Form 10-Q
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2011

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: 000-51757

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  x    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  x    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   x    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  x

The issuer had 145,843,942 common units outstanding as of July 29, 2011.

 

 

 


Table of Contents

FORM 10-Q

INDEX

Regency Energy Partners LP

 

PART I – FINANCIAL INFORMATION

  

ITEM 1.

 

FINANCIAL STATEMENTS (Unaudited)

  

Condensed Consolidated Balance Sheets

     2   

Condensed Consolidated Statements of Operations

     3   

Condensed Consolidated Statements of Comprehensive Income (Loss)

     5   

Condensed Consolidated Statements of Cash Flows

     6   

Condensed Consolidated Statement of Partners’ Capital and Noncontrolling Interest

     7   

Notes to Condensed Consolidated Financial Statements

     8   

ITEM 2.

  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS      24   

ITEM 3.

 

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     35   

ITEM 4.

 

CONTROLS AND PROCEDURES

     36   

PART II – OTHER INFORMATION

  

ITEM 1.

 

LEGAL PROCEEDINGS

     37   

ITEM 1A.

 

RISK FACTORS

     37   

ITEM 2.

 

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

     37   

ITEM 3.

 

DEFAULTS UPON SENIOR SECURITIES

     37   

ITEM 4.

 

[REMOVED AND RESERVED]

     37   

ITEM 5.

 

OTHER INFORMATION

     37   

ITEM 6.

 

EXHIBITS

     38   

SIGNATURE

     39   

 

i


Table of Contents

Introductory Statement

References in this report to the “Partnership,” “we,” “our,” “us” and similar terms, when used in an historical context, refer to Regency Energy Partners LP and its subsidiaries. When used in the present tense or prospectively, these terms refer to the Partnership 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
Bcf   One billion cubic feet
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.
ETE GP   ETE GP Acquirer LLC
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
GE EFS   General Electric Energy Financial Services, combined with Regency GP Acquirer LP and Regency LP
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
GP Seller   Regency GP Acquirer, L.P.
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
IRS   Internal Revenue Service
LDH   LDH Energy Asset Holdings LLC
LIBOR   London Interbank Offered Rate
Lone Star   Lone Star NGL LLC, a joint venture that is 70% owned by ETP and 30% owned by the Partnership
LTIP   Long-Term Incentive Plan
MEP   Midcontinent Express Pipeline LLC, a joint venture in which the Partnership owns a 49.9% interest
MMbtu   One million BTUs
NGLs   Natural gas liquids, including ethane, propane, normal butane, iso butane and natural gasoline
NYMEX   New York Mercantile Exchange
Partnership   Regency Energy Partners LP
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
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 natural gas liquids;

 

   

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;

 

   

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 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, 2010 Annual Report on Form 10-K and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2011.

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

As disclosed in Note 1, on May 26, 2010, GP Seller sold all of the outstanding membership interests of the Partnership’s General Partner to ETE, effecting a change in control of the Partnership. In connection with this transaction, the Partnership’s assets and liabilities were adjusted to fair value at the acquisition date by application of “push-down” accounting. As a result, the Partnership’s unaudited condensed consolidated financial statements and certain footnote disclosures are presented in two distinct periods to indicate the application of two different bases of accounting between the periods presented: (1) the period prior to the acquisition date (May 26, 2010), identified as “Predecessor” and (2) the period from May 26, 2010 forward, identified as “Successor.”

 

1


Table of Contents

Regency Energy Partners LP

Condensed Consolidated Balance Sheets

(in thousands)

(unaudited)

 

     June 30,
2011
    December 31,
2010
 
ASSETS     

Current Assets:

    

Cash and cash equivalents

   $ 3,105      $ 9,400   

Trade accounts receivable, net of allowance of $465 and $297

     36,740        35,212   

Accrued revenues

     85,195        74,017   

Related party receivables

     34,587        32,342   

Derivative assets

     1,075        2,650   

Other current assets

     8,772        7,384   
  

 

 

   

 

 

 

Total current assets

     169,474        161,005   

Property, Plant and Equipment:

    

Gathering and transmission systems

     591,915        543,286   

Compression equipment

     825,944        812,428   

Gas plants and buildings

     178,134        185,741   

Other property, plant and equipment

     122,276        81,295   

Construction-in-progress

     154,739        97,439   
  

 

 

   

 

 

 

Total property, plant and equipment

     1,873,008        1,720,189   

Less accumulated depreciation

     (123,755     (59,971
  

 

 

   

 

 

 

Property, plant and equipment, net

     1,749,253        1,660,218   

Other Assets:

    

Investment in unconsolidated affiliates

     1,920,412        1,351,256   

Long-term derivative assets

     366        23   

Other, net of accumulated amortization of debt issuance costs of $6,621 and $3,326

     43,316        37,758   
  

 

 

   

 

 

 

Total other assets

     1,964,094        1,389,037   

Intangible Assets and Goodwill:

    

Intangible assets, net of accumulated amortization of $30,220 and $15,584

     755,519        770,155   

Goodwill

     789,789        789,789   
  

 

 

   

 

 

 

Total intangible assets and goodwill

     1,545,308        1,559,944   
  

 

 

   

 

 

 

TOTAL ASSETS

   $ 5,428,129      $ 4,770,204   
  

 

 

   

 

 

 
LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST     

Current Liabilities:

    

Trade accounts payable

   $ 37,035      $ 50,208   

Accrued cost of gas and liquids

     81,906        80,756   

Related party payables

     37,185        3,338   

Deferred revenues, including related party amounts of $41 and $8,765

     17,348        25,257   

Derivative liabilities

     20,679        13,172   

Other current liabilities

     30,280        23,419   
  

 

 

   

 

 

 

Total current liabilities

     224,433        196,150   

Long-term derivative liabilities

     53,033        61,127   

Other long-term liabilities

     6,046        6,521   

Long-term debt, net

     1,685,613        1,141,061   

Commitments and contingencies

    

Series A Preferred Units, redemption amount of $84,549 and $83,891

     71,040        70,943   

Partners’ capital and noncontrolling interest:

    

Common units

     3,042,153        2,940,732   

General partner interest

     331,166        333,077   

Accumulated other comprehensive loss

     (17,571     (11,099
  

 

 

   

 

 

 

Total partners’ capital

     3,355,748        3,262,710   

Noncontrolling interest

     32,216        31,692   
  

 

 

   

 

 

 

Total partners’ capital and noncontrolling interest

     3,387,964        3,294,402   
  

 

 

   

 

 

 

TOTAL LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST

   $ 5,428,129      $ 4,770,204   
  

 

 

   

 

 

 

See accompanying notes to condensed consolidated financial statements

 

2


Table of Contents

Regency Energy Partners LP

Condensed Consolidated Statements of Operations

(in thousands except unit data and per unit data)

(unaudited)

 

     Successor           Predecessor  
     Three Months Ended
June  30, 2011
    Period  from
Acquisition
(May 26, 2010)  to
June 30, 2010
          Period from
April 1,  2010 to
May 25, 2010
 

REVENUES:

           

Gas sales, including related party amounts of $6,161, $447 and $0

   $ 132,800      $ 47,241           $ 87,193   

NGL sales, including related party amounts of $77,048, $18,054 and $0

     138,088        26,040             62,997   

Gathering, transportation and other fees, including related party amounts of $5,254, $2,086 and $3,680

     81,817        22,571             45,041   

Net realized and unrealized (loss) gain from derivatives

     (7,542     (130          223   

Other, including related party amounts of $2,924, $0 and $0

     11,335        1,258             4,811   
  

 

 

   

 

 

        

 

 

 

Total revenues

     356,498        96,980             200,265   

OPERATING COSTS AND EXPENSES:

           

Cost of sales, including related party amounts of $7,807, $2,281 and $3,198

     259,475        70,174             140,507   

Operation and maintenance

     33,996        10,402             19,315   

General and administrative, including related party amounts of $4,224, $833 and $0

     17,551        7,104             21,809   

Loss on asset sales, net

     153        10             19   

Depreciation and amortization

     40,503        10,545             16,889   
  

 

 

   

 

 

        

 

 

 

Total operating costs and expenses

     351,678        98,235             198,539   

OPERATING INCOME (LOSS):

     4,820        (1,255          1,726   

Income from unconsolidated affiliates

     32,167        8,121             7,959   

Interest expense, net

     (24,689     (8,081          (14,059

Other income and deductions, net

     2,641        (3,521          (624
  

 

 

   

 

 

        

 

 

 

INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES

     14,939        (4,736          (4,998

Income tax expense

     102        245             83   
  

 

 

   

 

 

        

 

 

 

INCOME (LOSS) FROM CONTINUING OPERATIONS

   $ 14,837      $ (4,981        $ (5,081

DISCONTINUED OPERATIONS:

           

Net income from operations of east Texas assets

     —          86             585   
  

 

 

   

 

 

        

 

 

 

NET INCOME (LOSS)

   $ 14,837      $ (4,895        $ (4,496

Net income attributable to noncontrolling interest

     (293     (29          (244
  

 

 

   

 

 

        

 

 

 

NET INCOME (LOSS) ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP

   $ 14,544      $ (4,924        $ (4,740
  

 

 

   

 

 

        

 

 

 

Amounts attributable to Series A Preferred Units

     1,995        668             1,335   

General partner’s interest, including IDRs

     1,550        803             —     
  

 

