fom10q.htm
UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-Q
(Mark
One)
þ
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|
QUARTERLY
REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF
1934
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For
the quarterly period ended March 31, 2008
OR
o
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TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF
1934
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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
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|
16-1731691
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(State
or other jurisdiction of incorporation or organization)
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(I.R.S.
Employer Identification No.)
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1700
PACIFIC AVENUE, SUITE 2900
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DALLAS,
TX
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75201
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(Address
of principal executive offices)
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(Zip
Code)
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(214)
750-1771
(Registrant’s
telephone number, including area code)
NONE
(Former
name, former address and former fiscal year, if changed since last
report.)
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.
þ Yes o 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 þ
Accelerated filer o
Non-accelerated filer (Do not check if a smaller reporting company) o Smaller reporting
company o
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act). o Yes þ No
The
issuer had 45,507,373 common units, 7,276,506 Class D common units, and
19,103,896 subordinated units outstanding as of April 30, 2008.
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1
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17
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26
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27
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PART
II — OTHER INFORMATION
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27
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27
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27
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Item
6. Exhibits
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Introductory
Statement
References
in this report to the “Partnership,” “we,” “our,” “us” and similar terms, when
used in a historical context, refer to Regency Energy Partners LP, or the
Partnership, and to Regency Gas Services LLC and its subsidiaries, all the
outstanding member interests of which were contributed to the Partnership on
February 3, 2006. 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
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Definition
or Description
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ASC
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ASC
Hugoton LLC, an affiliate of GECC
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BBE
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BlackBrush
Energy, Inc.
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Bbls/d
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Barrels
per day
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BBOG
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BlackBrush
Oil & Gas, LP
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Bcf
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One
billion cubic feet
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Bcf/d
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One
billion cubic feet per day
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BTU
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A
unit of energy needed to raise the temperature of one pound of water by
one degree Fahrenheit
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CDM
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CDM
Resource Management LLC
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CDM
GP
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CDM
OLP GP, LLC, the sole general partner of CDM
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CDM
LP
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CDMR
Holdings, LLC, the sole limited partner of CDM
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CERCLA
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Comprehensive
Environmental Response, Compensation and Liability Act
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DOT
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U.S.
Department of Transportation
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EIA
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Energy
Information Administration
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Enbridge
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Enbridge
Pipelines (NE Texas), LP, Enbridge Pipeline (Texas Interstate), LP and
Enbridge Pipelines (Texas Gathering), LP
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EnergyOne
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FrontStreet
EnergyOne LLC
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EPA
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Environmental
Protection Agency
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FASB
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Financial
Accounting Standards Board
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FERC
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Federal
Energy Regulatory Commission
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FrontStreet
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FrontStreet
Hugoton LLC
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Fund
V
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Hicks,
Muse, Tate & Furst Equity Fund V, L.P.
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GAAP
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Accounting
principles generally accepted in the United States
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GE
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General
Electric Company
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GE
EFS
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General
Electric Energy Financial Services, a unit of GECC, combined with Regency
GP Acquirer LP and Regency LP Acquirer LP
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GECC
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General
Electric Capital Corporation, an indirect wholly owned subsidiary of
GE
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General
Partner
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Regency
GP LP, the general partner of the Partnership, or Regency GP LLC, the
general partner of Regnecy GP LP, which effectively manages the business
and affairs of the Partnership
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GSTC
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Gulf
States Transmission Corporation
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HLPSA
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Hazardous
Liquid Pipeline Safety Act
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HM
Capital
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HM
Capital Partners LLC
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HM
Capital Investors
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Regency
Acquisition LP, HMTF Regency L.P., HM Capital and funds managed by HM
Capital, including Fund V, and certain co-investors, including some of the
directors and officers of the Managing GP
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HMTF
Gas Partners
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HMTF
Gas Partners II, LP
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HMTF
Regency
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HMTF
Regency L.P.
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IRS
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Internal
Revenue Service
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LIBOR
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London
Interbank Offered Rate
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Managing
GP
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Regency
GP LLC, the general partner of the General Partner, which effectively
manages the Partnership
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MMbtu
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One
million BTUs
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MMbtu/d
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One
million BTUs per day
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MMcf
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One
million cubic feet
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MMcf/d
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One
million cubic feet per day
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MQD
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Minimum
Quarterly Distribution
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NGA
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Natural
Gas Act of 1938
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NGLs
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Natural
gas liquids
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NGPA
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Natural
Gas Policy Act of 1978
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NGPSA
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Natural
Gas Pipeline Safety Act of 1968, as amended
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NPDES
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National
Pollutant Discharge Elimination System
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Nasdaq
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Nasdaq
Stock Market, LLC
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NYMEX
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New
York Mercantile Exchange
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OSHA
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Occupational
Safety and Health Act
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Partnership
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Regency
Energy Partners LP
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Pueblo
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Pueblo
Midstream Gas Corporation
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RCRA
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Resource
Conservation and Recovery Act
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RFS |
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Regency
Field Services LLC |
RGS
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Regency
Gas Services LLC
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RIGS
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Regency
Intrastate Gas LLC
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SEC
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Securities
and Exchange Commission
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SFAS
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Statement
of Financial Accounting Standard
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Tcf
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One
trillion cubic feet
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Tcf/d
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One
trillion cubic feet per day
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TexStar
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TexStar
Field Services, L.P. and its general partner, TexStar GP,
LLC
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TRRC
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Texas
Railroad Commission
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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 and Section 21E of the
Securities Exchange Act of 1934. 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 can not 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:
·
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changes
in laws and regulations impacting the midstream sector of the natural gas
industry;
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·
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the
level of creditworthiness of our counterparties and
customers;
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·
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our
ability to access the debt and equity
markets;
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·
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our
use of derivative financial instruments to hedge commodity and interest
rate risks;
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·
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the
amount of collateral required to be posted from time to time in our
transactions;
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·
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changes
in commodity prices, interest rates, demand for our
services;
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·
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weather
and other natural phenomena;
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·
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industry
changes including the impact of consolidations and changes in
competition;
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·
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our
ability to obtain required approvals for construction or modernization of
our facilities and the timing of production from such facilities;
and
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·
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the
effect of accounting pronouncements issued periodically by accounting
standard setting boards.
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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.
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.
Regency
Energy Partners LP
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Condensed
Consolidated Balance Sheets
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(in
thousands except unit data)
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March
31, 2008
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December
31, 2007*
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(Unaudited)
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ASSETS
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Current
Assets:
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Cash
and cash equivalents
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$ |
10,876 |
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$ |
32,971 |
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Restricted
cash
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14,568 |
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6,029 |
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Accounts
receivable, trade, net of allowance of $231 in 2008 and $61 in
2007
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32,474 |
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16,487 |
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Accrued
revenues
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141,663 |
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117,622 |
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Related
party receivables
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168 |
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61 |
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Assets
from risk management activities
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487 |
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- |
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Other
current assets
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8,471 |
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6,723 |
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Total
current assets
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208,707 |
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179,893 |
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Property,
plant and equipment
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Gas
plants and buildings
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134,976 |
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134,300 |
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Gathering
and transmission systems
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1,268,451 |
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780,761 |
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Other
property, plant and equipment
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111,285 |
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105,399 |
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Construction-in-progress
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94,056 |
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33,552 |
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Total
property, plant and equipment
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1,608,768 |
|
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|
1,054,012 |
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Less
accumulated depreciation
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|
(160,000 |
) |
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|
(140,903 |
) |
Property,
plant and equipment, net
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|
1,448,768 |
|
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913,109 |
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|
|
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Other
Assets:
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|
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Intangible
assets, net of accumulated amortization of $11,512 in 2008 and $8,929 in
2007
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155,701 |
