases of natural gas, NGL's and condensate
117,956

 
36,516

 
154,472

Direct operating expenses
12,152

 
5,031

 
17,183

Selling, general and administrative expenses
 
 
 
 
14,309

Equity compensation expense
 
 
 
 
1,783

Depreciation, amortization and accretion expense
 
 
 
 
21,287

Total operating expenses
 
 
 
 
209,034

Gain (loss) on involuntary conversion of property, plant and equipment
 
 
 
 
(1,021
)
Gain (loss) on sale of assets, net
 
 
 
 
123

Interest expense
 
 
 
 
(4,570
)
Income (loss) from operations of disposal groups
 
 
 
 
(18
)
Net income (loss)
 
 
 
 
(6,252
)
Less: Net income (loss) attributable to noncontrolling interests
 
 
 
 
256

Net income (loss) attributable to the Partnership
 
 
 
 
$
(6,508
)
 
 
 
 
 
 
Segment gross margin (b)
$
36,118

 
$
13,313

 
$
49,431


 
December 31,
 
2014
 
2013
Segment assets:
 
 
 
Gathering and Processing
686,395

 
178,869

Transmission
132,767

 
131,136

Terminals
71,180

 
60,873

Other (c)
26,302

 
11,197

Total assets
916,644

 
382,075


(a)
Terminals segment amounts are for the period from April 15, 2013 to December 31, 2013.
(b)
Segment gross margin for our Gathering and Processing segment consists of revenue less purchases of natural gas, NGLs and condensate and COMA. Segment gross margin for our Transmission segment consists of revenue, less purchases of natural gas and COMA. Segment gross margin for our Terminals segment consists of revenue, less direct operating expenses. Gross margin consists of the sum of the segment gross margin amounts for each of these segments. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow from operations as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner. Effective October 1, 2012, we changed our segment gross margin measure to exclude construction, operating and maintenance agreement ("COMA") income. Effective January 1, 2011, we changed our segment gross margin measure to exclude unrealized non-cash mark-to-market adjustments related to our commodity derivatives. Effective April 1, 2011, we changed our segment gross margin measure to exclude realized early termination costs on commodity derivatives.
(c)
Other assets not allocable to segments consist of investment in unconsolidated affiliate, corporate leasehold improvements, and other assets.

For a definition of gross margin and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP and a discussion of how we use gross margin to evaluate our operating performance, please read Item 7. "Management's Discussion and Analysis, How We Evaluate Our Operations."

The following table summarizes the percentage of revenue earned from those customers in each segment that exceed 10% of the Partnership's consolidated segment's revenue for the each of the periods presented below:

 
Year Ended December 31,
 
2014
 
2013
 
2012
Gathering and Processing:
 
 
 
 
 
Customer A
33
%
 
43
%
 
40
%
Customer B
12
%
 
19
%
 
11
%
Customer D
—

 
—
%
 
12
%
Other
55
%
 
38
%
 
37
%
Total
100
%
 
100
%
 
100
%
Transmission:
 
 
 
 
 
Customer C
43
%
 
39
%
 
50
%
Customer D
16
%
 
16
%
 
22
%
Customer E
—

 
—
%
 
10
%
Other
41
%
 
45
%
 
18
%
Total
100
%
 
100
%
 
100
%
Terminals:
 
 
 
 
 
Customer F
19
%
 
20
%
 
N/A

Customer B
20
%
 
17
%
 
N/A

Customer G
15
%
 
16
%
 
N/A

Customer H
11
%
 
13
%
 
N/A

Other
35
%
 
34
%
 
N/A

Total
100
%
 
100
%
 
—

Quarterly Financial Data (Notes)
Quarterly Financial Information [Text Block]
Quarterly Financial Data (Unaudited)

Summarized unaudited quarterly financial data for 2014 and 2013 are as follows (in thousands, except per unit amounts):
 
 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter (b)
Year Ended December 31, 2014
 
 
 
 
 
 
 
Total revenues
$
80,238

 
$
77,680

 
$
70,305

 
$
80,177

Gross margin (a)
23,081

 
22,167

 
21,332

 
36,227

Operating income (loss)
2,450

 
734

 
(290
)
 
(91,633
)
Net income (loss) from continuing operations
558

 
(1,095
)
 
(2,397
)
 
(94,261
)
Income (loss) from operations of disposal groups
(50
)
 
(506
)
 
(26
)
 
(29
)
Net income (loss) attributable to noncontrolling interest
108

 
66

 
33

 
7

Net income (loss) attributable to the Partnership
400

 
(1,667
)
 
(2,456
)
 
(94,297
)
General Partner's Interest in net income (loss)
7

 
(22
)
 
(32
)
 
(1,232
)
Limited Partners' Interest in net income (loss)
$
393

 
$
(1,645
)
 
$
(2,424
)
 
$
(93,065
)
 
 
 
 
 
 
 
 
Limited Partners' income (loss) per unit:
 
 
 
 
 
 
 
Income (loss) from continuing operations
$
(0.31
)
 
$
(0.55
)
 
$
(0.58
)
 
$
(4.98
)
Income (loss) from discontinued operations
(0.01
)
 
(0.04
)
 
—

 
—

Net income (loss)
$
(0.32
)
 
$
(0.59
)
 
$
(0.58
)
 
$
(4.98
)
Year Ended December 31, 2013
 
 
 
 
 
 
 
Total revenues
$
62,599

 
$
77,191

 
$
77,519

 
$
76,770

Gross margin (a)
12,705

 
18,317

 
20,908

 
22,891

Operating income (loss)
(1,661
)
 
(17,841
)
 
(104
)
 
(2,591
)
Net income (loss) from continuing operations
(3,392
)
 
(20,057
)
 
(2,526
)
 
(5,018
)
Income (loss) from operations of disposal groups
(6
)
 
(1,869
)
 
(15
)
 
(523
)
Net income (loss) attributable to noncontrolling interest
155

 
188

 
190

 
100

Net income (loss) attributable to the Partnership
(3,553
)
 
(22,114
)
 
(2,731
)
 
(5,641
)
General Partner's Interest in net income (loss)
(70
)
 
(905
)
 
(221
)
 
(209
)
Limited Partners' Interest in net income (loss)
$
(3,482
)
 
$
(21,209
)
 
$
(2,510
)
 
$
(5,433
)
 
 
 
 
 
 
 
 
Limited Partners' income (loss) per unit:
 
 
 
 
 
 
 
Income (loss) from continuing operations
$
(0.39
)
 
$
(4.01
)
 
$
(0.81
)
 
$
(1.43
)
Income (loss) from discontinued operations
0.01

 
(0.20
)
 
0.01

 
—

Net income (loss)
$
(0.38
)
 
$
(4.21
)
 
$
(0.80
)
 
$
(1.43
)
 
(a)
For a definition of gross margin and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP and a discussion of how we use gross margin to evaluate our operating performance, please read Item 7. "Management's Discussion and Analysis, How We Evaluate Our Operations."
(b)
The Partnership record an immaterial out-of-period adjustment in the fourth quarter of 2014 to account for the items associated with the material weakness described in Item 9A.  Management’s Annual Report over Internal Control over Financial Reporting.
Subsequent Events
Subsequent Events
Subsequent Events

Distribution

On January 22, 2015, we announced that the board of directors of our General Partner declared a quarterly cash distribution of $0.4725 per unit for the fourth quarter ended December 31, 2014, or $1.89 per unit on an annualized basis. The cash distribution was paid on February 13, 2015, to unitholders of record as of the close of business on February 6, 2015, together with our General Partner.
Organization and Basis of Presentation (Policies)
Nature of business 

American Midstream Partners, LP (the "Partnership"), was formed on August 20, 2009 as a Delaware limited partnership for the purpose of operating, developing and acquiring a diversified portfolio of midstream energy assets. The Partnership's general partner, American Midstream GP, LLC (the "General Partner"), is 95% owned by High Point Infrastructure Partners, LLC ("HPIP") and 5% owned by AIM Midstream Holdings, LLC. We hold our assets in a series of wholly owned limited liability companies, a limited partnership and a corporation. Our capital accounts consist of notional general partner units and limited partner interests.

Nature of business

We are engaged in the business of gathering, treating, processing, and transporting natural gas, fractionating NGLs and storing specialty chemical products through our ownership and operation of twelve gathering systems, five processing facilities, three fractionation facilities, four marine terminal sites, three interstate pipelines and five intrastate pipelines. We also own a 66.7% non-operating interest in Main Pass Oil Gathering, LP ("MPOG"), a crude oil gathering and processing system, as well as a 50% undivided, non-operating interest in the Burns Point Plant, a natural gas processing plant. Our primary assets, which are strategically located in Alabama, Georgia, Louisiana, Maryland, Mississippi, North Dakota, Tennessee and Texas, provide critical infrastructure that links producer of natural gas, NGLs, condensate and specialty chemicals to numerous intermediate and end-use markets. We currently operate more than 3,000 miles of pipelines that gather and transport over 1 Bcf/d of natural gas and operate approximately 1.7 million barrels of storage capacity across four marine terminal sites.

Basis of presentation 
Basis of presentation

The accompanying financial statements and related notes present our consolidated financial position as of December 31, 2014 and 2013, and results of operations, comprehensive income, changes in partners' capital and noncontrolling interest, and cash flows for the years ended December 31, 2014, 2013 and 2012.

We have prepared the consolidated financial statements in accordance with accounting principles generally accepted in the United States of America ("GAAP"). We have made reclassifications to amounts reported in prior period consolidated financial statements to conform with current year presentation. These reclassifications did not have an impact on net income for the period previously reported.

The financial results for the years ended December 31, 2013 and 2012 have been reclassified to present an asset group previously presented as held for sale as held and used.

The results of operations for acquisitions accounted for as business combinations have been included in the consolidated financial statements since their respective acquisition dates.
Transactions Between Entities Under Common Control 
Transactions Between Entities Under Common Control
 
We may enter into transactions with our General Partner and affiliates whereby we receive a contribution of midstream assets or subsidiaries in exchange for consideration from the Partnership. We account for the net assets received using the historical book value of the asset or subsidiary being contributed or transferred as these are transactions between entities under common control. Our historical financial statements may be revised to include the results attributable to the assets contributed from our General Partner as if we owned such assets for all periods presented by the Partnership since either the change in control of our General Partner, effective April 15, 2013 or later.
Consolidation policy 
Consolidation policy

The accompanying consolidated financial statements include accounts of American Midstream Partners, LP, and its controlled subsidiaries. All significant inter-company accounts and transactions have been eliminated in the preparation of the accompanying consolidated financial statements. We hold a 50% undivided interest in the Burns Point gas processing facility in which we are responsible for our proportionate share of the costs and expenses of the facility. Our consolidated financial statements reflect our proportionate share of the revenues, expenses, assets and liabilities of this undivided interest. In July 2012, the Partnership acquired an 87.4% undivided interest in the Chatom Processing and Fractionation facility (the "Chatom System"). In the fourth quarter of 2013, the Partnership acquired an additional 4.8% undivided interest in the Chatom System. Our consolidated financial statements reflect the accounts of the Chatom System since acquisition. The interests in the Chatom System held by non-affiliated working interest owners are reflected as noncontrolling interests in the Partnership's consolidated financial statements.

The Partnership accounts for its 66.7% non-operated interest in MPOG as an equity method investments under ASC 323, as the Partnership exercises significant influence but does not control nor is the primary beneficiary of MPOG.
Use of estimates 
Use of estimates

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

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.
Allowance for doubtful accounts 
Allowance for doubtful accounts

We establish provisions for losses on accounts receivable when we determine that we will not collect all or part of an outstanding balance. Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. As of December 31, 2014 and 2013, the Partnership recorded no allowances for losses on accounts receivable.
Inventory 
Inventory

Inventory includes natural gas liquids ("NGLs") product inventory. The Partnership records all product inventories at the lower of cost or market with a cost basis determined on a weighted average basis. Product inventories are included within Other current assets on the consolidated balance sheets.
Operational balancing agreements and natural gas imbalances 
Operational balancing agreements and natural gas imbalances

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

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

•
Commodity-based derivatives: "Total revenue"
•
Corporate interest rate derivatives: "Interest expense"

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

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

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

We use various assumptions and methods in estimating the fair values of our financial instruments. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximated their fair value due to the short-term maturity of these instruments. The carrying amount of our various credit facilities approximate fair value, because the interest rates on these facilities are variable.

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

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

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

We capitalize expenditures related to property, plant and equipment that have a useful life greater than one year for assets purchased or constructed; existing assets that are replaced, improved, or the useful lives of which have been extended; and all land, regardless of cost. Maintenance and repair costs, including any planned major maintenance activities, are expensed as incurred.

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

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

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

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

We record the estimated fair value of acquired customer contracts, relationships and dedicated acreage agreements as intangible assets. These intangible assets have definite lives and are subject to amortization on a straight-line basis over their economic lives, currently ranging between 5 months and thirty years.
Deferred financing costs 
Deferred financing costs

Costs incurred in connection with the issuance of long-term debt are deferred and charged to interest expense over the term of the related debt. Gains or losses on debt repurchase and debt extinguishment include any associated unamortized deferred financing costs.
Asset retirement obligations (AROs) 
Asset retirement obligations ("AROs")

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

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

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

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

Noncontrolling interests 
Noncontrolling interests

Noncontrolling interests represent the noncontrolling interest holders' proportionate share of the equity of the respective systems. Noncontrolling interest is adjusted for the noncontrolling interest holders' proportionate share of the earnings or losses. Management reports noncontrolling interest in the Chatom system in the financial statements pursuant to paragraph ASC 810-10-65-1. The 7.8% noncontrolling interest is held by non-affiliated working interest owners
Revenue recognition and the estimation of revenues and cost of purchases 
Revenue recognition and the estimation of revenues and cost of purchases

We recognize revenue 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 record revenue and cost of product sold on a gross basis for those transactions where we act as the principal and take title to natural gas, NGLs or condensates that are purchased for resale. When our customers pay us a fee for providing a service such as gathering, treating, transportation or storage, we record those fees separately in revenues. We have the following arrangements:

Fee-based

Under these arrangements, we generally are paid a fixed fee for gathering and transporting natural gas. Fee-based revenues are recorded when services have been provided, and collectability of the revenue is reasonably assured.

Percent-of-proceeds, or POP

Under these arrangements, we generally gather raw natural gas from producers at the wellhead or other supply points, transport it through our gathering system, process it and sell the residue natural gas and NGLs at market prices. Where we provide processing services at the processing plants that we own, or obtain processing service for our own account under our own elective processing arrangements we typically retain and sell a percentage of the residue natural gas and resulting NGLs. We recognize percent-of-proceeds contract revenue when the natural gas, NGLs or condensate is sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, and collectability of the revenue is reasonably assured.

Fixed-margin

Under these arrangements, we purchase natural gas from producers or suppliers at receipt points on our systems at an index price less a fixed transportation fee and simultaneously sell an identical volume of natural gas at delivery points on our systems at the same, undiscounted index price. We recognize revenue from fixed-margin contracts when the natural gas is sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, and collectability of the revenue is reasonably assured.

Firm transportation

Under arrangements to provide firm transportation service, we are obligated to transport natural gas nominated by the shipper up to the maximum daily quantity specified in the contract. In exchange for that obligation on our part, the shipper pays a specified reservation charge, whether or not they utilize the capacity. In most cases, the shipper also pays a variable-use charge with respect to quantities actually transported by us. Firm transportation revenue is recorded when products are delivered, services have been provided, and collectability of the revenue is reasonably assured.

Interruptible transportation

Under arrangements to provide interruptible transportation service, we are only obligated to transport natural gas nominated by the shipper to the extent we have available capacity. For this service, the shipper pays no reservation charge but pays a variable-use charge for quantities actually shipped. Interruptible transportation revenue is recorded when products are delivered, services have been provided, and collectability of revenue is reasonably assured.