 

   

 

 

        

 

 

 

Limited partners’ interest in net income (loss)

   $ 10,999      $ (6,395        $ (6,075
  

 

 

   

 

 

        

 

 

 

Income (loss) from continuing operations per common unit:

           

Amount allocated to common units

   $ 10,999      $ (6,479        $ (6,660

Weighted average number of common units outstanding

     142,937,163        119,600,652             92,832,219   

Basic income (loss) from continuing operations per common unit

   $ 0.08      $ (0.05        $ (0.07

Diluted income (loss) from continuing operations per common unit

   $ 0.07      $ (0.05        $ (0.07

Distributions per unit

   $ 0.45      $ 0.445           $ —     

Basic and diluted income from discontinued operations per common unit

   $ —        $ —             $ 0.01   

Basic and diluted net income (loss) per common unit:

           

Amount allocated to common units

   $ 10,999      $ (6,395        $ (6,075

Basic net income (loss) per common unit

   $ 0.08      $ (0.05        $ (0.07

Diluted net income (loss) per common unit

   $ 0.07      $ (0.05        $ (0.07

See accompanying notes to condensed consolidated financial statements

 

3


Table of Contents

Regency Energy Partners LP

Condensed Consolidated Statements of Operations

(in thousands except unit data and per unit data)

(unaudited)

 

     Successor           Predecessor  
     Six Months Ended
June  30, 2011
    Period  from
Acquisition
(May 26, 2010)  to
June 30, 2010
          Period from
January 1,  2010 to
May 25, 2010
 

REVENUES:

           

Gas sales, including related party amounts of $11,639, $447 and $0

   $ 242,887      $ 47,241           $ 228,097   

NGL sales, including related party amounts of $150,041, $18,054 and $0

     256,339        26,040             152,803   

Gathering, transportation and other fees, including related party amounts of $11,470, $2,086 and $12,200

     163,653        22,571             114,526   

Net realized and unrealized loss from derivatives

     (9,256     (130          (716

Other, including related party amounts of $4,790, $0 and $0

     20,127        1,258             10,340   
  

 

 

   

 

 

        

 

 

 

Total revenues

     673,750        96,980             505,050   

OPERATING COSTS AND EXPENSES:

           

Cost of sales, including related party amounts of $11,021, $2,281 and $6,564

     475,736        70,174             357,778   

Operation and maintenance

     67,556        10,402             47,842   

General and administrative, including related party amounts of $8,129, $833 and $0

     36,660        7,104             37,212   

Loss on asset sales, net

     181        10             303   

Depreciation and amortization

     80,739        10,545             41,784   
  

 

 

   

 

 

        

 

 

 

Total operating costs and expenses

     660,872        98,235             484,919   

OPERATING INCOME (LOSS):

     12,878        (1,255          20,131   

Income from unconsolidated affiliates

     55,975        8,121             15,872   

Interest expense, net

     (44,696     (8,081          (34,541

Loss on debt refinancing, net

     —          —               (1,780

Other income and deductions, net

     5,055        (3,521          (3,897
  

 

 

   

 

 

        

 

 

 

INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES

     29,212        (4,736          (4,215

Income tax expense

     70        245             404   
  

 

 

   

 

 

        

 

 

 

INCOME (LOSS) FROM CONTINUING OPERATIONS

   $ 29,142      $ (4,981        $ (4,619

DISCONTINUED OPERATIONS:

           

Net income (loss) from operations of east Texas assets

     —          86             (327
  

 

 

   

 

 

        

 

 

 

NET INCOME (LOSS)

   $ 29,142      $ (4,895        $ (4,946

Net income attributable to noncontrolling interest

     (524     (29          (406
  

 

 

   

 

 

        

 

 

 

NET INCOME (LOSS) ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP

   $ 28,618      $ (4,924        $ (5,352
  

 

 

   

 

 

        

 

 

 

Amounts attributable to Series A Preferred Units

     3,988        668             3,336   

General partner’s interest, including IDRs

     2,842        803             662   

Amount allocated to non-vested common units

     —          —               (79
  

 

 

   

 

 

        

 

 

 

Limited partners’ interest in net income (loss)

   $ 21,788      $ (6,395        $ (9,271
  

 

 

   

 

 

        

 

 

 

Income (loss) from continuing operations per common unit:

           

Amount allocated to common units

   $ 21,788      $ (6,479        $ (8,966

Weighted average number of common units outstanding

     140,135,219        119,600,652             92,788,319   

Basic income (loss) from continuing operations per common unit

   $ 0.16      $ (0.05        $ (0.10

Diluted income (loss) from continuing operations per common unit

   $ 0.14      $ (0.05        $ (0.10

Distributions per unit

   $ 0.895      $ 0.445           $ 0.445   

Basic and diluted income from discontinued operations per common unit

   $ —        $ —             $ —     

Basic and diluted net income (loss) per common unit:

           

Amount allocated to common units

   $ 21,788      $ (6,395        $ (9,271

Basic net income (loss) per common unit

   $ 0.16      $ (0.05        $ (0.10

Diluted net income (loss) per common unit

   $ 0.14      $ (0.05        $ (0.10

See accompanying notes to condensed consolidated financial statements

 

4


Table of Contents

Regency Energy Partners LP

Condensed Consolidated Statements of Comprehensive Income (Loss)

(in thousands)

(unaudited)

 

     Successor           Predecessor  
     Three Months Ended
June  30, 2011
    Period  from
Acquisition
(May 26, 2010)  to
June 30, 2010
          Period from
April 1,  2010 to
May 25, 2010
 

Net income (loss)

   $ 14,837      $ (4,895        $ (4,496

Net cash flow hedge amounts reclassified to earnings

     5,565        —               (512

Change in fair value of cash flow hedges

     1,530        —               8,649   
  

 

 

   

 

 

        

 

 

 

Comprehensive income (loss)

     21,932        (4,895          3,641   

Comprehensive income attributable to noncontrolling interest

     293        29             244   
  

 

 

   

 

 

        

 

 

 

Comprehensive income (loss) attributable to Regency Energy Partners LP

   $ 21,639      $ (4,924        $ 3,397   
  

 

 

   

 

 

        

 

 

 
         
     Successor           Predecessor  
     Six Months Ended
June 30, 2011
    Period  from
Acquisition
(May 26, 2010)  to
June 30, 2010
          Period from
January 1,  2010 to
May 25, 2010
 

Net income (loss)

   $ 29,142      $ (4,895        $ (4,946

Net cash flow hedge amounts reclassified to earnings

     8,994        —               2,145   

Net change in fair value of cash flow hedges

     (15,466     —               18,486   
  

 

 

   

 

 

        

 

 

 

Comprehensive income (loss)

     22,670        (4,895          15,685   

Comprehensive income attributable to noncontrolling interest

     524        29             406   
  

 

 

   

 

 

        

 

 

 

Comprehensive income (loss) attributable to Regency Energy Partners LP

   $ 22,146      $ (4,924        $ 15,279   
  

 

 

   

 

 

        

 

 

 

See accompanying notes to condensed consolidated financial statements

 

5


Table of Contents

Regency Energy Partners LP

Condensed Consolidated Statements of Cash Flows

(in thousands)

(unaudited)

 

     Successor           Predecessor  
     Six Months Ended
June 30, 2011
    Period  from
Acquisition

(May 26, 2010) to
June 30, 2010
          Period from
January 1, 2010
to

May 25, 2010
 

OPERATING ACTIVITIES:

           

Net income (loss)

   $ 29,142      $ (4,895        $ (4,946

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

           

Depreciation and amortization, including debt issuance cost amortization and bond premium amortization

     83,587        11,330             49,363   

Write-off of debt issuance costs

     —          —               1,780   

Amortization of excess fair value of unconsolidated affiliates

     2,923        365             —     

Equity in earnings of unconsolidated affiliates

     (58,898     (8,486          (15,872

Derivative valuation changes

     (5,826     6,921             12,004   

Loss on asset sales, net

     181        10             303   

Unit-based compensation expenses

     1,747        137             12,070   

Cash flow changes in current assets and liabilities:

           

Trade accounts receivable, accrued revenues and related party receivables

     (8,847     13,843             (11,272

Other current assets

     964        585             2,516   

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

     28,577        (15,460          8,649   

Other current liabilities

     (2,764     (20,497          22,614   

Distributions received from unconsolidated affiliates

     50,510        —               12,446   

Cash flow changes in other assets and liabilities

     (182     (60          (234
  

 

 

   

 

 

        

 

 

 

Net cash flows provided by (used in) operating activities

     121,114        (16,207          89,421   
  

 

 

   

 

 

        

 

 

 

INVESTING ACTIVITIES:

           

Capital expenditures

     (172,236     (20,875          (63,787

Capital contributions to unconsolidated affiliates

     (591,681     (38,922          (20,210

Distribution in excess of earnings of unconsolidated affiliates

     27,990        —               —     

Acquisitions, net of cash received

     —          12,848             (75,114

Proceeds from asset sales

     4,003        14             10,661   
  

 

 

   

 

 

        

 

 

 

Net cash flows used in investing activities

     (731,924     (46,935          (148,450
  

 

 

   

 

 

        

 

 

 

FINANCING ACTIVITIES:

           

