2014 Q2 10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 FORM 10-Q
    S
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended
June 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 11,143,553 common units, 5,430,455 Series A Units and 1,210,221 Series B Units of American Midstream Partners, LP outstanding as of August 7, 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.

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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.

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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)
 
June 30,
2014
 
December 31,
2013
Assets
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
3,007

 
$
393

Accounts receivable
7,337

 
6,822

Unbilled revenue
25,202

 
23,001

Risk management assets
885

 
473

Other current assets
5,996

 
7,497

Current assets held for sale
121

 
272

Total current assets
42,548

 
38,458

Property, plant and equipment, net
381,318

 
312,701

Goodwill
16,253

 
16,447

Intangible assets, net
49,522

 
3,682

Other assets, net
8,418

 
9,064

Noncurrent assets held for sale, net
1,148

 
1,723

Total assets
$
499,207

 
$
382,075

Liabilities, Equity and Partners’ Capital
 
 
 
Current liabilities
 
 
 
Accounts payable
$
10,538

 
$
3,261

Accrued gas purchases
17,256

 
17,386

Accrued expenses and other current liabilities
15,697

 
15,058

Current portion of long-term debt
574

 
2,048

Risk management liabilities
602

 
423

Current liabilities held for sale
54

 
114

Total current liabilities
44,721

 
38,290

Risk management liabilities
36

 
101

Asset retirement obligations
34,648

 
34,636

Other liabilities
229

 
191

Long-term debt
136,500

 
130,735

Deferred tax liability
4,694

 
4,749

Noncurrent liabilities held for sale, net

 
95

Total liabilities
220,828

 
208,797

Commitments and contingencies (see Note 14)


 


Convertible preferred units
 
 
 
Series A convertible preferred units (5,430 thousand and 5,279 thousand units issued and outstanding as of June 30, 2014, and December 31, 2013, respectively)
100,571

 
94,811

Equity and partners’ capital
 
 
 
General partner interest (235 thousand and 185 thousand units issued and outstanding as of June 30, 2014, and December 31, 2013, respectively)
(4,212
)
 
2,696

Limited partner interest (11,140 thousand and 7,414 thousand units issued and outstanding as of June 30, 2014, and December 31, 2013, respectively)
146,271

 
71,039


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Series B convertible units (1,210 thousand and zero units issued and outstanding as of June 30, 2014, and December 31, 2013, respectively)
31,052

 

Accumulated other comprehensive income
150

 
104

Total partners’ capital
173,261

 
73,839

Noncontrolling interests
4,547

 
4,628

Total equity and partners' capital
177,808

 
78,467

Total liabilities, equity and partners' capital
$
499,207

 
$
382,075

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

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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 June 30,
 
Six months ended June 30,
 
2014
 
2013
 
2014
 
2013
Revenue
$
77,873

 
$
76,277

 
$
158,241

 
$
139,181

(Loss) gain on commodity derivatives, net
(193
)
 
914

 
(323
)
 
609

Total revenue
77,680

 
77,191

 
157,918

 
139,790

Operating expenses:
 
 
 
 
 
 
 
Purchases of natural gas, NGLs and condensate
53,818

 
56,965

 
109,039

 
107,234

Direct operating expenses
11,044

 
8,402

 
20,005

 
13,277

Selling, general and administrative expenses
5,637

 
4,588

 
11,230

 
8,013

Equity compensation expense
435

 
1,097

 
795

 
1,485

Depreciation, amortization and accretion expense
6,012

 
8,748

 
13,644

 
14,394

Total operating expenses
76,946

 
79,800

 
154,713

 
144,403

Gain on involuntary conversion of property, plant and equipment

 

 

 
343

Loss on sale of assets, net

 

 
(21
)
 

Loss on impairment of property, plant and equipment

 
(15,232
)
 

 
(15,232
)
Operating income (loss)
734

 
(17,841
)
 
3,184

 
(19,502
)
Other expense:
 
 
 
 
 
 
 
Interest expense
(1,680
)
 
(2,591
)
 
(3,583
)
 
(4,322
)
Net loss before income tax benefit
(946
)
 
(20,432
)
 
(399
)
 
(23,824
)
Income tax (expense) benefit
(149
)
 
375

 
(138
)
 
