2014 Q3 10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 FORM 10-Q
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended
September 30, 2014
or
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from        to        
Commission File Number: 001-35257
 
 AMERICAN MIDSTREAM PARTNERS, LP
(Exact name of registrant as specified in its charter)
Delaware
27-0855785
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
 
 
1400 16th Street, Suite 310
 
Denver, CO
80202
(Address of principal executive offices)
(Zip code)
(720) 457-6060
(Registrant’s telephone number, including area code)
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  ý  Yes    ¨  No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  ý  Yes    ¨  No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
¨
Accelerated filer
ý
Non-accelerated filer
¨ (Do not check if a smaller reporting company)
Smaller reporting company
¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  ¨  Yes    ý  No
There were 15,775,018 common units, 5,585,611 Series A Units and 1,232,017 Series B Units of American Midstream Partners, LP outstanding as of November 6, 2014. Our common units trade on the New York Stock Exchange under the ticker symbol “AMID.”


TABLE OF CONTENTS
 
 
 
Page
Item 1.
 
 
 
 
 
 
 
 
 
Item 2.
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 3.
 
 
 
Item 4.
 
 
 
 
 
Item 1.
Item 1A.
Item 6.

2
Table of Contents

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

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

Bcf         One billion cubic feet.

Condensate
Liquid hydrocarbons present in casinghead gas that condense within the gathering system and are removed prior to delivery to the gas plant. This product is generally sold on terms more closely tied to crude oil pricing.

/d        Per day.

FERC         Federal Energy Regulatory Commission.

Fractionation    Process by which natural gas liquids are separated into individual components.

GAAP
Accounting principles generally accepted in the United States of America.

Gal         Gallons.

Mcf         One thousand cubic feet.

MMcf         One million cubic feet.

Mgal        One thousand gallons.

NGL or NGLs
Natural gas liquid(s): The combination of ethane, propane, normal butane, isobutane and natural gasoline that, when removed from natural gas, become liquid under various levels of higher pressure and lower temperature.

Throughput
The volume of natural gas transported or passing through a pipeline, plant, terminal or other facility during a particular period.

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

3
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PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
American Midstream Partners, LP and Subsidiaries
Condensed Consolidated Balance Sheets
(Unaudited, in thousands)
 
September 30,
2014
 
December 31,
2013
Assets
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
459

 
$
393

Accounts receivable
7,430

 
6,822

Unbilled revenue
21,271

 
23,001

Risk management assets
1,047

 
473

Other current assets
4,715

 
7,497

Current assets held for sale
29

 
272

Total current assets
34,951

 
38,458

Property, plant and equipment, net
415,799

 
312,701

Goodwill
16,253

 
16,447

Intangible assets, net
45,585

 
3,682

Investment in unconsolidated affiliate
11,017

 
—

Other assets, net
11,195

 
9,064

Noncurrent assets held for sale, net
1,164

 
1,723

Total assets
$
535,964

 
$
382,075

Liabilities, Equity and Partners’ Capital
 
 
 
Current liabilities
 
 
 
Accounts payable
$
12,426

 
$
3,261

Accrued gas purchases
14,762

 
17,386

Accrued expenses and other current liabilities
21,425

 
15,058

Current portion of long-term debt
1

 
2,048

Risk management liabilities
335

 
423

Current liabilities held for sale
1

 
114

Total current liabilities
48,950

 
38,290

Risk management liabilities
—

 
101

Asset retirement obligations
34,782

 
34,636

Other liabilities
161

 
191

Long-term debt
57,700

 
130,735

Deferred tax liability
4,816

 
4,749

Noncurrent liabilities held for sale, net
—

 
95

Total liabilities
146,409

 
208,797

Commitments and contingencies (See Note 14)
 
 
 
Convertible preferred units
 
 
 
Series A convertible preferred units (5,586 thousand and 5,279 thousand units issued and outstanding as of September 30, 2014, and December 31, 2013, respectively)
104,736

 
94,811

Equity and partners' capital
 
 
 
General partner interest (299 thousand and 185 thousand units issued and outstanding as of September 30, 2014, and December 31, 2013, respectively)
(3,106
)
 
2,696


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Limited partner interest (15,771 thousand and 7,414 thousand units issued and outstanding as of September 30, 2014, and December 31, 2013, respectively)
251,564

 
71,039

Series B convertible units (1,232 thousand and zero units issued and outstanding as of September 30, 2014, and December 31, 2013, respectively)
31,671

 
—

Accumulated other comprehensive income
157

 
104

Total partners’ capital
280,286

 
73,839

Noncontrolling interests
4,533

 
4,628

Total equity and partners' capital
284,819

 
78,467

Total liabilities, equity and partners' capital
$
535,964

 
$
382,075

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

5
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American Midstream Partners, LP and Subsidiaries
Condensed Consolidated Statements of Operations
(Unaudited, in thousands, except for per unit amounts)
 
Three months ended September 30,
 
Nine months ended September 30,
 
2014
 
2013
 
2014
 
2013
Revenue
$
69,699

 
$
78,018

 
$
227,940

 
$
217,201

(Loss) gain on commodity derivatives, net
606

 
(499
)
 
283

 
110

Total revenue
70,305

 
77,519

 
228,223

 
217,311

Operating expenses:
 
 
 
 
 
 
 
Purchases of natural gas, NGLs and condensate
46,690

 
55,765

 
155,729

 
162,998

Direct operating expenses
11,884

 
9,092

 
31,889

 
22,369

Selling, general and administrative expenses
5,875

 
4,494

 
17,105

 
12,507

Equity compensation expense
337

 
392

 
1,132

 
1,877

Depreciation, amortization and accretion expense
5,706

 
7,880

 
19,350

 
22,274

Total operating expenses
70,492

 
77,623

 
225,205

 
222,025

Gain on involuntary conversion of property, plant and equipment
—

 
—

 
—

 
343

Loss on sale of assets, net
(103
)
 
—

 
(124
)
 
—

Loss on impairment of property, plant and equipment
—

 
—

 
—

 
(15,232
)
Operating income (loss)
(290
)
 
(104
)
 
2,894

 
(19,603
)
Other income (expense):
 
 
 
 
 
 
 
     Interest expense
(1,430
)
 
(2,636
)
 
(5,013
)
 
(6,958
)
Other expense
(672
)
 
—

 
(672
)
 
—

Earnings in unconsolidated affiliate
117

 
—

 
117

 
—

Net loss before income tax (expense) benefit
(2,275
)
 
(2,740
)
 
(2,674
)
 
(26,561
)
Income tax (expense) benefit
(122
)
 
214

 
(260
)
 
589

Net loss from continuing operations
(2,397
)
 
(2,526
)
 
(2,934
)
 
(25,972
)
Discontinued operations:
 
 
 
 
 
 
 
Loss from operations of disposal groups, net of tax
(26
)
 