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77,804 |
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Long-term
assets from risk management activities
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708 |
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- |
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Other,
net of accumulated amortization of debt issuance costs of $3,146 in 2008
and $2,488 in 2007
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41,469 |
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13,529 |
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Goodwill
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298,580 |
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94,075 |
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Total
other assets
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496,458 |
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185,408 |
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TOTAL
ASSETS
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$ |
2,153,933 |
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$ |
1,278,410 |
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LIABILITIES
& PARTNERS' CAPITAL
|
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Current
Liabilities:
|
|
|
|
|
|
|
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Accounts
payable, trade
|
|
$ |
55,710 |
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$ |
48,904 |
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Accrued
cost of gas and liquids
|
|
|
113,974 |
|
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|
96,026 |
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Related
party payables
|
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10 |
|
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50 |
|
Escrow
payable
|
|
|
14,568 |
|
|
|
6,029 |
|
Liabilities
from risk management activities
|
|
|
35,584 |
|
|
|
37,852 |
|
Other
current liabilities
|
|
|
27,646 |
|
|
|
9,397 |
|
Total
current liabilities
|
|
|
247,492 |
|
|
|
198,258 |
|
|
|
|
|
|
|
|
|
|
Long-term
liabilities from risk management activities
|
|
|
14,033 |
|
|
|
15,073 |
|
Other
long-term liabilities
|
|
|
16,075 |
|
|
|
15,393 |
|
Long-term
debt
|
|
|
1,090,500 |
|
|
|
481,500 |
|
Minority
interest in consolidated subsidiary
|
|
|
885 |
|
|
|
4,893 |
|
|
|
|
|
|
|
|
|
|
Commitments
and contingencies
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partners'
Capital:
|
|
|
|
|
|
|
|
|
Common
units (41,277,082 and 41,283,079 units authorized; 40,700,898 and
40,514,895 units issued and outstanding at March 31, 2008 and December 31,
2007)
|
|
|
481,455 |
|
|
|
490,351 |
|
Class
D common units (7,276,506 units authorized, issued and outstanding at
March 31, 2008)
|
|
|
219,590 |
|
|
|
- |
|
Class
E common units (4,701,034 units authorized, issued and outstanding at
March 31, 2008 and December 31, 2007)
|
|
|
92,962 |
|
|
|
92,962 |
|
Subordinated
units (19,103,896 units authorized, issued and outstanding at March 31,
2008 and December 31, 2007)
|
|
|
2,438 |
|
|
|
7,019 |
|
General
partner interest
|
|
|
19,227 |
|
|
|
11,286 |
|
Accumulated
other comprehensive loss
|
|
|
(30,724 |
) |
|
|
(38,325 |
) |
Total
partners' capital
|
|
|
784,948 |
|
|
|
563,293 |
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND PARTNERS' CAPITAL
|
|
$ |
2,153,933 |
|
|
$ |
1,278,410 |
|
|
|
|
|
|
|
|
|
|
See
accompanying notes to condensed consolidated financial
statements
|
|
|
|
|
|
|
|
|
|
|
*
Recast to reflect an acquisition accounted for in a manner similar to a
pooling of interests.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Condensed
Consolidated Statements of Operations
|
|
Unaudited
|
|
(in
thousands except unit data and per unit data)
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
March
31, 2008
|
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March
31, 2007
|
|
|
|
|
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|
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REVENUES
|
|
|
|
|
|
|
Gas
sales
|
|
$ |
236,692 |
|
|
$ |
167,384 |
|
NGL
sales
|
|
|
108,499 |
|
|
|
63,541 |
|
Gathering,
transportation and other fees, including related party amounts of $53 and
$353
|
|
|
61,986 |
|
|
|
19,878 |
|
Net
realized and unrealized loss from risk management
activities
|
|
|
(13,657 |
) |
|
|
(85 |
) |
Other
|
|
|
11,715 |
|
|
|
5,710 |
|
Total
revenues
|
|
|
405,235 |
|
|
|
256,428 |
|
|
|
|
|
|
|
|
|
|
OPERATING
COSTS AND EXPENSES
|
|
|
|
|
|
|
|
|
Cost
of sales, including related party amounts of $403 and
$5,418
|
|
|
313,589 |
|
|
|
211,937 |
|
Operation
and maintenance
|
|
|
28,845 |
|
|
|
10,925 |
|
General
and administrative
|
|
|
10,923 |
|
|
|
6,851 |
|
Loss
on asset sales, net
|
|
|
- |
|
|
|
1,808 |
|
Management
services termination fee
|
|
|
3,888 |
|
|
|
- |
|
Transaction
expenses
|
|
|
348 |
|
|
|
- |
|
Depreciation
and amortization
|
|
|
21,741 |
|
|
|
11,427 |
|
Total
operating costs and expenses
|
|
|
379,334 |
|
|
|
242,948 |
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
25,901 |
|
|
|
13,480 |
|
|
|
|
|
|
|
|
|
|
Interest
expense, net
|
|
|
(15,406 |
) |
|
|
(14,885 |
) |
Other
income and deductions, net
|
|
|
176 |
|
|
|
110 |
|
Minority
interest
|
|
|
(72 |
) |
|
|
- |
|
INCOME
(LOSS) BEFORE INCOME TAXES
|
|
|
10,599 |
|
|
|
(1,295 |
) |
|
|
|
|
|
|
|
|
|
Income
tax expense
|
|
|
251 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
NET
INCOME (LOSS)
|
|
$ |
10,348 |
|
|
$ |
(1,295 |
) |
Less:
|
|
|
|
|
|
|
|
|
General
partner's make-whole allocation for prior year losses
|
|
$ |
569 |
|
|
$ |
- |
|
General
partner's interest in current period net income (loss)
|
|
|
196 |
|
|
|
(26 |
) |
Beneficial
conversion feature for Class C common units
|
|
|
- |
|
|
|
1,385 |
|
Beneficial
conversion feature for Class D common units
|
|
|
1,559 |
|
|
|
- |
|
Limited
partners' interest in net income (loss)
|
|
$ |
8,024 |
|
|
$ |
(2,654 |
) |
|
|
|
|
|
|
|
|
|
Earnings
per unit:
|
|
|
|
|
|
|
|
|
Amount
allocated to common and subordinated units
|
|
$ |
8,024 |
|
|
$ |
(2,654 |
) |
Weighted
average number of common and subordinated units
outstanding
|
|
|
59,229,507 |
|
|
|
42,356,956 |
|
Basic
income (loss) per common and subordinated unit
|
|
$ |
0.14 |
|
|
$ |
(0.06 |
) |
Diluted
income (loss) per common and subordinated unit |
|
$ |
0.13 |
|
|
$ |
(0.06 |
) |
Distributions
per unit
|
|
$ |
0.40 |
|
|
$ |
0.38 |
|
|
|
|
|
|
|
|
|
|
Amount
allocated to Class B common units
|
|
$ |
- |
|
|
$ |
- |
|
Weighted
average number of Class B common units outstanding
|
|
|
- |
|
|
|
2,644,074 |
|
Basic
and diluted income per Class B common unit
|
|
$ |
- |
|
|
$ |
- |
|
Distributions
per unit
|
|
$ |
- |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
Amount
allocated to Class C common units
|
|
$ |
- |
|
|
$ |
1,385 |
|
Total
number of Class C common units outstanding
|
|
|
- |
|
|
|
2,857,143 |
|
Basic
and diluted income per Class C common unit due to beneficial conversion
feature
|
|
$ |
- |
|
|
$ |
0.48 |
|
Distributions
per unit
|
|
$ |
- |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
Amount
allocated to Class D common units
|
|
$ |
1,559 |
|
|
$ |
- |
|
Total
number of Class D common units outstanding
|
|
|
7,276,506 |
|
|
|
- |
|
Basic
and diluted income per Class D common unit due to beneficial conversion
feature
|
|
$ |
0.21 |
|
|
$ |
- |
|
Distributions
per unit
|
|
$ |
- |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
Amount
allocated to Class E common units
|
|
$ |
- |
|
|
$ |
- |
|
Weighted
average number of Class E common units outstanding
|
|
|
4,701,034 |
|
|
|
- |
|
Basic
and diluted income per Class E common unit
|
|
$ |
- |
|
|
$ |
- |
|
Distributions
per unit
|
|
$ |
- |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
See
accompanying notes to condensed consolidated financial
statements
|
|
Regency
Energy Partners LP
|
Condensed
Consolidated Statements of Comprehensive Income (Loss)
|
Unaudited
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
March
31, 2008
|
|
|
March
31, 2007
|
|
|
|
|
|
|
|
|
Net
income (loss)
|
|
$ |
10,348 |
|
|
$ |
(1,295 |
) |
Hedging amounts
reclassified to earnings
|
|
|
10,435 |
|
|
|
(54 |
) |
Net
change in fair value of cash flow hedges
|
|
|
(2,834 |
) |
|
|
(12,445 |
) |
Comprehensive
income (loss)
|
|
$ |
17,949 |
|
|
$ |
(13,794 |
) |
|
|
|
|
|
|
|
|
|
See
accompanying notes to condensed consolidated financial
statements
|
|
|
Condensed
Consolidated Statements of Cash Flows
|
|
Unaudited
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
March
31, 2008
|
|
|
March
31, 2007
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
|
Net
income (loss)
|
|
$ |
10,348 |
|
|
$ |
(1,295 |
) |
Adjustments
to reconcile net income (loss) to net cash flows provided by operating
activities:
|
|
|
|
|
|
|
|
|
Depreciation
and amortization, including debt issuance cost
amortization
|
|
|
22,398 |
|
|
|
11,986 |
|
Equity
income
|
|
|
- |
|
|
|
(43 |
) |
Risk
management portfolio valuation changes
|
|
|
3,098 |
|
|
|
(124 |
) |
Loss
on asset sales
|
|
|
- |
|
|
|
1,808 |
|
Unit
based compensation expenses
|
|
|
794 |
|
|
|
1,103 |
|
Cash
flow changes in current assets and liabilities:
|
|
|
|
|
|
|
|
|
Accounts
receivable and accrued revenues
|
|
|
(19,264 |
) |
|
|
(1,959 |
) |
Other
current assets
|
|
|
2,800 |
|
|
|
598 |
|
Accounts payable, accrued cost of gas and liquids and accrued
liabilities
|
|
|
25,950 |
|
|
|
5,220 |
|
Other current liabilities
|
|
|
18,249 |
|
|
|
10,617 |
|
Other
assets and liabilities
|
|
|
(6,835 |
) |
|
|
(441 |
) |
Net
cash flows provided by operating activities
|
|
|
57,538 |
|
|
|
27,470 |
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Capital
expenditures
|
|
|
(97,896 |
) |
|
|
(47,501 |
) |
Acquisitions
|
|
|
(574,059 |
) |
|
|
- |
|
Acquisition
of investment in unconsolidated subsidiary, net of $100
cash
|
|
|
- |
|
|
|
(5,000 |
) |
Proceeds
from asset sales
|
|
|
- |
|
|
|
5,610 |
|
Net
cash flows used in investing activities
|
|
|
(671,955 |
) |
|
|
(46,891 |
) |
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Net
borrowings under revolving credit facilities
|
|
|
609,000 |
|
|
|
33,400 |
|
Partner
contributions
|
|
|
7,663 |
|
|
|
6 |
|
Partner
distributions
|
|
|
(24,341 |
) |
|
|
(14,620 |
) |
Net
cash flows provided by financing activities
|
|
|
592,322 |
|
|
|
18,786 |
|
|
|
|
|
|
|
|
|
|
Net
decrease in cash and cash equivalents
|
|
|
(22,095 |
) |
|
|
(635 |
) |
Cash
and cash equivalents at beginning of period
|
|
|
32,971 |
|
|
|
9,139 |
|
Cash
and cash equivalents at end of period
|
|
$ |
10,876 |
|
|
$ |
8,504 |
|
|
|
|
|
|
|
|
|
|
Supplemental
cash flow information:
|
|
|
|
|
|
|
|
|
Interest
paid, net of amounts capitalized
|
|
$ |
5,047 |
|
|
$ |
2,540 |
|
Non-cash
capital expenditures in accounts payable
|
|
|
18,517 |
|
|
|
10,509 |
|
Non-cash
capital expenditures for consolidation of investment in previously
unconsolidated subsidiary
|
|
|
- |
|
|
|
5,650 |
|
Issuance
of Class D common units for an acquisition
|
|
|
219,590 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
See
accompanying notes to condensed consolidated financial
statements
|
|
|
Condensed
Consolidated Statements of Partners' Capital
|
|
Unaudited
|
|
(in
thousands except unit data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Units
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
|
|
|
Class
D
|
|
|
Class
E
|
|
|
Subordinated
|
|
|
Common
Unitholders
|
|
|
Class
D Unitholders
|
|
|
Class
E Unitholders
|
|
|
Subordinated
Unitholders
|
|
|
General
Partner Interest
|
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
Total
|
|
Balance
- December 31, 2007 *
|
|
|
40,514,895 |
|
|
|
- |
|
|
|
4,701,034 |
|
|
|
19,103,896 |
|
|
$ |
490,351 |
|
|
$ |
- |
|
|
$ |
92,962 |
|
|
$ |
7,019 |
|
|
$ |
11,286 |
|
|
$ |
(38,325 |
) |
|
$ |
563,293 |
|
Issuance
of Class D common units
|
|
|
- |
|
|
|
7,276,506 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
219,590 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
219,590 |
|
Issuance
of restricted common units and option exercises, net of
forfeitures
|
|
|
186,003 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Unit
based compensation expenses
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
794 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
794 |
|
General
partner contributions
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
7,663 |
|
|
|
- |
|
|
|
7,663 |
|
Partner
distributions
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(16,212 |
) |
|
|
- |
|
|
|
- |
|
|
|
(7,642 |
) |
|
|
(487 |
) |
|
|
- |
|
|
|
(24,341 |
) |
Net
income
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
6,522 |
|
|
|
- |
|
|
|
- |
|
|
|
3,061 |
|
|
|
765 |
|
|
|
- |
|
|
|
10,348 |
|
Net
hedging amounts reclassified to earnings
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
10,435 |
|
|
|
10,435 |
|
Net
change in fair value of cash flow hedges
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(2,834 |
) |
|
|
(2,834 |
) |
Balance
- March 31, 2008
|
|
|
40,700,898 |
|
|
|
7,276,506 |
|
|
|
4,701,034 |
|
|
|
19,103,896 |
|
|
$ |
481,455 |
|
|
$ |
219,590 |
|
|
$ |
92,962 |
|
|
$ |
2,438 |
|
|
$ |
19,227 |
|
|
$ |
(30,724 |
) |
|
$ |
784,948 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See
accompanying notes to condensed consolidated financial
statements
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*Recast
to reflect an acquisition accounted for in a manner similar to a pooling
of interests.
|
Regency
Energy Partners LP
Notes
to Unaudited Condensed Consolidated Financial Statements
1. Organization
and Summary of Significant Accounting Policies
Organization and Basis of
Presentation. The unaudited condensed consolidated financial
statements presented herein contain the results of Regency Energy Partners LP, a
Delaware limited partnership, and its wholly owned subsidiaries. The
Partnership and its subsidiaries are engaged in the business of gathering,
processing, contract compression, marketing, and transportation of natural gas
and/or NGLs. The Partnership operates and manages its business as
three reportable segments: a) gathering and processing, b) transportation, and
c) contract compression.
On
January 7, 2008, the Partnership acquired all the outstanding equity of
FrontStreet (the “FrontStreet Acquisition”) from ASC and EnergyOne for the
issuance of 4,701,034 Class E common units of the Partnership to ASC and the
cash payment of $11,752,000 to EnergyOne, inclusive of a payment to terminate a
management services agreement in the amount of
$3,880,000. FrontStreet owns a gas gathering system located in Kansas
and Oklahoma, which is operated by a third party.
The
Partnership financed the cash portion of the purchase price with borrowings
under its revolving credit facility. In connection with the FrontStreet
Acquisition, the General Partner entered into Amendment No. 3 to the Amended and
Restated Agreement of Limited Partnership of the Partnership, which created the
Partnership’s Class E common units. The Class E common units have the same
terms and conditions as the Partnership’s common units, except that the Class E
common units are not entitled to participate in earnings or distributions of
operating surplus by the Partnership. The Class E common units were issued
in a private offering conducted in accordance with the exemption from the
registration requirements of the Securities Act of 1933 afforded by Section 4(2)
thereof. The Class E common units converted into common units on a
one-for-one basis on May 5, 2008.
Because
the FrontStreet Acquisition is a transaction between commonly controlled
entities (i.e., the buyer and the sellers were each affiliates of GECC), the
Partnership accounted for the acquisition in a manner similar to the pooling of
interests method. Under this method of accounting, the Partnership
reflected the historical balance sheet data for both the Partnership and
FrontStreet instead of reflecting the fair market value of FrontStreet’s assets
and liabilities. Further, certain transaction costs that would normally be
capitalized were expensed. Common control between the Partnership and
FrontStreet began on June 18, 2007. The Partnership recast the
December 31, 2007 financial statements to reflect the as-if pooling accounting
treatment of this acquisition. The three months ended March 31, 2008
statement of operations includes FrontStreet’s results for the entire
quarter.
The
unaudited financial information as of, and for the three months ended, March 31,
2008 has been prepared on the same basis as the audited consolidated financial
statements included in the Partnership’s Annual Report on Form 10-K and in
the Form 8-K filed on May 9, 2008 for the year ended December 31,
2007. In the opinion of the Partnership’s management, such financial
information reflects all adjustments necessary for a fair presentation of the
financial position and the results of operations for such interim periods in
accordance with GAAP. All intercompany items and transactions have
been eliminated in consolidation. Certain information and footnote disclosures
normally included in annual consolidated financial statements prepared in
accordance with GAAP have been omitted pursuant to the rules and regulations of
the SEC.
Use of
Estimates. The unaudited condensed consolidated financial
statements have been prepared in conformity with GAAP and, of necessity, include
the use of estimates and assumptions by management. Actual results could differ
from these estimates.
Intangible
Assets. The total gross carrying amount of intangible assets
that were subject to amortization was $167,213,000 and $86,733,000 at March 31,
2008 and December 31, 2007, respectively. Aggregate amortization
expense for the three months ended March 31, 2008 and 2007 was $2,583,000 and
$993,000, respectively.
Recently Issued Accounting
Standards. In January 2007, the FASB issued SFAS No. 159, “The
Fair Value Option for Financial Assets and Financial Liabilities, Including an
Amendment of FASB Statement No. 115” (“SFAS No. 159”), which permits entities to
measure many financial instruments and certain other assets and liabilities at
fair value on an instrument-by-instrument basis. The adoption of SFAS
No. 159 in the three months ended March 31, 2008 had no impact on the
Partnership’s financial position, results of operations or cash flows, as the
Partnership has elected to continue valuing its outstanding senior notes at
historical cost.