375

Net loss from continuing operations
(1,095
)
 
(20,057
)
 
(537
)
 
(23,449
)
Discontinued operations:
 
 
 
 
 
 
 
Loss from operations of disposal groups, net of tax
(506
)
 
(1,869
)
 
(556
)
 
(1,875
)
Net loss
(1,601
)
 
(21,926
)
 
(1,093
)
 
(25,324
)
Net income attributable to noncontrolling interests
66

 
188

 
174

 
343

Net loss attributable to the Partnership
$
(1,667
)
 
$
(22,114
)
 
$
(1,267
)
 
$
(25,667
)
 
 
 
 
 
 
 
 
General partner's interest in net loss
$
(22
)
 
$
(905
)
 
$
(15
)
 
$
(974
)
Limited partners' interest in net loss
$
(1,645
)
 
$
(21,209
)
 
$
(1,252
)
 
$
(24,693
)
 
 
 
 
 
 
 
 
Distribution declared per common unit (a)
$
0.4625

 
$
0.4325

 
$
0.9150

 
$
0.8650

Limited partners' net loss per common unit (See Note 4 and Note 11):
 
 
 
 
Basic and diluted:
 
 
 
 
 
 
 
Loss from continuing operations
$
(0.55
)
 
$
(4.01
)
 
$
(0.92
)
 
$
(4.39
)
Loss from discontinued operations
(0.04
)
 
(0.20
)
 
(0.05
)
 
(0.19
)
Net loss
$
(0.59
)
 
$
(4.21
)
 
$
(0.97
)
 
$
(4.58
)
Weighted average number of common units outstanding:
 
 
 
 
Basic and diluted
11,139

 
9,198

 
10,496

 
9,183


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

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

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American Midstream Partners, LP and Subsidiaries
Condensed Consolidated Statements of Comprehensive Income
(Unaudited, in thousands)
 
Three months ended June 30,
 
Six months ended June 30,
 
2014
 
2013
 
2014
 
2013
Net loss
$
(1,601
)
 
$
(21,926
)
 
$
(1,093
)
 
$
(25,324
)
Unrealized gain (loss) on post retirement benefit plan assets and liabilities
10

 
(43
)
 
46

 
(56
)
Comprehensive loss
(1,591
)
 
(21,969
)
 
(1,047
)
 
(25,380
)
Less: Comprehensive income attributable to noncontrolling interests
66

 
188

 
174

 
343

Comprehensive loss attributable to Partnership
$
(1,657
)
 
$
(22,157
)
 
$
(1,221
)
 
$
(25,723
)
The accompanying notes are an integral part of these condensed consolidated financial statements.

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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
(974
)
 
(24,693
)
 

 

 
(25,667
)
 
343

Unitholder contributions
22,696

 

 

 

 
22,696

 

Unitholder distributions
(203
)
 
(9,749
)
 

 

 
(9,952
)
 

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

 

 
(15,612
)
 

Net distributions to noncontrolling interest holders

 

 

 

 

 
(443
)
LTIP vesting
(1,125
)
 
1,125

 

 

 

 

LTIP tax netting unit repurchase

 
(339
)
 

 

 
(339
)
 

Unit based compensation
1,460

 

 

 

 
1,460

 

Other comprehensive loss

 

 

 
(56
)
 
(56
)
 

Balances at June 30, 2013
$
22,090

 
$
30,310

 
$

 
$
295

 
$
52,695

 
$
7,338

 
 
 
 
 
 
 
 
 
 
 
 
Balances at December 31, 2013
$
2,696

 
$
71,039

 
$

 
$
104

 
$
73,839

 
$
4,628

Net (loss) income
(15
)
 
(1,252
)
 

 

 
(1,267
)
 
174

Issuance of common units to public, net of offering costs

 
86,904

 

 

 
86,904

 

Issuance of Series B convertible units

 

 
31,052

 

 
31,052

 

Unitholder contributions
1,276

 

 

 

 
1,276

 

Unitholder distributions
(1,192
)
 
(18,093
)
 

 

 
(19,285
)
 

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

 

 

 

 

Net distributions to noncontrolling interest owners

 

 

 

 

 
(226
)
Acquisition of noncontrolling interest

 
21

 

 