Interest in the Burns Point Plant

We account for our interest in the Burns Point Plant using the proportionate consolidation method. Under this method, we include in our consolidated statement of operations our value of plant revenues taken in-kind and plant expenses reimbursed to the operator.

Terminal revenue and services

Revenues for our terminals include storage tank lease fees, whereby a customer agrees to pay for a certain amount of tank storage over a certain period of time; and throughput fees, whereby a customer pays a fee based on volumes moving through the terminal. At our terminals, we also offer and provide packaging, blending, handling, filtering and certain other ancillary services. Revenue from firm storage contracts is recognized ratably, which is typically monthly, over the term of the lease. Occasionally, customers pay for tank lease fees in advance. Fees received in advance are deferred until the period earned. Revenue from throughput fees and ancillary fees are recognized as services are provided to the customer and collectability is reasonably assured.
Equity-based compensation 
Equity-based compensation

We award equity-based compensation to management, non-management employees and directors in the form of phantom units, which are deemed to be equity awards. Compensation expense on phantom units is measured by the fair value of the award at the date of grant as determined by management. Compensation expense is recognized in Equity compensation expense over the requisite service period of each award.
Income taxes 
Income taxes

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

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

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

Accumulated other comprehensive income (loss) is comprised solely of adjustments related to the Partnership's postretirement benefit plan
Limited partners' net income (loss) per unit 
Limited partners' net income (loss) per unit

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

The two-class method does not impact our overall net income or other financial results; however, in periods in which aggregate net income exceeds our aggregate distributions for such period, it will have the impact of reducing net income per limited partner unit. This result occurs as a larger portion of our aggregate earnings, as if distributed, is allocated to the incentive distribution rights of the General Partner, even though we make distributions on the basis of available cash and not earnings. In periods in which our aggregate net income does not exceed our aggregate distributions for such period, the two-class method does not have any impact on our calculation of earnings per limited partner unit. We have no dilutive securities, therefore basic and diluted net income per unit are the same.
Acquisitions (Tables)
Schedule of business acquisitions 
The following table summarizes the fair value of consideration transferred to acquire Costar and the preliminary allocation of that amount to the assets acquired, liabilities assumed and the noncontrolling interest based upon their respective fair values as of the acquisition date. Such allocation will be finalized once the Partnership negotiates a final settlement of working capital amounts with the sellers with any resulting adjustment being recorded to goodwill.
Fair value of consideration transferred (in thousands):
 
Cash
$
265,383

Limited partner common units
147,296

Total fair value of consideration
$
412,679

Schedule of recognized identified assets acquired and liabilities assumed 
Property, plant and equipment:
 
Land
$
2

Pipelines
58,737

Equipment
753

Total property, plant and equipment
59,492

Intangible assets
21,350

Goodwill
23,567

Total cash consideration
$
104,409

The following table presents the carrying value of the identified assets received and liabilities assumed at the acquisition date (in thousands):
Cash and cash equivalents
$
1,935

Accounts receivable
3,629

Unbilled revenue
1,446

Other current assets
2,049

Property, plant and equipment, net
82,615

Other assets
1,000

Accounts payable
(11
)
Accrued expenses and other current liabilities
(4,077
)
Current portion of long-term debt
(893
)
Asset retirement obligation liability
(25,763
)
Total identifiable net assets
$
61,930

Fair Value of assets acquired, liabilities assumed and noncontrolling interest (in thousands):
 
Working capital
$
8,152

Property, plant and equipment:
 
Processing plants
$
48,357

Pipelines
128,799

Land
1,244

Buildings
682

Equipment
9,827

Construction in progress
16,146

Total property, plant and equipment
205,055

Investment in unconsolidated affiliate
11,884

Intangible assets:
 
Customer relationships
53,400

Dedicated acreage
32,000

Goodwill
102,407

Noncontrolling interest
(219
)
 
$
412,679

The following table presents the fair value of consideration transferred to acquire the Chatom system and the amounts of identified assets acquired and liabilities assumed at the acquisition date, as well as the fair value of the 12.6% noncontrolling interest in the Chatom system at the acquisition date (in thousands):
Cash consideration:
$
51,377

Recognized amounts of identifiable assets acquired and liabilities assumed:
 
Unbilled revenue
$
4,535

Property, plant and equipment
58,279

Asset retirement cost
452

Accounts payable
(399
)
Accrued gas purchases
(3,631
)
Asset retirement obligations
(452
)
Noncontrolling interest
(7,407
)
Total identifiable net assets:
$
51,377

Unaudited pro forma consolidated information of the partnership, adjusted for the acquisition of the Costar assets 
The following unaudited pro forma summary presents consolidated financial information for the Partnership as if the Costar acquisition had occurred on January 1, 2013 (in thousands):
 
Year Ended December 31,
 
2014
 
2013
Revenue
$
435,133

 
$
448,748

Net loss
(101,237
)
 
(30,672
)
Limited partners' net loss per unit
(6.15
)
 
(3.82
)
Discontinued Operations (Tables)
Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures [Table Text Block]
The following table presents the revenue, expense and (loss) gain from operations of disposal groups associated with the assets classified as held for sale for the years ended December 31, 2014, 2013, and 2012 (in thousands, except per unit amounts):

 
Year Ended December 31,
 
2014
 
2013
 
2012
Revenue
$
474

 
$
2,084

 
$
2,318

Expense
(658
)
 
(2,361
)
 
(2,336
)
Impairment
(673
)
 
(2,400
)
 
—

Loss on sale of assets
(87
)
 
(75
)
 
—

Income tax benefit
333

 
339

 
—

Gain (loss) from operations of disposal groups, net of tax
$
(611
)
 
$
(2,413
)
 
$
(18
)
Limited partners' net income (loss) per unit from discontinued operations (basic and diluted)
$
(0.04
)
 
$
(0.27
)
 
$
—

Concentration of Credit Risk and Trade Accounts Receivable (Tables)
Percentage of revenue earned from major customers
The following table summarizes the percentage of revenue earned from those customers that exceed 10% of the Partnership's consolidated revenue in the consolidated statement of operations for the each of the years presented below:

 
Year Ended December 31,
 
2014
 
2013
 
2012
Customer A
22
%
 
28
%
 
30
%
Customer B
—
%
 
13
%
 
—
%
Customer C
12
%
 
12
%
 
13
%
Customer D
10
%
 
10
%
 
14
%
Other
56
%
 
37
%
 
43
%
Total
100
%
 
100
%
 
100
%
The following table summarizes the percentage of revenue earned from those customers in each segment that exceed 10% of the Partnership's consolidated segment's revenue for the each of the periods presented below:

 
Year Ended December 31,
 
2014
 
2013
 
2012
Gathering and Processing:
 
 
 
 
 
Customer A
33
%
 
43
%
 
40
%
Customer B
12
%
 
19
%
 
11
%
Customer D
—

 
—
%
 
12
%
Other
55
%
 
38
%
 
37
%
Total
100
%
 
100
%
 
100
%
Transmission:
 
 
 
 
 
Customer C
43
%
 
39
%
 
50
%
Customer D
16
%
 
16
%
 
22
%
Customer E
—

 
—
%
 
10
%
Other
41
%
 
45
%
 
18
%
Total
100
%
 
100
%
 
100
%
Terminals:
 
 
 
 
 
Customer F
19
%
 
20
%
 
N/A

Customer B
20
%
 
17
%
 
N/A

Customer G
15
%
 
16
%
 
N/A

Customer H
11
%
 
13
%
 
N/A

Other
35
%
 
34
%
 
N/A

Total
100
%
 
100
%
 
—

Other Current Assets (Tables)
Schedule of other current assets
Other current assets consists of the following (in thousands):
 
December 31,
 
2014
 
2013
Prepaid insurance
$
4,162

 
$
3,166

Restricted cash
6,475

 
—

Other current assets
4,865

 
4,331

 
$
15,502

 
$
7,497



Restricted cash of $6.5 million is a cash-backed letter of credit related to Costar Midstream operations that the Partnership was contractually obligated to maintain after the Costar Acquisition. The Partnership was released of this obligation in January 2015.
Derivatives (Tables)
Fair value associated with commodity derivative instruments 
As of December 31, 2014 and 2013, the value associated with our commodity derivatives, interest rate swap and weather derivative were recorded in our consolidated balance sheets, under the captions as follows (in thousands):
 
 
Gross Risk Management Assets
 
Gross Risk Management Liabilities
 
Net Risk Management Assets (Liabilities)
Balance Sheet Classification
 
December 31, 2014
 
December 31, 2013
 
December 31, 2014
 
December 31, 2013
 
December 31, 2014
 
December 31, 2013
Current
 
$
688

 
$
473

 
$
—

 
$
—

 
$
688

 
$
473

Noncurrent
 
—

 
—

 
—

 
—

 
—

 
—

Total assets
 
$
688

 
$
473

 
$
—

 
$
—

 
$
688

 
$
473

 
 
 
 
 
 
 
 
 
 
 
 
 
Current
 
$
—

 
$
27

 
$
(215
)
 
$
(450
)
 
$
(215
)
 
$
(423
)
Noncurrent
 
—

 
—

 
—

 
(101
)
 
—

 
(101
)
Total liabilities
 
$
—

 
$
27

 
$
(215
)
 
$
(551
)
 
$
(215
)
 
$
(524
)

Realized and unrealized gains (losses) with commodity and interst rate derivative instruments 
For the years ended December 31, 2014, 2013 and 2012, the realized and unrealized gains (losses) associated with our commodity, interest rate and weather derivative instruments were recorded in our consolidated statements of operations, under the captions as follows (in thousands):
 
 
Realized
 
Unrealized
2014
 

Gain (loss) on commodity derivatives, net
 
$
735

 
$
356

Interest expense
 
(433
)
 
239

Direct operating expenses
 
(1,035
)
 
—

Total
 
$
(733
)
 
$
595

2013
 
 
 
 
Gain (loss) on commodity derivatives, net
 
$
1,069

 
$
(1,041
)
Interest expense
 
(207
)
 
(454
)
Direct operating expenses
 
(662
)
 
—

Total
 
$
200

 
$
(1,495
)
2012
 
 
 
 
Gain (loss) on commodity derivatives, net
 
$
2,408

 
$
992

Total
 
$
2,408

 
$
992

Fair Value Measurement (Tables)
Fair value of financial instruments
Fair Value of Financial Instruments

The following table sets forth by level within the fair value hierarchy, our commodity derivative instruments and interest rate swap, included as part of Risk management assets and Risk management liabilities within the consolidated balance sheet, that were measured at fair value on a recurring basis as of December 31, 2014 and 2013 (in thousands):

 
Carrying
Amount
 
Estimated Fair Value of the Asset (Liability)
 
Level 1
 
Level 2
 
Level 3
 
Total
Commodity derivative instruments, net
 
 
 
 
 
 
 
 
 
December 31, 2014
$
286

 
$
—

 
$
286

 
$
—

 
$
286

December 31, 2013
(70
)
 
—

 
(70
)
 
—

 
(70
)
Interest rate swap
 
 
 
 
 
 
 
 
 
December 31, 2014
$
(215
)
 
$
—

 
$
(215
)
 
$
—

 
$
(215
)
December 31, 2013
(454
)
 
—

 
(454
)
 
—

 
(454
)

The unamortized portion of the premium paid to enter the weather derivative described in Note 7 "Derivatives," is included within Risk management assets on the consolidated balance sheet but is not included in the above table as it is recorded at amortized cost, not fair value.
Property, Plant and Equipment, Net (Tables)
Property, plant, and equipment, net
Property, plant and equipment, net, as of December 31, 2014 and 2013, were as follows (in thousands):
 
 
Useful Life
(in years)
 
December 31,
2014
 
December 31,
2013
Land
N/A
 
$
5,282

 
$
6,015

Construction in progress
N/A
 
77,551

 
6,443

Base gas
N/A
 
1,108

 
1,108

Buildings and improvements
4 to 40
 
6,905

 
5,109

Processing and treating plants
8 to 40
 
80,141

 
97,106

Pipelines
5 to 40
 
452,180

 
239,865

Compressors
4 to 20
 
24,227

 
11,955

Dock
20 to 40
 
8,072

 
7,942

Tanks, truck rack and piping
20 to 40
 
30,079

 
22,432

Equipment
8 to 20
 
8,952

 
6,294

Computer software
5
 
3,520

 
3,531

Total property, plant and equipment
 
 
698,017

 
407,800

Accumulated depreciation
 
 
(115,835
)
 
(95,099
)
Property, plant and equipment, net
 
 
$
582,182

 
$
312,701

Goodwill and Intangible assets (Tables)
Schedule of Finite-Lived Intangible Assets [Table Text Block]
Intangible assets, net, consist of the following (in thousands):

 
December 31,
 
2014
 
2013
Gross carrying amount:
 
 
 
    Customer contracts
$
12,101

 
$
12,101

    Customer relationships
53,400

 
—

    Dedicated acreage
53,350

 
—

 
$
118,851

 
$
12,101

Accumulated amortization:
 
 
 
    Customer contracts
$
(11,110
)
 
$
(8,419
)
    Customer relationships
(553
)
 
—

    Dedicated acreage
(882
)
 
—

 
$
(12,545
)
 
$
(8,419
)
Net carrying amount:
 
 
 
    Customer contracts
$
991

 
$
3,682

    Customer relationships
52,847

 
—

    Dedicated acreage
52,468

 
—

 
$
106,306

 
$
3,682

Accrued Expenses and Other Current Liabilities (Tables)
Schedule of accrued expenses and other current liabilities
Accrued expenses and other current liabilities were as follows (in thousands):

 
 
December 31,
 
 
2014
 
2013
Accrued capital expenditures
 
$
17,134

 
$
2,562

Accrued expenses
 
7,036

 
5,412

Gas imbalances payable
 
1,069

 
4,305

Other
 
549

 
2,779

 
 
$
25,788

 
$
15,058

Asset Retirement Obligation (Tables)
Schedule of reconciliation of the beginning and ending aggregate carrying amount of ARO liabilities
The following table is a reconciliation of the asset retirement obligations (in thousands):
 
Year Ended December 31,
 
2014
 
2013
Beginning asset retirement obligation
$
34,636

 
$
8,319

Liabilities assumed
248

 
25,763

Expenditures
(1,030
)
 
—

Accretion expense
791

 
554

Ending asset retirement obligation
$
34,645

 
$
34,636

For the years ended December 31, 2014, 2013 and 2012, total expenses related to operating leases, land site leases and right-of-way agreements were $5.8 million, $1.1 million, and $0.9 million, respectively.
Debt Obligations (Tables)
Outstanding borrowings under the credit facility
Our outstanding borrowings under the credit facility were (in thousands):
 
 
December 31,
 
 
2014
 
2013
Revolving credit facility
 
$
372,950

 
$
130,735

Other debt
 
2,908

 
2,048

Total debt
 
375,858

 
132,783

Less: current portion
 
2,908

 
2,048

Long-term debt
 
$
372,950

 
$
130,735

Partners' Capital (Tables)
Schedule for number of units outstanding
The numbers of units outstanding were as follows (in thousands):
 
December 31,
 
2014
 
2013
 
2012
Series A convertible preferred units
5,745

 
5,279

 
—

Series B convertible units
1,255

 
—

 
—

Limited Partner common units
22,670

 
7,414

 
4,639

Limited Partner subordinated units
—

 
—

 
4,526

General Partner units
392

 
185

 
185



Distributions

We made cash distributions as follows (in thousands):
 
Year Ended December 31,
 
2014
 
2013
 
2012
Series A convertible preferred units
2,658

 
2,375

 
—

Limited Partner common units
22,656

 
8,207

 
7,919

Limited Partner subordinated units
—

 
5,073

 
7,830

General Partner units
333

 
284

 
321

General Partners' incentive distribution rights
2,362

 
181

 
—

 
$
28,009

 
$
16,120

 
$
16,070


At December 31, 2014, we have accrued $3.2 million for the paid-in-kind Series A Units. The distributions will be made in the first quarter of 2015. During the year ended December 31, 2014, we issued 555 thousand Series A PIK Units and 86 thousand Series B PIK Units.
The numbers of units outstanding were as follows (in thousands):
 