(15
)
 
(582
)
 
(1,891
)
Net loss
(2,423
)
 
(2,541
)
 
(3,516
)
 
(27,863
)
Net income attributable to noncontrolling interests
33

 
190

 
207

 
533

Net loss attributable to the Partnership
$
(2,456
)
 
$
(2,731
)
 
$
(3,723
)
 
$
(28,396
)
 
 
 
 
 
 
 
 
General partner's interest in net loss
$
(32
)
 
$
(221
)
 
$
(48
)
 
$
(1,194
)
Limited partners' interest in net loss
$
(2,424
)
 
$
(2,510
)
 
$
(3,675
)
 
$
(27,202
)
 
 
 
 
 
 
 
 
Distribution declared per common unit (a)
$
0.4625

 
$
0.4325

 
$
1.3775

 
$
0.8650

Limited partners' net loss per common unit (See Note 4 and Note 11):
 
 
 
 
Basic and diluted:
 
 
 
 
 
 
 
Loss from continuing operations
$
(0.58
)
 
$
(0.81
)
 
$
(1.52
)
 
$
(5.52
)
Loss from discontinued operations
—

 
0.01

 
(0.05
)
 
(0.21
)
Net loss
$
(0.58
)
 
$
(0.80
)
 
$
(1.57
)
 
$
(5.73
)
Weighted average number of common units outstanding:
 
 
 
 
Basic and diluted
13,204

 
6,663

 
11,409

 
8,334


(a) Declared and paid in the quarter(s) during the three and nine months ended September 30, 2014 and 2013 related to prior quarter earnings.

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

6
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American Midstream Partners, LP and Subsidiaries
Condensed Consolidated Statements of Comprehensive Income
(Unaudited, in thousands)
 
Three months ended September 30,
 
Nine months ended September 30,
 
2014
 
2013
 
2014
 
2013
Net loss
$
(2,423
)
 
$
(2,541
)
 
$
(3,516
)
 
$
(27,863
)
Unrealized gain (loss) on post retirement benefit plan assets and liabilities
7

 
(34
)
 
53

 
(90
)
Comprehensive loss
(2,416
)
 
(2,575
)
 
(3,463
)
 
(27,953
)
Less: Comprehensive income attributable to noncontrolling interests
33

 
190

 
207

 
533

Comprehensive loss attributable to Partnership
$
(2,449
)
 
$
(2,765
)
 
$
(3,670
)
 
$
(28,486
)
The accompanying notes are an integral part of these condensed consolidated financial statements.

7
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American Midstream Partners, LP and Subsidiaries
Condensed Consolidated Statements of Changes in Partners’ Capital
and Noncontrolling Interest
(Unaudited, in thousands)
 
 
General
Partner
Interest
 
Limited
Partner
Interest
 
Series B Convertible Units
 
Accumulated
Other
Comprehensive
Income
 
Total Partners' Capital
 
Noncontrolling Interest
Balances at December 31, 2012
$
548

 
$
79,266

 
$
—

 
$
351

 
$
80,165

 
$
7,438

Net (loss) income
(1,194
)
 
(27,202
)
 
—

 
—

 
(28,396
)
 
533

Unitholder contributions
35,196

 
—

 
—

 
—

 
35,196

 
—

Unitholder distributions
(340
)
 
(16,332
)
 
—

 
—

 
(16,672
)
 
—

Fair value of Series A Units in excess of net asset received
(312
)
 
(15,300
)
 
—

 
—

 
(15,612
)
 
—

Net distributions to noncontrolling interest holders
—

 
—

 
—

 
—

 
—

 
(571
)
LTIP vesting
(1,570
)
 
1,570

 
—

 
—

 
—

 
—

LTIP tax netting unit repurchase
—

 
(400
)
 
—

 
—

 
(400
)
 
—

Unit based compensation
1,824

 
—

 
—

 
—

 
1,824

 
—

Other comprehensive loss
—

 
—

 
—

 
(90
)
 
(90
)
 
—

Balances at September 30, 2013
$
34,152

 
$
21,602

 
$
—

 
$
261

 
$
56,015

 
$
7,400

 
 
 
 
 
 
 
 
 
 
 
 
Balances at December 31, 2013
$
2,696

 
$
71,039

 
$
—

 
$
104

 
$
73,839

 
$
4,628

Net (loss) income
(48
)
 
(3,675
)
 
—

 
—

 
(3,723
)
 
207

Issuance of common units, net of offering costs
—

 
204,335

 
—

 
—

 
204,335

 
—

Issuance of Series B convertible units
—

 
—

 
31,671

 
—

 
31,671

 
—

Unitholder contributions
2,964

 
—

 
—

 
—

 
2,964

 
—

Unitholder distributions
(1,857
)
 
(27,968
)
 
—

 
—

 
(29,825
)
 
—

Issuance and exercise of warrant
(7,164
)
 
7,164

 
—

 
—

 
—

 
—

Net distributions to noncontrolling interest owners
—

 
—

 
—

 
—

 
—

 
(273
)
Acquisition of noncontrolling interest
—

 
21

 
—

 
—

 
21

 
(29
)
LTIP vesting
(696
)
 
901

 
—

 
—

 
205

 
—

LTIP tax netting unit repurchase
—

 
(253
)
 
—

 
—

 
(253
)
 
—

Unit based compensation
999

 
—

 
—

 
—

 
999

 
—

Other comprehensive income
—

 
—

 
—

 
53

 
53

 
—

Balances at September 30, 2014
$
(3,106
)
 
$
251,564

 
$
31,671

 
$
157

 
$
280,286

 
$
4,533

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

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

Nine months ended September 30,
 
2014
 
2013
Cash flows from operating activities

 

Net loss
$
(3,516
)
 
$
(27,863
)
Adjustments to reconcile net loss to net cash provided by operating activities:

 

Depreciation, amortization and accretion expense
19,350

 
22,355

Amortization of deferred financing costs
1,894

 
975

Amortization of weather derivative premium
794

 
378

Unrealized (gain) loss on commodity derivatives, net
(592
)
 
1,159

Non-cash compensation expense
1,200

 
1,824

OPEB plan net periodic benefit
(35
)
 
(55
)
Gain on involuntary conversion of property, plant and equipment
—

 
(343
)
Loss on sale of assets
209

 
—

Loss on impairment of property, plant and equipment
—

 
15,232

Loss on impairment of noncurrent assets held for sale
673

 
1,807

Deferred tax benefit
(58
)
 
(662
)
Changes in operating assets and liabilities, net:
 

Accounts receivable
(599
)
 
397

Unbilled revenue
1,913

 
(1,970
)
Risk management assets and liabilities
(965
)
 
(1,147
)
Other current assets
2,858

 
602

Other assets, net
(608
)
 
(67
)
Accounts payable
624

 
121

Accrued gas purchases
(2,734
)
 