Net borrowings under revolving credit facility

     45,000        37,000             199,008   

Proceeds from issuance of senior notes

     500,000        —               —     

Debt issuance costs

     (9,936     (132          (15,728

Partner contributions

     —          7,436             —     

Partner distributions

     (131,106     —               (86,078

Disposition of assets between entities under common control in excess of historical cost

     25        —               (16,973

Distributions to noncontrolling interest

     —          —               (1,135

Proceeds from issuance of common units under LTIP, net of tax withholding

     506        150             (4,874

Proceeds from common unit issuances, net of issuance costs

     203,917        —               (89

Distributions to Series A Preferred Units

     (3,891     —               (1,945
  

 

 

   

 

 

        

 

 

 

Net cash flows provided by financing activities

     604,515        44,454             72,186   
  

 

 

   

 

 

        

 

 

 

Net change in cash and cash equivalents

     (6,295     (18,688          13,157   

Cash and cash equivalents at beginning of period

     9,400        22,984             9,827   
  

 

 

   

 

 

        

 

 

 

Cash and cash equivalents at end of period

   $ 3,105      $ 4,296           $ 22,984   
  

 

 

   

 

 

        

 

 

 

Supplemental cash flow information:

           

Non-cash capital expenditures

   $ 14,598      $ 16,159           $ 18,051   

Issuance of common units for an acquisition

     —          584,436             —     

Deemed contribution from acquisition of assets between entities under common control

     —          17,152             —     

Contribution receivable

     —          12,288             —     

See accompanying notes to condensed consolidated financial statements

 

6


Table of Contents

Regency Energy Partners LP

Condensed Consolidated Statement of Partners’ Capital and Noncontrolling Interest

(dollar amounts in thousands)

(unaudited)

 

     Regency Energy Partners LP               
     Units                                  
     Common      Common
Unitholders
    General
Partner
Interest
    Accumulated
Other
Comprehensive
Loss
    Noncontrolling
Interest
     Total  

Balance - December 31, 2010

     137,281,336       $ 2,940,732      $ 333,077      $ (11,099   $ 31,692       $ 3,294,402   

Private common unit offering, net of costs

     8,500,001         203,917        —          —          —           203,917   

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

     56,405         506        —          —          —           506   

Unit-based compensation expenses

     —           1,747        —          —          —           1,747   

Disposition of assets between entities under common control in excess of historical cost

     —           —          25        —          —           25   

Partner distributions

     —           (126,404     (4,702     —          —           (131,106

Accrued distributions to phantom units

     —           (209     —          —          —           (209

Net income

     —           25,776        2,842        —          524         29,142   

Distributions to Series A Preferred Units

     —           (3,815     (76     —          —           (3,891

Accretion of Series A Preferred Units

     —           (97     —          —          —           (97

Net cash flow hedge amounts reclassified to earnings

     —           —          —          8,994        —           8,994   

Change in fair value of cash flow hedges

     —           —          —          (15,466     —           (15,466
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Balance - June 30, 2011

     145,837,742       $ 3,042,153      $ 331,166      $ (17,571   $ 32,216       $ 3,387,964   
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

See accompanying notes to condensed consolidated financial statements

 

7


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. The Partnership and its subsidiaries are engaged in the business of gathering, processing and transporting natural gas and NGLs as well as providing contract compression and contract treating services. 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. In May 2010, GP Seller completed the sale of all of the outstanding membership interests of the General Partner pursuant to a Purchase Agreement (the “Purchase Agreement”) among itself, ETE and ETE GP (the “ETE Acquisition”). Prior to the closing of the Purchase Agreement, GP Seller, an affiliate of GE EFS, owned all of the outstanding limited partner interests in the General Partner and, as a result of that position, controlled the Partnership. As a result of this transaction, the outstanding voting interests of the General Partner and control of the Partnership were transferred from GE EFS to ETE.

In connection with this change in control, the Partnership’s assets and liabilities were adjusted to fair value on the closing date (May 26, 2010) by application of “push-down” accounting (the “Push-down Adjustments”). Due to the Push-down Adjustments, the Partnership’s unaudited condensed consolidated financial statements and certain footnote disclosures are presented in two distinct periods to indicate the application of two different bases of accounting between the periods presented: (1) the period prior to the acquisition date (May 26, 2010), identified as “Predecessor” and (2) the period from May 26, 2010 forward, identified as “Successor.”

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, 2010. 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. Certain prior year numbers have been reclassified to conform to the current year presentation.

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.

Quarterly Distributions of Available Cash. Following are distributions declared and/or paid by the Partnership subsequent to December 31, 2010:

 

Quarter Ended

  

Record Date

  

Payment Date

   Cash Distributions
(per  common unit)
 

December 31, 2010

   February 7, 2011    February 14, 2011    $ 0.445   

March 31, 2011

   May 6, 2011    May 13, 2011    $ 0.445   

June 30, 2011

   August 5, 2011    August 12, 2011    $ 0.45   

 

8


Table of Contents

2. Income (Loss) per Limited Partner Unit

The following tables provide a reconciliation of the numerator and denominator of the basic and diluted earnings per unit computations for the three and six months ended June 30, 2011. For the three and six months ended June 30, 2010, including successor and predecessor periods, diluted earnings per unit equaled basic earnings per unit because all instruments were antidilutive.

 

     Three Months Ended June 30, 2011  
     Income
(Numerator)
    Units
(Denominator)
     Per-Unit
Amount
 

Basic income from continuing operations per unit

       

Limited Partners’ interest

   $ 10,999        142,937,163       $ 0.08   

Effect of Dilutive Securities

       

Common unit options

     —          25,826      

Phantom units *

     —          237,747      

Series A Preferred Units

     (955     4,614,250      
  

 

 

   

 

 

    

Diluted income from continuing operations per unit

   $ 10,044        147,814,986       $ 0.07   
  

 

 

   

 

 

    
     Six Months Ended June 30, 2011  
     Income
(Numerator)
    Units
(Denominator)
     Per-Unit
Amount
 

Basic income from continuing operations per unit

       

Limited Partners’ interest

   $ 21,788        140,135,219       $ 0.16   

Effect of Dilutive Securities

       

Common unit options

     —          28,403      

Phantom units *

     —          231,251      

Series A Preferred Units

     (1,537     4,584,192      
  

 

 

   

 

 

    

Diluted income from continuing operations per unit

   $ 20,251        144,979,065       $ 0.14   
  

 

 

   

 

 

    

 

* 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:

 

     Successor           Predecessor  
     Three Months
Ended
June 30,

2011
     Period from
Acquisition

(May 26, 2010) to
June 30, 2010
          Period from
April 1, 2010 to
May 25, 2010
 

Restricted (non-vested) common units

     —           —               356,954   

Common unit options

     —           290,150            290,150   

Phantom units *

     —           322,750            351,345   

Series A Preferred Units

     —           4,584,192            4,584,192   
          
     Successor           Predecessor  
     Six Months
Ended
June 30,

2011
     Period from
Acquisition

(May 26, 2010) to
June 30, 2010
          Period from
January 1, 2010 to
May 25, 2010
 

Restricted (non-vested) common units

     —           —               396,918   

Common unit options

     —           290,150            298,400   

Phantom units *

     —           322,750            369,346   

Series A Preferred Units

     —           4,584,192            4,584,192   

 

* Amount assumes maximum conversion rate for market condition awards.

 

9


Table of Contents

3. Investment in Unconsolidated Affiliates

Lone Star. On May 2, 2011, Lone Star, a newly formed joint venture that is owned 70% by ETP and 30% by the Partnership, completed its acquisition of all of the membership interest in LDH, a wholly-owned subsidiary of Louis Dreyfus Highbridge Energy LLC, for $1.97 billion in cash, subject to customary post-closing purchase price adjustments. The Partnership contributed $591.7 million in cash to Lone Star, in exchange for its 30% interest. To fund a portion of this capital contribution, the Partnership issued 8,500,001 common units representing limited partnership interests with net proceeds of $203.9 million. These units were issued in a private placement conducted in accordance with the exemption from the registration requirement of the Securities Act of 1933, as amended, under section 4(2) thereof. These units were subsequently registered with the SEC. The remaining portion of the Partnership’s capital contribution was funded by additional borrowings under its revolving credit facility.

Lone Star owns and operates an NGL storage, fractionation and transportation business. Lone Star’s storage assets are primarily located in Mont Belvieu, Texas and its West Texas Pipeline transports NGLs through an intrastate pipeline system that originates in the Permian Basin in west Texas, passes through the Barnett Shale production area in north Texas and terminates at the Mont Belvieu storage and fractionation complex. Lone Star also owns and operates fractionation and processing assets located in Louisiana.

Lone Star is managed by a two-person board of directors, with the Partnership and ETP each having the right to appoint one director, and is operated by ETP. As of June 30, 2011, the carrying value of the Partnership’s interest in Lone Star was $600.1 million. Amounts recorded with respect to Lone Star for the period ended June 30, 2011 are summarized in the table below:

 

     Period from  Initial
Contribution

(May 2, 2011) to
June 30, 2011
 

Contributions to Lone Star

   $ 591,681  

Partnership’s share of Lone Star’s net income

     8,388  

The summarized income statement information of Lone Star (on a 100% basis) is disclosed below:

 

     Period from  Initial
Contribution

(May 2, 2011) to
June 30, 2011
 

Total revenues

   $ 98,820   

Operating income

     28,143   

Net income

     27,958   

Upon the completion of Lone Star’s acquisition of all of the membership interests in LDH, Lone Star recorded the assets and liabilities of LDH at fair value. As a result, no basis difference currently exists between the Partnership’s investment in Lone Star and the Partnership’s proportionate share of the underlying equity in net assets of Lone Star, and the Partnership’s equity of earnings for Lone Star reflects its proportionate share of Lone Star’s net income.

