AMID 2012.09.30 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 September 30, 2012
or
c   
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
x (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 4,623,436 common units and 4,526,066 subordinated units of American Midstream Partners, LP outstanding as of November 12, 2012. 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.


Table of Contents

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).
GAAP
General Accepted Accounting Principles: Accounting principles generally accepted in the United States of America.
EBITDA
Net income (loss) before net interest expense, income taxes, and depreciation and amortization. EBITDA is considered to be a non-GAAP measurement.
FERC
Federal Energy Regulatory Commission.
Bbl
Barrels: 42 U.S. gallons measured at 60 degrees Fahrenheit.
MBbl
One thousand barrels.
MMBbl
One million barrels.
Btu
British thermal unit; the approximate amount of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
MMBtu
One million British thermal units.
Mcf
One thousand cubic feet.
Gal
Gallons.
/d
Per day.
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.
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.
Fractionation

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

4

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PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
American Midstream Partners, LP and Subsidiaries
Condensed Consolidated Balance Sheets
(Unaudited)
 
 
September 30,
2012
 
December 31, 2011
 
(in thousands)
Assets
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
497

 
$
871

Accounts receivable
1,776

 
1,218

Unbilled revenue
17,603

 
19,745

Risk management assets
1,347

 
456

Other current assets
2,924

 
3,323

Total current assets
24,147

 
25,613

Property, plant and equipment, net
217,552

 
170,231

Risk management assets - long term
207

 

Other assets, net
4,520

 
3,707

Total assets
$
246,426

 
$
199,551

Liabilities and Partners’ Capital
 
 
 
Current liabilities
 
 
 
Accounts payable
$
3,040

 
$
837

Accrued gas purchases
12,912

 
14,715

Risk management liabilities

 
635

Accrued expenses and other current liabilities
5,207

 
7,086

Total current liabilities
21,159

 
23,273

Other liabilities
8,884

 
8,612

Long-term debt
118,650

 
66,270

Total liabilities
148,693

 
98,155

Commitments and contingencies (see Note 12)


 


Partners’ capital
 
 
 
General partner interest (185 and 185 thousand units issued and outstanding as of September 30, 2012 and December 31, 2011, respectively)
1,669

 
1,091

Limited partner interest (9,108 and 9,087 thousand units issued and outstanding as of September 30, 2012 and December 31, 2011, respectively)
88,202

 
99,890

Accumulated other comprehensive income
455

 
415

Total partners’ capital
90,326

 
101,396

Total liabilities and partners’ capital
$
239,019

 
$
199,551

Noncontrolling interests
7,407

 

Total liabilities, partners’ capital and noncontrolling interest
$
246,426

 
$
199,551

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

5

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American Midstream Partners, LP and Subsidiaries
Condensed Consolidated Statements of Operations
(Unaudited)
 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2012
 
2011
 
2012
 
2011
 
(in thousands, except for per unit amounts)
Revenue
$
58,086

 
$
57,005

 
$
148,363

 
$
190,374

Realized gain (loss) on early termination of commodity derivatives

 

 

 
(2,998
)
Unrealized gain (loss) on commodity derivatives
(1,762
)
 
953

 
1,732

 
(19
)
Total revenue
56,324

 
57,958

 
150,095

 
187,357

Operating expenses:
 
 
 
 
 
 
 
Purchases of natural gas, NGLs and condensate
43,900

 
47,359

 
107,348

 
157,725

Direct operating expenses
5,264

 
3,385

 
12,031

 
9,548

Selling, general and administrative expenses
3,679

 
2,497

 
10,676

 
7,649

Advisory services agreement termination fee

 
2,500

 

 
2,500

Equity compensation expense
474

 
331

 
1,272

 
2,989

Depreciation and accretion expense
5,536

 
5,261

 
15,819

 
15,468

(Gain) loss on sale of assets, net
(4
)
 
(586
)
 
(126
)
 
(586
)
Total operating expenses
58,849

 
60,747

 
147,020

 
195,293

Operating income (loss)
(2,525
)
 
(2,789
)
 
3,075

 
(7,936
)
Other income (expenses):
 
 
 
 
 
 
 
Interest expense
(1,501
)
 
(1,378
)
 
(3,083
)
 
(3,923
)
Net income (loss)
$
(4,026
)
 
$
(4,167
)
 
$
(8
)
 
$
(11,859
)
Net income (loss) attributable to noncontrolling interests
$
249

 
$

 
$
249

 
$

Net income (loss) attributable to the Partnership
$
(4,275
)
 
$
(4,167
)
 
$
(257
)
 
$
(11,859
)
General partners' interest in net income (loss)
$
(85
)
 
$
(83
)
 
$
(5
)
 
$
(237
)
Limited partners’ interest in net income (loss)
$
(4,190
)
 
$
(4,084
)
 
$
(252
)
 
$
(11,622
)
Limited partners’ net income (loss) per unit (basic and diluted) (See Note 9)
$
(0.46
)
 
(0.53
)
 
(0.03
)
 
(1.85
)
Weighted average number of units used in computation of limited partners’ net income (loss) per unit (basic and diluted)
9,108

 
7,774

 
9,103

 
6,296

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

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American Midstream Partners, LP and Subsidiaries
Condensed Consolidated Statements of Comprehensive Income
(Unaudited)
 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2012
 
2011
 
2012
 
2011
 
(in thousands)
Net income (loss)
$
(4,275
)
 
$
(4,167
)
 
$
(257
)
 
$
(11,859
)
Unrealized gain (loss) on post retirement benefit plan assets and liabilities
23

 
83

 
40

 
83

Comprehensive income (loss)
$
(4,252
)
 
$
(4,084
)
 
$
(217
)
 
$
(11,776
)
Less: Comprehensive income (loss) attributable to noncontrolling interests
$
249

 
$

 
$
249

 
$

Comprehensive income attributable to Partnership
$
(4,501
)
 
$
(4,084
)
 
$
(466
)
 
$
(11,776
)
The accompanying notes are an integral part of these condensed consolidated financial statements.

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American Midstream Partners, LP and Subsidiaries
Condensed Consolidated Statements of Changes in Partners’ Capital
and Noncontrolling Interest
(Unaudited)
 
 
Limited
Partner
Common
Units
Limited
Partner
Subordinated
Units
Limited
Partner
Interest
General
Partner
Units
General
Partner
Interest
Accumulated
Other
Comprehensive
Income
Total Partners' Capital
Noncontrolling Interest
 
(in thousands)
Balances at December 31, 2010
5,363


$
83,624

109

$
2,124

$
56

$
85,804


Net income (loss)


(11,622
)

(237
)

(11,859
)

Recapitalization
(4,602
)
4,526


76





Issuance of common units to public, net of offering costs
3,750


69,085




69,085


Unitholder distributions


(40,247
)

(814
)

(41,061
)

LTIP vesting
15


318


(318
)



Unit based compensation


218


1,016


1,234


Adjustments to other post retirement plan assets and liabilities





83

83


Balances at September 30, 2011
4,526

4,526

$
101,376

185

$
1,771

$
139

$
103,286


Balances at December 31, 2011
4,561

4,526

$
99,890

185

$
1,091

$
415

$
101,396


Acquisition of noncontrolling interests







7,407

Net income (loss)


(252
)

(5
)

(257
)
249

Unitholder contributions




13


13


Unitholder distributions


(11,809
)

(241
)

(12,050
)