 
21

 
(29
)
LTIP vesting
(511
)
 
639

 

 

 
128

 

LTIP tax netting unit repurchase

 
(151
)
 

 

 
(151
)
 

Unit based compensation
698

 

 

 

 
698

 

Other comprehensive income

 

 

 
46

 
46

 

Balances at June 30, 2014
$
(4,212
)
 
$
146,271

 
$
31,052

 
$
150

 
$
173,261

 
$
4,547

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

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

Six months ended June 30,
 
2014
 
2013
Cash flows from operating activities

 

Net loss
$
(1,093
)
 
$
(25,324
)
Adjustments to reconcile net loss to net cash provided by operating activities:

 

Depreciation, amortization and accretion expense
13,644

 
14,431

Amortization of deferred financing costs
847

 
614

Amortization of weather derivative premium
554

 
95

Unrealized loss on commodity derivatives
113

 
245

Equity based compensation
730

 
1,460

OPEB plan net periodic benefit
(23
)
 
(37
)
Gain on involuntary conversion of property, plant and equipment

 
(343
)
Loss on sale of assets
106

 

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
(161
)
 
(414
)
Changes in operating assets and liabilities, net:
 

Accounts receivable
(556
)
 
1,976

Unbilled revenue
(2,083
)
 
(2,522
)
Risk management assets and liabilities
(965
)
 
(1,134
)
Other current assets
1,547

 
(315
)
Other assets, net
22

 
(62
)
Accounts payable
(851
)
 
3,648

Accrued gas purchases
(188
)
 
2,347

Accrued expenses and other current liabilities
680

 
856

Asset retirement obligations
(623
)
 

Other liabilities
38

 
(142
)
Net cash provided by operating activities
12,411

 
12,418

Cash flows from investing activities

 

Cost of acquisitions
(110,909
)
 

Additions to property, plant and equipment
(13,229
)
 
(13,606
)
Proceeds from disposals of property, plant and equipment
6,202

 

Insurance proceeds from involuntary conversion of property, plant and equipment

 
482

Net cash used in investing activities
(117,936
)
 
(13,124
)
Cash flows from financing activities

 

Proceeds from issuance of common units to public, net of offering costs
86,904

 

Unitholder contributions
1,276

 
575

Unitholder distributions
(13,793
)
 
(7,805
)
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
(226
)
 
(443
)
LTIP tax netting unit repurchase
(151
)
 
(339
)
Payments of deferred debt issuance costs
(154
)
 
(1,315
)

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Payments on other debt
(1,644
)
 
(1,139
)
Borrowings on other debt
170

 
1,495

Payments on loan to affiliate

 
(489
)
Payments on bank loans

 
1,274

Payments on long-term debt
(75,220
)
 
(56,546
)
Borrowings on long-term debt
80,985

 
51,921

Net cash provided by financing activities
108,139

 
1,582

Net increase in cash and cash equivalents
2,614

 
876

Cash and cash equivalents

 

Beginning of period
393

 
576

End of period
$
3,007

 
$
1,452

Supplemental cash flow information

 

Interest payments, net
$
2,718

 
$
3,049

Supplemental non-cash information

 

Increase (decrease) in accrued property, plant and equipment
$
9,501

 
$
(6,023
)
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
5,760

 
2,146

In-kind unitholder distribution for Series B Units
1,052

 

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 ten 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.

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.

Basis of Presentation

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 year ended December 31, 2013 and for the three and six months ended June 30, 2013 are not consistent with amounts previously presented as an asset group previously presented as held for sale was reclassified during the current period to held and used. As a result, we reclassified amounts within the comparative periods to reflect that reclassification.

Our financial results for the three and six months ended June 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

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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 June 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.

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.

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.

3. Acquisitions and Divestitures

Lavaca Acquisition

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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 to 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 including an economic obsolescence factor 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 gas gathering agreement and recognize $1.9 million of amortization expense annually over the gas gathering agreement.

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 EBITDA; 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.

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
55,654

Equipment
753

Total property, plant and equipment
56,409

Intangible assets
48,000

Total cash consideration
$
104,409


For the three and six months ended June 30, 2014, the Lavaca System contributed $3.7 million and $6.0 million of revenue and $0.6 million and $2.2 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 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

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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 six months ended June 30, 2014, Blackwater contributed $3.9 million and $7.5 million of revenue and $0.4 million of net loss and $0.5 million of net income, respectively, attributable to the Partnership's Terminals segment, which are included in the condensed consolidated statement of operations.