HPC. The Partnership owns a 49.99% general partner interest in HPC. As of June 30, 2011 and December 31, 2010, the carrying value of the Partnership’s interest in HPC was $691.2 million and $698.8 million, respectively. Amounts recorded with respect to HPC for the three and six months ended June 30, 2011 and 2010, including successor and predecessor periods, are summarized in the tables below:

 

     Successor            Predecessor  
     Three Months
Ended
June 30,
2011
     Period  from
Acquisition

(May 26, 2010) to
June 30, 2010
           Period from
April 1,  2010 to
May 25, 2010
 

Contributions to HPC

   $ —         $ —              $ 20,210   

Distributions received from HPC

     18,113        —                8,920   

Partnership’s share of HPC’s net income

     15,130        4,460             7,959   

Amortization of excess fair value of investment in HPC

     1,461        365             —     

 

10


Table of Contents
     Successor            Predecessor  
     Six Months
Ended
June 30,
2011
     Period  from
Acquisition

(May 26, 2010) to
June 30, 2010
           Period from
January 1,  2010 to
May 25, 2010
 

Contributions to HPC

   $ —         $ —              $ 20,210   

Distributions received from HPC

     34,841        —                12,446   

Partnership’s share of HPC’s net income

     30,205        4,460             15,872   

Amortization of excess fair value of investment in HPC

     2,923        365             —     

The summarized income statement information of HPC (on a 100% basis) is disclosed below:

 

     Three Months Ended June 30,  
     2011      2010  

Total revenues

   $ 48,585       $ 44,375   

Operating income

     30,515         25,950   

Net income

     30,265         25,871   
     Six Months Ended June 30,  
     2011      2010  

Total revenues

   $ 97,234       $ 79,564   

Operating income

     60,842         44,416   

Net income

     60,421         44,274   

MEP. The Partnership owns a 49.9% interest in MEP. As of June 30, 2011 and December 31, 2010, the carrying value of the Partnership’s interest in MEP was $629.1 million and $652.5 million, respectively. Amounts recorded with respect to MEP for the three and six months ended June 30, 2011 and 2010 are summarized in the tables below:

 

     Three Months
Ended

June  30,
2011
     Period  from
Acquisition

(May 26, 2010) to
June 30, 2010
 

Distributions received from MEP

   $ 18,222      $ —     

Partnership’s share of MEP’s net income

     10,110        4,026  
     Six Months
Ended
June 30,

2011
     Period from
Acquisition

(May 26, 2010) to
June 30, 2010
 

Distributions received from MEP

   $ 43,659      $ —     

Partnership’s share of MEP’s net income

     20,305        4,026  

The summarized income statement information of MEP (on a 100% basis) is disclosed below:

 

     Three Months
Ended
June 30,
2011
     Period from
Acquisition

(May 26, 2010) to
June 30, 2010
 

Total revenues

   $ 64,943       $ 21,269   

Operating income

     33,190         11,499   

Net income

     20,276         8,068   
     Six Months
Ended
June 30,
2011
     Period from
Acquisition

(May 26, 2010) to
June 30, 2010
 

Total revenues

   $ 129,767       $ 21,269   

Operating income

     66,455         11,499   

Net income

     40,686         8,068   

 

11


Table of Contents

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 Management Committee of the General Partner is responsible for the oversight of these risks, including monitoring exposure limits. The Audit and Risk Management 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 other 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.

At June 30, 2011, all of the Partnership’s commodity swaps were accounted for as cash flow hedges.

Interest Rate Risk. The Partnership is exposed to variable interest rate risk as a result of borrowings under its revolving credit facility. As of June 30, 2011, the Partnership had $330 million of outstanding borrowings exposed to variable interest rate risk. In April 2010, the Partnership entered into two-year interest rate swaps related to $250 million of borrowings under its revolving credit facility, effectively locking the base rate, exclusive of applicable margins, for these borrowings at 1.325% through April 2012. The Partnership accounts for these interest rate swaps using the mark-to-market method of accounting.

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 with potentially better credit.

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 June 30, 2011 would be $1.4 million which would be reduced in full 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.

Quantitative Disclosures. The Partnership expects to reclassify $16.4 million of net hedging losses to revenues from accumulated other comprehensive loss in the next 12 months.

 

12


Table of Contents

The Partnership’s derivative assets and liabilities, including credit risk adjustments, as of June 30, 2011 and December 31, 2010 are detailed below:

 

     Assets      Liabilities  
     June 30, 2011      December 31, 2010      June 30, 2011      December 31, 2010  

Derivatives designated as cash flow hedges

           

Current amounts

           

Commodity contracts

   $ 1,075       $ 2,650       $ 18,827       $ 11,421   

Long-term amounts

           

Commodity contracts

     366         23         1,535         3,271   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total cash flow hedging instruments

     1,441         2,673         20,362         14,692   
  

 

 

    

 

 

    

 

 

    

 

 

 

Derivatives not designated as cash flow hedges

           

Current amounts

           

Interest rate contracts

     —           —           1,852         1,751   

Long-term amounts

           

Interest rate contracts

     —           —           —           833   

Embedded derivatives in Series A Preferred Units

     —           —           51,498         57,023   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total derivatives not designated as cash flow hedges

     —           —           53,350         59,607   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total derivatives

   $ 1,441       $ 2,673       $ 73,712       $ 74,299   
  

 

 

    

 

 

    

 

 

    

 

 

 

The Partnership’s statement of operations for the three months ended June 30, 2011 and 2010 were impacted by derivative instruments activities as follows:

 

          Successor           Predecessor  
          Three Months Ended
June  30, 2011
    Period  from
Acquisition

(May 26, 2010) to
June 30, 2010
          Period from
April 1,  2010 to
May 25, 2010
 
     Location of Gain/(Loss)
Recognized in Income
  

 

Change in Value Recognized in
AOCI on Derivatives (Effective Portion)

 

Derivatives in cash flow hedging relationships:

              

Commodity derivatives

   Revenues    $ 1,530      $ —             $ 7,428   
     Location of Gain/(Loss)
Recognized in Income
   Amount of Gain/(Loss) Reclassified from AOCI into
Income (Effective Portion)
 

Derivatives in cash flow hedging relationships:

              

Commodity derivatives

   Revenues    $ (7,133   $ —             $ (709
     Location of Gain/(Loss)
Recognized in Income
   Amount of Gain/(Loss) Recognized in
Income on Ineffective Portion
 

Derivatives in cash flow hedging relationships:

              

Commodity derivatives

   Revenues    $ (362   $ —             $ (301
     Location of Gain/(Loss)
Recognized in Income
   Amount of Gain/(Loss) from Designation
Amortized from AOCI into Income
 

Derivatives not designated in a hedging relationship:

              

Commodity derivatives

   Revenues    $ —        $ —             $ 1,221   
     Location of Gain/(Loss)
Recognized in Income
   Amount of Gain/(Loss) Recognized
in Income on Derivatives
 

Derivatives not designated in a hedging relationship:

              

Commodity derivatives (credit risk adjustment)

   Revenues    $ (47   $ (824        $ 12   

Interest rate swap derivatives

   Interest expense, net      (228     (1,715          (824

Embedded derivatives

   Other income & deductions      2,950        (3,606          (654
     

 

 

   

 

 

        

 

 

 
      $ 2,675      $ (6,145        $ (1,466
     

 

 

   

 

 

        

 

 

 

 

13


Table of Contents

The Partnership’s statement of operations for the six months ended June 30, 2011 and 2010 were impacted by derivative instruments activities as follows:

 

          Successor           Predecessor  
          Six Months Ended
June 30, 2011
    Period  from
Acquisition
(May 26, 2010)  to
June 30, 2010
          Period from
January 1,  2010 to
May 25, 2010
 
     Location of Gain/(Loss)
Recognized in Income
  

 

Change in Value Recognized in
AOCI on Derivatives (Effective Portion)

 

Derivatives in cash flow hedging relationships:

              

Commodity derivatives

   Revenues    $ (15,466   $ —             $ 14,371   
     Location of Gain/(Loss)
Recognized in Income
   Amount of Gain/(Loss) Reclassified from AOCI into
Income (Effective Portion)
 

Derivatives in cash flow hedging relationships:

              

Commodity derivatives

   Revenues    $ (8,994   $ —             $ (5,200

Interest rate swap derivatives

   Interest expense      —          —               (1,060
     

 

 

   

 

 

        

 

 

 
      $ (8,994   $ —             $ (6,260
     

 

 

   

 

 

        

 

 

 
     Location of Gain/(Loss)
Recognized in Income
   Amount of Gain/(Loss) Recognized in
Income on Ineffective Portion
 

Derivatives in cash flow hedging relationships:

              

Commodity derivatives

   Revenues    $ (274   $ —             $ (799
     Location of Gain/(Loss)
Recognized in Income
   Amount of Gain/(Loss) from Designation
Amortized from AOCI into Income
 

Derivatives not designated in a hedging relationship:

              