Net distributions to noncontrolling interest owners







(249
)
LTIP vesting
20


364


(364
)



Tax netting repurchase
(4
)

(88
)



(88
)

Unit based compensation
5


97


1,175


1,272


Adjustments to other post retirement plan assets and liabilities





40

40


Balances at September 30, 2012
4,582

4,526

$
88,202

185

$
1,669

$
455

$
90,326

$
7,407

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

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American Midstream Partners, LP and Subsidiaries
Condensed Consolidated Statements of Cash Flows
(Unaudited)
 
Nine Months Ended
 
September 30,
 
2012
 
2011
 
(in thousands)
Cash flows from operating activities
 
 
 
Net income (loss)
$
(8
)
 
$
(11,859
)
Adjustments to reconcile net income (loss) to net cash provided (used) in operating activities:
 
 
 
Depreciation and accretion expense
15,819

 
15,468

Amortization of deferred financing costs
493

 
1,121

Unrealized (gain) loss on derivative contracts
(1,733
)
 
19

Unit based compensation
1,272

 
1,234

OPEB plan net periodic (benefit) cost
(61
)
 

(Gain) loss on sale of assets
(126
)
 
(586
)
Changes in operating assets and liabilities, net of effects of assets acquired and liabilities assumed:
 
 
 
Accounts receivable
(558
)
 
(536
)
Unbilled revenue
6,677

 
4,108

Risk management assets

 
(670
)
Other current assets
1,285

 
(173
)
Other assets, net
(65
)
 
33

Accounts payable
1,396

 
(108
)
Accrued gas purchases
(5,833
)
 
(3,397
)
Accrued expenses and other current liabilities
(1,879
)
 
2,717

Other liabilities
(203
)
 
(272
)
Net cash provided (used) in operating activities
16,476

 
7,099

Cash flows from investing activities
 
 
 
Cost of acquisition, net of cash acquired
(51,377
)
 

Additions to property, plant and equipment
(4,465
)
 
(4,890
)
Proceeds from disposals of property, plant and equipment
126

 
125

Net cash provided (used) in investing activities
(55,716
)
 
(4,765
)
Cash flows from financing activities
 
 
 
Unit holder contributions
13

 

Unit holder distributions
(12,050
)
 
(41,061
)
Net distributions to noncontrolling interest owners
(249
)
 

Proceeds upon issuance of common units to public, net of offering costs

 
69,085

LTIP tax netting unit repurchase
(88
)
 

Payments on other loan

 
(615
)
Deferred debt issuance costs
(1,140
)
 
(2,256
)
Payments on long-term debt
(42,310
)
 
(103,870
)
Borrowings on long-term debt
94,690

 
76,850

Net cash provided (used) in financing activities
38,866

 
(1,867
)
Net increase (decrease) in cash and cash equivalents
(374
)
 
467

Cash and cash equivalents
 
 
 
Beginning of period
871

 
63

End of period
$
497

 
$
530

Supplemental cash flow information
 
 
 
Interest payments
$
1,894

 
$
3,201

Supplemental non-cash information
 
 
 
Increase (decrease) in accrued property, plant and equipment
$
808

 
$
353

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

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American Midstream Partners, LP and Subsidiaries
Notes to Condensed Consolidated Financial Statements
(Unaudited)
1. Organization and Basis of Presentation
Nature of Business
American Midstream Partners, LP (the “Partnership”) was formed on August 20, 2009 as a Delaware limited partnership for the purpose of acquiring and operating certain natural gas pipeline and processing businesses. We provide natural gas gathering, treating, processing, marketing, and transportation services 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.
We are controlled by our general partner, American Midstream GP, LLC, which is a wholly owned subsidiary of AIM Midstream Holdings, LLC.
Our assets are primarily located in Alabama, Louisiana, Mississippi, Tennessee, and Texas. We organize our operations into two business segments: (1) Gathering and Processing; and (2)Transmission.
Our Gathering and Processing segment is an integrated midstream natural gas system that provides gathering, compression, treating, processing, fractionation, transportation, and sales of natural gas, NGLs and condensate. Our Gathering and Processing segment includes the following systems:
The Gloria gathering system provides gathering and compression services through our assets, as well as processing services through processing arrangements. The Gloria system is a Section 311 intrastate pipeline located in Lafourche, Jefferson, Plaquemines, St. Charles and St. Bernard parishes of Louisiana consisting of approximately 110 miles of pipeline with diameters ranging from 3 to 16 inches and 3 compressors with a combined size of 1,877 horsepower.
The Lafitte gathering system is a Section 311 intrastate pipeline consisting of approximately 40 miles of gathering pipeline, with diameters ranging from 4 to 12 inches. The Lafitte system originates onshore in southern Louisiana and terminates in Plaquemines Parish, Louisiana at the Alliance Refinery owned by ConocoPhillips Corporation and is connected to our Gloria gathering system.
The Bazor Ridge gathering and processing system consists of approximately 160 miles of pipeline with diameters ranging from 3 to 8 inches and 3 compressor stations with a combined compression capacity of 1,069 horsepower. Our Bazor Ridge system is located in Jasper, Clarke, Wayne and Greene Counties of Mississippi.
The Quivira gathering system consists of approximately 34 miles of pipeline, with a 12- inch diameter mainline and several laterals ranging in diameter from 6 to 8 inches. The system originates offshore of Iberia and St. Mary Parishes of Louisiana in Eugene Island Block 24 and terminates onshore at a connection with the Burns Point Plant.
The Burns Point Plant is located in St. Mary Parish, Louisiana, where raw natural gas is processed through a cryogenic processing plant that is jointly owned by us and the operator, Enterprise.
The Chatom gathering, processing and fractionation plant 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, to which we have an 87.4% undivided interest.
The Offshore Texas system consists of the GIGS and Brazos systems, two parallel gathering systems that share common geography and operating characteristics. The Offshore Texas system provides gathering and dehydration services to natural gas producers in the shallow waters of the Gulf of Mexico region. The Offshore Texas system consists of approximately 56 miles of pipeline with diameters ranging from 6 to 16 inches.
The Alabama Processing system consists of 2 small skid-mounted treating and processing plants that we refer to, individually, as Atmore and Wildfork. These treating and processing plants are located in Escambia and Monroe Counties of Alabama.
The Magnolia gathering system is a Section 311 intrastate pipeline that gathers coal bed methane in Tuscaloosa, Greene, Bibb, Chilton and Hale counties of Alabama and delivers this natural gas to an interconnect with the Transco Pipeline system, an interstate pipeline owned by The Williams Companies, Inc. The Magnolia system consists of approximately 116 miles of pipeline with small-diameter gathering lines and trunk lines ranging from 6 to 24 inches in diameter and 1 compressor station with 3,328 horsepower.
Our other gathering and processing systems include the Fayette and Heidelberg gathering systems, located in

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Fayette County, Alabama and Jasper County, Mississippi, respectively.

