RGP-3.31.12-10Q
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 March 31, 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 170,104,818 common units outstanding as of May 2, 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
 
Bbls
Barrels
 
BTU
A unit of energy needed to raise the temperature of one pound of water by one degree Fahrenheit
 
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
 
LIBOR
London Interbank Offered Rate
 
Lone Star
Lone Star NGL LLC, a joint venture that is 30% owned by the Partnership and 70% owned by ETP
 
LTIP
Long-Term Incentive Plan
 
MEP
Midcontinent Express Pipeline LLC, a joint venture in which the Partnership currently owns a 50% interest
 
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, a joint venture that 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,” “will,” “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 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 "Part II – Other Information - Item 1A. Risk Factors" in this Quarterly Report on Form 10-Q.
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)
 
March 31,
2012
 
December 31,
2011
ASSETS
 
 
 
Current Assets:
 
 
 
Cash and cash equivalents
$
66,306

 
$
990

Trade accounts receivable, net of allowance of $864 and $1,190
43,169

 
43,917

Accrued revenues
99,730

 
68,011

Related party receivables
5,394

 
45,204

Derivative assets
5,671

 
4,374

Other current assets
25,320

 
24,628

Total current assets
245,590

 
187,124

Property, plant and equipment:
 
 
 
Property, plant and equipment
2,142,111

 
2,080,932

Less accumulated depreciation
(237,159
)
 
(195,404
)
Property, plant and equipment, net
1,904,952

 
1,885,528

Other Assets:
 
 
 
Investment in unconsolidated affiliates
2,007,414

 
1,924,705

Long-term derivative assets
324

 
474

Other, net of accumulated amortization of debt issuance costs of $12,057 and $10,186
38,011

 
39,353

Total other assets
2,045,749

 
1,964,532

Intangible assets, net of accumulated amortization of $52,174 and $44,856
733,565

 
740,883

Goodwill
789,789

 
789,789

TOTAL ASSETS
$
5,719,645

 
$
5,567,856

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

 
$
2,507

Trade accounts payable
50,340

 
73,462

Accrued cost of gas and liquids
76,375

 
84,943

Related party payables
25,235

 
12,625

Deferred revenues, including related party amounts of $28 and $41
13,728

 
16,225

Derivative liabilities
5,653

 
10,535

Other current liabilities
38,393

 
33,009

Total current liabilities
209,724

 
233,306

Long-term derivative liabilities
38,887

 
39,112

Other long-term liabilities
5,845

 
6,071

Long-term debt, net
1,604,915

 
1,687,147

Commitments and contingencies

 

Series A Preferred Units, redemption amount of $84,889 and $84,773
72,196

 
71,144

Partners’ capital and noncontrolling interest:
 
 
 
Common units
3,421,707

 
3,173,090

General partner interest
329,064

 
329,876

Accumulated other comprehensive loss
(1,094
)
 
(4,759
)
Total partners’ capital
3,749,677

 
3,498,207

Noncontrolling interest
38,401

 
32,869

Total partners’ capital and noncontrolling interest
3,788,078

 
3,531,076

TOTAL LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST
$
5,719,645

 
$
5,567,856

See accompanying notes to condensed consolidated financial statements
Regency Energy Partners LP
Condensed Consolidated Statements of Operations
(in thousands except unit data and per unit data)
(unaudited)
 
Three Months Ended March 31,
 
2012
 
2011
REVENUES
 
 
 
Gas sales, including related party amounts of $5,480 and $1,262
$
80,895

 
$
110,087

NGL sales, including related party amounts of $22,289 and $72,993
159,279

 
118,251

Gathering, transportation and other fees, including related party amounts of $6,651 and $6,216
100,314

 
81,836

Net realized and unrealized loss from derivatives
(1,184
)
 
(1,714
)
Other, including related party amounts of $1,478 and $1,866
18,595

 
8,792

Total revenues
357,899

 
317,252

OPERATING COSTS AND EXPENSES
 
 
 
Cost of sales, including related party amounts of $5,877 and $3,214
239,653

 
216,261

Operation and maintenance
40,981

 
33,672

General and administrative, including related party amounts of $4,300 and $3,905
15,695

 
18,997

Loss on asset sales, net
36

 
28

Depreciation and amortization
51,506

 
40,236

Total operating costs and expenses
347,871

 
309,194

OPERATING INCOME
10,028

 
8,058

Income from unconsolidated affiliates
31,958

 
23,808

Interest expense, net
(29,557
)
 
(20,007
)
Other income and deductions, net
16,522

 
2,414

INCOME BEFORE INCOME TAXES
28,951

 
14,273

Income tax expense (benefit)
51

 
(32
)
NET INCOME
$
28,900

 
$
14,305

Net income attributable to noncontrolling interest
(399
)
 
(231
)
NET INCOME ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP
$
28,501

 
$
14,074

Amounts attributable to Series A Preferred Units
2,997

 
1,993

General partner’s interest, including IDRs
2,488

 
1,292

Limited partners’ interest in net income
$
23,016

 
$
10,789

Basic and diluted net income per common unit:
 
 
 
Weighted average number of common units outstanding
158,690,035

 
137,304,783

Basic income per common unit
$
0.15

 
$
0.08

Diluted income per common unit
$
0.14

 
$
0.07

Distributions per common unit
$
0.46

 
$
0.445

See accompanying notes to condensed consolidated financial statements
Regency Energy Partners LP
Condensed Consolidated Statements of Comprehensive Income
(in thousands)
(unaudited)
 
Three Months Ended March 31,
 
2012
 
2011
Net income
$
28,900

 
$
14,305

Other comprehensive income (loss):
 