273

Accrued expenses and other current liabilities
(1,446
)
 
2,685

Asset retirement obligations
(690
)
 
—

Other liabilities
(32
)
 
(114
)
Net cash provided by operating activities
18,240

 
15,587

Cash flows from investing activities

 

Cost of acquisitions
(110,909
)
 
—

Additions to property, plant and equipment
(41,257
)
 
(22,842
)
Proceeds from disposals of property, plant and equipment
6,323

 
—

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

 
482

Equity method investment
(12,000
)
 
—

Proceeds from equity method investment, return of capital
983

 
—

Net cash used in investing activities
(156,860
)
 
(22,360
)
Cash flows from financing activities

 

Proceeds from issuance of common units, net of offering costs
204,335

 
—

Unitholder contributions
2,896

 
13,075

Unitholder distributions
(19,549
)
 
(12,458
)
Issuance of Series A convertible preferred units, net
—

 
14,393

Issuance of Series B Units
30,000

 
—

Acquisition of noncontrolling interest
(8
)
 
—

Net distributions to noncontrolling interest owners
(273
)
 
(571
)

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LTIP tax netting unit repurchase
(253
)
 
(400
)
Payments of deferred debt issuance costs
(3,380
)
 
(1,509
)
Payments on other debt
(2,217
)
 
(2,231
)
Borrowings on other debt
170

 
1,495

Payments on loan to affiliate
—

 
(1,072
)
Payments on bank loans
—

 
6,200

Payments on long-term debt
(212,670
)
 
(99,821
)
Borrowings on long-term debt
139,635

 
92,571

Net cash provided by financing activities
138,686

 
9,672

Net increase in cash and cash equivalents
66

 
2,899

Cash and cash equivalents

 

Beginning of period
393

 
576

End of period
$
459

 
$
3,475

Supplemental cash flow information

 

Interest payments, net
$
4,064

 
$
5,051

Supplemental non-cash information

 

Increase (decrease) in accrued property, plant and equipment
$
17,746

 
$
(6,080
)
Net assets contributed in the Blackwater Acquisition (see Note 3)
—

 
22,129

Net assets contributed in exchange for the issuance of Series A convertible preferred units
—

 
59,994

Fair value of Series A Units in excess of net assets received
—

 
15,612

Accrued and in-kind unitholder distribution for Series A Units
9,925

 
2,912

In-kind unitholder distribution for Series B Units
1,671

 
—

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

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American Midstream Partners, LP and Subsidiaries
Notes to Condensed Consolidated Financial Statements
(Unaudited)
1. Organization and Basis of Presentation

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. We provide natural gas gathering, treating, processing, fractionating, marketing and transportation services primarily in the Gulf Coast and Southeast regions of the United States through our ownership and operation of nine gathering systems, two processing facilities, one fractionation facility, three interstate pipelines and five intrastate pipelines. In addition, we own a 50% undivided, non-operating interest in a processing plant located in southern Louisiana. Through our four marine terminal sites, we provide petroleum, agricultural, and chemical liquid storage services.

We hold our assets in a series of wholly owned limited liability companies, a limited partnership and a corporation. Our capital accounts consist of general partner interests and limited partner interests.

Our interstate natural gas pipeline assets transport natural gas through the FERC regulated interstate natural gas pipelines in Louisiana, Mississippi, Alabama and Tennessee. Our interstate pipelines include:
•
High Point Gas Transmission, LLC, which owns and operates approximately 400 miles of intrastate pipeline and is connected to 40 meters with 32 active producers and offers processing options at the Toca processing plant with delivery to Southern Natural Gas available downstream of the processing plant in Louisiana;
•
American Midstream (Midla), LLC, which owns and operates approximately 370 miles of interstate pipeline that runs from the Monroe gas field in northern Louisiana south through Mississippi to Baton Rouge, Louisiana;
•
American Midstream (AlaTenn), LLC, which owns and operates approximately 295 miles of interstate pipeline that runs through the Tennessee River Valley from Selmer, Tennessee to Huntsville, Alabama and serves an eight-county area in Alabama, Mississippi and Tennessee.

Common Unit Purchase Agreement

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 (the "PIPE Offering") 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. The PIPE Offering was completed on August 20, 2014.

Series A Distribution Amendment

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. We have recorded the impacts of the Amendment for the three months ended September 30, 2014 and have accrued $4.2 million for the paid-in-kind Series A Units.

Equity Offering and Series B Convertible Units Issuance

In January 2014, in connection with the Lavaca Acquisition as discussed in Note 3, the Partnership completed a public equity offering resulting in net proceeds of $86.9 million and the issuance to our General Partner of 1,168,225 Series B convertible units ("Series B Units") representing Series B limited partnership interests in the Partnership. The net proceeds related to the Series B Units issuance was $30.0 million. The Series B Units have the right to share in distributions from the Partnership on a pro-rata basis with holders of the Partnership’s common units and will convert into common units on a one-for-one basis on January 31, 2016. During 2014, the Partnership has elected to pay the Series B distributions using paid-in-kind Series B Units.

Basis of Presentation

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These unaudited condensed consolidated financial statements have been prepared in accordance with GAAP for interim financial information. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. The year-end balance sheet data was derived from consolidated audited financial statements but does not include disclosures required by GAAP for annual periods. We have made reclassifications to amounts reported in prior period condensed consolidated financial statements to conform to our current year presentation. These reclassifications did not have an impact on net income for the period previously reported. The information furnished herein reflects all normal recurring adjustments which are, in the opinion of management, necessary for a fair statement of financial position and results of operations for the respective interim periods.

The financial results for the three and nine months ended September 30, 2013 have been reclassified to present an asset group previously presented as held for sale as held and used.

Our financial results for the three and nine months ended September 30, 2014 are not necessarily indicative of the results that may be expected for the full year ended December 31, 2014. These unaudited condensed consolidated financial statements should be read in conjunction with our consolidated financial statements and notes thereto included in i) our Annual Report on Form 10-K for the year ended December 31, 2013 (“Annual Report”) filed on March 11, 2014 and ii) our Annual Report on Form 10-K/A that was filed with the Securities and Exchange Commission ("SEC") on May 12, 2014, which updated portions of our annual report.

Consolidation Policy

Our condensed consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. 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 condensed consolidated financial statements reflect our proportionate share of the revenues, expenses, assets and liabilities of this undivided interest. As of September 30, 2014, we also hold a 92.2% undivided interest in the Chatom Processing and Fractionation facility (the "Chatom System"). Our condensed consolidated financial statements reflect the accounts of the Chatom System and the interests in the Chatom System held by non-affiliated working interest owners are reflected as noncontrolling interests in the Partnership's condensed consolidated financial statements.

The Partnership accounts for its 66.7% non-operated interest in Main Pass Oil Gathering Company ("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 condensed 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 judgments are based on information available at the time such estimates and judgments are made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously available. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things i) estimating unbilled revenues, accrued gas 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.