Our Transmission segment includes intrastate and interstate pipelines that transport natural gas through Alabama, Louisiana, Mississippi and Tennessee as follows:
Our Bamagas system is a Hinshaw intrastate natural gas pipeline that travels west to east from an interconnection point with TGP in Colbert County, Alabama to 2 power plants owned by Calpine Corporation, in Morgan County, Alabama. The Bamagas system consists of 52 miles of high pressure, 30 inch pipeline.
The MLGT system is an intrastate transmission system that sources natural gas from interconnects with the FGT Pipeline system, the Tetco Pipeline system, the Transco Pipeline system and our Midla system to a Baton Rouge, Louisiana refinery owned and operated by ExxonMobil and 7 other industrial customers. Our MLGT system is comprised of approximately 54 miles of pipeline with diameters ranging from 3 to 14 inches.
Our other intrastate transmission systems include the Chalmette system, located in St. Bernard Parish, Louisiana, and the Trigas system, located in 3 counties in northwestern Alabama.
We also own a number of miscellaneous interconnects and small laterals that are collectively referred to as the SIGCO assets.
Our Midla system is a FERC regulated system that includes approximately 370 miles of interstate pipeline that runs from the Monroe gas field in northern Louisiana south through Mississippi to Baton Rouge, Louisiana.
Our AlaTenn system is a FERC regulated system that includes approximately 295 miles of interstate pipeline that runs through the Tennessee River Valley from Selmer, Tennessee to Huntsville, Alabama and serves an 8 county area in Alabama, Mississippi and Tennessee.
Initial Public Offering
On July 26, 2011, we commenced the initial public offering of our common units pursuant to our Registration Statement on Form S-1, Commission File No. 333-173191 (the “Registration Statement”), which was declared effective by the SEC on July 26, 2011. Citigroup Global Markets Inc. and Merrill Lynch, Pierce, Fenner, & Smith Incorporated acted as representatives of the underwriters and as joint book-running managers of the offering.
Upon closing of our IPO on August 1, 2011, we issued 3,750,000 common units pursuant to the Registration Statement at a price per unit of $21.00. The Registration Statement registered the offer and sale of securities with a maximum aggregate offering price of $90,562,500. The aggregate offering amount of the securities sold pursuant to the Registration Statement was $78,750,000.
After deducting underwriting discounts and commissions of $4.9 million paid to the underwriters, offering expenses of $4.2 million and a structuring fee of $0.6 million, the net proceeds from our IPO were $69.1 million. We used all of the net offering proceeds from our IPO for the uses described in the final prospectus filed with the SEC pursuant to Rule 424(b) on July 27, 2011.
On July 29, 2011, in connection with the closing of our initial public offering, our general partner contributed 76,019 of our common units to us in exchange for 76,019 general partner units in order to maintain its 2.0% general partnership interest in us. This transaction was exempt from registration pursuant to Section 4(2) of the Securities Act of 1933, as amended.
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. 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 September 30, 2012, and December 31, 2011, condensed consolidated statement of operations for the three and nine months ended September 30, 2012 and 2011, statement of changes in partners’ capital and noncontrolling interest for the nine months ended September 30, 2012 and 2011, and statements of cash flows for the nine months ended September 30, 2012 and 2011.
Our financial results for the three and nine months ended September 30, 2012 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2012. 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, 2011 (“Annual Report”) filed on March 19, 2012.

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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 a 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.
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.
Accounting for Regulated Operations
Certain of our natural gas pipelines are subject to regulations by the FERC. The FERC exercises statutory authority over matters such as construction, transportation rates we charge and our underlying accounting practices and ratemaking agreements with customers. Accordingly, we record costs that are allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by a non-regulated entity. Also, we record assets and liabilities that result from the regulated ratemaking process that would be recorded under GAAP for our regulated entities. As of September 30, 2012 and December 31, 2011, we had no such material regulatory assets or liabilities.
2. Summary of Significant Accounting Policies

Revenue Recognition and the Estimation of Revenues
We recognize revenue when all of the following criteria are met: (1) persuasive evidence of an exchange arrangement exists, (2) delivery has occurred or services have been rendered, (3) the price is fixed or determinable and (4) collectability is reasonably assured. We record revenue and cost of product sold on a gross basis for those transactions where we act as the principal and take title to natural gas, NGLs or condensates that are purchased for resale. When our customers pay us a fee for providing a service such as gathering, treating or transportation, we record those fees separately in revenues. For the three and nine months ended September 30, 2012 and 2011, respectively, we recognized the following revenues by category:
 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2012
 
2011
 
2012
 
2011
 
(in thousands)
Transportation - firm
$
2,230

 
$
2,077

 
$
7,703

 
$
7,572

Transportation - interruptible
798

 
888

 
2,838

 
2,671

Sales of natural gas, NGLs and condensate
53,771

 
53,833

 
134,153

 
179,545

Other
1,287

 
207

 
3,669

 
586

Revenue
$
58,086

 
$
57,005

 
$
148,363

 
$
190,374

Limited Partners’ Net Income (Loss) Per Common Unit
We compute limited partners’ net income (loss) per common unit by dividing our limited partners’ interest in net income (loss) by the weighted average number of common units outstanding during the period. The overall computation, presentation and disclosure requirements for our limited partners’ net income (loss) per common unit are made in accordance with the “Earnings per Share” Topic of the Codification as described in the Annual Report. All per unit computations give effect to the retroactive application of the reverse unit split as described in Note 9, “Partners’ Capital”.


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Noncontrolling Interest

Noncontrolling interest represents the noncontrolling interest holders' proportionate share of the equity of the Chatom Assets.  Noncontrolling interest is adjusted for the noncontrolling interest holders' proportionate share of the earnings or losses.  Management reports noncontrolling interest in the Chatom Assets in the financial statements pursuant to paragraph ASU No. 810-10-65-1.  The 12.6% noncontrolling interest is held by other non-affiliated working interest owners.
Recent Accounting Pronouncements
In December 2011, the FASB issued ASU No. 2011-11 Disclosures about Offsetting Assets and Liabilities. The ASU requires additional disclosures about the impact of offsetting, or netting, on a company’s financial position, and is effective for annual periods beginning on or after January 1, 2013 and interim periods within those annual periods, and retrospectively for all comparative periods presented. Under GAAP, derivative assets and liabilities can be offset under certain conditions. The ASU requires disclosures showing both gross information and net information about instruments eligible for offset in the balance sheet. Except for additional disclosures related to our offsetting arrangements, the adoption of the amended guidance is not expected to have a material effect on the Partnership's consolidated financial statements.
3. Acquisitions
Burns Point Plant Interest
On December 1, 2011, we acquired a 50% undivided interest (“Interest”) in the Burns Point Plant (“Plant”) from Marathon Oil Company (“Seller”) for total cash consideration of $35.5 million. No liabilities of the Seller were assumed. The purchase was effective November 1, 2011 (“Effective Date”) with our assumption of insurable risks, operating liabilities and entitlement to in-kind revenues as of that date. The remaining 50% undivided interest is owned by the Plant operator, Enterprise Gas Processing, LLC (“Operator”). The Plant, which is an unincorporated joint venture, is governed by a construction and operating agreement (“Agreement”).
The Plant is located in St. Mary Parish, Louisiana, and processes raw natural gas using a cryogenic expander. The Plant inlet volumes are sourced from offshore natural gas production via our Quivira system, Gulf South pipelines and onshore from individual producers near the plant. The Quivira system currently supplies approximately 88% of the inlet volume to the Plant. The residue gas is transported, via pipeline to Gulf South and Tennessee Gas Pipeline and the Y-grade liquid is transported via pipeline to K/D/S Promix, LLC (“Promix”), an Enterprise-operated fractionator. The current capacity of the plant is 165.0 MMcf/d. The acquisition complemented our existing assets given it is the majority of the inlet volume to the Quivira system and is included in our Gathering and Processing segment.
The Plant is not a legal entity but rather an asset that is jointly owned by the Operator and us. We acquired an interest in the asset group and do not hold an interest in a legal entity. Each of the owners in the asset group is proportionately liable for the liabilities. Outside of the rights and responsibilities of the Operator, we and the Operator have equal rights and obligations to the assets. Significant non-capital and maintenance capital expenditures, plant expansions and significant plant dispositions require the approval of both owners.
Under the terms of the Agreement, the Operator is required to provide monthly production allocation and expense statements to us and is not required to prepare and provide to us balance sheet information or stand-alone financial statements. Historically, balance sheet and stand-alone financial statements for the Plant have not been prepared and are, therefore, not available.
We reviewed the governance structure of the Plant and applied the concepts discussed in ASC-810-10-45 (“Other Presentation Matters.”) We determined that while the facility is an unincorporated joint venture, the asset group is jointly controlled with the Operator.
We reviewed the requirements for the application of the equity method of accounting, given the joint control attribute of the Plant, and because the necessary complete Plant financial statements are not, nor expected to be, available from the Operator, we have elected to account for our Interest using the proportionate consolidation method. Our Interest in the Plant is recorded in property, plant and equipment, net on the consolidated balance sheet and will be depreciated over 40 years. Under this method, we include in our consolidated statement of operations the value of our Plant revenues taken in-kind and the Plant expenses reimbursed to the Operator.
Chatom Gathering, Processing and Fractionation Plant
Effective July 1, 2012, we acquired an 87.4% undivided interest in the Chatom processing and fractionation plant and associated gathering infrastructure (“Chatom Assets”) from affiliates of Quantum Resources Management, LLC. The acquisition fair value of consideration of $51.4 million includes a credit associated with the cash flow the Chatom Assets