December 31,
 
2014
 
2013
 
2012
Series A convertible preferred units
5,745

 
5,279

 
—

Series B convertible units
1,255

 
—

 
—

Limited Partner common units
22,670

 
7,414

 
4,639

Limited Partner subordinated units
—

 
—

 
4,526

General Partner units
392

 
185

 
185

Earnings per Unit (Tables)
Schedule of Earnings Per Share, Basic and Diluted, Per General and Limited Partner Unit, Including Two Class Method [Table Text Block]
We determined basic and diluted net income (loss) per limited partner unit as follows, (in thousands, except per unit amounts):

 
Year Ended December 31,
 
2014
 
2013
 
2012
Net income (loss) from continuing operations
$
(97,195
)
 
$
(30,993
)
 
$
(6,234
)
Net income (loss) attributable to noncontrolling interests
214

 
633

 
256

Net income (loss) from continuing operations attributable to the Partnership
(97,409
)
 
(31,626
)
 
(6,490
)
Less:
 
 
 
 
 
Distributions on Series A preferred units
14,492

 
24,117

 
—

Declared distributions on Series B Units
2,220

 
—

 
—

General partner's distributions
2,694

 
464

 
322

General partner's share in undistributed loss
(1,820
)
 
(1,708
)
 
(458
)
Blackwater net loss from continuing operations
—

 
(716
)
 
—

Net income (loss) from continuing operations available to limited Partners
(114,995
)
 
(53,783
)
 
(6,354
)
Net income (loss) from discontinued operations available to Limited Partners
(603
)
 
(2,051
)
 
(18
)
Net income (loss) available to Limited Partners
$
(115,598
)
 
$
(55,834
)
 
$
(6,372
)
 
 
 
 
 
 
Weighted average number of units used in computation of Limited Partners' net income (loss) per unit (basic and diluted)
13,472

 
7,525

 
9,113

 
 
 
 
 
 
Limited Partners' net income (loss) from continuing operations per unit (basic and diluted)
$
(8.54
)
 
$
(7.15
)
 
$
(0.70
)
Limited Partners' net income (loss) from discontinued operations per unit (basic and diluted)
(0.04
)
 
(0.27
)
 
—

Limited Partners' net income (loss) per unit (basic and diluted)
$
(8.58
)
 
$
(7.42
)
 
$
(0.70
)
Long-Term Incentive Plan (Tables)
Summarizes unit-based awards
The following table summarizes our unit-based awards for each of the periods indicated, in units:

 
 
Year Ended December 31, 2014
 
 
Shares
 
Weighted-Average Exercise Price
Outstanding at beginning of period
 
75,529

 
17.62

Granted
 
188,946

 
20.80

Forfeited
 
(12,009
)
 
18.28

Vested
 
(51,334
)
 
20.89

Outstanding at end of period
 
201,132

 
19.73

Post-Employment Benefits (Tables)
Schedule of changes in the benefit obligation, the fair value of the plan assets and the recorded asset or liability of the OPEB Plan using the accrual method 
The tables below detail the changes in the benefit obligation, the fair value of the plan assets and the funded status of the OPEB Plan using the accrual method (in thousands):

 
 
Year Ended December 31,
 
 
2014
 
2013
Change in benefit obligation
 
 
 
 
Benefit obligation, beginning of period
 
$
532

 
$
472

Service cost
 
2

 
5

Interest cost
 
24

 
15

Actuarial (gain) loss
 
122

 
(29
)
Plan amendments
 
—

 
126

Benefits paid
 
(25
)
 
(57
)
Benefit obligation, end of period
 
$
655

 
$
532

Change in plan assets
 
 
 
 
Fair value of plan assets, beginning of period
 
$
1,528

 
$
1,552

Actual return on plan assets
 
104

 
(53
)
Employer's contributions
 
90

 
90

Benefits paid
 
(38
)
 
(61
)
Fair value of plan assets, end of period
 
$
1,684

 
$
1,528

Funded status
 
 
 
 
Funded status
 
$
1,029

 
$
996

Schedule of amounts of plan assets recognized in consolidated balance sheets 
The weighted average asset allocation of our OPEB Plan at the measurement date by asset category, which are all classified as Level 1 investments, are as follows:
 
 
December 31,
 
 
2014
 
2013
 
2012
Fixed income (a)
 
70.0
%
 
70.1
%
 
72.2
%
Other (b)
 
30.0
%
 
29.9
%
 
27.8
%
Total
 
100.0
%
 
100.0
%
 
100.0
%
 
(a)
United States government securities, municipal corporate bonds and notes and asset backed securities
(b)
Cash and securities with maturities of one year or less
Schedule of components of net periodic benefit cost and other amounts recognized in other comprehensive income 
Components of Net Periodic Benefit Cost and Other amounts Recognized in Other Comprehensive Income (in thousands):
 
 
Year Ended December 31,
 
 
2014
 
2013
 
2012
Net Periodic Benefit Cost
 
 
 
 
 
 
Service cost
 
$
2

 
$
5

 
$
4

Interest cost
 
24

 
15

 
18

Expected return on plan assets
 
(70
)
 
(70
)
 
(67
)
Amortization of prior service cost
 
4

 
—

 
—

Amortization of net (gain) loss
 
(5
)
 
(23
)
 
(43
)
Net periodic benefit cost
 
$
(45
)
 
$
(73
)
 
$
(88
)
Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income
 
 
 
 
 
 
Net (gain) loss
 
$
102

 
$
247

 
$
64

Total recognized in other comprehensive income
 
102

 
247

 
64

Total recognized in net periodic benefit cost and other comprehensive income
 
$
57

 
$
174

 
$
(24
)
Schedule of assumptions made in measuremnet of the projected benefit obligations or assets of the OPEB Plan 
The assumptions made in measurement of the projected benefit obligations or assets of the OPEB Plan were as follows:

 
 
Year Ended December 31,
 
 
2014
 
2013
 
Discount rate
 
3.73
%
 
4.57
%
 
Expected return on plan assets
 
2.50
%
 
4.50
%
 
Health care trend rate
 
3.00
%
 
4.50
%
 
Schedule of benefits expected to be paid in each of the next five fiscal years 
The following table presents the benefits expected to be paid in each of the next five fiscal years, and in the aggregate for the five years thereafter by the OPEB Plan (in thousands):
For the year ending
 
2015
$
33.0

2016
32.0

2017
32.0

2018
32.0

2019
31.0

Five years thereafter
194.0

Income Tax (Tables)
Schedule of Deferred Tax Assets and Liabilities [Table Text Block] 
Net deferred income tax assets and liabilities consist of (in thousands):
 
December 31, 2014
 
December 31, 2013
Current deferred tax asset
$
3,086

 
$
—

Deferred tax liability, net
(8,199
)
 
(4,749
)
 
$
(5,113
)
 
$
(4,749
)
An analysis of the Partnership's deferred taxes is as follows (in thousands):
 
December 31, 2014
 
December 31, 2013
Deferred tax assets:
 
 
 
    Net operating loss carryforwards
$
4,173

 
$
5,455

    Other
213

 
182

    Total deferred tax assets
4,386

 
5,637

Deferred tax liabilities:
 
 
 
    Property, plant and equipment
9,112

 
9,022

    Intangible assets
387

 
1,364

    Total deferred tax liabilities
9,499

 
10,386

Deferred income tax liability, net
$
(5,113
)
 
$
(4,749
)
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block] 
The details of the provision for taxes on income for the year ended December 31, 2014, are as follows (in thousands):

 
Year Ended December 31,
 
2014
 
2013
Net loss before income tax benefit (expense)
$
(96,638
)
 
$
(31,488
)
US Federal statutory tax rate
34
%
 
34
%
Federal income tax benefit at statutory rate
32,857

 
10,706

Reconciling items:
 
 
 
    Partnership loss not subject to income tax
(33,216
)
 
(10,296
)
    Income not subject to corporate-level tax
—

 
222

    State and local tax benefit (expense)
(159
)
 
71

Adjustments related to prior years
(37
)
 
(175
)
    Other
(2
)
 
(33
)
Income tax benefit (expense)
$
(557
)
 
$
495

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block] 
The income tax provision related to continuing operations consist of the following (in thousands):
 
Year Ended December 31,
 
2014
 
2013
Current income tax benefit (expense)
$
(10
)
 
$
—

Deferred income tax benefit (expense)
(547
)
 
495

 
 
 
 
Effective income tax rate
0.6
%
 
1.6
%
Commitments and Contingencies (Tables)
Future non-cancelable commitments related to certain contractual obligations 
Future non-cancelable commitments related to certain contractual obligations as of December 31, 2014, are presented below (in thousands):
 
 
Operating leases and service contracts
 
Asset Retirement Obligation
 
Total
2015
 
$
3,428

 
$
—

 
$
3,428

2016
 
2,204

 
6,884

 
9,088

2017
 
1,421

 
—

 
1,421

2018
 
1,306

 
—

 
1,306

2019
 
1,525

 
—

 
1,525

Thereafter
 
2,945

 
27,761

 
30,706

 
 
$
12,829

 
$
34,645

 
$
47,474

Total expenses related to operating leases, asset retirement obligations, land site leases and right-of-way agreements 
The following table is a reconciliation of the asset retirement obligations (in thousands):
 
Year Ended December 31,
 
2014
 
2013
Beginning asset retirement obligation
$
34,636

 
$
8,319

Liabilities assumed
248

 
25,763

Expenditures
(1,030
)
 
—

Accretion expense
791

 
554

Ending asset retirement obligation
$
34,645

 
$
34,636

For the years ended December 31, 2014, 2013 and 2012, total expenses related to operating leases, land site leases and right-of-way agreements were $5.8 million, $1.1 million, and $0.9 million, respectively.
Reporting Segments (Tables)
Segment information for the periods 
The following tables set forth our segment information for the periods indicated (in thousands):

 
Year Ended December 31, 2014
 
Gathering
and
Processing
 
Transmission
 
Terminals
 
Total
Revenue
$
203,616

 
$
88,189

 
$
15,504

 
$
307,309

Gain (loss) on commodity derivatives, net
1,091

 
—

 
—

 
1,091

Total revenue
204,707

 
88,189

 
15,504

 
308,400

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

 
45,262

 
—

 
197,952

Direct operating expenses
23,783

 
15,577

 
6,342

 
45,702

Selling, general and administrative expenses
 
 
 
 
 
 
23,103

Equity compensation expense
 
 
 
 
 
 
1,536

Depreciation, amortization and accretion expense
 
 
 
 
 
 
28,832

Total operating expenses
 
 
 
 
 
 
297,125

Gain (loss) on sale of assets, net
 
 
 
 
 
 
(122
)
Loss on impairment of property, plant and equipment
 
 
 
 
 
 
(99,892
)
Other expense
 
 
 
 
 
 
(670
)
Interest expense
 
 
 
 
 
 
(7,577
)
Earnings in unconsolidated affiliates
 
 
 
 
 
 
348

Income tax benefit (expense)
 
 
 
 
 
 
(557
)
Income (loss) from operations of disposal groups, net of tax
 
 
 
 
 
 
(611
)
Net income (loss)
 
 
 
 
 
 
(97,806
)
Less: Net income (loss) attributable to noncontrolling interests
 
 
 
 
 
 
214

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

 
$
42,828

 
$
9,162

 
$
102,807


 
Year Ended December 31, 2013
 
Gathering
and
Processing
 
Transmission
 
Terminals (a)
 
Total
Revenue
$
205,179

 
$
79,041

 
$
9,831

 
$
294,051

Gain (loss) on commodity derivatives, net
28

 
—

 
—

 
28

Total revenue
205,207

 
79,041

 
9,831

 
294,079

Operating expenses:
 
 
 
 
 
 
 
Purchases of natural gas, NGL's and condensate
168,574

 
46,479

 
—

 
215,053

Direct operating expenses
14,574

 
13,259

 
4,403

 
32,236

Selling, general and administrative expenses
 
 
 
 
 
 
19,079

Equity compensation expense
 
 
 
 
 
 
2,094

Depreciation, amortization and accretion expense
 
 
 
 
 
 
30,002

Total operating expenses
 
 
 
 
 
 
298,464

Gain (loss) on involuntary conversion of property, plant and equipment
 
 
 
 
 
 
343

Loss on impairment of property, plant and equipment
 
 
 
 
 
 
(18,155
)
Interest expense
 
 
 
 
 
 
(9,291
)
Income tax benefit (expense)
 
 
 
 
 
 
495

Income (loss) from operation of disposal groups, net of tax
 
 
 
 
 
 
(2,413
)
Net income (loss)
 
 
 
 
 
 
(33,406
)
Less: Net income (loss) attributable to noncontrolling interests
 
 
 
 
 
 
633

Net income (loss) attributable to the Partnership
 
 
 
 
 
 
$
(34,039
)
 
 
 
 
 
 
 
 
Segment gross margin (b)
$
36,985

 
$
32,408

 
$
5,428

 
$
74,821


 
Year Ended December 31, 2012
 
Gathering
and
Processing
 
Transmission
 
Total
Revenue
$
152,339

 
$
52,529

 
$
204,868

Gain (loss) on commodity derivatives, net
3,400

 
—

 
3,400

Total revenue
155,739

 
52,529

 
208,268

Operating expenses:
 
 
 
 
 
Purchases of natural gas, NGL's and condensate
117,956

 
36,516

 
154,472

Direct operating expenses
12,152

 
5,031

 
17,183

Selling, general and administrative expenses
 
 
 
 
14,309

Equity compensation expense
 
 
 
 
1,783

Depreciation, amortization and accretion expense
 
 
 
 
21,287

Total operating expenses
 
 
 
 
209,034

Gain (loss) on involuntary conversion of property, plant and equipment
 
 
 
 
(1,021
)
Gain (loss) on sale of assets, net
 
 
 
 
123

Interest expense
 
 
 
 
(4,570
)
Income (loss) from operations of disposal groups
 
 
 
 
(18
)
Net income (loss)
 
 
 
 
(6,252
)
Less: Net income (loss) attributable to noncontrolling interests
 
 
 
 
256

Net income (loss) attributable to the Partnership
 
 
 
 
$
(6,508
)
 
 
 
 
 
 
Segment gross margin (b)
$
36,118

 
$
13,313

 
$
49,431


 
December 31,
 
2014
 
2013
Segment assets:
 
 
 
Gathering and Processing
686,395

 
178,869

Transmission
132,767

 
131,136

Terminals
71,180

 
60,873

Other (c)
26,302

 
11,197

Total assets
916,644

 
382,075


(a)
Terminals segment amounts are for the period from April 15, 2013 to December 31, 2013.
(b)
Segment gross margin for our Gathering and Processing segment consists of revenue less purchases of natural gas, NGLs and condensate and COMA. Segment gross margin for our Transmission segment consists of revenue, less purchases of natural gas and COMA. Segment gross margin for our Terminals segment consists of revenue, less direct operating expenses. Gross margin consists of the sum of the segment gross margin amounts for each of these segments. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow from operations as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner. Effective October 1, 2012, we changed our segment gross margin measure to exclude construction, operating and maintenance agreement ("COMA") income. Effective January 1, 2011, we changed our segment gross margin measure to exclude unrealized non-cash mark-to-market adjustments related to our commodity derivatives. Effective April 1, 2011, we changed our segment gross margin measure to exclude realized early termination costs on commodity derivatives.
(c)
Other assets not allocable to segments consist of investment in unconsolidated affiliate, corporate leasehold improvements, and other assets.

For a definition of gross margin and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP and a discussion of how we use gross margin to evaluate our operating performance, please read Item 7. "Management's Discussion and Analysis, How We Evaluate Our Operations."