2. Recent Accounting Pronouncements

In July 2013, the FASB issued Accounting Standards Update ("ASU ") No. 2013-11, Income Taxes (Topic 740): Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (a consensus of the FASB Emerging Issues Task Force). This guidance was issued related to the presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss or a tax credit carryforward exists. The updated guidance requires an entity to net its unrecognized tax benefits against the deferred tax assets for all same jurisdiction net operating loss carryforward, a similar tax loss, or tax credit carryforwards. A gross presentation will be required only if such carryforwards are not available or would not be used by the entity to settle any additional income taxes resulting from disallowance of the uncertain tax position. The update was effective for the Partnership on January 1, 2014 and did not have a material impact on its condensed consolidated financial statements.

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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 condensed 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 is currently evaluating the impact of this standard on its financial statements and does not believe there will be a material impact.

3. Acquisitions and Divestitures

Lavaca Acquisition

On January 31, 2014, the Partnership acquired approximately 120 miles of high- and low-pressure pipelines ranging from four to eight inches in diameter with over 9,000 horsepower of leased compression, and associated facilities located in the Eagle Ford shale in Gonzales and Lavaca Counties, Texas (the “Lavaca Acquisition”). The Lavaca Acquisition was financed with a portion of the net proceeds from the Partnership’s January 2014 equity offering of $86.9 million and proceeds of $30.0 million from the issuance to our General Partner of 1,168,225 Series B Units.

The Lavaca Acquisition qualified as a business combination in accordance with ASC 805, Business Combinations, and, as such, the Partnership engaged a third party to estimate the fair value of the assets as of the effective date of the acquisition. A combination of the income and cost approaches were utilized to estimate the fair value of the assets. 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, Fair Value Measurement.

Primarily using the cost approach to value the physical assets, the fair value estimates are based on i) replacement cost estimates using third party data based on installations of similar assets and ii) estimated depreciation on the assets based on third party sources and analysis of the life and use of the assets.

It was determined as part of the fair value analysis of the acquisition, that the Partnership acquired separately identifiable intangible assets. The Lavaca Acquisition includes a 25-year gas gathering agreement which states that Penn Virginia Corporation (NYSE: PVA) ("PVA") will dedicate certain acreage and all related future production to the gathering infrastructure included in the acquisition. In accordance with ASC 805, contract based intangible assets include the value of rights derived from contractual agreements. The Partnership will receive incremental value from PVA’s development of the reserves within the dedicated acreage and, therefore, it was determined that the dedicated acreage represents intangible assets acquired with the Lavaca Acquisition. The Partnership will amortize the Lavaca Acquisition intangibles using the straight-line method over the life of the related reserves within the dedicated acreage and recognize $1.5 million of amortization expense annually.

Primarily using the income approach to value the intangible assets, the fair value estimates are based on i) an assumed discount rate of 10.5%; ii) present value of estimated future cash flows; iii) estimated timing and amounts of future operating and development costs; iv) forward market prices as of December 2013 for natural gas and crude oil; and v) an increase in throughput volumes through 2019, declining thereafter.


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The Partnership completed a preliminary purchase price allocation to determine the estimated fair value of the acquired assets. The preliminary allocation is subject to various purchase price adjustments, which could impact the allocation presented below. The following table summarizes the preliminary purchase price allocation for the Lavaca Acquisition (in thousands):
Property, plant and equipment:
 
Land
$
2

Pipelines
58,737

Equipment
753

Total property, plant and equipment
59,492

Intangible assets
44,917

Total cash consideration
$
104,409


For the three and nine months ended September 30, 2014, the Lavaca System contributed $4.5 million and $10.6 million of revenue and $2.3 million and $4.5 million of net income, respectively, attributable to the Partnership's Gathering and Processing segment, which are included in the condensed consolidated statement of operations.

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, which is an offshore oil gathering system, for a net purchase price of $12.0 million. The acquisition was financed through the Partnership's credit facility. The interest is accounted for as an equity method investment under ASC 323, Investments-Equity Method and Joint Ventures. Although the Partnership owns a majority interest in MPOG, the ownership structure requires unanimous approval amongst 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 their obligations to absorb losses or receive returns. As such, MPOG is considered a variable interest entity however the Partnership is not the primary beneficiary and as a result does not consolidate MPOG. The Partnership recorded $0.1 million in earnings from unconsolidated affiliate, and received cash distributions of $1.1 million for the three and nine months ended September 30, 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 condensed consolidated statement of cash flows.

Williams Pipeline Acquisition

In the fourth quarter of 2013, High Point Gas Gathering LLC, a subsidiary of the Partnership, entered into a purchase and sale agreement to acquire natural gas pipeline facilities and interests thereto for approximately $6.5 million that are contiguous to, and connect with, our High Point System in offshore Louisiana (the “Williams Pipeline Acquisition”). The closing of the purchase and sale agreement 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. Total consideration was allocated to pipeline fixed assets using the income approach based on Level 3 inputs.

Blackwater Terminals Acquisition

Effective December 17, 2013, we acquired Blackwater Midstream Holdings, LLC ("Blackwater"), which operates 1.7 million barrels of storage capacity across four marine terminal sites located in Westwego, Louisiana; Brunswick, Georgia; Harvey, Louisiana; and Salisbury, Maryland. The acquisition of Blackwater represented 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, which was April 15, 2013.

For the three and nine months ended September 30, 2014, Blackwater contributed $3.8 million and $11.3 million of revenue and $0.7 million and $1.1 million of net income, respectively, attributable to the Partnership's Terminals segment, which are included in the condensed consolidated statement of operations.


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Subsequent to the acquisition of Blackwater, for the three and nine months ended September 30, 2013, Blackwater contributed $3.5 million and $6.3 million of revenue and $0.1 million and $0.7 million of net loss, respectively, attributable to the Partnership's Terminals segment, which are included in the condensed consolidated statement of operations.

High Point System Acquisition

Effective April 15, 2013, our General Partner contributed to us 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 entities own midstream assets consisting of approximately 700 miles of natural gas and liquids pipeline assets located in southeast Louisiana, in the Plaquemines and St. Bernard's 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.

For the three and nine months ended September 30, 2014, the High Point System contributed $6.4 million and $22.4 million of revenue and $2.6 million and $10.4 million of net income, respectively, attributable to the Partnership's Transmission segment, which are included in the condensed consolidated statement of operations.

Subsequent to the contribution from our General Partner, for the three and nine months ended September 30, 2013, the High Point System contributed $10.7 million and $19.7 million, respectively, of revenue and $1.2 million and $2.7 million, respectively, of net income, attributable to the Partnership's Transmission segment, which are included in the condensed consolidated statement of operations.

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.

4. Discontinued Operations

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.

