AMID 2013.06.30 10-Q
Table of Contents

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, 2013
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.)
 
 
1614 15th Street, Suite 300
 
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
¨
Non-accelerated filer
ý (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 4,696,666 common units, 4,526,066 subordinated units and 5,142,857 Series A Convertible Preferred Units of American Midstream Partners, LP outstanding as of July 31, 2013. Our common units trade on the New York Stock Exchange under the ticker symbol “AMID.”

Table of Contents

TABLE OF CONTENTS
 
 
 
Page
Item 1.
 
 
 
 
 
 
 
 
 
Item 2.
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 3.
 
 
 
Item 4.
 
 
 
 
 
Item 1.
Item 1A.
Item 2.
Item 3.
Item 4.
Item 5.
Item 6.

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:
 
ASC        Accounting Standards Codification; trademark of the Financial Accounting Standards Board (FASB).

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

Bcf         One billion cubic feet.

Btu
British thermal unit; the approximate amount of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

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.

EBITDA
Net income (loss) before net interest expense, income taxes, and depreciation and amortization. EBITDA is a non-GAAP measurement.

FERC         Federal Energy Regulatory Commission.

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

GAAP
General Accepted Accounting Principles: Accounting principles generally accepted in the United States of America.

Gal         Gallons.

MBbl         One thousand barrels.

MMBbl         One million barrels.

MMBtu         One million British thermal units.

Mcf         One thousand cubic feet.

MMcf         One million cubic feet.

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
Table of Contents

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
American Midstream Partners, LP and Subsidiaries
Condensed Consolidated Balance Sheets
(Unaudited, in thousands)
 
June 30,
2013
 
December 31, 2012
Assets
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
423

 
$
576

Accounts receivable
3,222

 
1,958

Unbilled revenue
25,479

 
21,512

Risk management assets
2,082

 
969

Other current assets
5,530

 
3,226

Total current assets
36,736

 
28,241

Property, plant and equipment, net
282,953

 
223,819

Noncurrent assets held for sale, net
874

 
—

Other assets, net
6,380

 
4,636

Total assets
$
326,943

 
$
256,696

Liabilities, Equity and Partners’ Capital
 
 
 
Current liabilities
 
 
 
Accounts payable
$
6,183

 
$
5,527

Accrued gas purchases
19,381

 
17,034

Accrued expenses and other current liabilities
12,826

 
9,619

Current portion of long-term debt
1,250

 
—

Risk management liabilities
290

 
—

Total current liabilities
39,930

 
32,180

Risk management liabilities
28

 
—

Asset retirement obligations
34,250

 
8,319

Other liabilities
188

 
309

Long-term debt
123,660

 
128,285

Total liabilities
198,056

 
169,093

Commitments and contingencies (see Note 13)


 


Convertible preferred units
 
 
 
Series A convertible preferred units (5,143 thousand units issued and outstanding as of June 30, 2013)
91,073

 
—

Equity and partners’ capital
 
 
 
General partner interest (185 thousand units issued and outstanding as of June 30, 2013 and December 31, 2012)
(129
)
 
548

Limited partner interest (9,209 and 9,165 thousand units issued and outstanding as of June 30, 2013 and December 31, 2012, respectively)
30,310

 
79,266

Accumulated other comprehensive income
295

 
351

Total partners’ capital
30,476

 
80,165

Noncontrolling interests
7,338

 
7,438

Total equity and partners' capital
37,814

 
87,603

Total liabilities, equity and partners' capital
$
326,943

 
$
256,696

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

4
Table of Contents

American Midstream Partners, LP and Subsidiaries
Condensed Consolidated Statements of Operations
(Unaudited, in thousands, except for per unit amounts)

 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2013
 
2012
 
2013
 
2012
Revenue
$
73,828

 
$
39,487

 
$
133,613

 
$
84,077

Gain on commodity derivatives, net
914

 
3,835

 
609

 
4,103

Total revenue
74,742

 
43,322

 
134,222

 
88,180

Operating expenses:
 
 
 
 
 
 
 
Purchases of natural gas, NGLs and condensate
57,396

 
27,942

 
104,698

 
58,711

Direct operating expenses
7,121

 
3,194

 
11,923

 
6,079

Selling, general and administrative expenses
4,588

 
3,668

 
8,013

 
6,997

Equity compensation expense
1,097

 
467

 
1,485

 
798

Depreciation and accretion expense
6,698

 
5,092

 
12,344

 
10,218

Total operating expenses
76,900

 
40,363

 
138,463

 
82,803

Gain on involuntary conversion of property, plant and equipment
—

 
—

 
343

 
—

Gain on sale of assets, net
—

 
117

 
—

 
122

Loss on impairment of property, plant and equipment
(15,232
)
 
—

 
(15,232
)
 
 
Operating (loss) income
(17,390
)
 
3,076

 
(19,130
)
 
5,499

Other expense:
 
 
 
 
 
 
 
Interest expense
(2,190
)
 
(825
)
 
(3,921
)
 
(1,582
)
Net (loss) income from continuing operations
$
(19,580
)
 
$
2,251

 
$
(23,051
)
 
$
3,917

Discontinued operations
 
 
 
 
 
 
 
(Loss) gain from operations of disposal groups
$
(1,869
)
 
$
76

 
$
(1,796
)
 
$
101

Net (loss) income
$
(21,449
)
 
$
2,327

 
$
(24,847
)
 
$
4,018

Net income attributable to noncontrolling interests
$
188

 
$
—

 
$
343

 
$
—

Net (loss) income attributable to the Partnership
$
(21,637
)
 
$
2,327

 
$
(25,190
)
 
$
4,018

General partners' interest in net (loss) income
$
(428
)
 
$
46

 
$
(497
)
 
$
80

Limited partners’ interest in net (loss) income
$
(21,209
)
 
$
2,281

 
$
(24,693
)
 
$
3,938

Limited partners’ net (loss) income from continuing operations per unit (basic) (See Note 10)
$
(4.00
)
 
$
0.24

 
$
(4.39
)
 
$
0.42

Limited partners’ net (loss) income per unit (basic) (See Note 10)
$
(4.20
)
 
$
0.25

 
$
(4.58
)
 
$
0.43

Weighted average number of units used in computation of limited partners’ net (loss) income per unit (basic)
9,198

 
9,107

 
9,183

 
9,100

Limited partners’ net (loss) income from continuing operations per unit (diluted) (See Note 10)
$
(4.00
)
 
$
0.24

 
$
(4.39
)
 
$
0.41

Limited partners’ net (loss) income per unit (diluted) (See Note 10)
$
(4.20
)
 
$
0.25

 
$
(4.58
)
 
$
0.43

Weighted average number of units used in computation of limited partners’ net (loss) income per unit (diluted) (See Note 10)
9,198

 
9,276

 
9,183

 
9,263

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

5
Table of Contents

American Midstream Partners, LP and Subsidiaries
Condensed Consolidated Statements of Comprehensive Income
(Unaudited, in thousands)
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2013
 
2012
 
2013
 
2012
Net (loss) income
$
(21,449
)
 
$
2,327

 
$
(24,847
)
 
$
4,018

Unrealized gain (loss) on post retirement benefit plan assets and liabilities
(43
)
 
14

 
(56
)
 
17

Comprehensive (loss) income
(21,492
)
 
2,341

 
(24,903
)
 
4,035

Less: Comprehensive income attributable to noncontrolling interests
188

 
—

 
343

 
—

Comprehensive (loss) income attributable to Partnership
$
(21,680
)
 
$
2,341

 
$
(25,246
)
 
$
4,035

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

6
Table of Contents

American Midstream Partners, LP and Subsidiaries
Condensed Consolidated Statements of Changes in Partners’ Capital
and Noncontrolling Interest
(Unaudited, in thousands)
 
 
 
Limited
Partner
Interest
 
General
Partner
Interest
 
Accumulated
Other
Comprehensive
Income
 
Total Partners' Capital
 
Noncontrolling Interest
Balances at December 31, 2011
 
$
99,890

 
$
1,091

 
$
415

 
$
101,396

 
—

Net income
 
3,938

 
80

 
—

 
4,018

 
—

Unitholder contributions
 
—

 
13

 
—

 
13

 
—

Unitholder distributions
 
(7,870
)
 
(161
)
 
—

 
(8,031
)
 
—

LTIP vesting
 
364

 
(364
)
 
—

 
—

 
—

Tax netting repurchase
 
(88
)
 
—

 
—

 
(88
)
 
—

Unit based compensation
 
97

 
701

 
—

 
798

 
—

Other comprehensive income
 
—

 
—

 
17

 
17

 
—

Balances at June 30, 2012
 
$
96,331

 
$
1,360

 
$
432

 
$
98,123

 
—

 
 
 
 
 
 
 
 
 
 
 
Balances at December 31, 2012
 
$
79,266

 
$
548

 
$
351

 
$
80,165

 
$
7,438

Net (loss) income
 
(24,693
)
 
(497
)
 
—

 
(25,190
)
 
343

Unitholder distributions
 
(9,749
)
 
(203
)
 
—

 
(9,952
)
 
—

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

 
(15,612
)
 
—

Net distributions to noncontrolling interest owners
 
—

 
—

 
—

 
—

 
(443
)
LTIP vesting
 
1,125

 
(1,125
)
 
—

 
—

 
—

Tax netting repurchase
 
(339
)
 
—

 
—

 
(339
)
 
—

Unit based compensation
 
—

 
1,460

 
—

 
1,460

 
—

Other comprehensive loss
 
—

 
—

 
(56
)
 
(56
)
 
—

Balances at June 30, 2013
 
$
30,310

 
$
(129
)
 
$
295

 
$
30,476

 
$
7,338

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

7
Table of Contents

American Midstream Partners, LP and Subsidiaries
Condensed Consolidated Statements of Cash Flows
(Unaudited, in thousands)
 
Six Months Ended June 30,
 
2013
 
2012
Cash flows from operating activities
 
 
 
Net (loss) income
$
(24,847
)
 
$
4,018

Adjustments to reconcile net (loss) income to net cash provided by operating activities:

 

Depreciation and accretion expense
12,344

 
10,283

Amortization of deferred financing costs
614

 
284

Amortization of weather derivative premium
95

 
—

Unrealized loss (gain) on commodity derivatives
245

 
(3,494
)
Unit based compensation
1,460

 
798

OPEB plan net periodic cost (benefit)
(37
)
 
(41
)
Gain on involuntary conversion of property, plant and equipment
(343
)
 
—

Gain on sale of assets, net
—

 
(122
)
Loss on impairment of property, plant and equipment
15,232

 
—

Loss on impairment of noncurrent assets held for sale
1,807

 
—

Changes in operating assets and liabilities, net:
 

Accounts receivable
2,365

 
(55
)
Unbilled revenue
(2,522
)
 
5,656

Risk management assets
(1,134
)
 
—

Other current assets
(255
)
 
1,013

Other assets, net
(62
)
 
(41
)
Accounts payable
3,639

 
(160
)
Accrued gas purchases
2,347

 
(5,264
)
Accrued expenses and other current liabilities
832

 
(1,769
)
Other liabilities
(121
)
 
(135
)
Net cash provided by operating activities
11,659

 
10,971

Cash flows from investing activities
 
 
 
Additions to property, plant and equipment
(12,516
)
 
(2,384
)
Proceeds from disposals of property, plant and equipment
—

 
122

Insurance proceeds from involuntary conversion of property, plant and equipment
482

 
—

Funds held in escrow
—

 
(5,500
)
Net cash used in investing activities
(12,034
)
 
(7,762
)
Cash flows from financing activities
 
 
 
Unit holder contributions
—

 
13

Unit holder distributions
(7,805
)
 
(8,031
)
Issuance of Series A convertible preferred units, net
14,393

 
—

Net distributions to noncontrolling interest owners
(443
)
 
—

LTIP tax netting unit repurchase
(339
)
 
(88
)
Payments for deferred debt issuance costs
(1,315
)
 
(926
)
Payments on other debt
(1,139
)
 
—

Borrowings on other debt
1,495

 
—

Payments on long-term debt
(56,546
)
 
(25,350
)
Borrowings on long-term debt
51,921

 
31,340

Net cash used in financing activities
222

 
(3,042
)

8
Table of Contents

Net (decrease) increase in cash and cash equivalents
(153
)
 
167

Cash and cash equivalents
 
 
 
Beginning of period
576

 
871

End of period
$
423

 
$
1,038

Supplemental cash flow information
 
 
 
Interest payments
$
3,017

 
$
1,043

Supplemental non-cash information
 
 
 
(Decrease) increase in accrued property, plant and equipment
$
(5,769
)
 
$
66

Receivable for reimbursable construction in progress projects
$
—

 
$
610

Net assets contributed in exchange for the issuance of Series A convertible preferred units (see Note 3)
$
59,994

 
$
—

Fair value of Series A Units in excess of net assets received
$
15,612

 
$
—

Accrued unitholder distribution for Series A Units
$
2,146

 
$
—

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

9
Table of Contents

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 acquiring and operating certain natural gas pipeline and processing businesses. We provide natural gas gathering, treating, processing, fractionating, marketing and transportation services primarily in the Gulf Coast and Southeast regions of the United States. We hold our assets in a series of wholly owned limited liability companies as well as a limited partnership. 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:
•
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; and
•
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.
ArcLight Transactions
On April 15, 2013, the Partnership, our general partner and AIM Midstream Holdings, LLC ("AIM"), an affiliate of American Infrastructure MLP Fund, entered into agreements (the "ArcLight Transactions") with High Point Infrastructure Partners, LLC ("HPIP"), an affiliate of ArcLight Capital Partners, LLC, pursuant to which HPIP (i) acquired 90% of our general partner and all of our subordinated units from AIM and (ii) contributed certain midstream assets and $15.0 million in cash to us in exchange for 5,142,857 newly issued convertible preferred units (the “Series A Units”) issued by the Partnership.  Of the $15.0 million cash consideration paid by High Point, approximately $2.5 million was used to pay certain transaction expenses of High Point, and the remaining approximately $12.5 million was used to repay borrowings outstanding under the Partnership's credit facility in connection with the Fourth Amendment. As a result of these transactions, which were also consummated on April 15, 2013, HPIP acquired both control of our general partner and a majority of our outstanding limited partner interests.  The midstream assets contributed by HPIP consist of approximately 600 miles of natural gas and liquids pipeline assets located in southeast Louisiana and the shallow water and deep shelf Gulf of Mexico (commonly referred to as the "High Point system"). The High Point system gathers natural gas from both onshore and offshore producing regions around southeast Louisiana. The onshore footprint is in Plaquemines and St. Bernard's Parishes, LA. The offshore footprint consists of the following federal Gulf of Mexico zones: Mississippi Canyon, Viosca Knoll, West Delta, Main Pass, South Pass and Breton Sound. Natural gas is collected at more than 75 receipt points that connect to hundreds of wells targeting various geological zones in water depths up to 1,000 feet, with an emphasis on oil and liquids-rich reservoirs. The High Point system is comprised of FERC-regulated transmission assets and non-jurisdictional assets, both of which accept natural gas from well production and interconnected pipeline systems. Natural gas is delivered to the Toca Gas Processing Plant, operated by Enterprise, where the products are processed and the residue gas sent to an unaffiliated interstate system owned by Kinder Morgan. See Note 3 "Acquisitions and Divestitures" for further information.

The Partnership believes that the consummation of the ArcLight Transactions will allow it to comply with the Consolidated Total Leverage to EBTIDA ratio in the Fourth Amendment to our June 2012 amended credit agreement ("Fourth Amendment"). However, no assurances can be given that the Partnership's results of operations following the ArcLight Transactions will allow us to comply with financial covenants of the Fourth Amendment. If we are not able to generate sufficient cash flows from operations to comply with the financial covenants in the Fourth Amendment and we are not able enter into an agreement to refinance or obtain covenant default waivers, then the outstanding balance under our credit facility could become due and payable upon acceleration by the lenders in our banking group and other agreements with cross-default provisions, if any, could become due. In addition, failure to comply with any of the covenants under our Fourth Amendment could adversely affect our ability to fund ongoing operations and growth capital requirements as well as our ability to pay distributions to our unitholders. See Note 17 "Liquidity" for further information.
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 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

10
Table of Contents

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 as of June 30, 2013, and December 31, 2012, condensed consolidated statement of operations for the three and six months ended June 30, 2013 and 2012, statement of comprehensive income for the three and six months ended June 30, 2013 and 2012, statement of changes in partners’ capital and noncontrolling interest for the six months ended June 30, 2013 and 2012, and statements of cash flows for the six months ended June 30, 2013 and 2012.
Our financial results for the six months ended June 30, 2013 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2013. These unaudited condensed consolidated financial statements should be read in conjunction with our consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2012 (“Annual Report”) filed on April 16, 2013.
Consolidation Policy
Our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. We hold an undivided interest in the Burns Point gas processing facility in which we are responsible for our proportionate share of the costs and expenses of the facility. Our consolidated financial statements reflect our proportionate share of the revenues, expenses, assets and liabilities of this undivided interest. In July 2012, the Partnership acquired a 87.4% undivided interest in the Chatom Processing and Fractionation facility (the "Chatom system"). Our consolidated financial statements reflect the accounts of the Chatom system since acquisition, and the interests in the Chatom system held by non-affiliated working interest owners are reflected as noncontrolling interests in the Partnership's consolidated financial statements.
Use of Estimates
When preparing 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 (1) estimating unbilled revenues, product purchases and operating and general and administrative costs, (2) developing fair value assumptions, including estimates of future cash flows and discount rates, (3) analyzing long-lived assets for possible impairment, (4) estimating the useful lives of assets and (5) determining amounts to accrue for contingencies, guarantees and indemnifications. Actual results, therefore, could differ materially from estimated amounts.
2. Summary of Significant Accounting Policies

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

Recent Accounting Pronouncements

In January 2013, the FASB issued Accounting Standards Update ("ASU") No. 2013-01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, which clarifies that ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities, applies to financial instruments or derivative transactions accounted for under ASC 815. The amendments require disclosures to present both gross and net amounts of derivative assets and liabilities that are subject to master netting arrangements with counterparties. We currently present our derivative assets and liabilities net on our statement of financial position. We have provided additional disclosures regarding the gross amounts of derivative assets and liabilities in Note 5 "Derivatives" in accordance with these new standards updates.

In February 2013, the FASB issued ASU No. 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income ("AOCI"), which requires entities to present either in a single note or parenthetically on the face of the financial statements (i) the amount of significant items reclassified from each component of AOCI and (ii) the income statement

11
Table of Contents

line items affected by the reclassifications. We adopted this guidance during the first quarter of 2013; it did not have a material impact on our condensed consolidated financial statements as there are currently no items reclassified from AOCI.
3. Acquisitions and Divestitures
High Point System
Effective April 15, 2013, our general partner contributed 100% of the limited liability company interests in High Point Gas Transmission, LLC and High Point Gas Gathering, LLC, (the “High Point System”). 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.

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

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

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

Accounts receivable
3,629

Unbilled revenue
1,445

Other current assets
2,049

Property, plant and equipment, net
82,615

Other assets
1,000

Accounts payable
(11
)
Accrued expenses and other current liabilities
(4,077
)
Current portion of long-term debt
(893
)
Asset retirement obligation liability
(25,763
)
Total identifiable net assets
$
61,929


Subsequent to the contribution, 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 for the three and six months ended June 30, 2013.

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

The Chatom system is located in Washington County, Alabama, approximately 15 miles from our Bazor Ridge processing plant in Wayne County, Mississippi, and consists of a 25 MMcf/d refrigeration processing plant, a 1,900 Bbl/d fractionation unit, a 160 long-ton per day sulfur recovery unit, and a 29 mile gas gathering system. We believe the fractionating services provide flexibility to the Partnership's product and service offerings.

12
Table of Contents


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

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

Property, plant and equipment
58,279

Asset retirement cost
452

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


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

Our 87.4% undivided interest in the Chatom system contributed $13.6 million and $27.3 million of revenue and $1.3 million and $2.4 million of net income attributable to the Partnership for the three and six months ended June 30, 2013, respectively which are included in the condensed consolidated statement of operations.