Subsequent to the acquisition of Blackwater, for the three and six months ended June 30, 2013, Blackwater contributed $2.9 million of revenue and $0.5 million of net loss 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 six months ended June 30, 2014, the High Point System contributed $7.3 million and $14.3 million of revenue and $3.1 million and $7.8 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 six months ended June 30, 2013, the High Point System contributed $5.2 million of revenue and $2.0 million 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.

As discussed in Note 2 “Recent Accounting Pronouncements”, the Partnership has elected to early adopt ASU 2014-08 effective with the interim period beginning April 1, 2014. The guidance is aimed at reducing the frequency of disposals reported as discontinued operations by focusing on strategic shifts that have, or will have, a major effect on an entity’s operations and financial results. Application of this new standard is prospective and therefore only applicable to those disposals and assets classified as held for sale after adoption of the new guidance. There was not a material impact from early adoption in the quarter ended June 30, 2014.


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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 six months ended June 30, 2014 and 2013 (in thousands, except per unit amounts):
 
Three months ended June 30,
 
Six months ended June 30,
 
2014
 
2013
 
2014
 
2013
Revenue
$
212

 
$
609

 
$
449

 
$
1,128

Expense
(268
)
 
(671
)
 
(545
)
 
(1,196
)
Loss on impairment of property, plant and equipment
(673
)
 
(1,807
)
 
(673
)
 
(1,807
)
Loss on sale of assets
(65
)
 

 
(87
)
 

Income tax benefit
288

 

 
300

 

Loss from operations of disposal groups, net of tax
$
(506
)
 
$
(1,869
)
 
$
(556
)
 
$
(1,875
)
Limited partners' net loss per unit from discontinued operations (basic and diluted)
$
(0.04
)
 
$
(0.20
)
 
$
(0.05
)
 
$
(0.19
)

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 have begun negotiations for the sale of those assets in the second half of 2014, contingent upon the purchaser’s completion of due diligence activities. There has been a deteriorating market for these certain assets and therefore the Partnership recognized an additional impairment on these assets of $0.7 million ($0.4 million, net of tax) in the three months ended June 30, 2014. 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 six months ended June 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:

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Three months ended June 30,
 
Six months ended June 30,
 
2014
 
2013
 
2014
 
2013
Customer A
26
%
 
24
%
 
27
%
 
27
%
Customer B
14
%
 
11
%
 
14
%
 
12
%
Customer C
11
%
 
12
%
 
10
%
 
13
%
Customer D
10
%
 
%
 
10
%
 
10
%
Other
39
%
 
53
%
 
39
%
 
38
%
Total
100
%
 
100
%
 
100
%
 
100
%

6. Derivatives

Commodity Derivatives

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 June 30, 2014, the aggregate notional volume of our commodity derivatives was 4.7 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 June 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 June 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 2013 and 2014, 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 $0.9 million as of June 30, 2014. The weather derivative entered into in the second quarter of 2013 was fully amortized as of June 30, 2014.

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As of June 30, 2014 and December 31, 2013, the value associated with our commodity derivatives and interest rate swap instrument 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
 
June 30,
2014
 
December 31, 2013
 
June 30,
2014
 
December 31, 2013
 
June 30,
2014
 
December 31, 2013
Current
 
$
885

 
$
473

 
$

 
$

 
$
885

 
$
473

Noncurrent
 

 

 

 

 

 

Total assets
 
$
885

 
$
473

 
$

 
$

 
$
885

 
$
473

 
 
 
 
 
 
 
 
 
 
 
 
 
Current
 
$
153

 
$
27

 
$
(755
)
 
$
(450
)
 
$
(602
)
 
$
(423
)
Noncurrent
 

 

 
(36
)
 
(101
)
 
(36
)
 
(101
)
Total liabilities
 
$
153

 
$
27

 
$
(791
)
 
$
(551
)
 
$
(638
)
 
$
(524
)
For the three and six months ended June 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 June 30,
 