In
December 2007, the FASB issued SFAS No. 141(R) “Business Combinations” (“SFAS
No. 141(R)”), which significantly changes the accounting for business
acquisitions both during the period of the acquisition and in subsequent
periods. SFAS No. 141(R) is effective for fiscal years beginning
after December 15, 2008. Generally, the effects of SFAS
No. 141(R) will depend on future acquisitions.
In
December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in
Consolidated Financial Statements, an amendment of ARB No. 51” (“SFAS No. 160”),
which will significantly change the accounting and reporting related to
noncontrolling interests in a consolidated subsidiary. SFAS No. 160
is effective for fiscal years beginning after December 15, 2008. The
Partnership is currently evaluating the potential impacts on its financial
position, results of operations or cash flows of the adoption of this
standard.
In
March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative
Instruments and Hedging Activities, an amendment of FASB Statement No. 133” (“SFAS
No. 161”). SFAS No. 161 requires enhanced disclosures about
derivative and hedging activities. These enhanced disclosures will
address (a) how and why a company uses derivative instruments, (b) how
derivative instruments and related hedged items are accounted for under FASB
Statement No. 133 and its related interpretations and (c) how derivative
instruments and related hedged items affect a company’s financial position,
results of operations and cash flows. SFAS No. 161 is effective for
fiscal years beginning on or after November 15, 2008, with earlier adoption
allowed. The Partnership is currently evaluating the potential
impacts on its financial position, results of operations or cash flows of the
adoption of this standard.
2. Income
(Loss) per Limited Partner Unit
In
connection with the CDM acquisition, the Partnership issued 7,276,506 Class D
common units. At the commitment date, the sales price of $30.18 per
unit represented a $1.10 discount from the fair value of the Partnership’s
common units. Under EITF No. 98-5, “Accounting for Convertible
Securities with Beneficial Conversion Features or Contingently Adjustable
Conversion Ratios,” the discount represented a beneficial conversion feature
(“BCF”) that is treated as a non-cash distribution for purposes of calculating
earnings per unit. The BCF is reflected in income per unit using the
effective yield method over the period the Class D common units are outstanding,
as indicated on the statements of operations in the line item entitled
“beneficial conversion feature for Class D common units.”
The
following table provides a reconciliation of the numerator and denominator of
the basic and diluted earnings per unit computations for the three months ended
March 31, 2008.
|
|
For
the Three Months Ended March 31, 2008
|
|
|
|
Income
(Numerator)
|
|
|
Units
(Denominator)
|
|
|
Per-Unit
Amount
|
|
|
|
(in
thousands)
|
|
|
|
|
|
|
|
Basic
Earnings per Unit
|
|
|
|
|
|
|
|
|
|
Limited
partners' interest in net income
|
|
$ |
8,024 |
|
|
|
59,229,507 |
|
|
$ |
0.14 |
|
Effect
of Dilutive Securities
|
|
|
|
|
|
|
|
|
|
|
|
|
Class
D common units
|
|
|
1,559 |
|
|
|
7,276,506 |
|
|
|
|
|
Class
E common units
|
|
|
- |
|
|
|
4,701,034 |
|
|
|
|
|
Common
unit options
|
|
|
- |
|
|
|
207,817 |
|
|
|
|
|
Restricted
(nonvested) common units
|
|
|
- |
|
|
|
- |
|
|
|
|
|
Diluted
Earnings per Unit
|
|
$ |
9,583 |
|
|
|
71,414,864 |
|
|
$ |
0.13 |
|
The
following data show securities that could potentially dilute earnings per unit
in the future that were not included in the computation of diluted EPS because
to do so would have been antidilutive for the period(s) presented.
|
|
March
31, 2008
|
|
|
March
31, 2007
|
|
Restricted
common units
|
|
|
555,000 |
|
|
|
687,500 |
|
Common
unit options
|
|
|
- |
|
|
|
884,866 |
|
Class
B common units
|
|
|
- |
|
|
|
5,173,189 |
|
Class
C common units
|
|
|
- |
|
|
|
2,857,143 |
|
3. Acquisitions
CDM Resource Management,
Ltd. On January 15, 2008, the Partnership and an indirect
wholly owned subsidiary of the Partnership (“Merger Sub”) consummated an
agreement and plan of merger (the “Merger Agreement”) with CDM Resource
Management, Ltd., CDM GP, and CDM LP (each a “CDM Partner” and together the “CDM
Partners”). Upon closing, CDM merged with and into Merger Sub, with
Merger Sub continuing as the surviving entity after the merger (the “CDM
Merger”). Following the merger, Merger Sub changed its name to CDM
Resource Management LLC. CDM provides its customers with turn-key natural
gas contract compression services to maximize their natural gas and crude oil
production, throughput, and cash flow in Texas, Louisiana, and
Arkansas. The Partnership operates and manages CDM as a separate reportable
segment.
The total
purchase price, subject to customary post-closing adjustments, paid by the
Partnership for the partnership interests of CDM consisted of (1) the
issuance of an aggregate of 7,276,506 Class D common units of the Partnership,
which were valued at $219,590,000, (2) the payment of an aggregate of
$161,945,000 in cash to the CDM Partners, and (3) the payment of $316,500,000 to
retire CDM’s debt obligations. Of the Class D common units issued,
4,197,303 Class D common units were deposited with an escrow agent pursuant to
an escrow agreement. Such common units constitute security to the
Partnership for a period of one year after the closing of the CDM
Merger with respect to any obligations of the CDM Partners under the Merger
Agreement, including obligations for breaches of representation, warranties and
covenants. In connection with the CDM Merger, the General Partner entered
into Amendment No. 4 to the Amended and Restated Agreement of Limited
Partnership of the Partnership, which created the Partnership’s Class D common
units. The Class D common units have the same terms and conditions as
the Partnership’s common units, except that the Class D common units are not
entitled to participate in distributions of operating surplus by the
Partnership. The Class D common units automatically convert into common
units on a one-for-one basis on the close of business on the first business day
after the record date for the quarterly distribution on the common units for the
quarter ending December 31, 2008. The Class D common units were issued in
a private offering conducted in accordance with the exemption from the
registration requirements of the Securities Act of 1933 afforded by Section
4(2) thereof.
The total
purchase price of $698,035,000 was allocated preliminarily as follows based on
estimates of the fair values of the assets acquired and the liabilities
paid.
|
|
At
January 15, 2008
|
|
|
|
(in
thousands)
|
|
|
|
|
|
Working
capital
|
|
$ |
19,276 |
|
Other
assets
|
|
|
4,548 |
|
Gas
plants and buildings
|
|
|
501 |
|
Gathering
and transmission systems
|
|
|
410,075 |
|
Other
property, plant and equipment
|
|
|
3,649 |
|
Construction-in-progress
|
|
|
40,737 |
|
Identifiable
intangible assets
|
|
|
80,480 |
|
Goodwill
|
|
|
138,769 |
|
Net
assets acquired
|
|
$ |
698,035 |
|
The final
purchase price allocation, which management expects to be completed before year
end, may differ from the above estimates.
Nexus Gas Holdings,
LLC. On March 25, 2008, the Partnership acquired Nexus Gas Holdings,
LLC, a Delaware limited liability company (“Nexus”) (“Nexus Acquisition”) by
merger for $87,749,000 in cash, including customary closing
adjustments. Nexus Gas Partners LLC, the sole member of Nexus prior
to the merger (“Nexus Member”), deposited $8,500,000 in an escrow account as
security to the Partnership for a period of one year against indemnification
obligations and any purchase price adjustment. The Partnership funded
the Nexus Acquisition through borrowings under the existing revolving credit
facility.
Upon
consummation of the Nexus Acquisition, the Partnership acquired Nexus’ rights
under a Purchase and Sale Agreement (the “Sonat Agreement”) between Nexus and
Southern Natural Gas Company (“Sonat”). Pursuant to the Sonat
Agreement, Nexus will purchase 136 miles of pipeline from Sonat (the “Sonat
Asset Acquisition”) that would enable the Nexus gathering system to be
integrated into the Partnership’s north Louisiana asset base. The
Sonat Asset Acquisition is subject to abandonment approval and jurisdictional
redetermination by the FERC, as well as customary closing
conditions. Upon closing of the Sonat Asset Acquisition, the
Partnership will pay Sonat $27,500,000, and, if the closing occurs on or prior
to March 1, 2010, on certain terms and conditions as provided in the Merger
Agreement, the Partnership will make an additional payment of $25,000,000 to the
Nexus Member.
The total
purchase price of $87,749,000 was allocated preliminarily as follows based on
estimates of the fair values of the assets acquired.
|
|
At
March 25, 2008
|
|
|
|
(in
thousands)
|
|
|
|
|
|
Working
capital
|
|
$ |
2,748 |
|
Buildings
|
|
|
12 |
|
Gathering
and transmission systems
|
|
|
8,403 |
|
Other
property, plant and equipment
|
|
|
11,096 |
|
Goodwill
|
|
|
65,490 |
|
Net
assets acquired
|
|
$ |
87,749 |
|
The final
purchase price allocation, which management expects to be completed before year
end, may differ from the above estimates.
The
following unaudited pro forma financial information has been prepared as if the
acquisitions of FrontStreet, CDM and Nexus had occurred as of the beginning of
the periods presented. In the three months ended March 31, 2007, the
Partnership’s acquisition of Pueblo is included since that acquisition occurred
in April 2007. Such unaudited pro forma information does not purport
to be indicative of the results of operations that would have been achieved if
the transactions to which the Partnership is giving pro forma effect actually
occurred on the date referred to above or the results of operations that may be
expected in the future.
|
|
Pro
Forma Results for the Three Months Ended
|
|
|
|
March
31, 2008
|
|
|
March
31, 2007
|
|
|
|
(in
thousands except unit and per unit data)
|
|
Revenue
|
|
$ |
412,443 |
|
|
$ |
297,198 |
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$ |
12,162 |
|
|
$ |
3,487 |
|
Less:
|
|
|
|
|
|
|
|
|
General
partner's make-whole allocation for prior year losses
|
|
|
- |
|
|
|
176 |
|
General
partner's interest in current period net income
|
|
|
243 |
|
|
|
66 |
|
Beneficial
conversion feature for Class C common units
|
|
|
- |
|
|
|
1,385 |
|
Beneficial
conversion feature for Class D common units
|
|
|
1,559 |
|
|
|
- |
|
Limited
partners' interest in net income
|
|
$ |
10,360 |
|
|
$ |
1,860 |
|
|
|
|
|
|
|
|
|
|
Earnings
per unit:
|
|
|
|
|
|
|
|
|
Amount
allocated to common and subordinated units
|
|
$ |
10,360 |
|
|
$ |
1,860 |
|
Weighted
average number of common and subordinated units
outstanding
|
|
|
59,229,507 |
|
|
|
42,356,956 |
|
Basic
income per common and subordinated unit
|
|
$ |
0.17 |
|
|
$ |
0.04 |
|
Diluted
income per common and subordinated unit |
|
$ |
0.16 |
|
|
$ |
0.04 |
|
Distributions
per unit
|
|
$ |
0.40 |
|
|
$ |
0.38 |
|
|
|
|
|
|
|
|
|
|
Amount
allocated to Class B common units
|
|
$ |
- |
|
|
$ |
- |
|
Weighted
average number of Class B common units outstanding
|
|
|
- |
|
|
|
2,644,074 |
|
Basic
and diluted income per Class B common unit
|
|
$ |
- |
|
|
$ |
- |
|
Distributions
per unit
|
|
$ |
- |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
Amount
allocated to Class C common units
|
|
$ |
- |
|
|
$ |
1,385 |
|
Total
number of Class C common units outstanding
|
|
|
- |
|
|
|
2,857,143 |
|
Basic
and diluted income per Class C common unit due to beneficial conversion
feature
|
|
$ |
- |
|
|
$ |
0.48 |
|
Distributions
per unit
|
|
$ |
- |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
Amount
allocated to Class D common units
|
|
$ |
1,559 |
|
|
$ |
- |
|
Total
number of Class D common units outstanding
|
|
|
7,276,506 |
|
|
|
7,276,506 |
|
Basic
and diluted income per Class D common unit due to beneficial conversion
feature
|
|
$ |
0.21 |
|
|
$ |
- |
|
Distributions
per unit
|
|
$ |
- |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
Amount
allocated to Class E common units
|
|
$ |
- |
|
|
$ |
- |
|
Weighted
average number of Class E common units outstanding
|
|
|
4,701,034 |
|
|
|
4,701,034 |
|
Basic
and diluted income per Class E common unit
|
|
$ |
- |
|
|
$ |
- |
|
Distributions
per unit
|
|
$ |
- |
|
|
$ |
- |
|
4. Risk
Management Activities
Effective
June 19, 2007, the Partnership elected to account for its entire outstanding
commodity hedging instruments on a mark-to-market basis except for the portion
pursuant to which all NGL products for a particular year were hedged and the
hedging relationship was, for accounting purposes, effective. On
March 7, 2008, the Partnership entered offsetting trades against its existing
2009 portfolio of mark-to-market hedges, which it believes will substantially
reduce the volatility of its net income. This group of trades, along
with the pre-existing 2009 portfolio, will continue to be accounted for on a
mark-to-market basis. Simultaneously, the Partnership executed
additional 2009 NGL swaps which were designated under SFAS No. 133 as cash flow
hedges. Currently, the Partnership accounts for a portion of its 2008
West Texas Intermediate crude oil swap and its 2009 West Texas Intermediate
crude oil swap using mark-to-market accounting.