Other non-strategic midstream assets

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

During the second quarter of 2013, management was approved to commit to a plan to sell certain non-strategic gathering and processing assets which meet specific criteria as held for sale. As of June 30, 2013, certain gathering and processing assets were written down by $1.8 million to the estimated fair value less cost to sell. These fair value measurements are based on significant inputs not observable in the market and thus represent a Level 3 measurement as defined by ASC 820. Primarily using the income approach, the fair value estimates are based on i) present value of estimated EBITDA, ii) an assumed discount rate of 10.0%, and iii) a decline in throughput volumes of 2.5% in 2013 and thereafter.

The net book value of the gathering and processing assets of $0.9 million are presented as Noncurrent assets held for sale, net on the condensed consolidated balance sheet. The following table presents the identifiable assets and liabilities of the assets classified as held for sale as of June 30, 2013 in the condensed consolidated balance sheet (in thousands):

Unbilled revenue
$
1,358

Property, plant and equipment, net
874

Accrued gas purchases
(1,222
)

As a result of the plan divestiture of these non-strategic midstream assets, we have accounted for these disposal groups as discontinued operations within our Gathering and Processing Segment. Accordingly, we reclassified and excluded the disposal group's results of operations from our results of continuing operations and reported the disposal group's results of operations as

13
Table of Contents

(Loss) gain from operations of disposal groups 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, expense and (loss) gain from operations of disposal groups associated with the assets classified as held for sale for the three and six months ended June 30, 2013 and 2012 (in thousands):
 
Three months ended June 30,
 
Six months ended June 30,
 
2013
 
2012
 
2013
 
2012
Revenue
$
3,921

 
$
2,738

 
$
7,559

 
$
5,592

Expense
3,983

 
2,662

 
7,548

 
5,491

Impairment
1,807

 
—

 
1,807

 
—

(Loss) gain from operations of disposal groups
(1,869
)
 
76

 
(1,796
)
 
101

Limited partners' net loss per unit from discontinued operations (basic and diluted)
$
(0.20
)
 
$
0.01

 
$
(0.19
)
 
$
0.01

4. 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 six months ended June 30, 2013 and 2012, no allowances on or write-offs of accounts receivable were recorded.
The following table summarizes the percentage of revenue earned from those customers that exceed 10% or greater of the Partnership's consolidated revenue in the consolidated statement of operations for the each of the periods presented below:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2013
 
2012
 
2013
 
2012
Customer A
25
%
 
29
%
 
27
%
 
31
%
Customer B
12
%
 
—
%
 
14
%
 
—
%
Customer C
12
%
 
12
%
 
12
%
 
13
%
Customer D
—
%
 
17
%
 
10
%
 
18
%
Other
51
%
 
42
%
 
37
%
 
38
%
Total
100
%
 
100
%
 
100
%
 
100
%
5. 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. 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. Currently, the commodity derivatives are in the form of swaps, puts and collars. As of June 30, 2013, the aggregate notional volume of our commodity derivatives was 7.1 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, 2013, we have not posted collateral with our counterparties. The

14
Table of Contents

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.

Interest Rate Swap

We entered into an interest rate swap to manage the impact of the interest rate risk associated with our credit facility, effectively converting a portion of the cash flows related to our long-term variable rate debt into fixed rate cash flows. As of June 30, 2013, the notional amount of our interest rate swap was $100 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 quarter of 2013, we entered into a weather derivative to mitigate the impact of potential unfavorable weather to our operations under which we could receive payments totaling up to $10 million in the event that a hurricane or hurricanes of certain strength pass through the area as identified in the derivative agreement. The weather derivative is being accounted for using the intrinsic value method, under which the fair value of the contract is zero and any amounts received are recognized as gains during the period received. The weather derivative was entered into with a single counterparty and we were not required to post collateral. We paid a premium of approximately $1.1 million which is recorded in Risk management assets on the condensed consolidated balance sheet and is being amortized to Direct operating expense on a straight-line basis over the 12 month term of the contract. As of June 30, 2013, the unamortized amount of the risk management asset was approximately $1.0 million.
As of June 30, 2013 and December 31, 2012, the value associated with our commodity derivatives, interest rate swap instrument 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
 
June 30, 2013
 
December 31, 2012
 
June 30, 2013
 
December 31, 2012
 
June 30, 2013
 
December 31, 2012
Current
 
$
2,153

 
$
1,889

 
$
(71
)
 
$
(920
)
 
$
2,082

 
$
969

Noncurrent
 
—

 
—

 
—

 
—

 
—

 
—

Total assets
 
$
2,153

 
$
1,889

 
$
(71
)
 
$
(920
)
 
$
2,082

 
$
969

 
 
 
 
 
 
 
 
 
 
 
 
 
Current
 
$
—

 
$
—

 
$
(290
)
 
$
—

 
$
(290
)
 
$
—

Noncurrent
 
—

 
—

 
(28
)
 
—

 
(28
)
 
—

Total liabilities
 
$
—

 
$
—

 
$
(318
)
 
$
—

 
$
(318
)
 
$
—

For the three and six months ended June 30, 2013 and 2012, 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
2013
 
 
 
 
 
 
 
Gain on commodity derivatives, net
$
360

 
$
554

 
$
536

 
$
73

Interest expense
—

 
(318
)
 
—

 
(318
)
Direct operating expenses
(95
)
 
—

 
(95
)
 
—

Total
$
265

 
$
236

 
$
441

 
$
(245
)
2012
 
 
 
 
 
 
 
Gain on commodity derivatives, net
$
664

 
$
3,171

 
$
609

 
$
3,494


6. 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:

15
Table of Contents

•
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 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. We will recognize transfers between levels at the end of the reporting period for which the transfer has occurred. We recognized transfers out of Level 3 into Level 2 as a result of changes in tenure and market points of certain contracts in the amount of $1.0 million for the year ended December 31, 2012. There were no such transfers for the three and six months ended June 30, 2013 and 2012.
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 liabilities within the balance sheet, that were measured at fair value on a recurring basis as of June 30, 2013 and December 31, 2012 (in thousands):
 
Carrying
Amount
 
Estimated Fair Value
 
Level 1
 
Level 2
 
Level 3
 
Total
Commodity derivative instruments, net
 
 
 
 
 
 
 
 
 
June 30, 2013
$
1,042

 
$
—

 
$
1,042

 
$
—

 
$
1,042

December 31, 2012
$
969

 
$
—

 
$
969

 
$
—

 
$
969

Interest rate swap
 
 
 
 
 
 
 
 
 
June 30, 2013
$
(318
)
 
$
—

 
$
(318
)
 
$
—

 
$
(318
)
December 31, 2012
$
—

 
$
—

 
$
—

 
$
—

 
$
—


The premium paid to enter the weather derivative described in Note 5 "Derivatives", is included within Risk management assets within the balance sheet but is not included as part of the above table as it is recorded at amortized carrying cost, not fair value.
7. Property, Plant and Equipment
Property, plant and equipment, net, as of June 30, 2013 and December 31, 2012 were as follows (in thousands):
 
 
Useful Life
(in years)
 
June 30,
2013
 
December 31, 2012
Land
N/A
 
$
2,254

 
$
2,254

Construction in progress
N/A
 
2,531

 
5,053

Base gas
N/A
 
1,108

 
—

Buildings and improvements
4 to 40
 
1,664

 
1,432

Processing and treating plants
8 to 40
 
97,787

 
98,106

Pipelines
5 to 40
 
236,272

 
163,447

Compressors
4 to 20
 
9,485

 
8,957

Equipment
8 to 20
 
5,237

 
4,785

Computer software
5
 
2,539

 
1,950

Total property, plant and equipment
 
 
358,877

 
285,984

Accumulated depreciation
 
 
(75,924
)
 
(62,165
)
Property, plant and equipment, net
 
 
$
282,953

 
$
223,819

Of the gross property, plant and equipment balances at June 30, 2013 and December 31, 2012, $98.1 million and $26.1 million, respectively, were related to AlaTenn, Midla and HPGT, our FERC regulated interstate assets.

16
Table of Contents

Capitalized interest was less than $0.1 million for the three and six months ended June 30, 2013.
Depreciation expense was $6.7 million and $12.3 million for the three and six months ended June 30, 2013, respectively.
Asset Impairments
During the second quarter of 2013, management determined to change its commercial approach towards certain non-strategic gathering and processing assets. As a result, an asset impairment charge of $15.2 million was recorded in the three months ended June 30, 2013. These fair value measurements are based on significant inputs not observable in the market and thus represent a Level 3 measurement as defined by ASC 820. Primarily using the income approach, the fair value estimates are based on i) present value of estimated EBITDA, ii) an assumed discount rate of 10.0%, and iii) an decline in throughput volumes of 2.5% in 2013 and thereafter.
During the second quarter of 2013, management was approved to commit to a plan to sell certain non-strategic gathering and processing assets which meet specific criteria as held for sale. As of June 30, 2013, certain gathering and processing assets were written down by $1.8 million to the estimated fair value less cost to sell. See Note 3 "Acquisitions and Divestitures".
Insurance proceeds
Involuntary conversions result from the loss of an asset because of some unforeseen event (e.g., destruction due to hurricanes). Some of these events are insurable, thus resulting in a property damage insurance recovery. Amounts we receive from insurance carriers are net of any deductibles related to the covered event. During the three and six months ended June 30, 2013, we collected $0.5 million and $1.1 million, respectively, of nonrefundable cash proceeds from our insurance carrier. During the first quarter of 2013, $0.5 million of nonrefundable cash proceeds were recognized as an offset to property, plant and equipment write-downs of $0.1 million and presented as $0.4 million under the caption Gain (loss) on involuntary conversion of property, plant and equipment. During the second quarter of 2013, $0.6 million of nonrefundable cash proceeds were associated with business interruption and recorded to Revenue in the condensed consolidated statement of operations.

8. 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.


17
Table of Contents

The following table is a reconciliation of the asset retirement obligations (in thousands):
Asset retirement obligation at December 31, 2012
$
8,319

Obligations assumed
25,764

Accretion expense
167

Asset retirement obligation at June 30, 2013
$
34,250

We recorded accretion expense, which is included in Depreciation and accretion expense, of approximately $0.1 million and approximately $0.2 million in our consolidated statements of operations for each of the three and six months ended June 30, 2013, respectively and less than $0.1 million for the three and six months ended June 30, 2012.
We are required to establish security against any potential secondary obligations relating to the abandonment of the certain transmission assets that may be imposed on the previous owner by applicable regulatory authorities. As such, we have a restricted cash account that is established, held, and maintained by a third party that amounts to $1.0 million and is presented in Other assets, net in our condensed consolidated balance sheet as of June 30, 2013.
9. Debt Obligations
Credit facility
As of December 31, 2012, the total leverage ratio test, one of the primary financial covenants that we were required to maintain under our credit facility, was limited to a maximum of 4.50 times. At December 31, 2012, our total indebtedness was approximately $130.9 million, which caused our total leverage to EBITDA ratio to be approximately 5.70-to-1. As a result, on December 26, 2012, the Partnership entered into the Third Amendment and Waiver to Credit Agreement, dated as of December 26, 2012 (the “Third Amendment”). The Third Amendment provided for a waiver of the Partnership's compliance with the Consolidated Total Leverage Ratio with respect to the quarter ending December 31, 2012 and for one month thereafter. The Third Amendment also required the Partnership to provide certain financial and operating information of the Partnership on a monthly basis for 2013 and for any month after 2013 in which the Consolidated Total Leverage Ratio of the Partnership is in excess of 4.00 to 1.00. The remaining material terms and conditions of the senior secured revolving credit facility, including pricing, maturity and covenants, remained unchanged by the Third Amendment.
On January 24, 2013, the Partnership entered into the second waiver to the credit facility that extended the waiver period with respect to the Consolidated Total Leverage Ratio to March 31, 2013 (and subsequently extended to April 16, 2013). Additional covenants during the waiver period included i) total outstanding borrowings under the credit facility shall not exceed $150.0 million; ii) restrictions on certain acquisitions; iii) an increase to the Eurodollar Rate by 0.50%; iv) additional fees of 0.125% of the principal amount on each of February 28, 2013 and March 31, 2013; and v) execution of a compliance certificate.
We were in compliance with the Consolidated Total Leverage Covenant Ratio test, which was 4.62, under our credit facility as of June 30, 2013, in accordance with the leverage covenants as modified in the Fourth Amendment to the credit facility executed on April 15, 2013. As of June 30, 2013, we had approximately $126.3 million of outstanding borrowings and approximately $34.6 million of available borrowing capacity as a result of the reduction of our borrowing capacity to a total of $175 million as described herein.
See Note 17 "Liquidity" for further updates to our liquidity and long-term debt.
Other debt
Other debt represents insurance premium financing in the original amounts of $3.3 million bearing interest at between 3.22% and 4.00% per annum, which is repayable in equal monthly installments of approximately $0.4 million through the fourth quarter of 2013.
Our outstanding borrowings under debt at June 30, 2013 and December 31, 2012, respectively, were (in thousands):
 

18
Table of Contents

 
June 30,
2013
 
December 31, 2012
Revolving loan facility
$
123,660

 
$
128,285

Other debt
1,250

 
—


124,910

 
128,285

Less: current portion
1,250

 
—


$
123,660

 
$
128,285

At June 30, 2013 and December 31, 2012, letters of credit outstanding under the credit facility were $2.6 million.
In connection with our credit facility and amendments thereto, we incurred $5.7 million in debt issuance costs that are being amortized on a straight-line basis over the term of the credit facility.
10. Partners’ Capital and Convertible Preferred Units
Our capital accounts are comprised of approximately 2% general partner interest and 98% 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 interests held by our general partner.
Series A Convertible Preferred Units
On April 15, 2013, the Partnership, our general partner and AIM Midstream Holdings, LLC entered in the ArcLight Transactions with High Point, pursuant to which High Point (i) acquired 90% of our general partner and all of our subordinated units from AIM Midstream Holdings and (ii) contributed certain midstream assets and $15.0 million in cash to us in exchange for 5,142,857 Series A Units issued by the Partnership.  Of the $15.0 million cash consideration paid by High Point, approximately $2.5 million was used to pay certain transaction expenses of High Point, and the remaining approximately $12.5 million was used to repay borrowings outstanding under the Partnership's credit facility in connection with the Fourth Amendment. As a result of these transactions, which were also consummated on April 15, 2013, High Point acquired both control of our general partner and a majority of our outstanding limited partnership interests. On April 15, 2013, our general partner entered into the Third Amended & Restated
Agreement of Limited Partnership (the “Amended Partnership Agreement”) of the Partnership providing for the creation and designation of the rights, preferences, terms and conditions of the Series A Units.
The Series A Units receive dividends prior to distributions to Partnership common unitholders. Through October 1, 2014, the dividends distributed to the Series A Unitholders are equal to $0.25 per unit and additional Series A Units in an amount equal to the cash portion of the distribution. Subsequent to that date, the distribution will be the greater of the distribution to be made to common unitholders or approximately $0.50 per unit. The Series A Units may be converted into common units on a one-to-one basis, subject to customary anti-dilutive adjustments, at the option of the unitholders on or any time after January 14, 2014.
Upon any liquidation and winding up of the Partnership or the sale of substantially all of the assets of the Partnership, the holders of Series A Preferred Units generally will be entitled to receive, in preference to the holders of any of the Partnership's other securities, an amount equal to the sum of the $17.50 multiplied by the number of Series A Units owned by such holders, plus all accrued but unpaid distributions on such Series A Preferred Units.
Prior to the consummation of any recapitalization, reorganization, consolidation, merger, spin-off or other business combination in which the holders of common units are to receive securities, cash or other assets (a “Partnership Event”), we are obligated to make an irrevocable written offer, subject to consummation of the Partnership Event, to each holder of Series A Preferred Units to redeem all (but not less than all) of such holder's Series A Preferred Units for a price per Series A Preferred Unit payable in cash equal to the greater of:
•
the sum of $17.50 and all accrued and accumulated but unpaid distributions for each Series A Preferred Unit; and
•
an amount equal to the product of:
(i) the number of common units into which each Series A Preferred Unit is convertible; and
(ii) the sum of:
(A) the cash consideration per common unit to be paid to the holders of common units pursuant to the Partnership Event, plus
(B) the fair market value per common unit of the securities or other assets to be distributed to the holders of the common units pursuant to the Partnership Event.
Upon receipt of such a redemption offer from us, each holder of Series A Preferred Units may elect to receive such cash amount or a preferred security issued by the person surviving or resulting from such Partnership Event and containing provisions substantially equivalent to the provisions set forth in the Amended Partnership Agreement with respect to the Series A Preferred Units without material abridgement.
The Series A Preferred Units have voting rights that are identical to the voting rights of the common units and will vote with the common units as a single class, with each Series A Preferred Unit entitled to one vote for each common unit into which such Series A Preferred Unit is convertible.
The fair value of the Series A Units on April 15, 2013 was $17.50 per unit, or $90.0 million and was issued by the Partnership in exchange for cash of approximately $12.5 million and net assets of $61.9 million contributed to the Partnership by our general partner.  The contribution of net assets of the High Point system was accounted for as a transaction between entities under common control whereby the High Point system was recorded at historical book value.  As such, the value of the Series A Units in excess of the net asset contributed by our general partner amounted to $15.6 million and was allocated pro-rata to the general partner and existing limited partners interest based on their ownership interests. The fair value measurement was based on significant inputs not observable in the market and thus represent a Level 3 measurement as defined by ASC 820. Primarily using the income approach, the fair value estimate was based on i) present value of estimated future contracted distributions, ii) an assumed discount rate of 18.0%, and iii) an assumed distribution growth rate of 1.0% in 2014 and thereafter.
The numbers of units outstanding as of June 30, 2013 and December 31, 2012, respectively, were as follows (in thousands):
 
June 30,
2013
 
December 31, 2012
Limited partner common units
4,683

 
4,639

Limited partner subordinated units
4,526

 
4,526

Preferred units
5,143

 
—

General partner units
185

 
185


Net Income (Loss) attributable to Limited Common and General Partner Units
Net income (loss) attributable to the general partner and the limited partners (common and subordinated unit holders) is allocated in accordance with their respective ownership percentages, after giving effect to incentive distributions paid to the general partner. Basic net income per limited partner unit is computed based on the weighted average number of units outstanding during the

19
Table of Contents

period. Diluted net income per limited partner unit is computed based on the weighted average number of units plus the effect of dilutive potential units outstanding during the period. Unvested share-based payment awards that contain non-forfeitable rights to distributions (whether paid or unpaid) are classified as participating securities and are included in our computation of diluted net income per limited partner unit. There was no dilutive effect of unit based awards for the three and six months ended June 30, 2013. The dilutive effect of unit based awards was 172,552 equivalent units during the three and six months ended June 30, 2012.
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 our Partnership agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period.
The two-class method does not impact our overall net income or other financial results; however, in periods in which aggregate net income exceeds our aggregate distributions for such period, it will have the impact of reducing net income per limited partner unit. This result occurs as a larger portion of our aggregate earnings, as if distributed, is allocated to the incentive distribution rights of the general partner, even though we make distributions on the basis of available cash and not earnings.
The following table is the calculation of net income (loss) per limited partner unit for the three and six months ended June 30, 2013 and 2012, respectively (in thousands, with the exception of per unit amounts):

20
Table of Contents

 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2013
 
2012
 
2013
 
2012
Net (loss) income from continuing operations
$
(19,768
)
 
$
2,251

 
$
(23,394
)
 
$
3,917

Less:
 
 
 
 
 
 
 
Declared cash distribution on Series A Preferred Units
1,074

 
—

 
1,074

 
—

Declared PIK distribution on Series A Preferred Units
1,074

 
—

 
1,074

 
—

Fair value of Series A Preferred Units in excess of value of contributed High Point System
15,612

 
—

 
15,612

 
—

General partners' distribution
80

 
81

 
160

 
161

General partners' share in undistributed loss
(820
)
 
(35
)
 
(970
)
 
(82
)
Net (loss) income from continuing operations available to limited partners
$
(36,788
)
 
$
2,205

 
$
(40,344
)
 
$
3,838

 
 
 
 
 
 
 
 
Net (loss) income attributable to the Partnership
$
(21,637
)
 
$
2,327

 
$
(25,190
)
 
$
4,018

Less:
 
 
 
 
 
 
 
Declared cash distribution on Series A Preferred Units
1,074

 
—

 
1,074

 
—

Declared PIK distribution on Series A Preferred Units
1,074

 
—

 
1,074

 
—

Fair value of Series A Preferred Units in excess of value of contributed High Point System
15,612