Percentage of revenue earned from major customers 
The following table summarizes the percentage of revenue earned from those customers that exceed 10% of the Partnership's consolidated revenue in the consolidated statement of operations for the each of the years presented below:

 
Year Ended December 31,
 
2014
 
2013
 
2012
Customer A
22
%
 
28
%
 
30
%
Customer B
—
%
 
13
%
 
—
%
Customer C
12
%
 
12
%
 
13
%
Customer D
10
%
 
10
%
 
14
%
Other
56
%
 
37
%
 
43
%
Total
100
%
 
100
%
 
100
%
The following table summarizes the percentage of revenue earned from those customers in each segment that exceed 10% of the Partnership's consolidated segment's revenue for the each of the periods presented below:

 
Year Ended December 31,
 
2014
 
2013
 
2012
Gathering and Processing:
 
 
 
 
 
Customer A
33
%
 
43
%
 
40
%
Customer B
12
%
 
19
%
 
11
%
Customer D
—

 
—
%
 
12
%
Other
55
%
 
38
%
 
37
%
Total
100
%
 
100
%
 
100
%
Transmission:
 
 
 
 
 
Customer C
43
%
 
39
%
 
50
%
Customer D
16
%
 
16
%
 
22
%
Customer E
—

 
—
%
 
10
%
Other
41
%
 
45
%
 
18
%
Total
100
%
 
100
%
 
100
%
Terminals:
 
 
 
 
 
Customer F
19
%
 
20
%
 
N/A

Customer B
20
%
 
17
%
 
N/A

Customer G
15
%
 
16
%
 
N/A

Customer H
11
%
 
13
%
 
N/A

Other
35
%
 
34
%
 
N/A

Total
100
%
 
100
%
 
—

Quarterly Financial Data (Tables)
Schedule of Quarterly Financial Information [Table Text Block]
Summarized unaudited quarterly financial data for 2014 and 2013 are as follows (in thousands, except per unit amounts):
 
 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter (b)
Year Ended December 31, 2014
 
 
 
 
 
 
 
Total revenues
$
80,238

 
$
77,680

 
$
70,305

 
$
80,177

Gross margin (a)
23,081

 
22,167

 
21,332

 
36,227

Operating income (loss)
2,450

 
734

 
(290
)
 
(91,633
)
Net income (loss) from continuing operations
558

 
(1,095
)
 
(2,397
)
 
(94,261
)
Income (loss) from operations of disposal groups
(50
)
 
(506
)
 
(26
)
 
(29
)
Net income (loss) attributable to noncontrolling interest
108

 
66

 
33

 
7

Net income (loss) attributable to the Partnership
400

 
(1,667
)
 
(2,456
)
 
(94,297
)
General Partner's Interest in net income (loss)
7

 
(22
)
 
(32
)
 
(1,232
)
Limited Partners' Interest in net income (loss)
$
393

 
$
(1,645
)
 
$
(2,424
)
 
$
(93,065
)
 
 
 
 
 
 
 
 
Limited Partners' income (loss) per unit:
 
 
 
 
 
 
 
Income (loss) from continuing operations
$
(0.31
)
 
$
(0.55
)
 
$
(0.58
)
 
$
(4.98
)
Income (loss) from discontinued operations
(0.01
)
 
(0.04
)
 
—

 
—

Net income (loss)
$
(0.32
)
 
$
(0.59
)
 
$
(0.58
)
 
$
(4.98
)
Year Ended December 31, 2013
 
 
 
 
 
 
 
Total revenues
$
62,599

 
$
77,191

 
$
77,519

 
$
76,770

Gross margin (a)
12,705

 
18,317

 
20,908

 
22,891

Operating income (loss)
(1,661
)
 
(17,841
)
 
(104
)
 
(2,591
)
Net income (loss) from continuing operations
(3,392
)
 
(20,057
)
 
(2,526
)
 
(5,018
)
Income (loss) from operations of disposal groups
(6
)
 
(1,869
)
 
(15
)
 
(523
)
Net income (loss) attributable to noncontrolling interest
155

 
188

 
190

 
100

Net income (loss) attributable to the Partnership
(3,553
)
 
(22,114
)
 
(2,731
)
 
(5,641
)
General Partner's Interest in net income (loss)
(70
)
 
(905
)
 
(221
)
 
(209
)
Limited Partners' Interest in net income (loss)
$
(3,482
)
 
$
(21,209
)
 
$
(2,510
)
 
$
(5,433
)
 
 
 
 
 
 
 
 
Limited Partners' income (loss) per unit:
 
 
 
 
 
 
 
Income (loss) from continuing operations
$
(0.39
)
 
$
(4.01
)
 
$
(0.81
)
 
$
(1.43
)
Income (loss) from discontinued operations
0.01

 
(0.20
)
 
0.01

 
—

Net income (loss)
$
(0.38
)
 
$
(4.21
)
 
$
(0.80
)
 
$
(1.43
)
 
(a)
For a definition of gross margin and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP and a discussion of how we use gross margin to evaluate our operating performance, please read Item 7. "Management's Discussion and Analysis, How We Evaluate Our Operations."
(b)
The Partnership record an immaterial out-of-period adjustment in the fourth quarter of 2014 to account for the items associated with the material weakness described in Item 9A.  Management’s Annual Report over Internal Control over Financial Reporting.
Organization and Basis of Presentation (Details)
12 Months Ended 12 Months Ended
Dec. 31, 2014
mi
billion_cubic_feet_per_day
bbl
pipeline
gathering_system
facility
Dec. 31, 2013
Dec. 31, 2013
Burns Point Plant [Member]
Dec. 31, 2013
Chatom processing, gathering and fractionation plant [Member]
Jul. 2, 2012
Chatom processing, gathering and fractionation plant [Member]
Dec. 31, 2014
Minimum [Member]
Dec. 31, 2014
Maximum [Member]
Dec. 31, 2014
Equity Method Investments [Member]
Sep. 30, 2014
Equity Method Investments [Member]
Collaborative Arrangements and Non-collaborative Arrangement Transactions [Line Items]
 
 
 
 
 
 
 
 
 
General Partners' Capital Account, Percentage
95.00% 
 
 
 
 
 
 
 
 
Limited Partners' Capital Account, Percentage
5.00% 
 
 
 
 
 
 
 
 
Number of Gathering Systems
12 
 
 
 
 
 
 
 
 
Number of Processing Facilities
5 
 
 
 
 
 
 
 
 
Number of Fractionation Facilities
3 
 
 
 
 
 
 
 
 
Number of Marine Terminal Sites
4 
 
 
 
 
 
 
 
 
Number of Interstate Pipelines
3 
 
 
 
 
 
 
 
 
Number of Intrastate Pipelines
5 
 
 
 
 
 
 
 
 
Ownership percentage
 
 
 
 
 
 
 
66.70% 
66.70% 
Acquired interest (percent)
 
 
50.00% 
4.80% 
87.40% 
 
 
 
 
Gathering pipeline (miles)
3,000 
 
 
 
 
 
 
 
 
Volume of Natural Gas, Operating
1 
 
 
 
 
 
 
 
 
Million barrels of storage capacity
1,700,000 
 
 
 
 
 
 
 
 
Useful life
25 years 
 
 
 
 
0 years 5 months 0 days 
30 years 
 
 
Noncontrolling interest, ownership percentage by noncontrolling owners
12.60% 
7.80% 
 
 
 
 
 
 
 
Acquisitions (Consideration Transferred) (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended 0 Months Ended
Dec. 31, 2014
Oct. 14, 2014
Costar Midstream, L.L.C. [Member]
Business Acquisition [Line Items]
 
 
Useful life
25 years 
 
Cash
 
$ 265,383 
Limited partner common units
 
147,296 
Total fair value of consideration
 
$ 412,679 
Acquisitions Fair Value of Identifiable Assets and Consideration Transferred (Details) (USD $)
In Thousands, unless otherwise specified
0 Months Ended 0 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Jul. 2, 2012
Chatom processing, gathering and fractionation plant [Member]
Oct. 14, 2014
Costar Midstream, L.L.C. [Member]
Oct. 14, 2014
Costar Midstream, L.L.C. [Member]
Oct. 14, 2014
Lavaca [Member]
Dec. 31, 2014
Lavaca [Member]
Oct. 14, 2014
Lavaca [Member]
Apr. 15, 2013
High Point [Member]
Dec. 31, 2014
Pipelines [Member]
Lavaca [Member]
Business Acquisition [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Working capital
 
 
 
 
 
$ 8,152 
 
 
 
 
 
Processing plants
 
 
 
 
 
48,357 
 
 
 
 
 
Pipelines
 
 
 
 
 
128,799 
 
 
 
 
 
Land
 
 
 
 
 
1,244 
 
2 
 
 
 
Buildings
 
 
 
 
 
682 
 
 
 
 
 
Equipment
 
 
 
 
 
9,827 
 
753 
 
 
 
Construction in progress
 
 
 
 
 
16,146 
 
 
 
 
 
Total property, plant and equipment
 
 
 
 
 
205,055 
 
59,492 
 
 
58,737 
Investment in unconsolidated affiliate
 
 
 
 
 
11,884 
 
 
 
 
 
Customer relationships
 
 
 
 
 
53,400 
 
 
 
 
 
Dedicated acreage
 
 
 
 
 
32,000 
 
 
 
 
 
Noncontrolling interest
 
 
 
 
 
219 
 
 
 
 
 
Goodwill
142,236 
16,447 
 
 
 
102,407 
 
 
23,567 
 
 
Intangible assets
 
 
 
 
 
 
 
21,350 
 
 
 
Total cash consideration
 
 
 
51,377 
 
 
 
 
 
 
 
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Less Noncontrolling Interest
 
 
 
 
 
412,679 
 
 
 
 
 
Cash
 
 
 
51,377 
 
 
 
 
 
 
 
Cash and cash equivalents
 
 
 
 
 
 
 
 
 
1,935 
 
Accounts receivable
 
 
 
 
 
 
 
 
 
3,629 
 
Unbilled revenue
 
 
 
 
 
 
 
 
 
1,446 
 
Other current assets
 
 
 
 
 
 
 
 
 
2,049 
 
Property, plant and equipment, net
 
 
 
 
 
 
 
 
 
82,615 
 
Other assets
 
 
 
 
 
 
 
 
 
1,000 
 
Accounts payable
 
 
 
 
 
 
 
 
 
11 
 
Accrued expenses and other current liabilities
 
 
 
 
 
 
 
 
 
4,077 
 
Current portion of long-term debt
 
 
 
 
 
 
 
 
 
893 
 
Asset retirement obligation liability
 
 
 
 
 
 
 
 
 
25,763 
 
Total identifiable net assets
 
 
 
 
 
 
 
 
 
61,930 
 
Unbilled revenue
 
 
 
4,535 
 
 
 
 
 
 
 
Property, plant and equipment
582,182 
312,701 
 
58,279 
 
 
 
 
 
 
 
Asset retirement cost
34,645 
34,636 
8,319 
452 
 
 
 
 
 
 
 
Accounts payable
20,326 
3,261 
 
399 
 
 
 
 
 
 
 
Accrued gas purchases
14,326 
17,386 
 
3,631 
 
 
 
 
 
 
 
Asset retirement obligations
 
 
 
452 
 
 
 
 
 
 
 
Noncontrolling interest
 
 
 
(7,407)
 
 
 
 
 
 
 
Cash
 
 
 
 
$ 265,383 
 
$ 104,409 
 
 
 
 
Acquisitions (Pro Forma Information) (Details) (Costar Midstream, L.L.C. [Member], USD $)
In Thousands, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Costar Midstream, L.L.C. [Member]
 
 
Business Acquisition [Line Items]
 
 
Revenue
$ 435,133 
$ 448,748 
Net loss
$ (101,237)
$ (30,672)
Limited partners' net loss per unit
$ (6.15)
$ (3.82)
Acquisitions Narrative (Details) (USD $)
0 Months Ended 3 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 0 Months Ended 3 Months Ended 0 Months Ended 9 Months Ended 12 Months Ended 3 Months Ended 12 Months Ended 12 Months Ended 0 Months Ended 12 Months Ended 0 Months Ended 12 Months Ended 0 Months Ended 12 Months Ended 9 Months Ended 3 Months Ended 12 Months Ended 12 Months Ended 0 Months Ended 12 Months Ended 0 Months Ended 12 Months Ended 3 Months Ended 0 Months Ended 3 Months Ended 12 Months Ended
Jan. 29, 2014
Dec. 31, 2014
bbl
Sep. 30, 2014
Jun. 30, 2014
Mar. 31, 2014
Dec. 31, 2013
Sep. 30, 2013
Jun. 30, 2013
Mar. 31, 2013
Dec. 31, 2014
mi
bbl
Dec. 31, 2013
Dec. 31, 2012
Aug. 20, 2014
Jan. 29, 2014
Dec. 11, 2013
Apr. 15, 2013
Dec. 31, 2014
Series B
Dec. 31, 2013
Series B
Dec. 31, 2012
Series B
Jan. 31, 2014
Series B
Dec. 31, 2013
Chatom processing, gathering and fractionation plant [Member]
mi
Dec. 31, 2012
Chatom processing, gathering and fractionation plant [Member]
Jul. 2, 2012
Chatom processing, gathering and fractionation plant [Member]
Oct. 14, 2014
Costar Midstream, L.L.C. [Member]
Dec. 31, 2014
Costar Midstream, L.L.C. [Member]
Oct. 14, 2014
Costar Midstream, L.L.C. [Member]
Oct. 14, 2014
Lavaca [Member]
Jan. 31, 2014
Lavaca [Member]
mi
Sep. 30, 2014
Lavaca [Member]
Dec. 31, 2014
Lavaca [Member]
Sep. 30, 2013
High Point [Member]
Dec. 31, 2014
High Point [Member]
mi
Apr. 15, 2013
High Point [Member]
Dec. 31, 2013
Williams [Member]
Dec. 31, 2014
Minimum [Member]
Oct. 14, 2014
Minimum [Member]
Costar Midstream, L.L.C. [Member]
Dec. 31, 2014
Maximum [Member]
Oct. 14, 2014
Maximum [Member]
Costar Midstream, L.L.C. [Member]
Apr. 15, 2013
Total Partners Capital
Dec. 31, 2014
Total Partners Capital
Dec. 31, 2013
Total Partners Capital
Dec. 31, 2012
Total Partners Capital
Dec. 31, 2014
Total Partners Capital
Series B
Dec. 31, 2014
Series B
Jan. 31, 2014
Series B
Dec. 31, 2014
Series B
Sep. 30, 2014
Equity Method Investments [Member]
Dec. 31, 2014
Equity Method Investments [Member]
Sep. 30, 2013
Terminals [Member]
Dec. 31, 2014
Terminals [Member]
Dec. 17, 2013
Terminals [Member]
bbl
Dec. 31, 2014
ArcLight [Member]
High Point [Member]
Gas_Receipt_Point
Dec. 17, 2013
Blackwater [Member]
Dec. 31, 2014
Blackwater [Member]
Dec. 31, 2013
Blackwater [Member]
Dec. 31, 2012
Blackwater [Member]
Dec. 17, 2013
Blackwater [Member]
Apr. 15, 2013
Blackwater [Member]
Apr. 15, 2013
Series A
Dec. 31, 2014
Series A
Apr. 15, 2013
Issuance of Preferred Units [Member]
High Point [Member]
Series A
Apr. 15, 2013
Revolving Credit Facility [Member]
Fourth Amendment [Member]
Series A
Apr. 15, 2013
AIM Midstream Holdings [Member]
High Point [Member]
Partnership Interest [Member]
Sep. 30, 2014
Madison [Member]
Dec. 31, 2013
Madison [Member]
Business Acquisition [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Preliminary purchase price allocation adjustment
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 23,600,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Finite Lived Intangible Assets Accumulated Amortization Adjustment
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
500,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proceeds from sale of property, plant, and equipment
 
 
 
 
 
 
 
 
 
6,323,000 
500,000 
128,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
6,100,000 
 
Noncontrolling interest, ownership percentage by noncontrolling owners
 
12.60% 
 
 
 