On
February 29, 2008, the Partnership entered into two year interest rate swaps
related to $300,000,000 of borrowings under its revolving credit facility,
effectively locking the rate for these borrowings at 2.4 percent, plus the
applicable margin (1.5 percent as of March 31, 2008). These interest
rate swaps were designated as cash flow hedges on March 7, 2008 and the
Partnership incurred an immaterial charge for the period in which mark-to-market
accounting applied.
The
Partnership’s hedging positions help reduce exposure to variability of future
commodity prices through 2009 and future interest rates on $300,000,000 of debt
under its revolving credit facility through March 5, 2010.
The net
fair value of the Partnership’s risk management activities constituted a net
liability of $48,422,000 at March 31, 2008. The Partnership expects
to reclassify $29,334,000 of hedging losses as an offset to revenues or interest
expense from accumulated other comprehensive income (loss) in the next twelve
months. During the three months ended March 31, 2008 and 2007, the
Partnership recorded $3,090,000 and $8,000 of mark-to-market losses for certain
commodity hedges that do not qualify for hedge accounting and recognized a
$223,000 ineffectiveness gain during the three months ended March 31, 2008,
which is included in the March 31, 2008 mark-to-market loss.
5. Long-Term
Debt
Long-term
debt obligations of the Partnership are as follows:
|
|
March
31, 2008
|
|
|
December
31, 2007
|
|
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
Senior
notes
|
|
$ |
357,500 |
|
|
$ |
357,500 |
|
Revolving
loans
|
|
|
733,000 |
|
|
|
124,000 |
|
Total
|
|
|
1,090,500 |
|
|
|
481,500 |
|
Less:
current portion
|
|
|
- |
|
|
|
- |
|
Long-term
debt
|
|
$ |
1,090,500 |
|
|
$ |
481,500 |
|
|
|
|
|
|
|
|
|
|
Availability
under term and revolving credit facility
|
|
|
|
|
|
Total
credit facility limit
|
|
$ |
900,000 |
|
|
$ |
500,000 |
|
Revolver
loans
|
|
|
(733,000 |
) |
|
|
(124,000 |
) |
Letters
of credit
|
|
|
(27,263 |
) |
|
|
(27,263 |
) |
Total
available
|
|
$ |
139,737 |
|
|
$ |
348,737 |
|
RGS
entered into Amendment No. 4 to its Fourth Amended and Restated Credit Facility
on January 15, 2008, thereby expanding its revolving credit facility thereunder
to $750,000,000. RGS also entered into Amendment No. 5 to its Fourth
Amended and Restated Credit Facility on February 13, 2008, expanding its
revolving credit facility thereunder to $900,000,000 and availability for
letters of credit to $100,000,000. The Partnership has the option to
request an additional $250,000,000 in revolving commitments with 10 business
days written notice provided that no event of default has occurred or would
result due to such increase, and all other additional conditions for the
increase of the commitments set forth in the credit facility have been
met. These amendments did not materially change other terms of the
RGS revolving credit facility.
The
outstanding balance of revolving debt under the credit facility bears interest
at LIBOR plus a margin or Alternative Base Rate (equivalent to the U.S. prime
lending rate) plus a margin, or a combination of both. The weighted
average interest rates for the revolving loans and senior notes, including
interest rate swap settlements, commitment fees, and amortization of debt
issuance costs were 6.90 percent and 8.78 percent for the three months
ended March 31, 2008 and 2007, respectively. The senior notes bear
interest at a fixed rate of 8.375 percent. The estimated fair market
value of the senior notes was $372,694,000 as of March 31, 2008.
The
senior notes are guaranteed by each of the Partnership’s current subsidiaries
(the “Guarantors”) as of March 31, 2008, except for the FrontStreet
assets. These note guarantees are the joint and several obligations
of the Guarantors. A Guarantor may not sell or otherwise dispose of all or
substantially all of its properties or assets if such sale would cause a default
under the terms of the senior notes. Events of default include nonpayment
of principal or interest when due; failure to comply with certain limits on the
payment of distributions; failure to make a change of control offer; failure to
comply with reporting requirements according to SEC rules and regulations; and
defaults on the payment of obligations under other mortgages or
indentures. Since certain wholly owned subsidiaries do not guarantee
the senior notes, the consolidating financial statements of the guarantors and
non-guarantors as of and for the three months March 31, 2008 are disclosed
below.
Balance
Sheet
|
|
March
31, 2008
|
|
(in
thousands)
|
|
|
|
Guarantors
|
|
|
Non
Guarantors
|
|
|
Consolidated
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
Total
current assets
|
|
$ |
195,732 |
|
|
$ |
12,975 |
|
|
$ |
208,707 |
|
Property,
plant and equipment, net
|
|
|
1,355,631 |
|
|
|
93,137 |
|
|
|
1,448,768 |
|
Total
other assets
|
|
|
496,458 |
|
|
|
- |
|
|
|
496,458 |
|
TOTAL
ASSETS
|
|
$ |
2,047,821 |
|
|
$ |
106,112 |
|
|
$ |
2,153,933 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES
& PARTNERS' CAPITAL
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
current liabilities
|
|
$ |
241,963 |
|
|
$ |
5,529 |
|
|
$ |
247,492 |
|
Long-term
liabilities from risk management activities
|
|
|
14,033 |
|
|
|
- |
|
|
|
14,033 |
|
Other
long-term liabilities
|
|
|
16,075 |
|
|
|
- |
|
|
|
16,075 |
|
Long-term
debt
|
|
|
1,090,500 |
|
|
|
- |
|
|
|
1,090,500 |
|
Minority
interest
|
|
|
885 |
|
|
|
- |
|
|
|
885 |
|
Partners'
capital
|
|
|
684,365 |
|
|
|
100,583 |
|
|
|
784,948 |
|
TOTAL
LIABILITIES & PARTNERS' CAPITAL
|
|
$ |
2,047,821 |
|
|
$ |
106,112 |
|
|
$ |
2,153,933 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statement
of Operations
|
|
For
the Three Months Ended March 31, 2008
|
|
(in
thousands)
|
|
|
|
Guarantors
|
|
|
Non
Guarantors
|
|
|
Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
Total
revenues
|
|
$ |
393,048 |
|
|
$ |
12,187 |
|
|
$ |
405,235 |
|
Total
operating costs and expenses
|
|
|
369,882 |
|
|
|
9,452 |
|
|
|
379,334 |
|
OPERATING
INCOME
|
|
|
23,166 |
|
|
|
2,735 |
|
|
|
25,901 |
|
Interest
expense, net
|
|
|
(15,406 |
) |
|
|
- |
|
|
|
(15,406 |
) |
Other
income and deductions, net
|
|
|
176 |
|
|
|
- |
|
|
|
176 |
|
Minority
interest
|
|
|
(66 |
) |
|
|
(6 |
) |
|
|
(72 |
) |
INCOME
BEFORE INCOME TAXES
|
|
|
7,870 |
|
|
|
2,729 |
|
|
|
10,599 |
|
Income
tax expense
|
|
|
251 |
|
|
|
- |
|
|
|
251 |
|
NET
INCOME
|
|
$ |
7,619 |
|
|
$ |
2,729 |
|
|
$ |
10,348 |
|
Statement
of Cash Flow
|
|
For
the Three Months Ended March 31, 2008
|
|
(in
thousands)
|
|
|
|
Guarantors
|
|
|
Non
Guarantors
|
|
|
Consolidated
|
|
Net
cash flows provided by (used in) operating activities
|
|
$ |
61,220 |
|
|
$ |
(3,682 |
) |
|
$ |
57,538 |
|
Net
cash flows used in investing activities
|
|
|
(671,488 |
) |
|
|
(467 |
) |
|
|
(671,955 |
) |
Net
cash flows provided by financing activities
|
|
|
592,322 |
|
|
|
- |
|
|
|
592,322 |
|
6. Commitments
and Contingencies
Legal. The
Partnership is involved in various other claims and lawsuits incidental to its
business. In the opinion of management, these claims and lawsuits in
the aggregate will not have a material adverse effect on the Partnership’s
business, financial condition, results of operations or cash flows.
Contingent Purchase of Sonat
Assets. In March of 2008, the Partnership, through its Nexus
acquisition, obtained the rights to a contingent commitment to purchase 136
miles of pipeline that would enable the integration of the recently acquired
Nexus gathering system into the Partnership’s north Louisiana asset
base. The purchase commitment is contingent upon the FERC declaring
that the pipeline is no longer subject to its jurisdiction, together with
approval of the current owner’s abandonment and other customary closing
conditions. In the event that all contingencies are satisfactorily
resolved, the Partnership will pay Sonat $27,500,000. Furthermore, if
the closing occurs on or prior to March 1, 2010, the Partnership will pay an
additional $25,000,000 to the sellers, subject to certain terms and
conditions.
Escrow Payable. At
March 31, 2008, $6,064,000 remained in escrow pending the completion by El Paso
Field Services, LP (“El Paso”) of environmental remediation projects pursuant to
the purchase and sale agreement (“El Paso PSA”) related to the assets in north
Louisiana and in the mid-continent area. In the El Paso PSA, El Paso
indemnified the predecessor of our operating partnership RGS against losses
arising from pre-closing and known environmental liabilities subject to a limit
of $84,000,000 and subject to certain deductible limits. Upon completion of
a Phase II environmental study, the Partnership notified El Paso of remediation
obligations amounting to $1,800,000 with respect to known environmental matters
and $3,600,000 with respect to pre-closing environmental
liabilities.
In
January 2008, pursuant to authorization by the Board of Directors of the General
Partner, the Partnership signed a settlement of the El Paso environmental
remediation. Under the settlement, El Paso will clean up and obtain “no
further action” letters from the relevant state agencies for three owned
Partnership facilities. El Paso is not obligated to clean up properties
leased by the Partnership, but it indemnified the Partnership for pre-closing
environmental liabilities. All sites for which the Partnership made
environmental claims against El Paso are either addressed in the settlement or
have already been resolved. In May 2008, the Partnership released all
but $1,500,000 from the escrow fund maintained to secure El Paso’s
obligations. This amount will be further reduced under a specified schedule
as El Paso completes its clean-up obligations and the remainder will be released
upon completion.
Nexus Escrow. Nexus Gas
Partners LLC deposited $8,500,000 in an escrow account as security to the
Partnership for a period of one year against indemnification obligations and any
purchase price adjustment related to the March 25, 2008 acquisition of Nexus Gas
Partners LLC.
Environmental. A Phase I
environmental study was performed on the Waha assets in connection with the
pre-acquisition due diligence process in 2004. Most of the identified
environmental contamination had either been remediated or was being remediated
by the previous owners or operators of the properties. The aggregate
potential environmental remediation costs at specific locations were estimated
to range from $1,900,000 to $3,100,000. No governmental agency has
required the Partnership to undertake these remediation efforts.
Management believes that the likelihood that it will be liable for any
significant potential remediation liabilities identified in the study is remote.
Separately, the Partnership acquired an environmental pollution liability
insurance policy in connection with the acquisition to cover any undetected or
unknown pollution discovered in the future. The policy covers clean-up
costs and damages to third parties, and has a 10-year term (expiring 2014) with
a $10,000,000 limit subject to certain deductibles. No claims have been
made.
TCEQ Notice of
Enforcement. On February 15, 2008, the Texas Commission on
Environmental Quality (“TCEQ”) issued to RFS a Notice of Enforcement concerning
its Tilden Gas Plant (“the Plant”), located in McMullen County,
Texas. The Notice of Enforcement alleges that, between March 9, 2006,
and May 8, 2007, the Plant experienced 15 emission events of various durations
from 4 hours to 41 days, which the Plant failed to report to TCEQ and other
agencies within 24 hours of occurrence. These events occurred during times
of failure of the Tilden plant sulphur recovery unit or ancillary equipment and
resulted in the flaring of acid gas. Of these events, one relates to an
alleged release of nearly 6 million pounds of sulphur dioxide and 64,000 pounds
of hydrogen sulphide, 11 related to less than 2,500 pounds of sulphur dioxide
and three related to more than 2,500 and less than 40,000 pounds of sulphur
dioxide (including two releases of 126 and 393 pounds of hydrogen
sulphide). In 2007, the subsidiary completed construction of an acid gas
reinjection unit at the Tilden plant and permanently shut down the Sulphur
Recovery Unit.
All these
emission incidents were reported by means of fax or telephone to the TCEQ
pursuant to an informal procedure established with the TCEQ by the prior owner
of the Tilden plant and emission fines were paid in connection with all the
incidents. Using that procedure, all except one were
timely. Prior to the acquisition of the Plant by our subsidiary, the TCEQ
had established its electronic data base for emission events, but our subsidiary
did not report using that facility. On April 3, 2008, the TCEQ presented
RFS with a written offer to settle the allegations made in the Notice of
Enforcement for an administrative penalty in the amount of
$480,000. RFS will meet with TCEQ to present its view that the
emissions were neither excessive nor improperly reported. Management
of the General Partner does not expect the NOE to have a material adverse
effect on its results of operations or financial condition.