 
—

 
15,612

 
—

General partners' distribution
80

 
81

 
160

 
161

General partners' share in undistributed loss
(861
)
 
(34
)
 
(1,013
)
 
(80
)
Net (loss) income available to limited partners
$
(38,616
)
 
$
2,280

 
$
(42,097
)
 
$
3,937

 
 
 
 
 
 
 
 
Weighted average number of units used in computation of limited partners’ net (loss) income per unit (basic)
9,198

 
9,107

 
9,183

 
9,100

 
 
 
 
 
 
 
 
Limited partners’ net (loss) income from continuing operations per unit (basic)
$
(4.00
)
 
$
0.24

 
$
(4.39
)
 
$
0.42

Limited partners’ net (loss) income per unit (basic)
$
(4.20
)
 
$
0.25

 
$
(4.58
)
 
$
0.43

 
 
 
 
 
 
 
 
Weighted average number of units used in computation of limited partners’ net (loss) income per unit (diluted)
9,198

 
9,276

 
9,183

 
9,263

 
 
 
 
 
 
 
 
Limited partners’ net (loss) income from continuing operations per unit (diluted)
$
(4.00
)
 
$
0.24

 
$
(4.39
)
 
$
0.41

Limited partners’ net (loss) income per unit (diluted)
$
(4.20
)
 
$
0.25

 
$
(4.58
)
 
$
0.43

Distributions
We made distributions of $7.8 million and $8.0 million in the six months ended June 30, 2013 and 2012, respectively. We made no distributions in respect of our general partner’s incentive distribution rights during 2013 or 2012. 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.
As a result of the issuance of the Series A Units, we have accrued $1.1 million equal to the cash portion of the distribution and $1.1 million equal to the additional Series A Units in an amount equal to the cash portion of the distribution payable in the third quarter of 2013.
11. Long-Term Incentive Plan
Our general partner manages our operations and activities and employs the personnel who provide support to our operations. On November 2, 2009, the board of directors of our general partner adopted a long-term incentive plan (“LTIP”) for its employees, consultants and directors who perform services for it or its affiliates. On May 25, 2010, the board of directors of our general partner adopted an amended and restated LTIP. On July 11, 2012, the board of directors of our general partner adopted a second amended and restated LTIP that effectively increased available awards by 871,750 units. At June 30, 2013 and December 31, 2012, 870,555 and 920,193 units, respectively, were available for future grant under the LTIP, giving retroactive treatment to the reverse unit split in connection with our recapitalization described in our Annual Report.
Ownership in the awards is subject to forfeiture until the vesting date. The LTIP is administered by the board of directors of our general partner. The board of directors of our general partner, at its discretion, may elect to settle such vested phantom units with a number of units equivalent to the fair market value at the date of vesting in lieu of cash. Although, our general partner has the option to settle in cash upon the vesting of phantom units, our general partner 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 ("DERs"). 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 our unit-based awards for each of the periods indicated, in units:
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2013
 
2012
 
2013
 
2012
Outstanding at beginning of period
101,950

 
142,552

 
90,938

 
162,860

Granted
56,467

 
34,560

 
80,388

 
34,560

Forfeited
(10,000
)
 
—

 
(12,426
)
 
—

Vested
(51,684
)
 
(4,560
)
 
(62,167
)
 
(24,868
)
Outstanding at end of period
96,733

 
172,552

 
96,733

 
172,552

Fair value per unit
$13.36 to $21.89
 
$14.70 to  $21.40
 
$13.36 to $21.89
 
$14.70 to  $21.40
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, 2013 and 2012 was $1.1 million and $0.5 million, respectively, and for the six months ended June 30, 2013 and 2012 was $1.5 million and $0.8 million, respectively, which is 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 $1.1 million and $0.5 million for the six months ended June 30, 2013 and 2012, respectively.
The total compensation cost related to unvested awards not yet recognized at June 30, 2013 and 2012 was $1.1 million and $2.6 million, respectively, and the weighted average period over which this cost is expected to be recognized as of June 30, 2013 is approximately 1.2 years.
12. Post-Employment Benefits
We sponsor a contributory post-retirement plan that provides medical, dental and life insurance benefits for qualifying U.S. retired employees (referred to as the “OPEB Plan”).
The following table summarizes the components of net periodic benefit recognized in the condensed consolidated statements of operations (in thousands):

21
Table of Contents

 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2013
 
2012
 
2013
 
2012
Service cost
$
1

 
$
1

 
$
2

 
2

Interest cost
4

 
4

 
8

 
8

Expected return on plan assets
(17
)
 
(16
)
 
(35
)
 
(33
)
Amortization of net gain
(6
)
 
(9
)
 
(12
)
 
(18
)
Net periodic benefit
$
(18
)
 
$
(20
)
 
$
(37
)
 
$
(41
)
Future contributions to the Plans
We expect to make contributions to the OPEB Plan for the year ending December 31, 2013 of $0.1 million.
13. Commitments and Contingencies
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.
Commitments and contractual obligations
Future non-cancellable commitments related to certain contractual obligations as of June 30, 2013 are presented below (in thousands):
 
 
Payments Due by Period
 
Total
 
2013
 
2014
 
2015
 
2016
 
2017
 
Thereafter
Operating leases and service contracts (a)
$
3,605

 
$
338

 
$
692

 
$
677

 
$
408

 
$
353

 
$
1,137

Asset retirement obligations
34,250

 
—

 
—

 
—

 
7,867

 
—

 
26,383

Total
$
37,855

 
$
338

 
$
692

 
$
677

 
$
8,275

 
$
353

 
$
27,520

(a) - Operating leases and service contracts have been reduced by total minimum sublease rentals of $52 due in the future under noncancelable subleases.
Total expenses related to operating leases, asset retirement obligations, land site leases and right-of-way agreements were (in thousands):
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2013
 
2012
 
2013
 
2012
Operating leases
$
265

 
$
225

 
$
484

 
$
439

Asset retirement obligation
157

 
7

 
167

 
13

 
$
422

 
$
232

 
$
651

 
$
452


14. 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, 2013, administrative and operational services expenses of $3.8 million and $6.3 million, respectively, were charged to us by our general partner. During the three and six months ended June 30, 2012, administrative and operational services expenses of $2.5 million and $6.2 million, respectively, were charged to us by our general partner. For the three and six months ended June 30, 2013, our general partner incurred approximately $0.2 million and $0.5 million, respectively, of costs associated with certain business development activities.  If the

22
Table of Contents

business development activities result in a project that will be pursued and funded by the Partnership, we will reimburse our general partner for the business development costs related to that project.
15. Reporting Segments
Our operations are located in the United States and are organized into two reporting segments: (1) Gathering and Processing and (2) Transmission.
Gathering and Processing
Our Gathering and Processing segment provides “wellhead-to-market” services, which include transporting raw natural gas from the wellhead through gathering systems, treating the raw natural gas, processing raw natural gas to separate the NGLs from the natural gas, performing fractionation and selling or delivering pipeline-quality natural gas and NGLs to various markets and pipeline systems, to producers of natural gas and oil.
Transmission
Our Transmission segment transports and delivers natural gas from producing wells, receipt points or pipeline interconnects for shippers and other customers, including local distribution companies, or LDCs, utilities and industrial, and commercial and power generation customers.
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 contribution of the High Point system, which occurred concurrently with HPIP's acquisition of 90% of our general partner, is presented within our Transmission segment. The following tables set forth our segment information for the three and six months ended June 30, 2013 and 2012 (in thousands):
 
 
Three Months Ended
 
June 30,
 
2013
 
2012
 
Gathering
and
Processing
 
Transmission
 
Total
 
Gathering
and
Processing
 
Transmission
 
Total
Revenue
$
49,175

 
$
24,653

 
$
73,828

 
$
28,218

 
$
11,269

 
$
39,487

Segment gross margin (a)
9,340

 
7,583

 
16,923

 
8,468

 
2,786

 
11,254

Gain on commodity derivatives, net
914

 
—

 
914

 
3,835

 
—

 
3,835

Direct operating expenses
3,565

 
3,556

 
7,121

 
2,069

 
1,125

 
3,194

Selling, general and administrative expenses
 
 
 
 
4,588

 
 
 
 
 
3,668

Equity compensation expense
 
 
 
 
1,097

 
 
 
 
 
467

Depreciation and accretion expense
 
 
 
 
6,698

 
 
 
 
 
5,092

Gain on sale of assets, net
 
 
 
 
—

 
 
 
 
 
117

Loss on impairment of property, plant and equipment
 
 
 
 
(15,232
)
 
 
 
 
 
—

Interest and other expense
 
 
 
 
(2,190
)
 
 
 
 
 
(825
)
(Loss) gain on discontinued operations
 
 
 
 
(1,869
)
 
 
 
 
 
76

Net (loss) income
 
 
 
 
(21,449
)
 
 
 
 
 
2,327

Less: Net income attributable to noncontrolling interests
 
 
 
 
188

 
 
 
 
 
—

Net (loss) income attributable to the Partnership
 
 
 
 
$
(21,637
)
 
 
 
 
 
$
2,327

 

23
Table of Contents

 
Six Months Ended
 
June 30,
 
2013
 
2012
 
Gathering
and
Processing
 
Transmission
 
Total
 
Gathering
and
Processing
 
Transmission
 
Total
Revenue
$
94,297

 
$
39,316

 
$
133,613

 
$
59,670

 
$
24,407

 
$
84,077

Segment gross margin (a)
18,340

 
11,581

 
29,921

 
17,012

 
6,803

 
23,815

Gain on commodity derivatives, net
609

 
—

 
609

 
4,103

 
—

 
4,103

Direct operating expenses
6,982

 
4,941

 
11,923

 
3,871

 
2,208

 
6,079

Selling, general and administrative expenses
 
 
 
 
8,013

 
 
 
 
 
6,997

Equity compensation expense
 
 
 
 
1,485

 
 
 
 
 
798

Depreciation and accretion expense
 
 
 
 
12,344

 
 
 
 
 
10,218

Gain on involuntary conversion of property, plant and equipment
 
 
 
 
343

 
 
 
 
 
—

Gain on sale of assets, net
 
 
 
 
—

 
 
 
 
 
122

Loss on impairment of property, plant and equipment
 
 
 
 
(15,232
)
 
 
 
 
 
—

Interest and other expense
 
 
 
 
(3,921
)
 
 
 
 
 
(1,582
)
(Loss) gain on discontinued operations (b)
 
 
 
 
(1,796
)
 
 
 
 
 
101

Net (loss) income
 
 
 
 
(24,847
)
 
 
 
 
 
4,018

Less: Net income attributable to noncontrolling interests
 
 
 
 
343

 
 
 
 
 
—

Net (loss) income attributable to the Partnership
 
 
 
 
$
(25,190
)
 
 
 
 
 
$
4,018


(a)
Segment gross margin for our Gathering and Processing segment consists of revenue, realized gain (loss) on commodity derivatives less construction, operating and maintenance agreement (“COMA”) income, less purchases of natural gas, NGLs and condensate (inclusive, of gross margin from discontinued operations). Segment gross margin for our Transmission segment consists of revenue, less COMA income, less purchases of natural gas. Gross margin consists of the sum of the segment gross margin amounts for each of these segments. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow from operations as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner. Effective October 1, 2012, we changed our segment gross margin measure to exclude COMA income. For the three months ended June 30, 2013 and 2012, $0.1 million and $0.1 million in COMA income was excluded from our Gathering and Processing segment gross margin, respectively and less than $0.1 million and $0.8 million in COMA income was excluded from our Transmission segment gross margin, respectively. For the six months ended June 30, 2013 and 2012, $0.1 million and $0.6 million in COMA income was excluded from our Gathering and Processing segment gross margin, respectively and less than $0.1 million and $1.6 million in COMA income was excluded from our Transmission segment gross margin, respectively.
(b)
(Loss) gain on discontinued operations impacts our Gathering and Processing segment.

Asset information, including capital expenditures, by segment is not included in reports used by our management in their monitoring of performance and therefore is not disclosed.

24
Table of Contents


16. Subsidiary Guarantors

The Partnership has filed a registration statement on Form S-3 with the SEC to register, among other securities, debt securities. The subsidiaries of the Partnership (the "Subsidiaries") will be co-registrants with the Partnership, and the registration statement will register guarantees of debt securities by one or more of the Subsidiaries (other than American Midstream Finance Corporation, a 100% owned subsidiary of the Partnership whose sole purpose is to act as co-issuer of such debt securities). The financial position and operations of the co-issuer are minor and therefore have been included with the Parent's financial information. As of June 30, 2012, the Subsidiaries were 100% owned by the Partnership and any guarantees by the Subsidiaries will be full and unconditional. Beginning July 1, 2012, the Subsidiaries have had an investment in the non-guarantor subsidiaries equal to a 87.4% undivided interest in its Chatom system. The Partnership has no assets or operations independent of the Subsidiaries, and there are no significant restrictions upon the ability of the Subsidiaries to distribute funds to the Partnership. In the event that more than one of the Subsidiaries provide guarantees of any debt securities issued by the Partnership, such guarantees will constitute joint and several obligations. None of the assets of the Partnership or the Subsidiaries represent restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X under the Securities Act of 1933, as amended. For purposes of the following unaudited condensed consolidating financial information, the Partnership's investments in its Subsidiaries and the guarantor subsidiaries' investment in its 87.4% undivided interest in the Chatom system are presented in accordance with the equity method of accounting. The financial information may not necessarily be indicative of the financial position, results of operations, or cash flows had the subsidiary guarantors operated as independent entities. Condensed consolidating financial information for the Partnership, its combined guarantor subsidiaries and non-guarantor subsidiary as of June 30, 2013 and December 31, 2012 and for the three and six months ended June 30, 2013 is as follows (in thousands):

25
Table of Contents

 
 Condensed Consolidating Balance Sheet
 
June 30, 2013
 
 Parent
 Guarantor Subsidiaries
 Non-Guarantor Subsidiaries
 Consolidating Adjustments
 Consolidated
Assets
 
 
 
 
 
Current assets
 
 
 
 
 
Cash and cash equivalents
$
1

$
422

$
—

$
—

$
423

Accounts receivable
—

2,114

1,108

—

3,222

Unbilled revenue
—

21,585

3,894

—

25,479

Risk management assets
—

2,082

—

—

2,082

Other current assets
—

5,096

434

—

5,530

Total current assets
1

31,299

5,436

—

36,736

Property, plant and equipment, net
—

223,947

59,006

—

282,953

Noncurrent assets held for sale, net
—

874

—

—

874

Investment in subsidiaries
122,621

47,587

—

(170,208
)
—

Other assets, net
—

6,380

—

—

6,380

Total assets
$
122,622

$
310,087

$
64,442

$
(170,208
)
$
326,943

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

$
(47
)
$
6,230

$
—

$
6,183

Accrued gas purchases
—

16,632

2,749

—

19,381

Accrued expenses and other current liabilities
1,073

11,681

72

—

12,826

Current portion of long-term debt
—

1,250

—

—

1,250

Risk management liabilities
—

290

—

—

290

Total current liabilities
1,073

29,806

9,051

—

39,930

Risk management liabilities
—

28

—

—

28

Assets retirement obligations
—

34,250

—

—

34,250

Other liabilities
—

(278
)
466

—

188

Long-term debt
—

123,660

—

—

123,660

Total liabilities
1,073

187,466

9,517

—

198,056

Convertible preferred units
91,073

—

—

—

91,073

Total partners' capital
30,476

122,621

47,587

(170,208
)
30,476

Noncontrolling interest
—

—

7,338

—

7,338

Total equity and partners' capital
30,476

122,621

54,925

(170,208
)
37,814

Total liabilities, equity and partners' capital
$
122,622

$
310,087

$
64,442

$
(170,208
)
$
326,943



26
Table of Contents

 
 Condensed Consolidating Balance Sheet
 
December 31, 2012
 
 Parent
 Guarantor Subsidiaries
 Non-Guarantor Subsidiaries
 Consolidating Adjustments
 Consolidated
Assets
 
 
 
 
 
Current assets
 
 
 
 
 
Cash and cash equivalents
$
1

$
575

$
—

$
—

$
576

Accounts receivable
—

1,612

346

—

1,958

Unbilled revenue
—

18,102

3,410

—

21,512

Risk management assets
—

969

—

—

969

Other current assets
—

2,967

259

—

3,226

Total current assets
1

24,225

4,015

—

28,241

Property, plant and equipment, net
—

165,001

58,818

—

223,819

Investment in subsidiaries
80,164

51,613

—

(131,777
)
—

Other assets, net
—

4,636

—

—

4,636

Total assets
$
80,165

$
245,475

$
62,833

$
(131,777
)
$
256,696

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

$
5,100

$
427

$
—

$
5,527

Accrued gas purchases
—

14,606

2,428

—

17,034

Accrued expenses and other current liabilities
—

9,150

469

—

9,619

Total current liabilities
—

28,856

3,324

—

32,180

Asset retirement obligations
—

7,861

458

—

8,319

Other liabilities
—

309

—

—

309

Long-term debt
—

128,285

—

—

128,285

Total liabilities
—

165,311

3,782

—

169,093

Total partners' capital
80,165

80,164

51,613

(131,777
)
80,165

Noncontrolling interest
—

—

7,438

—

7,438

Total equity and partners' capital
80,165

80,164

59,051

(131,777
)
87,603

Total liabilities, equity and partners' capital
$
80,165

$
245,475

$
62,833

$
(131,777
)
$
256,696



27
Table of Contents

 
 Condensed Consolidating Statements of Operations
 
Three months ended June 30, 2013
 
 Parent
 Guarantor Subsidiaries
 Non-Guarantor Subsidiaries
 Consolidating Adjustments
 Consolidated
Revenue
$
—

$
61,729

$
13,607

$
(1,508
)
$
73,828

Gain on commodity derivatives, net
—

914

—

—

914

Total revenue
—

62,643

13,607

(1,508
)
74,742

Operating expenses:
 
 
 
 
 
Purchases of natural gas, NGLs and condensate
—

48,333

10,571

(1,508
)
57,396

Direct operating expenses
—

6,004

1,117

—

7,121

Selling, general and administrative expenses
—

4,588

—

—

4,588

Equity compensation expense
—

1,097

—

—

1,097

Depreciation and accretion expense
—

6,284

414

—

6,698

Total operating expenses
—

66,306

12,102

(1,508
)
76,900

Loss on impairment of property, plant and equipment
—

(15,232
)
—

—

(15,232
)
Operating (loss) income
—

(18,895
)
1,505

—

(17,390
)
Other income (expense):
 
 
 
 
 
Earnings from consolidated affiliates
(21,637
)
1,317

—

20,320

—

Interest expense
—

(2,190
)
—

—

(2,190
)
Net (loss) income from continuing operations
(21,637
)
(19,768
)
1,505

20,320

(19,580
)
Discontinued operations
—

(1,869
)
—

—

(1,869
)
Net (loss) income
(21,637
)
(21,637
)
1,505

20,320

(21,449
)
Net income attributable to noncontrolling interests
—

—

188

—

188

Net (loss) income attributable to the Partnership
$
(21,637
)
$
(21,637
)
$
1,317

$
20,320

$
(21,637
)





28
Table of Contents

 
 Condensed Consolidating Statements of Operations
 
Six months ended June 30, 2013
 
 Parent
 Guarantor Subsidiaries
 Non-Guarantor Subsidiaries
 Consolidating Adjustments
 Consolidated
Revenue
$
—

$
109,828

$
27,256

$
(3,471
)
$
133,613

Gains on commodity derivatives, net
—

609

—

—

609

Total revenue
—

110,437

27,256

(3,471
)
134,222

Operating expenses:
 
 
 
 
 
Purchases of natural gas, NGLs and condensate
—

86,680

21,489

(3,471
)
104,698

Direct operating expenses
—

9,720

2,203

—

11,923

Selling, general and administrative expenses
—

8,013

—

—

8,013

Equity compensation expense
—

1,485

—

—

1,485

Depreciation and accretion expense
—

11,516

828

—

12,344

Total operating expenses
—

117,414

24,520

(3,471
)
138,463

Gain on involuntary conversion of property, plant and equipment
—

343

—

—

343

Loss on impairment of property, plant and equipment
—

(15,232
)
—

—

(15,232
)
Operating (loss) income
—

(21,866
)
2,736

—

(19,130
)
Other income (expense):