Commodity derivatives

   Revenues    $ —        $ —             $ 4,115   
     Location of Gain/(Loss)
Recognized in Income
   Amount of Gain/(Loss) Recognized
in Income on Derivatives
 

Derivatives not designated in a hedging relationship:

              

Commodity derivatives (credit risk adjustment)

   Revenues    $ 12     $ (824        $ 1,247   

Interest rate swap derivatives

   Interest expense, net      (487     (1,715          (824

Embedded derivatives

   Other income & deductions      5,525        (3,606          (4,039
     

 

 

   

 

 

        

 

 

 
      $ 5,050      $ (6,145        $ (3,616
     

 

 

   

 

 

        

 

 

 

5. Long-term Debt

Obligations in the form of senior notes and borrowings under the revolving credit facility are as follows:

 

     June 30, 2011     December 31, 2010  

Senior notes

   $ 1,355,613      $ 856,061   

Revolving loans

     330,000        285,000   
  

 

 

   

 

 

 

Total

     1,685,613        1,141,061   

Less: current portion

     —          —     
  

 

 

   

 

 

 

Long-term debt

   $ 1,685,613      $ 1,141,061   
  

 

 

   

 

 

 

Availability under revolving credit facility:

    

Total credit facility limit

   $ 900,000      $ 900,000   

Revolving loans

     (330,000     (285,000

Letters of credit

     (11,015     (16,015
  

 

 

   

 

 

 

Total available

   $ 558,985      $ 598,985   
  

 

 

   

 

 

 

 

14


Table of Contents

Scheduled maturities of long-term debt at June 30, 2011 are as follows:

 

Years Ending December 31,

   Amount  

2011 (remainder)

   $ —     

2012

     —     

2013

     —     

2014

     330,000   

2015

     —     

Thereafter

     1,350,000
  

 

 

 

Total

   $ 1,680,000   
  

 

 

 

 

* Excludes an unamortized premium of $5.6 million as of June 30, 2011.

Revolving Credit Facility. The Partnership’s $900 million revolving credit facility expires on June 15, 2014. The revolving credit facility and guarantees are senior to the Partnership’s and each guarantor’s unsecured obligations, to the extent of the value of the assets securing such obligations. The revolving credit facility contains financial covenants requiring RGS and its subsidiaries to maintain debt to consolidated EBITDA, as defined in the credit agreement, ratio less than 5.25. At June 30, 2011, RGS and its subsidiaries were in compliance with these covenants.

The outstanding balance under the revolving credit facility bears interest at LIBOR plus a margin or alternate base rate (equivalent to the U.S. prime rate lending rate) plus a margin, or a combination of both. The average interest rates, including commitment fees, were 3.25% and 3.92%, respectively, during the six months ended June 30, 2011 and 2010.

On May 2, 2011, the Partnership amended its Fifth Amended and Restated Credit Agreement to permit the acquisition of equity interests in Lone Star and to allow for additional investments in Lone Star of up to $150 million.

Senior Notes. In May 2011, the Partnership and Finance Corp. issued $500 million in senior notes that mature on July 15, 2021 (“2021 Notes”). The senior notes bear interest at 6.5% payable semi-annually in arrears on January 15 and July 15, commencing January 15, 2012. The Partnership capitalized $9.8 million in debt issuance costs that will be amortized to interest expense, net over the term of the senior notes. The proceeds were used to repay borrowings outstanding under the Partnership’s revolving credit facility.

At any time prior to July 15, 2014, the Partnership may redeem up to 35% of the senior notes at a price equal to 106.5% plus accrued interest. Beginning on July 15 of the years indicated below, the Partnership may redeem all or part of the 2021 Notes at the redemption prices, expressed as percentages of the principal amount, set forth below:

 

July 15 of year ending:

   Percentage of Redemption  

2016

     103.250 %

2017

     102.167 %

2018

     101.083 %

2019 and thereafter at 100%

     100.000 %

Upon a change of control, as defined in the indenture, followed by a rating decline within 90 days, each holder of the 2021 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 our debt agreements, including the Partnership’s revolving credit facility.

The 2021 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.

If the 2021 Notes achieve investment grade ratings by both Moody’s and S&P and no default or event of default has occurred and is continuing, the Partnership will no longer be subject to many of the foregoing covenants. At June 30, 2011, the Partnership was in compliance with these covenants.

 

15


Table of Contents

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 existing unconsolidated subsidiaries, except for one minor subsidiary, 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 will likely take place in late 2011 or early 2012.

7. Series A Preferred Units

On September 2, 2009, the Partnership issued 4,371,586 Series A Preferred Units. As of June 30, 2011, the Series A Preferred Units were convertible to 4,620,152 common units, and if outstanding, are mandatorily redeemable on September 2, 2029 for $80 million plus all accrued but unpaid distributions thereon. The Series A Preferred Units receive fixed quarterly cash distributions of $0.445 per unit beginning with the quarter ending March 31, 2010, if outstanding on the record dates of the Partnership’s common unit distributions. Effective as of March 2, 2010, 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 six months ended June 30, 2011:

 

     Units      Amount  

Balance at January 1, 2011

     4,371,586       $ 70,943   

Accretion to redemption value

     —           97   
  

 

 

    

 

 

 

Ending balance as of June 30, 2011

     4,371,586       $ 71,040
  

 

 

    

 

 

 

 

* This amount will be accreted to $80 million plus any accrued and unpaid distributions by deducting amounts from partners’ capital over the remaining period until the mandatory redemption date of September 2, 2029.

8. Related Party Transactions

As of June 30, 2011 and December 31, 2010, details of the Partnership’s related party receivables and related party payables were as follows:

 

     June 30, 2011      December 31, 2010  

Related party receivables

     

EPD and its subsidiaries

   $ 18,649       $ 25,539   

HPC

     7,846         5,823   

ETE and its subsidiaries

     6,669         970   

Other

     1,423         10   
  

 

 

    

 

 

 

Total related party receivables

   $ 34,587       $ 32,342   
  

 

 

    

 

 

 

Related party payables

     

EPD and its subsidiaries

   $ 754       $ 1,323   

HPC

     1,966         760   

ETE and its subsidiaries

     34,443         1,245   

Other

     22         10   
  

 

 

    

 

 

 

Total related party payables

   $ 37,185       $ 3,338   
  

 

 

    

 

 

 

Transactions with ETE and its subsidiaries. Under a May 26, 2010 service agreement with Services Co., Services Co. performs certain services for the Partnership. The Partnership pays Services Co.’s direct expenses for these services, 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 from May 26, 2010 to 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 Regency GP LP 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 has an initial term of one year and automatically renews on a year-to-year basis upon expiration of the initial term.

The total fees related to these service contracts were $4.2 million and $8.1 million for the three and six months ended June 30, 2011, and for the period from the acquisition, May 26, 2010, to June 30, 2010 was $0.8 million.

In conjunction with distributions by the Partnership to the limited and general partner interests, ETE received cash distributions of $14.1 million and $28.1 million during the three and six months ended June 30, 2011.

The Partnership’s Contract Compression segment provides contract compression services to subsidiaries of ETP and records revenue in gathering, transportation and other fees on the statement of operations.

 

16


Table of Contents

The Partnership’s Contract Compression segment sold compression equipment to a subsidiary of ETP for $5.5 million and $6.3 million for the three and six months ended June 30, 2011, respectively. As these transactions are between entities under common control, partners’ capital was increased by $25 thousand, which represented a deemed contribution of the excess sales price over the carrying amounts.

Prior to December 31, 2010, the employees operating the assets of the Partnership and its subsidiaries and all those providing staff or support services were employees of the General Partner. 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. For the six months ended June 30, 2011, reimbursements of $24.6 million and $8.6 million were recorded to the General Partner and to ETP, respectively, in the Partnership’s financial statements as operating expenses or general and administrative expenses, as appropriate. For the six months ended June 30, 2010, reimbursements of $5.7 million, $10.4 million and $31.1 million to the General Partner were recorded, respectively, during the periods from May 26, 2010 to June 30, 2010, from April 1, 2010 to May 25, 2010 and from January 1, 2010 to May 25, 2010 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. During the three and six months ended June 30, 2011, from May 26, 2010 to June 30, 2010, from April 1, 2010 to May 25, 2010 and from January 1, 2010 to May 25, 2010, the related party general and administrative expenses reimbursed to the Partnership were $4.2 million, $8.4 million, $1.4 million, $2.8 million and $6.9 million, respectively, which is recorded in gathering, transportation and other fees on the statement of operations.

The Partnership’s Contract Compression segment provides contract compression services to HPC and records revenues in gathering, transportation and other fees in the statement of operations. The Partnership also receives transportation services from HPC and records it as cost of sales.

Transactions with Enterprise. Enterprise Products Partners L.P. (“EPD”) owns a portion of ETE’s outstanding common units; therefore, it is considered a related party along with any of its subsidiaries. The Partnership, in the ordinary course of business, sells natural gas and NGLs to subsidiaries of EPD and records the revenues in gas sales and NGL sales. The Partnership also incurs NGL processing fees and transportation fees with subsidiaries of EPD and records these fees as cost of sales.

9. Segment Information

During the six months ended June 30, 2011, the Partnership changed the name of the Transportation segment to Joint Ventures, which represents the Partnership’s equity method investments in its three unconsolidated joint ventures: HPC, MEP and Lone Star. In addition, the disposition of the east Texas assets in July 2010 impacts the Gathering and Processing segment, as the results of those operations are now presented within discontinued operations and excluded from the segment information table. Accordingly, the Partnership has recast the segment information for the corresponding periods in 2010.

