RGP-9.30.12-10Q
Table of Contents

 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
ý
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
 
¨
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: 001-35262
REGENCY ENERGY PARTNERS LP
(Exact name of registrant as specified in its charter)
 
DELAWARE
 
16-1731691
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
 
 
2001 BRYAN STREET, SUITE 3700
DALLAS, TX
 
75201
(Address of principal executive offices)
 
(Zip Code)
(214) 750-1771
(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.    Yes  ý    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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ý    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 small reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
 
ý
  
Accelerated filer
 
¨
 
 
 
 
 
 
 
Non-accelerated filer
 
¨  (Do not check if a smaller reporting company)
  
Smaller reporting company
 
¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  ý
The issuer had 170,804,695 common units outstanding as of November 1, 2012.
 

Table of Contents

FORM 10-Q
TABLE OF CONTENTS
Regency Energy Partners LP
 
 
 
 
 
ITEM 1.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
ITEM 2.
 
 
 
ITEM 3.
 
 
 
ITEM 4.
 
 
 
 
 
 
ITEM 1.
 
 
 
ITEM 1A.
 
 
 
ITEM 2.
 
 
 
ITEM 3.
 
 
 
ITEM 4.
 
 
 
ITEM 5.
 
 
 
ITEM 6.
 
 
 

i
Table of Contents

Introductory Statement
References in this report to the “Partnership,” “we,” “our,” “us” and similar terms refer to Regency Energy Partners LP and its subsidiaries. We use the following definitions in this quarterly report on Form 10-Q:
 
Name
Definition or Description
 
/d
Per day
 
AOCI
Accumulated Other Comprehensive Income (Loss)
 
Bbls
Barrels
 
BTU
A unit of energy needed to raise the temperature of one pound of water by one degree Fahrenheit
 
Citi
Citigroup Global Markets Inc.
 
Edwards Lime
Edwards Lime Gathering, LLC, ELG Oil LLC and ELG Utility LLC which are 60% owned by the Partnership
 
ETC
Energy Transfer Company, the name assumed by La Grange Acquisition, L.P. for conducting business and shared services, a wholly owned subsidiary of ETP
 
ETE
Energy Transfer Equity, L.P.
 
ETP
Energy Transfer Partners, L.P.
 
Finance Corp.
Regency Energy Finance Corp., a wholly-owned subsidiary of the Partnership
 
GAAP
Accounting principles generally accepted in the United States of America
 
General Partner
Regency GP LP, the general partner of the Partnership, or Regency GP LLC, the general partner of Regency GP LP, which effectively manages the business and affairs of the partnerships
 
GPM
Gallons per minute
 
HPC
RIGS Haynesville Partnership Co., a general partnership in which the Partnership owns a 49.99% interest, and its 100% owned subsidiary, Regency Intrastate Gas LP
 
IDRs
Incentive Distribution Rights
 
Lone Star
Lone Star NGL LLC, which is 30% owned by the Partnership and 70% owned by ETP
 
LTIP
Long-Term Incentive Plan
 
MEP
Midcontinent Express Pipeline LLC, which is 50% owned by the Partnership
 
MBbls
One thousand barrels
 
MMBtu
One million BTUs
 
MMcf
One million cubic feet
 
NGLs
Natural gas liquids, including ethane, propane, normal butane, iso butane and natural gasoline
 
NYMEX
New York Mercantile Exchange
 
Partnership
Regency Energy Partners LP and its subsidiaries
 
Ranch JV
Ranch Westex JV LLC, which is 33.33% owned by the Partnership
 
RGS
Regency Gas Services LP, a wholly-owned subsidiary of the Partnership
 
RIGS
Regency Intrastate Gas System
 
SEC
Securities and Exchange Commission
 
Series A Preferred Units
Series A convertible redeemable preferred units
 
Services Co.
ETE Services Company, LLC, a wholly owned subsidiary of ETE
 
WTI
West Texas Intermediate Crude

ii
Table of Contents

Cautionary Statement about Forward-Looking Statements
Certain matters discussed in this report include forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “expect,” “continue,” “estimate,” “goal,” “forecast,” “may” or similar expressions help identify forward-looking statements. Although we believe our forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, we cannot give assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions including without limitation the following:
•volatility in the price of oil, natural gas, and NGLs;
•
declines in the credit markets and the availability of credit for us as well as for producers connected to our pipelines and our gathering and processing facilities, and for our customers of contract compression and contract treating businesses;
•
the level of creditworthiness of, and performance by, our counterparties and customers;
•
our access to capital to fund organic growth projects and acquisitions, and our ability to obtain debt or equity financing on satisfactory terms;
•
our use of derivative financial instruments to hedge commodity and interest rate risks;
•
the amount of collateral required to be posted from time-to-time in our transactions;
•
changes in commodity prices, interest rates and demand for our services;
•
changes in laws and regulations impacting the midstream sector of the natural gas industry, including those that relate to climate change and environmental protection and safety;
•
weather and other natural phenomena;
•
industry changes including the impact of consolidations and changes in competition;
•
regulation of transportation rates on our natural gas and NGL pipelines;
•
our ability to obtain indemnification related to cleanup liabilities and to clean up any hazardous materials release on satisfactory terms;
•
our ability to obtain required approvals for construction or modernization of our facilities and the timing of production from such facilities; and
•
the effect of accounting pronouncements issued periodically by accounting standard setting boards.
If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may differ materially from those anticipated, estimated, projected or expected.
Other factors that could cause our actual results to differ from our projected results are discussed in Item 1A of our December 31, 2011 Annual Report on Form 10-K and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2012.
Each forward-looking statement speaks only as of the date of the particular statement and we undertake no obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.
 

iii
Table of Contents

PART I – FINANCIAL INFORMATION
Item 1. Financial Statements
Regency Energy Partners LP
Condensed Consolidated Balance Sheets
(in thousands)
(unaudited)
 
September 30,
2012
 
December 31,
2011
ASSETS
 
 
 
Current Assets:
 
 
 
Cash and cash equivalents
$
36,464

 
$
990

Trade accounts receivable, net of allowance of $954 and $1,190
32,289

 
43,917

Accrued revenues
87,778

 
68,011

Related party receivables
19,138

 
45,204

Derivative assets
7,787

 
4,374

Other current assets
26,228

 
24,628

Total current assets
209,684

 
187,124

Property, plant and equipment:
 
 
 
Property, plant and equipment
2,367,865

 
2,080,932

Less accumulated depreciation
(308,669
)
 
(195,404
)
Property, plant and equipment, net
2,059,196

 
1,885,528

Other Assets:
 
 
 
Investment in unconsolidated affiliates
2,156,135

 
1,924,705

Long-term derivative assets
918

 
474

Other, net of accumulated amortization of debt issuance costs of $15,175 and $10,186
33,486

 
39,353

Total other assets
2,190,539

 
1,964,532

Intangible assets, net of accumulated amortization of $66,811 and $44,856
718,928

 
740,883

Goodwill
789,789

 
789,789

TOTAL ASSETS
$
5,968,136

 
$
5,567,856

LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST
 
 
 
Current Liabilities:
 
 
 