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generated between January 1, 2012, and the effective date of July 1, 2012.  The consideration paid by the Partnership consisted of cash, which was funded under borrowings under our revolving credit facility.

The Chatom Assets are 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, a160 long-ton per day sulfur recovery unit, and a 29 mile gas gathering system. We believe the Chatom Assets will be accretive to the Partnership's distributable cash flow per unit.

Our 87.4% undivided interest in the Chatom Assets contributed $13.1 million of revenue and $1.7 million of net income attributable to the partnership, which are included in the condensed consolidated statement of operations for the three and nine months ended September 30, 2012, respectively.

The following table presents unaudited pro forma consolidated information of the Partnership, adjusted for the acquisition of the Chatom Assets, as if the acquisition had occurred on January 1, 2011:
 
Nine months ended
 
September 30, 2012
 
(unaudited, in thousands)
Revenue
$
185,851

Net income
$
1,926


These amounts have been calculated after applying the Partnership's accounting policies and adjusting the results to reflect i) additional depreciation and amortization that would have been charged assuming fair value adjustments to property, plant and equipment, and ii) recording pro forma interest expense on debt that would have been incurred to acquire the Chatom Assets as of January 1, 2012.

The following table presents unaudited pro forma consolidated information of the Partnership, adjusted for the acquisition of the Chatom Assets, as if the acquisition had occurred on January 1, 2011:
 
 
Three months ended
 
Nine months ended
 
 
September 30, 2011
 
September 30, 2011
 
 
(unaudited, in thousands)
Revenue
 
$
68,721

 
$
221,579

Net loss
 
$
(4,580
)
 
$
(11,543
)

These amounts have been calculated after applying the Partnership's accounting policies and adjusting the results to reflect i) additional depreciation and amortization that would have been charged assuming fair value adjustments to property, plant and equipment, and ii) recording pro forma interest expense on debt that would have been incurred to acquire the Chatom Assets as of January 1, 2011.

The following table presents the fair value of consideration transferred to acquire the Chatom Assets 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 Assets at the acquisition date:

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(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. This fair value measurements are based on significant inputs not observable in the market and thus represents a Level 3 measurement as defined by ASC 820. Primarily using the income approach, the fair value 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, iv) a Federal tax rate of 35% and a state tax rate of 6.5%, and v) an increase in processed and fractionated volumes in 2013, declining thereafter. Working capital was estimated using net realizable value. Accrued revenue is deemed to be fully collectible at July 1, 2012.
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 and NGL 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 nine months ended September 30, 2012 and period ended December 31, 2011, no allowances on or write-offs of accounts receivable were recorded.
ConocoPhillips Corporation, Shell Trading (US) Company, Enbridge Marketing (US) L.P., and ExxonMobil Corporation were significant customers, representing at least 10% of our consolidated revenue, accounting for $13.3 million, $9.9 million, $6.9 million, and $6.5 million, respectively, of our consolidated revenue in the consolidated statement of operations in the three months ended September 30, 2012. ConocoPhillips Corporation, Enbridge Marketing (US) L.P., and ExxonMobil Corporation were significant customers, representing at least 10% of our consolidated revenue, accounting for $24.3 million, $10.5 million, and $10.1 million, respectively, of our consolidated revenue in the consolidated statement of operations in the three months ended September 30, 2011.
ConocoPhillips Corporation, Enbridge Marketing (US) L.P., and ExxonMobil Corporation were significant customers, representing at least 10% of our consolidated revenue, accounting for $42.7 million, $23.9 million, and $18.3 million, respectively, for nine months ended September 30, 2012 and $78.6 million, $33.4 million, and $29.8 million, respectively, for the nine months ended September 30, 2011.
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

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directors of our general partner. During the nine months ended September 30, 2012 and 2011, we entered into various commodity swap, option, and collar arrangements.
In June 2011, the Board of Directors of our general partner determined that we would gain operational and strategic flexibility from canceling our then-existing NGL swap contracts and entering into new NGL swap contracts with an existing counterparty that extend through the end of 2012.
We enter into commodity contracts with multiple counterparties. We may be required to post collateral with our counterparties in connection with our derivative positions. As of September 30, 2012, we have not posted collateral with our counterparties. The counterparties are not required to post collateral with us in connection with their derivative positions. Netting agreements are in place with our counterparties that permit us to offset our commodity derivative asset and liability positions.
As of September 30, 2012, the aggregate notional volume of our commodity derivatives was 11.4 million gallons.
As of September 30, 2012 and December 31, 2011, the fair value associated with our derivative instruments were recorded in our financial statements, under the caption Risk management assets and Risk management liabilities, as follows:
 
 
September 30,
2012
 
December 31, 2011
 
(in thousands)
Risk management assets:
 
 
 
Commodity derivatives
$
1,347

 
$
456

Risk management assets - long term:
 
 
 
Commodity derivatives
$
207

 
$

Risk management liabilities:
 
 
 
Commodity derivatives
$

 
$
635

Risk management liabilities - long term:
 
 
 
Commodity derivatives
$

 
$

We recorded the following unrealized mark-to-market gains (losses) in the condensed consolidated statement of operations:
 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2012
 
2011
 
2012
 
2011
 
(in thousands)
Commodity derivatives
$
(1,762
)
 
$
953

 
$
1,732

 
$
(19
)

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:
Level 1 – 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 and volatility curves, as well as other relevant economic measures. To extrapolate a forecast of future cash flows, discount

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factors are utilized. The inputs are obtained from independent pricing services, and we have made no adjustments to the obtained prices.
We have consistently applied these valuation techniques in all periods presented and believe we have obtained the most accurate information available for the types of derivatives contracts held. We will recognize transfers between levels at the end of the reporting period for which the transfer has occurred, there were no such transfers for nine months ended September 30, 2012 or period ended December 31, 2011.
Quantitative Information about Level 3 Fair Value Measurements
 