7.80% 
 
 
 
12.60% 
7.80% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Acquired interest (percent)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4.80% 
 
87.40% 
 
 
100.00% 
 
 
 
 
 
 
100.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Noncontrolling Interest, Ownership Percentage by Parent
 
92.20% 
 
 
 
 
 
 
 
92.20% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
265,383,000 
 
 
104,409,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Equity interests issued (in units)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
6,900,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Limited partner common units
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
147,296,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3,100,000 
 
 
 
 
 
 
 
 
 
 
Total identifiable net assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
61,930,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
22,700,000 
 
 
 
 
 
 
 
Partners' Capital Account, Distributions to Existing Interest
 
 
 
 
 
 
 
 
 
0 
15,612,000 
0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(15,600,000)
 
15,612,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Discount rate
 
9.50% 
 
 
 
 
 
 
 
10.00% 
10.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
10.50% 
 
 
 
 
 
11.00% 
 
16.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
18.00% 
 
 
 
 
 
 
Working capital, accounts receivable
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
11,200,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
80,177,000 
70,305,000 
77,680,000 
80,238,000 
76,770,000 
77,519,000 
77,191,000 
62,599,000 
308,400,000 
294,079,000 
208,268,000 
 
 
 
 
 
 
 
 
 
25,400,000 
 
 
19,900,000 
 
 
 
 
16,800,000 
30,400,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
9,800,000 
15,504,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net income (loss)
 
(94,297,000)
(2,456,000)
(1,667,000)
400,000 
(5,641,000)
(2,731,000)
(22,114,000)
(3,553,000)
(98,020,000)
(34,039,000)
(6,508,000)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
7,200,000 
 
 
 
 
 
 
 
 
(98,020,000)
(34,039,000)
(6,508,000)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating Income (Loss)
 
(91,633,000)
(290,000)
734,000 
2,450,000 
(2,591,000)
(104,000)
(17,841,000)
(1,661,000)
(88,739,000)
(22,197,000)
(1,664,000)
 
 
 
 
 
 
 
 
 
1,800,000 
 
 
300,000 
 
 
 
 
7,600,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
800,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Transaction costs
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
500,000 
 
 
 
 
100,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Length Of Pipeline
 
 
 
 
 
 
 
 
 
3,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
100 
 
 
 
700 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Issuance of common units, net of offering costs
86,900,000 
119,300,000 
 
 
 
 
 
 
 
204,255,000 
54,853,000 
0 
 
 
 
 
(30,000,000)
0 
0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
54,853,000 
 
 
0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Issuance of Series B Units
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
32,220,000 
 
30,000,000 
32,220,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Limited partners, units issued
 
22,670,000 
 
 
 
7,414,000 
 
 
 
22,670,000 
7,414,000 
 
4,622,352 
3,400,000 
2,568,712 
 
 
 
 
1,168,225 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Useful life
 
 
 
 
 
 
 
 
 
25 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0 years 5 months 0 days 
 
30 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Finite-lived intangible assets, amortization expense, next twelve months
 
5,300,000 
 
 
 
 
 
 
 
5,300,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ownership percentage
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
66.70% 
66.70% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Payments to acquire equity method investments
 
 
 
 
 
 
 
 
 
12,000,000 
0 
0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
12,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Earnings in unconsolidated affiliates
 
 
 
 
 
 
 
 
 
348,000 
0 
0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proceeds from equity method investement, return of capital
 
 
2,000,000 
 
 
 
 
 
 
1,632,000 
0 
0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Consideration
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
51,377,000 
 
 
 
 
 
 
 
 
 
 
6,500,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Million barrels of storage capacity
 
1,700,000 
 
 
 
 
 
 
 
1,700,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,300,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total fair value of consideration
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
412,679,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
63,900,000 
 
 
 
 
 
 
 
 
 
 
 
 
Distributions
 
 
 
 
 
 
 
 
 
28,009,000 
16,120,000 
16,070,000 
 
 
 
 
2,220,000 
0 
0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
42,063,000 
22,251,000 
16,070,000 
 
 
 
 
 
 
 
 
 
 
 
0 
27,650,000 
0 
 
 
 
 
 
 
 
 
 
Units issued in business acquisition
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
125,500 
 
 
 
 
 
 
 
 
Number of natural gas collection receipt points
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
75 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Consideration for Issuance of Preferred Units
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
15,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Contributed capital
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
5,142,857 
 
 
 
 
Transaction expenses
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2,500,000 
 
 
 
 
Payments on long-term debt
 
 
 
 
 
 
 
 
 
250,870,000 
131,571,000 
59,230,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
12,500,000 
 
 
 
Partnership cancellation of subordinated units (percent)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
90.00% 
 
 
Distribution made to member or limited partner, distributions paid, conversion price per unit
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 17.50 
 
 
 
 
 
 
Series A convertible preferred units
 
107,965,000 
 
 
 
94,811,000 
 
 
 
107,965,000 
94,811,000 
 
 
 
 
90,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distribution growth rate
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1.00% 
 
 
 
 
 
Fair value, paid in kind distributions
 
 
 
 
 
 
 
 
 
$ 19.67 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distribution made to member or limited partner, payment In kind declared
 
 
 
 
 
 
 
 
 
13,200,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair value input, option value
 
 
 
 
 
 
 
 
 
3.32 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Chatom Assets location
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
15 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Refrigeration processing plant
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
25 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fractation unit
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,900 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-ton per day sulfur recovery
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
160 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gas gathering system
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
24 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Business Acquisition Fair Value Measurement Composition, Assumed Cost of Capital
 
 
 
 
 
 
 
 
 
 
9.25% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Business Acquisition Fair Value Measurement Composition, Inflationary Cost
 
 
 
 
 
 
 
 
 
 
2.50% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Effective income tax rate, continuing operations
 
 
 
 
 
 
 
 
 
 
35.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Effective income tax rate reconciliation, state and local income taxes, percent
 
 
 
 
 
 
 
 
 
 
6.50% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percent of outstanding noncontrolling interest acquired
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
38.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Loss on impairment of property, plant and equipment
 
99,900,000 
 
 
 
3,000,000 
 
15,200,000 
100,000 
99,892,000 
18,155,000 
0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3,000,000 
Property plant and equipment gross
 
$ 698,017,000 
 
 
 
$ 407,800,000 
 
 
 
$ 698,017,000 
$ 407,800,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 6,100,000 
Discontinued Operations (Details) (USD $)
3 Months Ended 12 Months Ended
Dec. 31, 2014
Sep. 30, 2014
Jun. 30, 2014
Mar. 31, 2014
Dec. 31, 2013
Sep. 30, 2013
Jun. 30, 2013
Mar. 31, 2013
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Disposal Group, Including Discontinued Operation, Revenue
 
 
 
 
 
 
 
 
$ 474,000 
$ 2,084,000 
$ 2,318,000 
Disposal Group, Including Discontinued Operation, Operating Expense
 
 
 
 
 
 
 
 
(658,000)
(2,361,000)
(2,336,000)
Disposal Group, Including Discontinued Operation, Impairment
 
 
 
 
 
 
 
 
(673,000)
(2,400,000)
0 
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax
 
 
 
 
 
 
 
 
(87,000)
(75,000)
0 
Discontinued Operation, Tax Effect of Discontinued Operation
 
 
 
 
 
 
 
 
333,000 
339,000 
0 
Current liabilities held for sale
12,000 
 
 
 
114,000 
 
 
 
12,000 
114,000 
 
Loss on impairment of noncurrent assets held for sale
 
700,000 
 
 
 
 
 
 
673,000 
2,400,000 
0 
Discount rate
9.50% 
 
 
 
 
 
 
 
10.00% 
10.00% 
 
Current assets held for sale
52,000 
 
 
 
272,000 
 
 
 
52,000 
272,000 
 
Gain (loss) from operations of disposal groups, net of tax
(29,000)
(26,000)
(506,000)
(50,000)
(523,000)
(15,000)
(1,869,000)
(6,000)
(611,000)
(2,413,000)
(18,000)
Limited partners' net income (loss) from discontinued operations per unit (basic and diluted)
$ 0.00 
$ 0.00 
$ (0.04)
$ (0.01)
$ 0.00 
$ 0.01 
$ (0.20)
$ 0.01 
$ (0.04)
$ (0.27)
$ 0.00 
Blackwater [Member]
 
 
 
 
 
 
 
 
 
 
 
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Noncurrent assets held for sale, net
 
 
 
 
1,200,000 
 
 
 
 
1,200,000 
 
Current liabilities held for sale
 
 
 
 
100,000 
 
 
 
 
100,000 
 
Current assets held for sale
 
 
 
 
100,000 
 
 
 
 
100,000 
 
Gathering And Processing [Member]
 
 
 
 
 
 
 
 
 
 
 
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Loss on impairment of noncurrent assets held for sale
 
 
 
 
 
 
 
 
600,000 
1,800,000 
 
Discontinued Operations [Member]
 
 
 
 
 
 
 
 
 
 
 
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Loss on impairment of noncurrent assets held for sale
 
$ 400,000 
 
 
 
 
 
 
 
 
 
Concentration of Credit Risk and Trade Accounts Receivable (Details)
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Revenue, Major Customer
 
 
 
Entity-wide revenue by major customer, percentage
100.00% 
100.00% 
100.00% 
Customer A [Member]
 
 
 
Revenue, Major Customer
 
 
 
Entity-wide revenue by major customer, percentage
22.00% 
28.00% 
30.00% 
Customer B [Member]
 
 
 
Revenue, Major Customer
 
 
 
Entity-wide revenue by major customer, percentage
0.00% 
13.00% 
0.00% 
Cusotmer C [Member]
 
 
 
Revenue, Major Customer
 
 
 
Entity-wide revenue by major customer, percentage
12.00% 
12.00% 
13.00% 
Customer D [Member]
 
 
 
Revenue, Major Customer
 
 
 
Entity-wide revenue by major customer, percentage
10.00% 
10.00% 
14.00% 
Customer Other [Member]
 
 
 
Revenue, Major Customer
 
 
 
Entity-wide revenue by major customer, percentage
56.00% 
37.00% 
43.00% 
Other Current Assets (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Other Current Assets [Abstract]
 
 
Prepaid insurance
$ 4,162 
$ 3,166 
Restricted cash
6,475 
0 
Other current assets
4,865 
4,331 
Other current assets
$ 15,502 
$ 7,497 
Derivatives (Fair Value of Commodity Derivatives) (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Risk management assets and Risk management liabilities
 
 
Derivative Asset, Fair Value, Net
$ 688 
$ 473 
Derivative Liability, Fair Value, Net
(215)
(524)
Commodity derivatives [Member]
 
 
Risk management assets and Risk management liabilities
 
 
Derivative asset, gross derivative asset
688 
473 
Derivative asset, gross derivative liabilities
0 
0 
Derivative liability, gross derivative assets
0 
27 
Derivative liability, gross derivative liabilities
(215)
(551)
Commodity derivatives [Member] |
Risk Management Assets [Member]
 
 
Risk management assets and Risk management liabilities
 
 
Derivative asset, gross derivative asset
688 
473 
Derivative asset, gross derivative liabilities
0 
0 
Derivative Asset, Fair Value, Net
688 
473 
Commodity derivatives [Member] |
Risk Management Assets - Long Term [Member]
 
 
Risk management assets and Risk management liabilities
 
 
Derivative asset, gross derivative asset
0 
0 
Derivative asset, gross derivative liabilities
0 
0 
Derivative Asset, Fair Value, Net
0 
0 
Commodity derivatives [Member] |
Risk Management Liabilities [Member]
 
 
Risk management assets and Risk management liabilities
 
 
Derivative liability, gross derivative assets
0 
27 
Derivative liability, gross derivative liabilities
(215)
(450)
Derivative Liability, Fair Value, Net
(215)
(423)
Commodity derivatives [Member] |
Risk Management Liabilities - Long Term [Member]
 
 
Risk management assets and Risk management liabilities
 
 
Derivative liability, gross derivative assets
0 
0 
Derivative liability, gross derivative liabilities
0 
(101)
Derivative Liability, Fair Value, Net
$ 0 
$ (101)
Derivatives (Realized and Unrealized Gains (Losses)) (Details) (Commodity derivatives [Member], USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Derivatives, Fair Value [Line Items]
 
 
 
Gain (loss) on derivatives, realized
$ (733)
$ 200 
$ 2,408 
Gain (loss) on derivatives, unrealized
595 
(1,495)
992 
Gain (Loss) on Derivative Instruments [Member]
 
 
 
Derivatives, Fair Value [Line Items]
 
 
 
Gain (loss) on derivatives, realized
735 
1,069 
2,408 
Gain (loss) on derivatives, unrealized
356 
(1,041)
992 
Interest Expense [Member]
 
 
 
Derivatives, Fair Value [Line Items]
 
 
 
Gain (loss) on derivatives, realized
(433)
(207)
 
Gain (loss) on derivatives, unrealized
239 
(454)
 
Other Income [Member]
 
 
 
Derivatives, Fair Value [Line Items]
 
 
 
Gain (loss) on derivatives, realized
(1,035)
(662)
 
Gain (loss) on derivatives, unrealized
$ 0 
$ 0 
 
Derivatives (Details Textual) (USD $)
12 Months Ended
Dec. 31, 2014
gal
Dec. 31, 2013
Dec. 31, 2012
Derivative [Line Items]
 
 
 
Aggregate notional volume of our commodity derivative
500,000 
 
 
Amortization of weather derivative premium
$ 1,035,000 
$ 662,000 
$ 0 
Interest Rate Swap [Member]
 
 
 
Derivative [Line Items]
 
 
 
Notional amount of interest rate derivatives
100,000,000 
 
 
Weather Contract [Member]
 
 
 
Derivative [Line Items]
 
 
 
Derivative instruments not designated as hedging instruments, potential cash proceeds from Contract
 
10,000,000 
 
Derivative instruments not designated as hedging instruments, asset, at fair value
0 
 
 
Payments of derivative issuance costs
1,000,000 
1,100,000 
 
Term of Contract
1 year 0 months 0 days 
 
 
Amortization of weather derivative premium
$ 400,000 
$ 500,000 
 
Fair Value Measurement (Fair Value of Financial Instruments) (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Commodity Contract [Member]
 
 
Quantitative Information about Level 3 Fair Value Measurements
 
 
Estimated Fair Value
$ 286 
$ (70)
Commodity Contract [Member] |
Estimate of Fair Value, Fair Value Disclosure [Member]
 
 
Quantitative Information about Level 3 Fair Value Measurements
 
 
Estimated Fair Value
286 
(70)
Commodity Contract [Member] |
Level 1 [Member] |
Estimate of Fair Value, Fair Value Disclosure [Member]
 
 
Quantitative Information about Level 3 Fair Value Measurements
 
 
Estimated Fair Value
0 
0 
Commodity Contract [Member] |
Level 2 [Member] |
Estimate of Fair Value, Fair Value Disclosure [Member]
 
 
Quantitative Information about Level 3 Fair Value Measurements
 
 
Estimated Fair Value
286 
(70)
Commodity Contract [Member] |
Level 3 [Member] |
Estimate of Fair Value, Fair Value Disclosure [Member]
 
 
Quantitative Information about Level 3 Fair Value Measurements
 
 
Estimated Fair Value
0 
0 
Interest Rate Swap [Member]
 
 
Quantitative Information about Level 3 Fair Value Measurements
 
 
Estimated Fair Value
(215)
(454)
Interest Rate Swap [Member] |
Estimate of Fair Value, Fair Value Disclosure [Member]
 
 
Quantitative Information about Level 3 Fair Value Measurements
 
 
Estimated Fair Value
(215)
(454)
Interest Rate Swap [Member] |
Level 1 [Member] |
Estimate of Fair Value, Fair Value Disclosure [Member]
 
 
Quantitative Information about Level 3 Fair Value Measurements
 
 
Estimated Fair Value
0 
0 
Interest Rate Swap [Member] |
Level 2 [Member] |
Estimate of Fair Value, Fair Value Disclosure [Member]
 