Drafts payable
$
—

 
$
2,507

Trade accounts payable
67,976

 
73,462

Accrued cost of gas and liquids
66,220

 
84,943

Related party payables
23,791

 
12,625

Deferred revenues, including related party amounts of $71 and $41
15,149

 
16,225

Derivative liabilities
803

 
10,535

Other current liabilities
40,168

 
33,009

Total current liabilities
214,107

 
233,306

Long-term derivative liabilities
29,490

 
39,112

Other long-term liabilities
5,550

 
6,071

Long-term debt, net
1,960,429

 
1,687,147

Commitments and contingencies

 

Series A Preferred Units, redemption amount of $85,129 and $84,773
72,549

 
71,144

Partners’ capital and noncontrolling interest:
 
 
 
Common units
3,299,389

 
3,173,090

General partner interest
327,160

 
329,876

Accumulated other comprehensive income (loss)
1,330

 
(4,759
)
Total partners’ capital
3,627,879

 
3,498,207

Noncontrolling interest
58,132

 
32,869

Total partners’ capital and noncontrolling interest
3,686,011

 
3,531,076

TOTAL LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST
$
5,968,136

 
$
5,567,856

See accompanying notes to condensed consolidated financial statements

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Table of Contents

Regency Energy Partners LP
Condensed Consolidated Statements of Operations
(in thousands except unit data and per unit data)
(unaudited)
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2012

2011
 
2012
 
2011
REVENUES
 
 
 
 
 
 
 
Gas sales, including related party amounts of $4,507, $3,840, $13,788 and $15,479
$
82,437

 
$
118,754

 
$
227,374

 
$
361,641

NGL sales, including related party amounts of $(773), $103,892, $22,195 and $253,933
124,651

 
174,537

 
404,914

 
430,876

Gathering, transportation and other fees, including related party amounts of $9,024, $6,141, $23,024 and $17,611
101,410

 
91,596

 
296,989

 
255,249

Net realized and unrealized (loss) gain from derivatives
(5,232
)
 
(5,380
)
 
8,571

 
(14,636
)
Other, including related party amounts of $1, $2,665, $1,479 and $7,455
10,616

 
10,760

 
45,909

 
30,887

Total revenues
313,882

 
390,267

 
983,757

 
1,064,017

OPERATING COSTS AND EXPENSES
 
 
 
 
 
 
 
Cost of sales, including related party amounts of $4,391, $5,049, $12,965 and $16,070
206,881

 
279,526

 
633,349

 
755,262

Operation and maintenance
41,275

 
37,950

 
121,248

 
105,506

General and administrative, including related party amounts of $4,300, $4,225, $12,900 and $12,354
14,935

 
17,350

 
47,106

 
54,010

(Gain) loss on asset sales, net
(42
)
 
(131
)
 
1,542

 
50

Depreciation and amortization
45,881

 
41,956

 
142,519

 
122,695

Total operating costs and expenses
308,930

 
376,651

 
945,764

 
1,037,523

OPERATING INCOME
4,952

 
13,616

 
37,993

 
26,494

Income from unconsolidated affiliates
21,055

 
30,946

 
87,198

 
86,921

Interest expense, net
(28,567
)
 
(28,852
)
 
(86,058
)
 
(73,548
)
Loss on debt refinancing, net
—

 
—

 
(7,820
)
 
—

Other income and deductions, net
1,106

 
15,050

 
25,549

 
20,105

(LOSS) INCOME BEFORE INCOME TAXES
(1,454
)
 
30,760

 
56,862

 
59,972

Income tax expense (benefit)
—

 
(89
)
 
89

 
(19
)
NET (LOSS) INCOME
(1,454
)
 
30,849

 
56,773

 
59,991

Net loss attributable to noncontrolling interest
(379
)
 
(549
)
 
(1,427
)
 
(1,073
)
NET (LOSS) INCOME ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP
$
(1,833
)
 
$
30,300

 
$
55,346

 
$
58,918

Amounts attributable to Series A Preferred Units
2,125

 
1,997

 
7,242

 
5,985

General partner’s interest, including IDRs
2,019

 
2,060

 
7,012

 
4,902

Limited partners’ interest in net (loss) income
$
(5,977
)
 
$
26,243

 
$
41,092

 
$
48,031

Basic and diluted net income per common unit:
 
 
 
 
 
 
 
Weighted average number of common units outstanding
170,264,621

 
145,842,735

 
166,368,178

 
142,058,631

Basic (loss) income per common unit
$
(0.04
)
 
$
0.18

 
$
0.25

 
$
0.34

Diluted (loss) income per common unit
$
(0.04
)
 
$
0.09

 
$
0.22

 
$
0.23

Distributions per common unit
$
0.46

 
$
0.455

 
$
1.38

 
$
1.35



See accompanying notes to condensed consolidated financial statements

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Table of Contents

Regency Energy Partners LP
Condensed Consolidated Statements of Comprehensive (Loss) Income
(in thousands)
(unaudited)
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2012

2011
 
2012
 
2011
Net (loss) income
$
(1,454
)
 
$
30,849

 
$
56,773

 
$
59,991

Other comprehensive income (loss):
 
 
 
 
 
 
 
Net cash flow hedge amounts reclassified to earnings
265

 
5,282

 
6,089

 
14,276

Change in fair value of cash flow hedges
—

 
10,287

 
—

 
(5,179
)
Total other comprehensive income
265

 
15,569

 
6,089

 
9,097

Comprehensive (loss) income
(1,189
)
 
46,418

 
62,862

 
69,088

Comprehensive income attributable to noncontrolling interest
379

 
549

 
1,427

 
1,073

Comprehensive (loss) income attributable to Regency Energy Partners LP
$
(1,568
)
 
$
45,869

 
$
61,435

 
$
68,015






















See accompanying notes to condensed consolidated financial statements

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Table of Contents

Regency Energy Partners LP
Condensed Consolidated Statements of Cash Flows
(in thousands)
(unaudited)
 
Nine Months Ended September 30,
 
2012
 
2011
OPERATING ACTIVITIES:
 
 
 
Net income
$
56,773

 
$
59,991

Adjustments to reconcile net income to net cash flows provided by operating activities:
 
 
 
Depreciation and amortization, including debt issuance cost and bond premium amortization
146,913

 
127,079

Income from unconsolidated affiliates
(87,198
)
 
(86,921
)
Derivative valuation changes
(17,124
)
 
(21,660
)
Loss on asset sales, net
1,542

 
50

Unit-based compensation expenses
3,470

 
2,444

Cash flow changes in current assets and liabilities:
 
 
 
Trade accounts receivable, accrued revenues and related party receivables
10,779

 
(13,298
)
Other current assets
(1,429
)
 
186

Trade accounts payable, accrued cost of gas and liquids, related party payables and deferred revenues
(31,675
)
 
20,467

Other current liabilities
7,159

 
24,833

Distributions received from unconsolidated affiliates
91,893

 
91,306

Other assets and liabilities
(178
)
 
(61
)
Net cash flows provided by operating activities
180,925

 
204,416

INVESTING ACTIVITIES:
 
 
 
Capital expenditures
(306,159
)
 
(290,889
)
Capital contributions to unconsolidated affiliates
(272,759
)
 
(23,646
)
Acquisitions of investments in unconsolidated affiliates, net of cash received
—

 
(593,843
)
Distributions in excess of earnings of unconsolidated affiliates
49,814

 
40,354

Proceeds from asset sales
22,004

 
10,232

Net cash flows used in investing activities
(507,100
)
 