RIGS FERC
Petition. On April 29, 2008, we filed a petition with the FERC
seeking approval to maintain RIGS’ maximum Section 311 transportation
rates. The rate filing was required by a FERC Letter Order issued on
September 26, 2005, which approved a settlement in which RIGS agreed to justify
its existing rates or establish new rates for Section 311 service by May 1,
2008. The triennial rate review requirement is a standard settlement
provision in most intrastate pipeline rate proceedings.
In the
petition, RIGS requests to maintain its current maximum rates for both firm and
interruptible services as follows: firm service: reservation fee of $4.5625 per
MMBtu monthly ($0.15 per MMBtu daily) and commodity fee of $0.05 per
MMBtu; interruptible service: $0.20 per MMBtu. RIGS also requested a
continuation of its existing fuel retention percentage of up to two
percent. The proposed rates are subject to refund beginning May 1,
2008.
7. Related
Party Transactions
The
employees operating the assets of the Partnership and its subsidiaries and
substantially all those providing staff or support services are employees of the
General Partner and other affiliates of the Partnership. Pursuant to
the Partnership Agreement, our General Partner receives a monthly reimbursement
for all direct and indirect expenses that it incurs on behalf of the
Partnership. Reimbursements of $6,888,000 and $6,049,000 were
recorded in the Partnership’s financial statements during three months ended
March 31, 2008 and 2007, respectively, as operating expenses or general and
administrative expenses, as appropriate.
In
conjunction with distributions by the Partnership on common, subordinated units,
and general partner interest, GE EFS and affiliates, HM Capital Partners and
affiliates, and certain members of management received cash distributions of
$7,570,545, $3,259,469 and $289,755, respectively, in the three months ended
March 31, 2008 as a result of their ownership interest in the
Partnership.
8. Segment
Information
The
Partnership has three reportable segments: i) gathering and processing, ii)
transportation, and iii) contract compression. Gathering and
processing involves collecting raw natural gas from producer wells and
transporting it to treating plants where water and other impurities such as
hydrogen sulfide and carbon dioxide are removed. Treated gas is then
processed to remove the natural gas liquids. The treated and
processed natural gas is then transported to market separately from the natural
gas liquids. Revenues and the associated cost of sales directly
expose the Partnership to commodity price risk, which is managed through
derivative contracts and other measures. The Partnership aggregates
the results of its gathering and processing activities across five geographic
regions into a single reporting segment.
The
transportation segment uses pipelines to transport natural gas from receipt
points on its system to interconnections with larger pipelines or trading hubs
and other markets. The Partnership performs transportation services
for shipping customers under firm or interruptible arrangements. In either case,
revenues are primarily fee based and involve minimal direct exposure to
commodity price fluctuations. The Partnership also purchases natural
gas at the inlets to the pipeline and sells this gas at its
outlets. The north Louisiana intrastate pipeline operated by this
segment serves the Partnership’s gathering and processing facilities in the same
area and those transactions create the intersegment revenues shown in the table
below.
The
contract compression segment services include designing, sourcing, owning,
insuring, installing, operating, servicing, repairing, and maintaining
compressors and related equipment, with a focus on meeting the complex
requirements of field-wide compression applications,
as opposed to targeting the compression needs of individual wells within a
field. These field-wide applications include compression for natural
gas gathering, natural gas lift for crude oil production and natural gas
processing. Revenues in this segment are fee-based, with minimal
direct exposure to commodity price risk. The contract compression
operations are primarily located in Texas, Louisiana, and
Arkansas.
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 for the transportation segments, is defined as total revenues,
including service fees, less cost of sales. In the contract
compression segment, segment margin is defined as revenues minus direct costs,
which primarily consists of compressor repairs. Management believes
segment margin is an important measure because it is directly related to volumes
and commodity price changes. 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.
Results
for each statement of operations period, together with amounts related to
balance sheets for each segment, are shown below.
|
|
Gathering
and Processing
|
|
|
Transportation
|
|
|
Contract
Compression
|
|
|
Corporate
|
|
|
Eliminations
|
|
|
Total
|
|
|
|
(in
thousands)
|
|
External
Revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the three months ending March 31, 2008
|
|
$ |
261,585 |
|
|
$ |
118,383 |
|
|
$ |
25,267 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
405,235 |
|
For
the three months ending March 31, 2007
|
|
|
177,119 |
|
|
|
79,309 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
256,428 |
|
Intersegment
Revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the three months ending March 31, 2008
|
|
|
- |
|
|
|
30,684 |
|
|
|
118 |
|
|
|
- |
|
|
|
(30,802 |
) |
|
|
- |
|
For
the three months ending March 31, 2007
|
|
|
- |
|
|
|
14,818 |
|
|
|
- |
|
|
|
- |
|
|
|
(14,818 |
) |
|
|
- |
|
Cost
of Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the three months ending March 31, 2008
|
|
|
207,578 |
|
|
|
134,374 |
|
|
|
2,364 |
|
|
|
- |
|
|
|
(30,727 |
) |
|
|
313,589 |
|
For
the three months ending March 31, 2007
|
|
|
146,941 |
|
|
|
79,814 |
|
|
|
- |
|
|
|
- |
|
|
|
(14,818 |
) |
|
|
211,937 |
|
Segment
Margin
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the three months ending March 31, 2008
|
|
|
54,007 |
|
|
|
14,693 |
|
|
|
23,021 |
|
|
|
- |
|
|
|
(75 |
) |
|
|
91,646 |
|
For
the three months ending March 31, 2007
|
|
|
30,178 |
|
|
|
14,313 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
44,491 |
|
Operation
and Maintenance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the three months ending March 31, 2008
|
|
|
18,627 |
|
|
|
1,396 |
|
|
|
8,844 |
|
|
|
- |
|
|
|
(22 |
) |
|
|
28,845 |
|
For
the three months ending March 31, 2007
|
|
|
9,115 |
|
|
|
1,810 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
10,925 |
|
Depreciation
and Amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the three months ending March 31, 2008
|
|
|
12,670 |
|
|
|
3,491 |
|
|
|
5,354 |
|
|
|
226 |
|
|
|
- |
|
|
|
21,741 |
|
For
the three months ending March 31, 2007
|
|
|
7,885 |
|
|
|
3,250 |
|
|
|
- |
|
|
|
292 |
|
|
|
- |
|
|
|
11,427 |
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March
31, 2008
|
|
|
1,033,486 |
|
|
|
330,000 |
|
|
|
751,031 |
|
|
|
39,416 |
|
|
|
- |
|
|
|
2,153,933 |
|
December
31, 2007
|
|
|
886,477 |
|
|
|
329,862 |
|
|
|
- |
|
|
|
62,071 |
|
|
|
- |
|
|
|
1,278,410 |
|
Goodwill
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March
31, 2008
|
|
|
125,568 |
|
|
|
34,243 |
|
|
|
138,769 |
|
|
|
- |
|
|
|
- |
|
|
|
298,580 |
|
December
31, 2007
|
|
|
59,832 |
|
|
|
34,243 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
94,075 |
|
Expenditures
for Long-Lived Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the three months ending March 31, 2008
|
|
|
35,219 |
|
|
|
1,015 |
|
|
|
61,299 |
|
|
|
363 |
|
|
|
- |
|
|
|
97,896 |
|
For
the three months ending March 31, 2007
|
|
|
35,547 |
|
|
|
4,385 |
|
|
|
- |
|
|
|
87 |
|
|
|
- |
|
|
|
40,019 |
|
The table
below provides a reconciliation of total segment margin to net income
(loss).
|
|
Three
Months Ended
|
|
|
|
March
31, 2008
|
|
|
March
31, 2007
|
|
|
|
(in
thousands)
|
|
Net
income (loss)
|
|
$ |
10,348 |
|
|
$ |
(1,295 |
) |
Add
(deduct):
|
|
|
|
|
|
|
|
|
Operation
and maintenance
|
|
|
28,845 |
|
|
|
10,925 |
|
General
and administrative
|
|
|
10,923 |
|
|
|
6,851 |
|
Loss
on assets sales, net
|
|
|
- |
|
|
|
1,808 |
|
Management
services termination fee
|
|
|
3,888 |
|
|
|
- |
|
Transaction
expenses
|
|
|
348 |
|
|
|
- |
|
Depreciation
and amortization
|
|
|
21,741 |
|
|
|
11,427 |
|
Interest
expense, net
|
|
|
15,406 |
|
|
|
14,885 |
|
Other
income and deductions, net
|
|
|
(176 |
) |
|
|
(110 |
) |
Minority
interest
|
|
|
72 |
|
|
|
- |
|
Income
tax expense
|
|
|
251 |
|
|
|
- |
|
Total
segment margin
|
|
$ |
91,646 |
|
|
$ |
44,491 |
|
9. Equity
Based Compensation
In
December 2005, the compensation committee of the board of directors of the
Partnership’s General Partner approved a long-term incentive plan (“LTIP”) for
the Partnership’s employees, directors and consultants covering an aggregate of
2,865,584 common units. Outstanding, unvested LTIP restricted unit
awards generally vest on the basis of one-fourth of the award each
year. The Partnership expects to recognize an aggregate of
$16,367,000 of compensation expense related to the non-vested grants under
LTIP. All outstanding options are vested and expire ten years after the
grant date.
The
Partnership makes distributions to non-vested restricted common units at the
same rate as the common units. Restricted common units are subject to
contractual restrictions against transfer which lapse over time and are
subject to forfeiture upon termination of employment. Upon the exercise of
the common unit options, the Partnership anticipates settling these obligations
with common units.
The
common unit options and restricted (non-vested) unit activity for the three
months ended March 31, 2008 are as follows.
Common
Unit Options
|
|
Units
|
|
|
Weighted
Average Exercise Price
|
|
|
Weighted
Average Contractual Term (Years)
|
|
|
Aggregate
Intrinsic Value * (in thousands)
|
|
Outstanding
at beginning of period
|
|
|
738,668 |
|
|
$ |
21.05 |
|
|
|
|
|
|
|
Granted
|
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
Exercised
|
|
|
(54,000 |
) |
|
|
21.01 |
|
|
|
|
|
$ |
310 |
|
Forfeited
or expired
|
|
|
(7,700 |
) |
|
|
20.00 |
|
|
|
|
|
|
|
|
Outstanding
at end of period
|
|
|
676,968 |
|
|
|
21.06 |
|
|
|
7.98 |
|
|
|
3,846 |
|
Exercisable
at end of period
|
|
|
676,968 |
|
|
|
21.06 |
|
|
|
|
|
|
|
3,846 |
|
*
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
each period presented. Unit options with a strike price greater than the
end of the period closing market price are excluded.
Restricted
(Non-Vested) Units
|
|
Units
|
|
|
Weighted
Average Grant Date Fair Value
|
|
Outstanding
at beginning of period
|
|
|
397,500 |
|
|
$ |
31.62 |
|
Granted
|
|
|
192,000 |
|
|
|
30.99 |
|
Vested
|
|
|
- |
|
|
|
- |
|
Forfeited
or expired
|
|
|
(34,500 |
) |
|
|
31.58 |
|
Outstanding
at end of period
|
|
|
555,000 |
|
|
|
31.41 |
|
10. Fair
Value Measures
On
January 1, 2008, the Partnership adopted the provisions of SFAS No. 157, “Fair
Value Measurements” (“SFAS No. 157”), for financial assets and
liabilities. SFAS No. 157 became effective for financial assets and
liabilities on January 1, 2008. On January 1, 2009, the
Partnership will apply the provisions of SFAS No. 157 for non-recurring fair
value measurements of non-financial assets and
liabilities, such as goodwill, indefinite-lived intangible assets, property,
plant and equipment and asset retirement obligations. SFAS No. 157
defines fair value, thereby eliminating inconsistencies in guidance found in
various prior accounting pronouncements, and increases disclosures surrounding
fair value calculations.
SFAS No.
157 establishes 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
markets accessible by the
Partnership;
|
·
|
Level
2 – inputs that are observable in the marketplace other than those inputs
classified as Level 1; and
|
·
|
Level
3 – inputs that are unobservable in the marketplace and significant to the
valuation.
|
SFAS No.
157 encourages entities 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 risk management assets and liabilities. Risk
management assets and liabilities include interest rate swaps and commodity
swaps. Risk management assets and liabilities are valued in the
market using discounted cash flow techniques. These techniques incorporate
Level 1 and Level 2 inputs such as future interest rates and commodity rates.
These market inputs are utilized in the discounted cash flow calculation
considering the instrument’s term, notional amount, discount rate and credit
risk. Significant inputs to the discounted cash flow valuations are
observable in the active markets and are classified as Level 2 in the
hierarchy. The Partnership has no non-financial assets and
liabilities as of March 31, 2008 classified as Level 3 in the
hierarchy.
11.
Subsequent Events
Partner Distributions.
On April 25, 2008, the Partnership declared a distribution of $0.42 per
common and subordinated unit including units equivalent to the General
Partner’s two percent interest in the Partnership, and an aggregate
distribution of $177,000 with respect to the General Partner’s incentive
distribution rights, payable on May 14, 2008 to unitholders of record at the
close of business on May 7, 2008.
Class E Common
Units. The Class E common units converted into common units on a
one-for-one basis on May 5, 2008.
Item
2. Management’s Discussion and Analysis of Financial Condition and Results of
Operations
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 unaudited condensed
consolidated financial statements and notes included elsewhere in this
document.
OVERVIEW. We are a
growth-oriented publicly-traded Delaware limited partnership engaged in the
gathering, processing, contract compression, marketing, and transportation of
natural gas and NGLs. We provide these services through systems
located in Louisiana, Texas, Arkansas, and the mid-continent region of the
United States, which includes Kansas and Oklahoma.