During the second quarter of 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. Subsequently, as part of the Blackwater Acquisition described in Note 3, we acquired long-lived terminal assets classified as held for sale.

As a result of the planned divestiture of these non-strategic midstream assets, we have accounted for these disposal groups as discontinued operations within our Gathering and Processing and Terminal segments. 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 Loss from operations of disposal groups, net of tax in our accompanying condensed 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 condensed consolidated statement of cash flows as this activity was immaterial for all periods presented. The following table presents the revenue and expenses and Loss from operations of disposal groups, net of tax associated with the assets classified as held for sale for the three and nine months ended September 30, 2014 and 2013 (in thousands, except per unit amounts):

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Table of Contents

 
Three months ended September 30,
 
Nine months ended September 30,
 
2014
 
2013
 
2014
 
2013
Revenue
$
13

 
$
591

 
$
461

 
$
1,717

Expense
(55
)
 
(606
)
 
(599
)
 
(1,801
)
Loss on impairment of property, plant and equipment
—

 
—

 
(673
)
 
(1,807
)
Loss on sale of assets
—

 
—

 
(87
)
 
—

Income tax benefit
16

 
—

 
316

 
—

Loss from operations of disposal groups, net of tax
$
(26
)
 
$
(15
)
 
$
(582
)
 
$
(1,891
)
Limited partners' net loss per unit from discontinued operations (basic and diluted)
$
—

 
$
0.01

 
$
(0.05
)
 
$
(0.21
)

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 in the fourth quarter of 2014, contingent upon the purchaser’s completion of due diligence activities. The Partnership recognized an additional impairment on these assets of $0.7 million ($0.4 million, net of tax) during the nine months ended September 30, 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.

5. 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, NGL and condensate products. This concentration of customers may affect our overall credit risk in that the customers may be similarly affected by changes in economic, regulatory or other factors. Generally, 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 three and nine months ended September 30, 2014 and 2013, no allowances on or write-offs of accounts receivable were recorded.

The following table summarizes the percentage of revenue earned from those customers that accounted for 10% or more of the Partnership's consolidated revenue in the condensed consolidated statement of operations for the each of the periods presented below:
 
Three months ended September 30,
 
Nine months ended September 30,
 
2014
 
2013
 
2014
 
2013
Customer A
24
%
 
27
%
 
26
%
 
29
%
Customer B
14
%
 
13
%
 
14
%
 
12
%
Customer C
10
%
 
13
%
 
10
%
 
13
%
Customer D
—
%
 
—
%
 
10
%
 
—
%
Other
52
%
 
47
%
 
40
%
 
46
%
Total
100
%
 
100
%
 
100
%
 
100
%

6. Derivatives

Commodity Derivatives


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To minimize the effect of commodity prices and maintain our cash flow and the economics of our development plans, we enter into commodity hedge contracts from time to time. Those commodity hedge contracts may be in the form of swaps, puts and/or collars. The terms of the contracts depend on various factors, including management’s view of future commodity prices, acquisition economics on purchased assets and future financial commitments. This hedging program is designed to mitigate the effect of commodity price downturns 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. As of September 30, 2014, the aggregate notional volume of our commodity derivatives was 3.5 million gallons.

We enter into commodity contracts with multiple counterparties. We may be required to post collateral with our counterparties in connection with our derivative positions. As of September 30, 2014, we have not posted collateral with any counterparty. Our counterparties are not required to post collateral with us in connection with their derivative positions. Netting agreements are in place with our counterparties that permit us to offset our commodity derivative asset and liability positions.

For accounting purposes, no derivative instruments were designated as hedging instruments and were instead accounted for under the mark-to-market method of accounting, with any changes in the fair value of the derivatives recorded in the condensed consolidated balance sheets and through earnings, rather than being deferred until the anticipated transactions affect earnings. The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying commodity price indices or interest rates.

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 our long-term variable rate debt into fixed rate debt. As of September 30, 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.

Weather Derivative

In the second quarters 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 balance sheet and are amortized to Direct operating expenses on a straight-line basis over the one year term of the respective contract. For the weather derivative entered into in the second quarter of 2014, the unamortized amount was approximately $0.6 million as of September 30, 2014. The weather derivative entered into in the second quarter of 2013 was fully amortized as of September 30, 2014.
As of September 30, 2014 and December 31, 2013, the value associated with our commodity derivatives, interest rate swap, and weather derivative were recorded in our condensed 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
 
September 30,
2014
 
December 31, 2013
 
September 30,
2014
 
December 31, 2013
 
September 30,
2014
 
December 31, 2013
Current
 
$
1,047

 
$
473

 
$
—

 
$
—

 
$
1,047

 
$
473

Noncurrent
 
—

 
—

 
—

 
—

 
—

 
—

Total assets
 
$
1,047

 
$
473

 
$
—

 
$
—

 
$
1,047

 
$
473

 
 
 
 
 
 
 
 
 
 
 
 
 
Current
 
$
—

 
$
27

 
$
(335
)
 
$
(450
)
 
$
(335
)
 
$
(423
)
Noncurrent
 
—

 
—

 
—

 
(101
)
 
—

 
(101
)
Total liabilities
 
$
—

 
$
27

 
$
(335
)
 
$
(551
)
 
$
(335
)
 
$
(524
)

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For the three and nine months ended September 30, 2014 and 2013, respectively, the realized and unrealized gains (losses) associated with our commodity derivatives, interest rate swap instrument and weather derivative were recorded in our condensed consolidated statements of operations, under the captions as follows (in thousands):
 
Three months ended September 30,
 
Nine months ended September 30,
 
Gain (loss) on derivatives
 
Gain (loss) on derivatives
Statement of Operations Classification
Realized
 
Unrealized
 
Realized
 
Unrealized
2014
 
 
 
 
 
 
 
Commodity derivatives
$
(9
)
 
$
615

 
$
(191
)
 
$
474

Interest expense
(109
)
 
91

 
(322
)
 
118

Direct operating expenses
(241
)
 
—

 
(794
)
 
—

Total
$
(359
)
 
$
706

 
$
(1,307
)
 
$
592

2013
 
 
 
 
 
 
 
Commodity derivatives
$
261

 
$
(760
)
 
$
797

 
$
(687
)
Interest expense
(101
)
 
(153
)
 
(101
)
 
(471
)
Direct operating expenses
(284
)
 
—

 
(378
)
 
—

Total
$
(124
)
 
$
(913
)
 
$
318

 
$
(1,158
)

7. Fair Value Measurement

The authoritative guidance for fair value measurements establishes a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value. These tiers include:
•
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.

A financial instrument’s categorization within the fair value hierarchy is based upon the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the classification of assets and liabilities within the fair value hierarchy.

We believe the carrying amount of cash and cash equivalents approximates fair value because of the short-term maturity of these instruments. Our cash and cash equivalents would be classified as Level 1 under the fair value hierarchy.