(857,792
)
FINANCING ACTIVITIES:
 
 
 
Net borrowings under revolving credit facility
363,000

 
160,000

Proceeds from issuance of senior notes
—

 
500,000

Redemption of senior notes
(87,500
)
 
—

Debt issuance costs
(1,438
)
 
(9,955
)
Drafts payable
(2,507
)
 
—

Partner distributions
(240,304
)
 
(199,640
)
Transfer of assets between entities under common control in excess of historical cost
436

 
66

Contributions from noncontrolling interest
23,836

 
—

Issuance of common units under LTIP, net of forfeitures and tax withholding
(207
)
 
655

Common unit offering, net of costs
296,817

 
203,917

Common units issued under equity distribution program, net of costs
15,352

 
—

Distributions to Series A Preferred Units
(5,836
)
 
(5,836
)
Net cash flows provided by financing activities
361,649

 
649,207

Net change in cash and cash equivalents
35,474

 
(4,169
)
Cash and cash equivalents at beginning of period
990

 
9,400

Cash and cash equivalents at end of period
$
36,464

 
$
5,231

Supplemental Cash Flow Information:
 
 
 
Accrued capital expenditures and contributions to unconsolidated affiliates
$
41,668

 
$
25,504

Deemed contribution from acquisition of assets between entities under common control
—

 
177


See accompanying notes to condensed consolidated financial statements

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Table of Contents

Regency Energy Partners LP
Condensed Consolidated Statement of Partners' Capital and Noncontrolling Interest
(in thousands except unit data)
(unaudited)
 
Regency Energy Partners LP
 
 
 
 
 
Units
 
 
 
 
 
 
 
 
 
 
 
Common
 
Common
Unitholders
 
General
Partner
Interest
 
Accumulated
Other
Comprehensive
(Loss) Income
 
Noncontrolling
Interest
 
Total
Balance - December 31, 2011
157,437,608

 
$
3,173,090

 
$
329,876

 
$
(4,759
)
 
$
32,869

 
$
3,531,076

Common unit offering, net of costs
12,650,000

 
296,817

 
—

 
—

 
—

 
296,817

Common units issued under equity distribution program, net of costs
691,129

 
15,352

 
—

 
—

 
—

 
15,352

Issuance of common units under LTIP, net of forfeitures and tax withholding
25,958

 
(207
)
 
—

 
—

 
—

 
(207
)
Unit-based compensation expenses
—

 
3,470

 
—

 
—

 
—

 
3,470

Transfer of assets between entities under common control in excess of historical cost
—

 
—

 
436

 
—

 
—

 
436

Partner distributions
—

 
(230,262
)
 
(10,042
)
 
—

 
—

 
(240,304
)
Accrued distributions to phantom units
—

 
(86
)
 
—

 
—

 
—

 
(86
)
Net income
—

 
48,334

 
7,012

 
—

 
1,427

 
56,773

Contributions from noncontrolling interest
—

 
—

 
—

 
—

 
23,836

 
23,836

Distributions to Series A Preferred Units
—

 
(5,738
)
 
(98
)
 
—

 


 
(5,836
)
Accretion of Series A Preferred Units
—

 
(1,381
)
 
(24
)
 
—

 
—

 
(1,405
)
Net cash flow hedge amounts reclassified to earnings
—

 
—

 
—

 
6,089

 
—

 
6,089

Balance - September 30, 2012
170,804,695

 
$
3,299,389

 
$
327,160

 
$
1,330

 
$
58,132

 
$
3,686,011












See accompanying notes to condensed consolidated financial statements

5
Table of Contents

Regency Energy Partners LP
Notes to Condensed Consolidated Financial Statements
(Tabular dollar amounts, except per unit data, are in thousands)
(unaudited)
1. Organization and Summary of Significant Accounting Policies
Organization. The unaudited condensed consolidated financial statements presented herein contain the results of Regency Energy Partners LP and its subsidiaries ("Partnership"), a Delaware limited partnership. The Partnership is engaged in the business of gathering and processing, contract compression, treating and transportation of natural gas and the transportation, fractionation and storage of NGLs. Regency GP LP is the Partnership’s general partner and Regency GP LLC (collectively the “General Partner”) is the general partner of Regency GP LP.
Basis of Presentation. The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2011. In the opinion of the Partnership’s management, such financial information reflects all adjustments necessary for a fair presentation of the financial position and the results of operations for such interim periods in accordance with GAAP. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC.
Use of Estimates. The unaudited condensed consolidated financial statements have been prepared in conformity with GAAP, which includes the use of estimates and assumptions made by management that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities that exist at the date of the condensed consolidated financial statements. Although these estimates are based on management’s available knowledge of current and expected future events, actual results could be different from those estimates.
Property, Plant and Equipment. In March 2012, the Partnership recorded a $6.9 million “out-of-period” adjustment to depreciation expense to correct the estimated useful lives of certain assets to comply with its policy. The adjustment to depreciation expense related to the year ended December 31, 2011 and the period from May 26, 2010 to December 31, 2010 was $4.4 million and $2.5 million, respectively. The adjustment to depreciation expense related to the three and nine months ended September 30, 2011 was $1.1 million and $3.3 million, respectively.
2. Partners' Capital and Distributions
Equity Distribution Agreement. On June 19, 2012, the Partnership entered into an Equity Distribution Agreement with Citi under which the Partnership may offer and sell common units, representing limited partner interests, having an aggregate offering price of up to $200 million, from time to time through Citi, as sales agent for the Partnership. Sales of these units, if any, made from time to time under the Equity Distribution Agreement will be made by means of ordinary brokers’ transactions on the New York Stock Exchange at market prices, in block transactions, or as otherwise agreed upon by the Partnership and Citi. The Partnership may also sell common units to Citi as principal for its own account at a price agreed upon at the time of sale. Any sale of common units to Citi as principal would be pursuant to the terms of a separate agreement between the Partnership and Citi. The Partnership intends to use the net proceeds from the sale of these units for general partnership purposes. As of September 30, 2012, the Partnership has issued 691,129 common units resulting in net proceeds of $15.4 million.
Quarterly Distributions of Available Cash. Following are distributions declared by the Partnership subsequent to December 31, 2011:
Quarter Ended
 
Record Date
 
Payment Date
 
Cash Distributions
(per common unit)
December 31, 2011
 
February 6, 2012
 
February 13, 2012
 
$0.46
March 31, 2012
 
May 7, 2012
 
May 14, 2012
 
$0.46
June 30, 2012
 
August 6, 2012
 
August 14, 2012
 
$0.46
September 30, 2012
 
November 6, 2012
 
November 14, 2012
 
$0.46
Common Unit Offering. In March 2012, the Partnership issued 12,650,000 common units representing limited partner interests in a public offering at a price of $24.47 per common unit, resulting in net proceeds of $296.8 million. In May 2012, the Partnership used the net proceeds from this offering to redeem 35%, or $87.5 million, in aggregate principal amounts of its outstanding senior notes due 2016; pay related premium, expenses and accrued interest; and repay outstanding borrowings under the revolving credit facility.