Earnings from consolidated affiliates
(25,190
)
2,393

—

22,797

—

Interest expense
—

(3,921
)
—

—

(3,921
)
Net (loss) income from continuing operations
(25,190
)
(23,394
)
2,736

22,797

(23,051
)
Discontinued operations
—

(1,796
)
—

—

(1,796
)
Net (loss) income
(25,190
)
(25,190
)
2,736

22,797

(24,847
)
Net income attributable to noncontrolling interests
—

—

343

—

343

Net (loss) income attributable to the Partnership
$
(25,190
)
$
(25,190
)
$
2,393

$
22,797

$
(25,190
)


29
Table of Contents

 
 Condensed Consolidating Statements of Cash Flows
 
Six months ended June 30, 2013
 
 Parent
 Guarantor Subsidiaries
 Non-Guarantor Subsidiaries
 Consolidating Adjustments
 Consolidated
Net cash provided by operating activities
$
—

$
8,923

$
2,736

$
—

$
11,659

Cash flows from investing activities
 
 
 
 
 
Cost of acquisitions, net of cash acquired
—

—

—

—

—

Additions to property, plant and equipment
—

(12,515
)
(1
)
—

(12,516
)
Proceeds from property damage insurance recoveries
—

482

—

—

482

Net contributions from affiliates
7,805

—

—

(7,805
)
—

Net distributions to affiliates
(14,393
)
—

—

14,393

—

Net cash provided by (used in) investing activities
(6,588
)
(12,033
)
(1
)
6,588

(12,034
)
Cash flows from financing activities
 
 
 
 
 
Net contributions from affiliates
—

14,393

—

(14,393
)
—

Net distributions to affiliates
—

(5,513
)
(2,292
)
7,805

—

Unit holder distributions
(7,805
)
—

—

—

(7,805
)
Issuance of Series A convertible preferred units
14,393

—

—

—

14,393

Net distributions to noncontrolling interest owners
—

—

(443
)
—

(443
)
LTIP tax netting unit repurchase
—

(339
)
—

—

(339
)
Payments for deferred debt issuance costs
—

(1,315
)
—

—

(1,315
)
Payments on other debt
—

(1,139
)
—

—

(1,139
)
Borrowings on other debt
—

1,495

—

—

1,495

Payments on long-term debt
—

(56,546
)
—

—

(56,546
)
Borrowings on long-term debt
—

51,921

—

—

51,921

Net cash (used in) provided by financing activities
6,588

2,957

(2,735
)
(6,588
)
222

Net (decrease) increase in cash and cash equivalents
—

(153
)
—

—

(153
)
Cash and cash equivalents
 
 
 
 
 
Beginning of period
1

575

—

—

576

End of period
$
1

$
422

$
—

$
—

$
423

Supplemental cash flow information
 
 
 
 
 
Interest payments
$
—

$
3,017

$
—

$
—

$
3,017

Supplemental non-cash information
 
 
 
 
 
(Decrease) increase in accrued property, plant and equipment
$
—

$
(5,769
)
$
—

$
—

$
(5,769
)
Net assets contributed in exchange for the issuance of Series A convertible preferred units (see Note 3)
$
59,994

$
—

$
—

$
—

$
59,994

Fair value of Series A Units in excess of net assets received
$
15,612

$
—

$
—

$
—

$
15,612

Accrued unitholder distribution for Series A Units
$
2,146

$
—

$
—

$
—

$
2,146


17. Liquidity

30
Table of Contents

We are required to comply with certain financial covenants and ratios in our credit facility. As of December 31, 2012, the total leverage ratio test, one of the primary financial covenants that we are required to maintain under our credit facility, was not to exceed 4.50 times. At December 31, 2012, our total indebtedness was approximately $130.9 million, which caused our total leverage to EBITDA ratio to be approximately 5.70-to-1. As a result, on December 26, 2012, the Partnership entered into the Third Amendment and Waiver to Credit Agreement, dated as of December 26, 2012 (the “Third Amendment”). The Third Amendment provided for a waiver of the Partnership's compliance with the Consolidated Total Leverage Ratio with respect to the quarter ending December 31, 2012 and for one month thereafter. The Third Amendment also requires the Partnership to provide certain financial and operating information of the Partnership on a monthly basis for 2013 and for any month after 2013 in which the Consolidated Total Leverage Ratio of the Partnership is in excess of 4.00 to 1.00. The remaining material terms and conditions of the senior secured revolving credit facility, including pricing, maturity and covenants, remained unchanged by the Third Amendment.
On January 24, 2013, the Partnership entered into the second waiver to the credit facility that extended the waiver period with respect to the Consolidated Total Leverage Ratio to March 31, 2013 (and subsequently extended to April 16, 2013). Additional covenants during the waiver period included i) total outstanding borrowings under the credit facility shall not exceed $150.0 million; ii) restrictions on certain acquisitions; iii) an increase to the Eurodollar rate by 0.50%; iv) additional fees of 0.125% of the principal amount on each of February 28, 2013 and March 31, 2013; and v) execution of a compliance certificate.
On April 15, 2013, we repaid approximately $12.5 million in outstanding borrowings under the credit agreement and entered into the Fourth Amendment in connection with the ArcLight Transaction. As a result, we had approximately $130 million of outstanding borrowings as of April 15, 2013 and approximately $45 million of available borrowing capacity as a result of the reduction of our borrowing capacity to a total of $175 million as described below. Until the quarter ending June 30, 2013, we were not required to meet a Consolidated Leverage Ratio under our June 2012 amended credit facility as amended to date. The Fourth Amendment provides for the following:
•
The consummation of the ArcLight Transactions and the PIK Distribution according to the terms of the Amended Partnership Agreement are permitted;
•
Commencing on October 1, 2013, the aggregate commitments of the lenders under the credit agreement will be reduced to $175 million unless before such date AIM Midstream Holdings makes an equity contribution to the Partnership of $12.5 million that is used to repay borrowings under the credit facility by October 1, 2013;
•
The total outstanding borrowings under the credit agreement are limited to $175 million until such equity contribution by AIM Midstream Holdings and debt repayment has occurred, at which time the maximum permitted borrowings under the credit agreement will be raised to $200 million;
•
The margins relating to our (i) Eurodollar-based loans range from 2.50% to 4.75% depending on the Consolidated Total Leverage ratio then in effect, and (ii) base rate loans range from 1.5% to 3.75%;
•
The definition of Consolidated Total Indebtedness will not include the Series A Units or certain unsecured surety bonds relating to the High Point Assets;
•
The definition of Consolidated EBITDA (the consolidated EBITDA for the quarters ending June 30 and September 30, 2013 will be annualized for purposes of the Consolidated Total Leverage Ratio) will:
◦
include, on a pro forma basis, the consolidated EBITDA of the High Point Subsidiaries as if they were owned by the Partnership beginning on January 1, 2013;
◦
exclude any insurance proceeds attributable to any event occurring prior to January 1, 2013; and
◦
exclude any one-time, non-recurring transaction expenses of the Partnership incurred in connection with the ArcLight Transactions or the Fourth Amendment.
•
During the period that commenced with the quarter ended March 31, 2013 and that ends with the quarter ending December 31, 2013, unless the Partnership has permanently canceled at least 20% of the number of subordinated units outstanding on April 15, 2013, the Partnership must reduce any quarterly cash distribution on either its subordinated units or Series A Preferred Units (at the Partnership's election) by an aggregate of $0.4 million per quarter, and such reduction may not be replaced by in-kind distributions of Partnership securities;
•
The maximum Consolidated Total Leverage Ratio permitted as of the end of any fiscal quarter cannot exceed the ratio set forth below:

31
Table of Contents

Fiscal Quarter Ending
Consolidated Total Leverage Ratio
June 30, 2013
5.90:1.00
September 30, 2013
5.90:1.00
December 31, 2013
5.75:1.00
March 31, 2014
5.75:1.00
June 30, 2014
5.75:1.00
September 30, 2014
5.50:1.00
December 31, 2014
5.25:1.00
March 31, 2015 and each fiscal quarter thereafter
4.50:1.00

•
The Partnership agrees to cooperate with and pay the fees and expenses incurred by Bank of America, N.A., the administrative agent for the credit agreement, in connection with its engagement of FTI Consulting to advise and assist it in an assessment of the Partnership's financial condition; and
•
The lenders permanently waived the Partnership's failure to comply with covenants relating to the Partnership's Consolidated Total Leverage Ratio for the quarters ended December 31, 2012 and March 31, 2013.

As of July 31, 2013, we had approximately $131.2 million of outstanding borrowings and approximately $29.7 million of available borrowing capacity as a result of the reduction of our borrowing capacity to a total of $175 million as described herein.

The Partnership believes that the consummation of the ArcLight Transactions will allow it to comply with the Consolidated Total Leverage to EBTIDA ratio in the Fourth Amendment. However, no assurances can be given that the Partnership's results of operations following the ArcLight Transactions will allow us to comply with financial covenants of the Fourth Amendment. If we are not able to generate sufficient cash flows from operations to comply with the financial covenants in the Fourth Amendment and we are not able enter into an agreement to refinance or obtain covenant default waivers, then the outstanding balance under our credit facility could become due and payable upon acceleration by the lenders in our banking group and other agreements with cross-default provisions, if any, could become due. In addition, failure to comply with any of the covenants under our Fourth Amendment could adversely affect our ability to fund ongoing operations and growth capital requirements as well as our ability to pay distributions to our unitholders.


32
Table of Contents

18. Subsequent Events
Distribution
On July 23, 2013, we announced a distribution of $0.4325 per unit for the quarter ended June 30, 2013, or $1.73 per unit on an annualized basis, payable on August 14, 2013 to unitholders of record on August 7, 2013 amounting to $3.7 million, net of $0.4 million of distribution foregone by our general partner.

Equity restructuring

Effective August 9, 2013, we executed an equity restructuring agreement with American Midstream GP, LLC, our general partner, the holder of all of the Incentive Distribution Rights, and HPIP, owner of all of the outstanding subordinated units. As part of the equity restructuring agreement, 4.5 million subordinated units and previous Incentive Distribution Rights of the Partnership were combined into, and restructured as a new class of Incentive Distribution Rights (referred to herein as the “new IDRs”).   The transaction, which does not require further consents or approvals, was unanimously approved by the Board of Directors of the Partnership, on the unanimous approval and recommendation of its Conflicts Committee, which is composed solely of independent directors.

The equity restructuring permanently eliminates the subordinated units and previous Incentive Distribution Rights of the Partnership in return for the new IDRs.  Prior to completion of the equity restructuring, we were required to pay the minimum quarterly distribution of $0.4125 per unit on the subordinated units, or approximately $2 million per quarter, prior to increasing the quarterly distribution on American Midstream's common units.
 
The prior Incentive Distribution Rights provided for our general partner to receive increasing percentages (ranging from 13 percent to 48 percent) of incremental cash distributions after unitholders of the Partnership (both common and subordinated) received quarterly distributions ranging from $0.47438 per unit to $0.61875 per unit.  The new IDRs entitle our general partner to receive 48 percent of any quarterly cash distributions after common unit holders of the Partnership have received the full minimum quarterly distribution ($0.4125 per unit) for each quarter plus any arrearages from prior quarters (of which there are currently none).  

In conjunction with the equity restructuring, we are entitled to receive $12.5 million that was placed in escrow in conjunction with the acquisition in April 2013 by HPIP of our subordinated units and general partner interests. Once released from escrow, we will use the proceeds to repay borrowings on its credit facility. The former owner of the General Partner commenced legal action against the new majority owner of the General Partner in connection with the equity restructuring.  This legal action may result in a delay of the release of the $12.5 million from escrow.  If a delay occurs, and the delay extends beyond September 30, 2013, the new majority owner of the General Partner has agreed to pay $12.5 million to the Partnership to be used to repay borrowings on its credit facility. Following the release of the $12.5 million from escrow, the former majority owner of the general partner is entitled to receive warrants to purchase 300,000 of the Partnership's common units with a $0.01 per warrant exercise price. The warrants will be exercisable on the later of 18 months from the completion of the equity restructuring or the date that the volume weighted average closing price of the common units exceeds $25.00 for 30 consecutive trading days.

Due to the improvement in distribution coverage resulting from the equity restructuring, management intends to recommend to the board of directors an increase in the quarterly distribution of three percent to five percent beginning with the distribution for the third quarter 2013.

33
Table of Contents

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the unaudited consolidated financial statements and the related notes thereto included elsewhere in this Quarterly Report and the audited consolidated financial statements and notes thereto and management’s discussion and analysis of financial condition and results of operations as of and for the year ended December 31, 2012 included in Annual Report on Form 10-K (“Annual Report”) that was filed with the Securities and Exchange Commission (the “SEC”) on April 16, 2013. This discussion contains forward-looking statements that reflect management’s current views with respect to future events and financial performance. Our actual results may differ materially from those anticipated in these forward-looking statements or as a result of certain factors such as those set forth below under the caption “Cautionary Statement Regarding Forward-Looking Statements.”
Cautionary Statement About Forward-Looking Statements
Our reports, filings and other public announcements may from time to time contain statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements”. You can typically identify forward-looking statements by the use of forward-looking words, such as “may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,” “plan,” “forecast” and other similar words.
All statements that are not statements of historical facts, including statements regarding our future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements.
These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. These risks and uncertainties, many of which are beyond our control, include, but are not limited to, the risks set forth in “Item 1A. Risk Factors” and elsewhere in this Quarterly Report, the Annual Report and the following:
•
the amount of collateral required to be posted from time to time in our transactions;
•
our success in risk management activities, including the use of derivative financial instruments to hedge weather, commodity and interest rate risks;
•
the level of creditworthiness of counterparties to transactions;
•
changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment;
•
the timing and extent of changes in natural gas, natural gas liquids and other commodity prices, interest rates and demand for our services;
•
weather and other natural phenomena;
•
industry changes, including the impact of consolidations and changes in competition;
•
our ability to obtain necessary licenses, permits and other approvals;
•
the level and success of crude oil and natural gas drilling around our existing and recently acquired assets and our success in connecting natural gas supplies to our gathering and processing systems;
•
our ability to grow through acquisitions or internal growth projects and the successful integration and future performance of such assets; and
•
general economic, market and business conditions.
Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and, therefore, we cannot assure you that the forward-looking statements included in this Quarterly Report will prove to be accurate. Some of these and other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described in “Item 1A. Risk Factors” and elsewhere in this Quarterly Report and our Annual Report. Except as may be required by applicable law, we undertake no obligation to publicly update or advise of any change in any forward-looking statement, whether as a result of new information, future events or otherwise.
Overview
We are a growth-oriented Delaware limited partnership that was formed in August 2009 to own, operate, develop and acquire a diversified portfolio of natural gas midstream energy assets. We are engaged in the business of gathering, treating, processing, fractionating and transporting natural gas through our ownership and operation of eleven gathering systems, four processing facilities, three interstate pipelines and five intrastate pipelines. We also own a 50% undivided, non-operating interest in a processing plant located in southern Louisiana. Our primary assets, which are strategically located in Alabama, Louisiana, Mississippi, and Texas, provide critical infrastructure that links producers and suppliers of natural gas to diverse natural gas markets, including

34
Table of Contents

various interstate and intrastate pipelines, as well as utility, industrial and other commercial customers. We currently operate approximately 2,100 miles of pipelines that gather and transport over 1 Bcf/d of natural gas.
Significant financial highlights and challenges during the three months ended June 30, 2013, include the following:
•
The High Point System, along with $15 million in cash, was contributed to the us by HPIP in exchange for 5,142,857 Series A Units, effective April 15, 2013. The contribution of the High Point System occurred concurrently with HPIP's acquisition of 90% of our general partner and all of our subordinated units, which resulted in HPIP gaining control of the our general partner and a majority of our outstanding limited partner interests;
•
Our distributable cash flow for the three months ended June 30, 2013 was $1.8 million. We distributed $3.7 million to our unitholders or $0.4325 per unit, net of $0.4 million of distribution foregone by our general partner for the first quarter of 2013 during the three months ended June 30, 2013;
•
For the three months ended June 30, 2013, gross margin increased to $16.9 million or 50% compared to the same period in 2012;
•
On April 15, 2013, we repaid approximately $12.5 million in outstanding borrowings under the credit agreement and entered into the Fourth Amendment in connection with the ArcLight Transactions; and
•
During the second quarter of 2013, management was approved to commit to a plan to sell certain non-strategic gathering and processing assets which meet specific criteria as held for sale. As of June 30, 2013, certain of our gathering and processing assets were written down by $1.8 million to the estimated fair value less cost to sell.
Significant operational highlights and challenges during the three months ended June 30, 2013, include the following:
•
Throughput attributable to the Partnership totaled 951.1 MMcf/d for the second quarter of 2013 representing a 26.5% increase compared to the same period in 2012;
•
Incremental condensate production associated with our 87.4% undivided interest in the Chatom system totaled 38.6 Mgal/d for the second quarter of 2013 which contributed to our overall of increase in condensate production of 679% for the three months ended June 30, 2013;
•
As previously disclosed, certain assets were impacted by Hurricane Isaac to which the Partnership is insured for named windstorms on the affected assets after a $1.0 million deductible. Insurance proceeds of $0.6 million were received during the three months ended June 30, 2013. and
•
During the second quarter of 2013, management determined to change its commercial approach towards certain non-strategic gathering and processing assets. As a result, an asset impairment charge of $15.2 million was recorded for the three months ended June 30, 2013.
Recent Developments
On April 15, 2013, the Partnership, our general partner and AIM Midstream Holdings, LLC, an affiliate of American Infrastructure MLP Fund, entered into agreements with High Point Infrastructure Partners, LLC, an affiliate of ArcLight Capital Partners, LLC (“High Point”), pursuant to which High Point (i) acquired 90% of our general partner, which holds all of our general partner units and incentive distribution rights, and all of our subordinated units from AIM Midstream Holdings, LLC and (ii) contributed certain midstream assets and $15.0 million in cash to us in exchange for 5,142,857 convertible preferred units (the “Series A Preferred Units”) issued by the Partnership. Of the $15.0 million cash consideration paid by High Point, approximately $2.5 million was used to pay certain transaction expenses of High Point, and the remaining approximately $12.5 million was used to repay borrowings outstanding under the Partnership's credit facility in connection with the Fourth Amendment. As a result of these transactions, which were also consummated on April 15, 2013, High Point acquired both control of our general partner and a majority of our outstanding limited partnership interests. Please read "— ArcLight Transactions." Contemporaneously with the consummation of these transactions, we also entered into a Fourth Amendment to our credit agreement that, among other things, provides for the permanent waiver of any recent covenant breaches relating to consolidated total leverage ratio, modifies the covenant relating to total leverage ratio through the quarter ended December 31, 2014 and requires us to reduce the quarterly cash distribution that would otherwise be payable in respect of our subordinated units or Series A Preferred Units for the first, second, third and fourth