 
Fair Value at
 
 
 
 
 
 
 
 
 
September 30,
2012
 
Valuation
Technique
 
Unobservable Input
 
Range
 
(in thousands)
 
 
 
 
 
 
 
 
Commodity derivative asset (liability), net
$
1,553

 
Forecasted
future cash
flow
 
Forward commodity prices
 
$0.965
to
$1.220
 
Volatility curves
 
20.0%
to
34.8%
 
Discount factors
 
0.973
to
1.070
The significant unobservable inputs used in the fair value measurement of the commodity derivative asset (liability) are forward commodity prices and volatility curves. Significant increases or decreases in the inputs in isolation would result in a significantly lower or higher fair value measurement.
Fair Value of Financial Instruments
The following table sets forth by level within the fair value hierarchy, our net derivative assets (liabilities) that were measured at fair value on a recurring basis as of September 30, 2012 and December 31, 2011:
 
 
Carrying
Amount
 
Estimated Fair Value
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
 
(in thousands)
 
 
Commodity derivative asset (liability), net
 
 
 
 
 
 
 
 
 
September 30, 2012
$
1,553

 
$

 
$

 
$
1,553

 
$
1,553

December 31, 2011
$
(179
)
 
$

 
$

 
$
(179
)
 
$
(179
)
Changes in Level 3 Fair Value Measurements
The table below includes a roll forward of the balance sheet amounts (including the change in fair value) for financial instruments classified by us within Level 3 of the valuation hierarchy. When a determination is made to classify a financial instrument within Level 3 of the valuation hierarchy, the determination is based upon the significance of the unobservable factors to the overall fair value measurement. Level 3 financial instruments typically include, in addition to the unobservable or Level 3 components, observable components (that is, components that are actively quoted and can be validated to external sources). Contracts classified as Level 3 are valued using price inputs available from public markets to the extent that the markets are liquid or the relevant settlement periods:
 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2012
 
2011
 
2012
 
2011
 
(in thousands)
Fair value asset (liability), beginning of period
$
3,315

 
$
(302
)
 
$
(179
)
 
$

Realized gain (loss) on early termination of commodity derivatives

 

 

 
(2,998
)
Unrealized gain (loss) on commodity derivatives
(1,762
)
 
953

 
1,732

 
(19
)
Purchases

 

 

 
670

Settlements

 

 

 
2,998

Fair value asset (liability), end of period
$
1,553

 
$
651

 
$
1,553

 
$
651


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Also included in revenue were $1.0 million and $(0.4) million in realized gains (losses) for the three months ended September 30, 2012 and 2011, respectively, and $1.6 million and $(1.3) million in realized gains (losses) for the nine months ended September 30, 2012 and 2011, respectively, representing our monthly swap settlements.
7. Property, Plant and Equipment
Property, plant and equipment, net, as of September 30, 2012 and December 31, 2011 were as follows:
 
 
Useful Life
 
September 30,
2012
 
December 31, 2011
 
(in years)
 
(in thousands)
Land
 
 
$
2,254

 
$
41

Construction in progress
 
 
3,347

 
3,380

Buildings and improvements
4 to 40
 
1,439

 
1,490

Processing and treating plants
8 to 40
 
97,816

 
49,396

Pipelines
5 to 40
 
157,042

 
146,788

Compressors
4 to 20
 
8,681

 
7,437

Equipment
8 to 20
 
2,078

 
1,198

Computer software
5
 
1,691

 
1,500

Total property, plant and equipment
 
 
274,348

 
211,230

Accumulated depreciation
 
 
(56,796
)
 
(40,999
)
Property, plant and equipment, net
 
 
$
217,552

 
$
170,231

Of the gross property, plant and equipment balances at September 30, 2012 and December 31, 2011, $24.8 million and $24.0 million were related to AlaTenn and Midla, our FERC regulated interstate assets.
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.
During the nine months ended September 30, 2012 and year ended December 31, 2011, we recognized $0.5 million and $0.9 million of AROs included in other liabilities for specific assets that we intend to retire for operational purposes.
We recorded accretion expense, which is included in depreciation expense, of less than $0.1 million and $0.3 million in our consolidated statements of operations for the three months ended September 30, 2012 and 2011, respectively, and less than $0.1 million and $1.0 million in our consolidated statements of operations for the nine months ended September 30, 2012 and 2011, respectively, related to these AROs.
8. Long-Term Debt
On June 27, 2012, we amended our 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. The credit facility also provides for a $50 million dollar accordion feature. If the accordion feature were to be fully exercised, the total commitment under the existing facility would be $250 million.
The credit facility provides for a maximum borrowing equal to the lesser of (i) $200 million or (ii) 4.50 times adjusted consolidated EBITDA. We may elect to have loans under the 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”, and (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 pay a commitment fee of 0.50% per annum on the undrawn portion of the revolving loan. For the nine months ended September 30, 2012 and 2011, the weighted average interest rate on borrowings under our credit facility was approximately 4.09% and 7.37%, respectively.

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Our obligations under the credit facility are secured by a first mortgage in favor of the lenders in our real property. Advances made under the credit 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 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 credit facility also contains customary representations and warranties (including those relating to organization and authorization, compliance with laws, absence of defaults, material agreements and litigation) and customary events of default (including those relating to monetary defaults, covenant defaults, cross defaults and bankruptcy events). The primary financial covenants contained in the credit facility are (i) a total leverage ratio test (not to exceed 4.50 times) and a minimum interest coverage ratio test (not less than 2.50 times). We were in compliance with all of the covenants under our credit facility as of September 30, 2012.
As of September 30, 2012, the total leverage ratio test, one of the primary financial covenants that we are required to maintain under our credit facility, was 4.31. Our ability to comply with these covenants and ratios in the future will be affected by the levels of debt and of cash flow from our operations, among other factors.

In order to remain in compliance with our financial covenants and ratios under our credit facility, we believe that we have several options available to us that we may pursue separately or in combination. First, subject to market conditions, we have the ability to issue debt or equity securities to refinance or pay down outstanding borrowings under our credit facility and to fund future growth capital expenditures. Second, we may request a waiver from the lenders in our credit facility. Third, we may seek to reduce our debt by amounts that exceed our operating cash flows through actions such as a reduction in capital expenditures; suspension of our quarterly distributions to subordinated unitholders and, thereafter, unitholders; the sale of assets; further reduction of operating and administrative costs; or other steps to enhance liquidity and reduce debt and avoid default.