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Table of Contents

3. (Loss) Income per Common Unit
The following tables provide a reconciliation of the numerator and denominator of the basic and diluted earnings per common unit computations for the three and nine months ended September 30, 2012 and 2011:
 
Three Months Ended September 30,
 
2012
 
2011
 
(Loss)
(Numerator)
 
Units
(Denominator)
 
Per-Unit
Amount
 
Income
(Numerator)
 
Units
(Denominator)
 
Per-Unit
Amount
Basic (loss) income per unit
 
 
 
 
 
 
 
 
 
 
 
Limited Partners’ interest in net (loss) income
$
(5,977
)
 
170,264,621

 
$
(0.04
)
 
$
26,243

 
145,842,735

 
$
0.18

Effect of Dilutive Securities:
 
 
 
 
 
 
 
 
 
 
 
Common unit options
—

 
—

 
 
 
—

 
13,633

 
 
Phantom units *
—

 
—

 
 
 
—

 
281,320

 
 
Series A Preferred Units
—

 
—

 
 
 
(13,233
)
 
4,626,197

 
 
Diluted (loss) income per unit
$
(5,977
)
 
170,264,621

 
$
(0.04
)
 
$
13,010

 
150,763,885

 
$
0.09

 
Nine Months Ended September 30,
 
2012
 
2011
 
Income
(Numerator)
 
Units
(Denominator)
 
Per-Unit
Amount
 
Income
(Numerator)
 
Units
(Denominator)
 
Per-Unit
Amount
Basic income per unit
 
 
 
 
 
 
 
 
 
 
 
Limited Partners’ interest in net income
$
41,092

 
166,368,178

 
$
0.25

 
$
48,031

 
142,058,631

 
$
0.34

Effect of Dilutive Securities:
 
 
 
 
 
 
 
 
 
 
 
Common unit options
—

 
13,113

 
 
 
—

 
23,450

 
 
Phantom units *
—

 
320,452

 
 
 
—

 
237,192

 
 
Series A Preferred Units
(2,713
)
 
4,651,884

 
 
 
(14,770
)
 
4,626,197

 
 
Diluted income per unit
$
38,379

 
171,353,627

 
$
0.22

 
$
33,261

 
146,945,470

 
$
0.23

__________________
*
Amount assumes maximum conversion rate for market condition awards.
The following data show securities that could potentially dilute earnings per unit in the future that were not included in the computation of diluted earnings per unit because to do so would have been antidilutive for the periods presented:
 
Three Months
Ended
September 30,
2012
Common unit options
9,147

Phantom units *
313,378

Series A Preferred Units
4,651,884

__________________
*
Amount assumes maximum conversion rate for market condition awards.

7
Table of Contents

4. Investment in Unconsolidated Affiliates
As of September 30, 2012, the Partnership has a 49.99% general partner interest in HPC, a 50% membership interest in MEP, a 30% membership interest in Lone Star, and a 33.33% membership interest in Ranch JV. The carrying value of the Partnership's investment in each of the unconsolidated affiliates as of September 30, 2012 and December 31, 2011 is as follows:
 
September 30,
2012
 
December 31,
2011
HPC
$
658,869

 
$
682,046

MEP
588,800

 
613,942

Lone Star
876,133

 
628,717

Ranch JV
32,333

 
—

 
$
2,156,135

 
$
1,924,705

The following tables summarize the Partnership's investment activities in each of the unconsolidated affiliates for the three and nine months ended September 30, 2012 and 2011:
 
Three Months Ended September 30, 2012
 
HPC
 
MEP
 
Lone Star
 
Ranch JV
Contributions to unconsolidated affiliates
$
—

 
$
—

 
$
78,042

 
$
10,287

Distributions from unconsolidated affiliates
16,438

 
18,263

 
21,051

 
—

Share of unconsolidated affiliates' net income (loss)
3,259

 
10,367

 
9,184

 
(293
)
Amortization of excess fair value of investment
(1,462
)
 
—

 
—

 
—

 
Three Months Ended September 30, 2011
 
HPC
 
MEP
 
Lone Star(1)
 
Ranch JV
Contributions to unconsolidated affiliates
$
—

 
$
—

 
$
24,630

 
N/A
Distributions from unconsolidated affiliates
15,022

 
19,238

 
18,900

 
N/A
Share of unconsolidated affiliates' net income
12,138

 
10,985

 
9,285

 
N/A
Amortization of excess fair value of investment
(1,462
)
 
—

 
—

 
N/A
 
Nine Months Ended September 30, 2012
 
HPC
 
MEP
 
Lone Star
 
Ranch JV
Contributions to unconsolidated affiliates
$
—

 
$
—

 
$
253,296

 
$
32,643

Distributions from unconsolidated affiliates
46,468

 
56,445

 
38,794

 
—

Share of unconsolidated affiliates' net income (loss)
27,676

 
31,303

 
32,914

 
(310
)
Amortization of excess fair value of investment
(4,385
)
 
—

 
—

 
—

 
Nine Months Ended September 30, 2011
 
HPC
 
MEP
 
Lone Star(1)
 
Ranch JV
Contributions to unconsolidated affiliates
$
—

 
$
—

 
$
616,311

 
N/A
Distributions from unconsolidated affiliates
49,863

 
62,897

 
18,900

 
N/A
Share of unconsolidated affiliates' net income
42,343

 
31,290

 
17,673

 
N/A
Amortization of excess fair value of investment
(4,385
)
 
—

 
—

 
N/A
__________________
(1)
For the period from initial contribution, May 2, 2011, to September 30, 2011.
N/A
The Partnership acquired a 33.33% membership interest in Ranch JV in December 2011.

8
Table of Contents

The following tables present selected income statement data for each of the unconsolidated affiliates, on a 100% basis, for the three and nine months ended September 30, 2012 and 2011:
 
Three Months Ended September 30, 2012
 
HPC
 
MEP
 
Lone Star
 
Ranch JV
Total revenues
$
42,212

 
$
65,052

 
$
164,931

 
$
20

Operating income (loss)
21,088

 
33,547

 
31,128

 
(880
)
Net income (loss)
6,520

 
20,735

 
30,611

 
(880
)
 
Three Months Ended September 30, 2011
 
HPC
 
MEP
 
Lone Star(1)
 
Ranch JV
Total revenues
$
43,809

 
$
65,853

 
$
146,596

 
N/A

Operating income
24,627

 
34,852

 
30,936

 
N/A

Net income
24,282

 
21,998

 
30,952

 
N/A

 
Nine Months Ended September 30, 2012
 
HPC
 
MEP
 
Lone Star
 
Ranch JV
Total revenues
$
130,352

 
$
196,181

 
$
489,517

 
$
150

Operating income (loss)
70,737

 
101,210

 
109,748

 
(931
)
Net income (loss)
55,364

 
62,606

 
109,712

 
(931
)
 
Nine Months Ended September 30, 2011
 
HPC
 
MEP
 
Lone Star(1)
 