35
Table of Contents

quarters of 2013. Please read "— Fourth Amendment to Credit Agreement" and "—Liquidity and Capital Resources — Our Credit Facility" for more information about our credit facility, covenant violations and related waivers and the Fourth Amendment.
ArcLight Transactions
Purchase Agreement
On April 15, 2013, AIM Midstream Holdings and High Point entered into a Purchase Agreement, pursuant to which High Point purchased from AIM Midstream Holdings all of the Partnership's 4,526,066 subordinated units and 90% of the limited liability company interests in our general partner, which holds all of our general partner units and incentive distribution rights. The transactions contemplated by the Purchase Agreement were consummated on April 15, 2013. Of the cash consideration paid to AIM Midstream Holdings, $12.5 million is being held in escrow until its release upon satisfaction of certain conditions.
Contribution Agreement
On April 15, 2013, the Partnership and High Point entered into a Contribution Agreement, pursuant to which High Point contributed to us 100% of the limited liability company interests in certain of its subsidiaries that own midstream assets located in southern and offshore Louisiana (the “High Point system”) and $15.0 million in cash in exchange for 5,142,857 newly issued Series A Preferred Units. Of the $15.0 million cash consideration paid by High Point, approximately $2.5 million was used to pay certain transaction expenses of High Point, and the remaining approximately $12.5 million was used to repay borrowings outstanding under the Partnership's June 2012 amended credit facility in connection with the Fourth Amendment. The transactions contemplated by the Contribution Agreement were consummated on April 15, 2013.
Third Amended & Restated Agreement of Limited Partnership
On April 15, 2013, our general partner entered into the Third Amended & Restated Agreement of Limited Partnership of the Partnership (the “Amended Partnership Agreement”) providing for the creation and designation of the rights, preferences, terms and conditions of the Series A Preferred Units.
Under the terms of the Amended Partnership Agreement, during the period that commences with the quarter that ends on June 30, 2013 and ending with the earlier of the quarter that includes a conversion of the Series A Preferred Units and the quarter beginning October 1, 2014 (the “Coupon Conversion Quarter”), the Series A Preferred Units will each receive quarterly distributions (the “Series A Quarterly Distributions”) in an amount equal to (i) 0.01428571 of additional Series A Preferred Units (subject to customary anti-dilution adjustments) (the "PIK Distribution") and (ii) $0.25 in cash (with the additional Series A Preferred Units and cash portion relating to the quarter ending June 30, 2013 being prorated based on the number of days in such quarter that follow the date on which the Series A Preferred Units were issued). Commencing with the Coupon Conversion Quarter, the Series A Preferred Units will receive the Series A Quarterly Distributions in an amount equal to the greater of (a) the amount of aggregate distributions that would be payable had such Series A Preferred Units converted into Common Units and (b) a fixed rate of 0.023571428 multiplied by the conversion price, which will initially be $17.50 per Series A Preferred Unit (subject to customary anti-dilution adjustments) (the “Conversion Price”), paid in arrears within 45 days after the end of each quarter and prior to distributions with respect to the common units and subordinated units. The record date for the determination of holders entitled to receive Series A Quarterly Distributions will be the same as the record date for determination of common unit holders entitled to receive quarterly distributions.
If we fail to pay in full any Series A Quarterly Distribution, the amount of such unpaid distribution will accrue, accumulate and bear interest at a rate of 6.0% per annum from the first day of the quarter immediately following the quarter for which such distribution is due until paid in full.
The Series A Preferred Units have voting rights that are identical to the voting rights of the common units and will vote with the common units as a single class, with each Series A Preferred Unit entitled to one vote for each common unit into which such Series A Preferred Unit is convertible. The Series A Preferred Units also have separate class voting rights on any matter, including a merger, consolidation or business combination, that adversely affects, amends or modifies any of the rights, preferences, privileges or terms of the Series A Preferred Units. Moreover, the general partner may not take any of the following actions without the prior written consent of High Point or any of its affiliates, as long as High Point or such affiliates together hold at least 50% of the Series A Preferred Units and Subordinated Units held by High Point immediately following the issuance of the Series A Preferred Units on April 15, 2013:
•
cause or permit us to invest in, or dispose of, the equity securities or debt securities of any person or otherwise acquire or dispose of any interest in any person, to acquire or dispose of interest in any joint venture or partnership or any similar arrangement with any person, or to acquire or dispose of assets of any person, or to make any capital expenditure (other than maintenance capital expenditures), or to make any loan or advance to any person if the total consideration (including cash,

36
Table of Contents

equity issued and debt assumed) paid or payable, or received or receivable, by us exceeds $15,000,000 in any one or series of related transactions or in the aggregate exceeds $50,000,000 in any twelve-month period;
•
cause or permit us to (i) incur, create or guarantee any indebtedness that exceeds (x) $75,000,000 in any one or series of related transactions to the extent the proceeds of such financing are used to refinance our existing indebtedness, or (y) $25,000,000 in any twelve-month period to the extent such indebtedness increases our aggregate indebtedness or (ii) incur, create or guarantee any indebtedness with a yield to maturity exceeding ten percent (10)%;
•
authorize or permit the purchase, redemption or other acquisition of Partnership interests (or any options, rights, warrants or appreciation rights relating to the Partnership interests) by us;
•
select or dismiss, or enter into any employment agreement or amendment of any employment agreement of, the chief executive officer and the chief financial officer of the Partnership or its subsidiary, American Midstream, LLC;
•
enter into any agreement or effect any transaction between us or any of our subsidiaries, on the one hand, and any affiliate of the Partnership or the general partner, on the other hand, other than any transaction in the ordinary course of business and determined by the board of directors of the general partner to be on an arm's length basis; or
•
cause or permit us or any of our subsidiaries to enter into any agreement or make any commitment to do any of the foregoing.
The Series A Preferred Units are convertible in whole or in part into common units at any time after January 1, 2014 or, prior to that date, with the consent of the required lenders under the June 2012 amended credit agreement, at the holder's election. The number of common units into which a Series A Preferred Unit is convertible will be an amount equal to (i) the sum of $17.50 and all accrued and accumulated but unpaid distributions, divided by (ii) the Conversion Price, which will initially be $17.50 per Series A Preferred Unit (subject to customary anti-dilution adjustments) (the “Conversion").
In the event that the Partnership issues, sells or grants any common units or convertible securities at an indicative per Common Unit price that is less than $17.50 (subject to customary anti-dilution adjustments), then the Conversion Rate will be adjusted according to a formula to provide an increase in the number of common units into which Series A Preferred Units are convertible.
Prior to the consummation of any recapitalization, reorganization, consolidation, merger, spin-off or other business combination in which the holders of common units are to receive securities, cash or other assets (a “Partnership Event”), we are obligated to make an irrevocable written offer, subject to consummation of the Partnership Event, to each holder of Series A Preferred Units to redeem all (but not less than all) of such holder's Series A Preferred Units for a price per Series A Preferred Unit payable in cash equal to the greater of:
•
the sum of $17.50 and all accrued and accumulated but unpaid distributions for each Series A Preferred Unit; and
•
an amount equal to the product of:
(i) the number of common units into which each Series A Preferred Unit is convertible; and
(ii) the sum of:
(A) the cash consideration per common unit to be paid to the holders of common units pursuant to the Partnership Event, plus
(B) the fair market value per common unit of the securities or other assets to be distributed to the holders of the common units pursuant to the Partnership Event.
Upon receipt of such a redemption offer from us, each holder of Series A Preferred Units may elect to receive such cash amount or a preferred security issued by the person surviving or resulting from such Partnership Event and containing provisions substantially equivalent to the provisions set forth in the Amended Partnership Agreement with respect to the Series A Preferred Units without material abridgement.
Upon any liquidation and winding up of the Partnership or the sale of substantially all of the assets of the Partnership, the holders of Series A Preferred Units generally will be entitled to receive, in preference to the holders of any of the Partnership's other securities, an amount equal to the sum of the $17.50 multiplied by the number of Series A Units owned by such holders, plus all accrued but unpaid distributions on such Series A Preferred Units.
Change of Control of the General Partner and the Partnership
Through the acquisition of the 90% interest in our general partner, the acquisition of all of our 4,526,066 subordinated units and the issuance of the 5,142,857 Series A Units, High Point acquired control of our general partner and a majority of our outstanding limited partner interests. In connection with High Point's acquisition of control of our general partner, each of Robert B. Hellman, Jr., Edward O. Diffendal and L. Kent Moore resigned from the board of directors of our general partner. Mr. Hellman also resigned as chairman of the board of directors of our general partner. These resignations occurred on April 15, 2013. High Point, as the owner of 90% of the limited liability company interests in our general partner, will have the right to fill the board vacancies created by these resignations. Effective April 15, 2013, High Point appointed Messrs. Bergstrom, Erhard and Revers to the board of directors of our general partner.
Fourth Amendment to Credit Agreement

37
Table of Contents

On April 15, 2013, a subsidiary of the Partnership, American Midstream, LLC, as borrower (the “Borrower”) and the Partnership entered into a Fourth Amendment with its lenders under its June 2012 amended credit agreement. The Fourth Amendment provides for the following:
•
Permits the consummation of the ArcLight Transactions and the PIK Distribution according to the terms of the Amended Partnership Agreement;
•
The aggregate commitments of the lenders under the June 2012 amended credit agreement will be reduced to $175 million if an equity contribution of $12.5 million has not been made by AIM Midstream Holdings and used to repay borrowings under the June 2012 amended credit facility by October 1, 2013;
•
The total outstanding borrowings under the June 2012 amended credit facility shall not exceed $175 million until such equity contribution by AIM Midstream Holdings has occurred;
•
The margins relating to our (i) Eurodollar-based loans range from 2.50% to 4.75% depending on the Consolidated Total Leverage ratio then in effect, and (ii) base rate loans range from 1.5% to 3.75%;
•
The definition of Consolidated Total Indebtedness will not include the Series A Preferred Units or certain surety bonds relating to the High Point Assets;
•
The definition of Consolidated EBITDA (the consolidated EBITDA for the quarters ending June 30 and September 30, 2013 will be annualized for purposes of the Consolidated Total Leverage Ratio) will:
◦
include, on a pro forma basis, the consolidated EBITDA of the High Point Subsidiaries as if they were owned by the Partnership beginning on January 1, 2013;
◦
exclude any insurance proceeds attributable to any event occurring prior to January 1, 2013; and
◦
exclude any one-time, non-recurring transaction expenses of the Partnership incurred in connection with the ArcLight Transactions or the Fourth Amendment.
•
Starting with the quarter ending March 31, 2013 and ending with the quarter ending December 31, 2013, unless the Partnership has permanently canceled at least 20% of the number of subordinated units outstanding on April 15, 2013, the Partnership must reduce any quarterly cash distribution on either its subordinated units or Series A Preferred Units (at the Partnership's election) by an aggregate of $0.4 million per quarter, and such reduction may not be replaced by in-kind distributions of Partnership securities;
•
The maximum Consolidated Total Leverage Ratio permitted as of the end of any fiscal quarter cannot exceed the ratio set forth below:
Fiscal Quarter Ending
Consolidated Total Leverage Ratio
June 30, 2013
5.90:1.00
September 30, 2013
5.90:1.00
December 31, 2013
5.75:1.00
March 31, 2014
5.75:1.00
June 30, 2014
5.75:1.00
September 30, 2014
5.50:1.00
December 31, 2014
5.25:1.00
March 31, 2015 and each fiscal quarter thereafter
4.50:1.00

•
The Partnership agrees to cooperate with and pay the fees and expenses incurred by Bank of America, N.A., the administrative agent for the June 2012 amended credit agreement, in connection with its engagement of FTI Consulting to advise and assist it in an assessment of the Partnership's financial condition; and
•
The lenders permanently waived the Partnership's failure to comply with covenants relating to the Partnership's Consolidated Total Leverage Ratio for the quarters ended December 31, 2012 and March 31, 2013.

As of July 31, 2013, we had approximately $131.2 million of outstanding borrowings and approximately $29.7 million of available borrowing capacity as a result of the reduction of our borrowing capacity to a total of $175 million as described herein.

Subsequent Events
Distribution
On July 23, 2013, we announced a distribution of $0.4325 per unit for the quarter ended June 30, 2013, or $1.73 per unit on an annualized basis, payable on August 14, 2013 to unitholders of record on August 7, 2013 amounting to $3.7 million, net of $0.4 million of distribution foregone by our general partner.

38
Table of Contents


Equity restructuring

Effective August 9, 2013, we executed an equity restructuring agreement with American Midstream GP, LLC, our general partner, the holder of all of the Incentive Distribution Rights, and HPIP, owner of all of the outstanding subordinated units. As part of the equity restructuring agreement, 4.5 million subordinated units and previous Incentive Distribution Rights of the Partnership were combined into, and restructured as a new class of Incentive Distribution Rights (referred to herein as the “new IDRs”).   The transaction, which does not require further consents or approvals, was unanimously approved by the Board of Directors of the Partnership, on the unanimous approval and recommendation of its Conflicts Committee, which is composed solely of independent directors.

The equity restructuring permanently eliminates the subordinated units and previous Incentive Distribution Rights of the Partnership in return for the new IDRs.  Prior to completion of the equity restructuring, we were required to pay the minimum quarterly distribution of $0.4125 per unit on the subordinated units, or approximately $2 million per quarter, prior to increasing the quarterly distribution on American Midstream's common units.
 
The prior Incentive Distribution Rights provided for our general partner to receive increasing percentages (ranging from 13 percent to 48 percent) of incremental cash distributions after unitholders of the Partnership (both common and subordinated) received quarterly distributions ranging from $0.47438 per unit to $0.61875 per unit.  The new IDRs entitle our general partner to receive 48 percent of any quarterly cash distributions after common unit holders of the Partnterhsip have received the full minimum quarterly distribution ($0.4125 per unit) for each quarter plus any arrearages from prior quarters (of which there are currently none).  

In conjunction with the equity restructuring, we are entitled to receive $12.5 million that was placed in escrow in conjunction with the acquisition in April 2013 by HPIP of our subordinated units and general partner interests. Once released from escrow, we will use the proceeds to repay borrowings on our credit facility. Following the release of the $12.5 million from escrow, the former majority owner of the general partner is entitled to receive warrants to purchase 300,000 of the Partnership's common units with a $0.01 per warrant exercise price. The warrants will be exercisable on the later of 18 months from the completion of the equity restructuring or the date that the volume weighted average closing price of the common units exceeds $25.00 for 30 consecutive trading days.

Due to the improvement in distribution coverage resulting from the equity restructuring, management intends to recommend to the board of directors an increase in the quarterly distribution of three percent to five percent beginning with the distribution for the third quarter 2013.

Our Operations
We manage our business and analyze and report our results of operations through two business segments:
•
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, performing fractionation 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.
Gathering and Processing Segment
Results of operations from our Gathering and Processing segment are determined primarily by the volumes of natural gas we gather, process and fractionate, the commercial terms in our current contract portfolio and natural gas, NGL and condensate prices. We gather and process gas primarily pursuant to the following arrangements:
•
Fee-Based Arrangements. Under these arrangements, we generally are paid a fixed cash fee for gathering and processing and transporting natural gas.
•
Fixed-Margin Arrangements. Under these arrangements, we purchase natural gas from producers or suppliers at receipt points on our systems at an index price less a fixed transportation fee and simultaneously sell an identical volume of natural gas at delivery points on our systems at the same, undiscounted index price. By

39
Table of Contents

entering into back-to-back purchases and sales of natural gas, we are able to lock in a fixed-margin on these transactions. We view the segment gross margin earned under our fixed-margin arrangements to be economically equivalent to the fee earned in our fee-based arrangements.
•
Percent-of-Proceeds Arrangements (“POP”). Under these arrangements, we generally gather raw natural gas from producers at the wellhead or other supply points, transport it through our gathering system, process it and sell the residue natural gas, NGLs and condensate at market prices. Where we provide processing services at the processing plants that we own or obtain processing services for our own account in connection with our elective processing arrangements, such as under our Toca contract, we generally retain and sell a percentage of the residue natural gas and resulting NGLs and condensate. However, we also have contracts under which we retain a percentage of the resulting NGLs and do not retain a percentage of residue natural gas, such as for our interest in the Burns Point Plant. Our POP arrangements also often contain a fee-based component.
•
Interest in the Burns Point Plant. We account for our interest in the Burns Point Plant using the proportionate consolidation method. Under this method, we include in our consolidated statement of operations, our value of plant revenues taken in-kind and plant expenses reimbursed to the operator.
•
Interest in the Chatom Assets. We account for our 87.4% undivided interest in the Chatom Assets pursuant to ASC No. 810, Consolidation. Under this method, revenues, expenses, gains, losses, net income or loss, and other comprehensive income are reported in the consolidated financial statements at the consolidated amounts, which include the amounts attributable to the partners' and the noncontrolling interests. The consolidated income statement shall separately present net income attributable to the partners' and the noncontrolling interests.
Gross margin earned under fee-based and fixed-margin arrangements is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices. However, a sustained decline in commodity prices could result in a decline in volumes and, thus, a decrease in our fee-based and fixed-margin gross margin. These arrangements provide stable cash flows, but minimal, if any, upside in higher commodity price environments. Under our typical POP arrangement, our gross margin is directly impacted by the commodity prices we realize on our share of natural gas, NGLs and condensate received as compensation for processing raw natural gas. However, our POP arrangements also often contain a fee-based component, which helps to mitigate the degree of commodity-price volatility we could experience under these arrangements. We further seek to mitigate our exposure to commodity price risk through our hedging program. Please read “ — Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk.”
Transmission Segment
Results of operations from our Transmission segment are determined primarily by capacity reservation fees from firm transportation contracts and, to a lesser extent, the volumes of natural gas transported on the interstate and intrastate pipelines we own pursuant to interruptible transportation or fixed-margin contracts. Our transportation arrangements are further described below:
•
Firm Transportation Arrangements. Our obligation to provide firm transportation service means that we are obligated to transport natural gas nominated by the shipper up to the maximum daily quantity specified in the contract. In exchange for that obligation on our part, the shipper pays a specified reservation charge, whether or not the shipper utilizes the capacity. In most cases, the shipper also pays a variable use charge with respect to quantities actually transported by us.
•
Interruptible Transportation Arrangements. Our obligation to provide interruptible transportation service means that we are only obligated to transport natural gas nominated by the shipper to the extent that we have available capacity. For this service the shipper pays no reservation charge but pays a variable use charge for quantities actually shipped.
•
Fixed-Margin Arrangements. Under these arrangements, we purchase natural gas from producers or suppliers at receipt points on our systems at an index price less a fixed transportation fee and simultaneously sell an identical volume of natural gas at delivery points on our systems at the same, undiscounted index price. We view fixed-margin arrangements to be economically equivalent to our interruptible transportation arrangements.

The contribution of the High Point system, which occurred concurrently with HPIP's acquisition of 90% of our general partner, is presented within our Transmission segment.
How We Evaluate Our Operations
Our management uses a variety of financial and operational metrics to analyze our performance. We view these metrics as important factors in evaluating our profitability and review these measurements on at least a monthly basis for consistency and trend analysis. These metrics include throughput volumes, gross margin and direct operating expenses on a segment basis, and adjusted EBITDA and distributable cash flow on a company-wide basis.

40
Table of Contents

Throughput Volumes
In our Gathering and Processing segment, we must continually obtain new supplies of natural gas to maintain or increase throughput volumes on our systems. Our ability to maintain or increase existing volumes of natural gas and obtain new supplies is impacted by (i) the level of work-overs or recompletions of existing connected wells and successful drilling activity in areas currently dedicated to or near our gathering systems, (ii) our ability to compete for volumes from successful new wells in the areas in which we operate, (iii) our ability to obtain natural gas that has been released from other commitments and (iv) the volume of natural gas that we purchase from connected systems. We actively monitor producer activity in the areas served by our gathering and processing systems to pursue new supply opportunities.

In our Transmission segment, a significant portion of our segment gross margin is generated by firm capacity reservation fees, as opposed to the actual throughput volumes, on our interstate and intrastate pipelines. Segment gross margin on our High Point system, effective April 15, 2013, is generated through volumetric fees, and therefore gross margin is highly dependent on throughput volumes. Substantially all Transmission segment gross margin is generated under contracts with shippers, including producers, industrial companies, LDCs and marketers, for firm and interruptible natural gas transportation on our pipelines. We routinely monitor natural gas market activities in the areas served by our transmission systems to pursue new shipper opportunities.
Gross Margin and Segment Gross Margin
Gross margin and segment gross margin are metrics that we use to evaluate our performance. We define segment gross margin in our Gathering and Processing segment as revenue generated from gathering and processing operations and realized gain (loss) on commodity derivatives, less construction, operating and maintenance agreement (“COMA”) income, less the cost of natural gas, NGLs and condensate purchased (inclusive, of gross margin from discontinued operations). Revenue includes revenue generated from fixed fees associated with the gathering and treating of natural gas and from the sale of natural gas, NGLs and condensate resulting from gathering, processing and fractionating activities under fixed-margin and POP arrangements. The cost of natural gas, NGLs and condensate includes volumes of natural gas, NGLs and condensate remitted back to producers pursuant to POP arrangements and the cost of natural gas purchased for our own account, including pursuant to fixed-margin arrangements.
We define segment gross margin in our Transmission segment as revenue generated from firm and interruptible transportation agreements and fixed-margin arrangements, plus other related fees, less COMA income, less the cost of natural gas purchased in connection with fixed-margin arrangements. Substantially all of our gross margin in this segment is fee-based or fixed-margin, with little to no direct commodity price risk.
Effective October 1, 2012, we changed our segment gross margin measure to exclude COMA income. For the three months ended June 30, 2013 and 2012, $0.1 million and $0.1 million in COMA income was excluded from our Gathering and Processing segment gross margin, respectively and less than $0.1 million and $0.8 million in COMA income was excluded from our Transmission segment gross margin, respectively. For the six months ended June 30, 2013 and 2012, $0.1 million and $0.6 million in COMA income was excluded from our Gathering and Processing segment gross margin, respectively and $0.1 million and $1.6 million in COMA income was excluded from our Transmission segment gross margin, respectively.
Direct Operating Expenses
Our management seeks to maximize the profitability of our operations in part by minimizing direct operating expenses without sacrificing safety or the environment. Direct labor costs, insurance costs, ad valorem and property taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities, lost and unaccounted for gas and contract services comprise the most significant portion of our operating expenses. These expenses are relatively stable and largely independent of throughput volumes through our systems, but may fluctuate depending on the activities performed during a specific period.
Adjusted EBITDA
Adjusted EBITDA is a measure used by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:
•
the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
•
the ability of our assets to generate cash sufficient to support our indebtedness and make cash distributions to our unitholders and general partner;
•
our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and
•
the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.