If we were not in compliance with the financial covenants in the credit facility, or if we did not enter into an agreement to refinance or extend the due date on the credit facility, our debt could become due and payable upon acceleration by the lenders in our banking group. In addition, failure to comply with any of the covenants under our credit facility could adversely affect our ability to fund ongoing operations and growth capital requirements as well as our ability to pay distributions to our unitholders.
Our outstanding borrowings under the credit facility at September 30, 2012 and December 31, 2011, respectively, were:
 
 
September 30,
2012
 
December 31, 2011
 
(in thousands)
Revolving loan facility
$
118,650

 
$
66,270

At September 30, 2012 and December 31, 2011, letters of credit outstanding under the credit facility were $0.6 million.
In connection with our credit facility and amendments thereto, we incurred $3.6 million in debt issuance costs that are being amortized on a straight-line basis over the term of the credit facility.
9. Partners’ Capital
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, as discussed below, 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 nonvoting limited partner interests held by our general partner.
On August 1, 2011, we closed our IPO of 3,750,000 common units at an offering price of $21.00 per unit. After deducting underwriting discounts and commissions of $4.9 million paid to the underwriters, estimated offering expenses of $4.2 million and a structuring fee of $0.6 million, the net proceeds from our initial public offering were $69.1 million. We used all of the net offering proceeds from our initial public offering for the uses described in the Annual Report.
Immediately prior to the closing of our IPO the following recapitalization transactions occurred:
each common unit held by AIM Midstream Holdings reverse split into 0.485 common units, resulting in the ownership by AIM Midstream Holdings of an aggregate of 5,327,205 common units, representing an

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aggregate 97.1% limited partner interest in us;
the common units held by AIM Midstream Holdings then converted into 801,139 common units and 4,526,066 subordinated units:
each general partner unit held by our general partner reverse split into 0.485 general partner units, resulting in the ownership by our general partner of an aggregate of 108,718 general partner units, representing a 2.0% general partner interest in us;
each common unit held by participants in our LTIP, reverse split into 0.485 common units, resulting in their ownership of an aggregate of 50,946 common units, representing an aggregate 0.9% limited partner interest in us, and
each outstanding phantom unit granted to participants in our LTIP reverse split into 0.485 phantom units, resulting in their holding an aggregate of 209,824 phantom units.
In connection with the closing of our IPO and immediately following the recapitalization transactions, the following transactions also occurred:
AIM Midstream Holdings contributed 76,019 common units to our general partner as a capital contribution, and
our general partner contributed the common units contributed to it by AIM Midstream Holdings to us in exchange for 76,019 general partner units in order to maintain its 2.0% general partner interest in us.
The numbers of units outstanding were as follows:
 
 
September 30,
2012
 
December 31, 2011
 
(in thousands)
Limited partner common units
4,582

 
4,561

Limited partner subordinated units
4,526

 
4,526

General partner units
185

 
185

The outstanding units noted above reflect the retroactive treatment of the reverse unit split resulting from the recapitalization described above.
Net Income (Loss) attributable to Limited Common and General Partner Units
Net income (loss) attributable to the general partner and the limited partners (common unit holders) is allocated in accordance with their respective ownership percentages, after giving effect to incentive distributions paid to the general partner. Basic and diluted net income (loss) per limited partner common unit is calculated by dividing limited partners’ interest in net income (loss) by the weighted average number of outstanding limited partner common units 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 basic and diluted net income per limited partner unit.
We compute earnings per unit using the two-class method. The two-class method requires that securities that meet the definition of a participating security be considered for inclusion in the computation of basic earnings per unit. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of our agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period.
The two-class method does not impact our overall net income or other financial results; however, in periods in which aggregate net income exceeds our aggregate distributions for such period, it will have the impact of reducing net income per limited partner unit. This result occurs as a larger portion of our aggregate earnings, as if distributed, is allocated to the incentive distribution rights of the general partner, even though we make distributions on the basis of available cash and not earnings. In periods in which our aggregate net income does not exceed our aggregate distributions for such period, the two-class method does not have any impact on our calculation of earnings per limited partner unit.
We determined basic and diluted net income (loss) per general partner unit and limited partner unit as follows:
 

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Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2012
 
2011
 
2012
 
2011
 
(In thousands except unit amounts)
Net income (loss) attributable to general partner and limited partners
$
(4,275
)
 
$
(4,167
)
 
$
(257
)
 
$
(11,859
)
Weighted average general partner and limited partner units outstanding (basic and diluted) (a)
9,293

 
7,932

 
9,288

 
6,421

General partner and limited partner net income (loss) per unit (basic and diluted)
(0.46
)
 
(0.53
)
 
(0.03
)
 
(1.85
)
Net income (loss) attributable to limited partners
$
(4,190
)
 
$
(4,084
)
 
$
(252
)
 
$
(11,622
)
Weighted average limited partner units outstanding (basic and diluted) (a)
9,108

 
7,774

 
9,103

 
6,296

Limited partners’ net income (loss) per unit (basic and diluted)
(0.46
)
 
(0.53
)
 
(0.03
)
 
(1.85
)
Net income (loss) attributable to general partner
$
(85
)
 
$
(83
)
 
$
(5
)
 
$
(237
)
Weighted average general partner units outstanding (basic and diluted)
185

 
158

 
185

 
125

General partner net income (loss) per unit (basic and diluted)
$
(0.46
)
 
$
(0.53
)
 
$
(0.03
)
 
$
(1.90
)

a)
Gives effect to the reverse unit split.
Distributions
We made distributions of $12.1 million and $7.4 million for the nine months ended September 30, 2012 and 2011, respectively. We made no distributions in respect of our general partner’s incentive distribution rights.
In addition to the distributions described above, in August 2011, we made a special distribution of $33.7 million to participants in our long-term incentive plan (“LTIP”) holding common units, AIM Midstream Holdings and our general partner.
10. 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 and consultants and directors who perform services for it or its affiliates. On May 25, 2010, the board of directors of our general partner adopted an amended and restated long-term incentive plan. On July 11, 2012, the board of directors of our general partner adopted a second amended and restated long-term incentive plan that effectively increased available awards by 871,750 units. At September 30, 2012 and December 31, 2011, 908,588 and 54,827 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 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.
Prior to our initial public offering, the fair value of the grants issued was calculated by the general partner based on several valuation models, including: a discounted cash flow ("DCF") model, a comparable company multiple analysis and a comparable recent transaction multiple analysis. As it relates to the DCF model, the model includes certain market assumptions related to future throughput volumes, projected fees and/or prices, expected costs of sales and direct operating costs and risk adjusted discount rates. Both the comparable company analysis and recent transaction analysis contain significant assumptions consistent with the DCF model, in addition to assumptions related to comparability, appropriateness of multiples (primarily based on adjusted EBITDA and DCF) and certain assumptions in the calculation of enterprise value.

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The following table summarizes our unit-based awards for each of the periods indicated, in units:
 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2012
 
2011
 
2012
 
2011
 
(in thousands)
Outstanding at beginning of period
172,551

 
209,824

 
162,860

 
205,864

Granted

 

 
34,560

 
19,414

Forfeited
(12,517
)
 

 
(12,517
)
 

Vested

 

 
(24,869
)
 
(15,454
)
Outstanding at end of period
160,034

 
209,824

 
160,034

 
209,824

Fair value per unit
14.70 to $21.40

 
14.70 to $19.69

 
14.70 to $21.40

 
14.70 to $19.69

The fair value of our phantom units, which are subject to equity classification, is based on the fair value of our units at the grant date. Compensation costs related to these awards, including amortization, for the three months ended September 30, 2012 and 2011 was $0.5 million and $0.3 million, respectively, and for the nine months ended September 30, 2012 and 2011 was $1.3 million and $3.0 million, respectively, which is classified as equity compensation expense in the consolidated statement of operations and the non-cash portion in partners’ capital on the consolidated balance sheet.
The total fair value of vested units at the time of vesting was $0.5 million and $1.2 million for the nine months ended September 30, 2012 and period ended December 31, 2011, respectively.
The total compensation cost related to unvested awards not yet recognized at September 30, 2012 and period ended December 31, 2011 was $2.1 million and $2.7 million, respectively, and the weighted average period over which this cost is expected to be recognized as of September 30, 2012 is approximately 1.3 years.
11. Post-Employment Benefits
We sponsor a contributory postretirement plan that provides medical, dental and life insurance benefits for qualifying U.S. retired employees (referred to as the “OPEB Plan”).
Components of Net Periodic (Benefit) Cost recognized in the Condensed Consolidated Statements of Operations
 
 
OPEB Plan
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2012
 
2011
 
2012
 
2011
 
(in thousands)
Net Periodic (Benefit) Cost
 
 
 
 
 
 
 
Service cost
$
1

 

 
$
3

 

Interest cost
4

 

 
12

 

Expected return on plan assets
(16
)
 

 
(49
)
 

Amortization of net (gain) loss
(9
)
 

 
(27
)
 

Net periodic (benefit) cost
$
(20
)
 
$

 
$
(61
)
 
$

Future contributions to the Plans
We expect to make contributions to the OPEB Plan for the year ending December 31, 2012 of $0.1 million.