 
 
Net cash flow hedge amounts reclassified to earnings
3,665

 
3,429

Change in fair value of cash flow hedges

 
(16,996
)
Total other comprehensive income (loss)
3,665

 
(13,567
)
Comprehensive income
32,565

 
738

Comprehensive income attributable to noncontrolling interest
399

 
231

Comprehensive income attributable to Regency Energy Partners LP
$
32,166

 
$
507

See accompanying notes to condensed consolidated financial statements

Regency Energy Partners LP
Condensed Consolidated Statements of Cash Flows
(in thousands)
(unaudited)
 
Three Months Ended March 31,
 
2012
 
2011
OPERATING ACTIVITIES:
 
 
 
Net income
$
28,900

 
$
14,305

Adjustments to reconcile net income to net cash flows provided by operating activities:
 
 
 
Depreciation and amortization, including debt issuance cost, bond premium and excess fair value of unconsolidated affiliates amortization
54,491

 
43,111

Income from unconsolidated affiliates
(33,420
)
 
(25,270
)
Derivative valuation changes
(2,588
)
 
(4,686
)
Loss on asset sales, net
36

 
28

Unit-based compensation expenses
1,289

 
921

Cash flow changes in current assets and liabilities:
 
 
 
Trade accounts receivable, accrued revenues and related party receivables
7,348

 
7,300

Other current assets
(723
)
 
(2,096
)
Trade accounts payable, accrued cost of gas and liquids, related party payables and deferred revenues
(33,546
)
 
(12,145
)
Other current liabilities
5,384

 
10,613

Distributions received from unconsolidated affiliates
29,012

 
25,270

Other assets and liabilities
(116
)
 
15

Net cash flows provided by operating activities
56,067

 
57,366

INVESTING ACTIVITIES:
 
 
 
Capital expenditures
(75,842
)
 
(68,633
)
Capital contributions to unconsolidated affiliates
(80,540
)
 

Distribution in excess of earnings of unconsolidated affiliates
13,489

 
16,895

Proceeds from asset sales
13,058

 
6

Net cash flows used in investing activities
(129,835
)
 
(51,732
)
FINANCING ACTIVITIES:
 
 
 
Net (repayments) borrowings under revolving credit facility
(82,000
)
 
75,000

Debt issuance costs
(641
)
 
(184
)
Partner distributions
(76,139
)
 
(63,599
)
Disposition of assets between entities under common control in excess of historical cost

 
25

Contributions from noncontrolling interest
5,133

 

Bank overdraft
(2,507
)
 

Issuance of common units under LTIP, net of forfeitures and tax withholding
(119
)
 
393

Common unit offering, net of costs
297,302

 

Distributions to Series A Preferred Units
(1,945
)
 
(1,945
)
Net cash flows provided by financing activities
139,084

 
9,690

Net change in cash and cash equivalents
65,316

 
15,324

Cash and cash equivalents at beginning of period
990

 
9,400

Cash and cash equivalents at end of period
$
66,306

 
$
24,724

Non-cash Investing Activities:
 
 
 
Accrued capital expenditures and contributions to unconsolidated affiliates
$
36,080

 
$
16,605

See accompanying notes to condensed consolidated financial statements
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
 
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

 
297,302

 

 

 

 
297,302

Issuance of common units under LTIP, net of forfeitures and tax withholding
9,296

 
(119
)
 

 

 

 
(119
)
Unit-based compensation expenses

 
1,289

 

 

 

 
1,289

Partner distributions

 
(72,891
)
 
(3,248
)
 

 

 
(76,139
)
Accrued distributions to phantom units

 
(32
)
 

 

 

 
(32
)
Net income

 
26,013

 
2,488

 

 
399

 
28,900

Contributions from noncontrolling interest

 

 

 

 
5,133

 
5,133

Distributions to Series A Preferred Units

 
(1,911
)
 
(34
)
 

 

 
(1,945
)
Accretion of Series A Preferred Units

 
(1,034
)
 
(18
)
 

 

 
(1,052
)
Net cash flow hedge amounts reclassified to earnings

 

 

 
3,665

 

 
3,665

Balance - March 31, 2012
170,096,904

 
$
3,421,707

 
$
329,064

 
$
(1,094
)
 
$
38,401

 
$
3,788,078

See accompanying notes to condensed consolidated financial statements


1

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 and its subsidiaries are 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 managing general partner of the Partnership and 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 inter-company 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. During the quarter ended March 31, 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 three months ended March 31, 2011, the year ended December 31, 2011 and the period from May 26, 2010 to December 31, 2010 was $1.1 million, $4.4 million and $2.5 million, respectively.
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
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 $297.3 million. The Partnership will use 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. The Partnership expects to complete this redemption in May 2012.