Ranch JV
Total revenues
$
141,043

 
$
195,620

 
$
245,416

 
N/A

Operating income
85,469

 
101,307

 
59,079

 
N/A

Net income
84,703

 
62,684

 
58,910

 
N/A

__________________
(1)
For the period from initial contribution, May 2, 2011, to September 30, 2011.
N/A
The Partnership acquired a 33.33% membership interest in Ranch JV in December 2011.
5. Derivative Instruments
Policies. The Partnership established comprehensive risk management policies and procedures to monitor and manage the market risks associated with commodity prices, counterparty credit and interest rates. The General Partner is responsible for delegation of transaction authority levels, and the Audit and Risk Committee of the General Partner is responsible for the oversight of these risks, including monitoring exposure limits. The Audit and Risk Committee receives regular briefings on exposures and overall risk management in the context of market activities.
Commodity Price Risk. The Partnership is a net seller of NGLs, condensate and natural gas as a result of its gathering and processing operations. The prices of these commodities are impacted by changes in the supply and demand as well as market forces. Both the Partnership's profitability and cash flow are affected by the inherent volatility of these commodities which could adversely affect its ability to make distributions to its unitholders. The Partnership manages this commodity price exposure through an integrated strategy that includes management of its contract portfolio, matching sales prices of commodities with purchases, optimization of its portfolio by monitoring basis and other price differentials in operating areas, and the use of derivative contracts. In some cases, the Partnership may not be able to match pricing terms or cover its risk to price exposure with financial hedges, and it may be exposed to commodity price risk. Speculative positions with derivative contracts are prohibited under the Partnership's policies.
The Partnership has swap contracts settled against NGLs (ethane, propane, butane, and natural gasoline), condensate and natural gas market prices. The Partnership also has put options to protect against falling ethane prices.
On January 1, 2012, the Partnership de-designated its swap contracts and began accounting for these contracts using the mark-to-market method of accounting. As of September 30, 2012, the Partnership has $1.3 million in net hedging gains in AOCI which will be amortized to earnings over the next 1.5 years, $1.2 million of which will be over the next 12 months.

9
Table of Contents

Interest Rate Risk. The Partnership is exposed to variable interest rate risk as a result of borrowings under its revolving credit facility. The Partnership's $250 million interest rate swaps expired in April 2012.
Credit Risk. The Partnership's resale of NGLs, condensate and natural gas exposes it to credit risk, as the margin on any sale is generally a very small percentage of the total sales price. Therefore, a credit loss can be very large relative to overall profitability on these transactions. The Partnership attempts to ensure that it issues credit only to credit-worthy counterparties and that in appropriate circumstances any such extension of credit is backed by adequate collateral, such as a letter of credit or parental guarantee from a parent company.
The Partnership is exposed to credit risk from its derivative counterparties. The Partnership does not require collateral from these counterparties. The Partnership deals primarily with financial institutions when entering into financial derivatives, and utilizes master netting agreements that allow for netting of swap contract receivables and payables in the event of default by either party. If the Partnership's counterparties fail to perform under existing swap contracts, the Partnership's maximum loss as of September 30, 2012 would be $7.5 million. The Partnership has elected to present assets and liabilities under master netting agreements gross on the condensed consolidated balance sheets.
Embedded Derivatives. The Series A Preferred Units contain embedded derivatives which are required to be bifurcated and accounted for separately, such as the holders' conversion option and the Partnership's call option. These embedded derivatives are accounted for using mark-to-market accounting. The Partnership does not expect the embedded derivatives to affect its cash flows.
The Partnership’s derivative assets and liabilities, including credit risk adjustments, as of September 30, 2012 and December 31, 2011 are detailed below:
 
Assets
 
Liabilities
 
September 30,
2012
 
December 31, 2011
 
September 30,
2012
 
December 31, 2011
Derivatives designated as cash flow hedges:
 
 
 
 
 
 
 
Current amounts
 
 
 
 
 
 
 
Commodity contracts
$
—

 
$
4,065

 
$
—

 
$
10,065

Long-term amounts
 
 
 
 
 
 
 
Commodity contracts
—

 
474

 
—

 
63

Total cash flow hedging instruments
—

 
4,539

 
—

 
10,128

Derivatives not designated as cash flow hedges:
 
 
 
 
 
 
 
Current amounts
 
 
 
 
 
 
 
Commodity contracts
6,757

 
—

 
803

 
—

Ethane put options
1,030

 
309

 
—

 
—

Interest rate swap contracts
—

 
—

 
—

 
470

Long-term amounts
 
 
 
 
 
 
 
Commodity contracts
918

 
—

 
396

 
—

Embedded derivatives in Series A Preferred Units
—

 
—

 
29,094

 
39,049

Total derivatives not designated as cash flow hedges
8,705

 
309

 
30,293

 
39,519

Total derivatives
$
8,705

 
$
4,848

 
$
30,293

 
$
49,647


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Table of Contents

The Partnership’s statements of operations and comprehensive (loss) income for the three and nine months ended September 30, 2012 and 2011 were impacted by derivative instruments activities as follows:
 
 
 
 
Three Months Ended September 30,
 
 
 
 
2012
 
2011
Derivatives in cash flow hedging relationships:
 
 
 
 
Change in Value Recognized in
AOCI on Derivatives (Effective Portion)
Commodity derivatives
 
 
 
$
—

 
$
10,287

 
 
 
 
 
 
 
Derivatives in cash flow hedging relationships:
 
Location of Gain/(Loss)
Recognized in Income
 
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)
Commodity derivatives
 
Revenues
 
$
—

 
$
(5,282
)
 
 
 
 
 
 
 
Derivatives in cash flow hedging relationships:
 
Location of Gain/(Loss)
Recognized in Income
 
Amount of Gain/(Loss) Recognized in
Income on Ineffective Portion
Commodity derivatives
 
Revenues
 
$
—

 
$
21

 
 
 
 
 
 
 
Derivatives not designated in a hedging relationship:
 
Location of Gain/(Loss)
Recognized in Income
 
Amount of Gain/(Loss) from De-designation Amortized from AOCI into Income
Commodity derivatives
 
Revenues
 
$
(265
)
 
$
—

 
 
 
 
 
 
 
Derivatives not designated in a hedging relationship:
 
Location of Gain/(Loss)
Recognized in Income
 
Amount of Gain/(Loss) Recognized
in Income on Derivatives
Commodity derivatives
 
Revenues
 
$
(4,967
)
 
$
(119
)
Interest rate swap contracts
 
Interest expense, net
 
—

 
99

Embedded derivatives in Series A Preferred Units
 
Other income &  deductions, net
 
1,550

 
15,230

 
 
 
 
$
(3,417
)
 
$
15,210

 
 
 
 
Nine Months Ended September 30,
 
 
 
 
2012
 
2011
Derivatives in cash flow hedging relationships:
 
 
 
 
Change in Value Recognized in
AOCI on Derivatives (Effective Portion)
Commodity derivatives
 
 
 
$
—

 
$
(5,179
)
 
 
 
 
 
 
 
Derivatives in cash flow hedging relationships:
 
Location of Gain/(Loss)
Recognized in Income
 
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)
Commodity derivatives
 
Revenues
 
$
—

 
$
(14,276
)
 
 
 
 
 
 
 
Derivatives in cash flow hedging relationships:
 
Location of Gain/(Loss)
Recognized in Income
 
Amount of Gain/(Loss) Recognized in
Income on Ineffective Portion
Commodity derivatives
 
Revenues
 
$
—

 
$
(253
)
 
 
 
 
 
 
 
Derivatives not designated in a hedging relationship:
 
Location of Gain/(Loss)
Recognized in Income
 
Amount of Gain/(Loss) from De-designation Amortized from AOCI into Income
Commodity derivatives
 
Revenues
 
$
(6,089
)
 
$
—

 
 