Gathering and Processing. The Partnership provides “wellhead-to-market” services to producers of natural gas, which include gathering 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 a 49.99% general partner interest in HPC, which delivers natural gas from northwest Louisiana to downstream pipelines and markets through the 450-mile Regency Intrastate Gas pipeline system. The

 

17


Table of Contents

Partnership owns a 49.9% interest in MEP, which owns approximately 500 miles of natural gas pipeline stretching from southeast Oklahoma through northeast Texas, northern Louisiana and central Mississippi into Alabama. The Partnership has a 30% interest in Lone Star, an entity owning a diverse set of midstream energy assets including pipelines, storage 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 10 mile interstate 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 and revenue generating horsepower. 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. We do not record segment margin for the Joint Ventures segment because we record our ownership percentages of the net income in HPC, MEP and Lone Star as income from unconsolidated affiliates in accordance with the equity method of accounting.

 

18


Table of Contents

Results for each period, together with amounts related to balance sheets for each segment, are shown below:

 

     Successor           Predecessor  
     Three Months Ended
June  30, 2011
    Period  from
Acquisition
(May 26, 2010)  to
June 30, 2010
          Period from
April 1,  2010 to
May 25, 2010
 

External Revenues

           

Gathering and Processing

   $ 303,203      $ 83,778           $ 173,206   

Joint Ventures

     —          —               —     

Contract Compression

     38,072        12,054             23,992   

Contract Treating

     10,842        —               —     

Corporate and Others

     4,381        1,148             3,067   

Eliminations

     —          —               —     
  

 

 

   

 

 

        

 

 

 

Total

   $ 356,498      $ 96,980           $ 200,265   
  

 

 

   

 

 

        

 

 

 

Intersegment Revenues

           

Gathering and Processing

   $ —        $ —             $ —     

Joint Ventures

     —          —               —     

Contract Compression

     2,917        1,998             3,794   

Contract Treating

     —          —               —     

Corporate and Others

     110        22             52   

Eliminations

     (3,027     (2,020          (3,846
  

 

 

   

 

 

        

 

 

 

Total

   $ —        $ —             $ —     
  

 

 

   

 

 

        

 

 

 

Segment Margin

           

Gathering and Processing

   $ 50,495      $ 14,373           $ 35,195   

Joint Ventures

     —          —               —     

Contract Compression

     36,973        12,488             25,326   

Contract Treating

     7,701        —               —     

Corporate and Others

     4,762        1,943             3,031   

Eliminations

     (2,908     (1,998          (3,794
  

 

 

   

 

 

        

 

 

 

Total

   $ 97,023      $ 26,806           $ 59,758   
  

 

 

   

 

 

        

 

 

 

Operation and Maintenance

           

Gathering and Processing

   $ 19,528      $ 7,463           $ 13,390   

Joint Ventures

     —          —               —     

Contract Compression

     16,310        4,924             9,698   

Contract Treating

     675        —               —     

Corporate and Others

     397        13             21   

Eliminations

     (2,914     (1,998          (3,794
  

 

 

   

 

 

        

 

 

 

Total

   $ 33,996      $ 10,402           $ 19,315   
  

 

 

   

 

 

        

 

 

 

 

19


Table of Contents
     Successor           Predecessor  
     Six Months Ended
June 30, 2011
    Period  from
Acquisition

(May 26, 2010) to
June 30, 2010
          Period from
January 1, 2010 to

May 25, 2010
 

External Revenues

           

Gathering and Processing

   $ 569,175      $ 83,778           $ 438,804   

Joint Ventures

     —          —               —     

Contract Compression

     76,508        12,054             58,971   

Contract Treating

     19,275        —               —     

Corporate and Others

     8,792        1,148             7,275   

Eliminations

     —          —               —     
  

 

 

   

 

 

        

 

 

 

Total

   $ 673,750      $ 96,980           $ 505,050   
  

 

 

   

 

 

        

 

 

 

Intersegment Revenues

           

Gathering and Processing

   $ —        $ —             $ —     

Joint Ventures

     —          —               —     

Contract Compression

     9,470        1,998             9,126   

Contract Treating

     —          —               —     

Corporate and Others

     177        22             91   

Eliminations

     (9,647     (2,020          (9,217
  

 

 

   

 

 

        

 

 

 

Total

   $ —        $ —             $ —     
  

 

 

   

 

 

        

 

 

 

Segment Margin

           

Gathering and Processing

   $ 104,295      $ 14,373           $ 85,997   

Joint Ventures

     —          —               —     

Contract Compression

     78,413        12,488             62,356   

Contract Treating

     14,952        —               —     

Corporate and Others

     9,815        1,943             8,045   

Eliminations

     (9,461     (1,998          (9,126
  

 

 

   

 

 

        

 

 

 

Total

   $ 198,014      $ 26,806           $ 147,272   
  

 

 

   

 

 

        

 

 

 

Operation and Maintenance

           

Gathering and Processing

   $ 42,470      $ 7,463           $ 33,430   

Joint Ventures

     —          —               —     

Contract Compression

     32,702        4,924             23,476   

Contract Treating

     1,409        —               —     

Corporate and Others

     442        13             59   

Eliminations

     (9,467     (1,998          (9,123
  

 

 

   

 

 

        

 

 

 

Total

   $ 67,556      $ 10,402           $ 47,842   
  

 

 

   

 

 

        

 

 

 

The tables below provide a reconciliation of total segment margin to income from continuing operations before income taxes:

 

     Successor           Predecessor  
     Three Months Ended
June  30, 2011
    Period from
Acquisition

(May 26, 2010) to
June 30, 2010
          Period from
April 1,  2010 to
May 25, 2010
 

Total segment margin

   $ 97,023      $ 26,806           $ 59,758   

Operation and maintenance

     (33,996     (10,402          (19,315

General and administrative

     (17,551     (7,104          (21,809

Loss on assets sales, net

     (153     (10          (19

Depreciation and amortization

     (40,503     (10,545          (16,889

Income from unconsolidated affiliates

     32,167        8,121             7,959   

Interest expense, net

     (24,689     (8,081          (14,059

Other income and deductions, net

     2,641        (3,521          (624
  

 

 

   

 

 

        

 

 

 

Income (loss) from continuing operations before income taxes

   $ 14,939      $ (4,736        $ (4,998
  

 

 

   

 

 

        

 

 

 

 

20


Table of Contents
     Successor           Predecessor  
     Six Months Ended
June 30, 2011
    Period  from
Acquisition

(May 26, 2010) to
June 30, 2010
          Period from
January 1, 2010 to

May 25, 2010
 

Total segment margin

   $ 198,014      $ 26,806           $ 147,272   

Operation and maintenance

     (67,556     (10,402          (47,842

General and administrative

     (36,660     (7,104          (37,212

Loss on assets sales, net

     (181     (10          (303

Depreciation and amortization

     (80,739     (10,545          (41,784

Income from unconsolidated affiliates

     55,975        8,121             15,872   

Interest expense, net

     (44,696     (8,081          (34,541

Loss on debt refinancing, net

     —          —               (1,780

Other income and deductions, net

     5,055        (3,521          (3,897
  

 

 

   

 

 

        

 

 

 

Income (loss) from continuing operations before income taxes

   $ 29,212      $ (4,736        $ (4,215
  

 

 

   

 

 

        

 

 

 

The table below provides a listing of assets reflected in the consolidated balance sheet for each segment:

 

     June 30, 2011      December 31, 2010  

Gathering and Processing

   $ 1,800,025       $ 1,724,682   

Joint Ventures

     1,920,412         1,351,256   

Contract Compression

     1,409,239         1,411,325   

Contract Treating

     221,110         220,584   

Corporate and Others

     77,343         62,357   
  

 

 

    

 

 

 

Total

   $ 5,428,129       $ 4,770,204   
  

 

 

    

 

 

 

10. Equity-Based Compensation

The Partnership’s LTIP for its employees, directors and consultants authorizes grants up to 3,565,584 common units. LTIP compensation expense of $0.8 million, $1.7 million, $0.1 million, $10.4 million and $12.1 million is recorded in general and administrative expense in the statement of operations for the three and six months ended June 30, 2011 and for the periods from May 26, 2010 to June 30, 2010, April 1, 2010 to May 25, 2010 and from January 1, 2010 to May 25, 2010, respectively.

Common Unit Options. The common unit options activity during the six months ended June 30, 2011 is as follows:

 

2011

 

Common Unit Options

   Units     Weighted Average
Exercise Price
     Weighted
Average
Contractual
Term (Years)
     Aggregate
Intrinsic Value *
 

Outstanding at the beginning of period (January 1, 2011)

     201,950      $ 21.93         

Granted

     —          —           

Exercised

     (32,100     20.21          $ 204   

Forfeited or expired

     (3,800     26.39         
  

 

 

         

Outstanding at end of period

     166,050        22.13         4.9         652   
  

 

 

         

Exercisable at the end of the period (June 30, 2011)

     166,050              652   

 

* Intrinsic value equals the closing market price of a unit less the option strike price, multiplied by the number of unit options outstanding as of the end of the period presented. Unit options with an exercise price greater than the end of the period closing market price are excluded.

During the six months ended June 30, 2011, the Partnership received $0.7 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.