Six months ended June 30,
 
Gain (loss) on derivatives
 
Gain (loss) on derivatives
Statement of Operations Classification
Realized
 
Unrealized
 
Realized
 
Unrealized
2014
 
 
 
 
 
 
 
Loss on commodity derivatives, net
$
(80
)
 
$
(113
)
 
(182
)
 
(141
)
Interest expense
(109
)
 
38

 
(213
)
 
28

Direct operating expenses
(269
)
 

 
(553
)
 

Total
$
(458
)
 
$
(75
)
 
$
(948
)
 
$
(113
)
2013
 
 
 
 
 
 
 
Gain on commodity derivatives, net
$
360

 
$
554

 
536

 
73

Interest expense

 
(318
)
 

 
(318
)
Direct operating expenses
(95
)
 

 
(95
)
 

Total
$
265

 
$
236

 
$
441

 
$
(245
)

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.


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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 June 30, 2014 and December 31, 2013 (in thousands):
 
Carrying
Amount
 
Estimated Fair Value
 
Level 1
 
Level 2
 
Level 3
 
Total
Commodity derivative instruments, net
 
 
 
 
 
 
 
 
 
June 30, 2014
$
(211
)
 
$

 
$
(211
)
 
$

 
$
(211
)
December 31, 2013
(70
)
 

 
(70
)
 

 
(70
)
Interest rate swap
 
 
 
 
 
 
 
 
 
June 30, 2014
$
(426
)
 
$

 
$
(426
)
 
$

 
$
(426
)
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 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 June 30, 2014 and December 31, 2013 were as follows (in thousands):
 
Useful Life
(in years)
 
June 30,
2014
 
December 31,
2013
Land
N/A
 
$
6,133

 
$
6,015

Construction in progress
N/A
 
20,305

 
6,443

Base gas
N/A
 
1,108

 
1,108

Buildings and improvements
4 to 40
 
5,299

 
5,109

Processing and treating plants
8 to 40
 
98,404

 
97,106

Pipelines
5 to 40
 
298,168

 
239,865

Compressors
4 to 20
 
12,488

 
11,955

Dock
20 to 40
 
7,954

 
7,942

Tanks, truck rack and piping
20 to 40
 
22,432

 
22,432

Equipment
8 to 20
 
8,497

 
6,294

Computer software
5
 
3,595

 
3,531

Total property, plant and equipment
 
 
484,383

 
407,800

Accumulated depreciation
 
 
(103,065
)
 
(95,099
)
Property, plant and equipment, net
 
 
$
381,318

 
$
312,701


Of the gross property, plant and equipment balances at June 30, 2014 and December 31, 2013, $101.4 million and $100.5 million, respectively, were related to AlaTenn, Midla and HPGT, our FERC regulated interstate and intrastate assets.

Capitalized interest was $0.1 million and less than $0.1 million for the three months ended June 30, 2014 and 2013, respectively, and $0.2 million and $0.1 million for the six months ended June 30, 2014 and 2013, respectively.

Depreciation expense was $4.7 million and $6.8 million for the three months ended June 30, 2014 and 2013, respectively, and $11.1 million and $12.4 million for the six months ended June 30, 2014 and 2013, respectively.


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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 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 six months ended June 30, 2014. The following table is a reconciliation of the asset retirement obligations (in thousands):
 
June 30, 2014
Beginning asset retirement obligation
$
34,636

Liabilities assumed
248

Expenditures
(623
)
Accretion expense
387

Ending asset retirement obligation
$
34,648

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 June 30, 2014.

10. Debt Obligations

As of June 30, 2014, the Partnership's Credit Agreement (the "Credit Agreement") provides for a maximum borrowing equal to $200.0 million subject to, among other restrictions, the requirement that our indebtedness not exceed 5.75 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 1.50% to 3.75% 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 2.50% to 4.75% depending on the total leverage ratio then in effect. We also paid a 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 the majority of our real property. Advances made under the credit facility 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 August 1, 2016.

The credit facility 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 5.75 times) and ii) a minimum interest coverage ratio test (not less than 2.50).

For the six months ended June 30, 2014 and 2013, the weighted average interest rate on borrowings under our credit facility was approximately 4.18% and 4.48%, respectively.