41
Table of Contents

We define adjusted EBITDA as net income, plus interest expense, income tax expense, depreciation expense, certain non-cash charges such as non-cash equity compensation, unrealized losses on commodity derivative contracts and selected charges that are unusual or non-recurring such as impairments of long-lived assets, less interest income, income tax benefit, unrealized gains on commodity derivative contracts, COMA income, amortization of commodity put purchase costs, and selected gains that are unusual or non-recurring. The GAAP measure most directly comparable to adjusted EBITDA is net income.
Distributable Cash Flow
Distributable cash flow is a significant performance metric used by us and by external users of our financial statements, such as investors, commercial banks and research analysts, to compare basic cash flows generated by us to the cash distributions we expect to pay our unitholders. Using this metric, management and external users of our financial statements can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. Distributable cash flow is also an important financial measure for our unitholders since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Distributable cash flow is also a quantitative standard used throughout the investment community with respect to publicly-traded partnerships and limited liability companies because the value of a unit of such an entity is generally determined by the unit’s yield (which in turn is based on the amount of cash distributions the entity pays to a unitholder). Distributable cash flow will not reflect changes in working capital balances.
We define distributable cash flow as adjusted EBITDA plus interest income, less cash paid for interest expense, normalized integrity management costs, normalized maintenance capital expenditures and accrued cash distributions on our Series A Units.

Note About Non-GAAP Financial Measures
Gross margin, adjusted EBITDA and distributable cash flow are all non-GAAP financial measures. Each has important limitations as an analytical tool because it excludes some, but not all, items that affect the most directly comparable GAAP financial measures. Management compensates for the limitations of these non-GAAP measures as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these data points into management’s decision-making process.
You should not consider any of gross margin, adjusted EBITDA or distributable cash flow in isolation or as a substitute for analysis of our results as reported under GAAP. Gross margin, adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry Our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.
For a reconciliation of gross margin to net income, its most directly comparable financial measure calculated and presented in accordance with GAAP, please read Note 15 "Reporting Segments" to our unaudited condensed consolidated financial statements included in “Item 1. Financial Statements” of this Quarterly Report.
The following tables reconcile the non-GAAP financial measures, adjusted EBITDA and distributable cash flow, used by management to their most directly comparable GAAP measures for the three and six months ended June 30, 2013 and 2012 (in thousands):
 

42
Table of Contents

 
Three months ended June 30,
 
Six months ended June 30,
 
2013
 
2012
 
2013
 
2012
Net (loss) income attributable to the Partnership
$
(21,637
)
 
$
2,327

 
$
(25,190
)
 
$
4,018

Add:
 
 
 
 
 
 
 
Depreciation and accretion expense
6,733

 
5,124

 
12,411

 
10,283

Interest expense
1,581

 
825

 
3,080

 
1,582

Debt issuance costs
403

 
—

 
1,315

 
—

Unrealized (gain) loss on derivatives, net
(236
)
 
(3,171
)
 
245

 
(3,494
)
Non-cash equity compensation expense
1,097

 
467

 
1,485

 
798

Transaction expenses
1,080

 
—

 
1,422

 
—

Loss on impairment of property, plant and equipment
15,232

 
—

 
15,232

 
—

Loss on impairment of noncurrent assets held for sale
1,807

 
—

 
1,807

 
—

Deduct:
 
 
 
 
 
 
 
COMA income
146

 
955

 
252

 
2,161

Straight-line amortization of put costs (1)
30

 
111

 
57

 
223

OPEB plan net periodic benefit
18

 
20

 
36

 
41

Gain on involuntary conversion of property, plant and equipment
—

 
—

 
343

 
—

Gain on sale of assets, net
—

 
117

 
—

 
122

Adjusted EBITDA
$
5,866

 
$
4,369

 
$
11,119

 
$
10,640

Deduct:
 
 
 
 
 
 
 
Cash interest expense (2)
$
1,557

 
$
682

 
$
3,039

 
$
1,298

Normalized maintenance capital (3)
1,104

 
875

 
2,145

 
1,750

Normalized integrity management (4)
370

 
375

 
544

 
750

Series A Convertible Preferred payment (5)
1,074

 
—

 
1,074

 
—

Distributable Cash Flow
$
1,761

 
$
2,437

 
$
4,317

 
$
6,842

 
(1)
Amounts noted represent the straight-line amortization of the cost of commodity put contracts over the life of the contract.
(2)
Excludes amortization of debt issuance costs and mark-to-market adjustments related to interest rate derivatives.
(3)
Amounts noted represent estimated annual maintenance capital expenditures of $4.5 million which is what we expect to be required to maintain our assets over the long term.
(4)
Amounts noted represent average estimated integrity management costs over the seven year mandatory testing cycle net of integrity management costs that are expensed in direct operating expenses.
(5)
Calculated on a pro-rata basis for the number of days the Series A units were outstanding during the second quarter of 2013.
General Trends and Outlook
We expect our business to continue to be affected by the key trends discussed under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations — General Trends and Outlook” in the Annual Report.
Results of Operations — Combined Overview
For the three and six months ended June 30, 2013, gross margin increased by $5.6 million, or 50% and $6.1 million or 26%, respectively, as compared to the same periods in 2012. For the six months ended June 30, 2013, the increase in gross margin was largely a result of (i) higher gross margin in our Transmission segment of $4.8 million as a result of incremental gross margin associated with our High Point system, effective April 15, 2013, of $5.6 million and (ii) higher gross margin in our Gathering and Processing segment of $1.3 million due to incremental gross margin at our Chatom system, effective July 1, 2012, of $5.7 million, offset by lower natural gas throughput volumes of 102.6 MMcf/d or 28.9% from other assets in the segment amounting to $4.4 million.


43
Table of Contents

For the three and six months ended June 30, 2013, our distributable cash flow was $1.8 million and $4.3 million, respectively. We distributed $7.8 million to our unitholders or $0.865 per unit paid during the six months ended June 30, 2013.
The following table and discussion presents certain of our historical consolidated financial data for the periods indicated. The results of operations by segment are discussed in further detail following this combined overview.
 
 
Three months ended June 30,
 
Six months ended June 30,
 
2013
 
2012
 
2013
 
2012
 
(in thousands)
Statement of Operations Data:
 
 
 
 
 
 
 
Revenue
$
73,828

 
$
39,487

 
$
133,613

 
$
84,686

Unrealized gain on commodity derivatives
914

 
3,835

 
609

 
3,494

Total revenue
74,742

 
43,322

 
134,222

 
88,180

Operating expenses
 
 
 
 
 
 
 
Purchases of natural gas, NGLs and condensate
57,396

 
27,942

 
104,698

 
58,711

Direct operating expenses
7,121

 
3,194

 
11,923

 
6,079

Selling, general and administrative expenses
4,588

 
3,668

 
8,013

 
6,997

Equity compensation expense
1,097

 
467

 
1,485

 
798

Depreciation and accretion expense
6,698

 
5,092

 
12,344

 
10,218

Total operating expenses
76,900

 
40,363

 
138,463

 
82,803

Gain on involuntary conversion of property, plant and equipment
—

 
—

 
343

 
—

Gain on sale of assets, net
—

 
117

 
—

 
122

Loss on impairment of property, plant and equipment
(15,232
)
 
—

 
(15,232
)
 
—

Operating (loss) income
(17,390
)
 
3,076

 
(19,130
)
 
5,499

Other income (expense):
 
 
 
 
 
 
 
Interest expense
(2,190
)
 
(825
)
 
(3,921
)
 
(1,582
)
Net (loss) income from continuing operations
$
(19,580
)
 
$
2,251

 
$
(23,051
)
 
$
3,917

Discontinued operations
(1,869
)
 
76

 
(1,796
)
 
101

Net (loss) income
$
(21,449
)
 
$
2,327

 
$
(24,847
)
 
$
4,018

Net income attributable to noncontrolling interests
$
188

 
$
—

 
$
343

 
 
Net (loss) income attributable to the Partnership
$
(21,637
)
 
$
2,327

 
$
(25,190
)
 
$
4,018

Other Financial Data:
 
 
 
 
 
 
 
Gross margin (a)
$
16,923

 
$
11,254

 
$
29,921

 
$
23,815

Adjusted EBITDA (b)
$
5,866

 
$
4,369

 
11,119

 
$
10,640

Distributable cash flow (c)
$
1,761

 
$
2,437

 
4,317

 
$
6,842

 
(a)
For a definition of gross margin and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read Note 15 "Reporting Segments" to our unaudited condensed consolidated financial statements included in this Quarterly Report for a discussion of how we use gross margin to evaluate our operating performance.
(b)
For a definition of adjusted EBITDA and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP and a discussion of how we use adjusted EBITDA to evaluate our operating performance, please read “—How We Evaluate Our Operations”.
(c)
For a definition of distributable cash flow and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP and a discussion of how we use distributable cash flow to evaluate our operating performance, please read “—How We Evaluate Our Operations”.



44
Table of Contents

Three months ended June 30, 2013 Compared to Three months ended June 30, 2012
Revenue. Our revenue for the three months ended June 30, 2013 was $73.8 million compared to $39.5 million for the three months ended June 30, 2012. This increase of $34.3 million was primarily due to the following:
•
Natural gas revenues increased $14.2 million as a result of higher realized natural gas prices of $4.37/Mcf, an increase of $1.92/Mcf or 78.4% period over period, along while natural gas sales volumes increased 5% period over period;
•
Condensate revenues increased $9.6 million as a result of higher condensate production of 39.4 Mgal/d due to the newly acquired Chatom system, effective July 1, 2012, period over period, offset by lower realized condensate prices of $2.25/gal, a decrease of $0.26/gal period over period;
•
NGL revenues increased $1.9 million as a result of higher NGL volumes associated with our elective processing agreement offset by lower gross NGL production volumes of 7.10 Mgal/d due to lower volumes from our Gathering and Processing segment and lower realized NGL prices of $0.82/gal, a decrease of $0.27/gal period over period; and
•
Transmission revenues from the transportation of natural gas increased $13.4 million primarily as a result of (i) incremental revenue of $5.2 million associated with our High Point system, and (ii) higher realized natural gas prices on our fixed margin contracts of $4.25/Mcf amounting to $6.1 million and higher transmission throughput of 48.6 MMcf/d or 20% period over period.

Purchases of Natural Gas, NGLs and Condensate. Our purchases of natural gas, NGLs and condensate for the three months ended June 30, 2013 were $57.4 million compared to $27.9 million for the three months ended June 30, 2012. This increase of $29.5 million was primarily due to higher purchase costs associated with natural gas and condensate due to higher realized natural gas prices, higher natural gas purchase volumes and higher condensate production related to POP contracts associated with owned processing plants in our Gathering and Processing segment, offset by lower realized NGL and condensate prices.
Gross Margin. Gross margin for the three months ended June 30, 2013 was $16.9 million compared to $11.3 million for the three months ended June 30, 2012. This increase of $5.6 million was primarily due to (i) higher gross margin in our Transmission segment of $4.8 million as a result of incremental gross margin associated with our High Point system, effective April 15, 2013, of $5.6 million and (ii) higher gross margin in our Gathering and Processing segment of $0.8 million due to incremental gross margin at our Chatom system, effective July 1, 2012, of $3.1 million, offset by lower natural gas throughput volumes of 82.7 MMcf/d or 24.0% from other assets and lower margins associated with our POP and elective processing agreements in the segment amounting to $2.3 million.
Direct Operating Expenses. Direct operating expenses for the three months ended June 30, 2013 were $7.1 million compared to $3.2 million in the three months ended June 30, 2012. This increase of $3.9 million was primarily due to: (i) $2.1 million of additional direct operating expenses associated with the contributed High Point system, effective April 15, 2013; (ii) $1.1 million of additional direct operating expenses associated with our newly acquired Chatom system, effective July 1, 2012; and (iii) $0.8 million of costs associated with our property and casualty insurance.
Selling, General and Administrative Expenses ("SG&A"). SG&A expenses for the three months ended June 30, 2013 were $4.6 million compared to $3.7 million for the three months ended June 30, 2012. This increase of $0.9 million was primarily due to (i) higher transaction costs of $1.1 million associated with the Arclight Transactions; (ii) incremental costs of $0.3 million associated with our High Point system, effective April 15, 2013; offset by (iii) lower personnel costs.
Equity Compensation Expense. Compensation expense related our LTIP for the three months ended June 30, 2013 was $1.1 million compared to $0.5 million for the three months ended June 30, 2012. This increase of $0.6 million was primarily due to the amortization of additional unit based awards granted in 2013 and 2012.
Depreciation and Accretion Expense. Depreciation expense for the three months ended June 30, 2013 was $6.7 million compared to $5.1 million for the three months ended June 30, 2012. This increase of $1.6 million was due to depreciation associated with (i) the contributed assets of the High Point system, effectively April 15, 2013; (ii) the acquired Chatom system, effectively July 1, 2012; and (iii) other capital projects placed into service during the period.
Loss on impairment of property, pant and equipment. During the second quarter of 2013, management determined to change its commercial approach towards certain non-strategic gathering and processing assets. As a result, an asset impairment charge of $15.2 million was recorded for the three months ended June 30, 2013. There was no impairment charge necessary in the comparative periods presented.
Interest Expense. Interest expense for the three months ended June 30, 2013 was $2.2 million compared to $0.8 million for the three months ended June 30, 2012. This increase of $1.4 million was primarily due to the increase in borrowings under our credit facility associated with the acquired Chatom system, effectively July 1, 2012.

45
Table of Contents


Six months ended June 30, 2013 Compared to Six months ended June 30, 2012
Revenue. Our revenue for the six months ended June 30, 2013 was $133.6 million compared to $84.7 million for the six months ended June 30, 2012. This increase of $48.9 million was primarily due to the following:
•
Natural gas revenues increased $22.2 million as a result of higher realized natural gas prices of $4.06/Mcf, an increase of $1.46/Mcf or 56.2% period over period, along while natural gas sales volumes increased 2% period over period;
•
Condensate revenues increased $19.4 million as a result of higher condensate production of 38.7 Mgal/d due to the newly acquired Chatom system, effective July 1, 2012, period over period, offset by lower realized condensate prices of $2.32/gal, a decrease of $0.22/gal period over period;
•
NGL revenues increased $2.8 million as a result of slightly higher gross NGL production volumes at our owned processing plants of 0.3 Mgal/d and higher NGL production associated with our elective processing agreement in our Gathering and Processing segment, offset by lower realized NGL prices of $0.85/gal, a decrease of $0.37/gal period over period; and
•
Transmission revenues from the transportation of natural gas increased $14.9 million primarily as a result of i) incremental revenue of $5.2 million associated with our High Point system, and ii) higher realized natural gas prices on our fixed margin contracts of $4.25/Mcf amounting to $6.1 million and higher transmission throughput of 48.6 MMcf/d or 20% period over period.

Purchases of Natural Gas, NGLs and Condensate. Our purchases of natural gas, NGLs and condensate for the six months ended June 30, 2013 were $104.7 million compared to $58.7 million for the six months ended June 30, 2012. This increase of $46.0 million was primarily due to higher purchase costs associated with natural gas and condensate due to higher realized natural gas prices, higher natural gas purchase volumes and higher condensate production related to POP contracts associated with owned processing plants in our Gathering and Processing segment, offset by lower realized NGL and condensate prices.
Gross Margin. Gross margin for the six months ended June 30, 2013 was $29.9 million compared to $23.8 million for the six months ended June 30, 2012. This increase of $6.1 million was primarily due to (i) higher gross margin in our Transmission segment of $4.8 million as a result of incremental gross margin associated with our High Point system, effective April 15, 2013, of $5.6 million and (ii) higher gross margin in our Gathering and Processing segment of $1.3 million due to incremental gross margin at our Chatom system, effective July 1, 2012, of $5.7 million, offset by lower natural gas throughput volumes of 102.6 MMcf/d or 28.9% from other assets in the segment amounting to $4.4 million.
Direct Operating Expenses. Direct operating expenses for the six months ended June 30, 2013 were $11.9 million compared to $6.1 million in the six months ended June 30, 2012. This increase of $5.8 million was primarily due to: (i) $2.1 million of additional direct operating expenses associated with the contributed High Point system, effective April 15, 2013; (ii) $2.2 million of additional direct operating expenses associated with our acquired Chatom system, effective July 1, 2012; and (iii) $0.9 million of costs associated with our property and casualty insurance.
Selling, General and Administrative Expenses ("SG&A"). SG&A expenses for the six months ended June 30, 2013 were $8.0 million compared to $7.0 million for the six months ended June 30, 2012. This increase of $1.0 million was primarily due to (i) higher transaction costs of $1.4 million associated with the Arclight Transactions; (ii) incremental costs of $0.3 million associated with our High Point system, effective April 15, 2013; offset by (iii) lower personnel costs.
Equity Compensation Expense. Compensation expense related our LTIP for the six months ended June 30, 2013 was $1.5 million compared to $0.8 million for the six months ended June 30, 2012. This increase of $0.7 million was primarily due to the amortization of additional unit based awards granted in 2013 and 2012.
Depreciation and Accretion Expense. Depreciation expense for the six months ended June 30, 2013 was $12.3 million compared to $10.2 million for the six months ended June 30, 2012. This increase of $2.1 million was due to depreciation associated with (i) the contributed assets of the High Point system, effectively April 15, 2013; (ii) the acquired Chatom system, effectively July 1, 2012; and (iii) other capital projects placed into service during the period.
Loss on impairment of property, pant and equipment. During the second quarter of 2013, management determined to change its commercial approach towards certain non-strategic gathering and processing assets. As a result, an asset impairment charge of $15.2 million was recorded for the six months ended June 30, 2013. There was no impairment charge necessary in the comparative periods presented.

46
Table of Contents

Interest Expense. Interest expense for the six months ended June 30, 2013 was $3.9 million compared to $1.6 million for the six months ended June 30, 2012. This increase of $2.3 million was primarily due to the increase in borrowings under our credit facility associated with the acquired Chatom system, effectively July 1, 2012.
Results of Operations — Segment Results
The table below contains key segment performance indicators related to our segment results of operations.
 