RECENT
DEVELOPMENTS.
We
completed three acquisitions in the three months ended March 31,
2008.
FrontStreet Hugoton,
LLC. On January 7, 2008, the Partnership, through RGS,
acquired all of the outstanding equity (the “FrontStreet Acquisition”) of
FrontStreet Hugoton, LLC from ASC and EnergyOne. FrontStreet owns a
gas gathering system located in Kansas and Oklahoma, which is operated by a
third party.
The total
purchase price, subject to customary post-closing adjustments, paid by the
Partnership for FrontStreet consisted of (1) the issuance of 4,701,034 Class E
common units of the Partnership to ASC and (2) the cash payment of $11,752,000
to EnergyOne, inclusive of a payment to terminate a management services
agreement in the amount of $3,888,000. RGS financed the cash portion
of the purchase price out of its revolving credit facility. In
connection with the FrontStreet Acquisition, the General Partner entered into
Amendment No. 3 to the Amended and Restated Agreement of Limited Partnership of
the Partnership, which created the Partnership’s Class E common
units. The Class E common units have the same terms and conditions as
the Partnership’s common units, except that the Class E common units were not
entitled to participate in earnings or distributions of operating surplus by the
Partnership. The Class E common units were issued in a private
offering conducted in accordance with the exemption from the registration
requirements of the Securities Act of 1933 afforded by Section 4(2)
thereof. The Class E common units converted into common units on a
one-for-one basis on May 5, 2008.
Because
the FrontStreet Acquisition is a transaction between commonly controlled
entities (i.e., the buyer and the sellers were each affiliates of GECC), the
Partnership accounted for the acquisition in a manner similar to the pooling of
interest method. Under this method of accounting, the Partnership
will reflect historical balance sheet data for both the Partnership and
FrontStreet instead of reflecting the fair market value of FrontStreet’s assets
and liabilities. Further, certain transaction costs that would normally be
capitalized were expensed. Common control between the Partnership and
FrontStreet began on June 18, 2007. The three months ended March 31,
2008 statement of operations includes FrontStreet’s results for the entire
quarter.
CDM Resource Management,
Ltd. On January 15, 2008, the Partnership and an indirect
wholly owned subsidiary of the Partnership (“Merger Sub”) consummated an
agreement and plan of merger (the “Merger Agreement”) with CDM Resource
Management, Ltd., CDM GP, and CDM LP (each a “CDM Partner” and together the “CDM
Partners”). Upon closing, CDM merged with and into Merger Sub, with
Merger Sub continuing as the surviving entity after the merger (the “CDM
Merger”). Following the merger, Merger Sub changed its name to CDM
Resource Management LLC. CDM provides its customers with turn-key natural
gas contract compression services to maximize their natural gas and crude oil
production, throughput, and cash flow in Texas, Louisiana, and
Arkansas. The Partnership operates and manages CDM as a separate reportable
segment.
The total
purchase price, subject to customary post-closing adjustments, paid by the
Partnership for the partnership interests of CDM consisted of (1) the
issuance of an aggregate of 7,276,506 Class D common units of the Partnership,
which were valued at $219,590,000, (2) the payment of an aggregate of
$161,945,000 in cash to the CDM Partners, and (3) the payment of $316,500,000 to
retire CDM’s debt obligations. Of the Class D common units issued,
4,197,303 Class D common units were deposited with an escrow agent pursuant to
an escrow agreement. Such common units constitute security to the
Partnership for a period of one year after the closing of the CDM
Merger with respect to any obligations of the CDM Partners under the Merger
Agreement, including obligations for breaches of representation, warranties and
covenants. In connection with the CDM Merger, the General Partner entered
into Amendment No. 4 to the Amended and Restated Agreement of Limited
Partnership of the Partnership, which created the Partnership’s Class D common
units. The Class D common units have the same terms and conditions as
the Partnership’s common units, except that the Class D common units are not
entitled to participate in distributions of operating surplus by the
Partnership. The Class D common units automatically convert into common
units on a one-for-one basis on the close of business on the first business day
after the record date for the quarterly distribution on the common units for the
quarter ending December 31, 2008. The Class D common units were issued in
a private offering conducted in accordance with the exemption from the
registration requirements of the Securities Act of 1933 afforded by Section
4(2) thereof.
Nexus Gas Holdings,
LLC. On March 25, 2008, the Partnership acquired Nexus Gas Holdings,
LLC, a Delaware limited liability company (“Nexus”) (“Nexus Acquisition”) by
merger for $87,749,000 in cash, including customary closing
adjustments. Nexus Gas Partners LLC, the sole member of Nexus prior
to the merger (“Nexus Member”), deposited $8,500,000 in an escrow account as
security to the Partnership for a period of one year against indemnification
obligations and any purchase price adjustment. The Partnership funded
the Nexus Acquisition through borrowings under our existing revolving credit
facility.
Upon
consummation of the Nexus Acquisition, the Partnership acquired Nexus’ rights
under a Purchase and Sale Agreement (the “Sonat Agreement”) between Nexus and
Southern Natural Gas Company (“Sonat”). Pursuant to the Sonat
Agreement, Nexus will purchase 136 miles of pipeline from Sonat (the “Sonat
Asset Acquisition”) that would enable the Nexus gathering system to be
integrated into the Partnership’s north Louisiana asset base. The
Sonat Asset Acquisition is subject to abandonment approval and jurisdictional
redetermination by the FERC, as well as customary closing
conditions. Upon closing of the Sonat Asset Acquisition, the
Partnership will pay Sonat $27,500,000, and, if the closing occurs on or prior
to March 1, 2010, on certain terms and conditions as provided in the Merger
Agreement, the Partnership will make an additional payment of $25,000,000 to the
Nexus Member.
RIGS FERC
Petition. On April 29, 2008, we filed a petition with the FERC
seeking approval to maintain RIGS’ maximum Section 311 transportation
rates. The rate filing was required by a FERC Letter Order issued on
September 26, 2005, which approved a settlement in which RIGS agreed to justify
its existing rates or establish new rates for Section 311 service by May 1,
2008. The triennial rate review requirement is a standard settlement
provision in most intrastate pipeline rate proceedings.
In the
petition, RIGS requests to maintain its current maximum rates for both firm and
interruptible services as follows: firm service: reservation fee of $4.5625 per
MMBtu monthly ($0.15 per MMBtu daily) and commodity fee of $0.05 per
MMBtu; interruptible service: $0.20 per MMBtu. RIGS also requested a
continuation of its existing fuel retention percentage of up to 2
percent. The proposed rates are subject to refund beginning May 1,
2008.
TCEQ Notice of
Enforcement. On April 3, 2008, TCEQ presented RFS with a
written offer to settle the allegations made in the Notice of Enforcement for an
administrative penalty in the amount of $480,000. RFS will meet with
TCEQ to present its view that the emissions were neither excessive nor
improperly reported.
TRENDS IN
INDUSTRY. Recently, a number of key producers have announced
the discovery of a significant gas reserves, the Haynesville Shale, in north
Louisiana that encompasses more than 3,000 square miles. We believe
our Louisiana assets, including our recently acquired Nexus system, are well
positioned to capitalize on this new development.
OUR OPERATIONS. We
manage our business and analyze and report our results of operations through
three business segments.
-
Gathering
and Processing: We
provide “wellhead-to-market” services to producers of natural gas, which
include transporting raw natural gas from the wellhead through gathering
systems, processing raw natural gas to separate NGLs from the raw natural gas
and selling or delivering the pipeline-quality natural gas and NGLs to various
markets and pipeline systems;
-
Transportation: We
deliver natural gas from northwest Louisiana to more favorable markets in
northeast Louisiana through our 320-mile Regency Intrastate Pipeline system;
and
-
Contract
Compression: We provide customers with turn-key natural gas
compression services to maximize their natural gas and crude oil production,
throughput, and cash flow. Our integrated solutions include a
comprehensive assessment of a customer’s natural gas contract compression
needs and the design and installation of a compression system that addresses
those particular needs. We are responsible for the installation and
ongoing operation, service, and repair of our compression units, which we
modify as necessary to adapt to our customers’ changing operating
conditions.
HOW WE EVALUATE OUR
OPERATIONS. Our management uses a variety of financial and
operational measurements to analyze our performance. We view these
key performance indicators as important tools for evaluating the success of our
operations and review these key performance indicators on a monthly basis for
consistency and trend analysis. For our gathering and processing and
transportation segments, the key performance indicators include volumes, segment
margin, and operating and maintenance expenses. For our contract
compression segment, the key performance indicators include revenue generating
horsepower, average horsepower per revenue generating compression unit, segment
margin, and operation and maintenance expenses. Management also
reviews EBITDA for each reportable segment and in total to analyze our
performance.
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 (1) the level of workovers or recompletions of existing connected
wells and successful drilling activity in areas currently dedicated to our
pipelines, (2) our ability to compete for volumes from successful new wells in
other areas and (3) our ability to obtain natural gas that has been released
from other commitments. We routinely monitor producer activities in
the areas served by our gathering and processing systems to pursue new supply
opportunities.
To
increase throughput volumes on our intrastate pipeline we must contract with
shippers, including producers and marketers, for supplies of natural
gas. We routinely monitor producer and marketing activities in the
areas served by our transportation system in search of new supply
opportunities.
Revenue Generating Horsepower. Revenue
generating horsepower growth is the primary driver for revenue growth in the
contract compression segment, and it is also the base measure for evaluating our
operational efficiency. Revenue generating horsepower is our total
available horsepower less horsepower under contract that is not yet generating
revenue and idle horsepower.
Average Horsepower per Revenue Generating Compression
Unit. We calculate average
horsepower per revenue generating compression unit as our revenue generating
horsepower divided by the number of revenue generating compression
units.
Segment Margin. We
calculate our gathering and processing segment margin as our revenue generated
from our gathering and processing operations minus the cost of natural gas and
NGLs purchased and other cost of sales, including third-party transportation and
processing fees. Revenue includes revenue from the sale of natural
gas and NGLs resulting from these activities and fixed fees associated with the
gathering and processing of natural gas.
We
calculate our transportation segment margin as revenue generated by fee income
as well as, in those instances in which we purchase and sell gas for our
account, gas sales revenue minus the cost of natural gas that we purchase and
transport. Revenue primarily includes fees for the transportation of
pipeline-quality natural gas and the margin generated by sales of natural gas
transported for our account. Most of our segment margin is fee-based
with little or no commodity price risk. We generally purchase
pipeline-quality natural gas at a pipeline inlet price adjusted to reflect our
transportation fee and we sell that gas at the pipeline outlet. We
regard the difference between the purchase price and the sale price as the
economic equivalent of our transportation fee.
We
calculate our contract compression segment margin as our revenues generated from
our contract compression operations minus the direct costs, primarily compressor
unit repairs, associated with those revenues.
Total Segment
Margin. Segment margin from gathering and processing,
transportation and contract compression comprise total segment
margin. We use total segment margin as a measure of
performance. The reconciliation of the non-GAAP financial
measure, total segment margin, to its most directly comparable GAAP measure, net
income (loss) is included in Note 8, Segment Information, within the condensed
consolidated financial statements included in Item 1 of this
report.
Operation and
Maintenance. Operation and maintenance expenses are a separate
measure that we use to evaluate operating performance of field
operations. Direct labor, insurance, property taxes, repair and
maintenance, consumables, utilities and contract services comprise the most
significant portion of our operating and maintenance expenses. These
expenses fluctuate depending on the activities performed during a specific
period. We do not deduct operation and maintenance from total
revenues in calculating segment margin because we separately evaluate commodity
volume, revenue generating horsepower and price changes in segment
margin.
EBITDA. We define
EBITDA as net income plus interest expense, provision for income taxes and
depreciation and amortization expense. EBITDA is used as a
supplemental measure by our management and by external users of our financial
statements such as investors, commercial 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 partners;
-
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.
EBITDA
should not be considered as an alternative to 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 reconciles the non-GAAP financial measure, EBITDA, to its most directly
comparable GAAP measures, net income (loss) and net cash flows provided by
operating activities.
|
|
Three
Months Ended
|
|
|
|
March
31, 2008
|
|
|
March
31, 2007
|
|
|
|
(in
thousands)
|
|
Net
cash flows provided by operating activities
|
|
$ |
57,538 |
|
|
$ |
27,470 |
|
Add
(deduct):
|
|
|
|
|
|
|
|
|
Depreciation
and amortization, including debt issuance cost
amortization
|
|
|
(22,398 |
) |
|
|
(11,986 |
) |
Equity
income
|
|
|
- |
|
|
|
43 |
|
Risk
management portfolio value changes
|
|
|
(3,098 |
) |
|
|
124 |
|
Loss
on asset sales
|
|
|
- |
|
|
|
(1,808 |
) |
Unit
based compensation expenses
|
|
|
(794 |
) |
|
|
(1,103 |
) |
Changes
in current assets and liabilities:
|
|
|
|
|
|
|
|
|
Accounts
receivable and accrued revenues
|
|
|
19,264 |
|
|
|
1,959 |
|
Other
current assets
|
|
|
(2,800 |
) |
|
|
(598 |
) |
Accounts
payable, accrued cost of gas and liquids and accrued
liabilities
|
|
|
(25,950 |
) |
|
|
(5,220 |
) |
Other
current liabilities
|
|
|
(18,249 |
) |
|
|
(10,617 |
) |
Other
assets and liabilities
|
|
|
6,835 |
|
|
|
441 |
|
Net
income (loss)
|
|
$ |
10,348 |
|
|
$ |
(1,295 |
) |
Add:
|
|
|
|
|
|
|
|
|
Interest
expense, net
|
|
|
15,406 |
|
|
|
14,885 |
|
Depreciation
and amortization
|
|
|
21,741 |
|
|
|
11,427 |
|
Income
tax expense
|
|
|
251 |
|
|
|
- |
|
EBITDA
|
|
$ |
47,746 |
|
|
$ |
25,017 |
|
CASH
DISTRIBUTIONS. On April 25, 2008, the Partnership declared a
distribution of $0.42 per common and subordinated unit including units
equivalent to the General Partner’s two percent interest in the Partnership, and
an aggregate distribution of $177,000 with respect to the General Partner’s
incentive distribution rights, payable on May 14, 2008 to unitholders of record
at the close of business on May 7, 2008.