2. 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 months ended March 31, 2012 and 2011:
 
Three Months Ended March 31,
 
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
$
23,016

 
158,690,035

 
$
0.15

 
$
10,789

 
137,304,783

 
$
0.08

Effect of Dilutive Securities:
 
 
 
 
 
 
 
 
 
 
 
Common unit options

 
21,129

 
 
 

 
31,056

 
 
Phantom units *

 
361,550

 
 
 

 
222,124

 
 
Series A Preferred Units

 

 
 
 
(582
)
 
4,584,192

 
 
Diluted income per unit
$
23,016

 
159,072,714

 
$
0.14

 
$
10,207

 
142,142,155

 
$
0.07

__________________
*
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
March 31, 2012
Series A Preferred Units
4,638,732

3. Investment in Unconsolidated Affiliates
As of March 31, 2012, the Partnership has a 49.99% general partner interest in HPC, 50% membership interest in MEP, 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 March 31, 2012 and December 31, 2011 is as follows:
 
March 31,
2012
 
December 31,
2011
HPC
$
675,734

 
$
682,046

MEP
605,303

 
613,942

Lone Star
712,965

 
628,717

Ranch JV
13,412

 

 
$
2,007,414

 
$
1,924,705

The following tables summarize the Partnership's investment activities in each of the unconsolidated affiliates for the three months ended March 31, 2012 and 2011:
 
Three Months Ended March 31, 2012
 
HPC
 
MEP
 
Lone Star
 
Ranch JV
Contributions to unconsolidated affiliates

 

 
79,840

 
13,412

Distributions from unconsolidated affiliates
16,159

 
19,386

 
6,956

 

Share of unconsolidated affiliates' net income
11,309

 
10,747

 
11,364

 

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

 

 

 
Three Months Ended March 31, 2011
 
HPC
 
MEP
 
Lone Star
 
Ranch JV
Contributions to unconsolidated affiliates
$

 
$

 
*
 
**
Distributions from unconsolidated affiliates
16,728

 
25,437

 
*
 
**
Share of unconsolidated affiliates' net income
15,075

 
10,195

 
*
 
**
Amortization of excess fair value of investment
(1,462
)
 

 
*
 
**
__________________
*
The Partnership acquired a 30% membership interest in Lone Star in May 2011.
**
The Partnership acquired a 33.33% membership interest in Ranch JV December 2011.
The following tables present selected income statement data for each of the unconsolidated affiliates, on a 100% basis, for the three months ended March 31, 2012 and 2011:
 
Three Months Ended March 31, 2012
 
HPC
 
MEP
 
Lone Star
 
Ranch JV
Total revenues
$
41,816

 
$
66,160

 
$
166,995

 
$

Operating income (loss)
22,969

 
34,389

 
38,554

 
(24
)
Net income (loss)
22,622

 
21,494

 
37,881

 
(24
)
 
Three Months Ended March 31, 2011
 
HPC
 
MEP
 
Lone Star
 
Ranch JV
Total revenues
$
48,649

 
$
64,824

 
*
 
**
Operating income
30,327

 
33,265

 
*
 
**
Net income
30,156

 
20,410

 
*
 
**
__________________
*
The Partnership acquired a 30% membership interest in Lone Star in May 2011.
**
The Partnership acquired a 33.33% membership interest in Ranch JV December 2011.
4. 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 market forces of supply and demand. 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 that settle 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 March 31, 2012, the Partnership has $1.1 million in net hedging losses in accumulated other comprehensive loss which will be amortized to earnings over the next 2 years. Over the next 12 months, the Partnership will amortize $1.5 million in net hedging losses to income.
Interest Rate Risk. The Partnership is exposed to variable interest rate risk as a result of borrowings under its revolving credit facility. As of March 31, 2012, total borrowings under the revolving credit facility were $250 million. 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, and because the margin on any sale is generally a very small percentage of the total sales price, 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 guarantee from a parent company.
The Partnership is exposed to credit risk from its derivative contract 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 March 31, 2012 would be $6 million which would be reduced by $3.5 million due to the netting feature. 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 March 31, 2012 and December 31, 2011 are detailed below:
 
Assets
 
Liabilities
 
March 31, 2012
 
December 31, 2011
 
March 31, 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
4,791

 

 
5,653

 

Ethane put options
880

 
309

 

 

Interest rate swap contracts

 

 

 
470

Long-term amounts
 
 
 
 
 
 
 
Commodity contracts
324

 

 
334

 

Embedded derivatives in Series A Preferred Units

 

 
38,553

 
39,049

Total derivatives not designated as cash flow hedges
5,995

 
309

 
44,540

 
39,519

Total derivatives
$
5,995

 
$
4,848

 
$
44,540

 
$
49,647

The Partnership’s statement of operations for the three months ended March 31, 2012 and 2011 were impacted by derivative instruments activities as follows:
 
 
 
 
Three Months Ended March 31,
 
 
 
 
2012
 
2011
Derivatives in cash flow hedging relationships:
 
 
 
 
Change in Value Recognized in
AOCI on Derivatives (Effective Portion)
Commodity derivatives
 
 
 
$

 
$
(16,996
)
 
 
 
 
 
 
 
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
 
$

 
$
(3,429
)
 
 
 
 
 
 
 
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
 
$

 
$
88

 
 
 
 
 
 
 
Derivatives in cash flow hedging relationships:
 
Location of Gain/(Loss)
Recognized in Income
 
Amount of Gain/(Loss) Recognized in
Income on Pre-Hedge Designation Fair Value
Commodity derivatives
 
Revenues
 
$

 
$
1,627

 
 
 
 
 
 
 
Derivatives not designated in a hedging relationship:
 
Location of Gain/(Loss)
Recognized in Income
 
Amount of Gain/(Loss) Amortized
from AOCI into Income
Commodity derivatives
 
Revenues
 
$
(3,665
)
 
$

 
 
 
 
 
 
 
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
 
$
2,481

 
$

Interest rate swap contracts
 
Interest expense, net
 
(12
)
 
(259
)
Embedded derivatives in Series A Preferred Units
 
Other income &  deductions, net
 
496

 
2,575

 
 
 
 
$
2,965

 
$
2,316

5. Long-term Debt
Obligations in the form of senior notes and borrowings under the revolving credit facility are as follows:
 