 
 
 
 
 
Derivatives not designated in a hedging relationship:
 
Location of Gain/(Loss)
Recognized in Income
 
Amount of Gain/(Loss) Recognized
in Income on Derivatives
Commodity derivatives
 
Revenues
 
$
14,660

 
$
(107
)
Interest rate swap contracts
 
Interest expense, net
 
(12
)
 
(388
)
Embedded derivatives in Series A Preferred Units
 
Other income &  deductions, net
 
9,955

 
20,755

 
 
 
 
$
24,603

 
$
20,260


11
Table of Contents

6. Long-term Debt
Obligations in the form of senior notes and borrowings under the revolving credit facility are as follows:
 
September 30,
2012
 
December 31,
2011
Senior notes
$
1,265,429

 
$
1,355,147

Revolving loans
695,000

 
332,000

Total
1,960,429

 
1,687,147

Less: current portion
—

 
—

Long-term debt
$
1,960,429

 
$
1,687,147

Availability under revolving credit facility:
 
 
 
Total credit facility limit
$
1,150,000

 
$
900,000

Revolving loans
(695,000
)
 
(332,000
)
Letters of credit
(8,600
)
 
(19,000
)
Total available
$
446,400

 
$
549,000

Scheduled maturities of long-term debt at September 30, 2012 are as follows:
Years Ending December 31,
 
Amount
 
2012 (remainder)
 
$
—

  
2013
 
—

  
2014
 
695,000

  
2015
 
—

  
2016
 
162,500

 
Thereafter
 
1,100,000

 
Total
 
$
1,957,500

*
__________________
*
Excludes unamortized premiums of $2.9 million as of September 30, 2012.
Revolving Credit Facility. In August 2012, RGS exercised the accordion feature of the Fifth Amended and Restated Credit Agreement (the "Credit Agreement") to increase its commitments under the revolving credit facility by $250 million to a total of $1.15 billion. The new commitments will be available pursuant to the same terms and subject to the same interest rates and fees as the existing commitments under the Credit Agreement. The weighted average interest rate on the total amounts outstanding under the Partnership's revolving credit facility was 2.72% and 3.03% as of September 30, 2012 and 2011, respectively.
Senior Notes. In October 2012, the Partnership and Finance Corp. issued $700 million in senior notes that mature on April 15, 2023 (the “2023 Notes”). The 2023 Notes bear interest at 5.5% payable semi-annually in arrears on April 15 and October 15, commencing April 15, 2013. The proceeds were used to repay borrowings outstanding under the Partnership’s revolving credit facility.
At any time prior to October 15, 2015, the Partnership may redeem up to 35% of the 2023 Notes at a price equal to 105.5% plus accrued interest. Beginning on October 15 of the years indicated below, the Partnership may redeem all or part of the 2023 Notes at the redemption prices, expressed as percentages of the principal amount, set forth below:
October 15 of year ending:
 
Percentage of Redemption Price
2017
 
102.750%
2018
 
101.833%
2019
 
100.917%
2020 and thereafter
 
100.000%

12
Table of Contents

Upon a change of control, as defined in the indenture, followed by a rating decline within 90 days, each holder of the 2023 Notes will be entitled to require the Partnership to purchase all or a portion of its notes at a purchase price of 101% plus accrued interest and liquidated damages, if any. The Partnership's ability to purchase the notes upon a change of control will be limited by the terms of its debt agreements, including the Partnership's revolving credit facility.
The 2023 Notes contain various covenants that limit, among other things, the Partnership's ability, and the ability of certain of its subsidiaries, to:
•
incur additional indebtedness;
•
pay distributions on, or repurchase or redeem equity interests;
•
make certain investments;
•
incur liens;
•
enter into certain types of transactions with affiliates; and
•
sell assets, consolidate or merge with or into other companies
In May 2012, the Partnership exercised its option to redeem 35% or $87.5 million of its outstanding senior notes due 2016 at a price of 109.375% of the principal amount plus accrued interest.
At September 30, 2012, the Partnership was in compliance with all debt covenants.
Finance Corp., co-issuer for all of the Partnership’s senior notes, has no operations and will not have revenues other than as may be incidental. The senior notes due in years 2016, 2018, 2021 and 2023 are fully and unconditionally and jointly and severally guaranteed by all of the Partnership’s current consolidated subsidiaries, other than Finance Corp. and several minor subsidiaries, and by certain of its future subsidiaries. The senior notes and the guarantees are unsecured and rank equally with all of the Partnership’s and the guarantors’ existing and future unsecured obligations. The senior notes and the guarantees will be senior in right of payment to any of the Partnership’s and the guarantors’ future obligations that are, by their terms, expressly subordinated in right of payment to the notes and the guarantees. The senior notes and the guarantees will be effectively subordinated to the Partnership’s and the guarantors’ secured obligations, including the Partnership’s revolving credit facility, to the extent of the value of the assets securing such obligations.
7. Commitments and Contingencies
Legal. The Partnership is involved in various claims, lawsuits and audits by taxing authorities incidental to its business. These claims and lawsuits in the aggregate are not expected to have a material adverse effect on the Partnership’s business, financial condition, results of operations or cash flows.
Keyes Litigation. In August 2008, Keyes Helium Company, LLC (“Keyes”) filed suit against RGS, the Partnership, the General Partner and various other subsidiaries. Keyes entered into an output contract with the Partnership’s predecessor-in-interest in 1996 under which it purchased all of the helium produced at the Lakin, Kansas processing plant. In September 2004, the Partnership decided to shut down its Lakin plant and contract with a third party for the processing of volumes processed at Lakin; as a result, the Partnership no longer delivered any helium to Keyes. In its suit, Keyes alleges it is entitled to damages for the costs of covering its purchases of helium. On May 7, 2010, the jury rendered a verdict in favor of the Partnership. No damages were awarded to the Plaintiffs. Plaintiffs have appealed the verdict. The hearing on appeal took place on April 24, 2012. A decision is not expected for at least several months.
8. Series A Preferred Units
On September 2, 2009, the Partnership issued 4,371,586 Series A Preferred Units. As of September 30, 2012, the Series A Preferred Units were convertible to 4,651,884 common units, and if outstanding, are mandatorily redeemable on September 2, 2029 for $80 million plus all accrued but unpaid distributions and interest thereon. The Series A Preferred Units receive fixed quarterly cash distributions of $0.445 per unit if outstanding on the record dates of the Partnership’s common unit distributions. Holders can elect to convert Series A Preferred Units to common units at any time in accordance with the partnership agreement.