RESULTS
OF OPERATIONS
Three
Months Ended March 31, 2008 vs. Three Months Ended March 31, 2007
The
following table contains key company-wide performance indicators related to our
discussion of the results of operations.
|
|
Three
Months Ended
|
|
|
|
|
|
|
|
|
|
March
31, 2008
|
|
March
31, 2007
|
|
|
Change
|
|
|
Percent
|
|
|
|
(in
thousands except percentages and volume data)
|
|
|
|
|
Revenues
|
|
$ |
405,235 |
|
$ |
256,428 |
|
|
$ |
148,807 |
|
|
|
58 |
% |
Cost
of sales
|
|
|
313,589 |
|
|
211,937 |
|
|
|
101,652 |
|
|
|
48 |
|
Total
segment margin (1)
|
|
|
91,646 |
|
|
44,491 |
|
|
|
47,155 |
|
|
|
106 |
|
Operation
and maintenance
|
|
|
28,845 |
|
|
10,925 |
|
|
|
17,920 |
|
|
|
164 |
|
General
and administrative
|
|
|
10,923 |
|
|
6,851 |
|
|
|
4,072 |
|
|
|
59 |
|
Loss
on asset sales, net
|
|
|
- |
|
|
1,808 |
|
|
|
(1,808 |
) |
|
|
(100 |
) |
Management
services termination fee
|
|
|
3,888 |
|
|
- |
|
|
|
3,888 |
|
|
|
N/M |
|
Transaction
expenses
|
|
|
348 |
|
|
- |
|
|
|
348 |
|
|
|
N/M |
|
Depreciation
and amortization
|
|
|
21,741 |
|
|
11,427 |
|
|
|
10,314 |
|
|
|
90 |
|
Operating
income
|
|
|
25,901 |
|
|
13,480 |
|
|
|
12,421 |
|
|
|
92 |
|
Interest
expense, net
|
|
|
(15,406 |
) |
|
(14,885 |
) |
|
|
(521 |
) |
|
|
4 |
|
Other
income and deductions, net
|
|
|
176 |
|
|
110 |
|
|
|
66 |
|
|
|
60 |
|
Minority
interest
|
|
|
(72 |
) |
|
- |
|
|
|
(72 |
) |
|
|
N/M |
|
Income
tax expense
|
|
|
(251 |
) |
|
- |
|
|
|
(251 |
) |
|
|
N/M |
|
Net
income (loss)
|
|
$ |
10,348 |
|
$ |
(1,295 |
) |
|
$ |
11,643 |
|
|
|
899 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
System
inlet volumes (MMbtu/d) (2)
|
|
|
1,378,932 |
|
|
1,133,844 |
|
|
|
245,088 |
|
|
|
22 |
|
Revenue
generating horsepower (3)
|
|
|
615,852 |
|
|
- |
|
|
|
615,852 |
|
|
|
N/M |
|
(1) For
reconciliation of total segment margin to its most directly comparable financial
measure calculated and presented in accordance with GAAP, please read “– Item 1.
Financial Statements - Note 8, Segment Information.”
(2) System inlet
volumes include total volumes taken into both our gathering and processing
system and our transportation systems.
(3) Revenue
generating horsepower is the primary volumetric measure for our contract
compression segment.
The table
below contains key segment performance indicators related to our discussion of
the results of operations.
|
|
Three
Months Ended
|
|
|
|
|
|
|
|
|
|
March
31, 2008
|
|
|
March
31, 2007
|
|
|
Change
|
|
|
Percent
|
|
|
|
(in
thousands except percentages and volume data) |
|
|
Segment
Financial and Operating Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering
and Processing Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial
data:
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
margin (1)
|
|
$ |
54,007 |
|
|
$ |
30,178 |
|
|
$ |
23,829 |
|
|
|
79 |
% |
Operation
and maintenance
|
|
|
18,627 |
|
|
|
9,115 |
|
|
|
9,512 |
|
|
|
104 |
|
Operating
data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Throughput
(MMbtu/d) (2)
|
|
|
918,950 |
|
|
|
729,218 |
|
|
|
189,732 |
|
|
|
26 |
|
NGL
gross production (Bbls/d)
|
|
|
23,068 |
|
|
|
20,047 |
|
|
|
3,021 |
|
|
|
15 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation
Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial
data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
margin (1)
|
|
$ |
14,693 |
|
|
$ |
14,313 |
|
|
$ |
380 |
|
|
|
3 |
|
Operation
and maintenance
|
|
|
1,396 |
|
|
|
1,810 |
|
|
|
(414 |
) |
|
|
(23 |
) |
Operating
data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Throughput
(MMbtu/d) (2)
|
|
|
732,006 |
|
|
|
704,458 |
|
|
|
27,548 |
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract
Compression Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial
data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
margin (1)
|
|
$ |
23,021 |
|
|
$ |
- |
|
|
$ |
23,021 |
|
|
|
N/M |
|
Operation
and maintenance
|
|
|
8,844 |
|
|
|
- |
|
|
|
8,844 |
|
|
|
N/M |
|
Operating
data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
generating horsepower
|
|
|
615,852 |
|
|
|
- |
|
|
|
615,852 |
|
|
|
N/M |
|
Average
horsepower per revenue generating compression unit
|
|
|
849 |
|
|
|
- |
|
|
|
849 |
|
|
|
N/M |
|
(1) Combined
segment margin varies from consolidated total segment margin due to
inter-segment eliminations between the contract compression, transportation and
gathering and processing segments.
(2) Combined
throughput volumes for the gathering and processing segment and the
transportation segment vary from consolidated system inlet volumes due to
inter-segment eliminations between the two segments.
N/M – Not
Meaningful
Net income. Net income for
the three months ended March 31, 2008 increased $11,643,000 compared to the
three months ended March 31, 2007. An increase in total segment
margin of $47,155,000 primarily attributable to our acquisitions of CDM and
FrontStreet as well as organic growth in the gathering and processing segment
and the absence in March 2008 of a $1,808,000 loss in March 2007 on the sale of
non-core assets, was offset in part by:
·
|
increased operation
and maintenance expense of $17,920,000 primarily due to our CDM and
FrontStreet acquisitions, employee related expenses and contractor
expenses primarily in the gathering and processing
segment;
|
·
|
increased
depreciation and amortization expense of $10,314,000 primarily due to our
CDM, FrontStreet and Pueblo acquisitions and organic
growth projects completed since March 31,
2007;
|
·
|
increased
general and administrative expense of $4,072,000 primarily due to our CDM
acquisition and increased employee-related expenses;
and
|
·
|
payment,
in the three months ended March 31, 2008, of a management services
termination fee of $3,888,000 related to the acquisition of
FrontStreet.
|
Segment Margin. Segment
margin for the three months ended March 31, 2008 increased $47,155,000
compared with the three months ended March 31, 2007, consisting of an
increase of $23,829,000 in gathering and processing segment, an increase of
$380,000 in transportation segment and $23,021,000 in the contract compression
segment recorded in the three months ended March 31, 2008, discussed
below.
Gathering
and processing segment margin increased to $54,007,000 in the three months
ended March 31, 2008 from $30,178,000, an increase of $23,829,000, or 79
percent. The major components of this increase were as
follows:
·
|
$12,187,000
attributed to our FrontStreet
assets;
|
·
|
$9,749,000
attributed to organic growth projects, primarily in
Texas;
|
·
|
$3,524,000
attributed to higher throughput volumes, primarily in north
Louisiana;
|
·
|
$1,450,000
attributed to better pricing on commodity derivative contract settlements;
and partially offset by a
|
·
|
$3,082,000
decrease in non-cash valuation changes in certain commodity derivative
contracts.
|
Transportation
segment margin increased to $14,693,000 for the three months ended
March 31, 2008 from $14,313,000 for the three months ended March 31,
2007, an increase of $380,000, or three percent. The major components of
this increase were as follows:
·
|
$276,000
increase due to our merchant function;
and
|
·
|
$104,000
increase from additional throughput volumes partially offset by slightly
lower margins per unit of
throughput.
|
Contract
compression segment margin was $23,021,000 in the three months ended March 31,
2008, which consisted of $25,267,000, exclusive of $118,000 of intersegment
revenue, of operating revenue and $2,364,000 of direct operating
costs. The following table sets forth certain information regarding
revenue generating horsepower as of March 31, 2008.
|
|
|
Total
Revenue Generating Horsepower
|
|
|
Percentage
of Revenue Generating Horsepower
|
|
|
|
|
|
0-499
|
|
|
|
47,673 |
|
|
|
8 |
% |
|
|
285 |
|
|
500-999
|
|
|
|
65,699 |
|
|
|
11 |
% |
|
|
106 |
|
|
1,000+
|
|
|
|
502,480 |
|
|
|
81 |
% |
|
|
334 |
|
|
|
|
|
|
615,852 |
|
|
|
100 |
% |
|
|
725 |
|
Operation and
Maintenance. Operation and maintenance expense increased to
$28,845,000 in the three months ended March 31, 2008 from $10,925,000 for the
corresponding period in 2007, a 164 percent increase. This increase
is attributable to the following factors:
·
|
$8,844,000
related to contract compression assets acquired on January 15,
2008;
|
·
|
$6,846,000
related to our FrontStreet assets;
|
·
|
$977,000
increase primarily in the gathering and processing segment for the hiring
of additional employees;
|
·
|
$868,000
increase in contractor expense primarily in the gathering and processing
segment related to assets acquired, which are operated by a third party,
subsequent to March 31, 2007;
|
·
|
$848,000
in various operation and maintenance expenses primarily in the gathering
and processing segment associated with organic growth; and partially
offset by a
|
·
|
$463,000
charge to unplanned outage expense in the three months ended March 31,
2007 in the transportation segment related to the Eastside compressor
fire, which represents an estimated 30-day deductible under our insurance
coverage.
|
General and
Administrative. General and administrative expense increased
to $10,923,000 in the three months ended March 31, 2008 from $6,851,000 for the
same period in 2007, a 59 percent increase. The increase is primarily
attributable the following factors:
·
|
$3,440,000
related to contract compression assets acquired on January 15, 2008;
and
|
·
|
$919,000 increase
for hiring additional employees.
|
Other. In the
three months ended March 31, 2008, we recorded a charge of $3,888,000 for the
termination of long-term management services contract and transaction expenses
of $348,000 in connection with our FrontStreet Acquisition. In the
three months ended March 31, 2007, we sold certain non-core assets and recorded
a net charge of $1,808,000.
Depreciation and
Amortization. Depreciation and amortization expense increased to
$21,741,000 in the three months ended March 31, 2008 from $11,427,000 for
the three months ended March 31, 2007, a 90 percent increase.
This increase consists of the following:
·
|
$5,353,000
related to contract compression assets acquired on January 15,
2008;
|
·
|
$2,576,000
related primarily to organic growth projects completed since March 31,
2007; and
|
·
|
$2,385,000
attributed to our FrontStreet
assets.
|
Interest Expense,
Net. Interest expense, net increased $521,000, or four
percent, in the three months ended March 31, 2008 compared to the same period in
2007. Of this increase, $3,895,000 was attributable to increased
levels of borrowings, offset by a decrease of $3,374,000 attributable to lower
interest rates.
CRITICAL ACCOUNTING POLICIES AND
ESTIMATES. In addition to the information set forth in this
report, further information regarding the Partnership’s critical
accounting policies and estimates is included in Item 7 of the Partnership’s
Annual Report on Form 10-K for the year ended December 31, 2007.
As-if Pooling of Interests Method of
Accounting. We account for acquisitions where common control
exists by following the as-if pooling method of accounting as described in SFAS
No. 141, “Business Combinations”. Under this method of accounting, we
reflect the historical balance sheet data for both the acquirer and acquiree
instead of reflecting the fair market value of acquiree’s assets and
liabilities. In common control acquisitions where a minority interest
is also acquired, we use the purchase method of accounting for the minority
interest. Further, certain transaction costs that would normally be
capitalized are expensed.
Fair Value
Measurements. On January 1, 2008, we adopted the provisions of
SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”), for
financial assets and liabilities. SFAS No. 157 defines fair value,
thereby eliminating inconsistencies in guidance found in various prior
accounting pronouncements, and increases disclosures surrounding fair value
calculations. The adoption of SFAS No. 157 for financial assets and
liabilities did not have a material impact on our statement of operations,
financial position or cash flows for the three months ended March 31,
2008.