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As of June 30, 2014, our consolidated total leverage was 3.51 times, which was in compliance with the consolidated total leverage ratio test in our credit facility, and we had approximately $136.5 million of outstanding borrowings under our credit facility and approximately $59.2 million of available borrowing capacity.

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.

Our outstanding borrowings at June 30, 2014 and December 31, 2013, respectively, were (in thousands):
 
June 30,
2014
 
December 31,
2013
Revolving credit facility
$
136,500

 
$
130,735

Other debt
574

 
2,048

Total debt
137,074

 
132,783

Less: current portion
574

 
2,048

Long-term debt
$
136,500

 
$
130,735

At June 30, 2014 and December 31, 2013, letters of credit outstanding under the credit facility totaled $4.3 million and $4.8 million, respectively.

In connection with our credit facility and amendments thereto, we incurred $6.6 million in debt issuance costs that are being amortized on a straight-line basis over the term of the credit facility.

11. Partners’ Capital and Convertible Preferred Units

Our capital accounts are comprised of approximately a 1.3% general partner interest 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 IDRs 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 six months ended June 30, 2014, the Partnership issued 41,996 of paid-in-kind Series B Units with a fair value of $1.1 million.

Equity Offering

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.

General Partner Units


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In connection with our equity offering, we received proceeds of $1.3 million from our General Partner as consideration for 49,678 additional general partner units.

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 June 30, 2014 and December 31, 2013, respectively, were as follows (in thousands):
 
June 30,
2014
 
December 31,
2013
Series A convertible preferred units
5,430

 
5,279

Series B convertible units
1,210

 

Limited partner common units
11,140

 
7,414

General partners units
235

 
185


Distributions

We made cash distributions of $5.8 million and $11.1 million, inclusive of distributions of $0.5 million and $0.9 million in respect of our General Partner’s incentive distribution rights, in the three and six months ended June 30, 2014, respectively. We made distributions of $3.7 million and $7.8 million in the three and six months ended June 30, 2013, respectively. We made no distributions in respect of our General Partner's incentive distribution rights in the six months ended June 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 of our operating cashflow.

The Partnership executed an amendment to the Partnership agreement, which became effective August 4, 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, beginning with the distribution for the three months ended June 30, 2014 and the subsequent three fiscal quarters. 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 as of June 30, 2014, we have accrued $3.9 million for the paid-in-kind Series A Units. The distributions will be made in the third 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

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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.

We determined basic and diluted net income (loss) per limited partner unit as follows, (in thousands, except per unit amounts):
 
Three months ended June 30,
 
Six months ended June 30,
 
2014
 
2013
 
2014
 
2013
Net loss from continuing operations
$
(1,095
)
 
$
(20,057
)
 
$
(537
)
 
$
(23,449
)
Less: Net income attributable to noncontrolling interests
66

 
188

 
174

 
343

Net loss from continuing operations attributable to the Partnership
(1,161
)
 
(20,245
)
 
(711
)
 
(23,792
)
Less:
 
 
 
 
 
 
 
Contractual distributions on Series A Units
3,917

 
17,760

 
7,098

 
17,760

Declared distributions on Series B Units
560

 

 
1,052

 

General partner's distribution
603

 
80

 
1,085

 
160

General partner's share in undistributed loss
(149
)
 
(1,236
)
 
(262
)
 
(1,386
)
Net loss from continuing operations available to limited partners
(6,092
)
 
(36,849
)
 
(9,684
)
 
(40,326
)
Net loss from operations of disposal groups, net of tax, available to limited partners
(499
)
 
(1,846
)
 
(549
)
 
(1,710
)
Net loss available to limited partners
$
(6,591
)
 
$
(38,695
)
 
$
(10,233
)
 
$
(42,036
)
 
 
 
 
 
 
 
 
Weighted average number of units used in computation of limited partners’ net (loss) income per unit (basic and diluted)
11,139

 
9,198

 
10,496

 
9,183

 
 
 
 
 
 
 
 
Limited partners' net loss per common unit
 
 
 
 
 
 
 
Basic and diluted:
 
 
 
 
 
 
 
Loss from continuing operations
$
(0.55
)
 
$
(4.01
)
 
$
(0.92
)
 
$
(4.39
)
Loss from discontinued operations
(0.04
)
 
(0.20
)
 
(0.05
)
 