 
Three months ended June 30,
 
Six months ended June 30,
 
2013
 
2012
 
2013
 
2012
 
(in thousands except operational data)
Segment Financial and Operating Data:
 
 
 
 
 
 
 
Gathering and Processing segment
 
 
 
 
 
 
 
Financial data:
 
 
 
 
 
 
 
Revenue
$
49,175

 
$
28,218

 
$
94,297

 
$
59,670

Gain on commodity derivatives, net
914

 
3,835

 
609

 
4,103

Total revenue
50,089

 
32,053

 
94,906

 
63,773

Purchases of natural gas, NGLs and condensate
40,366

 
20,278

 
77,067

 
42,670

Direct operating expenses
3,565

 
2,069

 
6,982

 
3,871

Other financial data:
 
 
 
 
 
 
 
Segment gross margin
$
9,340

 
$
8,468

 
18,340

 
$
17,012

Operating data:
 
 
 
 
 
 
 
Average throughput (MMcf/d)
261.2

 
343.9

 
253.0

 
355.6

Average plant inlet volume (MMcf/d) (a) (b)
112.3

 
143.1

 
104.3

 
145.8

Average gross NGL production (Mgal/d) (a) (c)
43.6

 
50.7

 
51.4

 
51.1

Average gross condensate production (Mgal/d) (a) (c)
45.2

 
5.8

 
44.7

 
6.0

Average realized prices:
 
 
 
 
 
 
 
Natural gas ($/MMcf)
$
4.37

 
$
2.45

 
$
4.06

 
$
2.60

NGLs ($/gal)
0.82

 
1.09

 
0.85

 
1.22

Condensate ($/gal)
2.25

 
2.51

 
2.32

 
2.54

Transmission segment
 
 
 
 
 
 
 
Financial data:
 
 
 
 
 
 
 
Total revenue
$
24,653

 
$
11,269

 
$
39,316

 
$
24,407

Purchases of natural gas, NGLs and condensate
17,030

 
7,664

 
27,631

 
16,041

Direct operating expenses
3,556

 
1,125

 
4,941

 
2,208

Other financial data:
 
 
 
 
 
 
 
Segment gross margin
$
7,583

 
$
2,786

 
11,581

 
$
6,803

Operating data:
 
 
 
 
 
 
 
Average throughput (MMcf/d)
689.9

 
407.8

 
567.0

 
400.6

Average firm transportation - capacity reservation (MMcf/d)
680.9

 
661.1

 
724.6

 
711.2

Average interruptible transportation - throughput (MMcf/d)
110.3

 
77.4

 
119.7

 
67.0

 
(a)
Excludes volumes and gross production under our elective processing arrangements.
(b)
Includes gross plant inlet volume associated with our interest in the Burns Point processing plant.
(c)
Includes net NGL and condensate production associated with our interest in the Burns Point processing plant.


47
Table of Contents

Three months ended June 30, 2013 Compared to Three months ended June 30, 2012
Gathering and Processing Segment
Revenue. Segment total revenue in the three months ended June 30, 2013 was $50.1 million compared to $32.1 million in the three months ended June 30, 2012. This increase of $18.0 million was primarily due to the following:
•
Higher realized natural gas prices of 78.4% offset by lower realized NGL prices of 24.8% and realized condensate prices of 10.4% period over period as a result of variable commodity prices;
•
Higher average gross condensate production amounting to 39.4 Mgal/d or 679.3% period over period as a result of our acquired 87.4% undivided interest in the Chatom system, effective July 1, 2012; offset by
•
Lower average natural gas throughput volumes amounting to 82.7 MMcf/d or 24.0% period over period primarily as a result of lower natural gas throughput volumes of 50.9 MMcf/d and 35.6 MMCf/d on our Quivira system and into our Burns Point plant, respectively;
•
Higher NGL volume associated with our elective processing agreement offset by lower average gross NGL production amounting to 7.1 Mgal/d or 14.0% period over period as a result of our reduced production of 4.9 Mgal/d at the Burns Point plant and 3.9 Mgal/d on our Bazor Ridge system offset by 2.4 Mgal/d on our acquired 87.4% undivided interest in the Chatom system, effective July 1, 2012; and
•
A decrease in Gain on commodity derivatives, net of $2.9 million period over period on our commodity derivatives which comprised of financial swaps, collars and option contracts used to mitigate commodity price risk that will settled in 2013. For a discussion of our commodity derivative positions, please read “Item 3. Quantitative and Qualitative Disclosures about Market Risk.”
Purchases of Natural Gas, NGLs and Condensate. Our purchases of natural gas, NGLs and condensate for the three months ended June 30, 2013 were $40.4 million compared to $20.3 million for the three months ended June 30, 2012. This increase of $20.1 million was primarily due to (i) primarily due to higher purchase costs associated with natural gas and condensate due to higher realized natural gas prices, higher natural gas purchase volumes and higher condensate production related to POP contracts associated with owned processing plants, offset by lower realized NGL and condensate prices; and (ii) incremental purchase costs associated with our Chatom system, effective July 1, 2012, of $10.6 million.
Segment Gross Margin. Segment gross margin for the three months ended June 30, 2013 was $9.3 million compared to $8.5 million for the three months ended June 30, 2012. This increase of $0.8 million was primarily due to the following:
•
Incremental segment gross margin of $2.9 million associated with the POP and fee based contracts associated with the Chatom system, acquired effective July 1, 2012;
•
Receipt of insurance proceeds related to our business interruption claim as a result of Hurricane Issac of $0.6 million; offset by
•
Lower segment gross margins of $1.4 million associated with our Burns Point plant and Quivira system as a result of lower level of volumes from a producer customer;
•
Lower segment gross margin of $1.6 million associated with lower NGL sales volumes and NGL prices on our Bazor Ridge system and lower realized NGL prices related to our elective processing agreement on our Gloria system; and
•
An decrease in realized gains of $0.4 million period over period on our commodity derivatives which comprised of financial swaps, collars and option contracts which were used to mitigate commodity price risk that settled in 2013.
Direct Operating Expenses. Direct operating expenses for the three months ended June 30, 2013 were $3.6 million compared to $2.1 million for the three months ended June 30, 2012. This increase of $1.5 million was primarily due to the incremental operating costs associated with our 87.4% undivided interest in the Chatom system, effective July 1, 2012, amounting to $1.1 million.
Loss on impairment of property, pant and equipment. During the second quarter of 2013, management determined to change its commercial approach towards certain non-strategic gathering and processing assets. As a result, an asset impairment charge of $15.2 million was recorded for the three months ended June 30, 2013. There was no impairment charge necessary in the comparative periods presented.
Transmission Segment
Revenue. Segment total revenue for the three months ended June 30, 2013 was $24.7 million compared to $11.3 million for the three months ended June 30, 2012. This increase of $13.4 million in segment revenue was primarily due to:

48
Table of Contents

•
Higher realized natural gas prices on our fixed margin contracts of $1.89/Mcf amounting to $6.1 million; and
•
Total natural gas throughput volumes on our Transmission systems for the three months ended June 30, 2013 were 689.9 MMcf/d compared to 407.8 MMcf/d for the three months ended June 30, 2012 representing a 69.2% increase period over period primarily due to the contribution of the High Point system, effective April 15, 2013, amounting to $5.2 million.
Purchases of Natural Gas, NGLs and Condensate. Purchases of natural gas, NGLs and condensate for the three months ended June 30, 2013 were $17.0 million compared to $7.7 million for the three months ended June 30, 2012. This increase of $9.3 million was primarily due to (i) higher realized natural gas prices, which resulted in higher natural gas purchase costs associated with our fixed margin agreements on MLGT and Midla amounting to $3.4 million, and (ii) incremental purchase costs associated with our High Point system, effective April 15, 2013, of $0.4 million.
Segment Gross Margin. Segment gross margin for the three months ended June 30, 2013 was $7.6 million compared to $2.8 million for the three months ended June 30, 2012. This increase of $4.8 million was primarily due to incremental gross margin on our High Point system, effective April 15, 2013, of $5.6 million.
Direct Operating Expenses. Direct operating expenses for the three months ended June 30, 2013 were $3.6 million compared to $1.1 million for the three months ended June 30, 2012. This increase of $2.5 million is primarily due to our High Point system, effective April 15, 2013, amounting $2.1 million.
Six months ended June 30, 2013 Compared to Six months ended June 30, 2012
Gathering and Processing Segment
Revenue. Segment total revenue in the six months ended June 30, 2013 was $94.9 million compared to $63.8 million in the six months ended June 30, 2012. This increase of $31.1 million was primarily due to the following:
•
Higher realized natural gas prices of 56.2% offset by lower realized NGL prices of 30.3% and realized condensate prices of 8.7% period over period as a result of variable commodity prices;
•
Higher average gross condensate production amounting 38.7 Mgal/d or 645.0% period over period as a result of our acquired 87.4% undivided interest in the Chatom system, effective July 1, 2012;
•
Higher NGL volume associated with our elective processing agreement and slightly higher average gross NGL production amounting to 0.3 Mgal/d or 0.6% period over period as a result of our acquired 87.4% undivided interest in the Chatom system, effective July 1, 2012 offset by lower production on our Bazor Ridge system and Burns Point Plant; offset by
•
Lower average natural gas throughput volumes amounting to 102.6 MMcf/d or 28.9% period over period as a result of lower volumes at our Burns Point plant and Quivira system; and
•
A decrease in Gain on commodity derivatives, net of $3.5 million period over period on our commodity derivatives which comprised of financial swaps, collars and option contracts used to mitigate commodity price risk that will settled in 2013. For a discussion of our commodity derivative positions, please read “Item 3. Quantitative and Qualitative Disclosures about Market Risk.”
Purchases of Natural Gas, NGLs and Condensate. Our purchases of natural gas, NGLs and condensate for the six months ended June 30, 2013 were $77.1 million compared to $42.7 million for the six months ended June 30, 2012. This increase of $34.4 million was primarily due to (i) primarily due to higher purchase costs associated with natural gas and condensate due to higher realized natural gas prices, higher natural gas purchase volumes and higher condensate production related to POP contracts associated with owned processing plants, offset by lower realized NGL and condensate prices; and (ii) incremental purchase costs associated with our Chatom system, effective July 1, 2012, of $21.5 million.
Segment Gross Margin. Segment gross margin for the six months ended June 30, 2013 was $18.3 million compared to $17.0 million for the six months ended June 30, 2012. This increase of $1.3 million was primarily due to the following:
•
Incremental segment gross margin of $5.7 million associated with the POP and fee based contracts associated with the Chatom system, acquired effective July 1, 2012;
•
Receipt of insurance proceeds related to our business interruption claim as a result of Hurricane Issac of $0.6 million; offset by
•
Lower segment gross margins of $2.9 million associated with our Burns Point Plant and Quivira system as a result of lower level of volumes on one of its offshore pipeline systems;

49
Table of Contents

•
Lower segment gross margin of $2.3 million associated with lower NGL sales volumes and NGL prices on our Bazor Ridge system and lower realized NGL prices related to our elective processing agreement on our Gloria system; and
•
An decrease in realized gains of $0.2 million period over period on our commodity derivatives which comprised of financial swaps, collars and option contracts which were used to mitigate commodity price risk that settled in 2013.
Direct Operating Expenses. Direct operating expenses for the six months ended June 30, 2013 were $7.0 million compared to $3.9 million for the six months ended June 30, 2012. This increase of $3.1 million was primarily due to (i) incremental operating costs associated with our 87.4% undivided interest in the Chatom system, effective July 1, 2012, amounting to $2.2 million and (ii) $0.9 million of costs associated with our property and casualty insurance.
Loss on impairment of property, pant and equipment. During the second quarter of 2013, management determined to change its commercial approach towards certain non-strategic gathering and processing assets. As a result, an asset impairment charge of $15.2 million was recorded for the six months ended June 30, 2013. There was no impairment charge necessary in the comparative periods presented.
Transmission Segment
Revenue. Segment total revenue for the six months ended June 30, 2013 was $39.3 million compared to $24.4 million for the six months ended June 30, 2012. This increase of $14.9 million in segment revenue was primarily due to:
•
Higher realized natural gas prices on our fixed margin contracts of $1.28/Mcf amounting to $7.4 million; and
•
Total natural gas throughput volumes on our Transmission systems for the six months ended June 30, 2013 was 567.0 MMcf/d compared to 400.6 MMcf/d for the six months ended June 30, 2012 representing a 41.5% increase period over period primarily due to the contribution of the High Point system, effective April 15, 2013, amounting to $5.2 million.
Purchases of Natural Gas, NGLs and Condensate. Purchases of natural gas, NGLs and condensate for the six months ended June 30, 2013 were $27.6 million compared to $16.0 million for the six months ended June 30, 2012. This increase of $11.6 million was primarily due to higher realized natural gas prices, which resulted in higher natural gas purchase costs associated with our fixed margin agreements on MLGT and Midla amounting to $5.2 million, and (ii) incremental purchase costs associated with our High Point system, effective April 15, 2013, of $0.4 million.
Segment Gross Margin. Segment gross margin for the six months ended June 30, 2013 was $11.6 million compared to $6.8 million for the six months ended June 30, 2012. This increase of $4.8 million was primarily due to incremental gross margin on our High Point system, effective April 15, 2013, of $5.6 million offset be lower gross margin on our remaining assets of $0.8 million.
Direct Operating Expenses. Direct operating expenses for the six months ended June 30, 2013 were $4.9 million compared to $2.2 million for the six months ended June 30, 2012. This increase of $2.7 million is primarily due to our High Point system, effective April 15, 2013, amounting $2.1 million.
Liquidity and Capital Resources
Our business is capital intensive and requires significant investment for the maintenance of existing assets and the acquisition and development of new systems and facilities.
Our Credit Facility
On June 27, 2012, we amended our August 2011 credit facility to increase the commitments from an aggregate principal amount of $100 million to an aggregate principal amount of $200 million, evidenced by a credit agreement with Bank of America, N.A., as Administrative Agent, Collateral Agent and L/C Issuer; Comerica Bank and Citicorp North America, Inc., as Co-Syndication Agents; BBVA Compass, as Documentation Agent; and the other financial institutions party thereto.
Our June 2012 amended credit facility provided for a maximum borrowing equal to the lesser of (i) $200 million or (ii) 4.50 times adjusted consolidated EBITDA. Prior to the Third Amendment described below, we could elect to have loans under the June 2012 amended credit facility bear interest either at a Eurodollar-based rate plus a margin ranging from 2.25% to 3.50% 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 1/2 of 1%, (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 1.25% to 2.50% 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.

50
Table of Contents

For the six months ended June 30, 2013 and 2012, the weighted average interest rate on borrowings under our credit facility was approximately 4.48% and 3.88%, respectively.
Our obligations under each of our credit facilities, including the current June 2012 amended credit facility, are secured by a first mortgage in favor of the lenders in our real property. Advances made under the June 2012 amended credit facility are guaranteed on a senior unsecured basis by our subsidiaries (“Guarantors”). These guarantees are full and unconditional and joint and several among the Guarantors. The terms of the June 2012 amended 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, August 1, 2016.
The June 2012 amended 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 June 2012 amended credit facility are (i) a total leverage ratio test (which, prior the Fourth Amendment could not exceed 4.50) and a minimum interest coverage ratio test (which, prior to the Third Amendment could not less be than 2.50).
As of December 31, 2012, the total leverage ratio test, one of the primary financial covenants that we were required to maintain under our June 2012 amended credit facility, exceeded the leverage covenant. As a result, on December 26, 2012, the Partnership entered into the Third Amendment and Waiver to Credit Agreement, dated as of December 26, 2012 (the “Third Amendment”). The Third Amendment provided for a waiver of the Partnership's compliance with the Consolidated Total Leverage Ratio with respect to the quarter ending December 31, 2012 and for one month thereafter. The Third Amendment also required the Partnership to provide certain financial and operating information of the Partnership on a monthly basis for 2013 and for any month after 2013 in which the Consolidated Total Leverage Ratio of the Partnership is in excess of 4.00 to 1.00. The remaining material terms and conditions of the June 2012 amended credit facility, including pricing, maturity and covenants, remained unchanged by the Third Amendment.
On January 24, 2013, the Partnership entered into the second waiver to the June 2012 amended credit facility that extended the waiver period with respect to the Consolidated Total Leverage Ratio to March 31, 2013 (and subsequently extended to April 16, 2013). Additional covenants during the waiver period included i) total outstanding borrowings under the June 2012 amended credit facility could not exceed $150 million; ii) restrictions on certain acquisitions; iii) an increase to the Eurodollar rate by 0.50%; iv) additional fees of 0.125% of the principal amount on each of February 28, 2013 and March 31, 2013; and v) execution of a compliance certificate.
At December 31, 2012, our total indebtedness was approximately $130.9 million, which caused our total leverage to EBITDA ratio to be approximately 5.7-to-1. Prior to the Fourth Amendment to our June 2012 amended credit agreement, the maximum value permitted under the June 2012 amended credit agreement for that ratio could not exceed 4.5 to 1.0. As of March 31, 2013, outstanding debt under our June 2012 amended credit facility was approximately $139 million, which further exceeded the maximum Consolidated Total Leverage Ratio as of that date and constituted a default under the June 2012 amended credit agreement. Please read “Recent Developments — Fourth Amendment to Credit Agreement” for a description of the Fourth Amendment.
On April 15, 2013, we repaid approximately $12.5 million in outstanding borrowings under the June 2012 amended credit agreement and entered into the Fourth Amendment to our June 2012 amended credit agreement in connection with the ArcLight Transactions. As a result, we had approximately $130 million of outstanding borrowings as of April 15, 2013 and approximately $45 million of available borrowing capacity as a result of the reduction of our borrowing capacity to a total of $175 million as described below. Until June 30, 2013, we were not required to meet a Consolidated Leverage Ratio under our June 2012 amended credit facility. We expect that we will have continued availability under our June 2012 amended credit facility and be able to meet the Fourth Amendment's Consolidated Leverage Ratio, but there can be no assurance that will be the case or what that availability might be. Please see “Recent Developments — ArcLight Transactions” for more information about the ArcLight Transactions.
The principal indicators of our liquidity at June 30, 2013 were our cash on hand and availability under our credit facility as it exists under the Fourth Amendment as discussed below. As of June 30, 2013, our available liquidity was $35.0 million, comprised of cash on hand of $0.4 million and $34.6 million available under our credit facility. As of July 31, 2013, our available liquidity was $29.7 million.
In the near term, we expect our sources of liquidity to include cash generated from operations, asset sales, borrowings under our credit facility and issuances of debt and equity securities. As a result of the contribution of the High Point assets to the Partnership (with the resultant expected increase in the Partnership's EBITDA for the trailing twelve months), the Fourth Amendment, and the PIK Distribution on the Series A Preferred Units and the Preferred Unit Distribution Waiver, we expect to generate sufficient cash flow from operations and borrowings under our June 2012 amended credit facility, as needed, to:

51
Table of Contents

•
pay the required distribution on the Series A Convertible Preferred Units (a portion of which is payable in-kind in additional Series A Preferred Units (“Series A PIK Units”), less the Preferred Unit Distribution Waiver;
•
pay at least the minimum quarterly distribution on all outstanding common units, subordinated units, and general partner units; and
•
meet our requirements for working capital and capital expenditures, in each case until at least April 16, 2014. Please see “Recent Developments — ArcLight Transactions” for more information about the ArcLight Transactions.

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. We are required to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control, including events and circumstances that may stem from the condition of financial markets and commodity price levels. Our failure to comply with any of the covenants under our credit facility could result in a default, which could cause all of our existing indebtedness to become immediately due and payable. We were unable to maintain compliance with consolidated total leverage ratio required by our June 2012 amended credit agreement as it existed prior to the Fourth Amendment during the quarters ended December 31, 2012 and March 31, 2013 but we were able to obtain wavers from the lenders for these covenant breaches. On April 15, 2013, we entered into a Fourth Amendment to our June 2012 amended credit agreement that, among other things, modified the maximum permitted consolidated total leverage ratio. The maximum consolidated total leverage ratio permitted by the Fourth Amendment varies by quarter, initially permitting a ratio of 5.90 to 1.00 for the quarter ending June 30, 2013 and then gradually lowering to 4.50 to 1.00 commencing with the quarter ending March 31, 2015. The Partnership believes that the consummation of the ArcLight Transactions will allow it to comply with the Consolidated Total Leverage to EBTIDA ratio in the Fourth Amendment until at least April 16, 2014. However, no assurances can be given that the ArcLight Transactions will achieve the necessary ratios or that the contributed business can yield the necessary cash flows.