March 31,
2012
 
December 31,
2011
Senior notes
$
1,354,915

 
$
1,355,147

Revolving loans
250,000

 
332,000

Total
1,604,915

 
1,687,147

Less: current portion

 

Long-term debt
$
1,604,915

 
$
1,687,147

Availability under revolving credit facility:
 
 
 
Total credit facility limit
$
900,000

 
$
900,000

Revolving loans
(250,000
)
 
(332,000
)
Letters of credit
(11,500
)
 
(19,000
)
Total available
$
638,500

 
$
549,000

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

  
2013
 

  
2014
 
250,000

  
2015
 

  
2016
 
250,000

  
Thereafter
 
1,100,000

Total
 
$
1,600,000

  
__________________
*
Excludes unamortized premiums of $4.9 million as of March 31, 2012.
Revolving Credit Facility. The weighted average interest rate on the total amounts outstanding under the Partnership's revolving credit facility was 3.09% and 2.78% as of March 31, 2012 and 2011, respectively.
Senior Notes. In April 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 March 31, 2012, the Partnership was in compliance with all 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. Since the Partnership has no independent operations, the guarantees are fully unconditional and joint and several of its subsidiaries, except for a few minor subsidiaries, and the Partnership has not included condensed consolidated financial information of guarantors of the senior notes.
6. 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 several months.
7. Series A Preferred Units
On September 2, 2009, the Partnership issued 4,371,586 Series A Preferred Units. As of March 31, 2012, the Series A Preferred Units were convertible to 4,638,732 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.
The following table provides a reconciliation of the beginning and ending balances of the Series A Preferred Units for the three months ended March 31, 2012:
 
Units
 
Amount
 
Outstanding at beginning of period
4,371,586

 
$
71,144

  
Accretion to redemption value

 
1,052

  
Outstanding at end of period
4,371,586

 
$
72,196

__________________
*
This amount will be accreted to $80 million plus any accrued and unpaid distributions and interest by deducting amounts from partners’ capital over the remaining periods until the mandatory redemption date of September 2, 2029.
8. 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. Also, the Partnership, 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 $3.9 million for the three months ended March 31, 2012 and 2011, respectively.
In conjunction with distributions by the Partnership to the limited and general partner interests, ETE received cash distributions of $15.5 million and $14 million during the three months ended March 31, 2012 and 2011, respectively.
The Partnership's Gathering and Processing segment, in the ordinary course of business, 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 $0.8 million for the three months ended March 31, 2011.
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 of $13.8 million and $20.4 million were recorded to the General Partner during the three months ended March 31, 2012 and 2011, respectively, in the Partnership’s financial statements as operating expenses or general and administrative expenses. For the three months ended March 31, 2012 and 2011, respective reimbursements of $8.3 million and $5.5 million to ETP were recorded 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. The related party general and administrative expenses reimbursed to the Partnership was $4.2 million for each of the three months ended March 31, 2012 and 2011, 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 it as cost of sales.

9. 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.
Joint Ventures. The Partnership owns investments in four joint ventures:
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;
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; and
a 33.33% membership interest in Ranch JV, which, upon completion of construction in 2012, will process natural gas delivered from the NGLs-rich Bone Spring and Avalon shale formations in west Texas.
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. The Partnership does not record segment margin 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.
Results for each period, together with amounts related to balance sheets for each segment, are shown below:
 
Three Months Ended March 31,
 
2012
 
2011
External Revenues
 
 
 
Gathering and Processing
$
307,167

 
$
265,972

Joint Ventures

 

Contract Compression
37,201

 
38,436

Contract Treating
9,135

 
8,433

Corporate and Others
4,396

 
4,411

Eliminations

 

Total
$
357,899

 
$
317,252

Intersegment Revenues
 
 
 
Gathering and Processing
$

 
$

Joint Ventures

 

Contract Compression
4,129

 
6,553

Contract Treating
494

 

Corporate and Others
56

 
67

Eliminations
(4,679
)
 
(6,620
)
Total
$

 
$

Segment Margin
 
 
 
Gathering and Processing
$
71,335

 
$
53,800

Joint Ventures

 

Contract Compression
38,986

 
41,440

Contract Treating
7,883

 
7,251

Corporate and Others
4,648

 
5,053

Eliminations
(4,606
)
 
(6,553
)
Total
$
118,246

 
$
100,991

Operation and Maintenance
 
 
 
Gathering and Processing
$
28,223

 
$
22,942

Joint Ventures

 

Contract Compression
16,407

 
16,504

Contract Treating
844

 
734

Corporate and Others
113

 
45

Eliminations
(4,606
)
 
(6,553
)
Total
$
40,981

 
$
33,672

The table below provides a reconciliation of total segment margin to income before income taxes:
 
Three Months Ended March 31,
 
2012

2011
Total segment margin
$
118,246

 
$
100,991

Operation and maintenance
(40,981
)
 
(33,672
)
General and administrative
(15,695
)
 
(18,997
)
Loss on asset sales, net
(36
)
 
(28
)
Depreciation and amortization
(51,506
)
 
(40,236
)
Income from unconsolidated affiliates
31,958

 
23,808

Interest expense, net
(29,557
)
 
(20,007
)
Other income and deductions, net
16,522

*
2,414

Income before income taxes
$
28,951

 
$
14,273

__________________
*
Other income and deductions, net for the three months ended March 31, 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 assets reflected in the consolidated balance sheet for each segment:
 