(0.19
)
Net loss
$
(0.59
)
 
$
(4.21
)
 
$
(0.97
)
 
$
(4.58
)

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 June 30, 2014 and December 31, 2013, 685,492 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 six months ended June 30, 2014 indicated, in units:

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

 
17.62

Granted
 
180,791

 
20.56

Forfeited
 
(5,135
)
 
20.13

Vested
 
(31,829
)
 
19.34

Outstanding at end of period
 
219,356

 
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, including amortization, for the three months ended June 30, 2014 and 2013 were $0.4 million and $1.1 million, respectively, and for the six months ended June 30, 2014 and 2013 were $0.8 million and $1.5 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 $0.8 million and $1.1 million for the six months ended June 30, 2014 and 2013, respectively.

The total compensation cost related to unvested awards not yet recognized at June 30, 2014 and 2013 was $3.8 million and $1.1 million, respectively, and the weighted average period over which this cost is expected to be recognized as of June 30, 2014 is approximately 3.4 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 six months ended June 30, 2014 was $0.1 million and $0.1 million, respectively, resulting in an effective tax rate of 15.8% and 34.6%, respectively. For the three and six months ended June 30, 2013, Partnership income tax was a benefit of $0.4 million, resulting in an effective tax rate of 1.8% and 1.6%, respectively.

The effective tax rates for the three and six months ended June 30, 2014 and June 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 and are eliminated in the consolidation of Net loss before income tax 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 third 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.

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 six months ended June 30, 2014, administrative and operational services expenses of $5.1 million and $10.1 million, respectively, were charged to us by our General Partner. During the three and six months ended June 30, 2013, administrative and operational services expenses of $3.8 million and $6.3 million, respectively, were charged to us by our General Partner. For the three and six months ended June 30, 2014, we incurred approximately $0.2 million and $0.7 million, respectively, of costs primarily associated with certain business development activities led by an affiliate of our General Partner. For the three and six months ended June 30, 2013, we incurred approximately $0.2 million and $0.5 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 current 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 months ended June 30, 2014, the Partnership recognized $0.2 million 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

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 crude oil, bunker fuel, distillates, chemicals and agricultural products.

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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 six months ended June 30, 2014 and 2013 (in thousands):
 
 
Three months ended June 30, 2014
 
Gathering
and
Processing
 
Transmission
 
Terminals
 
Total
Revenue
$
50,015

 
$
23,960

 
$
3,898

 
$
77,873

Loss on commodity derivatives, net
(193
)
 

 

 
(193
)
Total revenue
49,822

 
23,960

 
3,898

 
77,680

Operating expenses:
 
 
 
 
 
 
 
Purchases of natural gas, NGL's and condensate
39,238

 
14,580

 

 
53,818

Direct operating expenses
5,746

 
3,736

 
1,562

 
11,044

Selling, general and administrative expenses
 
 
 
 
 
 
5,637

Equity compensation expense
 
 
 
 
 
 
435

Depreciation, amortization and accretion expense
 
 
 
 
 
 
6,012

Total operating expenses
 
 
 
 
 
 
76,946

Interest expense
 
 
 
 
 
 
(1,680
)
Income tax benefit
 
 
 
 
 
 
(149
)
Loss from operations of disposal groups, net of tax
 
 
 
 
 
 
(506
)
Net income
 
 
 
 
 
 
(1,601
)
Less: Net income attributable to non-controlling interests
 
 
 
 
 
 
66

Net income attributable to the Partnership
 
 
 
 
 
 
$
(1,667
)
 
 
 
 
 
 
 
 
Segment gross margin (a)
$
10,481

 
$
9,350

 
$
2,336

 
$
22,167



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Three months ended June 30, 2013
 
Gathering
and
Processing
 
Transmission
 
Terminals
 
Total
Revenue
$
52,525

 
$
20,886

 
$
2,866

 
$
76,277

Gain on commodity derivatives, net
914

 

 

 
914

Total revenue
53,439

 
20,886

 
2,866

 
77,191

Operating expenses:
 
 
 
 
 
 
 
Purchases of natural gas, NGL's and condensate
43,702

 
13,263

 

 
56,965

Direct operating expenses
3,637

 
3,556

 
1,209

 
8,402

Selling, general and administrative expenses
 
 
 