Working Capital
Working capital is the amount by which current assets exceed current liabilities and is a measure of our ability to pay our liabilities as they become due. Our working capital requirements are primarily driven by changes in accounts receivable and accounts payable. These changes are impacted by changes in the prices of commodities that we buy and sell. In general, our working capital requirements increase in periods of rising commodity prices and decrease in periods of declining commodity prices. However, our working capital needs do not necessarily change at the same rate as commodity prices because both accounts receivable and accounts payable are impacted by commodity prices. In addition, the timing of payments received from our customers or paid to our suppliers can also cause fluctuations in working capital because we settle with most of our larger suppliers and customers on a monthly basis and often near the end of the month. We expect that our future working capital requirements will be impacted by these same factors.
Our working capital deficit was $3.2 million at June 30, 2013.
Cash Flows
The following table reflects cash flows for the applicable periods:
 
Six months ended June 30,
 
2013
 
2012
 
(in thousands)
Net cash provided by (used in):
 
 
 
Operating activities
$
11,659

 
$
10,971

Investing activities
(12,034
)
 
(7,762
)
Financing activities
222

 
(3,042
)
Six months ended June 30, 2013 Compared to Six months ended June 30, 2012
Operating Activities. Net cash provided by operating activities was $11.7 million for the six months ended June 30, 2013 compared to $11.0 million for the six months ended June 30, 2012. Net cash provided by operating activities for the six months ended June 30, 2013 increased period over period primarily due to (i) incremental gross margin associated with our High Point system, effective April 15, 2013, of $5.6 million and additional gross margin at our Chatom system, effective July 1, 2012, of $5.8 million, offset by lower realized NGL prices and reduced gathering and processing volumes associated with one of our offshore pipeline systems; offset by net cash used of (ii) $2.1 million of additional direct operating expenses associated with the contributed High Point system, effective April 15, 2013, $2.2 million of additional direct operating expenses associated with our acquired Chatom system, effective July 1, 2012, and $0.9 million of additional costs associated with our property and casualty insurance; (iii) incremental

52
Table of Contents

SG&A costs of $1.0 million; and (iv) an decrease in proceeds received from the settlement of commodity derivatives of $0.2 million.
One of the primary sources of variability in our cash flows from operating activities is fluctuation in commodity prices, which we partially mitigate by entering into commodity derivatives. Average throughput volume changes also impact cash flow, but have not been as volatile as commodity prices. Our long-term cash flows from operating activities are dependent on commodity prices, average throughput volumes, costs required for continued operations and cash interest expense.
Investing Activities. Net cash used in investing activities was $12.0 million for the six months ended June 30, 2013 compared to $7.8 million for the six months ended June 30, 2012. Cash used in investing activities for the six months ended June 30, 2013 increased period over period primarily due to (i) $7.2 million used to fund the development of our Madison County system and (ii) $3.1 million used to fund maintenance capital primarily associated improvements at our Bazor Ridge system, as compared to $5.5 million used to fund the escrow associated with the acquisition of the Chatom system, effective July 1, 2012, for the six months ended June 30, 2012.
Financing Activities. Net cash used in financing activities was $0.2 million for the six months ended June 30, 2013 compared to net cash used of $3.0 million for the six months ended June 30, 2012. Cash used by financing activities for the six months ended June 30, 2013 increased period over period primarily due to (i) distribution payments of $7.8 million and (ii) a decrease of $4.6 million in net borrowings from our credit facility which is used to fund growth opportunities and maintenance capital, offset by (iii) the issuance of the Series A convertible preferred units amounting to $14.4 million, as compared to higher net borrowings of $6.0 million for the six months ended June 30, 2012.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements.
Capital Requirements
The midstream energy business can be capital intensive, requiring significant investment for the maintenance of existing assets and the acquisition and development of new systems and facilities. We categorize our capital expenditures as either:
•
maintenance capital expenditures, which are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity; or
•
expansion capital expenditures, which are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term.
Historically, our maintenance capital expenditures have not included all capital expenditures required to maintain volumes on our systems. It is customary in the regions in which we operate for producers to bear the cost of well connections, but we cannot be assured that this will be the case in the future. For the six months ended June 30, 2013, capital expenditures totaled $12.5 million including growth capital expenditures of $8.9 million, maintenance capital expenditures of $3.1 million and reimbursable project expenditures (capital expenditures for which we expect to be reimbursed for all or part of the expenditures by a third party) of $0.5 million. Although we classified our capital expenditures as expansion and maintenance, we believe those classifications approximate, but do not necessarily correspond to, the definitions of estimated maintenance capital expenditures and expansion capital expenditures under our partnership agreement.
We anticipate that we will continue to make significant expansion capital expenditures in the future. Consequently, our ability to develop and maintain sources of funds to meet our capital requirements is critical to our ability to meet our growth objectives. As a result of the change in our General Partner, contribution of the High Point assets to the Partnership, the Fourth Amendment, the PIK Distribution on the Series A Preferred Units and the Preferred Unit Distribution Waiver, we expect to generate sufficient cash flow from operations and borrowings under our June 2012 amended credit facility, as needed, to meet our requirements for future expansion capital expenditures until at least April 16, 2014.
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. We are required to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control, including events and circumstances that may stem from the condition of financial markets and commodity price levels. Our failure to comply with any of the covenants under our credit facility could result in a default, which could cause all of our existing indebtedness to become immediately due and payable. We were unable to maintain compliance with consolidated total leverage ratio required by our amended June 2012 credit agreement as it existed prior to the Fourth Amendment during the quarters ended December 31, 2012 and March 31, 2013 but we were able to obtain wavers from the lenders for these covenant breaches. On April 15, 2013, we entered into a Fourth Amendment to our

53
Table of Contents

June 2012 amended credit agreement that, among other things, modified the maximum permitted consolidated total leverage ratio. The maximum consolidated total leverage ratio permitted by the Fourth Amendment varies by quarter, initially permitting a ratio of 5.90 to 1.00 for the quarter ending June 30, 2013 and then gradually lowering to 4.50 to 1.00 commencing with the quarter ending March 31, 2015.
Integrity Management
Certain operating assets require an ongoing integrity management program under regulations of the U.S. Department of Transportation, or DOT. These regulations require transportation pipeline operators to implement continuous integrity management programs over a seven-year cycle. Our current program addresses sixteen high consequence areas, or HCAs, that required further testing pursuant to DOT regulations. We expect to incur approximately $2.0 million in integrity management expenses for the year ended December 31, 2013 associated with these HCAs to complete the current integrity management program.
Over the course of the seven-year cycle, we expect to incur an average of $1.5 million in integrity management expenses per year .
Because DOT regulations require integrity management activities for each HCA to be performed within seven years from when they were last performed, we expect to incur the following expenses (in thousands):
 
Year
Integrity
Management
Expense
2013
$
2,000

2014
5,015

2015
839

2016
675

2017
—

2018
—

2019
2,080

Total
$
10,609

Distributions
We intend to pay a quarterly distribution though we do not have a legal obligation to make distributions except as provided in our partnership agreement.
On February 14, 2013, we paid a distribution for the fourth quarter 2012 of $0.4325 per unit, or $4.0 million. On May 15, 2013, we paid a distribution for the first quarter 2013 of $0.4325 per unit, or $3.7 million, net of $0.4 million of distribution foregone by our general partner.
On July 23, 2013, we announced a distribution of $0.4325 per unit for the quarter ended June 30, 2013, or $1.73 per unit on an annualized basis, payable on August 14, 2013 to unitholders of record on August 7, 2013 amounting to $3.7 million, net of $0.4 million of distribution foregone by our general partner.
Due to the improvement in distribution coverage resulting from the equity restructuring, management intends to recommend to the board of directors an increase in the quarterly distribution of three percent to five percent beginning with the distribution for the third quarter 2013.
Contractual Obligations
The table below summarizes our obligations and other commitments as of June 30, 2013 (in thousands):
 
Payments Due by Period
 
Total
 
2013
 
2014
 
2015
 
2016
 
2017
 
Thereafter
Operating leases and service contracts - (a)
$
3,605

 
$
338

 
$
692

 
$
677

 
$
408

 
$
353

 
$
1,137

Asset retirement obligations
34,250

 
—

 
—

 
—

 
7,867

 
—

 
26,383

Total
$
37,855

 
$
338

 
$
692

 
$
677

 
$
8,275

 
$
353

 
$
27,520

(a) - Operating leases and service contracts have been reduced by total minimum sublease rentals of $52 due in the future under noncancelable subleases.


54
Table of Contents

Critical Accounting Policies
There were no changes to our significant accounting policies from those disclosed in the Annual Report.
Recent Accounting Pronouncements

In January 2013, the FASB issued Accounting Standards Update ("ASU") No. 2013-01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, which clarifies that ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities, applies to financial instruments or derivative transactions accounted for under ASC 815. The amendments require disclosures to present both gross and net amounts of derivative assets and liabilities that are subject to master netting arrangements with counterparties. We currently present our derivative assets and liabilities net on our statement of financial position. We have provided additional disclosures regarding the gross amounts of derivative assets and liabilities in Note 5 "Derivatives" in accordance with these new standards updates.

In February 2013, the FASB issued ASU No. 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income ("AOCI"), which requires entities to present either in a single note or parenthetically on the face of the financial statements (i) the amount of significant items reclassified from each component of AOCI and (ii) the income statement line items affected by the reclassifications. We adopted this guidance during the first quarter of 2013 which did not have a material impact on our condensed consolidated financial statements as there are currently no items reclassified from AOCI.

Item 3. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
The following should be read in conjunction with Quantitative and Qualitative Disclosures about Market Risk included in the Annual Report. We are exposed to market risk on our open derivative contracts of non-performance by our counterparties. We do not expect such non-performance because our contracts are with major financial institutions with investment grade credit ratings. We did not post collateral under any of these contracts, as they are secured under our credit agreement. We account for our derivative activities whereby each derivative instrument is recorded on the balance sheet as either an asset or liability measured at fair value. Refer to Note 5 "Derivatives" for further details.
During 2012, we entered into additional commodity contracts with existing counterparties to hedge our 2013 exposure to commodity prices. As of June 30, 2013, we have hedged approximately 51% of our expected exposure to commodity prices for the remainder of 2013.
The table below sets forth certain information regarding the financial instruments used to hedge of commodity price risk as of June 30, 2013 (in thousands):
 
Commodity
 
Instrument
 
Notional
Volumes (a)
 
Weighted Average Price
 
Period
 
Unrealized gain at June 30, 2013
Natural Gas (Mmbtu)
 
Swaps
 
(129,300
)
 
$3.80
 
Jul 2013 - Dec 2013
 
$
4.6

NGLs (gals)
 
Swaps
 
(1,521,600
)
 
$1.53
 
Jul 2013 - Dec 2013
 
897.9

 
 
Puts
 
(401,800
)
 
$1.06
 
Jul 2013 - Dec 2013
 
38.0

 
 
Collars (b)
 
(2,792,000
)
 
$1.02
 
Jul 2013 - Dec 2013
 
87.9

Oil (bbls)
 
Swaps
 
(37,300
)
 
$101.59
 
Jul 2013 - Dec 2013
 
13.7

 
 
 
 
 
 
 
 
 
 
$
1,042.1

(a)
Contracted volumes represented as a net short financial position by instrument.
(b)
Collars contain weighted average price for floors and caps of $0.80 and $1.25, respectively.

Interest Rate Risk
During the six months ended June 30, 2013, we had exposure to changes in interest rates on our indebtedness associated with our credit facility. During the second quarter of 2013 we entered into an interest rate swap to manage the impact of the interest rate risk associated with our credit facility, effectively converting the cash flows related to $100 million of our long-term variable rate debt into fixed rate cash flows.

55
Table of Contents

The credit markets have recently experienced historical lows in interest rates. As the overall economy strengthens, it is possible that monetary policy will begin to tighten, resulting in higher interest rates. Interest rates on floating rate credit facilities and future debt offerings could be higher than current levels, causing our financing costs to increase accordingly.
A hypothetical increase or decrease in interest rates by 1.0% would have changed our interest expense by $0.7 million for the six months ended June 30, 2013.

Item 4. Controls and Procedures
We maintain controls and procedures designed to ensure that information required to be disclosed in the reports we file with the SEC is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to our management, including our general partner’s President and Chief Executive Officer (our principal executive officer) and our general partner’s Senior Vice President & Chief Financial Officer (our principal financial officer), as appropriate, to allow for timely decisions regarding required disclosure. An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) or Rule 15d-15(e) of the Securities Exchange Act of 1934 (the “Exchange Act”)) was performed as of June 30, 2013. This evaluation was performed by our management, with the participation of our general partner’s President and Chief Executive Officer and Senior Vice President & Chief Financial Officer. Based on this evaluation, our general partner’s President and Chief Executive Officer and Senior Vice President & Chief Financial Officer concluded that these disclosure controls and procedures are effective to ensure that we are able to collect, process and disclose the information we are required to disclose in the reports we file with the SEC within the required time periods.
Changes in internal control
No changes in our internal control over financial reporting occurred during the quarter ended June 30, 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
The certifications of our general partner’s President and Chief Executive Officer and Senior Vice President & Chief Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a) are filed with this Quarterly Report on Form 10-Q as Exhibits 31.1 and 31.2. The certifications of our President and Chief Executive Officer and Senior Vice President & Chief Financial Officer pursuant to 18 U.S.C. 1350 are furnished with this Quarterly Report on Form 10-Q as Exhibits 32.1 and 32.2.


56
Table of Contents

PART II. OTHER INFORMATION
Item 1. Legal Proceedings
We are not a party to any legal proceeding other than legal proceedings arising in the ordinary course of our business. We are a party to various administrative and regulatory proceedings that have arisen in the ordinary course of our business. Please read under the captions “— Regulation of Operations — Interstate Transportation Pipeline Regulation” and “— Environmental Matters” in our Annual Report for more information.
Item 1A. Risk Factors
In addition to the other information set forth in this Quarterly Report, careful consideration should be given to the risk factors discussed under the caption “Risk Factors” in the Annual Report and below in this Quarterly Report.
Risks Related to Financing and Credit Environment
Our June 2012 amended credit facility includes financial covenants and ratios. We may have difficulty maintaining compliance with the financial covenants, which include a maximum leverage ratio on a quarterly basis, which could adversely affect our operations and our ability to pay distributions to our unitholders.

We depend on our June 2012 amended credit facility for future capital needs and to fund a portion of cash distributions to unitholders, as necessary. We are required to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control, including events and circumstances that may stem from the condition of financial markets and commodity price levels. Our failure to comply with any of the covenants under our June 2012 amended credit facility could result in a default, which could cause all of our existing indebtedness to become immediately due and payable. We were unable to maintain compliance with consolidated total leverage ratio required by our June 2012 amended credit agreement as it existed prior to the Fourth Amendment during the quarters ended December 31, 2012 and March 31, 2013. On April 15, 2013, we entered into a Fourth Amendment to our June 2012 amended credit agreement that, among other things, modified the maximum permitted consolidated total leverage ratio. The maximum consolidated total leverage ratio permitted by the Fourth Amendment varies by quarter, initially permitting a ratio of 5.90 to 1.00 for the quarter ending June 30, 2013 and then gradually lowering to 4.50 to 1.00 commencing with the quarter ending March 31, 2015.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Not applicable.
Item 3. Defaults Upon Senior Securities
Not applicable.
Item 4. Mine Safety Disclosures
Not applicable.
Item 5. Other Information
Not applicable.
Item 6. Exhibits

57
Table of Contents

Exhibit
Number
Exhibit
3.1
Certificate of Limited Partnership of American Midstream Partners, LP (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 (Commission File No. 333-173191) filed on March 31, 2011).
3.2
Second Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on August 4, 2011).
3.3
Certificate of Formation of American Midstream GP, LLC (incorporated by reference to Exhibit 3.4 to the Registration Statement on Form S-1 (Commission File No. 333-173191) filed on March 31, 2011).
3.4
Amended and Restated Limited Liability Company Agreement of American Midstream GP, LLC (incorporated by reference to Exhibit 3.5 to the Registration Statement on Form S-1 (Commission File No. 333-173191) filed on March 31, 2011).
3.5
First Amendment to Amended and Restated Limited Liability Company Agreement of American Midstream GP, LLC (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on August 4, 2011).
10.1
Second Waiver to Credit Agreement, dated as of January 24, 2013 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on January 29, 2013).
10.2
Third Waiver to Credit Agreement, dated as of March 29, 2013 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on April 1, 2013).
31.1*
Certification of Brian F. Bierbach, President and Chief Executive Officer of American Midstream GP, LLC, the general partner of American Midstream Partners, LP, for the March 31, 2013 Quarterly Report on Form 10-Q, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*
Certification of Daniel C. Campbell, Senior Vice President & Chief Financial Officer of American Midstream GP, LLC, the general partner of American Midstream Partners, LP, for the March 31, 2013 Quarterly Report on Form 10-Q, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*
Certification of Brian F. Bierbach, President and Chief Executive Officer of American Midstream GP, LLC, the general partner of American Midstream Partners, LP, for the March 31, 2013 Quarterly Report on Form 10-Q, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*
Certification of Daniel C. Campbell, Senior Vice President & Chief Financial Officer of American Midstream GP, LLC, the general partner of American Midstream Partners, LP, for the March 31, 2013 Quarterly Report on Form 10-Q, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
**101.INS
XBRL Instance Document
**101.SCH
XBRL Taxonomy Extension Schema Document
**101.CAL
XBRL Taxonomy Extension Calculation Linkbase Document
**101.DEF
XBRL Taxonomy Extension Definition Linkbase Document
**101.LAB
XBRL Taxonomy Extension Label Linkbase Document
**101.PRE
XBRL Taxonomy Extension Presentation Linkbase Document
 
*
Filed herewith
**
Submitted electronically herewith. Pursuant to Rule 406T of Regulation S-T, the interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement of prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not files for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended and otherwise are not subject to liability under those sections.

58
Table of Contents

SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
Date: August 14, 2013
 
 
 
AMERICAN MIDSTREAM PARTNERS, LP
 
 
By:
American Midstream GP, LLC, its general partner
 
 
By:
/s/ Stephen W. Bergstrom
Name:
Stephen W. Bergstrom
Title:
President and Chief Executive Officer
 
(principal executive officer)
 
 
By:
/s/ Daniel C. Campbell
Name:
Daniel C. Campbell
Title:
Senior Vice President & Chief Financial Officer
 
(principal financial officer)

59
Table of Contents

EXHIBIT INDEX
 
Exhibit
Number
Exhibit
3.1
Certificate of Limited Partnership of American Midstream Partners, LP (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 (Commission File No. 333-173191) filed on March 31, 2011).
3.2
Second Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on August 4, 2011).
3.3
Certificate of Formation of American Midstream GP, LLC (incorporated by reference to Exhibit 3.4 to the Registration Statement on Form S-1 (Commission File No. 333-173191) filed on March 31, 2011).
3.4
Amended and Restated Limited Liability Company Agreement of American Midstream GP, LLC (incorporated by reference to Exhibit 3.5 to the Registration Statement on Form S-1 (Commission File No. 333-173191) filed on March 31, 2011).
3.5
First Amendment to Amended and Restated Limited Liability Company Agreement of American Midstream GP, LLC (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on August 4, 2011).
10.1
Second Waiver to Credit Agreement, dated as of January 24, 2013 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on January 29, 2013).
10.2
Third Waiver to Credit Agreement, dated as of March 29, 2013 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on April 1, 2013).
31.1*
Certification of Brian F. Bierbach, President and Chief Executive Officer of American Midstream GP, LLC, the general partner of American Midstream Partners, LP, for the March 31, 2013 Quarterly Report on Form 10-Q, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*
Certification of Daniel C. Campbell, Senior Vice President & Chief Financial Officer of American Midstream GP, LLC, the general partner of American Midstream Partners, LP, for the March 31, 2013 Quarterly Report on Form 10-Q, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*
Certification of Brian F. Bierbach, President and Chief Executive Officer of American Midstream GP, LLC, the general partner of American Midstream Partners, LP, for the March 31, 2013 Quarterly Report on Form 10-Q, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*
Certification of Daniel C. Campbell, Senior Vice President & Chief Financial Officer of American Midstream GP, LLC, the general partner of American Midstream Partners, LP, for the March 31, 2013 Quarterly Report on Form 10-Q, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
**101.INS
XBRL Instance Document
**101.SCH
XBRL Taxonomy Extension Schema Document
**101.CAL
XBRL Taxonomy Extension Calculation Linkbase Document
**101.DEF
XBRL Taxonomy Extension Definition Linkbase Document
**101.LAB
XBRL Taxonomy Extension Label Linkbase Document
**101.PRE
XBRL Taxonomy Extension Presentation Linkbase Document

*
Filed herewith
**
Submitted electronically herewith. Pursuant to Rule 406T of Regulation S-T, the interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement of prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not files for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended and otherwise are not subject to liability under those sections.


60