March 31,
2012
 
December 31,
2011
Gathering and Processing
$
1,978,072

 
$
1,959,697

Joint Ventures
2,007,414

 
1,924,705

Contract Compression
1,395,797

 
1,405,600

Contract Treating
211,593

 
215,172

Corporate and Others
126,769

 
62,682

Total
$
5,719,645

 
$
5,567,856

10. 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 $1.3 million and $0.9 million, is recorded in general and administrative expense for the three months ended March 31, 2012 and 2011, respectively.
Common Unit Options. There was no common unit option activity for the three months ended March 31, 2012. The aggregate intrinsic value and weighted average contractual term in years as of March 31, 2012 for the outstanding and exercisable common unit options was $0.5 million and 4.1 years, respectively. During the three months ended March 31, 2011, the Partnership received $0.5 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 20 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.
The following table presents phantom units activity for the three months ended March 31, 2012:
Phantom Units
Units
 
Weighted Average Grant
Date Fair Value
Outstanding at beginning of period
1,086,393

 
$
24.51

Service condition grants
4,000

 
26.24

Vested service condition
(13,039
)
 
20.65

Forfeited service condition
(15,950
)
 
24.81

Outstanding at end of period
1,061,404

 
24.56

The Partnership expects to recognize $19.1 million of compensation expense related to non-vested phantom units over a period of 4.1 years.
11. 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 March 31, 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
$
4,677

 
$
4,677

 
$

 
$
3,907

 
$
3,907

 
$

NGLs
394

 
394

 

 
94

 
94

 

Condensate
44

 
44

 

 
538

 
538

 

Ethane - Put Options
880

 
880

 

 
309

 
309

 

Total Assets
$
5,995

 
$
5,995

 
$

 
$
4,848

 
$
4,848

 
$

Liabilities:
 
 
 
 
 
 
 
 
 
 
 
Interest Rate Derivatives
$

 
$

 
$

 
$
470

 
$
470

 
$

Commodity Derivatives:
 
 
 
 
 
 
 
 
 
 
 
Natural Gas

 

 

 

 

 

NGLs
3,809

 
3,809

 

 
8,561

 
8,561

 

Condensate
2,178

 
2,178

 

 
1,567

 
1,567

 

Embedded Derivatives in Series A Preferred Units
38,553

 

 
38,553

 
39,049

 

 
39,049

Total Liabilities
$
44,540

 
$
5,987

 
$
38,553

 
$
49,647

 
$
10,598

 
$
39,049

The following table presents the material unobservable inputs used to estimate the fair value of the embedded derivatives in the Series A Preferred Units:
Unobservable Input
 
 
March 31,
2012
Credit Spread
 
 
6.89
%
Volatility
 
 
16.06
%
Changes in the Partnership's cost of equity and U.S. Treasury yields would cause a change in the credit spread used to value the embedded derivatives. Changes in the Partnership's historical unit price volatility would cause a change in the volatility used to value the embedded derivatives.
The following table presents the changes in Level 3 derivatives measured on a recurring basis for the three months ended March 31, 2012. There were no transfers between the fair value hierarchy levels for the three months ended March 31, 2012.
 
Embedded Derivatives in Series A Preferred Units
Balance at December 31, 2011
$
39,049

Change in fair value
(496
)
Balance at March 31, 2012
$
38,553

The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximates fair value due to their short-term maturities. Long-term debt, other than the senior notes, is comprised of borrowings under which interest accrues under a floating interest rate structure. Accordingly, the carrying value approximates fair value.
The following table presents the estimated fair value of senior notes, based on third party market value quotations (Level 1), as of March 31, 2012 and December 31, 2011:
Outstanding Senior Notes
 
March 31,
2012
 
December 31,
2011
$250 million senior notes due 2016
 
$
275,313

 
$
276,250

$600 million senior notes due 2018
 
634,128

 
643,500

$500 million senior notes due 2021
 
524,750

 
516,250


2

Table of Contents

Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
(Tabular dollar amounts are in thousands)
The following discussion analyzes our financial condition and results of operations. You should read the following discussion of our financial condition and results of operations in conjunction with our historical condensed consolidated financial statements and the notes included elsewhere in this document.
OVERVIEW. We are a growth-oriented publicly-traded Delaware limited partnership formed in 2005 engaged in the gathering and processing, contract compression, treating and transportation of natural gas and the transportation, fractionation and storage of NGLs. We focus on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus, Bone Spring and Avalon shales and the mid-continent region. Our assets are located in Texas, Louisiana, Arkansas, Pennsylvania, California, Mississippi, Alabama, West Virginia and the mid-continent region of the United States, which includes Kansas, Colorado and Oklahoma.
OUR OPERATIONS. We divide our operations into five business segments:
Gathering and Processing. We provide “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 and selling or delivering the pipeline-quality natural gas and NGLs to various markets and pipeline systems.
Joint Ventures. We own investments in four joint ventures:
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;
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; and
a 33.33% membership interest in Ranch JV, which, upon completion of construction in 2012, will process natural gas delivered from the NGLs-rich Bone Spring and Avalon shale formations in west Texas.
Contract Compression. We own and operate a fleet of compressors used to provide turn-key natural gas compression services for customer specific systems.
Contract Treating. We own and operate 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. Our Corporate and Others segment comprises a small regulated pipeline and our corporate offices.
HOW WE EVALUATE OUR OPERATIONS. Management uses a variety of financial and operational measurements to analyze our performance. We view these measures as important tools for evaluating the success of our operations and review these measurements on a monthly basis for consistency and trend analysis. These measures include volumes, segment margin, total segment margin, adjusted segment margin, adjusted total segment margin and operation and maintenance expense on a segment and company-wide basis and EBITDA and adjusted EBITDA on a company-wide basis.
Volumes. We must continually obtain new supplies of natural gas to maintain or increase throughput volumes on our gathering and processing systems. Our ability to maintain existing supplies of natural gas and obtain new supplies is affected by (i) the level of workovers or recompletions of existing connected wells and successful drilling activity in areas currently dedicated to our gathering and processing systems, (ii) our ability to compete for volumes from successful new wells in other areas and (iii) our ability to obtain natural gas that has been released from other commitments. We routinely monitor producer activity in the areas served by our gathering and processing systems to pursue new supply opportunities.
Segment Margin and Total Segment Margin. We define segment margin, generally, as revenues minus cost of sales. We calculate our Gathering and Processing segment margin and Corporate and Others segment margin as our revenues generated from operations less the cost of natural gas and NGLs purchased and other cost of sales, including third-party transportation and processing fees.