 
Quantitative Information about Level 3 Fair Value Measurements
 
 
Estimated Fair Value
(215)
(454)
Interest Rate Swap [Member] |
Level 3 [Member] |
Estimate of Fair Value, Fair Value Disclosure [Member]
 
 
Quantitative Information about Level 3 Fair Value Measurements
 
 
Estimated Fair Value
$ 0 
$ 0 
Fair Value Measurement (Details Textual) (USD $)
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Fair Value Disclosures [Abstract]
 
 
Transfers out of Level 3
$ 0 
$ 0 
Property, Plant and Equipment, Net (Details) (USD $)
3 Months Ended 12 Months Ended 3 Months Ended 12 Months Ended
Sep. 30, 2014
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2014
Land [Member]
Dec. 31, 2013
Land [Member]
Dec. 31, 2014
Construction in progress [Member]
Dec. 31, 2013
Construction in progress [Member]
Dec. 31, 2014
Base Gas [Member]
Dec. 31, 2013
Base Gas [Member]
Dec. 31, 2014
Buildings and improvements [Member]
Dec. 31, 2013
Buildings and improvements [Member]
Dec. 31, 2014
Processing and treating plants [Member]
Dec. 31, 2013
Processing and treating plants [Member]
Dec. 31, 2014
Pipelines [Member]
Dec. 31, 2013
Pipelines [Member]
Dec. 31, 2014
Compressors [Member]
Dec. 31, 2013
Compressors [Member]
Dec. 31, 2014
Dock [Member]
Dec. 31, 2013
Dock [Member]
Dec. 31, 2014
Tanks, truck rack and piping [Member]
Dec. 31, 2013
Tanks, truck rack and piping [Member]
Dec. 31, 2014
Equipment [Member]
Dec. 31, 2013
Equipment [Member]
Dec. 31, 2014
Computer software [Member]
Dec. 31, 2013
Computer software [Member]
Dec. 31, 2014
Minimum [Member]
Buildings and improvements [Member]
Dec. 31, 2014
Minimum [Member]
Processing and treating plants [Member]
Dec. 31, 2014
Minimum [Member]
Pipelines [Member]
Dec. 31, 2014
Minimum [Member]
Compressors [Member]
Dec. 31, 2014
Minimum [Member]
Dock [Member]
Dec. 31, 2014
Minimum [Member]
Tanks, truck rack and piping [Member]
Dec. 31, 2014
Minimum [Member]
Equipment [Member]
Dec. 31, 2014
Maximum [Member]
Buildings and improvements [Member]
Dec. 31, 2014
Maximum [Member]
Processing and treating plants [Member]
Dec. 31, 2014
Maximum [Member]
Pipelines [Member]
Dec. 31, 2014
Maximum [Member]
Compressors [Member]
Dec. 31, 2014
Maximum [Member]
Dock [Member]
Dec. 31, 2014
Maximum [Member]
Tanks, truck rack and piping [Member]
Dec. 31, 2014
Maximum [Member]
Equipment [Member]
Dec. 31, 2014
Maximum [Member]
Computer software [Member]
Dec. 31, 2014
Ala Tenn System [Member]
Dec. 31, 2013
Ala Tenn System [Member]
Dec. 31, 2014
Gathering And Processing [Member]
Dec. 31, 2013
Gathering And Processing [Member]
Property, Plant and Equipment [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Insurance settlements receivable
 
 
$ 1,100,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Loss on impairment of noncurrent assets held for sale
700,000 
673,000 
2,400,000 
0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
600,000 
1,800,000 
Property, Plant and Equipment, Net [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Property plant and equipment in useful life
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4 years 
8 years 
5 years 
4 years 
20 years 
20 years 
8 years 
40 years 
40 years 
40 years 
20 years 
40 years 
40 years 
20 years 
5 years 
 
 
 
 
Property plant and equipment gross
 
698,017,000 
407,800,000 
 
5,282,000 
6,015,000 
77,551,000 
6,443,000 
1,108,000 
1,108,000 
6,905,000 
5,109,000 
80,141,000 
97,106,000 
452,180,000 
239,865,000 
24,227,000 
11,955,000 
8,072,000 
7,942,000 
30,079,000 
22,432,000 
8,952,000 
6,294,000 
3,520,000 
3,531,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
101,900,000 
100,500,000 
 
 
Accumulated depreciation
 
(115,835,000)
(95,099,000)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Property, plant and equipment, net
 
582,182,000 
312,701,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest Costs Capitalized
 
800,000 
200,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Depreciation
 
$ 23,900,000 
$ 25,900,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Property, Plant and Equipment, Net (Asset Impairments and Insurance Proceeds) (Details) (USD $)
3 Months Ended 12 Months Ended
Dec. 31, 2014
Sep. 30, 2014
Dec. 31, 2013
Jun. 30, 2013
Mar. 31, 2013
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Property, Plant and Equipment [Line Items]
 
 
 
 
 
 
 
 
Loss on impairment of property, plant and equipment
$ 99,900,000 
 
$ 3,000,000 
$ 15,200,000 
$ 100,000 
$ 99,892,000 
$ 18,155,000 
$ 0 
Discount rate
9.50% 
 
 
 
 
10.00% 
10.00% 
 
Impairment of long lived assets
 
700,000 
 
 
 
673,000 
2,400,000 
0 
Insurance settlements receivable
 
 
 
 
 
 
1,100,000 
 
Insurance proceeds from involuntary conversion of property, plant and equipment
 
 
 
600,000 
500,000 
0 
482,000 
527,000 
Gain (loss) on involuntary conversion of property, plant and equipment
 
 
 
 
400,000 
0 
343,000 
(1,021,000)
Fair Value, Inputs, Level 3 [Member] |
Income Approach Valuation Technique [Member]
 
 
 
 
 
 
 
 
Property, Plant and Equipment [Line Items]
 
 
 
 
 
 
 
 
Throughput volume decline rate
 
 
 
 
 
 
2.50% 
 
Discontinued Operations [Member]
 
 
 
 
 
 
 
 
Property, Plant and Equipment [Line Items]
 
 
 
 
 
 
 
 
Impairment of long lived assets
 
400,000 
 
 
 
 
 
 
Gathering And Processing [Member]
 
 
 
 
 
 
 
 
Property, Plant and Equipment [Line Items]
 
 
 
 
 
 
 
 
Impairment of long lived assets
 
 
 
 
 
$ 600,000 
$ 1,800,000 
 
Goodwill and Intangible assets (Details) (USD $)
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Goodwill [Line Items]
 
 
Goodwill
$ 142,236,000 
$ 16,447,000 
Useful life
25 years 
 
Amortization of Intangible Assets
4,100,000 
3,700,000 
Finite-lived intangible assets, amortization expense, next twelve months
5,300,000 
 
Finite-Lived Intangible Assets, Amortization Expense, Year Two
4,300,000 
 
Finite-Lived Intangible Assets, Amortization Expense, Year Three
4,300,000 
 
Finite-Lived Intangible Assets, Amortization Expense, Year Four
4,300,000 
 
Finite-Lived Intangible Assets, Amortization Expense, Year Five
4,300,000 
 
Gathering And Processing [Member]
 
 
Goodwill [Line Items]
 
 
Goodwill
125,900,000 
 
Terminals [Member]
 
 
Goodwill [Line Items]
 
 
Goodwill
$ 16,300,000 
 
Minimum [Member]
 
 
Goodwill [Line Items]
 
 
Useful life
0 years 5 months 0 days 
 
Maximum [Member]
 
 
Goodwill [Line Items]
 
 
Useful life
30 years 
 
Goodwill and Intangible assets Schedule of intangible assets (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Finite-Lived Intangible Assets [Line Items]
 
 
Gross carrying amount
$ 118,851 
$ 12,101 
Accumulated amortization
(12,545)
(8,419)
Net carrying amount
106,306 
3,682 
Customer Contracts [Member]
 
 
Finite-Lived Intangible Assets [Line Items]
 
 
Gross carrying amount
12,101 
12,101 
Accumulated amortization
(11,110)
(8,419)
Net carrying amount
991 
3,682 
Customer Relationships [Member]
 
 
Finite-Lived Intangible Assets [Line Items]
 
 
Gross carrying amount
53,400 
0 
Accumulated amortization
(553)
0 
Net carrying amount
52,847 
0 
Dedicated Acreage [Member]
 
 
Finite-Lived Intangible Assets [Line Items]
 
 
Gross carrying amount
53,350 
0 
Accumulated amortization
(882)
0 
Net carrying amount
$ 52,468 
$ 0 
Accrued Expenses and Other Current Liabilities (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Payables and Accruals [Abstract]
 
 
Accrued capital expenditures
$ 17,134 
$ 2,562 
Accrued expenses
7,036 
5,412 
Gas imbalances payable
1,069 
4,305 
Other
549 
2,779 
Accrued expenses and other current liabilities
$ 25,788 
$ 15,058 
Asset Retirement Obligation (Details) (USD $)
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]
 
 
Restricted Cash and Cash Equivalents
$ 5,000,000 
$ 3,000,000 
Balance at beginning of period
34,636,000 
8,319,000 
Additions
248,000 
25,763,000 
Expenditures
(1,030,000)
0 
Accretion expense
791,000 
554,000 
Balance at end of period
$ 34,645,000 
$ 34,636,000 
Debt Obligations (Outstanding Borrowings) (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Debt Disclosure [Abstract]
 
 
Revolving credit facility
$ 372,950 
$ 130,735 
Other debt
2,908 
2,048 
Total debt
375,858 
132,783 
Less: current portion
2,908 
2,048 
Long-term debt
$ 372,950 
$ 130,735 
Debt Obligations (Textual) (Details) (USD $)
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Debt Instrument [Line Items]
 
 
 
Line of credit facility, amount outstanding limit
$ 500,000,000 
 
 
Unused capacity, commitment fee percentage
0.50% 
 
 
Ratio of indebtedness to net capital
4.44 
 
 
Interest coverage ratio
13.4 
 
 
Debt, weighted average interest rate
3.80% 
4.53% 
4.09% 
Letters of credit outstanding amount
1,600,000 
4,800,000 
 
Revolving credit facility
372,950,000 
130,735,000 
 
Proceeds from (payments for) other financing activities
3,300,000 
 
 
Periodic payment
400,000 
 
 
Debt issuance cost
10,400,000 
 
 
Gains on extinguishment of debt
$ 700,000 
 
 
Minimum [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Interest coverage ratio
2.50 
 
 
Maximum [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Ratio of indebtedness to net capital
4.75 
 
 
Ratio of indebtedness to net capital, after allowed acquisition
5.25 
 
 
Federal Funds [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Facility fee (percent)
0.50% 
 
 
Eurodollar [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Facility fee (percent)
1.00% 
 
 
Insurance Premium Financing [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Facility fee (percent)
3.95% 
 
 
Fiscal Quarter Ending December 31, 2014 [Member] |
Fourth Amendment [Member] |
Base Rate [Member] |
Minimum [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Basis spread on variable rate
2.00% 
 
 
Fiscal Quarter Ending December 31, 2014 [Member] |
Fourth Amendment [Member] |
Base Rate [Member] |
Maximum [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Basis spread on variable rate
3.25% 
 
 
Fiscal Quarter Ending December 31, 2014 [Member] |
Fourth Amendment [Member] |
Eurodollar [Member] |
Minimum [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Basis spread on variable rate
1.00% 
 
 
Fiscal Quarter Ending December 31, 2014 [Member] |
Fourth Amendment [Member] |
Eurodollar [Member] |
Maximum [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Basis spread on variable rate
2.25% 
 
 
Partners' Capital (Units Outstanding) (Details)
Dec. 31, 2014
Dec. 31, 2013
Aug. 9, 2013
Dec. 31, 2012
Limited partner common units
22,670,000 
7,414,000 
 
 
General partner units
392,000 
185,000 
 
 
AIM Midstream Holdings No. of units outstanding [Member]
 
 
 
 
Preferred units outstanding
 
 
 
0 
Limited partner common units
22,670,000 
7,414,000 
 
4,639,000 
Limited partner subordinated units
0 
0 
4,526,066 
4,526,000 
General partner units
392,000 
185,000 
 
185,000 
Series A
 
 
 
 
Preferred units outstanding
5,745,000 
5,279,000 
 
 
Series B
 
 
 
 
Preferred units outstanding
1,255,000 
0 
 
0 
Partners Capital (Details Textual) (USD $)
0 Months Ended 3 Months Ended 12 Months Ended 12 Months Ended 0 Months Ended 3 Months Ended 0 Months Ended 3 Months Ended 12 Months Ended 0 Months Ended 0 Months Ended 12 Months Ended 12 Months Ended 0 Months Ended
Jan. 29, 2014
Dec. 31, 2014
Jun. 30, 2014
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Aug. 20, 2014
Feb. 5, 2014
Jan. 29, 2014
Dec. 11, 2013
Dec. 31, 2014
Series B
Dec. 31, 2014
General Partner Interest
Dec. 31, 2013
General Partner Interest
Dec. 31, 2012
General Partner Interest
Dec. 31, 2014
General Partner [Member]
Feb. 5, 2014
AIM Midstream Holdings [Member]
Feb. 5, 2014
High Point [Member]
Apr. 15, 2013
Series A
Apr. 15, 2013
Series A
Cash Distribution [Member]
Apr. 15, 2013
Issuance of Preferred Units [Member]
Series A
High Point [Member]
Dec. 31, 2014
Partnership Interest [Member]
Dec. 31, 2013
Partnership Interest [Member]
Aug. 9, 2013
Partnership Interest [Member]
Dec. 31, 2012
Partnership Interest [Member]
Apr. 15, 2013
Partnership Interest [Member]
High Point [Member]
AIM Midstream Holdings [Member]
Dec. 31, 2014
High Point [Member]
Sep. 30, 2014
High Point [Member]
Dec. 31, 2014
High Point [Member]
Dec. 31, 2013
High Point [Member]
Oct. 14, 2014
Costar Midstream, L.L.C. [Member]
Apr. 15, 2013
High Point [Member]
Apr. 15, 2013
Fourth Amendment [Member]
Revolving Credit Facility [Member]
Series A
Dec. 31, 2014
Series A
Dec. 31, 2014
Series B
Dec. 31, 2013
Series B
Dec. 31, 2012
Series B
Jan. 31, 2014
Series B
Dec. 31, 2014
Series B
Dec. 31, 2014
Dividend Paid [Member]
Series B
Oct. 14, 2014
Limited Partner [Member]
Costar Midstream, L.L.C. [Member]
Subsidiary, Sale of Stock [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Paid in Kind
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 3,200,000 
 
 
 
 
 
 
 
General partner interest
 
 
 
1.30% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Limited partner interest
 
 
 
98.70% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Limited partners, units issued
 
22,670,000 
 
22,670,000 
7,414,000 
 
4,622,352 
 
3,400,000 
2,568,712 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,168,225 
 
86,461 
 
Partners' Capital Account, Private Placement of Units
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2,200,000 
 
 
Partnership cancellation of subordinated units (percent)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
90.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Consideration for Issuance of Preferred Units
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
15,000,000 
 
 
 
 
 
 
 
 
 
Contributed capital
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
5,142,857 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Transaction expenses
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2,500,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Payments on long-term debt
 
 
 
(250,870,000)
(131,571,000)
(59,230,000)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(12,500,000)
 
 
 
 
 
 
 
 
Earned and paid (usd per unit)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 0.25 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Incentive Distribution, Distribution Per Unit
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 0.4125 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distribution made to member or limited partner, distributions paid, conversion price per unit
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 17.50 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair value, paid in kind distributions
 
3,200,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Ownership Interests, Units Outstanding
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0 
0 
4,526,066 
4,526,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Incentive Distribution Right Allocation
 
 
 
 
 
 
 
 
 
 
 
 
 
 
14.98% 
 
 
 
 
 
 
 
 
 