 

21


Table of Contents

The following table presents phantom units activity for the six months ended June 30, 2011:

 

2011

 

Phantom Units

   Units     Weighted Average Grant
Date Fair Value
 

Outstanding at the beginning of the period (January 1, 2011)

     742,517      $ 23.61   

Service condition grants

     68,745       26.21   

Market condition grants

     —          —     

Vested service condition

     (20,980     20.69   

Vested market condition

     (8,550     19.52   

Forfeited service condition

     (56,900     25.07   

Forfeited market condition

     (6,660     19.52   
  

 

 

   

Total outstanding at end of period (June 30, 2011)

     718,172       24.77   
  

 

 

   

The Partnership expects to recognize $13 million of compensation expense related to non-vested phantom units over a period of 4.2 years.

11. Fair Value Measures

The fair value measurement provisions establish a three-tiered fair value hierarchy that prioritizes inputs to valuation techniques used in fair value calculations. The three levels of inputs are defined as follows:

 

   

Level 1—unadjusted quoted prices for identical assets or liabilities in active accessible markets;

 

   

Level 2—inputs that are observable in the marketplace other than those classified as Level 1; and

 

   

Level 3—inputs that are unobservable in the marketplace and significant to the valuation.

Entities are encouraged to maximize the use of observable inputs and minimize the use of unobservable inputs. If a financial instrument uses inputs that fall in different levels of the hierarchy, the instrument will be categorized based upon the lowest level of input that is significant to the fair value calculation.

The Partnership’s financial assets and liabilities measured at fair value on a recurring basis are derivatives related to interest rate and commodity swaps and embedded derivatives in the Series A Preferred Units. Derivatives related to interest rate and commodity swaps 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. 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 June 30, 2011      Fair Value Measurements at December 31, 2010  
     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

   $ 1,374       $ 1,374       $ —         $ 2,481       $ 2,481       $ —     

NGLs

     67         67         —           192         192         —     
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Assets

   $ 1,441       $ 1,441       $ —         $ 2,673       $ 2,673       $ —     
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Liabilities:

                 

Interest Rate Derivatives

   $ 1,852       $ 1,852       $ —         $ 2,584       $ 2,584       $ —     

Commodity Derivatives:

                 

Natural Gas

     —           —           —           427         427         —     

NGLs

     16,711         16,711         —           10,684         10,684         —     

Condensate

     3,651         3,651         —           3,581         3,581         —     

Embedded Derivatives in Series A Preferred Units

     51,498         —           51,498         57,023         —           57,023   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Liabilities

   $ 73,712       $ 22,214       $ 51,498       $ 74,299       $ 17,276       $ 57,023   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

22


Table of Contents

The following table presents the changes in Level 3 derivatives measured on a recurring basis for the six months ended June 30, 2011. There were no transfers between the fair value hierarchy levels for the six months ended June 30, 2011.

 

Balance at January 1, 2011

   $ 57,023   

Net unrealized gain included in other income and deductions, net

     (5,525
  

 

 

 

Balance at June 30, 2011

   $ 51,498   
  

 

 

 

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 estimated fair value of the 2016 Notes, based on third party market value quotations as of June 30, 2011 and December 31, 2010 was $279.4 million and $274.4 million, respectively. The estimated fair value of the 2018 Notes, based on third party market value quotations as of June 30, 2011 and December 31, 2010 was $624.0 million and $607.5 million, respectively. The estimated fair value of the 2021 Notes, based on third party market value quotations as of June 30, 2011 was $506.3 million.

 

23


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 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, treating, processing, compression and transportation of natural gas and NGLs. We focus on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Haynesville, Eagle Ford, Barnett, Fayetteville, and Marcellus shales as well as the Permian Delaware basin. Our assets are located in Louisiana, Texas, Arkansas, Pennsylvania, Mississippi, Alabama and the mid-continent region of the United States, which includes Kansas, Colorado and Oklahoma.

RECENT DEVELOPMENTS

Eagle Ford Expansion. In June 2011, we entered into agreements to provide gas and condensate gathering services for a producer in the Eagle Ford Shale and to construct facilities to perform these services, including a wellhead gathering system, at an expected cost of approximately $450 million. The expansion will be owned and operated by us and will tie into our existing gathering system. In addition, we have purchased certain existing midstream assets located in the Eagle Ford Shale as part of this expansion. The expansion is scheduled for completion by 2014.

Lone Star Expansion. In May 2011, Lone Star announced a construction project of a 100,000 Bbls/d fractionator and related storage services and interconnectivity infrastructure to be constructed in Mont Belvieu, Texas, which is expected to be completed in early 2013. Our estimated capital expenditures for this project are approximately $110 million.

In June 2011, Lone Star announced it would construct an approximate 530-mile natural gas liquids pipeline that extends from Winkler County in west Texas to a processing plant in Jackson County, Texas. This pipeline will have a minimum capacity of approximately 130,000 Bbls/d with the potential to upsize the pipeline capacity depending on ongoing negotiations. Our estimated capital expenditures for this project are $210 million. In addition, Lone Star has secured capacity on ETP’s recently announced NGL pipeline from Jackson County to Mont Belvieu, Texas.

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 gathering raw natural gas from the wellhead through gathering systems, processing raw natural gas to separate NGLs and selling or delivering pipeline-quality natural gas and NGLs to various markets and pipeline systems.

 

   

Joint Ventures. We own 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. We own a 49.9% 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. We own a 30% interest in Lone Star, an entity owning a diverse set of midstream energy assets including pipelines, storage and processing facilities located in the states of Texas, Mississippi and Louisiana.

 

   

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 interstate 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, operating and maintenance expense, EBITDA, and adjusted EBITDA on a segment and company-wide basis.

 

24


Table of Contents

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 for the Gathering and Processing and the Corporate and Others segments, as revenues, including service fees, less cost of sales. We calculate 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.

We do not record segment margin for the Joint Ventures segment because we record our ownership percentages of the net income in HPC, MEP and Lone Star as income from unconsolidated affiliates in accordance with the equity method of accounting.

We calculate our Contract Compression segment margin as revenues minus direct costs, primarily compressor unit repairs, associated with those revenues.

We calculate our Contract Treating segment margin as revenues minus direct costs associated with those revenues.

We calculate total segment margin as the summation of segment margin of our five 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. We define adjusted total segment margin as total 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 as they represent the results of our revenues and cost of revenues, 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 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 revenue.

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 separately evaluate commodity volume and price changes in segment margin.

EBITDA and Adjusted EBITDA. We define EBITDA as net income (loss) plus interest expense, net, income tax expense, net 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

 

   

the Partnership’s interest in adjusted EBITDA from unconsolidated affiliates less income from unconsolidated affiliates.

 

25


Table of Contents

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 and the overall rates of return on alternative investment opportunities.

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:

 

     Successor     Predecessor  
     Six  Months
Ended
June 30, 2011
    Period  from
Acquisition

(May 26, 2010) to
June 30, 2010
    Period from
January  1, 2010 to
May 25, 2010
 

Reconciliation of “Adjusted EBITDA” to net cash flows provided by (used in)

operating activities and net income (loss)

        

Net cash flows provided by (used in) operating activities

   $ 121,114      $ (16,207   $ 89,421   

Add (deduct):

        

Depreciation and amortization, including debt issuance cost amortization and bond premium amortization

     (83,587     (11,330     (49,363

Write-off of debt issuance costs

     —          —          (1,780

Amortization of excess fair value of unconsolidated affiliates

     (2,923     (365     —     

Income from unconsolidated affiliates

     58,898        8,486        15,872   

Derivative valuation change

     5,826        (6,921     (12,004

Loss on assets sales, net

     (181     (10     (303

Unit-based compensation expenses

     (1,747     (137     (12,070

Trade accounts receivable, accrued revenues and related party receivables

     8,847        (13,843     11,272   

Other current assets

     (964     (585     (2,516

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

     (28,577     15,460        (8,649

Other current liabilities

     2,764        20,497        (22,614

Distributions received from unconsolidated affiliates

     (50,510     —          (12,446

Other assets and liabilities

     182        60        234   
  

 

 

   

 

 

   

 

 

 

Net income (loss)

     29,142        (4,895     (4,946

Add (deduct):

        

Interest expense, net

     44,696        8,109        34,679   

Depreciation and amortization expense

     80,739        10,995        46,084   

Income tax expense

     70        245        404   
  

 

 

   

 

 

   

 

 

 

EBITDA

     154,647        14,454        76,221   
 

Add (deduct):

        

Non-cash (gain) loss from commodity and embedded derivatives

     (5,093     5,856        11,189   

Non-cash unit-based compensation expense

     1,796        113        11,925   

Loss on assets sales, net

     181        10        303   

Income from unconsolidated affiliates, net of amortization

     (55,975     (8,121     (15,872

Partnership’s ownership interest in HPC’s adjusted EBITDA

     38,775        5,824        21,184   

Partnership’s ownership interest in MEP’s adjusted EBITDA

     50,513        8,424        —     

Partnership’s ownership interest in Lone Star’s adjusted EBITDA

     10,584        —          —     

Loss on debt refinancing, net

     —          —          1,780   

Other (income) expense, net

     (235     191        2,064   
  

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

   $ 195,193      $ 26,751      $ 108,794   
  

 

 

   

 

 

   

 

 

 

 