3

Table of Contents

We do not record segment margin for the Joint Ventures segment because we record our ownership percentages of the net income of our unconsolidated affiliates as income from unconsolidated affiliates in accordance with the equity method of accounting.
We calculate our Contract Compression segment margin as our revenues generated from our contract compression operations minus direct costs, primarily compressor unit repairs, associated with those revenues.
We calculate our Contract Treating segment margin as revenues generated from our contract treating operations minus direct costs associated with those revenues.
We calculate total segment margin as the total of segment margin of our segments, less intersegment eliminations.
Adjusted Segment Margin and Adjusted Total Segment Margin. We define adjusted segment margin as segment margin adjusted for non-cash (gains) losses from commodity derivatives. Our adjusted total segment margin equals the sum of our operating segments' adjusted segment margins or segment margins, including intersegment eliminations. Adjusted segment margin and adjusted total segment margin are included as supplemental disclosures because they are primary performance measures used by management because they represent the results of product purchases and sales, a key component of our operations.
Revenue Generating Horsepower. Revenue generating horsepower is the primary driver for revenue growth in our contract compression segment, and it is also the primary measure for evaluating our operational efficiency. Revenue generating horsepower is the total horsepower that our Contract Compression segment owns and operates for external customers. It does not include horsepower under contract that is not generating revenue or idle horsepower.
Revenue Generating Gallons per Minute (GPM). Revenue generating GPM is the primary driver for revenue growth of the treating business in our contract treating segment. GPM is used as a measure of the treating capacity of an amine plant. Revenue generating GPM is our total GPM under contract less GPM that is not generating revenues.
Operation and Maintenance Expense. Operation and maintenance expense is a separate measure that we use to evaluate operating performance of field operations. Direct labor, insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of our operating and maintenance expense. These expenses are largely independent of the volumes through our systems but fluctuate depending on the activities performed during a specific period. We do not deduct operation and maintenance expenses from total revenues in calculating segment margin because we use segment margin to separately evaluate commodity volume and price changes.
EBITDA and Adjusted EBITDA. We define EBITDA as net income (loss) plus interest expense, net, income tax expense and depreciation and amortization expense. We define adjusted EBITDA as EBITDA plus or minus the following:
non-cash loss (gain) from commodity and embedded derivatives;
non-cash unit based compensation;
loss (gain) on asset sales, net;
loss on debt refinancing;
other non-cash (income) expense, net;
net income attributable to noncontrolling interest; and
our interest in adjusted EBITDA from unconsolidated affiliates less income from unconsolidated affiliates.
These measures are used as supplemental measures by our management and by external users of our financial statements such as investors, banks, research analysts and others, to assess:
financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make cash distributions to our unitholders and General Partner;
our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and
the viability of acquisitions and capital expenditure projects.

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Neither EBITDA nor adjusted EBITDA should be considered as an alternative to, or more meaningful than, net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP. EBITDA is the starting point in determining cash available for distribution, which is an important non-GAAP financial measure for a publicly traded partnership.
The following table presents a reconciliation of EBITDA and adjusted EBITDA to net cash flows provided by operating activities and to net income (loss) for the Partnership:
 
Three Months Ended March 31,
Reconciliation of “Adjusted EBITDA” to net cash flows provided by operating activities and net income
2012
 
2011
Net cash flows provided by operating activities
$
56,067

 
$
57,366

Add (deduct):
 
 
 
Depreciation and amortization, including debt issuance cost, bond premium and excess fair value of unconsolidated affiliates amortization
(54,491
)
 
(43,111
)
Income from unconsolidated affiliates
33,420

 
25,270

Derivative valuation change
2,588

 
4,686

Loss on asset sales, net
(36
)
 
(28
)
Unit-based compensation expenses
(1,289
)
 
(921
)
Trade accounts receivable, accrued revenues and related party receivables
(7,348
)
 
(7,300
)
Other current assets
723

 
2,096

Trade accounts payable, accrued cost of gas and liquids, related party payables and deferred revenues
33,546

 
12,145

Other current liabilities
(5,384
)
 
(10,613
)
Distributions received from unconsolidated affiliates
(29,012
)
 
(25,270
)
Other assets and liabilities
116

 
(15
)
Net income
28,900

 
14,305

Add (deduct):
 
 
 
Interest expense, net
29,557

 
20,007

Depreciation and amortization expense
51,506

 
40,236

Income tax expense (benefit)
51

 
(32
)
EBITDA
110,014

 
74,516

Add (deduct):
 
 
 
Non-cash gain from commodity and embedded derivatives
(2,115
)
 
(4,290
)
Unit-based compensation expenses
1,289

 
921

Loss on asset sales, net
36

 
28

Income from unconsolidated affiliates
(31,958
)
 
(23,808
)
Partnership’s interest in unconsolidated affiliates' adjusted EBITDA
57,218