 
100.00% 
100.00% 
85.02% 
85.02% 
 
 
 
 
 
 
 
 
 
 
 
Incentive Distribution Right, After Minimum Quarterly Distributions, Percent
 
 
 
 
 
 
 
 
 
 
 
 
 
 
48.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Partners' Capital Account, Percentage
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
5.00% 
95.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Class of Warrant or Right, Number of Securities Called by Warrants or Rights
 
 
 
 
 
 
 
300,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Class of Warrant or Right, Exercise Price of Warrants or Rights
 
 
 
 
 
 
 
$ 0.01 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Limited partner common units
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
147,296,000 
 
 
 
 
 
 
 
 
 
6,900,000 
Sale of Stock, Price Per Share
 
$ 22.47 
 
$ 22.47 
 
 
$ 25.8075 
 
$ 26.75 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distribution declared per common unit (a)
 
 
$ 0.4625 
$ 1.85 
$ 1.75 
$ 1.73 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Issuance of common units, net of offering costs
86,900,000 
119,300,000 
 
204,255,000 
54,853,000 
0 
 
 
 
 
0 
0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(30,000,000)
0 
0 
 
 
 
 
Partners' Capital Account, Contributions
 
 
 
 
 
 
 
 
 
 
$ 0 
$ 5,678,000 
$ 12,500,000 
$ 13,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
General partners' interest units issued
 
392,000 
 
392,000 
185,000 
 
 
 
 
 
 
206,810 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Payment in Kind, Units Issued
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
555,000 
86,000 
 
 
 
 
 
 
Partners' Capital Cash Distributions (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Class of Stock [Line Items]
 
 
 
Distributions
$ 28,009 
$ 16,120 
$ 16,070 
Preferred Partner [Member] |
Series A
 
 
 
Class of Stock [Line Items]
 
 
 
Distributions
2,658 
2,375 
0 
Limited Partner [Member]
 
 
 
Class of Stock [Line Items]
 
 
 
Distributions
22,656 
8,207 
7,919 
Limited Party, Subordinated [Member]
 
 
 
Class of Stock [Line Items]
 
 
 
Distributions
0 
5,073 
7,830 
General Partner [Member]
 
 
 
Class of Stock [Line Items]
 
 
 
Distributions
333 
284 
321 
General Partner, Incentive Distribution Rights [Member]
 
 
 
Class of Stock [Line Items]
 
 
 
Distributions
$ 2,362 
$ 181 
$ 0 
Earnings per Unit (Details) (USD $)
In Thousands, except Per Share data, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2014
Sep. 30, 2014
Jun. 30, 2014
Mar. 31, 2014
Dec. 31, 2013
Sep. 30, 2013
Jun. 30, 2013
Mar. 31, 2013
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Net income (loss) from continuing operations
$ (94,261)
$ (2,397)
$ (1,095)
$ 558 
$ (5,018)
$ (2,526)
$ (20,057)
$ (3,392)
$ (97,195)
$ (30,993)
$ (6,234)
Net Income (loss) attributable to noncontrolling interests
 
 
 
 
 
 
 
 
214 
633 
256 
Net income (loss) from continuing operations attributable to the Partnership
 
 
 
 
 
 
 
 
(97,409)
(31,626)
(6,490)
Distributions on Series A preferred units
 
 
 
 
 
 
 
 
14,492 
24,117 
0 
Distributions
 
 
 
 
 
 
 
 
28,009 
16,120 
16,070 
General partner's share in undistributed loss
 
 
 
 
 
 
 
 
(1,820)
(1,708)
(458)
Net income (loss) from continuing operations available to limited partners
 
 
 
 
 
 
 
 
(114,995)
(53,783)
(6,354)
Net income (loss) from discontinued operations available to limited partners
 
 
 
 
 
 
 
 
(603)
(2,051)
(18)
Net income (loss) available to limited partners
 
 
 
 
 
 
 
 
(115,598)
(55,834)
(6,372)
Weighted average number of units used in computation of limited partners' net income (loss) per unit (basic and diluted)
 
 
 
 
 
 
 
 
13,472 
7,525 
9,113 
Limited partners' net income (loss) from continuing operations per unit (basic and diluted)
$ (4.98)
$ (0.58)
$ (0.55)
$ (0.31)
$ (1.43)
$ (0.81)
$ (4.01)
$ (0.39)
$ (8.54)
$ (7.15)
$ (0.70)
Limited partners' net income (loss) from discontinued operations per unit (basic and diluted)
$ 0.00 
$ 0.00 
$ (0.04)
$ (0.01)
$ 0.00 
$ 0.01 
$ (0.20)
$ 0.01 
$ (0.04)
$ (0.27)
$ 0.00 
Limited partners’ net income (loss) per unit (basic and diluted)
$ (4.98)
$ (0.58)
$ (0.59)
$ (0.32)
$ (1.43)
$ (0.80)
$ (4.21)
$ (0.38)
$ (8.58)
$ (7.42)
$ (0.70)
Series B
 
 
 
 
 
 
 
 
 
 
 
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Distributions
 
 
 
 
 
 
 
 
2,220 
0 
0 
Blackwater [Member]
 
 
 
 
 
 
 
 
 
 
 
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Net income (loss) from continuing operations
 
 
 
 
 
 
 
 
0 
(716)
0 
General Partner [Member]
 
 
 
 
 
 
 
 
 
 
 
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Distributions
 
 
 
 
 
 
 
 
2,913 
623 
322 
General Partner [Member] |
Dividend Declared [Member]
 
 
 
 
 
 
 
 
 
 
 
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Distributions
 
 
 
 
 
 
 
 
$ 2,694 
$ 464 
$ 322 
Long-Term Incentive Plan (Unit-based Awards) (Details) (USD $)
In Thousands, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding
 
 
Outstanding at beginning of period
75,529 
 
Granted
188,946 
 
Forfeited
(12,009)
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period
(51,334)
 
Outstanding at end of period
201,132 
 
Share-based Compensation Arrangements by Share-based Payment Award, Options, Grants in Period, Weighted Average Exercise Price
$ 20.80 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures and Expirations in Period, Weighted Average Exercise Price
$ 18.28 
 
Share-based Compensation Arrangements by Share-based Payment Award, Options, Exercises in Period, Weighted Average Exercise Price
$ 20.89 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price
$ 19.73 
$ 17.62 
Long Term Incentive Plan (Textual) (Details) (USD $)
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Jul. 11, 2012
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
 
 
 
 
Equity compensation expense
$ 1,536,000 
$ 2,094,000 
$ 1,783,000 
 
Long-term incentive plan, increase in available awards
 
 
 
871,750 
Long term incentive plan available for future grant
688,976 
855,089 
920,193 
 
Grants issued under long term incentive plan
25.00% 
 
 
 
Total fair value of vested units
1,400,000 
2,200,000 
1,900,000 
 
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized
$ 3,100,000 
$ 900,000 
$ 1,400,000 
 
Weighted average period cost recognized
3 years 0 months 
 
 
 
Post-Employment Benefits (Changes in Benefit Obligation) (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Change in plan assets
 
 
Funded status
$ 1,029 
$ 996 
Defined Benefit Plan, Plan Amendments
0 
126 
Change in Benefit Obligation [Member]
 
 
Change in benefit obligation
 
 
Obligation, beginning of period
532 
472 
Service cost
2 
5 
Interest cost
24 
15 
Actuarial (gain) loss
122 
(29)
Benefits paid
(25)
(57)
Benefit obligationm, ending
655 
532 
Change in plan assets
 
 
Benefits paid
(25)
(57)
Change in Plan Assets [Member]
 
 
Change in benefit obligation
 
 
Benefits paid
(38)
(61)
Change in plan assets
 
 
Fair value of plan assets, beginning of period
1,528 
1,552 
Actual return on plan assets
104 
(53)
Employer's contributions
90 
90 
Benefits paid
(38)
(61)
Fair value of plan assets, ending
$ 1,684 
$ 1,528 
Post-Employment Benefits (Plan Assets Recognized) (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Defined Benefit Plan, Amortization of Net Gains (Losses)
$ 0 
$ (100)
$ (100)
OPEB Plan [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Defined Benefit Plan, Amortization of Net Gains (Losses)
$ 5 
$ 23 
$ 43 
Post-Employment Benefits (Net Periodic Benefit Cost) (Details) (USD $)
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year
$ 100,000 
 
 
Cost recognized in Consolidated Statements of Operations
 
 
 
Defined Benefit Plan, Amortization of Net Gains (Losses)
0 
100,000 
100,000 
Net periodic (benefit) cost
(45,000)
(73,000)
(88,000)
OPEB Plan [Member]
 
 
 
Cost recognized in Consolidated Statements of Operations
 
 
 
Service cost
2,000 
5,000 
4,000 
Interest cost
24,000 
15,000 
18,000 
Expected return on plan assets
(70,000)
(70,000)
(67,000)
Amortization of prior service cost
4,000 
0 
0 
Defined Benefit Plan, Amortization of Net Gains (Losses)
(5,000)
(23,000)
(43,000)
Net periodic (benefit) cost
(45,000)
(73,000)
(88,000)
Net loss (gain)
102,000 
247,000 
64,000 
Total recognized in other comprehensive income
102,000 
247,000 
64,000 
Total recognized in net periodic benefit cost and other comprehensive income
$ 57,000 
$ 174,000 
$ (24,000)
Post-Employment Benefits (Economic Assumptions) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
 
 
Effect of one percentage point increase in assumed medical and dental care trend
$ 0.1 
 
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate
3.00% 
4.50% 
OPEB Plan [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Discount rate
3.73% 
4.57% 
Expected return on plan assets
2.50% 
4.50% 
Post-Employment Benefits (Expected Future Benefit Payments) (Details) (OPEB Plan [Member], USD $)
12 Months Ended
Dec. 31, 2014
OPEB Plan [Member]
 
Defined Benefit Plan Disclosure [Line Items]
 
2015
$ 33,000 
2016
32,000 
2017
32,000 
2018
32,000 
2019
31,000 
Five years thereafter
194,000 
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year
$ 100,000 
Post-Employment Benefits (Weighted Average Asset Allocation) (Details)
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Weighted average asset allocation (as a percent)
100.00% 
100.00% 
100.00% 
Fixed Income [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Weighted average asset allocation (as a percent)
70.00% 1
70.10% 1
72.20% 1
Cash and Short Term Assets [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Weighted average asset allocation (as a percent)
30.00% 2
29.90% 2
27.80% 2
Post-Employment Benefits (Details Textual) (USD $)
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Defined Benefit Plan, Amortization of Net Gains (Losses)
$ 0 
$ (100,000)
$ (100,000)
OPEB Plan [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year
100,000 
 
 
Defined Benefit Plan, Amortization of Net Gains (Losses)
$ 5,000 
$ 23,000 
$ 43,000 
Income Tax (Details) (USD $)
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Operating Loss Carryforwards [Line Items]
 
 
 
Current deferred tax asset
$ 3,086,000 
$ 0 
 
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest
(96,638,000)
(31,488,000)
(6,234,000)
Current Income Tax Expense (Benefit)
(10,000)
0 
 
Deferred Income Tax Expense (Benefit)
(547,000)
495,000 
 
Effective Income Tax Rate, Continuing Operations
0.60% 
1.60% 
 
Effective income tax rate, continuing operations
34.00% 
34.00% 
 
Operating Loss Carryforwards
10,700,000 
 
 
Operating Loss Carryforwards
4,173,000 
5,455,000 
 
Deferred Tax Assets, Other
213,000 
182,000 
 
Deferred Tax Assets, Gross
4,386,000 
5,637,000 
 
Deferred Tax Liabilities, Property, Plant and Equipment
9,112,000 
9,022,000 
 
Deferred Tax Liabilities, Intangible Assets
387,000 
1,364,000 
 
Deferred Tax Liabilities, Gross
9,499,000 
10,386,000 
 
Income Tax Reconciliation, Income Tax Expense (Benefit), at Federal Statutory Income Tax Rate
32,857,000 
10,706,000 
 
Effective Income Tax Rate Reconciliation, Tax Exempt Income
(33,216,000)
(10,296,000)
 
Income Tax Reconciliation, Other Adjustments
0 
222,000 
 
Current State and Local Tax Expense (Benefit)
(159,000)
71,000 
 
Income Tax Reconciliation, Prior Year Income Taxes
(37,000)
(175,000)
 
Income Tax Reconciliation, Other Reconciling Items
(2,000)
(33,000)
 
Income Tax Expense (Benefit), Continuing Operations
(557,000)
495,000 
0 
Deferred Tax Liabilities, Net
(8,199,000)
(4,749,000)
 
Deferred Tax Assets, Net
$ (5,113,000)
$ (4,749,000)
 
2012
 
 
 
Operating Loss Carryforwards [Line Items]
 
 
 
Margin tax rate
0.95% 
 
 
2013
 
 
 
Operating Loss Carryforwards [Line Items]
 
 
 
Margin tax rate
0.975% 
 
 
2014
 
 
 
Operating Loss Carryforwards [Line Items]
 
 
 
Margin tax rate
1.00% 
 
 
Commitments and Contingencies (Contractual Obligations) (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2014
Future Non Cancelable Commitment [Line Items]
 
2015
$ 3,428 
2016
9,088 
2017
1,421 
2018
1,306 
2019
1,525 
Thereafter
30,706 
Total
47,474 
Operating leases and service contract [Member]
 
Future Non Cancelable Commitment [Line Items]
 
2015
3,428 
2016
2,204 
2017
1,421 
2018
1,306 
2019
1,525 
Thereafter
2,945 
Total
12,829 
ARO [Member]
 
Future Non Cancelable Commitment [Line Items]
 
2015
0 
2016
6,884 
2017
0 
2018
0 
2019
0 
Thereafter
27,761 
Total
$ 34,645 
Commitments and Contingencies (Details Textual) (USD $)
In Millions, except Share data, unless otherwise specified
12 Months Ended 3 Months Ended 12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Feb. 5, 2014
Feb. 5, 2014
High Point [Member]
Feb. 5, 2014
AIM Midstream Holdings [Member]
Dec. 31, 2014
High Point [Member]
Sep. 30, 2014
High Point [Member]
Dec. 31, 2014
High Point [Member]
Dec. 31, 2013
High Point [Member]
Loss Contingencies [Line Items]
 
 
 
 
 
 
 
 
 
 
Partners' Capital Account, Percentage
 
 
 
 
95.00% 
5.00% 
 
 
 
 
Incentive Distribution Right Allocation
 
 
 
 
 
 
100.00% 
100.00% 
85.02% 
85.02% 
Class of Warrant or Right, Number of Securities Called by Warrants or Rights
 
 
 
300,000 
 
 
 
 
 
 
Class of Warrant or Right, Exercise Price of Warrants or Rights
 
 
 
$ 0.01 
 
 
 
 
 
 
Loss Contingency, Damages Sought
1.0 
 
 
 
 
 
 
 
 
 
Operating leases
$ 5.8 
$ 1.1 
$ 0.9 
 
 
 
 
 
 
 
Related- Party Transactions (Details Textual) (USD $)
12 Months Ended 12 Months Ended 3 Months Ended 0 Months Ended 12 Months Ended 12 Months Ended 0 Months Ended 12 Months Ended 0 Months Ended 12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Aug. 20, 2014
Jan. 29, 2014
Dec. 11, 2013
Oct. 9, 2012
Dec. 31, 2014
American Midstream, LLC [Member]
Dec. 31, 2013
American Midstream, LLC [Member]
Dec. 31, 2012
American Midstream, LLC [Member]
Apr. 15, 2013
High Point [Member]
Apr. 15, 2013
High Point [Member]
Issuance of Preferred Units [Member]
Series A
Apr. 15, 2013
Revolving Credit Facility [Member]
Fourth Amendment [Member]
Series A
Dec. 17, 2013
Blackwater [Member]
Dec. 31, 2014
Blackwater [Member]
Dec. 31, 2013
Blackwater [Member]
Dec. 31, 2012
Blackwater [Member]
Dec. 17, 2013
Blackwater [Member]
Apr. 15, 2013
Blackwater [Member]
Dec. 31, 2014
Limited Partner [Member]
Dec. 31, 2013
Limited Partner [Member]
Dec. 31, 2012
Limited Partner [Member]
Dec. 17, 2013
Limited Partner [Member]
Blackwater [Member]
Dec. 31, 2014
Series B
Dec. 31, 2013
Series B
Dec. 31, 2012
Series B
Jan. 31, 2014
Series B
Jan. 31, 2014
Series B
Dec. 31, 2014
Series B
Related Party Transactions (Textual) [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Administrative and operational service expenses
 