12. 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

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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 September 30, 2012 are presented below:
 
 
Payments Due by Period
(in thousands)
 
Total
 
2012
 
2013
 
2014
 
2015
 
2016
 
Thereafter
Operating leases and service contract
$
2,282

 
$
99

 
$
416

 
$
423

 
$
400

 
$
156

 
$
788

Asset retirement obligation
8,559

 

 

 

 

 
8,107

 
452

Total
$
10,841

 
$
99

 
$
416

 
$
423

 
$
400

 
$
8,263

 
$
1,240

Total expenses related to operating leases, asset retirement obligations, land site leases and right-of-way agreements were:
 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2012
 
2011
 
2012
 
2011
 
(in thousands)
Operating leases
$
254

 
$
177

 
$
692

 
$
578

Asset retirement obligation
10

 
2

 
23

 
10

 
$
264

 
$
179

 
$
715

 
$
588

Bazor Ridge Emissions Matter
In July 2011, in the course of preparing our annual filing for 2010 with the Mississippi Department of Environmental Quality (“MDEQ”) as required by our Title V Air Permit, we determined that we underreported to the MDEQ the SO2 (sulfur dioxide) emissions from the Bazor Ridge plant for 2009 and 2010. In addition, we determined that certain SO2 emissions during 2009 and 2010 exceeded the reportable quantity threshold under the federal Emergency Planning and Community Right-to-Know Act, or EPCRA, requiring notification of various governmental authorities. We did not make any such EPCRA notifications.
In July 2011, we self-reported these issues to the MDEQ and EPA Region IV. In January 2012, we met with EPA Region IV representatives, and have agreed to a settlement with respect to the EPCRA reporting issue. A Consent Agreement and Final Order was executed, which included a civil penalty of $23,010. After discussion with the MDEQ, in February 2012 we submitted an application to amend our Title V Air Permit to account for these SO2 emissions. The MDEQ is currently processing this permit application. In December 2011, EPA Region IV performed an inspection of the plant, and they followed up with an Information Request in May 2012. We have responded to this Information Request.
Although these current negotiations with the MDEQ and EPA are proceeding towards completion, either agency could initiate further enforcement proceedings with respect to these matters, which could result in additional monetary sanctions and our Bazor Ridge plant could become subject to significant restrictions or limitations on its operations. If the Bazor Ridge plant were subject to any curtailment or other operational restrictions as a result of any such enforcement proceeding, or were required to incur additional capital expenditures for additional emission controls through any permitting process, the costs to us could be material. In addition, if emission levels for our Bazor Ridge plant were not properly reported by the prior owner for periods before our acquisition, it is possible, though not probable at this time, that one or both of the MDEQ and the EPA may institute enforcement actions against us and/or the prior owner, in which case we may have an obligation under our purchase agreement with the prior owner to indemnify them for any resulting losses (as defined in the purchase agreement). We cannot estimate the likelihood or financial impact from any further enforcement proceedings at this time, and therefore, we have not recorded a loss contingency as the criteria under ASC 450, Contingencies, have not been met.
Separation Agreement
As of September 30, 2012, it is possible that we will incur cost of up to approximately $0.5 million in relation to a separation agreement with a former employee. In the event payment is made to the former employee pursuant to the separation agreement, we expect to receive payment from our insurance carrier of up to approximately 30% of the amount paid to the former employee.
13. Related-Party Transactions

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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 months ended September 30, 2012 and 2011, administrative and operational services expenses of $2.9 million and $2.0 million, respectively, were charged to us by our general partner. During the nine months ended September 30, 2012 and 2011 administrative and operational services expense of $9.1 million and $7.4 million respectively, were charged to us by our general partner and increased primarily due to payroll costs. For the three months ended September 30, 2012, our general partner incurred approximately $0.2 million of costs associated with certain business development activities.  If the business development activities result in a project that will be pursued and funded by the Partnership, we will reimburse our general partner for the business development costs related to that project.
Prior to our IPO, we had entered into an advisory services agreement with American Infrastructure MLP Management, L.L.C., American Infrastructure MLP PE Management, L.L.C., and American Infrastructure MLP Associates Management, L.L.C., as the advisors. The agreement provided for the payment of $0.3 million in 2010 and annual fees of $0.3 million plus annual increases in proportion to the increase in budgeted gross revenues thereafter. In exchange, the advisors agreed to provide us services in obtaining equity, debt, lease and acquisition financing, as well as providing other financial, advisory and consulting services. On August 1, 2011, and in connection with our IPO, we terminated the advisory services agreement in exchange for a one-time payment of $2.5 million. For the three and nine months ended September 30, 2011, less than $0.1 million was recorded to selling, general and administrative expenses under this agreement.
14. 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 following tables set forth our segment information:
 

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Table of Contents

 
Three Months Ended
 
September 30,
 
2012
 
2011
 
Gathering
and
Processing
 
Transmission
 
Total
 
Gathering
and
Processing
 
Transmission
 
Total
 
(in thousands)
Revenue
$
45,376

 
$
12,710

 
$
58,086

 
$
41,218

 
$
15,787

 
$
57,005

Segment gross margin (a)
10,736

 
3,450

 
14,186

 
6,821

 
2,825

 
9,646

Unrealized gain (loss) on commodity derivatives (b)
(1,762
)
 

 
(1,762
)
 
953

 

 
953

Direct operating expenses
3,935

 
1,329

 
5,264

 
1,845

 
1,540

 
3,385

Selling, general and administrative expenses
 
 
 
 
3,679

 
 
 
 
 
2,497

Advisory services agreement termination fee
 
 
 
 

 
 
 
 
 
2,500

Equity compensation expense
 
 
 
 
474

 
 
 
 
 
331

Depreciation and accretion expense
 
 
 
 
5,536

 
 
 
 
 
5,261

(Gain) loss on sale of assets, net
 
 
 
 
(4
)
 
 
 
 
 
(586
)
Interest expense
 
 
 
 
1,501

 
 
 
 
 
1,378

Net income (loss)
 
 
 
 
(4,026
)
 
 
 
 
 
(4,167
)
Less: Net income (loss) attributable to noncontrolling interests
 
 
 
 
249

 
 
 
 
 

Net income (loss) attributable to the Partnership
 
 
 
 
$
(4,275
)
 
 
 
 
 
$
(4,167
)
 
 
Nine Months Ended
 
September 30,
 
2012
 
2011
 
Gathering
and
Processing
 
Transmission
 
Total
 
Gathering
and
Processing
 
Transmission
 
Total
 
(in thousands)
Revenue
$
111,246

 
$
37,117

 
$
148,363

 
$
138,487

 
$
51,887

 
$
190,374

Segment gross margin (a)
29,198

 
11,817

 
41,015

 
22,988

 
9,661

 
32,649

Realized gain (loss) on early termination of commodity derivatives (b)