 
44,459

Other income, net
(434
)
 
(89
)
Adjusted EBITDA
$
134,050

 
$
91,737


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The following tables present reconciliations of net income to adjusted EBITDA for our unconsolidated affiliates, on a 100% basis, and the Partnership's interest in adjusted EBITDA for the three months ended March 31, 2012 and 2011:
 
Three Months Ended March 31, 2012
 
HPC
 
MEP
 
Lone Star
 
Ranch JV
 
Total
Net income (loss)
$
22,622

 
$
21,494

 
$
37,881

 
$
(24
)
 


Add:
 
 

 
 
 
 
 
 
Depreciation and amortization
9,094

 
17,364

 
12,270

 

 
 
Interest expense, net
480

 
12,894

 

 

 
 
Other expenses

 

 
673

 

 
 
Adjusted EBITDA
32,196

 
51,752

 
50,824

 
(24
)
 

Ownership interest
49.99
%
 
50
%
 
30
%
 
33.33
%
 
 
Partnership's interest in adjusted EBITDA
$
16,095

 
$
25,876

 
$
15,247

 
$

 
$
57,218

 
Three Months Ended March 31, 2011
 
HPC
 
MEP
 
Lone Star
 
Ranch JV
 
Total
Net income
$
30,156

 
$
20,410

 
N/A
 
N/A
 
 
Add:
 
 
 
 
 
 
 
 
 
Depreciation and amortization
8,082

 
17,377

 
N/A
 
N/A
 
 
Interest expense, net
136

 
12,855

 
N/A
 
N/A
 
 
Other expenses
11

 

 
N/A
 
N/A
 
 
Adjusted EBITDA
38,385

 
50,642

 
N/A
 
N/A
 
 
Ownership interest
49.99
%
 
49.9
%
 
N/A
 
N/A
 
 
Partnership's interest in adjusted EBITDA
$
19,189

 
$
25,270

 
$

 
$

 
$
44,459

__________________
N/A
We acquired a 30% membership interest in Lone Star in May 2011. We acquired a 33.33% membership interest in Ranch JV in December 2011.
The following table presents a reconciliation of total segment margin and adjusted total segment margin to net income for the three month periods ended March 31, 2012 and 2011 for the Partnership:
 
Three Months Ended March 31,
 
2012
 
2011
Net income
$
28,900

 
$
14,305

Add (deduct):
 
 
 
Operation and maintenance
40,981

 
33,672

General and administrative
15,695

 
18,997

Loss on asset sales, net
36

 
28

Depreciation and amortization
51,506

 
40,236

Income from unconsolidated affiliates
(31,958
)
 
(23,808
)
Interest expense, net
29,557

 
20,007

Other income and deductions, net
(16,522
)
 
(2,414
)
Income tax expense (benefit)
51

 
(32
)
Total segment margin
118,246

 
100,991

Add:
 
 
 
Non-cash gain from commodity derivatives
(1,619
)
 
(1,715
)
Adjusted total segment margin
$
116,627

 
$
99,276




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RESULTS OF OPERATIONS
Three Months Ended March 31, 2012 vs. Three Months Ended March 31, 2011
 
Three Months Ended March 31,
 
 
 
 
 
2012
 
2011
 
Change
 
Percent

Total revenues
$
357,899

 
$
317,252

 
$
40,647

 
13
%
Cost of sales
239,653

 
216,261

 
(23,392
)
 
11

Total segment margin (1)
118,246

 
100,991

 
17,255

 
17

Operation and maintenance
40,981

 
33,672

 
(7,309
)
 
22

General and administrative
15,695

 
18,997

 
3,302

 
17

Loss on asset sales, net
36

 
28

 
(8
)
 
29

Depreciation and amortization
51,506

 
40,236

 
(11,270
)
 
28

Operating income
10,028

 
8,058

 
1,970

 
24

Income from unconsolidated affiliates
31,958

 
23,808

 
8,150

 
34

Interest expense, net
(29,557
)
 
(20,007
)
 
(9,550
)
 
48

Other income and deductions, net
16,522

 
2,414

 
14,108

 
584

Income before income taxes
28,951

 
14,273

 
14,678

 
103

Income tax expense (benefit)
51

 
(32
)
 
(83
)
 
259

Net income
28,900

 
14,305

 
14,595

 
102

Net income attributable to noncontrolling interest
(399
)
 
(231
)
 
(168
)
 
73

Net income attributable to Regency Energy Partners LP
$
28,501

 
$
14,074

 
$
14,427

 
103

Gathering and processing segment margin
$
71,335

 
$
53,800

 
$
17,535

 
33

Non-cash gain from commodity derivatives
(1,619
)
 
(1,715
)
 
96

 
6

Adjusted gathering and processing segment margin
69,716

 
52,085

 
17,631

 
34

Contract compression segment margin (2)
38,986

 
41,440

 
(2,454
)
 
6

Contract treating segment margin (2)
7,883

 
7,251

 
632

 
9

Corporate and others segment margin
4,648

 
5,053

 
(405
)
 
8

Intersegment eliminations (2)
(4,606
)
 
(6,553
)
 