26


Table of Contents

The following table presents a reconciliation of net income to EBITDA and adjusted EBITDA for HPC and represents 100% of HPC’s consolidated results of operations:

 

     Six Months Ended
June 30,
 
     2011      2010  

Net income

   $ 60,421       $ 44,274   

Add:

     

Depreciation and amortization

     16,746         14,421   

Interest expense, net

     387         201   
  

 

 

    

 

 

 

EBITDA

   $ 77,554       $ 58,896   

Add:

     

Other expenses, net

     11         12   
  

 

 

    

 

 

 

Adjusted EBITDA

   $ 77,565       $ 58,908   
  

 

 

    

 

 

 

The following table presents a reconciliation of net income to EBITDA and adjusted EBITDA for MEP and represents 100% of MEP’s consolidated results of operations:

 

     Six  Months
Ended
June 30, 2011
     Period  from
Acquisition

(May 26, 2010) to
June 30, 2010
 

Net income

   $ 40,686       $ 8,068   

Add:

     

Depreciation and amortization

     34,775         5,383   

Interest expense, net

     25,768         3,431   
  

 

 

    

 

 

 

EBITDA and Adjusted EBITDA

   $ 101,229       $ 16,882   
  

 

 

    

 

 

 

The following table presents a reconciliation of net income to EBITDA and adjusted EBITDA for Lone Star and represents 100% of Lone Star’s consolidated results of operations:

 

     Period from  Initial
Contribution

(May 2, 2011) to
June 30, 2011
 

Net income

   $ 27,958   

Add:

  

Depreciation and amortization

     7,139   

Other expenses, net

     185   
  

 

 

 

EBITDA and Adjusted EBITDA

   $ 35,282   
  

 

 

 

The following tables present a reconciliation of total segment margin and adjusted total segment margin to net income (loss) for the three and six month periods ended June 30, 2011 for the Partnership:

 

     Successor     Predecessor  
     Three  Months
Ended
June 30, 2011
    Period  from
Acquisition

(May 26, 2010) to
June 30, 2010
    Period from
April  1, 2010 to
May 25, 2010
 

Net income (loss)

   $ 14,837      $ (4,895   $ (4,496

Add (deduct):

        

Operation and maintenance

     33,996        10,402        19,315   

General and administrative

     17,551        7,104        21,809   

Loss on assets sales, net

     153        10        19   

Depreciation and amortization

     40,503        10,545        16,889   

Income from unconsolidated affiliates

     (32,167     (8,121     (7,959

Interest expense, net

     24,689        8,081        14,059   

Other income and deductions, net

     (2,641     3,521        624   

Income tax expense

     102        245        83   

Discontinued operations

     —          (86     (585
  

 

 

   

 

 

   

 

 

 

Total segment margin

     97,023        26,806        59,758   

Add:

        

Non-cash loss from commodity derivatives

     2,147        2,250        3,344   
  

 

 

   

 

 

   

 

 

 

Adjusted total segment margin

   $ 99,170      $ 29,056      $ 63,102   
  

 

 

   

 

 

   

 

 

 

 

27


Table of Contents
     Successor          Predecessor  
     Six  Months
Ended
June 30, 2011
    Period  from
Acquisition

(May 26, 2010) to
June 30, 2010
         Period from
January  1, 2010 to
May 25, 2010
 

Net income (loss)

   $ 29,142      $ (4,895       $ (4,946

Add (deduct):

          

Operation and maintenance

     67,556        10,402            47,842   

General and administrative

     36,660        7,104            37,212   

Loss on assets sales, net

     181        10            303   

Depreciation and amortization

     80,739        10,545            41,784   

Income from unconsolidated affiliates

     (55,975     (8,121         (15,872

Interest expense, net

     44,696        8,081            34,541   

Loss on debt refinancing, net

     —          —              1,780   

Other income and deductions, net

     (5,055     3,521            3,897   

Income tax expense

     70        245            404   

Discontinued operations

     —          (86         327   
  

 

 

   

 

 

       

 

 

 

Total segment margin

     198,014        26,806            147,272   

Add:

          

Non-cash loss from commodity derivatives

     432        2,250            7,150   
  

 

 

   

 

 

       

 

 

 

Adjusted total segment margin

   $ 198,446      $ 29,056          $ 154,422   
  

 

 

   

 

 

       

 

 

 

RESULTS OF OPERATIONS

Three Months Ended June 30, 2011 vs. Combined Three Months Ended June 30, 2010

 

    Successor     Predecessor                    
    Three Months
Ended
June 30, 2011
    Period  from
Acquisition

(May 26, 2010) to
June 30, 2010
    Period from
April 1,  2010 to
May 25, 2010
    Combined
Three  Months
Ended

June 30, 2010
    Change     Percent  

Total revenues

  $ 356,498      $ 96,980      $ 200,265      $ 297,245      $ 59,253        20

Cost of sales

    259,475        70,174        140,507        210,681        (48,794     23
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

Total segment margin (1)

    97,023        26,806        59,758        86,564        10,459        12

Operation and maintenance

    33,996        10,402        19,315        29,717        (4,279     14

General and administrative

    17,551        7,104        21,809        28,913        11,362        39

Loss on asset sales, net

    153        10        19        29        (124     428

Depreciation and amortization

    40,503        10,545        16,889        27,434        (13,069     48
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

Operating income (loss)

    4,820        (1,255     1,726        471        4,349        923

Income from unconsolidated affiliates

    32,167        8,121        7,959        16,080        16,087        100

Interest expense, net

    (24,689     (8,081     (14,059     (22,140     (2,549     12

Other income and deductions, net

    2,641        (3,521     (624     (4,145     6,786        164
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

Income (loss) from continuing operations before income taxes

    14,939        (4,736     (4,998     (9,734     24,673        253

Income tax expense

    102        245        83        328        226        69
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

Net income (loss) from continuing operations

    14,837        (4,981     (5,081     (10,062     24,899        247

Discontinued operations

    —          86        585        671        (671     100
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

Net income (loss)

    14,837        (4,895     (4,496     (9,391     24,228        258

Net income attributable to noncontrolling interest

    (293     (29     (244     (273     (20     7
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

Net income (loss) attributable to Regency Energy Partners LP

  $ 14,544      $ (4,924   $ (4,740   $ (9,664   $ 24,208        250
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

Gathering and processing segment margin (2)

  $ 50,495      $ 14,373      $ 35,195      $ 49,568      $ 927        2

Non-cash loss from commodity derivatives

    2,147        2,250        3,344        5,594        (3,447     62
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

Adjusted gathering and processing segment

margin

    52,642        16,623        38,539        55,162        (2,520     5

Contract compression segment margin (3)

    36,973        12,488        25,326        37,814        (841     2

Contract treating segment margin

    7,701        —          —          —          7,701        100

Corporate and others segment margin (2)

    4,762        1,943        3,031        4,974        (212     4

Intersegment eliminations (3)

    (2,908     (1,998     (3,794     (5,792     2,884        50
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

Adjusted total segment margin

  $ 99,170      $ 29,056      $ 63,102      $ 92,158      $ 7,012        8
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

(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) Segment margin differs from previously disclosed amounts due to the presentation as discontinued operations for the disposition of our east Texas assets, as well as a functional reorganization of our operating segments.
(3) Contract Compression segment margin includes intersegment revenues of $2.9 million and $5.8 million for the three months ended June 30, 2011 and June 30, 2010, respectively. These intersegment revenues were eliminated upon consolidation.

 

28


Table of Contents

Net Income (Loss) Attributable to Regency Energy Partners LP. Our income increased to $14.5 million for the three months ended June 30, 2011 from a net loss of $9.7 million for the combined three months ended June 30, 2010. The major components of this change were as follows:

 

   

$16.1 million increase in income from unconsolidated affiliates from the acquisition of a 30% interest in Lone Star in May 2011 and the acquisition of a 49.9% interest in MEP in May 2010;

 

   

$11.4 million decrease in general and administrative expense related to the vesting of the outstanding restricted and phantom units that occurred in the second quarter of 2010 upon the change in control resulting from the acquisition of our General Partner;

 

   

$10.5 million increase in total segment margin primarily from the addition of the Contract Treating segment acquired in September 2010; offset by

 

   

$13.1 million increase in depreciation and amortization expense primarily related to the completion of various organic growth projects since June 2010 and the increase of property, plant and equipment and intangible amounts resulting from the fair value adjustments upon the change of control resulting from the acquisition of our General Partner in May 2010.

Adjusted Total Segment Margin. Adjusted total segment margin increased to $99.2 million in the three months ended June 30, 2011 from $92.2 million in the combined three months ended June 30, 2010. The major components of this change were as follows:

 

   

Adjusted Gathering and Processing segment margin decreased to $52.6 million during the three months ended June 30, 2011 from $55.2 million for the combined three months ended June 30, 2010 primarily due to lower realized commodity prices and lower production in north Louisiana, offset by volume growth in the Eagle Ford Shale and west Texas. Total Gathering and Processing throughput increased to 1,063,000 MMBtu/d during the three months ended June 30, 2011 from 1,002,000 MMBtu/d during the three months ended June 30, 2010. Total NGL gross production increased to 28,000 Bbls/d during the three months ended June 30, 2011 from 25,000 Bbls/d during the three months ended June 30, 2010;

 

   

Contract Compression segment margin decreased to $37 million in the three months ended June 30, 2011 from $37.8