SFAS No.
157 establishes 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
markets accessible by us;
|
·
|
Level
2 — inputs that are observable in the marketplace other than those inputs
classified as Level 1; and
|
·
|
Level
3 — inputs that are unobservable in the marketplace and significant to the
valuation.
|
SFAS No.
157 requires us to maximize the use of observable inputs and minimize the use of
unobservable inputs. If a financial instrument valuation 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. Our financial assets and liabilities measured at fair
value on a recurring basis are derivative financial instruments consisting of
interest rate swaps and commodity swaps.
OTHER
MATTERS. Information regarding the Partnership’s commitments
and contingencies are included in Note 6-Commitments and Contingencies to the
condensed consolidated financial statements included in Item 1 of this
report.
LIQUIDITY
AND CAPITAL RESOURCES
We expect
our sources of liquidity to include:
·
|
cash
generated from operations;
|
·
|
borrowings
under our credit facility;
|
·
|
issuance
of additional partnership units.
|
We
believe that the cash generated from these sources, including $139,737,000
available under our revolving credit facility, will be sufficient to meet
our minimum quarterly cash distributions and our requirements for short-term
working capital and growth capital expenditures for the next twelve
months.
Working Capital Surplus
(Deficit). Working capital is the amount by which current
assets exceed current liabilities and is a measure of our ability to pay our
liabilities as they become due. During periods of growth capital
expenditures, we experience working capital deficits when we fund construction
expenditures out of working capital until they are permanently
financed. Our working capital is also influenced by current risk
management assets and liabilities due to fair market value changes in our
derivative positions being reflected on our balance sheet. These
represent our expectations for the settlement of risk management rights and
obligations over the next twelve months, and so must be viewed differently from
trade accounts receivable and accounts payable which settle over a much shorter
span of time. When our derivative positions are settled, we expect an
offsetting physical transaction, and, as a result, we do not expect risk
management assets and liabilities to affect our ability to pay bills as they
come due.
Our
working capital deficit increased by $20,420,000 from December 31, 2007 to March
31, 2008 primarily resulting from the following:
§
|
a
$22,095,000 decrease in cash and cash equivalents primarily due to the
timing of payment of accounts
payable;
|
§
|
a
$17,463,000 decrease from an increase in other current liabilities,
excluding taxes payable, primarily due to the inclusion of deferred
revenues from our contract compression segment, increased interest payable
on our senior notes based on the timing of interest payments and increased
interest payable on our revolving credit facility based on increased
levels of borrowings related to our acquisitions and organic growth
in the three months ended March 31,
2008;
|
§
|
a
$15,421,000 increase resulting from an increase in net accounts receivable
and payable due to the timing of cash receipts and payments;
and
|
§
|
a
$2,755,000 increase resulting from a decrease in net risk management
liabilities primarily due to a decrease in commodity prices we
expect to pay (index prices) on our outstanding swaps as compared to the
commodity prices we expect to receive upon
settlement.
|
Cash Flows from
Operations. Net cash flows provided by operating activities
increased $30,068,000 for the three months ended March 31, 2008 as compared to
the three months ended March 31, 2007. Our cash flows from operations
increased primarily due to increased segment margin from our FrontStreet and CDM
acquisitions in January 2008, our Pueblo acquisition in April 2007 and organic
growth in our gathering and processing segment.
Cash Flows from Investing
Activities. Net cash flows used in investing activities
increased $625,064,000 in the three months ended March 31, 2008 compared to the
three months ended March 31, 2007. The major portion of this increase
is attributable to our FrontStreet, CDM and Nexus acquisitions and higher growth
and maintenance capital expenditures discussed in “Capital
Requirements.”
Cash Flows from Financing
Activities. Net cash flows provided by financing activities
increased $573,536,000 in the three months ended March 31, 2008 compared to the
three months ended March 31, 2007 primarily due to increased levels of
borrowings on our revolving credit facility utilized to fund our FrontStreet,
CDM and Nexus acquisitions.
Capital
Requirements
We
categorize our capital expenditures as either:
·
|
Growth
capital expenditures, which are made to acquire additional assets to
increase our business, to expand and upgrade existing systems and
facilities or to construct or acquire similar systems or facilities;
or
|
·
|
Maintenance
capital expenditures, which are made to replace partially or fully
depreciated assets, to maintain the existing operating capacity of our
assets and to extend their useful lives or to maintain existing system
volumes and related cash flows.
|
Growth Capital Expenditures.
In the three months ended March 31, 2008, we incurred $61,427,000 of
growth capital expenditures. Growth capital expenditures primarily relate
to projects listed below.
·
|
$25,300,000
for the fabrication of new compression packages for our contract
compression segment;
|
·
|
$12,600,000
for constructing 20 miles of 10 inch diameter pipeline, which will connect
the Fashing Processing Plant to our Tilden Processing Plant in south Texas
and reconfiguring our Tilden Processing Plant, which we anticipate will be
completed in the first half of
2008;
|
·
|
$4,600,000
for installation of gathering and compression facilities in south Texas;
and
|
·
|
$3,800,000
for construction of pipeline, compression, and treating facilities related
to a joint venture in south Texas.
|
Our 2008
growth budget includes $208,000,000 of currently identified organic growth
capital expenditures, including $117,000,000 for an additional 174,700
horsepower of compression for our contract compression segment. The
most significant projects in our gathering and processing segment are the
following:
·
|
$12,000,000
for our portion of the construction of pipeline, compression, and treating
facilities related to a joint venture in south
Texas;
|
·
|
$19,000,000
for constructing 40 miles, 10 inch diameter pipeline, which we
anticipate will be completed in
2008;
|
·
|
$17,100,000
for constructing 20 miles of 10 inch diameter pipeline, which will connect
the Fashing Processing Plant to our Tilden Processing Plant in south
Texas, and reconfiguring our Tilden Processing Plant, which we anticipate
will be completed in the first half of
2008;
|
·
|
$6,800,000
for installation of gathering and compression facilities in south
Texas;
|
·
|
$5,800,000
for additional processing, compression, and gathering facilities in north
Louisiana.
|
Maintenance Capital
Expenditures. In the three months ended March 31, 2008, we
incurred $3,326,000 of maintenance capital expenditures. Maintenance
capital expenditures primarily consist of compressor and equipment overhauls, as
well as new well connects to our gathering systems, which help replace volumes
from naturally occurring depletion of wells already connected.
Contractual
Obligations. At March 31, 2008 our long-term debt increased to
$1,090,500,000 from $481,500,000 at December 31, 2007 primarily due to three
acquisitions completed in the three months ended March 31, 2008. Our
long-term debt obligation, including interest at a one-month LIBOR of 2.70
percent as of March 31, 2008 plus our applicable margin, was $1,375,815,000 in
the aggregate and by period as follows:
§
|
2009
– 2010: $122,501,000;
|
§
|
2011
– 2012: $812,450,000; and
|
§
|
Thereafter:
$387,441,000
|
Commodity Price
Risk. We are a net seller of NGLs, and as such our financial
results are exposed to fluctuations in NGLs pricing. We have executed
swap contracts settled against crude oil, ethane, propane, normal butane, iso
butane and natural gasoline market prices. We have hedged our
expected exposure to declines in prices for NGLs and condensate volumes produced
for our account in the approximate percentages set forth below:
|
|
2008
|
|
|
2009
|
|
NGL
|
|
|
88
|
% |
|
|
78
|
% |
Condensate
|
|
|
69 |
|
|
|
69 |
|
We
continually monitor our hedging and contract portfolio and expect to continue to
adjust our hedge position as conditions warrant.
On
February 29, 2008, the Partnership entered into two year interest rate swaps
related to $300,000,000 of borrowings under our revolving credit facility,
effectively locking the rate for these borrowings at 2.4 percent, plus the
applicable margin (1.5 percent as of March 31, 2008).
On March
7, 2008, we entered offsetting trades against our existing 2009 portfolio of
hedges, which we believe will substantially reduce the volatility of our net
income. This group of trades, along with the pre-existing 2009
portfolio, will continue to be accounted for on a mark-to-market
basis. Simultaneously, we executed additional 2009 NGL swaps which
were designated under SFAS No. 133 as cash flow hedges.
The
following table sets forth certain information regarding our NGL and interest
rate swaps outstanding at March 31, 2008. The relevant payment index
price is the monthly average of the daily closing price for deliveries of
commodities into Mont Belvieu, Texas as reported by the Oil Price Information
Service (OPIS).
|
|
|
|
|
|
|
|
Period
|
Underlying
|
Notional
Volume/Amount
|
We
Pay
|
We
Receive
|
|
Fair
Value Asset/(Liability)
|
|
|
|
|
|
|
|
(in
thousands)
|
|
April
2008-December 2009
|
Ethane
|
1,261
(MBbls)
|
Index
|
$0.58-$0.80
($/gallon)
|
|
$ |
(7,223 |
) |
April
2008-December 2009
|
Propane
|
791
(MBbls)
|
Index
|
$0.93-$1.37
($/gallon)
|
|
|
(12,423 |
) |
January
2009-December 2009
|
Iso
Butane
|
422
(MBbls)
|
Index
|
$1.69
($/gallon)
|
|
|
(9,519 |
) |
April
2008-December 2009
|
Normal
Butane
|
95
(MBbls)
|
Index
|
$1.12-$1.68
($/gallon)
|
|
|
(63 |
) |
April
2008-December 2009
|
Natural
Gasoline
|
328
(MBbls)
|
Index
|
$1.41-$2.09
($/gallon)
|
|
|
(6,653 |
) |
April
2008- December 2009
|
West
Texas Intermediate Crude
|
416
(MBbls)
|
Index
|
$68.17-$68.38
($/Bbls)
|
|
|
(11,924 |
) |
April
2008-March 2010
|
Interest
Rate
|
$300,000,000
|
Fixed
|
LIBOR
|
|
|
(618 |
) |
|
|
|
|
Total
Fair Value
|
|
$ |
(48,423 |
) |
Disclosure controls. At the
end of the period covered by this report, an evaluation was performed under the
supervision and with the participation of our management, including the Chief
Executive Officer and Chief Financial Officer of our managing general partner,
of the effectiveness of the design and operation of our disclosure controls and
procedures (as such terms are defined in Rule 13a–15(e) and 15d–15(e) of the
Exchange Act). Based on that evaluation, management, including the
Chief Executive Officer and Chief Financial Officer of our managing general
partner, concluded that our disclosure controls and procedures were effective as
of March 31, 2008 to provide reasonable assurance that information required to
be disclosed by us in the reports that we file or submit under the Exchange Act
is properly recorded, processed, summarized and reported, within the time
periods specified in the SEC’s rules and forms.
Internal control over financial
reporting. Other than described below, there have been no
changes in the Partnership’s internal controls over financial reporting that
have materially affected, or are reasonably likely to affect, the Partnership’s
internal controls over financial reporting.
Subsequent
to our CDM acquisition, we initiated a program of documentation, implementation
and testing of internal controls over financial reporting for
CDM. This program will continue through December 31, 2009,
culminating with the inclusion of CDM in our Section 404 certification and
attestation in early 2010.
PART
II – OTHER INFORMATION
Item
1. Legal Proceedings
The
information required for this item is provided in Note 6, Commitments and
Contingencies, included in the notes to the unaudited condensed consolidated
financial statements included under Part I, Item 1, which information is
incorporated by reference into this item.
Item 1A. Risk
Factors
In
addition to the other information set forth in this report, you should carefully
consider the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual
Report on Form 10-K for the year ended December 31, 2007, which could materially
affect our business, financial condition or future results. The risks
described in our Annual Report on Form 10-K are not the only risks facing our
Partnership.
Item
2. Unregistered Sales of Equity Securities and Use of
Proceeds
The
information required for this item is provided in Note 1, Organization and
Summary of Significant Accounting Policies, and Note 3, Acquisitions, included
in the notes to the unaudited condensed consolidated financial statements
included under Part I, Item 1, which information is incorporated by reference
into this item.
Item
6. Exhibits
The
exhibits below are filed as a part of this report:
Exhibit
10.1. Employment Agreement with Byron R. Kelley
Exhibit
10.2. Severance Agreement with Dan A. Fleckman
Exhibit
10.3. Consulting Services Agreement with James W. Hunt
Exhibit
12.1. Computation of Ratio of Earnings to Fixed Charges
Exhibit
31.1. Rule 13a-14(a)/15d-14(a) Certification of Chief Executive
Officer
Exhibit
31.2. Rule 13a-14(a)/15d-14(a) Certification of Chief Financial
Officer
Exhibit
32.1. Section 1350 Certifications of Chief Executive
Officer
Exhibit
32.2. Section 1350 Certifications of Chief Financial
Officer
Pursuant
to the requirements of the Securities Exchange Act of 1934, the registrant has
duly caused this report to be signed on its behalf by the undersigned thereunto
duly authorized.
|
REGENCY
ENERGY PARTNERS LP
|
|
|
|
By:
Regency GP LP, its general partner
|
|
|
|
By:
Regency GP LLC, its general partner
|
|
|
|
/s/
Lawrence B. Connors
|
|
|
|
Lawrence
B. Connors
|
|
Senior
Vice President of Accounting and Finance (Duly Authorized Officer and
Chief Accounting
Officer)
|