1,947

 
30

Adjusted total segment margin
$
116,627

 
$
99,276

 
$
17,351

 
17
%
__________________
(1)
For a reconciliation of segment margin to the most directly comparable financial measure calculated and presented in accordance with GAAP, see the reconciliation provided above.
(2)
Contract Compression and Contract Treating segment margin includes intersegment revenues of $4.6 million and $6.6 million for the three months ended March 31, 2012 and 2011, respectively. These intersegment revenues were eliminated upon consolidation.
Net Income Attributable to Regency Energy Partners LP. Our income increased to $28.5 million for the three months ended March 31, 2012 from $14.1 million for the three months ended March 31, 2011. The major components of this change were as follows:
$17.3 million increase in total segment margin primarily due to a $17.5 million increase in Gathering and Processing segment margin related to additional volumes in south and west Texas and in north Louisiana;
$14.1 million increase in other income and deductions, net primarily due to a $15.6 million one-time producer payment received in March 2012 related to an assignment of certain contracts;
$8.2 million increase in income from unconsolidated affiliates primarily due to our acquisition of a 30% interest in Lone Star in May 2011;
$3.3 million decrease in general and administrative expenses primarily due to decreases in employee related costs, office expenses, and legal fees; offset by
$11.3 million increase in depreciation and amortization expense primarily related to the completion of various organic growth projects since March 2011 as well as an out of period adjustment of $6.9 million;

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$9.6 million increase in interest expense primarily related to the interest associated with the $500 million senior notes we issued in May 2011; and
$7.3 million increase in operation and maintenance expense primarily due to increases in compressor maintenance costs, employee expenses, plant operating expenses and consumable products.
Adjusted Total Segment Margin. Adjusted total segment margin increased to $116.6 million in the three months ended March 31, 2012 from $99.3 million in the three months ended March 31, 2011. The major components of this change were as follows:
Adjusted Gathering and Processing segment margin increased to $69.7 million during the three months ended March 31, 2012 from $52.1 million for the three months ended March 31, 2011 primarily due to volume growth in south and west Texas and in north Louisiana. Total Gathering and Processing throughput increased to 1,387,000 MMBtu/d during the three months ended March 31, 2012 from 1,006,000 MMBtu/d during the three months ended March 31, 2011. Total NGL gross production increased to 38,000 Bbls/d during the three months ended March 31, 2012 from 28,000 Bbls/d during the three months ended March 31, 2011;
Contract Compression segment margin decreased to $39 million in the three months ended March 31, 2012 from $41.4 million in the three months ended March 31, 2011, which was primarily due to the decrease in intersegment transactions with the Gathering and Processing segment as a result of the transfer of certain compression units from the Contract Compression segment to the Gathering and Processing segment in the second quarter of 2011. The decrease was also due to a slight decrease in revenue generating horsepower from external customers. As of March 31, 2012, our Contract Compression segment's total revenue generating horsepower was 761,000 compared to 762,000 as of March 31, 2011;
Contract Treating segment margin increased to $7.9 million for the three months ended March 31, 2012 from $7.3 million for the three months ended March 31, 2011. Revenue generating GPM as of March 31, 2012 and March 31, 2011 was 3,370 and 3,268, respectively; and
Intersegment eliminations decreased to $4.6 million in the three months ended March 31, 2012 from $6.6 million in the three months ended March 31, 2011. The decrease was primarily due to a decrease in transactions between the Gathering and Processing and the Contract Compression segments as a result of the transfer of certain compression units from the Contract Compression segment to the Gathering and Processing segment in the second quarter of 2011.
Operation and Maintenance. Operation and maintenance expense increased to $41 million in the three months ended March 31, 2012 from $33.7 million during the three months ended March 31, 2011. The change was primarily due to the following:
$3.2 million increase in compressor maintenance expense primarily due to an increase in chemical products, lube oil and materials costs;
$1.8 million increase in employee expenses primarily due to organic growth projects in south and west Texas;
$1.3 million increase in plant operating expenses primarily related to increased activity in south Texas; and
$0.8 million increase in ad valorem taxes.
General and Administrative. General and administrative expense decreased to $15.7 million in the three months ended March 31, 2012 from $19 million during the three months ended March 31, 2011. The change was primarily due to the following:
$1.3 million decrease in employee related costs due to the shared services integration and subsequent reduction in employee headcount; and
$1.9 million decrease in office expenses primarily related to a decrease in office expense and legal fees.
Depreciation and Amortization. Depreciation and amortization expense increased to $51.5 million in the three months ended March 31, 2012 from $40.2 million in the three months ended March 31, 2011. This increase was the result of $4.4 million of additional depreciation and amortization expense due to the completion of various organic growth projects since April 2011 and $6.9 million related to an “out-of-period” adjustment for all periods subsequent to May 26, 2010 (the “Successor” period as described in our Form 10-K for the year ended December 31, 2011) related to our Contract Compression segment to adjust the estimated useful lives of certain assets to comply with our policy. The amounts related to the year ended December 31, 2011 and to the period from May 26, 2010 to December 31, 2010 were $4.4 million and $2.5 million, respectively. Had these amounts been recorded to their respective period, the depreciation and amortization expense for the quarters ended March 31, 2012 and 2011 would have been $44.6 million and $41.3 million, respectively.

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Table of Contents

Income from Unconsolidated Affiliates. Income from unconsolidated affiliates increased to $32 million for the three months ended March 31, 2012 from $23.8 million for the three months ended March 31, 2011. The schedule below summarizes the components of income from unconsolidated affiliates and our ownership interest for the three months ended March 31, 2012 and 2011, respectively:
 
 
Three Months Ended March 31, 2012
 
 
HPC
 
MEP
 
Lone Star
 
Ranch JV
 
Total
Net income (loss)
 
$
22,622

 
$
21,494

 
$
37,881

 
$
(24
)
 
$
81,973

Ownership interest
 
49.99
%
 
50
%
 
30
%
 
33.33
%
 
N/M

Share of unconsolidated affiliates’ net income
 
11,309
</