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. Our existing revolving credit facility would be classified as Level 1 under the fair value hierarchy.

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.

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 condensed consolidated balance sheet, that were measured at fair value on a recurring basis as of September 30, 2014 and December 31, 2013 (in thousands):

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Carrying
Amount
 
Estimated Fair Value
 
Level 1
 
Level 2
 
Level 3
 
Total
Commodity derivative instruments, net
 
 
 
 
 
 
 
 
 
September 30, 2014
$
404

 
$
—

 
$
404

 
$
—

 
$
404

December 31, 2013
(70
)
 
—

 
(70
)
 
—

 
(70
)
Interest rate swap
 
 
 
 
 
 
 
 
 
September 30, 2014
$
(335
)
 
$
—

 
$
(335
)
 
$
—

 
$
(335
)
December 31, 2013
(454
)
 
—

 
(454
)
 
—

 
(454
)

The premium paid to enter the weather derivative described in Note 6 "Derivatives" is included within Risk management assets on the condensed consolidated balance sheet but is not included as part of the above table as it is recorded at amortized carrying cost, not fair value.

8. Property, Plant and Equipment

Property, plant and equipment, net, as of September 30, 2014 and December 31, 2013 were as follows (in thousands):
 
Useful Life
(in years)
 
September 30,
2014
 
December 31,
2013
Land
N/A
 
$
6,133

 
$
6,015

Construction in progress
N/A
 
44,707

 
6,443

Base gas
N/A
 
1,108

 
1,108

Buildings and improvements
4 to 40
 
5,522

 
5,109

Processing and treating plants
8 to 40
 
98,291

 
97,106

Pipelines
5 to 40
 
304,771

 
239,865

Compressors
4 to 20
 
18,185

 
11,955

Dock
20 to 40
 
8,004

 
7,942

Tanks, truck rack and piping
20 to 40
 
24,390

 
22,432

Equipment
8 to 20
 
8,645

 
6,294

Computer software
5
 
3,696

 
3,531

Total property, plant and equipment
 
 
523,452

 
407,800

Accumulated depreciation
 
 
(107,653
)
 
(95,099
)
Property, plant and equipment, net
 
 
$
415,799

 
$
312,701


Of the gross property, plant and equipment balances at September 30, 2014 and December 31, 2013, $101.5 million and $100.5 million, respectively, were related to AlaTenn, Midla and HPGT, our FERC regulated interstate and intrastate assets.

Capitalized interest was $0.3 million and less than $0.1 million for the three months ended September 30, 2014 and 2013, respectively, and $0.4 million and $0.1 million for the nine months ended September 30, 2014 and 2013, respectively.

Depreciation expense was $4.6 million and $6.5 million for the three months ended September 30, 2014 and 2013, respectively, and $15.7 million and $18.9 million for the nine months ended September 30, 2014 and 2013, respectively.

9. Asset Retirement Obligations

We record a liability for the fair value of asset retirement obligations and conditional asset retirement obligations that we can reasonably estimate, on a discounted basis, in the period in which the liability is incurred. We collectively refer to asset retirement obligations and conditional asset retirement obligations as ARO.

Certain assets related to our Transmission segment have regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are abandoned. These asset retirement obligations include varying levels of activity including disconnecting inactive assets from active assets, cleaning and purging assets, and in some cases, completely removing the assets and returning the land to its original state. These assets have been in existence for many years and with regular maintenance will continue to be in service for many years to come. It is not possible to predict when demand for these transmission

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services will cease, and we do not believe that such demand will cease for the foreseeable future. A portion of our regulatory obligations is related to assets that we plan to take out of service.

No assets were legally restricted for purposes of settling our ARO liabilities during the nine months ended September 30, 2014. The following table is a reconciliation of the asset retirement obligations (in thousands):
 
September 30, 2014
Beginning asset retirement obligation
$
34,636

Liabilities assumed
248

Expenditures
(690
)
Accretion expense
588

Ending asset retirement obligation
$
34,782

We are required to establish security against any potential secondary obligations relating to the abandonment of 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 amounts to $3.0 million and is presented in Other assets, net in our consolidated balance sheet as of September 30, 2014.

10. Debt Obligations

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. 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). 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 Agreement are secured by a first mortgage in favor of the lenders in the majority of 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, which is September 5, 2016.

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). The primary financial covenants contained in the credit facility are i) a total consolidated leverage ratio test (not to exceed 4.75 times in the absence of a permitted acquisition) and ii) a minimum interest coverage ratio test (not less than 2.50).

For the nine months ended September 30, 2014 and 2013, the weighted average interest rate on borrowings under our Credit Agreement was approximately 4.38% and 4.50%, respectively.

As of September 30, 2014, we had approximately $57.7 million of outstanding borrowings under our credit facility. Our consolidated total leverage calculation pursuant to the Credit Agreement was 1.49 times resulting in approximately $135.2 million of available borrowing capacity as of September 30, 2014.

Other debt

Other debt represents insurance premium financing in the original amount of $2.5 million bearing interest at 3.95% per annum, which is repayable in equal monthly installments of approximately $0.3 million through the third quarter of 2014.


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Our outstanding borrowings at September 30, 2014 and December 31, 2013, respectively, were (in thousands):
 
September 30,
2014
 
December 31,
2013
Revolving credit facility
$
57,700

 
$
130,735

Other debt
1

 
2,048

Total debt
57,701

 
132,783

Less: current portion
1

 
2,048

Long-term debt
$
57,700

 
$
130,735


At September 30, 2014 and December 31, 2013, letters of credit outstanding under the credit facility totaled $4.2 million and $4.8 million, respectively.

In connection with our credit facility and amendments thereto, we have incurred $10.1 million of debt issuance costs inception to date that 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 condensed consolidated statement of operations.

11. Partners’ Capital and Convertible Preferred Units

Our capital accounts are comprised of approximately 1.3% general partner interests and 98.7% limited partner interests. Our limited partners have limited rights of ownership as provided for under our partnership agreement and the right to participate in our distributions. Our General Partner manages our operations and participates in our distributions, including certain incentive distributions pursuant to the Incentive Distribution Rights that are non-voting limited partner rights 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. 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 has 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 nine months ended September 30, 2014, the Partnership issued 63,972 of paid-in-kind Series B Units with a fair value of $1.7 million.

Equity Offerings

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 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.

General Partner Units

In connection with the equity offerings discussed above, we received proceeds of $3.0 million from our General Partner as consideration for 113,131 additional general partner units.

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Issuance and Exercise of Warrant

Effective February 5, 2014, we issued to our General Partner 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”). The Warrant was exercised on February 21, 2014, resulting in the issuance of approximately 300,000 common units. The value of the Warrant of $7.2 million was determined based on the close price of $23.89 of the common units on the exercise date.