 
 
 
 
 
 
$ 23,500,000 
$ 14,200,000 
$ 12,500,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cost of business development activities
 
 
 
 
 
 
 
(1,200,000)
1,800,000 
400,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Management Fees Revenue
900,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Notes Payable, Related Parties, Current
 
 
 
 
 
 
20,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Consideration for Issuance of Preferred Units
 
 
 
 
 
 
 
 
 
 
15,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Contributed capital
 
 
 
 
 
 
 
 
 
 
 
5,142,857 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Transaction expenses
 
 
 
 
 
 
 
 
 
 
 
2,500,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Payments on long-term debt
(250,870,000)
(131,571,000)
(59,230,000)
 
 
 
 
 
 
 
 
 
(12,500,000)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total identifiable net assets
 
 
 
 
 
 
 
 
 
 
61,930,000 
 
 
 
 
 
 
 
22,700,000 
 
 
 
 
 
 
 
 
 
 
Purchase price of business
 
 
 
 
 
 
 
 
 
 
 
 
 
63,900,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distributions
28,009,000 
16,120,000 
16,070,000 
 
 
 
 
 
 
 
 
 
 
 
0 
27,650,000 
0 
 
 
39,150,000 
21,628,000 
15,748,000 
 
2,220,000 
0 
0 
 
 
 
Units issued in business acquisition
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
125,500 
 
 
 
 
 
 
 
 
 
 
 
General Partner Noncash Distributions
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3,052,000 
 
 
 
 
 
 
Limited partners, units issued
22,670,000 
7,414,000 
 
4,622,352 
3,400,000 
2,568,712 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,168,225 
 
 
Issuance of Series B Units
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 0 
 
 
 
 
 
 
 
$ 30,000,000 
$ 32,220,000 
Reporting Segments (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2014
Sep. 30, 2014
Jun. 30, 2014
Mar. 31, 2014
Dec. 31, 2013
Sep. 30, 2013
Jun. 30, 2013
Mar. 31, 2013
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Segment information
 
 
 
 
 
 
 
 
 
 
 
Revenue, net
 
 
 
 
 
 
 
 
$ 307,309 
$ 294,051 
$ 204,868 
Derivative, Gain (Loss) on Derivative, Net
 
 
 
 
 
 
 
 
1,091 
28 
3,400 
Total revenue
80,177 
70,305 
77,680 
80,238 
76,770 
77,519 
77,191 
62,599 
308,400 
294,079 
208,268 
Direct operating expenses
 
 
 
 
 
 
 
 
(45,702)
(32,236)
(17,183)
Purchases of natural gas, NGLs and condensate
 
 
 
 
 
 
 
 
197,952 
215,053 
154,472 
Selling, general and administrative expenses
 
 
 
 
 
 
 
 
(23,103)
(19,079)
(14,309)
Advisory services agreement termination fee
 
 
 
 
 
 
 
 
 
 
(6,252)
Allocated Share-based Compensation Expense
 
 
 
 
 
 
 
 
(1,536)
(2,094)
(1,783)
Depreciation and Accretion Expense, Including Discontinued Operation
 
 
 
 
 
 
 
 
28,832 
29,999 
21,414 
Depreciation, Depletion and Amortization
 
 
 
 
 
 
 
 
(28,832)
(30,002)
(21,287)
Gross Profit
36,227 
21,332 
22,167 
23,081 
22,891 
20,908 
18,317 
12,705 
102,807 
74,821 
209,034 
Costs and Expenses
 
 
 
 
 
 
 
 
297,125 
298,464 
 
Gain (loss) on acquisition of assets
 
 
 
 
 
 
 
 
 
 
49,431 
Gain (loss) on involuntary conversion of property, plant and equipment
 
 
 
 
 
 
 
400 
0 
343 
(1,021)
Loss on impairment of property, plant and equipment
 
 
 
 
 
 
 
 
(122)
0 
123 
Other expense
 
 
 
 
 
 
 
 
(670)
0 
0 
Loss on impairment of property, plant and equipment
99,900 
 
 
 
3,000 
 
15,200 
100 
99,892 
18,155 
0 
Interest expense
 
 
 
 
 
 
 
 
7,577 
9,291 
4,570 
Earnings in unconsolidated affiliates
 
 
 
 
 
 
 
 
348 
0 
0 
Income Tax Expense (Benefit), Continuing Operations
 
 
 
 
 
 
 
 
557 
(495)
0 
Net income (loss)
 
 
 
 
 
 
 
 
(97,806)
(33,406)
(6,252)
Gain (loss) from operations of disposal groups, net of tax
(29)
(26)
(506)
(50)
(523)
(15)
(1,869)
(6)
(611)
(2,413)
(18)
Less: Comprehensive income (loss) attributable to noncontrolling interests
 
 
 
 
 
 
 
 
214 
633 
256 
Net income (loss)
(94,297)
(2,456)
(1,667)
400 
(5,641)
(2,731)
(22,114)
(3,553)
(98,020)
(34,039)
(6,508)
Gathering And Processing [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment information
 
 
 
 
 
 
 
 
 
 
 
Revenue, net
 
 
 
 
 
 
 
 
203,616 
205,179 
152,339 
Derivative, Gain (Loss) on Derivative, Net
 
 
 
 
 
 
 
 
1,091 
28 
3,400 
Total revenue
 
 
 
 
 
 
 
 
204,707 
205,207 
155,739 
Direct operating expenses
 
 
 
 
 
 
 
 
(23,783)
(14,574)
(12,152)
Purchases of natural gas, NGLs and condensate
 
 
 
 
 
 
 
 
152,690 
168,574 
117,956 
Gross Profit
 
 
 
 
 
 
 
 
50,817 
36,985 
36,118 
Transmission [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment information
 
 
 
 
 
 
 
 
 
 
 
Revenue, net
 
 
 
 
 
 
 
 
88,189 
79,041 
52,529 
Derivative, Gain (Loss) on Derivative, Net
 
 
 
 
 
 
 
 
0 
0 
0 
Total revenue
 
 
 
 
 
 
 
 
88,189 
79,041 
52,529 
Direct operating expenses
 
 
 
 
 
 
 
 
(15,577)
(13,259)
(5,031)
Purchases of natural gas, NGLs and condensate
 
 
 
 
 
 
 
 
45,262 
46,479 
36,516 
Gross Profit
 
 
 
 
 
 
 
 
42,828 
32,408 
13,313 
Terminals [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment information
 
 
 
 
 
 
 
 
 
 
 
Revenue, net
 
 
 
 
 
 
 
 
 
9,831 
 
Derivative, Gain (Loss) on Derivative, Net
 
 
 
 
 
 
 
 
0 
0 
 
Total revenue
 
 
 
 
 
9,800 
 
 
15,504 
 
 
Business Acquisition, Pro Forma Revenue
 
 
 
 
 
 
 
 
 
9,831 
 
Direct operating expenses
 
 
 
 
 
 
 
 
(6,342)
(4,403)
 
Purchases of natural gas, NGLs and condensate
 
 
 
 
 
 
 
 
0 
0 
 
Gross Profit
 
 
 
 
 
 
 
 
9,162 
5,428 
 
Commodity Contract [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment information
 
 
 
 
 
 
 
 
 
 
 
Unrealized gain (loss) on commodity derivatives
 
 
 
 
 
 
 
 
595 
(1,495)
992 
Gain (Loss) on Derivative Instruments [Member] |
Commodity Contract [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment information
 
 
 
 
 
 
 
 
 
 
 
Unrealized gain (loss) on commodity derivatives
 
 
 
 
 
 
 
 
356 
(1,041)
992 
Terminals [Member] |
Terminals [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment information
 
 
 
 
 
 
 
 
 
 
 
Revenue, net
 
 
 
 
 
 
 
 
$ 15,504 
 
 
Reporting Segments Reporting Segment (Revenue Earned from Customers that Exceed 10%) (Details)
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Segment Reporting Information [Line Items]
 
 
 
Entity-wide revenue by major customer, percentage
100.00% 
100.00% 
100.00% 
Customer A [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Entity-wide revenue by major customer, percentage
22.00% 
28.00% 
30.00% 
Customer B [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Entity-wide revenue by major customer, percentage
0.00% 
13.00% 
0.00% 
Customer D [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Entity-wide revenue by major customer, percentage
10.00% 
10.00% 
14.00% 
Customer Other [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Entity-wide revenue by major customer, percentage
56.00% 
37.00% 
43.00% 
Customer Concentration Risk [Member] |
Revenue [Member] |
Gathering And Processing [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Entity-wide revenue by major customer, percentage
100.00% 
100.00% 
100.00% 
Customer Concentration Risk [Member] |
Revenue [Member] |
Transmission [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Entity-wide revenue by major customer, percentage
100.00% 
100.00% 
100.00% 
Customer Concentration Risk [Member] |
Revenue [Member] |
Terminals [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Entity-wide revenue by major customer, percentage
100.00% 
100.00% 
0.00% 
Customer Concentration Risk [Member] |
Revenue [Member] |
Customer A [Member] |
Gathering And Processing [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Entity-wide revenue by major customer, percentage
33.00% 
43.00% 
40.00% 
Customer Concentration Risk [Member] |
Revenue [Member] |
Customer B [Member] |
Gathering And Processing [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Entity-wide revenue by major customer, percentage
12.00% 
19.00% 
11.00% 
Customer Concentration Risk [Member] |
Revenue [Member] |
Customer B [Member] |
Terminals [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Entity-wide revenue by major customer, percentage
20.00% 
17.00% 
 
Customer Concentration Risk [Member] |
Revenue [Member] |
Customer C [Member] |
Transmission [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Entity-wide revenue by major customer, percentage
43.00% 
39.00% 
50.00% 
Customer Concentration Risk [Member] |
Revenue [Member] |
Customer D [Member] |
Gathering And Processing [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Entity-wide revenue by major customer, percentage
0.00% 
0.00% 
12.00% 
Customer Concentration Risk [Member] |
Revenue [Member] |
Customer D [Member] |
Transmission [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Entity-wide revenue by major customer, percentage
16.00% 
16.00% 
22.00% 
Customer Concentration Risk [Member] |
Revenue [Member] |
Customer E [Member] |
Transmission [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Entity-wide revenue by major customer, percentage
0.00% 
0.00% 
10.00% 
Customer Concentration Risk [Member] |
Revenue [Member] |
Customer H [Member] |
Terminals [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Entity-wide revenue by major customer, percentage
11.00% 
13.00% 
 
Customer Concentration Risk [Member] |
Revenue [Member] |
Customer F [Member] |
Terminals [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Entity-wide revenue by major customer, percentage
19.00% 
20.00% 
 
Customer Concentration Risk [Member] |
Revenue [Member] |
Customer G [Member] |
Terminals [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Entity-wide revenue by major customer, percentage
15.00% 
16.00% 
 
Customer Concentration Risk [Member] |
Revenue [Member] |
Customer Other [Member] |
Gathering And Processing [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Entity-wide revenue by major customer, percentage
55.00% 
38.00% 
37.00% 
Customer Concentration Risk [Member] |
Revenue [Member] |
Customer Other [Member] |
Transmission [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Entity-wide revenue by major customer, percentage
41.00% 
45.00% 
18.00% 
Customer Concentration Risk [Member] |
Revenue [Member] |
Customer Other [Member] |
Terminals [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Entity-wide revenue by major customer, percentage
35.00% 
34.00% 
 
Reporting Segments Assets (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Segment Reporting Information [Line Items]
 
 
Total assets
$ 916,644 
$ 382,075 
Gathering And Processing [Member]
 
 
Segment Reporting Information [Line Items]
 
 
Total assets
686,395 
178,869 
Transmission [Member]
 
 
Segment Reporting Information [Line Items]
 
 
Total assets
132,767 
131,136 
Terminals [Member]
 
 
Segment Reporting Information [Line Items]
 
 
Total assets
71,180 
60,873 
Other Segments [Member]
 
 
Segment Reporting Information [Line Items]
 
 
Total assets
$ 26,302 
$ 11,197 
Quarterly Financial Data (Details) (USD $)
In Thousands, except Per Share data, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2014
Sep. 30, 2014
Jun. 30, 2014
Mar. 31, 2014
Dec. 31, 2013
Sep. 30, 2013
Jun. 30, 2013
Mar. 31, 2013
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Quarterly Financial Information Disclosure [Abstract]
 
 
 
 
 
 
 
 
 
 
 
Total revenue
$ 80,177 
$ 70,305 
$ 77,680 
$ 80,238 
$ 76,770 
$ 77,519 
$ 77,191 
$ 62,599 
$ 308,400 
$ 294,079 
$ 208,268 
Gross Profit
36,227 
21,332 
22,167 
23,081 
22,891 
20,908 
18,317 
12,705 
102,807 
74,821 
209,034 
Operating Income (Loss)
(91,633)
(290)
734 
2,450 
(2,591)
(104)
(17,841)
(1,661)
(88,739)
(22,197)
(1,664)
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest
(94,261)
(2,397)
(1,095)
558 
(5,018)
(2,526)
(20,057)
(3,392)
(97,195)
(30,993)
(6,234)
Gain (loss) from operations of disposal groups, net of tax
(29)
(26)
(506)
(50)
(523)
(15)
(1,869)
(6)
(611)
(2,413)
(18)
Net income (loss) attributable to noncontrolling interests
7 
33 
66 
108 
100 
190 
188 
155 
 
 
 
Net income (loss)
(94,297)
(2,456)
(1,667)
400 
(5,641)
(2,731)
(22,114)
(3,553)
(98,020)
(34,039)
(6,508)
Net Income (Loss) Allocated to General Partners
(1,232)
(32)
(22)
7 
(209)
(221)
(905)
(70)
 
 
 
Net Income (Loss) Allocated to Limited Partners
$ (93,065)
$ (2,424)
$ (1,645)
$ 393 
$ (5,433)
$ (2,510)
$ (21,209)
$ (3,482)
 
 
 
Limited partners’ net income (loss) per unit (basic and diluted)
$ (4.98)
$ (0.58)
$ (0.59)
$ (0.32)
$ (1.43)
$ (0.80)
$ (4.21)
$ (0.38)
$ (8.58)
$ (7.42)
$ (0.70)
Income (Loss) from Continuing Operations, Per Outstanding Limited Partnership Unit, Basic
$ (4.98)
$ (0.58)
$ (0.55)
$ (0.31)
$ (1.43)
$ (0.81)
$ (4.01)
$ (0.39)
$ (8.54)
$ (7.15)
$ (0.70)
Limited partners' net income (loss) from discontinued operations per unit (basic and diluted)
$ 0.00 
$ 0.00 
$ (0.04)
$ (0.01)
$ 0.00 
$ 0.01 
$ (0.20)
$ 0.01 
$ (0.04)
$ (0.27)
$ 0.00 
Subsequent Events Subsequent events (Details)
3 Months Ended 12 Months Ended 0 Months Ended
Jun. 30, 2014
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Jan. 22, 2015
Subsequent Event [Member]
Subsequent Event [Line Items]
 
 
 
 
 
Distribution declared per common unit (a)
$ 0.4625 
$ 1.85 
$ 1.75 
$ 1.73 
$ 0.4725 
Distribution Made to Limited Partner, Distributions Declared, Per Unit, Annualized Basis
 
 
 
 
$ 1.89