 
 
 
4,588

Equity compensation expense
 
 
 
 
 
 
1,097

Depreciation, amortization and accretion expense
 
 
 
 
 
 
8,748

Total operating expenses
 
 
 
 
 
 
79,800

Loss on impairment of property, plant and equipment
 
 
 
 
 
 
(15,232
)
Interest expense
 
 
 
 
 
 
(2,591
)
Income tax benefit
 
 
 
 
 
 
375

Loss from operations of disposal groups, net of tax
 
 
 
 
 
 
(1,869
)
Net loss
 
 
 
 
 
 
(21,926
)
Less: Net income attributable to non-controlling interests
 
 
 
 
 
 
188

Net loss attributable to the Partnership
 
 
 
 
 
 
$
(22,114
)
 
 
 
 
 
 
 
 
Segment gross margin (a)
$
9,077

 
$
7,583

 
$
1,657

 
$
18,317


 
Six months ended June 30, 2014
 
Gathering
and
Processing
 
Transmission
 
Terminals
 
Total
Revenue
$
101,641

 
$
49,088

 
$
7,512

 
$
158,241

Loss on commodity derivatives, net
(323
)
 

 

 
(323
)
Total revenue
101,318

 
49,088

 
7,512

 
157,918

Operating expenses:
 
 
 
 
 
 
 
Purchases of natural gas, NGL's and condensate
80,359

 
28,680

 

 
109,039

Direct operating expenses
9,914

 
6,854

 
3,237

 
20,005

Selling, general and administrative expenses
 
 
 
 
 
 
11,230

Equity compensation expense
 
 
 
 
 
 
795

Depreciation, amortization and accretion expense
 
 
 
 
 
 
13,644

Total operating expenses
 
 
 
 
 
 
154,713

Loss on sale of assets, net
 
 
 
 
 
 
(21
)
Interest expense
 
 
 
 
 
 
(3,583
)
Income tax benefit
 
 
 
 
 
 
(138
)
Loss from operations of disposal groups, net of tax
 
 
 
 
 
 
(556
)
Net income
 
 
 
 
 
 
(1,093
)
Less: Net income attributable to non-controlling interests
 
 
 
 
 
 
174

Net income attributable to the Partnership
 
 
 
 
 
 
$
(1,267
)
 
 
 
 
 
 
 
 
Segment gross margin (a)
$
20,610

 
$
20,363

 
$
4,275

 
$
45,248



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Six months ended June 30, 2013
 
Gathering
and
Processing
 
Transmission
 
Terminals
 
Total
Revenue
$
100,766

 
$
35,549

 
$
2,866

 
$
139,181

Loss on commodity derivatives, net
609

 

 

 
609

Total revenue
101,375

 
35,549

 
2,866

 
139,790

Operating expenses:
 
 
 
 
 
 
 
Purchases of natural gas, NGL's and condensate
83,370

 
23,864

 

 
107,234

Direct operating expenses
7,127

 
4,941

 
1,209

 
13,277

Selling, general and administrative expenses
 
 
 
 
 
 
8,013

Equity compensation expense
 
 
 
 
 
 
1,485

Depreciation, amortization and accretion expense
 
 
 
 
 
 
14,394

Total operating expenses
 
 
 
 
 
 
144,403

Gain on involuntary conversion of property, plant and equipment
 
 
 
 
 
 
343

Loss on impairment of property, plant and equipment
 
 
 
 
 
 
(15,232
)
Interest expense
 
 
 
 
 
 
(4,322
)
Income tax benefit
 
 
 
 
 
 
375

Loss from operations of disposal groups, net of tax
 
 
 
 
 
 
(1,875
)
Net loss
 
 
 
 
 
 
(25,324
)
Less: Net income attributable to non-controlling interests
 
 
 
 
 
 
343

Net loss attributable to the Partnership
 
 
 
 
 
 
$
(25,667
)
 
 
 
 
 
 
 
 
Segment gross margin (a)
$
17,784

 
$
11,581

 
$
1,657

 
$
31,022


(a)
Segment gross margin for our Gathering and Processing segment consists of revenue less purchases of natural gas, NGLs and condensate and revenue from construction, operating and maintenance agreements (“COMA”). Segment gross margin for our Transmission segment consists of re