The numbers of units outstanding as of September 30, 2014 and December 31, 2013, respectively, were as follows (in thousands):
 
September 30,
2014
 
December 31,
2013
Series A convertible preferred units
5,586

 
5,279

Series B convertible units
1,232

 
—

Limited partner common units
15,771

 
7,414

General partners units
299

 
185


Distributions

We made cash distributions of $5.8 million and $19.5 million, inclusive of distributions of $0.5 million and $1.5 million in respect of our General Partner’s incentive distribution rights, in the three and nine months ended September 30, 2014, respectively. We made distributions of $4.7 million and $12.5 million in the three and nine months ended September 30, 2013, respectively. We made no distributions in respect of our General Partner's incentive distribution rights in the nine months ended September 30, 2013. We depend on our credit facility for future capital needs and may use it to fund a portion of cash distributions to unitholders, as necessary, depending on the level and timing of our operating cashflow.

The Partnership executed an amendment to the Partnership agreement, which became effective July 24, 2014, related to its outstanding Series A Units. 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. For the Series A Unit distributions for the three months ended September 30, 2014, we have accrued $4.2 million for the paid-in-kind Series A Units. The distributions will be made in the fourth quarter of 2014.

Net Income (Loss) attributable to Limited Partner Units

Net income (loss) is allocated to the General Partner and the limited partners in accordance with their respective ownership percentages, after giving effect to contractual distributions on Series A preferred convertible units, declared distributions on the Series B Units, limited partner and to the general partner units, including incentive distribution rights. 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 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 (loss) 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 (loss) 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.


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We determined basic and diluted net income (loss) per limited partner unit as follows, (in thousands, except per unit amounts):
 
Three months ended September 30,
 
Nine months ended September 30,
 
2014
 
2013
 
2014
 
2013
Net loss from continuing operations
$
(2,397
)
 
$
(2,526
)
 
$
(2,934
)
 
$
(25,972
)
Less: Net income attributable to noncontrolling interests
33

 
190

 
207

 
533

Net loss from continuing operations attributable to the Partnership
(2,430
)
 
(2,716
)
 
(3,141
)
 
(26,505
)
Less:
 
 
 
 
 
 
 
Contractual distributions on Series A Units
4,165

 
2,873

 
11,263

 
20,899

Declared distributions on Series B Units
619

 
—

 
1,671

 
—

General partner's distribution
603

 
80

 
1,688

 
240

General partner's share in undistributed loss
(169
)
 
(290
)
 
(430
)
 
(1,610
)
Net loss from continuing operations available to limited partners
(7,648
)
 
(5,379
)
 
(17,333
)
 
(46,034
)
Net loss from operations of disposal groups, net of tax, available to limited partners
(26
)
 
38

 
(574
)
 
(1,742
)
Net loss available to limited partners
$
(7,674
)
 
$
(5,341
)
 
$
(17,907
)
 
$
(47,776
)
 
 
 
 
 
 
 
 
Weighted average number of units used in computation of limited partners’ net (loss) income per unit (basic and diluted)
13,204

 
6,663

 
11,409

 
8,334

 
 
 
 
 
 
 
 
Limited partners' net loss per common unit
 
 
 
 
 
 
 
Basic and diluted:
 
 
 
 
 
 
 
Loss from continuing operations
$
(0.58
)
 
$
(0.81
)
 
$
(1.52
)
 
$
(5.52
)
Loss from discontinued operations
—

 
0.01

 
(0.05
)
 
(0.21
)
Net loss
$
(0.58
)
 
$
(0.80
)
 
$
(1.57
)
 
$
(5.73
)

12. Long-Term Incentive Plan

Our General Partner manages our operations and activities and employs the personnel who provide support to our operations. The board of directors of our General Partner provides a long-term incentive plan (“LTIP”) for its employees, consultants and directors who perform services for it or its affiliates. At September 30, 2014 and December 31, 2013, 693,410 and 855,089 units, respectively, were 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 which, 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, it does not currently intend to settle these awards in cash. Although other types of awards are contemplated under the LTIP, all currently outstanding awards are phantom units without distribution equivalent rights.

Generally, grants issued under the LTIP vest in increments of 25% on each of the first four anniversary dates of the date of the grant and do not contain any other restrictive conditions related to vesting other than continued employment.

The following table summarizes the change in our unit-based awards during the nine months ended September 30, 2014 indicated, in units:

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Nine months ended September 30, 2014
 
 
Shares
 
Weighted-Average Exercise Price
Outstanding at beginning of period
 
75,529

 
17.62

Granted
 
183,163

 
20.68

Forfeited
 
(12,009
)
 
18.28

Vested
 
(43,986
)
 
20.72

Outstanding at end of period
 
202,697

 
19.67


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, including amortization, for the three months ended September 30, 2014 and 2013 were $0.3 million and $0.4 million, respectively, and for the nine months ended September 30, 2014 and 2013 were $1.1 million and $1.9 million, respectively, which are classified as Equity compensation expense in the condensed consolidated statements of operations and the non-cash portion in partners’ capital on the condensed consolidated balance sheets.

The total fair value of vested units at the time of vesting was $1.2 million and $1.6 million for the nine months ended September 30, 2014 and 2013, respectively.

The total compensation cost related to unvested awards not yet recognized at September 30, 2014 and 2013 was $3.4 million and $1.1 million, respectively, and the weighted average period over which this cost is expected to be recognized as of September 30, 2014 is approximately 3.3 years.

13. 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. However, one of our subsidiaries, Blackwater, is a taxable entity. Partnership income tax expense for the three and nine months ended September 30, 2014 was $0.1 million and $0.3 million, respectively, resulting in an effective tax rate of 5.4% and 9.7%, respectively. For the three and nine months ended September 30, 2013, Partnership income tax was a benefit of $0.2 million and $0.6 million, resulting in an effective tax rate of 7.8% and 2.2%, respectively.

The effective tax rates for the three and nine months ended September 30, 2014 and September 30, 2013, differ from the statutory rate primarily due to Partnership income and loss that is not subject to U. S. federal income taxes, as well as transactions between the Partnership and its taxable subsidiary that generate tax deductions for the taxable subsidiary, which are eliminated in the consolidation of Net loss before income tax (expense) benefit.

14. Commitments and Contingencies

Resolution of legal matter

In January 2009, Rigolets Limited Partnership (“Rigolets”) filed suit for damages alleging failure to maintain a right-of-way along our Gloria System. Following negotiations, we expect to enter into an agreement with Rigolets during the fourth quarter of 2014 for the procurement of additional needed 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 $1.8 million of capital expenditures over the next twelve months in connection with this rebuilding.

Legal proceedings

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:

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•
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.

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 and processing 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 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 Federal Energy Regulatory Commission (“FERC”).