 

 

 
(2,998
)
 

 
(2,998
)
Unrealized gain (loss) on commodity derivatives (b)
1,732

 

 
1,732

 
(19
)
 

 
(19
)
Direct operating expenses
8,495

 
3,536

 
12,031

 
5,478

 
4,070

 
9,548

Selling, general and administrative expenses
 
 
 
 
10,676

 
 
 
 
 
7,649

Advisory services agreement termination fee
 
 
 
 

 
 
 
 
 
2,500

Equity compensation expense
 
 
 
 
1,272

 
 
 
 
 
2,989

Depreciation and accretion expense
 
 
 
 
15,819

 
 
 
 
 
15,468

(Gain) loss on sale of assets, net
 
 
 
 
(126
)
 
 
 
 
 
(586
)
Interest expense
 
 
 
 
3,083

 
 
 
 
 
3,923

Net income (loss)
 
 
 
 
(8
)
 
 
 
 
 
(11,859
)
Less: Net income (loss) attributable to noncontrolling interests
 
 
 
 
249

 
 
 
 
 

Net income (loss) attributable to the Partnership
 
 
 
 
$
(257
)
 
 
 
 
 
$
(11,859
)
 
(a)
Segment gross margin for our Gathering and Processing segment consists of total revenue less purchases of natural gas, NGLs and condensate. Segment gross margin for our Transmission segment consists of total revenue less purchases of natural gas. Gross margin consists of the sum of the segment gross margin for each segment. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful

25

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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.
(b)
Effective January 1, 2011, we changed our segment gross margin measure to exclude unrealized non cash mark-to-market adjustments related to our commodity derivatives. For the three and nine months ended September 30, 2011, $1.0 million and $(0.1) million, respectively, in unrealized gains (losses) were excluded from our Gathering and Processing segment gross margin. Effective April 1, 2011 we changed our segment gross margin measure to exclude realized gain (loss) on early termination of commodity derivatives. For the three and nine months ended September 30, 2011, zero dollars and $(3.0) million, respectively, in unrealized gains (losses) were excluded from our Gathering and Processing segment gross margin.
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.
15. Subsequent Events
Distribution
On October 23, 2012, we announced a distribution of $0.4325 per unit payable on November 14, 2012 to unitholders of record on November 7, 2012.

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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. As of September 30, 2012, the Subsidiaries have an investment in the non-guarantor subsidiaries equal to a 87.4% undivided interest in its Chatom Assets. 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 Assets 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 September 30, 2012 and for the three and nine months ended is as follows:


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Table of Contents

 Condensed Consolidating Balance Sheet
As of September 30, 2012
 
 
 
 
 
 
 
 Parent
 Guarantor Subsidiaries
 Non-Guarantor Subsidiaries
 Consolidating Adjustments
 Consolidated
 
(in thousands)
Assets
 
 
 
 
 
Current assets
 
 
 
 
 
Cash and cash equivalents
$
1

$
496

$

$

$
497

Accounts receivable

1,776



1,776

Unbilled revenue

11,999

5,604


17,603

Risk management assets

1,347



1,347

Other current assets

2,602

322


2,924

Total current assets
1

18,220

5,926


24,147

Property, plant and equipment, net

158,951

58,601


217,552

Risk management assets - long term

207



207

Investment in subsidiaries
90,325

51,863


(142,188
)

Other assets, net

4,520



4,520

Total assets
$
90,326

$
233,761

$
64,527

$
(142,188
)
$
246,426

 
 
 
 
 
 
Liabilities and Partners’ Capital
 
 
 
 
 
Current liabilities
 
 
 
 
 
Accounts payable
$

$
2,571

$
469

$

$
3,040

Accrued gas purchases

8,615

4,297


12,912

Risk management liabilities





Accrued expenses and other current liabilities

5,171

36


5,207

Total current liabilities

16,357

4,802


21,159

Other liabilities

8,429

455


8,884

Long-term debt

118,650



118,650

Total liabilities

143,436

5,257


148,693

 
 
 
 
 
 
Total partners' capital
90,326

90,325

51,863

(142,188
)
90,326

Total liabilities and partners' capital
$
90,326

$
233,761

$
57,120

$
(142,188
)
$
239,019

Noncontrolling interest


7,407


7,407

Total liabilities, partners' equity and noncontrolling interest
$
90,326

$
233,761

$
64,527

$
(142,188
)
$
246,426



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Table of Contents

 Condensed Consolidating Statements of Operations
Three months ended September 30, 2012
 
 
 
 
 
 
 
 Parent
 Guarantor Subsidiaries
 Non-Guarantor Subsidiaries
 Consolidating Adjustments
 Consolidated
 
(in thousands)
Revenue
$

$
43,085

$
15,371

$
(370
)
$
58,086

Unrealized gains (loss) on commodity derivatives

(1,762
)


(1,762
)
Total revenue

41,323

15,371

(370
)
56,324

Operating expenses:
 
 
 
 
 
Purchases of natural gas, NGLs and condensate

32,729

11,541

(370
)
43,900

Direct operating expenses

4,286

978


5,264

Selling, general and administrative expenses

3,583

96


3,679

Equity compensation expense

474



474

Depreciation and accretion expense

5,134

402


5,536

(Gain) loss on sale of assets, net

(4
)


(4
)
Total operating expenses

46,202

13,017

(370
)
58,849

Operating income (loss)

(4,879
)
2,354


(2,525
)
Other income (expenses):
 
 
 
 
 
Earnings from consolidated affiliates
(4,275
)
2,105


2,170


Interest expense

(1,501
)


(1,501
)
Net income (loss)
(4,275
)
(4,275
)
2,354

2,170

(4,026
)
Net income (loss) attributable to noncontrolling interests


249


249

Net income (loss) attributable to the Partnership
$
(4,275
)
$
(4,275
)
$
2,105

$
2,170

$
(4,275
)




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Table of Contents

 Condensed Consolidating Statements of Operations
Nine months ended September 30, 2012
 
 
 
 
 
 
 
 Parent
 Guarantor Subsidiaries
 Non-Guarantor Subsidiaries
 Consolidating Adjustments
 Consolidated
 
(in thousands)
Revenue
$

$
133,362

$
15,371

$
(370
)
$
148,363

Unrealized gains (loss) on commodity derivatives

1,732



1,732

Total revenue

135,094

15,371

(370
)
150,095

Operating expenses:
 
 
 
 
 
Purchases of natural gas, NGLs and condensate

96,177

11,541

(370
)
107,348

Direct operating expenses

11,053

978


12,031

Selling, general and administrative expenses

10,580

96


10,676

Equity compensation expense

1,272



1,272

Depreciation and accretion expense

15,417

402


15,819

(Gain) loss on sale of assets, net

(126
)


(126
)
Total operating expenses

134,373

13,017

(370
)
147,020

Operating income (loss)

721

2,354


3,075

Other income (expenses):
 
 
 
 
 
Earnings from consolidated affiliates
(257
)
2,105


(1,848
)

Interest expense

(3,083
)


(3,083
)
Net income (loss)
(257
)
(257
)
2,354

(1,848
)
(8
)
Net income (loss) attributable to noncontrolling interests


249


249

Net income (loss) attributable to the Partnership
$
(257
)