13
Table of Contents

The following table provides a reconciliation of the beginning and ending balances of the Series A Preferred Units for the nine months ended September 30, 2012:
 
Units
 
Amount
 
Outstanding at beginning of period
4,371,586

 
$
71,144

  
Accretion to redemption value
—

 
1,405

  
Outstanding at end of period
4,371,586

 
$
72,549

* 
__________________
*
This amount will be accreted to $80 million plus any accrued but unpaid distributions and interest by deducting amounts from partners’ capital over the remaining periods until the mandatory redemption date of September 2, 2029.
9. Related Party Transactions
Transactions with ETE and its subsidiaries. Under the service agreement with Services Co., the Partnership pays Services Co.’s direct expenses for services performed, plus an annual fee of $10 million, and receives the benefit of any cost savings recognized for these services. The services agreement has a five year term which expires May 26, 2015, subject to earlier termination rights in the event of a change in control, the failure to achieve certain cost savings for the Partnership or upon an event of default. The Partnership also, together with the General Partner and RGS, entered into an operation and service agreement (the “Operations Agreement”) with ETC. Under the Operations Agreement, ETC will perform certain operations, maintenance and related services reasonably required to operate and maintain certain facilities owned by the Partnership. Pursuant to the Operations Agreement, the Partnership will reimburse ETC for actual costs and expenses incurred in connection with the provision of these services based on an annual budget agreed-upon by both parties. The Operations Agreement automatically renews on a year-to-year basis upon expiration of the initial term. The Partnership incurred total service fees of $4.3 million and $4.2 million for the three months ended September 30, 2012 and 2011, respectively, and $12.9 million and $12.4 million for the nine months ended September 30, 2012 and 2011, respectively.
In conjunction with distributions by the Partnership on the basis of limited and general partner interests, ETE received cash distributions of $15.5 million and $14.4 million for the three months ended September 30, 2012 and 2011, respectively, and $46.4 million and $42.5 million for the nine months ended September 30, 2012 and 2011, respectively.
The Partnership's Gathering and Processing segment, in the ordinary course of business, gathers, processes, transports and sells natural gas and NGLs to subsidiaries of ETE and records the revenue in gas sales and NGL sales. The Partnership’s Contract Compression segment provides contract compression services to subsidiaries of ETP and records revenue in gathering, transportation and other fees. The Partnership’s Contract Compression segment sold compression equipment to a subsidiary of ETP for $0.3 million and $1.6 million for the three months ended September 30, 2012 and 2011, respectively, and $1.1 million and $7.9 million for the nine months ended September 30, 2012 and 2011. The Partnership’s Contract Compression segment purchased compression equipment from a subsidiary of ETP for $6.2 million and $24.3 million for the three and nine months ended September 30, 2011, respectively. During 2012, the Partnership's Contract Compression segment has made no purchases of compression equipment from subsidiaries of ETP.
Pursuant to the Partnership agreement, the General Partner receives a monthly reimbursement for all direct and indirect expenses incurred on behalf of the Partnership. Effective January 1, 2011, certain employees of the Partnership became employees of ETP, and the Partnership reimburses ETP for all direct and indirect expenses incurred on behalf of the Partnership related to those employees. Reimbursements were recorded to the General Partner for $12.9 million and $12.6 million during the three months ended September 30, 2012 and 2011, respectively, and $37.8 million and $47 million during the nine months ended September 30, 2012 and 2011, respectively, in the Partnership’s financial statements as operating expenses or general and administrative expenses. Reimbursements were also recorded to ETP for $9.4 million and $6.2 million during the three months ended September 30, 2012 and 2011, respectively, and $23.9 million and $14.8 million during the nine months ended September 30, 2012 and 2011, respectively, in the Partnership’s financial statements as operating expenses or general and administrative expenses.
Transactions with HPC. Under a Master Services Agreement with HPC, the Partnership operates and provides all employees and services for the operation and management of HPC. Related party general and administrative expenses reimbursed to the Partnership were $5.1 million and $4.2 million for the three months ended September 30, 2012 and 2011, respectively, and $14.4 million and $12.6 million for the nine months ended September 30, 2012 and 2011, respectively, which are recorded in gathering, transportation and other fees.
The Partnership’s Contract Compression segment provides contract compression services to HPC and records revenues in gathering, transportation and other fees. The Partnership also receives transportation services from HPC and records those as cost of sales.

14
Table of Contents

10. Segment Information
The Partnership has the following five reportable segments:
Gathering and Processing. The Partnership provides “wellhead-to-market” services to producers of natural gas, which include transporting raw natural gas from the wellhead through gathering systems, processing raw natural gas to separate NGLs from the raw natural gas and selling or delivering pipeline-quality natural gas and NGLs to various markets and pipeline systems. This segment also includes the Partnership's investment in Ranch JV, which processes natural gas delivered from the NGLs-rich Bone Spring and Avalon shale formations in west Texas. The Partnership initially included Ranch JV in the Joint Ventures segment upon formation in December 2011 until March 31, 2012, during which time Ranch JV's only activity was the construction of capital projects.
Joint Ventures. The Partnership's Joint Ventures segment includes the following:
◦
a 49.99% general partner interest in HPC, which owns RIGS, a 450 mile intrastate pipeline that delivers natural gas from northwest Louisiana to downstream pipelines and markets;
◦
a 50% membership interest in MEP, which owns an interstate natural gas pipeline with approximately 500 miles stretching from southeast Oklahoma through northeast Texas, northern Louisiana and central Mississippi to an interconnect with the Transcontinental Gas Pipe Line system in Butler, Alabama; and
◦
a 30% membership interest in Lone Star, an entity owning a diverse set of midstream energy assets including NGL pipelines, storage, fractionation and processing facilities located in the states of Texas, Mississippi and Louisiana.
Contract Compression. The Partnership owns and operates a fleet of compressors used to provide turn-key natural gas compression services for customer specific systems.
Contract Treating. The Partnership owns and operates a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and BTU management, to natural gas producers and midstream pipeline companies.
Corporate and Others. The Corporate and Others segment comprises a small regulated pipeline and the Partnership’s corporate offices.
The Partnership accounts for intersegment revenues as if the revenues were to third parties, exclusive of certain cost of capital charges.
Management evaluates the performance of each segment and makes capital allocation decisions through the separate consideration of segment margin and operation and maintenance expenses. Segment margin for the Gathering and Processing and the Corporate and Others segments is defined as total revenues, including service fees, less cost of sales. In the Contract Compression segment and Contract Treating segment, segment margin is defined as revenues less direct costs.
Management believes segment margin is an important measure because it directly relates to volume, commodity price changes, revenue generating horsepower and revenue generating gallons per minute. Operation and maintenance expenses are a separate measure used by management to evaluate performance of field operations. Direct labor, insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of operation and maintenance expenses. These expenses fluctuate depending on the activities performed during a specific period. The Partnership does not deduct operation and maintenance expenses from total revenues in calculating segment margin because management separately evaluates commodity volume and price changes in segment margin.