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

15. 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 three and nine months ended September 30, 2014, administrative and operational services expenses of $5.7 million and $15.9 million, respectively, were charged to us by our General Partner. During the three and nine months ended September 30, 2013, administrative and operational services expenses of $3.3 million and $10.3 million, respectively, were charged to us by our General Partner. For the three and nine months ended September 30, 2014, we incurred approximately $0.2 million and $1.0 million, respectively, of costs primarily associated with certain business development activities led by an affiliate of our General Partner. For the three and nine months ended September 30, 2013, we incurred approximately $0.2 million and $0.6 million, respectively, of costs primarily associated with certain business development activities led by an affiliate of our General Partner. We expect to be reimbursed by this affiliate of our General Partner for the business development costs related to those projects.

During the second quarter, 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. During the three and nine months ended September 30, 2014, the Partnership recognized $0.2 million and $0.3 million, respectively, in management fee income that has been recorded as a reduction to Selling, general and administrative expenses.

16. Reporting Segments

Our operations are located in the United States and are organized into three reporting segments: (1) Gathering and Processing, (2) Transmission and (3) Terminals.

Gathering and Processing

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Our Gathering and Processing segment provides “wellhead-to-market” services to producers of natural gas and oil, which include transporting raw natural gas from various receipt points through gathering systems, treating the raw natural gas, processing raw natural gas to separate the NGLs from the natural gas, fractionating NGLs, and selling or delivering pipeline-quality natural gas as well as 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, which include local distribution companies (“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 chemicals, distillates, and agricultural products.

These segments are monitored separately by management for performance and are consistent with 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 business of each segment.

The following tables set forth our segment information for the three and nine months ended September 30, 2014 and 2013 (in thousands):
 
 
Three months ended September 30, 2014
 
Gathering
and
Processing
 
Transmission
 
Terminals
 
Total
Revenue
$
45,569

 
$
20,328

 
$
3,802

 
$
69,699

Loss on commodity derivatives, net
606

 
—

 
—

 
606

Total revenue
46,175

 
20,328

 
3,802

 
70,305

Operating expenses:
 
 
 
 
 
 
 
Purchases of natural gas, NGL's and condensate
35,024

 
11,666

 
—

 
46,690

Direct operating expenses
5,249

 
5,033

 
1,602

 
11,884

Selling, general and administrative expenses
 
 
 
 
 
 
5,875

Equity compensation expense
 
 
 
 
 
 
337

Depreciation, amortization and accretion expense
 
 
 
 
 
 
5,706

Total operating expenses
 
 
 
 
 
 
70,492

Loss on sale of assets, net
 
 
 
 
 
 
(103
)
Other expense
 
 
 
 
 
 
(672
)
Interest expense
 
 
 
 
 
 
(1,430
)
Earnings in unconsolidated affiliate
 
 
 
 
 
 
117

Income tax expense
 
 
 
 
 
 
(122
)
Loss from operations of disposal groups, net of tax
 
 
 
 
 
 
(26
)
Net loss
 
 
 
 
 
 
(2,423
)
Less: Net income attributable to non-controlling interests
 
 
 
 
 
 
33

Net loss attributable to the Partnership
 
 
 
 
 
 
$
(2,456
)
 
 
 
 
 
 
 
 
Segment gross margin (a)
$
10,513

 
$
8,619

 
$
2,200

 
$
21,332



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Three months ended September 30, 2013
 
Gathering
and
Processing
 
Transmission
 
Terminals
 
Total
Revenue
$
52,082

 
$
22,478

 
$
3,458

 
$
78,018

Gain on commodity derivatives, net
(499
)
 
—

 
—

 
(499
)
Total revenue
51,583

 
22,478

 
3,458

 
77,519

Operating expenses:
 
 
 
 
 
 
 
Purchases of natural gas, NGL's and condensate
41,180

 
14,585

 
—

 
55,765

Direct operating expenses
3,805

 
3,994

 
1,293

 
9,092

Selling, general and administrative expenses
 
 
 
 
 
 
4,494

Equity compensation expense
 
 
 
 
 
 
392

Depreciation, amortization and accretion expense
 
 
 
 
 
 
7,880

Total operating expenses
 
 
 
 
 
 
77,623

Interest expense
 
 
 
 
 
 
(2,636
)
Income tax benefit
 
 
 
 
 
 
214

Loss from operations of disposal groups, net of tax
 
 
 
 
 
 
(15
)
Net loss
 
 
 
 
 
 
(2,541
)
Less: Net income attributable to non-controlling interests
 
 
 
 
 
 
190

Net loss attributable to the Partnership
 
 
 
 
 
 
$
(2,731
)
 
 
 
 
 
 
 
 
Segment gross margin (a)
$
10,879

 
$
7,864

 
$
2,165

 
$
20,908


 
Nine months ended September 30, 2014
 
Gathering
and
Processing
 
Transmission
 
Terminals
 
Total
Revenue
$
147,209

 
$
69,417

 
$
11,314

 
$
227,940

Loss on commodity derivatives, net
283

 
—

 
—

 
283

Total revenue
147,492

 
69,417

 
11,314

 
228,223

Operating expenses:
 
 
 
 
 
 
 
Purchases of natural gas, NGL's and condensate
115,383

 
40,346

 
—

 
155,729

Direct operating expenses
15,163

 
11,887

 
4,839

 
31,889

Selling, general and administrative expenses
 
 
 
 
 
 
17,105

Equity compensation expense
 
 
 
 
 
 
1,132

Depreciation, amortization and accretion expense
 
 
 
 
 
 
19,350

Total operating expenses
 
 
 
 
 
 
225,205

Loss on sale of assets, net
 
 
 
 
 
 
(124
)
Other expense
 
 
 
 
 
 
(672
)
Interest expense
 
 
 
 
 
 
(5,013
)
Earnings in unconsolidated affiliate
 
 
 
 
 
 
117

Income tax expense
 
 
 
 
 
 
(260
)
Loss from operations of disposal groups, net of tax
 
 
 
 
 
 
(582
)
Net loss
 
 
 
 
 
 
(3,516
)
Less: Net income attributable to non-controlling interests
 
 
 
 
 
 
207

Net loss attributable to the Partnership
 
 
 
 
 
 
$
(3,723
)
 
 
 
 
 
 
 
 
Segment gross margin (a)
$
31,122

 
$
28,983

 
$
6,475

 
$
66,580



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Nine months ended September 30, 2013
 
Gathering
and
Processing
 
Transmission
 
Terminals
 
Total
Revenue
$
154,336

 
$
56,539

 
$
6,326

 
$
217,201

Loss on commodity derivatives, net
110

 
—

 
—

 
110

Total revenue
154,446

 
56,539

 
6,326

 
217,311

Operating expenses:
 
 
 
 
 
 
 
Purchases of natural gas, NGL's and condensate
125,888

 
37,110

 
—

 
162,998

Direct operating expenses
10,924

 
8,943

 
2,502

 
22,369