15
Table of Contents

Results for each segment are shown below:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2012
 
2011
 
2012
 
2011
External Revenues
 
 
 
 
 
 
 
Gathering and Processing
$
262,087

 
$
339,273

 
$
832,354

 
$
908,448

Joint Ventures (1)
—

 
—

 
—

 
—

Contract Compression
37,841

 
36,024

 
111,279

 
112,532

Contract Treating
8,707

 
10,573

 
25,230

 
29,848

Corporate and Others
5,247

 
4,397

 
14,894

 
13,189

Eliminations
—

 
—

 
—

 
—

Total
$
313,882

 
$
390,267

 
$
983,757

 
$
1,064,017

Intersegment Revenues
 
 
 
 
 
 
 
Gathering and Processing
$
—

 
$
—

 
$
—

 
$
—

Joint Ventures (1)
—

 
—

 
—

 
—

Contract Compression
4,407

 
3,339

 
12,968

 
12,809

Contract Treating
1,092

 
20

 
2,271

 
20

Corporate and Others
58

 
60

 
167

 
237

Eliminations
(5,557
)
 
(3,419
)
 
(15,406
)
 
(13,066
)
Total
$
—

 
$
—

 
$
—

 
$
—

Segment Margin
 
 
 
 
 
 
 
Gathering and Processing
$
59,392

 
$
64,716

 
$
210,143

 
$
169,011

Joint Ventures (1)
—

 
—

 
—

 
—

Contract Compression
39,380

 
37,957

 
116,381

 
116,370

Contract Treating
8,115

 
6,642

 
23,239

 
21,594

Corporate and Others
5,459

 
4,767

 
15,604

 
14,582

Eliminations
(5,345
)
 
(3,341
)
 
(14,959
)
 
(12,802
)
Total
$
107,001

 
$
110,741

 
$
350,408

 
$
308,755

Operation and Maintenance
 
 
 
 
 
 
 
Gathering and Processing
$
30,226

 
$
24,426

 
$
87,240

 
$
67,250

Joint Ventures (1)
—

 
—

 
—

 
—

Contract Compression
15,099

 
15,916

 
45,648

 
48,618

Contract Treating
1,180

 
902

 
2,846

 
2,311

Corporate and Others
115

 
41

 
473

 
129

Eliminations
(5,345
)
 
(3,335
)
 
(14,959
)
 
(12,802
)
Total
$
41,275

 
$
37,950

 
$
121,248

 
$
105,506

__________________
(1)
The Partnership does not record segment margin or operation and maintenance expenses for the Joint Ventures segment because it records its ownership percentages of the net income of its unconsolidated affiliates as income from unconsolidated affiliates in accordance with the equity method of accounting.

16
Table of Contents

The table below provides a reconciliation of total segment margin to income before income taxes:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2012

2011
 
2012
 
2011
Total segment margin
$
107,001

 
$
110,741

 
$
350,408

 
$
308,755

Operation and maintenance
(41,275
)
 
(37,950
)
 
(121,248
)
 
(105,506
)
General and administrative
(14,935
)
 
(17,350
)
 
(47,106
)
 
(54,010
)
Gain (loss) on asset sales, net
42

 
131

 
(1,542
)
 
(50
)
Depreciation and amortization
(45,881
)
 
(41,956
)
 
(142,519
)
 
(122,695
)
Income from unconsolidated affiliates
21,055

 
30,946

 
87,198

 
86,921

Interest expense, net
(28,567
)
 
(28,852
)
 
(86,058
)
 
(73,548
)
Loss on debt refinancing, net
—

 
—

 
(7,820
)
 
—

Other income and deductions, net
1,106

 
15,050

 
25,549

*
20,105

(Loss) income before income taxes
$
(1,454
)
 
$
30,760

 
$
56,862


$
59,972

__________________
*
Other income and deductions, net for the nine months ended September 30, 2012, included a one-time producer payment of $15.6 million related to an assignment of certain contracts.
The table below provides a listing of total assets reflected in the consolidated balance sheet for each segment:
 
September 30,
2012
 
December 31,
2011
Gathering and Processing
$
2,127,565

 
$
1,959,697

Joint Ventures
2,123,802

 
1,924,705

Contract Compression
1,421,377

 
1,405,600

Contract Treating
228,940

 
215,172

Corporate and Others
66,452

 
62,682

Total
$
5,968,136

 
$
5,567,856

11. Equity-Based Compensation
The Partnership’s LTIP for its employees, directors and consultants authorizes grants up to 5,865,584 common units. LTIP compensation expense of $1.2 million and $0.7 million, is recorded in general and administrative expense for the three months ended September 30, 2012 and 2011, respectively, and $3.5 million and $2.4 million for the nine months ended September 30, 2012 and 2011, respectively.
Common Unit Options. There was no common unit option activity for the nine months ended September 30, 2012. The aggregate intrinsic value and weighted average contractual term in years as of September 30, 2012 for the outstanding and exercisable common unit options was $0.3 million and 3.6 years, respectively. During the nine months ended September 30, 2011, the Partnership received $0.8 million in proceeds from the exercise of unit options.
 
 
 
 
 
 
 
 
Phantom Units. All phantom units granted prior to November 2010 were in substance two grants composed of (1) service condition grants with graded vesting over three years and (2) market condition grants with cliff vesting based upon the Partnership’s relative ranking in total unitholder return among 18 peer companies. Distributions related to these unvested phantom units will be accrued and paid upon vesting. All phantom units granted after November 2010 were service condition grants only with graded vesting over five years. Distributions related to these unvested phantom units will be paid concurrent with the Partnership’s distribution for common units.

17
Table of Contents

The following table presents phantom units activity for the nine months ended September 30, 2012:
Phantom Units
Units
 
Weighted Average Grant
Date Fair Value
Outstanding at beginning of period
1,086,393

 
$
24.51

Service condition grants
8,250

 
24.18

Vested service condition
(29,553
)
 
23.33

Vested market condition
(10,200
)
 
19.52

Forfeited service condition
(92,468
)
 
24.86

Forfeited market condition
(4,350
)
 
19.52

Outstanding at end of period
958,072

 
24.58

The Partnership expects to recognize $16.3 million of compensation expense related to non-vested phantom units over a period of 3.6 years.
12. Fair Value Measures
The Partnership's financial assets and liabilities measured at fair value on a recurring basis are derivatives related to interest rate swaps, commodity swaps, ethane put options and embedded derivatives in the Series A Preferred Units. Derivatives related to interest rate swaps, commodity swaps and ethane put options are valued using discounted cash flow techniques. These techniques incorporate Level 1 and Level 2 inputs such as future interest rates and commodity prices. These market inputs are utilized in the discounted cash flow calculation considering the instrument's term, notional amount, discount rate and credit risk and are classified as Level 2 in the hierarchy. Embedded derivatives related to Series A Preferred Units are valued using a binomial lattice model. The market inputs utilized in the model include credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected volatility, and are classified as Level 3 in the hierarchy.
The following table presents the Partnership's derivative assets and liabilities measured at fair value on a recurring basis:
 
Fair Value Measurements at September 30, 2012
 
Fair Value Measurements at December 31, 2011
 
Fair Value Total
 
Significant
Observable
Inputs
(Level 2)
 
Unobservable
Inputs
(Level 3)
 
Fair Value Total
 
Significant
Observable
Inputs
(Level 2)
 
Unobservable
Inputs
(Level 3)
Assets:
 
 
 
 
 
 
 
 
 
 
 
Commodity Derivatives:
 
 
 
 
 
 
 
 
 
 
 
Natural Gas
$
1,238

 
$
1,238

 
$
—

 
$
3,907

 
$
3,907

 
$
—

NGLs
3,927

 
3,927

 
—

 
94

 
94

 
—

Condensate
2,510

 
2,510

 
—

 
538

 
538

 
—

Ethane - Put Options
1,030

 
1,030

 
—

 
309

 
309

 
—

Total Assets
$
8,705

 
$
8,705

 
$
—

 
$
4,848

 
$
4,848

 
$
—

Liabilities:
 
 
 
 
 
 
 
 
 
 
 
Interest Rate Derivatives
$
—

 
$
—

 
$
—

 
$
470

 
$
470

 
$
—

Commodity Derivatives:
 
 
 
 
 
 
 
 
 
 
 
Natural Gas
923

 
923

 
—

 
—

 
—</